Gulfport Energy (GPOR) 10-K 26 Feb 25 2024 FY Annual report Financial data

COVER PAGE

COVER PAGE - USD ($) $ in Billions	12 Months Ended
	Dec. 31, 2024	Feb. 20, 2025	Jun. 30, 2024
Cover [Abstract]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2024
Current Fiscal Year End Date	--12-31
Document Transition Report	false
Entity File Number	001-19514
Entity Registrant Name	Gulfport Energy Corp
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	86-3684669
Entity Address, Address Line One	713 Market Drive
Entity Address, City or Town	Oklahoma City,
Entity Address, State or Province	OK
Entity Address, Postal Zip Code	73114
City Area Code	405
Local Phone Number	252-4600
Title of 12(b) Security	Common Stock, $0.0001 par value per share
Trading Symbol	GPOR
Security Exchange Name	NYSE
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
ICFR Auditor Attestation Flag	true
Document Financial Statement Error Correction	false
Entity Shell Company	false
Entity Public Float			$ 2
Entity Common Stock, Shares Outstanding (in shares)		17,894,932
Documents Incorporated by Reference	DOCUMENTS INCORPORATED BY REFERENCE Portions of Gulfport Energy Corporation’s Proxy Statement for the 2025 Annual Meeting of Stockholders are incorporated by reference in Items 10, 11, 12, 13 and 14 of Part III of this Form 10-K.
Amendment Flag	false
Entity Central Index Key	0000874499
Document Fiscal Year Focus	2024
Document Fiscal Period Focus	FY

AUDIT INFORMATION

AUDIT INFORMATION	12 Months Ended
	Dec. 31, 2024
Auditor Information [Abstract]
Auditor Name	GRANT THORNTON LLP
Auditor Location	Oklahoma City, Oklahoma
Auditor Firm ID	248

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2024	Dec. 31, 2023
Current assets:
Cash and cash equivalents	$ 1,473	$ 1,929
Accounts receivable—oil, natural gas, and natural gas liquids sales	155,942	122,479
Accounts receivable—joint interest and other	8,727	22,221
Prepaid expenses and other current assets	7,086	16,951
Short-term derivative instruments	58,085	233,226
Total current assets	231,313	396,806
Property and equipment:
Proved oil and natural gas properties	3,349,805	2,904,519
Unproved properties	221,650	204,233
Other property and equipment	11,291	9,165
Total property and equipment	3,582,746	3,117,917
Less: accumulated depletion, depreciation, amortization and impairment	(1,564,475)	(865,618)
Total property and equipment, net	2,018,271	2,252,299
Other assets:
Long-term derivative instruments	6,003	47,566
Deferred tax asset	581,233	525,156
Operating lease assets	6,099	14,299
Other assets	22,778	31,487
Total other assets	616,113	618,508
Total assets	2,865,697	3,267,613
Current liabilities:
Accounts payable and accrued liabilities	298,081	309,532
Short-term derivative instruments	41,889	21,963
Current portion of operating lease liabilities	5,538	12,959
Total current liabilities	345,508	344,454
Non-current liabilities:
Long-term derivative instruments	35,081	18,602
Asset retirement obligation	32,949	29,941
Non-current operating lease liabilities	561	1,340
Long-term debt	702,857	667,382
Total non-current liabilities	771,448	717,265
Total liabilities	1,116,956	1,061,719
Commitments and contingencies (Notes 17 and 18)
Mezzanine equity:
Preferred stock - $0.0001 par value, 110.0 thousand shares authorized, 37.3 thousand issued and outstanding at December 31, 2024, and 44.2 thousand issued and outstanding at December 31, 2023	37,348	44,214
Stockholders’ equity:
Common stock - $0.0001 par value, 42.0 million shares authorized, 17.8 million issued and outstanding at December 31, 2024, and 18.3 million issued and outstanding at December 31, 2023	2	2
Additional paid-in capital	129,059	315,726
Common stock held in reserve, 0 shares at December 31, 2024, and 62.0 thousand shares at December 31, 2023	0	(1,996)
Retained earnings	1,582,332	1,847,948
Total stockholders’ equity	1,711,393	2,161,680
Total liabilities, mezzanine equity and stockholders’ equity	$ 2,865,697	$ 3,267,613

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares	Dec. 31, 2024	Dec. 31, 2023
Statement of Financial Position [Abstract]
Temporary equity, par or stated value (in dollars per share)	$ 0.0001	$ 0.0001
Temporary equity, shares authorized (in shares)	110,000	110,000
Temporary equity, shares issued (in shares)	37,300	44,200
Temporary equity, shares outstanding (in shares)	37,348	44,214
Common stock, par value (in dollars per share)	$ 0.0001	$ 0.0001
Common stock, shares authorized (in shares)	42,000,000	42,000,000
Common stock, shares issued (in shares)	17,800,000	18,300,000
Common stock, shares outstanding (in shares)	17,800,000	18,300,000
Common stock, capital shares reserved for future issuance (in shares)	0	62,000

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
REVENUES:
Net gain (loss) on natural gas, oil and NGL derivatives	$ 29,527,000	$ 740,319,000	$ (999,747,000)
Total revenues	958,131,000	1,791,702,000	1,331,112,000
OPERATING EXPENSES:
Lease operating expenses	70,112,000	68,648,000	64,790,000
Taxes other than income	29,737,000	33,717,000	60,139,000
Transportation, gathering, processing and compression	351,237,000	348,631,000	357,246,000
Depreciation, depletion and amortization	325,723,000	319,715,000	267,761,000
Impairment of oil and natural gas properties	373,214,000	0	0
General and administrative expenses	42,558,000	38,600,000	35,304,000
Restructuring costs	0	4,762,000	0
Accretion expense	2,307,000	2,782,000	2,746,000
Total operating expenses	1,194,888,000	816,855,000	787,986,000
(LOSS) INCOME FROM OPERATIONS	(236,757,000)	974,847,000	543,126,000
OTHER EXPENSE (INCOME):
Interest expense	59,982,000	57,069,000	59,773,000
Loss on debt extinguishment	13,388,000	0	0
Other, net	7,336,000	(27,982,000)	(11,348,000)
Total other expense	80,706,000	29,087,000	48,425,000
(LOSS) INCOME BEFORE INCOME TAXES	(317,463,000)	945,760,000	494,701,000
INCOME TAX BENEFIT:
Current	0	0	0
Deferred	(56,077,000)	(525,156,000)	0
Total income tax benefit	(56,077,000)	(525,156,000)	0
NET (LOSS) INCOME	(261,386,000)	1,470,916,000	494,701,000
Dividends on preferred stock	(4,230,000)	(4,840,000)	(5,444,000)
Participating securities - preferred stock	0	(212,360,000)	(76,401,000)
NET (LOSS) INCOME ATTRIBUTABLE TO COMMON STOCKHOLDERS	$ (265,616,000)	$ 1,253,716,000	$ 412,856,000
NET (LOSS) INCOME PER COMMON SHARE:
Basic (in dollars per share)	$ (14.72)	$ 67.24	$ 20.45
Diluted (in dollars per share)	$ (14.72)	$ 66.46	$ 20.32
Weighted average common shares outstanding - Basic (shares)	18,050	18,645	20,185
Weighted average common shares outstanding - Diluted (shares)	18,050	18,902	20,347
Natural gas sales
REVENUES:
Revenue from contracts with customers	$ 714,160,000	$ 831,812,000	$ 1,998,452,000
Oil and condensate sales
REVENUES:
Revenue from contracts with customers	101,589,000	99,854,000	147,444,000
Natural gas liquid sales
REVENUES:
Revenue from contracts with customers	$ 112,855,000	$ 119,717,000	$ 184,963,000

CONSOLIDATED STATEMENTS OF STOC

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY - USD ($) $ in Thousands	Total	Common Stock	Common Stock Held in Reserve	Treasury Stock	Paid-in Capital	Retained Earnings (Accumulated Deficit)
Beginning balance (in shares) at Dec. 31, 2021		21,537,000	938,000
Beginning balance at Dec. 31, 2021	$ 549,478	$ 2	$ (30,216)	$ 0	$ 692,521	$ (112,829)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	494,701					494,701
Conversion of preferred stock (in shares)		407,000
Conversion of preferred stock	5,601				5,601
Stock compensation	8,670				8,670
Repurchase of common stock under Repurchase Program (in shares)		(2,896,000)
Repurchase of common stock under Repurchase Program	(250,768)			(286)	(250,482)
Issuance of common stock held in reserve (in shares)			876,000
Issuance of common stock held in reserve	28,220		$ 28,220
Issuance of common stock upon vesting of share-based awards (in shares)		68,000
Issuance of common stock upon vesting of share-based awards	0				0
Common stock withheld for income taxes on share-based awards (in shares)		(19,000)
Common stock withheld for income taxes on share-based awards	(1,623)				(1,623)
Dividends on preferred stock	(5,444)				(5,444)
Ending balance (in shares) at Dec. 31, 2022		19,097,000	62,000
Ending balance at Dec. 31, 2022	828,835	$ 2	$ (1,996)	(286)	449,243	381,872
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	$ 1,470,916					1,470,916
Conversion of preferred stock (in shares)	(8,081)	593,000
Conversion of preferred stock	$ 8,081				8,081
Stock compensation	13,525				13,525
Repurchase of common stock under Repurchase Program (in shares)		(1,470,000)
Repurchase of common stock under Repurchase Program	(151,626)			286	(151,912)
Issuance of common stock upon vesting of share-based awards (in shares)		102,000
Issuance of common stock upon vesting of share-based awards	0				0
Common stock withheld for income taxes on share-based awards (in shares)		(34,000)
Common stock withheld for income taxes on share-based awards	(3,207)				(3,207)
Dividends on preferred stock	$ (4,844)				(4)	(4,840)
Ending balance (in shares) at Dec. 31, 2023	18,300,000	18,288,000	62,000
Ending balance at Dec. 31, 2023	$ 2,161,680	$ 2	$ (1,996)	0	315,726	1,847,948
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	$ (261,386)					(261,386)
Conversion of preferred stock (in shares)	(6,866)	500,000
Conversion of preferred stock	$ 6,866				6,866
Stock compensation	16,355				16,355
Repurchase of common stock under Repurchase Program (in shares)		(1,203,000)
Repurchase of common stock under Repurchase Program	(186,271)			0	(186,271)
Issuance of common stock held in reserve (in shares)		0	62,000
Issuance of common stock held in reserve	1,996		$ 1,996
Issuance of common stock upon vesting of share-based awards (in shares)		363,000
Issuance of common stock upon vesting of share-based awards	0				0
Common stock withheld for income taxes on share-based awards (in shares)		(150,000)
Common stock withheld for income taxes on share-based awards	(23,614)				(23,614)
Dividends on preferred stock	$ (4,233)				(3)	(4,230)
Ending balance (in shares) at Dec. 31, 2024	17,800,000	17,798,000	0
Ending balance at Dec. 31, 2024	$ 1,711,393	$ 2	$ 0	$ 0	$ 129,059	$ 1,582,332

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($)	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Cash flows from operating activities:
Net (loss) income	$ (261,386,000)	$ 1,470,916,000	$ 494,701,000
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depletion, depreciation and amortization	325,723,000	319,715,000	267,761,000
Impairment of oil and natural gas properties	373,214,000	0	0
Loss on debt extinguishment	13,388,000	0	0
Net (gain) loss on derivative instruments	(29,527,000)	(740,319,000)	999,747,000
Net cash receipts (payments) on settled derivative instruments	282,637,000	152,199,000	(1,053,810,000)
Deferred income tax benefit	(56,077,000)	(525,156,000)	0
Stock-based compensation expense	10,958,000	9,480,000	5,723,000
Other, net	6,315,000	7,645,000	5,528,000
Changes in operating assets and liabilities, net	(15,212,000)	28,701,000	19,427,000
Net cash provided by operating activities	650,033,000	723,181,000	739,077,000
Cash flows from investing activities:
Additions to oil and natural gas properties	(454,098,000)	(537,360,000)	(460,780,000)
Proceeds from sale of oil and natural gas properties	225,000	2,659,000	3,360,000
Other, net	(2,120,000)	(2,526,000)	(875,000)
Net cash used in investing activities	(455,993,000)	(537,227,000)	(458,295,000)
Cash flows from financing activities:
Issuance of 2029 Senior Notes	650,000,000	0	0
Early retirement of 2026 Senior Notes	(524,298,000)	0	0
Premium paid on 2026 Senior Notes	(12,941,000)	0	0
Debt issuance costs and loan commitment fees	(14,933,000)	(7,068,000)	(234,000)
Dividends on preferred stock	(4,230,000)	(4,840,000)	(5,444,000)
Shares exchanged for tax withholdings	(23,614,000)	(3,207,000)	(1,623,000)
Other, net	(3,000)	(4,000)	0
Net cash used in financing activities	(194,496,000)	(191,284,000)	(276,783,000)
Net change in cash and cash equivalents	(456,000)	(5,330,000)	3,999,000
Cash and cash equivalents at beginning of period	1,929,000	7,259,000	3,260,000
Cash and cash equivalents at end of period	1,473,000	1,929,000	7,259,000
Nonrelated Party
Cash flows from financing activities:
Repurchase of common stock under Repurchase Program	(105,344,000)	(108,735,000)	(250,482,000)
Related Party
Cash flows from financing activities:
Repurchase of common stock under Repurchase Program	(79,133,000)	(40,430,000)	0
New Credit Facility
Cash flows from financing activities:
Principal payments on Credit Facility	(1,036,000,000)	(998,000,000)	(2,082,000,000)
Borrowings on Credit Facility	$ 956,000,000	$ 971,000,000	$ 2,063,000,000

SUMMARY OF SIGNIFICANT ACCOUNTI

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	12 Months Ended
	Dec. 31, 2024
Accounting Policies [Abstract]
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Description of Company Gulfport Energy Corporation is an independent natural gas-weighted exploration and production company focused on the exploration, acquisition and production of natural gas, crude oil and NGL in the United States with primary focus in the Appalachia and Anadarko basins. The Company's principal properties are located in eastern Ohio targeting the Utica and Marcellus and in central Oklahoma targeting the SCOOP Woodford and Springer formations. Basis of Presentation The consolidated financial statements included in this Annual Report are prepared in accordance with GAAP and the rules and regulations of the SEC. Risks and Uncertainties The Company's revenue, profitability and future growth are substantially dependent upon the prevailing and future prices for oil, gas and NGL, which are affected by many factors outside of Gulfport’s control, including changes in market supply and demand. Field-level prices received for Gulfport’s production have historically been volatile and may be subject to significant fluctuations in the future. The Company's derivative contracts serve to mitigate in part the effect of this price volatility on the Company's cash flows, and the Company has derivative contracts in place for a portion of its expected future natural gas, crude oil and NGL production. See Note 12 for further discussion of the Company's commodity derivative contracts. Principles of Consolidation The consolidated financial statements include the Company and its wholly-owned subsidiaries, Gulfport Energy Operating Corporation, 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 and Mule Sky LLC. All intercompany balances and transactions are eliminated in consolidation. Segments The Company's assets and operations consist of one reportable segment. The Company has a single management team that administers all properties as a whole rather than by geographic operating area. See Not e 2 , Segment Information, for further detail. Cash and Cash Equivalents The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents for purposes of the consolidated financial statements. Accounts Receivable The Company sells oil and natural gas to various purchasers and participates in drilling, completion and operation of oil and natural gas wells with joint interest owners on properties the Company operates. The related receivables are classified as accounts receivable—oil and natural gas sales and accounts receivable—joint interest and other, respectively. Credit is extended based on evaluation of a customer’s payment history and, generally, collateral is not required. Accounts receivable are due within 30 days and are stated at amounts due from customers, net of an allowance for doubtful accounts when the Company believes collection is doubtful. Accounts outstanding longer than the contractual payment terms are considered past due. The Company determines its allowance by considering a number of factors, including the length of time accounts receivable are past due, the Company’s previous loss history, the customer’s current ability to pay its obligation to the Company, amounts which may be obtained by an offset against production proceeds due the customer and the condition of the general economy and the industry as a whole. No material allowance was deemed necessary at December 31, 2024 and December 31, 2023. 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 to 18 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 non-cash write-down 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. The Company recognized ceiling test impairments of $373.2 million during the year ended December 31, 2024. There were no impairments recognized in 2023 or 2022. 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 $221.7 million and $204.2 million at December 31, 2024 and December 31, 2023, 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 Other property and equipment is recorded at cost. The Company expenses maintenance and repairs in the period incurred. 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. Net Income (Loss) per Common Share Basic net income (loss) 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 (loss) 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 (loss) per common share are illustrated in Note 11 . Income Taxes The amount of income taxes recorded by Gulfport requires interpretations of complex rules and regulations of various tax jurisdictions throughout the United States. 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 state jurisdictions. With few exceptions, the Company is no longer subject to U.S. federal, state and local income tax examinations by tax authorities for years prior to 2021. As of December 31, 2024, 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. See Note 10 for further discussion of the Company's income taxes. 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. Gathering, processing and compression fees attributable to gas processing, as well as any transportation fees, including firm transportation fees, incurred to deliver the product to the purchaser, are presented as transportation, gathering, processing and compression in the accompanying consolidated statements of operations. Revenue is measured based on consideration specified in the contract with the customer, and excludes any amounts collected on behalf of third parties. These contracts typically include variable consideration that is based on pricing tied to market indices and volumes delivered in the current month. As such, this market pricing may be constrained (i.e., not estimable) at the inception of the contract but will be recognized based on the applicable market pricing, which will be known upon transfer of the goods to the customer. The payment date is usually within 30 days of the end of the calendar month in which the commodity is delivered. The recognition of gains or losses on derivative instruments is outside the scope of ASC 606, Revenue from Contracts with Customers 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. Accounting for Stock-based Compensation Share-based payments to employees and members of its Board of Directors, including grants of restricted stock units and performance vesting restricted stock units, are recognized as equity at the fair value on the date of grant and to be expensed over the applicable vesting period. The vesting periods for restricted shares generally range between one year to three years with annual vesting installments. The Company does not recognize expense based on an estimate of forfeitures, but rather recognizes the impact of forfeitures only as they occur. 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 GAAP 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. Although management believes these estimates are reasonable, actual results could differ from these estimates. 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 income (loss) or total operating cash flows. Supplemental Cash Flow and Non-Cash Information (in thousands) Year Ended December 31, 2024 Year Ended December 31, 2023 Year Ended December 31, 2022 Supplemental disclosure of cash flow information: Interest payments, net of amounts capitalized $ 46,406 $ 53,820 $ 57,685 Changes in operating assets and liabilities, net: Accounts receivable - oil, natural gas, and natural gas liquids sales (33,463) 155,925 (45,550) Accounts receivable - joint interest and other 13,494 (743) (1,095) Accounts payable and accrued liabilities 4,067 (126,329) 59,879 Prepaid expenses 667 (215) 4,863 Other assets 23 63 1,330 Total changes in operating assets and liabilities, net $ (15,212) $ 28,701 $ 19,427 Supplemental disclosure of non-cash transactions: Capitalized stock-based compensation $ 5,397 $ 4,046 $ 2,948 Asset retirement obligation capitalized 682 588 2,169 Asset retirement obligation removed due to divestiture and settlements — (1,267) (7) Asset retirement obligation revisions 19 (5,077) 2,072 Release of common stock held in reserve 1,996 — 28,220 Unamortized 2026 Senior Notes debt issuance costs 447 — — Accounts Payable and Accrued Liabilities Accounts payable and accrued liabilities consisted of the following (in thousands): December 31, 2024 December 31, 2023 Revenue payable and suspense $ 139,703 $ 148,598 Accounts payable 34,668 43,517 Accrued capital expenditures 20,229 38,322 Accrued transportation, gathering, processing, and compression 36,170 32,849 Accrued contract rejection damages and shares held in reserve — 1,996 Other accrued liabilities 67,311 44,250 Total accounts payable and accrued liabilities $ 298,081 $ 309,532 Other, net Other, net in the Company's consolidated statements of operations for the year ended December 31, 2024, included approximately $4.9 million related to changes in the Company's legal reserves for certain litigation and regulatory proceedings. Additionally, Other, net included approximately $1.9 million as a result of a write-down of certain of its pipe inventory that the Company does not expect to utilize in its drilling and completion activities. As part of its Chapter 11 Cases and restructuring efforts, the Company filed motions to reject certain firm transportation agreements between the Company and affiliates of TC Energy Corporation (“TC”) and Rover Pipeline LLC (“Rover”). During the first quarter of 2023, Gulfport finalized a settlement agreement with Rover that was approved by the Bankruptcy Court on February 21, 2023. Pursuant to the settlement agreement, Gulfport and Rover agreed that the firm transportation contracts between them would be rejected. As part of the settlement, Gulfport paid a $1.0 million administrative claim, which is included in Other, net. On February 24, 2023, Gulfport received an additional $17.8 million interim distribution for its TC claim, which is also included in Other, net. Other, net in the second quarter of 2023 included a $5.0 million recoupment of previously placed collateral for certain firm transportation commitments during the Company's Chapter 11 Cases. Additionally, in the fourth quarter of 2023, Gulfport received an additional $8.3 million distribution related to its TC claim. Recent Accounting Pronouncements In November 2023, the FASB issued ASU 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures (Topic 280). The amendments require disclosure for each reportable segment, the significant expense categories and amounts that are regularly provided to the CODM and included in each reported measure of a segment’s profit or loss. Additionally, this ASU enhances interim disclosure requirements and provides new segment disclosure requirements for entities with a single reportable segment. The Company adopted ASU 2023-07 during the year ended December 31, 2024. See Note 2 , Segment Information, for further detail. In December 2023, the FASB issued ASU 2023-09, Income Taxes: Improvements to Income Tax Disclosures (Topic 740). The amendment requires annual disclosure of additional categories of information about federal, state, and foreign income taxes in the rate reconciliation table and to provide more details about the reconciling items in some categories if the items meet a quantitative threshold. Additionally, the amendment requires disclosure of annual income taxes paid (net of refunds received) disaggregated by federal, state, and foreign taxes and to disaggregate the information by jurisdiction based on a quantitative threshold. ASU 2023-09 is effective for the Company’s annual reporting periods beginning after December 15, 2024, with early adoption permitted, and should be applied on a prospective basis, with a retrospective option. The Company is currently evaluating the effect the adoption of ASU 2023-09 will have on its disclosures and does not expect it to have a material impact on its consolidated financial statements. In November 2024, the FASB issued ASU 2024-03, Disaggregation of Income Statement Expenses, which requires disclosures about specific types of expenses included in the expense captions presented on the face of the income statement as well as disclosures about selling expenses. ASU 2024-03 is effective for annual reporting periods beginning after December 15, 2026, and interim reporting periods beginning after December 15, 2027. The requirements will be applied prospectively with the option for retrospective application. The Company is currently evaluating the impact that the adoption of this accounting standard will have on its financial disclosures.

SEGMENT INFORMATION

SEGMENT INFORMATION	12 Months Ended
	Dec. 31, 2024
Segment Reporting [Abstract]
SEGMENT REPORTING	SEGMENT INFORMATION The Company's assets and operations consist of one reportable segment with all revenues, operating expenses and assets attributable to this segment reflected in the consolidated financial statements. The Company derives its revenue from the sale of natural gas, oil and condensate and NGL produced from its oil and natural gas properties located in the United States. The CODM of the Company is its Chief Executive Officer. The CODM assesses entity-wide operating results and performance and decides how to allocate resources based on net (loss) income, which is reported on the consolidated statement of operations. The measure of segment assets is reported on the consolidated balance sheets as “ total assets ”. The following table presents selected financial information with respect to the Company's one operating segment for the years ended December 31, 2024, 2023 and 2022 (in thousands): Year Ended December 31, 2024 Year Ended December 31, 2023 Year Ended December 31, 2022 Total revenues $ 958,131 $ 1,791,702 $ 1,331,112 Significant segment expenses Lease operating expenses 70,112 68,648 64,790 Taxes other than income 29,737 33,717 60,139 Transportation, gathering, processing and compression 351,237 348,631 357,246 Depreciation, depletion, and amortization 325,723 319,715 267,761 Impairment of oil and gas properties 373,214 — — General and administrative 42,558 38,600 35,304 Interest expense 59,982 57,069 59,773 Other segment expenses (1) 23,031 (20,438) (8,602) Income tax benefit (56,077) (525,156) — Total significant segment expenses 1,219,517 320,786 836,411 Net (loss) income $ (261,386) $ 1,470,916 $ 494,701 Capital expenditures (2) $ 464,492 $ 521,187 $ 470,396 _____________________ (1) Other segment expenses include “Restructuring costs”, “Accretion expense”, “Loss on debt extinguishment”, and “Other, net” from the consolidated statements of operations. (2) Capital expenditures include capitalized general and administrative costs and capitalized interest expense.

PROPERTY AND EQUIPMENT

PROPERTY AND EQUIPMENT	12 Months Ended
	Dec. 31, 2024
Property, Plant and Equipment [Abstract]
PROPERTY AND EQUIPMENT	PROPERTY AND EQUIPMENT The major categories of property and equipment and related accumulated DD&A are as follows (in thousands): December 31, 2024 December 31, 2023 Proved oil and natural gas properties $ 3,349,805 $ 2,904,519 Unproved properties 221,650 204,233 Other depreciable property and equipment 10,905 8,779 Land 386 386 Total property and equipment 3,582,746 3,117,917 Accumulated DD&A and impairment (1,564,475) (865,618) Property and equipment, net $ 2,018,271 $ 2,252,299 Oil and Natural Gas Properties 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 Company's oil and natural gas properties. During the year ended December 31, 2024, the net book value of the Company's oil and gas properties exceeded the calculated ceiling. As a result, the Company recorded a non-cash ceiling test impairment of its oil and natural gas properties of $30.5 million in the third quarter of 2024 and $342.7 million in the fourth quarter of 2024. The impairments resulted from declines in the full cost ceiling, which primarily resulted from the significant decrease in the 12-month average trailing price for natural gas. The Company did not record an impairment of its oil and natural gas properties during 2023 or 2022. Lower natural gas, oil and NGL prices can reduce the value of the Company’s assets. In addition to commodity prices, our production rates, levels of proved reserves, future development costs, transfers of unevaluated properties and other factors will determine the actual ceiling test calculation and impairment analysis in future periods. Given the decline of natural gas prices through December 2024, we may have additional ceiling test impairments of our oil and natural gas properties in subsequent quarters if the 12-month average trailing price does not improve from the $2.13 per MMBtu utilized in the fourth quarter 2024 ceiling test. Any such ceiling test impairment could be material to our net earnings; however, given the inter-relationship of the various judgements made to estimate proved reserves, it is impractical to estimate the potential changes in these estimates and their impact on the impairment. 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 $25.3 million, $22.8 million and $20.2 million for the years ended December 31, 2024, 2023 and 2022, respectively. The average depletion rate per Mcfe, which is a function of capitalized costs, future development costs and the related underlying reserves in the periods presented, was $0.84, $0.83 and $0.74 per Mcfe for the years ended December 31, 2024, 2023 and 2022, respectively. The following table summarizes the Company’s non-producing properties excluded from amortization by area (in thousands): December 31, 2024 December 31, 2023 Utica & Marcellus $ 197,513 $ 177,888 SCOOP 24,137 26,345 Total unproved properties $ 221,650 $ 204,233 The following is a summary of Gulfport’s oil and natural gas properties not subject to amortization as of December 31, 2024 (in thousands): Costs Incurred in 2024 2023 2022 Prior to 2022 Total Acquisition costs $ 58,742 $ 58,002 $ 17,288 $ 82,695 $ 216,727 Exploration costs — — — — — Development costs 1,472 556 — — 2,028 Capitalized interest 2,895 — — — 2,895 Total oil and natural gas properties not subject to amortization $ 63,109 $ 58,558 $ 17,288 $ 82,695 $ 221,650 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 years to five years. However, the majority of the Company's non-producing leases in the Utica/Marcellus have five-year extension terms, which could extend this time frame beyond five years. Asset Retirement Obligation The following table provides a reconciliation of the Company's asset retirement obligation for the years ended December 31, 2024 and 2023 (in thousands): Year Ended December 31, 2024 Year Ended December 31, 2023 Asset retirement obligation, beginning of period $ 29,941 $ 33,171 Liabilities incurred 682 588 Liabilities settled — (604) Liabilities removed due to divestitures — (919) Accretion expense 2,307 2,782 Revisions in estimated cash flows (1) 19 (5,077) Asset retirement obligation, end of period $ 32,949 $ 29,941 _____________________ (1) Revisions represent changes in the present value of liabilities resulting from changes in estimated costs.

LONG-TERM DEBT

LONG-TERM DEBT	12 Months Ended
	Dec. 31, 2024
Long-Term Debt, Unclassified [Abstract]
LONG-TERM DEBT	LONG-TERM DEBT Long-term debt consisted of the following items as of December 31, 2024 and 2023 (in thousands): December 31, 2024 December 31, 2023 6.750% senior unsecured notes due 2029 $ 650,000 $ — 8.0% senior unsecured notes due 2026 25,702 550,000 Credit Facility due 2028 38,000 — Credit Facility due 2027 — 118,000 Net unamortized debt issuance costs (10,845) (618) Total debt, net 702,857 667,382 Less: current maturities of long-term debt — — Total long-term debt, net $ 702,857 $ 667,382 2029 Senior Notes In September 2024, Gulfport Operating completed a private offering of $650.0 million aggregate principal amount of 6.750% senior notes due September 1, 2029. The 2029 Senior Notes are guaranteed on a senior unsecured basis by the Company and each of the Company's subsidiaries that guarantee the Credit Facility. Interest on the 2029 Senior Notes is payable semi-annually, on March 1 and September 1 of each year, beginning on March 1, 2025. The net proceeds from the offering, together with cash on hand were used to purchase $524.3 million of the 2026 Senior Notes in a tender offer and repay a portion of its outstanding borrowings under the Credit Facility. The 2029 Senior Notes were issued under the 2029 Senior Notes Indenture, dated as of September 13, 2024, by and among Gulfport Operating, UMB Bank, National Association, as trustee, and the Guarantors. The 2029 Senior Notes will mature on September 1, 2029. The 2029 Senior Notes Indenture contains covenants limiting Gulfport Operating’s and its restricted subsidiaries’ ability to (i) incur additional debt, (ii) make certain restricted payments, (iii) make certain investments (iv) create restrictions on distributions from restricted subsidiaries, (v) engage in specified sales of assets, (vi) enter into certain transactions among affiliates, (vii) engage in consolidations, mergers and acquisitions, (viii) create unrestricted subsidiaries (ix) incur or create liens. These covenants contain important exceptions, limitations and qualifications. At any time that the 2029 Senior Notes are rated investment grade, certain covenants will be terminated and cease to apply. 2026 Senior Notes In May 2021, Gulfport Operating issued $550 million aggregate principal amount of its 8.0% senior notes due 2026. The notes are guaranteed on a senior unsecured basis by the Company and each of the Company's subsidiaries that guarantee the Credit Facility. Interest on the 2026 Senior Notes is payable semi-annually, on June 1 and December 1 of each year. The 2026 Senior Notes were issued under the 2026 Senior Notes Indentures, dated as of May 17, 2021, by and among the Issuer, UMB Bank, National Association, as trustee, and the Guarantors and mature on May 17, 2026. The covenants of the 1145 Indenture (other than the payment covenant) require that the Company comply with the covenants of the 4(a)(2) Indenture, as amended. The 4(a)(2) Indenture contains covenants limiting the Issuer’s and its restricted subsidiaries’ ability to (i) incur additional debt, (ii) pay dividends or distributions in respect of certain equity interests or redeem, repurchase or retire certain equity interests or subordinated indebtedness, (iii) make certain investments, (iv) create restrictions on distributions from restricted subsidiaries, (v) engage in specified sales of assets, (vi) enter into certain transactions among affiliates, (vii) engage in certain lines of business, (viii) engage in consolidations, mergers and acquisitions, (ix) create unrestricted subsidiaries and (x) incur or create liens. These covenants contain important exceptions, limitations and qualifications. At any time that the 2026 Senior Notes are rated investment grade, certain covenants will be terminated and cease to apply. As noted above, in September 2024, Gulfport Operating purchased and retired $524.3 million of its 2026 Senior Notes in a tender offer using net proceeds from the 2029 Senior Notes offering. The 2026 Senior Notes were tendered at an average price equal to 102.3% of the principal amount. The retirement of the 2026 Senior Notes resulted in a loss on debt extinguishment of $13.4 million, which included cash costs of $12.9 million. Credit Facility On May 1, 2023, the Company entered into that certain Joinder, Commitment Increase and Borrowing Base Redetermination Agreement, and Third Amendment to Credit Agreement (the “Third Amendment”) which amended the Company’s Credit Facility. The Third Amendment, among other things, (a) increased the aggregate elected commitment amounts under the Credit Facility from $700 million to $900 million, (b) increased the borrowing base under the Credit Facility from $1 billion to $1.1 billion, (c) increased the excess cash threshold under the Credit Facility from $45 million to $75 million, and (d) extended the maturity date under the Credit Facility from October 14, 2025 to the earlier of (i) May 1, 2027 and (ii) the 91st day prior to the maturity date of the 2026 Senior Notes or any other permitted senior notes or any permitted refinancing debt under the Credit Facility having an aggregate outstanding principal amount equal to or exceeding $100 million; provided that such notes have not been refinanced, redeemed or repaid in full on or prior to such 91st day. On April 18, 2024, Gulfport completed its semi-annual borrowing base redetermination during which the borrowing base was reaffirmed at $1.1 billion with elected commitments remaining at $900 million. Prior to the Fourth Amendment (as defined below), the Credit Facility bore interest at a rate equal to, at the Company’s election, either (a) SOFR benchmark plus an applicable margin that varies from 2.75% to 3.75% per annum or (b) a base rate plus an applicable margin that varies from 1.75% to 2.75% per annum, based on borrowing base utilization. Prior to the Fourth Amendment, the Company was required to pay a commitment fee of 0.50% per annum on the average daily unused portion of the current aggregate commitments under the Credit Facility. The Company was also required to pay customary letter of credit and fronting fees. Prior to the Fourth Amendment, the Credit Facility required the Company to maintain as of the last day of each fiscal quarter (i) a net funded leverage ratio of less than or equal to 3.25 to 1.00, and (ii) a current ratio of greater than or equal to 1.00 to 1.00. On September 12, 2024, the Company entered into the Commitment Increase, Borrowing Base Reaffirmation Agreement, and Fourth Amendment to Credit Agreement (the “Fourth Amendment”), which amended the Company’s Third Amended and Restated Credit Agreement. The Fourth Amendment, among other things, (a) increased the aggregate elected commitment amounts under the Credit Facility to $1.0 billion, (b) reaffirmed the borrowing base under the Credit Facility at $1.1 billion, (c) extended the maturity date under the Credit Facility to September 12, 2028, and (d) reduced the pricing grid 50 bps. The Credit Facility bears interest at a rate equal to, at the Company’s election, either (a) SOFR benchmark plus an applicable margin that varies from 2.25% to 3.25% per annum or (b) a base rate plus an applicable margin that varies from 1.25% to 2.25% per annum, based on borrowing base utilization. The Company is required to pay a commitment fee that varies from 0.375% to 0.50% per annum on the average daily unused portion of the current aggregate commitments under the Credit Facility. The Company is also required to pay customary letter of credit and fronting fees. The Credit Facility requires the Company to maintain as of the last day of each fiscal quarter (i) a net funded leverage ratio of less than or equal to 3.50 to 1.00, and (ii) a current ratio of greater than or equal to 1.00 to 1.00. The obligations under the Credit Facility, certain swap obligations and certain cash management obligations, are guaranteed by the Company and the wholly-owned domestic material subsidiaries of the Borrower (collectively, the “Guarantors” and, together with the Borrower, the “Loan Parties”) and secured by substantially all of the Loan Parties’ assets (subject to customary exceptions). The Credit Facility also contains customary affirmative and negative covenants, including, among other things, as to compliance with laws (including environmental laws and anti-corruption laws), delivery of quarterly and annual financial statements and borrowing base certificates, conduct of business, maintenance of property, maintenance of insurance, entry into certain derivatives contracts, restrictions on the incurrence of liens, indebtedness, asset dispositions, restricted payments, and other customary covenants. These covenants are subject to a number of limitations and exceptions. As of December 31, 2024, the Company had $38.0 million outstanding borrowings under the Credit Facility, $63.8 million in letters of credit outstanding and was in compliance with all covenants under the credit agreement. For the years ended December 31, 2024 and 2023, the Credit Facility bore interest at a weighted average rate of 8.23% and 8.15%, respectively. Interest Expense The following schedule shows the components of interest expense for the years ended December 31, 2024, 2023 and 2022 (in thousands): Year Ended December 31, 2024 Year Ended December 31, 2023 Year Ended December 31, 2022 Cash paid for interest $ 51,177 $ 57,967 $ 57,685 Change in accrued interest 9,368 (7) (826) Capitalized interest (4,771) (4,147) — Amortization of loan costs 4,208 3,256 2,914 Other — — — Total interest expense $ 59,982 $ 57,069 $ 59,773 The Company capitalized $4.8 million and $4.1 million in interest expense for the years ended December 31, 2024 and 2023, respectively, to undeveloped oil and natural gas properties. The Company did not capitalize interest expense for the year ended December 31, 2022. Fair Value of Debt At December 31, 2024, the carrying value of the outstanding debt represented by the 2026 Senior Notes and 2029 Senior Notes were approximately $25.7 million and $639.2 million, respectively. Based on the quoted market prices (Level 1), the fair value of the 2026 Senior Notes and 2029 Senior Notes was determined to be approximately $26.0 million and $655.0 million, respectively, at December 31, 2024.

MEZZANINE EQUITY

MEZZANINE EQUITY	12 Months Ended
	Dec. 31, 2024
Equity [Abstract]
MEZZANINE EQUITY	MEZZANINE EQUITY The Company's amended and restated certificate of incorporation provides for, among other things, (i) the authority to issue 42 million shares of common stock with a par value of $0.0001 per share and (ii) the designation of 110,000 shares of preferred stock, with a par value of $0.0001 per share and a liquidation preference of $1,000 per share (the “Liquidation Preference”). Preferred Stock In May 2021, the Company issued 55,000 shares of preferred stock. Holders of preferred stock are entitled to receive cumulative quarterly dividends at a rate of 10% per annum of the Liquidation Preference with respect to cash dividends and 15% per annum of the Liquidation Preference with respect to dividends paid in kind as additional shares of preferred stock (“PIK Dividends”). Gulfport currently has the option to pay either cash dividends or PIK Dividends on a quarterly basis. Each holder of shares of preferred stock has the right (the “Conversion Right”), at its option and at any time, to convert all or a portion of the shares of preferred stock that it holds into a number of shares of common stock equal to the quotient obtained by dividing (x) the product obtained by multiplying (i) the Liquidation Preference times (ii) an amount equal to one (1) plus the Per Share Makewhole Amount (as defined in the Preferred Terms) on the date of conversion, by (y) $14.00 per share (as may be adjusted under the Preferred Terms). The shares of preferred stock outstanding at December 31, 2024 would convert to 2.7 million shares of common stock if all holders of preferred stock exercised their Conversion Right. Gulfport may redeem all, but not less than all, of the outstanding shares of preferred stock by notice to the holders of preferred stock, at the greater of (i) the aggregate value of the preferred stock, calculated by the Current Market Price (as defined in the Preferred Terms) of the number of shares of common stock into which, subject to redemption, such preferred stock would have been converted if such shares were converted pursuant to the Conversion Right at the time of such redemption and (ii) the Liquidation Preference (the “Redemption Price”). Following the Emergence Date, if there is a Fundamental Change (as defined in the Preferred Terms), Gulfport is required to redeem all, but not less than all, of the outstanding shares of preferred stock by cash payment of the Redemption Price per share of preferred stock within three (3) business days of the occurrence of such Fundamental Change. Notwithstanding the foregoing, in the event of a redemption pursuant to the preceding sentence, if Gulfport lacks sufficient cash to redeem all outstanding shares of preferred stock, the Company is required to redeem a pro rata portion of each holder’s shares of preferred stock. The preferred stock has no stated maturity and will remain outstanding indefinitely unless repurchased or redeemed by Gulfport or converted into common stock. The preferred stock has been classified as mezzanine equity in the accompanying consolidated balance sheets due to the redemption features noted above. Dividends and Conversions During the years ended December 31, 2024, 2023 and 2022 the Company paid $4.2 million, $4.8 million and $5.4 million, respectively, of cash dividends to holders of our preferred stock. The following table summarizes activity of the Company’s preferred stock for the years ended December 31, 2024 and 2023: Year Ended December 31, 2024 Year Ended December 31, 2023 Preferred stock, beginning of period 44,214 52,295 Issuance of preferred stock — — Conversion of preferred stock (6,866) (8,081) Preferred stock, end of period 37,348 44,214 EQUITY In May 2021, the Company filed an amended and restated certificate of incorporation with the Delaware Secretary of State to provide for, among other things, (i) the authority to issue 42 million shares of common stock with a par value of $0.0001 per share and (ii) the designation of 110,000 shares of preferred stock, with a par value of $0.0001 per share and a Liquidation Preference of $1,000 per share. Common Stock In May 2021, Gulfport issued approximately 19.8 million shares of common stock and 1.7 million shares of common stock were issued to the Disputed Claims Reserve. In January 2024, the remaining 62,000 shares in the Disputed Claims Reserve were issued to certain claimants. There are no remaining shares in the Disputed Claims Reserve subsequent to the January 2024 issuance. Common Stock Offering On June 26, 2023, Gulfport completed an underwritten public offering of 1.5 million shares of its common stock by certain stockholders at a price to the public of $95.00 per share. Gulfport did not sell any of its common stock as part of this offering and did not receive any proceeds from the sale of the shares sold by the selling stockholders. Concurrent with the closing of the offering, Gulfport purchased 263,158 shares of its common stock at $95.00 per share. The repurchase was part of the Company's existing Repurchase Program discussed below. On December 14, 2023, Gulfport completed an underwritten public offering of 653,464 shares of its common stock by certain stockholders at a price to the public of $128.21 per share. Gulfport did not sell any of its common stock as part of this offering and did not receive any proceeds from the sale of the shares sold by the selling stockholders. Stock Repurchase Program In November 2021 the Company's Board of Directors approved the Repurchase Program to acquire up to $100 million of common stock, which has subsequently been increased up to $1 billion and extended through December 31, 2025. Purchases under the Repurchase Program may be made from time to time in open market or privately negotiated transactions, and will be subject to available liquidity, market conditions, credit agreement restrictions, applicable legal requirements, contractual obligations and other factors. The Repurchase Program does not require the Company to acquire any specific number of shares of common stock. The Company intends to purchase shares under the Repurchase Program with available funds while maintaining sufficient liquidity to fund its capital development program. The Repurchase Program may be suspended from time to time, modified, extended or discontinued by the Board of Directors at any time. The following table summarizes activity under the Repurchase Program for the year ended December 31, 2024 (number of shares and dollar value of shares purchased shown in thousands): Total Number of Shares Purchased Dollar Value of Shares Purchased Average Price Paid Per Share First quarter 2024 210 $ 29,492 $ 140.39 Second quarter 2024 161 25,000 155.65 Third quarter 2024 341 49,862 146.17 Fourth quarter 2024 491 80,123 163.13 Total 1,203 $ 184,477 $ 153.35 As of December 31, 2024, the Company has repurchased 5.6 million shares for $584.1 million at a weighted average price of $104.88 per share since the inception of the Repurchase Program.

EQUITY

EQUITY	12 Months Ended
	Dec. 31, 2024
Equity [Abstract]
EQUITY	MEZZANINE EQUITY The Company's amended and restated certificate of incorporation provides for, among other things, (i) the authority to issue 42 million shares of common stock with a par value of $0.0001 per share and (ii) the designation of 110,000 shares of preferred stock, with a par value of $0.0001 per share and a liquidation preference of $1,000 per share (the “Liquidation Preference”). Preferred Stock In May 2021, the Company issued 55,000 shares of preferred stock. Holders of preferred stock are entitled to receive cumulative quarterly dividends at a rate of 10% per annum of the Liquidation Preference with respect to cash dividends and 15% per annum of the Liquidation Preference with respect to dividends paid in kind as additional shares of preferred stock (“PIK Dividends”). Gulfport currently has the option to pay either cash dividends or PIK Dividends on a quarterly basis. Each holder of shares of preferred stock has the right (the “Conversion Right”), at its option and at any time, to convert all or a portion of the shares of preferred stock that it holds into a number of shares of common stock equal to the quotient obtained by dividing (x) the product obtained by multiplying (i) the Liquidation Preference times (ii) an amount equal to one (1) plus the Per Share Makewhole Amount (as defined in the Preferred Terms) on the date of conversion, by (y) $14.00 per share (as may be adjusted under the Preferred Terms). The shares of preferred stock outstanding at December 31, 2024 would convert to 2.7 million shares of common stock if all holders of preferred stock exercised their Conversion Right. Gulfport may redeem all, but not less than all, of the outstanding shares of preferred stock by notice to the holders of preferred stock, at the greater of (i) the aggregate value of the preferred stock, calculated by the Current Market Price (as defined in the Preferred Terms) of the number of shares of common stock into which, subject to redemption, such preferred stock would have been converted if such shares were converted pursuant to the Conversion Right at the time of such redemption and (ii) the Liquidation Preference (the “Redemption Price”). Following the Emergence Date, if there is a Fundamental Change (as defined in the Preferred Terms), Gulfport is required to redeem all, but not less than all, of the outstanding shares of preferred stock by cash payment of the Redemption Price per share of preferred stock within three (3) business days of the occurrence of such Fundamental Change. Notwithstanding the foregoing, in the event of a redemption pursuant to the preceding sentence, if Gulfport lacks sufficient cash to redeem all outstanding shares of preferred stock, the Company is required to redeem a pro rata portion of each holder’s shares of preferred stock. The preferred stock has no stated maturity and will remain outstanding indefinitely unless repurchased or redeemed by Gulfport or converted into common stock. The preferred stock has been classified as mezzanine equity in the accompanying consolidated balance sheets due to the redemption features noted above. Dividends and Conversions During the years ended December 31, 2024, 2023 and 2022 the Company paid $4.2 million, $4.8 million and $5.4 million, respectively, of cash dividends to holders of our preferred stock. The following table summarizes activity of the Company’s preferred stock for the years ended December 31, 2024 and 2023: Year Ended December 31, 2024 Year Ended December 31, 2023 Preferred stock, beginning of period 44,214 52,295 Issuance of preferred stock — — Conversion of preferred stock (6,866) (8,081) Preferred stock, end of period 37,348 44,214 EQUITY In May 2021, the Company filed an amended and restated certificate of incorporation with the Delaware Secretary of State to provide for, among other things, (i) the authority to issue 42 million shares of common stock with a par value of $0.0001 per share and (ii) the designation of 110,000 shares of preferred stock, with a par value of $0.0001 per share and a Liquidation Preference of $1,000 per share. Common Stock In May 2021, Gulfport issued approximately 19.8 million shares of common stock and 1.7 million shares of common stock were issued to the Disputed Claims Reserve. In January 2024, the remaining 62,000 shares in the Disputed Claims Reserve were issued to certain claimants. There are no remaining shares in the Disputed Claims Reserve subsequent to the January 2024 issuance. Common Stock Offering On June 26, 2023, Gulfport completed an underwritten public offering of 1.5 million shares of its common stock by certain stockholders at a price to the public of $95.00 per share. Gulfport did not sell any of its common stock as part of this offering and did not receive any proceeds from the sale of the shares sold by the selling stockholders. Concurrent with the closing of the offering, Gulfport purchased 263,158 shares of its common stock at $95.00 per share. The repurchase was part of the Company's existing Repurchase Program discussed below. On December 14, 2023, Gulfport completed an underwritten public offering of 653,464 shares of its common stock by certain stockholders at a price to the public of $128.21 per share. Gulfport did not sell any of its common stock as part of this offering and did not receive any proceeds from the sale of the shares sold by the selling stockholders. Stock Repurchase Program In November 2021 the Company's Board of Directors approved the Repurchase Program to acquire up to $100 million of common stock, which has subsequently been increased up to $1 billion and extended through December 31, 2025. Purchases under the Repurchase Program may be made from time to time in open market or privately negotiated transactions, and will be subject to available liquidity, market conditions, credit agreement restrictions, applicable legal requirements, contractual obligations and other factors. The Repurchase Program does not require the Company to acquire any specific number of shares of common stock. The Company intends to purchase shares under the Repurchase Program with available funds while maintaining sufficient liquidity to fund its capital development program. The Repurchase Program may be suspended from time to time, modified, extended or discontinued by the Board of Directors at any time. The following table summarizes activity under the Repurchase Program for the year ended December 31, 2024 (number of shares and dollar value of shares purchased shown in thousands): Total Number of Shares Purchased Dollar Value of Shares Purchased Average Price Paid Per Share First quarter 2024 210 $ 29,492 $ 140.39 Second quarter 2024 161 25,000 155.65 Third quarter 2024 341 49,862 146.17 Fourth quarter 2024 491 80,123 163.13 Total 1,203 $ 184,477 $ 153.35 As of December 31, 2024, the Company has repurchased 5.6 million shares for $584.1 million at a weighted average price of $104.88 per share since the inception of the Repurchase Program.

STOCK-BASED COMPENSATION

STOCK-BASED COMPENSATION	12 Months Ended
	Dec. 31, 2024
Share-Based Payment Arrangement, Noncash Expense [Abstract]
STOCK-BASED COMPENSATION	STOCK-BASED COMPENSATION In May 2021, the Board of Directors adopted the Incentive Plan with a share reserve of 2.8 million shares of common stock. The Incentive Plan provides for the grant of incentive stock options, nonstatutory stock options, restricted stock, restricted stock units, stock appreciation rights, dividend equivalents and performance awards or any combination of the foregoing. The Company has granted both restricted stock units and performance vesting restricted stock units to employees and directors pursuant to the Incentive Plan, as discussed below. During the years ended December 31, 2024 and 2023, the Company's stock-based compensation expense was $16.4 million and $12.3 million of which the Company capitalized $5.4 million and $4.0 million, respectively, relating to its exploration and development efforts. Stock compensation expense, net of the amounts capitalized, is included in general and administrative expenses in the accompanying consolidated statements of operations. As of December 31, 2024, the Company has awarded an aggregate of approximately 444,493 restricted stock units and approximately 462,982 performance vesting restricted stock units under the Incentive Plan. The vesting for certain share-based awards was accelerated in the first three months of 2023 in conjunction with the restructuring activities described in Note 13 and is included in restructuring costs in the accompanying consolidated statement of operations. The following table summarizes activity for the years ended December 31, 2022, 2023 and 2024: Number of Weighted Number of Weighted Unvested shares as of December 31, 2021 198,413 $ 66.04 153,138 $ 48.54 Granted 78,192 96.90 37,666 66.82 Vested (67,564) 65.91 — — Forfeited/canceled (11,269) 80.11 — — Unvested shares as of December 31, 2022 197,772 $ 77.49 190,804 $ 52.15 Granted 104,901 88.59 83,820 58.39 Vested (101,804) 75.75 — — Forfeited/canceled (7,267) 91.61 (19,046) 49.37 Unvested shares as of December 31, 2023 193,602 $ 83.89 255,578 $ 54.40 Granted (1) 75,476 152.79 188,358 81.90 Vested (96,942) 81.14 (265,797) 48.65 Forfeited/canceled (5,122) 114.91 — — Unvested shares as of December 31, 2024 167,014 $ 115.67 178,139 $ 92.06 _____________________ (1) The table includes the impacts of performance share units granted in a prior year that vested higher than 100% of target due to the Company's TSR performance compared to peers. The aggregate fair value of share-based awards that vested during the years ended December 31, 2024, 2023 and 2022, was approximately $56.8 million, $9.9 million and $5.9 million, respectively, based on the stock price at the time of vesting. Restricted Stock Units Restricted stock units awarded under the Incentive Plan generally vest over a period of 3 years in the case of employees and 1 or 4 years in the case of directors upon the recipient meeting applicable service requirements. Stock-based compensation expense is 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 the grant. Unrecognized compensation expense as of December 31, 2024, was $12.1 million. The expense is expected to be recognized over a weighted average period of 1.72 years. Performance Vesting Restricted Stock Units The Company has awarded performance vesting restricted stock units to certain of its executive officers under the Incentive Plan. The number of shares of common stock issued pursuant to the award will be based on a combination of (i) the Company's TSR and (ii) the Company's RTSR for the performance period. Participants will earn from 0% to 200% of the target award based on the Company's TSR and RTSR ranking compared to the TSR of the companies in the Company's designated peer group at the end of the performance period. Awards will be earned and vested at the end of a three-year performance period, subject to earlier termination of the performance period in the event of a change in control. The grant date fair values were determined using the Monte Carlo simulation method and are being recorded ratably over the performance period. The table below summarizes the assumptions used in the Monte Carlo simulation to determine the grant date fair value of awards granted during the years ended December 31, 2022, 2023 and 2024: Grant date April 29, 2022 January 24, 2023 March 3, 2023 April 3, 2023 March 1, 2024 Forecast period (years) 3 3 3 3 3 Risk-free interest rates 2.87% 3.88% 4.64% 3.79% 4.36% Implied equity volatility 88.4% 87.2% 86.4% 70.8% 46.7% Stock price on the date of grant $93.98 $72.99 $82.20 $79.50 $142.00 Unrecognized compensation expense as of December 31, 2024, related to performance vesting restricted shares was $8.0 million. The expense is expected to be recognized over a weighted average period of 1.73 years.

REVENUE FROM CONTRACTS WITH CUS

REVENUE FROM CONTRACTS WITH CUSTOMERS	12 Months Ended
	Dec. 31, 2024
Revenue from Contract with Customer [Abstract]
REVENUE FROM CONTRACTS WITH CUSTOMERS	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. These sales 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. Gathering, processing and compression fees attributable to gas processing, as well as any transportation fees, including firm transportation fees, incurred to deliver the product to the purchaser, are presented as transportation, gathering, processing and compression expense in the accompanying consolidated statements of operations. 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 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 $155.9 million and $122.5 million as of December 31, 2024 and December 31, 2023, respectively, and are reported in accounts receivable - oil, natural gas, and natural gas liquids 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 each of the periods presented, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.

LEASES

LEASES	12 Months Ended
	Dec. 31, 2024
Leases [Abstract]
LEASES	LEASES Nature of Leases The Company has operating leases on certain equipment with remaining lease durations in excess of one year. The Company recognizes a right-of-use asset and lease liability on the balance sheet for all leases with lease terms of greater than one year. Short-term leases that have an initial term of one year or less are not capitalized. The Company has entered into contracts for drilling rigs with varying terms with third parties to ensure operational continuity, cost control and rig availability in its operations. The Company has concluded its drilling rig contracts are operating leases as the assets are identifiable and the Company has the right to control the identified assets. The Company's drilling rig commitments are typically structured with an initial term of less than one year. At December 31, 2024, the Company had one active long-term drilling rig contract. 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 v olatility in commodity prices, the Company is unable to determine at contract commencement with reasonable certainty if the renewal options will be exercised; therefore, renewal options are not considered in the lease term for drilling contracts. The operating lease liabilities associated with these rig commitments, when applicable, are based on the minimum contractual obligations, primarily standby rates, and do not include variable amounts based on actual activity in a given period. Pursuant to the full cost method of accounting, these costs are capitalized as part of oil and natural gas properties on the accompanying consolidated balance sheets. A portion of drilling costs are borne by other interest owners in our wells. The Company rents office space for its corporate headquarters, field locations and certain other equipment from third parties, which expire at various dates through 2027. These agreements are typically structured with non-cancelable terms of one year 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. Future amounts due under operating lease liabilities as of December 31, 2024, were as follows (in thousands): 2025 $ 5,657 2026 561 2027 10 2028 — 2029 — Total lease payments $ 6,228 Less: imputed interest (129) Total $ 6,099 Lease costs incurred for the years ended December 31, 2024 and 2023 consisted of the following (in thousands): Year Ended December 31, 2024 Year Ended December 31, 2023 Operating lease cost $ 12,828 $ 13,752 Variable lease cost — — Short-term lease cost 26,817 28,691 Total lease cost (1) $ 39,645 $ 42,443 _____________________ (1) The majority of the Company's total lease cost was capitalized to the full cost pool, and the remainder was included in either lease operating expenses or general and administrative expenses in the accompanying consolidated statements of operations. The weighted-average remaining lease term as of December 31, 2024, was 0.76 years. The weighted-average discount rate used to determine the operating lease liability as of December 31, 2024, was 6.25%.

INCOME TAXES

INCOME TAXES	12 Months Ended
	Dec. 31, 2024
Income Tax Disclosure [Abstract]
INCOME TAXES	INCOME TAXES Details of income tax provisions and deferred income taxes from continuing operations are provided in the following tables. The components of income tax benefits were as follows (in thousands): Year Ended December 31, 2024 Year Ended December 31, 2023 Year Ended December 31, 2022 Current: State $ — $ — $ — Federal — — — Deferred: State 11,747 (26,704) — Federal (67,824) (498,452) — Total income tax benefit provision $ (56,077) $ (525,156) $ — A reconciliation of the statutory federal income tax amount to the recorded benefit follows (in thousands): Year Ended December 31, 2024 Year Ended December 31, 2023 Year Ended December 31, 2022 Income (loss) before federal income taxes $ (317,463) $ 945,760 $ 494,701 Expected income tax at statutory rate (66,668) 198,610 103,887 State income taxes 4,765 (2,581) 2,227 Remeasurement of state deferred tax asset 54 — 13,869 Return to provision 5,800 (5,592) (17,075) Other differences 1,857 1,982 1,117 Change in valuation allowance due to current year activity (1,885) (717,575) (104,025) Income tax benefit recorded $ (56,077) $ (525,156) $ — For the year ended December 31, 2024, the Company's effective tax rate was 18% and an income tax benefit of $56.1 million. For the year ended December 31, 2023, the Company's effective tax rate was (56)% and an income tax benefit of $525.2 million. For the year ended December 31, 2022, the Company's effective tax rate was 0%. The higher effective income tax rate for the year ended December 31, 2024, is primarily related to the valuation allowance the Company released during the year ended December 31, 2023. The tax effects of temporary differences and net operating loss carryforwards, which give rise to deferred tax assets and liabilities at December 31, 2024 and December 31, 2023 are estimated as follows (in thousands): Year Ended December 31, 2024 Year Ended December 31, 2023 Deferred tax assets: Net operating loss carryforward and tax credits $ 345,770 $ 399,017 Oil and gas property basis difference 194,412 143,769 Investment in pass through entities 65,210 68,114 Stock-based compensation expense 1,821 1,262 Change in fair value of derivative instruments 6,106 — Other assets 56,849 52,730 Total deferred tax assets 670,168 664,892 Valuation allowance for deferred tax assets (83,695) (85,757) Deferred tax assets, net of valuation allowance 586,473 579,135 Deferred tax liabilities: Change in fair value of derivative instruments 3,401 50,448 Right of use asset 1,281 3,003 Other 558 528 Total deferred tax liabilities 5,240 53,979 Net deferred tax asset $ 581,233 $ 525,156 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. A valuation allowance for deferred tax assets, including net operating losses, is recognized when it is more likely than not that some or all of the benefit from the deferred tax assets will not be realized. To assess the likelihood, the Company uses estimates and judgment regarding future taxable income and considers the tax laws in the jurisdiction where such taxable income is generated, to determine whether a valuation allowance is required. Such evidence can include current financial position, results of operations, both actual and forecasted, the reversal of deferred tax liabilities and tax planning strategies as well as the current and forecasted business economics of the oil and gas industry. Based upon the Company’s analysis, the Company currently believes it is more-likely-than-not that a portion of the Company's federal and state deferred tax assets will be utilized. The Company has maintained a $83.7 million valuation allowance associated with its federal and state deferred tax assets. The Company will continue to evaluate both the positive and negative evidence on a quarterly basis in determining the need for a valuation allowance with respect to the deferred tax assets. Changes in positive and negative evidence, including differences between estimated and actual results, could result in changes in the valuation of the deferred tax assets that could have a material impact on the consolidated financial statements. Changes in existing tax laws could also affect actual tax results and the realization of deferred tax assets over time. The Company has an available federal tax net operating loss carryforward estimated at approximately $1.6 billion as of December 31, 2024. These federal net operating loss carryforwards of approximately $264.5 million generated in tax years prior to 2018 will begin to expire in 2036. As a result of the Tax Cuts and Jobs Act, the 2018 through 2024 federal NOL carryforwards of $1.3 billion have no expiration. The Company also has state net operating loss carryovers of approximately $394.5 million that will begin to expire in 2025.

EARNINGS (LOSS) PER SHARE

EARNINGS (LOSS) PER SHARE	12 Months Ended
	Dec. 31, 2024
Earnings Per Share [Abstract]
EARNINGS (LOSS) PER SHARE	EARNINGS (LOSS) PER SHARE Basic income or loss per share attributable to common stockholders is computed as (i) net income or loss less (ii) dividends paid to holders of preferred stock less (iii) net income or loss attributable to participating securities divided by (iv) weighted average basic shares outstanding. Diluted net income or loss per share attributable to common stockholders is computed as (i) basic net income or loss attributable to common stockholders plus (ii) diluted adjustments to income allocable to participating securities divided by (iii) weighted average diluted shares outstanding. The “if-converted” method is used to determine the dilutive impact for the Company's convertible preferred stock and the treasury stock method is used to determine the dilutive impact of unvested restricted stock. There were 0.3 million shares of restricted stock that were considered anti-dilutive for the year ended December 31, 2024. There were 0.3 million and 0.2 million shares of restricted stock that were considered dilutive for the years ended December 31, 2023 and 2022, respectively. There were 2.7 million, 3.2 million and 3.7 million potential shares of common stock issuable due to the Company's convertible preferred stock for the years ended December 31, 2024, 2023 and 2022, respectively. Reconciliations of the components of basic and diluted net (loss) income per common share are presented in the table below (in thousands): Year Ended December 31, 2024 Year Ended December 31, 2023 Year Ended December 31, 2022 Net (loss) income $ (261,386) $ 1,470,916 $ 494,701 Dividends on preferred stock (4,230) (4,840) (5,444) Participating securities - preferred stock (1) — (212,360) (76,401) Net (loss) income attributable to common stockholders $ (265,616) $ 1,253,716 $ 412,856 Re-allocation of participating securities — 2,475 512 Diluted net (loss) income attributable to common stockholders $ (265,616) $ 1,256,191 $ 413,368 Basic Shares 18,050 18,645 20,185 Dilutive Shares 18,050 18,902 20,347 Basic EPS $ (14.72) $ 67.24 $ 20.45 Dilutive EPS $ (14.72) $ 66.46 $ 20.32 _____________________ (1) Preferred stock represents participating securities because it participates in any dividends on shares of common stock on a pari passu , pro rata basis. However, preferred stock does not participate in undistributed net losses.

DERIVATIVE INSTRUMENTS

DERIVATIVE INSTRUMENTS	12 Months Ended
	Dec. 31, 2024
Derivative Instruments and Hedging Activities Disclosure [Abstract]
DERIVATIVE INSTRUMENTS	DERIVATIVE INSTRUMENTS Natural Gas, Oil and NGL Derivative Instruments The Company seeks to mitigate risks related to unfavorable changes in natural gas, oil and NGL prices, which are subject to significant and often volatile fluctuation, by entering into over-the-counter fixed price swaps, basis swaps, costless collars and various types of option contracts. These contracts allow the Company to mitigate the impact of declines in future natural gas, oil and NGL prices by effectively locking in a floor price for a certain level of the Company’s production. However, these hedge contracts also limit the benefit to the Company in periods of favorable price movements. The volume of production subject to commodity derivative instruments and the mix of the instruments are frequently evaluated and adjusted by management in response to changing market conditions. Gulfport may enter into commodity derivative contracts up to limitations set forth in its Credit Facility. The Company generally enters into commodity derivative contracts for approximately 30% to 70% of its forecasted current year annual production by the end of the first quarter of each fiscal year. The Company typically enters into commodity derivative contracts for the next 12 to 36 months. Gulfport does not enter into commodity derivative contracts for speculative purposes. The Company does not currently have any commodity derivative transactions that have margin requirements or collateral provisions that would require payments prior to the scheduled settlement dates. The Company's commodity derivative contract counterparties are typically financial institutions and energy trading firms with investment-grade credit ratings. Gulfport routinely monitors and manages its exposure to counterparty risk by requiring specific minimum credit standards for all counterparties, actively monitoring counterparties' public credit ratings and avoiding the concentration of credit exposure by transacting with multiple counterparties. The Company has master netting agreements with some counterparties that allow the offsetting of receivables and payables in a default situation. As of December 31, 2024, our commodity derivative contracts were spread among 12 counterparties. Fixed price swaps require that the Company receive a fixed price and pay a floating market price to the counterparty for the hedged commodity. They 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 Company has entered into natural gas, crude oil and NGL fixed price swap contracts based off the NYMEX Henry Hub, NYMEX WTI and Mont Belvieu C3 indices. Below is a summary of the Company's open fixed price swap positions as of December 31, 2024: Index Daily Volume Weighted Natural Gas (MMBtu/d) ($/MMBtu) 2025 NYMEX Henry Hub 250,000 $ 3.82 2026 NYMEX Henry Hub 200,000 $ 3.64 Oil (Bbl/d) ($/Bbl) 2025 NYMEX WTI 2,000 $ 74.50 NGL (Bbl/d) ($/Bbl) 2025 Mont Belvieu C3 2,504 $ 29.97 2026 Mont Belvieu C3 496 $ 29.51 Each two-way costless collar has a set floor and ceiling price for the hedged production. They are settled monthly based on differences between the floor and ceiling prices specified in the contract and the referenced settlement price. If the applicable monthly price indices are outside of the ranges set by the floor and ceiling prices in the collar contracts, the Company will cash-settle the difference with the hedge counterparty. When the referenced settlement price is less than the floor price in the contract, the Company receives an amount from the counterparty based on the price difference multiplied by the hedged contract volume. Similarly, when the referenced settlement price exceeds the ceiling price specified in the contract, the Company pays the counterparty an amount based on the price difference multiplied by the hedged contract volume. No payment is due from either party if the referenced settlement price is within the range set by the floor and ceiling prices. The Company has entered into natural gas costless collars based off the NYMEX Henry Hub index. Below is a summary of the Company's costless collar positions as of December 31, 2024: Index Daily Volume Weighted Average Floor Price Weighted Average Ceiling Price Natural Gas (MMBtu/d) ($/MMBtu) ($/MMBtu) 2025 NYMEX Henry Hub 220,000 $ 3.37 $ 4.23 2026 NYMEX Henry Hub 90,000 $ 3.35 $ 4.10 From time to time the Company has sold natural gas 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. Each sold call option has an established ceiling price. If at the time of settlement the referenced settlement price exceeds the ceiling price, 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. No payment is due from either party if the referenced settlement price is below the price ceiling. Below is a summary of the Company's open sold call option positions as of December 31, 2024: Index Daily Volume Weighted Average Ceiling Price Natural Gas (MMBtu/d) ($/MMBtu) 2025 NYMEX Henry Hub 193,315 $ 5.80 In addition, the Company has entered into natural gas basis swap positions. These instruments are arrangements that guarantee a fixed price differential to NYMEX Henry Hub from a specified delivery point. The Company receives the fixed price differential and pays the floating market price differential to the counterparty for the hedged commodity. As of December 31, 2024, the Company had the following natural gas basis swap positions open: Gulfport Pays Gulfport Receives Daily Volume Weighted Average Fixed Spread Natural Gas (MMBtu/d) ($/MMBtu) 2025 Rex Zone 3 NYMEX Plus Fixed Spread 110,000 $ (0.20) 2025 NGPL TXOK NYMEX Plus Fixed Spread 40,000 $ (0.29) 2025 TETCO M2 NYMEX Plus Fixed Spread 230,000 $ (0.96) 2025 Transco Station 85 NYMEX Plus Fixed Spread 5,000 $ 0.38 2025 TGP 500 NYMEX Plus Fixed Spread 10,000 $ 0.31 2026 Rex Zone 3 NYMEX Plus Fixed Spread 40,000 $ (0.19) 2026 NGPL TXOK NYMEX Plus Fixed Spread 30,000 $ (0.30) 2026 TETCO M2 NYMEX Plus Fixed Spread 130,000 $ (0.98) 2026 Transco Station 85 NYMEX Plus Fixed Spread 5,000 $ 0.52 2026 TGP 500 NYMEX Plus Fixed Spread 10,000 $ 0.54 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, 2024 and December 31, 2023 (in thousands): December 31, 2024 December 31, 2023 Short-term derivative asset $ 58,085 $ 233,226 Long-term derivative asset 6,003 47,566 Short-term derivative liability (41,889) (21,963) Long-term derivative liability (35,081) (18,602) Total commodity derivative position $ (12,882) $ 240,227 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, 2024, 2023 and 2022 (in thousands): Year Ended December 31, 2024 Year Ended December 31, 2023 Year Ended December 31, 2022 Natural gas derivatives - fair value (losses) gains $ (251,019) $ 584,563 $ 32,797 Natural gas derivatives - settlement gains (losses) 284,626 146,381 (1,002,098) Total gains (losses) on natural gas derivatives 33,607 730,944 (969,301) Oil and condensate derivatives - fair value gains 2,351 5,971 6,618 Oil and condensate derivatives - settlement gains (losses) 166 (3,272) (39,163) Total gains (losses) on oil and condensate derivatives 2,517 2,699 (32,545) NGL derivatives - fair value (losses) gains (4,442) (2,414) 14,648 NGL derivatives - settlement (losses) gains (2,155) 9,090 (12,549) Total (losses) gains on NGL derivatives (6,597) 6,676 2,099 Total gains (losses) on natural gas, oil and NGL derivatives $ 29,527 $ 740,319 $ (999,747) 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 (in thousands): As of December 31, 2024 Gross Assets (Liabilities) Presented in the Consolidated Balance Sheets Gross Amounts Subject to Master Netting Agreements Net Amount Derivative assets $ 64,088 $ (49,343) $ 14,745 Derivative liabilities $ (76,970) $ 49,343 $ (27,627) As of December 31, 2023 Gross Assets (Liabilities) Presented in the Consolidated Balance Sheets Gross Amounts Subject to Master Netting Agreements Net Amount Derivative assets $ 280,792 $ (30,866) $ 249,926 Derivative liabilities $ (40,565) $ 30,866 $ (9,699) Concentration of Credit Risk By using derivative instruments that are not traded on an exchange, the Company is exposed to the credit risk of its counterparties. Credit risk is the risk of loss from counterparties not performing under the terms of the derivative instrument. When the fair value of a derivative instrument is positive, the counterparty is expected to owe the Company, which creates credit risk. To minimize the credit risk in derivative instruments, it is the Company’s policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers. The Company’s derivative contracts are spread between multiple counterparties to lessen its exposure to any individual counterparty. Additionally, the Company uses master netting agreements to minimize credit risk exposure. The creditworthiness of the Company’s counterparties is subject to periodic review. None of the Company’s derivative instrument contracts contain credit-risk related contingent features. Other than as provided by the Company’s revolving credit facility, the Company is not required to provide credit support or collateral to any of its counterparties under its derivative instruments, nor are the counterparties required to provide credit support to the Company.

RESTRUCTURING COSTS

RESTRUCTURING COSTS	12 Months Ended
	Dec. 31, 2024
Restructuring and Related Activities [Abstract]
RESTRUCTURING COSTS	RESTRUCTURING COSTS

INVESTMENTS

INVESTMENTS	12 Months Ended
	Dec. 31, 2024
Equity Method Investments and Joint Ventures [Abstract]
INVESTMENTS	INVESTMENTS Grizzly Oil Sands ULC The Company, through its wholly owned subsidiary Grizzly Holdings, owns an approximate 24.5% interest in Grizzly, a Canadian unlimited liability company. As of December 31, 2024, Grizzly had approximately 830,000 acres under lease in the Athabasca, Peace River and Cold Lake oil sands regions of Alberta, Canada. The Company has not paid any cash calls since its decision to cease funding further capital calls in 2019. Grizzly’s functional currency is the Canadian dollar. The Company reduced the carrying value of its investment in Grizzly to zero upon the Emergence Date. The reduction in valuation was based upon the Company's new management's assessment of the investment and its priority for future funding in its portfolio. In particular, Grizzly’s operations remained suspended, even with improvements in the pricing environment since its initial suspension in 2015. Additionally, the Company does not anticipate funding future capital calls, which will lead to further dilution of its equity ownership interest.

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS	12 Months Ended
	Dec. 31, 2024
Fair Value Disclosures [Abstract]
FAIR VALUE MEASUREMENTS	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 (unadjusted) in active markets for identical assets and liabilities that the Company has the ability to access at the measurement date. 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. Financial assets and liabilities The following tables summarize the Company’s financial and non-financial assets and liabilities by valuation level as of December 31, 2024 and December 31, 2023 (in thousands): December 31, 2024 Level 1 Level 2 Level 3 Assets: Derivative instruments $ — $ 64,088 $ — Contingent consideration arrangement $ — $ — $ 2,700 Total assets $ — $ 64,088 $ 2,700 Liabilities: Derivative instruments $ — $ 76,970 $ — December 31, 2023 Level 1 Level 2 Level 3 Assets: Derivative instruments $ — $ 280,792 $ — Contingent consideration arrangement $ — $ — $ 2,900 Total assets $ — $ 280,792 $ 2,900 Liabilities: Derivative instruments $ — $ 40,565 $ — The Company estimates the fair value of all derivative instruments using industry-standard models that consider 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 Company's SCOOP water infrastructure sale, which closed in the first quarter of 2020, included a contingent consideration arrangement. As of December 31, 2024, the fair value of the contingent consideration was $2.7 million, of which $0.5 million is included in prepaid expenses and other current assets and $2.2 million is included in other assets in the accompanying consolidated balance sheets. The fair value of the contingent consideration arrangement is calculated using discounted cash flow techniques and is based on internal estimates of the Company's future development program and water production levels. Given the unobservable nature of the inputs, the fair value measurement of the contingent consideration arrangement is deemed to use Level 3 inputs. The Company has elected the fair value option for this contingent consideration arrangement and, therefore, records changes in fair value in earnings. The Company recognized an immaterial gain for the year ended December 31, 2024 and a loss of $1.4 million for the year ended December 31, 2023, with respect to this contingent consideration arrangement. These fair value changes are included in Other, net in the accompanying consolidated statements of operations. Non-financial assets and liabilities The initial measurement of asset retirement obligations at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with oil and gas properties. Given the unobservable nature of the inputs, including plugging costs and reserve lives, the initial measurement of the asset retirement obligation liability is deemed to use Level 3 inputs. See Note 3 for further discussion of the Company’s asset retirement obligations. Asset retirement obligations incurred were $0.7 million and $0.6 million for the years ended December 31, 2024 and 2023, respectively. Fair value of other financial instruments

RELATED PARTY TRANSACTIONS

RELATED PARTY TRANSACTIONS	12 Months Ended
	Dec. 31, 2024
Related Party Transactions [Abstract]
RELATED PARTY TRANSACTIONS	RELATED PARTY TRANSACTIONS Stock Repurchase Program The following table summarizes the Company's purchases of its common stock from Silver Point Capital, L.P. for the years ended December 31, 2023 and 2024 (dollar value of shares purchased shown in thousands): Date of Transaction Shares Repurchased Repurchase Amount Closing Date June 22, 2023 (1) 215,060 $ 20,430 June 26, 2023 December 07, 2023 146,455 $ 20,000 December 11, 2023 March 19, 2024 97,219 $ 15,002 March 19, 2024 September 19, 2024 170,000 $ 24,863 September 25, 2024 November 21, 2024 150,000 $ 26,340 December 03, 2024 December 19, 2024 79,410 $ 12,929 December 26, 2024 _____________________ (1) Concurrent with the closing of the June 2023 offering transaction discussed in Note 6 .

COMMITMENTS

COMMITMENTS	12 Months Ended
	Dec. 31, 2024
Commitments and Contingencies Disclosure [Abstract]
COMMITMENTS	COMMITMENTS Firm Transportation and Gathering Agreements The Company has contractual commitments with midstream and pipeline companies for future gathering and transportation of natural gas from the Company's producing wells to downstream markets. Under certain of these agreements, the Company has minimum daily volume commitments. The Company is also obligated under certain of these arrangements to pay a demand charge for firm capacity rights on pipeline systems regardless of the amount of pipeline capacity utilized by the Company. If the Company does not utilize the capacity, it often can release it to other counterparties, thus reducing the cost of these commitments. Working interest owners and royalty interest owners, where appropriate, will be responsible for their proportionate share of these costs. Commitments related to future firm transportation and gathering agreements are not recorded as obligations in the accompanying consolidated balance sheets; however, costs associated with utilized future firm transportation and gathering agreements are reflected in the Company's estimates of proved reserves. A summary of these commitments at December 31, 2024, are set forth in the table below (in thousands): 2025 $ 140,434 2026 134,281 2027 136,448 2028 136,604 2029 136,762 Thereafter 463,417 Total $ 1,147,946 Future Firm 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 operated production has generally been sufficient to satisfy its delivery commitments during the periods presented, and it expects its operated production will continue to be the primary means of fulfilling its future commitments. However, where the Company's operated production is not sufficient to satisfy its delivery commitments, it can and may use spot market purchases to satisfy the commitments. A summary of these volume commitments at December 31, 2024, are set forth in the table below (MMBtu per day): 2025 68,000 2026 75,000 2027 12,000 2028 — Thereafter — Total 155,000 Other Operational Commitments The Company entered into various contractual commitments to purchase inventory and other material to be used in future activities. The Company's commitment to purchase these materials exists through 2025, with approximately $13.8 million remaining. Contributions to 401(k) Plan Gulfport sponsors a 401(k) plan under which eligible employees may contribute a portion of their total compensation up to the maximum threshold through salary deferrals. The plan is considered a Safe Harbor 401(k) and provides a company match on 100% of salary deferrals that do not exceed 6% of compensation. The Company may also make discretionary elective contributions to the plan. The following table summarizes the contributions expenses related to this plan for the years ended December 31, 2024, 2023 and 2022 (in thousands): Year Ended December 31, 2024 Year Ended December 31, 2023 Year Ended December 31, 2022 Contributions expense $ 1,749 $ 1,549 $ 1,386

CONTINGENCIES

CONTINGENCIES	12 Months Ended
	Dec. 31, 2024
Commitments and Contingencies Disclosure [Abstract]
CONTINGENCIES	CONTINGENCIES The Company is involved in a number of litigation and regulatory proceedings 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. In accordance with ASC Topic 450, Contingencies , an accrual is recorded for a material loss contingency when its occurrence is probable and damages are reasonably estimable based on the anticipated most likely outcome or the minimum amount within a range of possible outcomes. Litigation and Regulatory Proceedings The Company, along with other oil and gas companies, have been named as a defendant in a number of lawsuits where Plaintiffs assert their respective leases are limited to the Utica/Marcellus shale geological formations and allege that Defendants have willfully trespassed and illegally produced oil, natural gas, and other hydrocarbon products beyond these respective formations. They also allege that Defendants engaged in conversion and were unjustly enriched. Plaintiffs seek the full value of any production from below the Utica/Marcellus shale formations, unspecified damages from the diminution of value to their mineral estate, unspecified punitive damages, and the payment of reasonable attorney fees, legal expenses, and interest. On April 27, 2021, the Bankruptcy Court for the Southern District of Texas approved a settlement agreement in which the plaintiffs fully released the Company from all claims that accrued and any damages related to the period before the effective date of the Company’s Chapter 11 plan, which occurred on May 17, 2021. The plaintiffs are continuing to pursue alleged damages after May 17, 2021. The Company received Notice and Finding of Violations (“NOV/FOVs”) from the USEPA alleging violations of the Clean Air Act at 17 locations in Ohio between 2013 and 2019. On January 22, 2020, the Company entered a Consent Decree with the Department of Justice and USEPA addressing Gulfport's failure to capture and control air emissions from storage vessels and to comply with associated inspection, recordkeeping, and reporting requirements. During the process of terminating the Consent Decree, the Company was informed that there were untimely repairs on a number of locations subject to the Company's Consent Decree that failed to comply with Subpart OOOO or Permit to Install and Operate Applications. On July 31, 2024, the Company received a NOV/FOV from USEPA related to the alleged untimely repairs. While these repairs have been completed, resolution of the matter may result in monetary sanctions exceeding $300,000. The Company also received a Demand for Stipulated Penalties for Certain Instances of Alleged Non-Compliance with Consent Decree Requirements from the United States Department of Justice (“USDOJ”) on September 5, 2024. The Company paid a $97,500 penalty to resolve the USDOJ demand for stipulated penalties. In November 2020, Robert T. Stephenson and Sandra J. Bass, as the Successor Co-Trustees of the Robert L. Stephenson Living Trust, dated January 28, 2004, and express trust; and Norma E. Stephenson, Trustee of the Norma E. Stephenson Living Trust, dated July 29, 1991, and express trust filed an action against the Company in the District Court of Grady County in the State of Oklahoma. In June 2021 the case was removed to the United States District Court for the Western District of Oklahoma. The parties have engaged in discovery and a trial has been set for Summer 2025. The complaint alleges that the Company has failed to comply with a Letter Agreement from April 1979 granting an overriding royalty interest covering 16 sections (approximately 10,240 acres). The plaintiffs seek quiet title, declaratory judgment, breach of contract, specific performance, and damages under the Oklahoma Production Revenue Standards Act. Given the nature of this matter, the Company is unable to reasonably estimate the total possible loss or ranges of loss. The Company believes it has strong defenses to these claims and intends to vigorously defend this matter; however, an adverse decision could have a material effect on the Company, its financial condition, results of operations, and cash flows. In January 2025, Grace E. Moore Great Grandchildren Trust of 2006, Joseph Gorsha, Damon Faldowski, Damon Faldowski II, and Mark Faldowski, individually and on behalf of all others similarly situated, filed a class action against Gulfport and another natural gas producer in the United States District Court, Southern District of Ohio, Eastern Division. The lawsuit alleges, among other things, that defendants underpaid royalties to the plaintiffs in connection with the production and sale of natural gas and NGL. The lawsuit seeks compensatory damages, injunctive relief regarding royalty payment practices, restitution, disgorgement of profits, prejudgment interest, post-judgment interest, attorney’s fees, and costs. Given the preliminary nature of this action, we are currently unable to estimate what, if any, liability may result from this matter. Business Operations The Company is involved in various lawsuits and disputes incidental to its business operations, including commercial disputes, personal injury claims, royalty claims, property damage claims and contract actions. Environmental Contingencies The nature of the oil and gas business carries with it certain environmental risks for Gulfport and its subsidiaries. Gulfport and its subsidiaries have implemented various policies, programs, procedures, training and audits to reduce and mitigate environmental risks. The Company conducts periodic reviews, on a company-wide basis, to assess changes in its 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, it may, among other things, exclude a property from the transaction, require the seller to remediate the property to its satisfaction in an acquisition or agree to assume liability for the remediation of the property. Other Matters Based on management’s current assessment, they are of the opinion that no pending or threatened lawsuit or dispute relating to its business operations is likely to have a material adverse effect on their future consolidated financial position, results of operations or cash flows. The final resolution of such matters could exceed amounts accrued, however, and actual results could differ materially from management’s estimates. Concentration of Credit Risk Gulfport operates in the oil and natural gas industry principally in the states of Ohio 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. At December 31, 2024, Gulfport held no cash in excess of insured limits in these banks.

SUPPLEMENTAL INFORMATION ON OIL

SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES (UNAUDITED)	12 Months Ended
	Dec. 31, 2024
Extractive Industries [Abstract]
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES (UNAUDITED)	SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES (UNAUDITED) The Company is making the following supplemental disclosures of oil and gas activities, in accordance with the full cost method of accounting for its oil and gas exploration and development activities. The Company owns a 24.5% interest in Grizzly. However, Grizzly did not have any material activity or proved reserves in the years presented below. As such, amounts related to Grizzly have been omitted below. The following table provides 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 (in thousands) Year Ended December 31, 2024 Year Ended December 31, 2023 Proved properties $ 3,349,805 $ 2,904,519 Unproved properties 221,650 204,233 Total oil and natural gas properties 3,571,455 3,108,752 Accumulated depletion and amortization (1,559,546) (862,253) Net capitalized costs $ 2,011,909 $ 2,246,499 Costs Incurred in Oil and Gas Property Acquisition, Development and Exploratory Activities (in thousands) Year Ended December 31, 2024 Year Ended December 31, 2023 Year Ended December 31, 2022 Acquisition $ 89,646 $ 93,905 $ 29,675 Development 373,284 419,431 441,458 Exploratory — — — Total $ 462,930 $ 513,336 $ 471,133 Capitalized interest is included as part of the cost of oil and natural gas properties. The Company capitalized $4.8 million and $4.1 million for the years ended December 31, 2024 and 2023, respectively, based on the Company's weighted average cost of borrowings used to finance expenditures. The Company did not capitalize interest expense for the year ended December 31, 2022. In addition to capitalized interest, the Company capitalized internal costs totaling $25.3 million, $22.8 million and $20.2 million during the years ended December 31, 2024, 2023, and 2022, respectively, which were directly related to the acquisition, exploration and development of the Company's oil and natural gas properties. Results of Operations for Producing Activities (in thousands) The following table 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. Year Ended December 31, 2024 Year Ended December 31, 2023 Year Ended December 31, 2022 Revenues $ 928,604 $ 1,051,383 $ 2,330,859 Production costs (451,086) (450,996) (482,175) Depletion (324,078) (318,473) (266,449) Impairment (373,214) — — Income tax benefit 56,077 525,156 — Results of operations from producing activities $ (163,697) $ 807,070 $ 1,582,235 Depletion per Mcf of gas equivalent (Mcfe) $ 0.84 $ 0.83 $ 0.74 Oil and Natural Gas Reserves The following table presents estimated volumes of proved developed and undeveloped oil and gas reserves as of December 31, 2024, 2023 and 2022 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, 2024, 2023 and 2022, in accordance with guidelines of the SEC applicable to reserves estimates. The prices used for the 2024 reserve report are $76.32 per barrel of oil, $2.13 per MMbtu and $31.30 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, 2023 and 2022 for reserve report purposes are $78.21 per barrel, $2.64 per MMbtu and $31.42 per barrel for NGL and $94.14 per barrel, $6.36 per MMbtu and $47.86 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. Oil (MMBbl) Natural Gas (Bcf) NGL (MMBbl) Natural Gas Equivalent (Bcfe) Proved Reserves December 31, 2021 16 3,478 54 3,898 Purchases of reserves — — — — Extensions and discoveries 3 391 5 439 Sales of reserves — — — — Revisions of prior reserve estimates — 66 — 70 Current production (2) (322) (4) (359) December 31, 2022 18 3,612 54 4,048 Purchases of reserves — — — — Extensions and discoveries 6 875 14 996 Sales of reserves — — — — Revisions of prior reserve estimates (4) (411) (1) (445) Current production (1) (350) (4) (385) December 31, 2023 19 3,725 63 4,214 Purchases of reserves — — — — Extensions and discoveries 5 398 20 547 Sales of reserves — — — — Revisions of prior reserve estimates — (413) 1 (406) Current production (1) (354) (4) (386) December 31, 2024 22 3,356 80 3,969 Proved developed reserves December 31, 2021 8 1,928 31 2,165 December 31, 2022 9 2,034 34 2,295 December 31, 2023 6 1,980 31 2,203 December 31, 2024 7 1,879 31 2,109 Proved undeveloped reserves December 31, 2021 8 1,550 22 1,733 December 31, 2022 9 1,578 20 1,752 December 31, 2023 12 1,746 32 2,011 December 31, 2024 15 1,478 49 1,861 Totals may not sum or recalculate due to rounding. In 2024, the Company experienced extensions of 547.5 Bcfe of estimated proved reserves, which were primarily attributable to the Company's continued development of its Utica/Marcellus and SCOOP acreages. Of the total extensions, 340.7 Bcfe was attributable to the addition of 33 Utica PUD locations, 92.4 Bcfe was attributable to the addition of 13 Marcellus PUD locations, and 114.4 Bcfe was attributable to the addition of 16 SCOOP PUD locations. The Company experienced total downward revisions of 406.0 Bcfe in estimated proved reserves. These consisted of upward revisions of 16.2 Bcfe as a result of positive well performance and 171.2 Bcfe due to an increase in working interest and net revenue interest as a result of our successful leasing efforts through 2024. These were offset by downward revisions of 487.9 Bcfe which were due to commodity price changes. Commodity prices experienced volatility throughout 2024 and the 12-month average price for natural gas decreased from $2.64 per MMBtu for 2023 to $2.13 per MMBtu for 2024, the 12-month average price for NGL decreased from $31.42 per barrel for 2023 to $31.30 per barrel for 2024, and the 12-month average price for crude oil decreased from $78.21 per barrel for 2023 to $76.32 per barrel for 2024. Additionally, downward revisions of 172.4 Bcfe were primarily a result of development schedule changes with some PUD well design changes. The schedule changes moved the development of 11 Utica/Marcellus PUD locations and 6 SCOOP PUD locations beyond the SEC requirement of developing these wells five years from initial booking. The development schedule changes reflect our ongoing commitment to optimizing the long-term plan to best develop our asset and maximize cash flow and overall economic returns. These locations excluded from our SEC reserves report remain in Gulfport's development plan. Finally, upward revisions of 66.9 Bcfe were a result of a combination of various economic assumption updates. In 2023, the Company experienced extensions of 995.7 Bcfe of estimated proved reserves, which were primarily attributable to the Company's continued development of its Utica/Marcellus and SCOOP acreages. Of the total extensions, 789.2 Bcfe was attributable to the addition of 67 Utica PUD locations, 88.6 Bcfe was attributable to the addition of 12 Marcellus PUD locations, and 110.4 Bcfe was attributable to the addition of 14 SCOOP PUD locations. The Company experienced total downward revisions of 444.9 Bcfe in estimated proved reserves. These consisted of upward revisions of 24.9 Bcfe as a result of positive well performance and 293.9 Bcfe due to an increase in working interest and net revenue interest as a result of our successful leasing efforts through 2023. These were offset by downward revisions of 554.9 Bcfe which were primarily a result of development schedule changes with some PUD well design changes. The schedule changes moved the development of 36 Utica/Marcellus PUD locations and 8 SCOOP PUD locations beyond the SEC requirement of developing these wells five years from initial booking. The development schedule changes reflect our ongoing commitment to optimizing the long-term plan to best develop our asset and maximize cash flow and overall economic returns. These locations excluded from our SEC reserves report remain in Gulfport's development plan. Additionally, downward revisions of 159.7 Bcfe due to commodity price changes. Commodity prices experienced volatility throughout 2023 and the 12-month average price for natural gas decreased from $6.36 per MMBtu for 2022 to $2.64 per MMBtu for 2023, the 12-month average price for NGL increased from $47.86 per barrel for 2022 to $31.42 per barrel for 2023, and the 12-month average price for crude oil decreased from $94.14 per barrel for 2022 to $78.21 per barrel for 2023. Finally, downward revisions of 49.1 Bcfe were a result of a combination of various economic assumption updates. In 2022, the Company experienced extensions of 438.9 Bcfe of estimated proved reserves, which were primarily attributable to the Company's continued development of its Utica/Marcellus and SCOOP acreages. Of the total extensions, 295.9 Bcfe was attributable to the addition of 36 PUD locations in the Utica, 72.1 Bcfe was attributable to the addition of 8 PUD locations in the Marcellus and 65.4 Bcfe was attributable to the addition of 5 PUD locations in the SCOOP. The Company experienced total upward revisions of approximately 69.7 Bcfe in estimated proved reserves, of which 47.7 Bcfe was the result of improved commodity prices. The 12-month average price for natural gas increased from $3.60 per MMBtu for 2021 to $6.36 per MMBtu for 2022, the 12-month average price for NGL increased from $31.90 per barrel for 2021 to $47.86 per barrel for 2022, and the 12-month average price for crude oil increased from $66.55 per barrel for 2021 to $94.14 per barrel for 2022. Upward revisions of 144.5 Bcfe were a result of an increase in working interest and net revenue interests as a result of our successful leasing efforts through 2022. Downward revisions of 95.6 Bcfe were experienced as a result of the SEC five-year development window, which removed 4 PUD locations in the Utica and 5 PUD locations in the SCOOP. The development plan changes reflect our commitment to optimizing the long-term development schedule to maximize cash flow and overall economic returns. A small downward revision of 26.9 Bcfe was primarily a result of performance changes to several wells and changes in PUD location forecasts. Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves The following tables present the estimated future cash flows, and changes therein, from Gulfport’s proven oil and gas reserves as of December 31, 2024, 2023 and 2022 using an unweighted average first-of-the-month price for the year January through December 31, 2024, 2023 and 2022. The average gas prices used were $2.13, $2.64 and $6.36 per MMbtu, for the years ended December 31, 2024, 2023 and 2022, respectively. The average oil prices used were $76.32, $78.21 and $94.14 per Bbl, for the years ended December 31, 2024, 2023 and 2022, respectively. The average NGL prices used were $31.30, $31.42 and $47.86 per Bbl, for the years ended December 31, 2024, 2023 and 2022, respectively. Year ended operating expenses, development costs and appropriate statutory income tax rates, with consideration of future tax rates, were used to compute the future net cash flows. All cash flows were discounted at 10% to reflect the time value of cash flows, without regard to the risk of specific properties. The estimated future costs to develop proved developed non-producing and proved undeveloped reserves are approximately $280.2 million in 2025, $318.8 million in 2026 and $259.2 million in 2027. Estimated future development costs include capital spending on major development projects. Gulfport believes cash flow from its operating activities, cash on hand and borrowings under its Credit Facility will be sufficient to cover these estimated future development costs. The assumptions used to derive the standardized measure of discounted future net cash flows are those required by accounting standards and do not necessarily reflect the Company's expectations. The information may be useful for certain comparative purposes but should not be solely relied upon in evaluating Gulfport or its performance. Furthermore, information contained in the following table may not represent realistic assessments of future cash flows, nor should the standardized measure of discounted future net cash flows be viewed as representative of the current value of the Company's reserves. Management believes that the following factors should be considered when reviewing the information below: • Future commodity prices received for selling the Company's net production will likely differ from those required to be used in these calculations. • Future operating and capital costs will likely differ from those required to be used in these calculations and do not reflect cost savings of Company owned midstream operations on future operating expenses. • Future market conditions, government regulations, reservoir conditions and risks inherent in the production of oil and condensate and gas may cause production rates in future years to vary significantly from those rates used in the calculations. • Future revenues may be subject to different production, severance and property taxation rates. • The selection of a 10% discount rate is arbitrary and may not be a reasonable factor in adjusting for future economic conditions or in considering the risk that is part of realizing future net cash flows from the reserves. The following table summarizes estimated future net cash flows from natural gas and crude oil reserves (in millions): Year Ended December 31, 2024 Year Ended December 31, 2023 Year Ended December 31, 2022 Future cash flows $ 10,474 $ 12,338 $ 26,677 Future development and abandonment costs (1,498) (1,625) (1,588) Future production costs (5,268) (5,641) (5,872) Future production taxes (212) (303) (553) Future income taxes (23) (63) (2,609) Future net cash flows 3,473 4,706 16,055 10% discount to reflect timing of cash flows (1,726) (2,323) (7,776) Standardized measure of discounted future net cash flows $ 1,747 $ 2,383 $ 8,279 Totals may not sum or recalculate due to rounding. Future development and abandonment costs include not only development costs but also all future costs to settle asset retirement obligations. The following table summarizes the total of all future costs to settle asset retirement obligations that are included in future development and abandonment costs above (in millions): Year Ended December 31, 2024 Year Ended December 31, 2023 Year Ended December 31, 2022 Future asset retirement obligations $ 240 $ 229 $ 222 Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves The principal source of change in the standardized measure of discounted future net cash flows relating to proved reserves is presented in the table below (in millions): Year Ended December 31, 2024 Year Ended December 31, 2023 Year Ended December 31, 2022 Sales and transfers of oil and gas produced, net of production costs $ (478) $ (600) $ (1,849) Net changes in prices, production costs, and development costs (910) (7,181) 5,130 Acquisition of oil and gas reserves in place — — — Extensions and discoveries 368 581 941 Previously estimated development costs incurred during the period 211 263 204 Revisions of previous quantity estimates, less related production costs (21) (278) 154 Sales of oil and gas reserves in place — — (1) Accretion of discount 238 828 414 Net changes in income taxes 16 1,219 (1,067) Change in production rates and other (60) (728) 215 Total change in standardized measure of discounted future net cash flows $ (636) $ (5,896) $ 4,141

SUBSEQUENT EVENTS

SUBSEQUENT EVENTS	12 Months Ended
	Dec. 31, 2024
Subsequent Events [Abstract]
SUBSEQUENT EVENTS	SUBSEQUENT EVENTS Natural gas, Oil and NGL Derivative Instruments Subsequent to December 31, 2024 and as of February 20, 2025, the Company entered into the following derivative contracts: Period Type of Derivative Instrument Index Daily Volume Weighted Natural Gas (MMBtu/d) ($/MMBtu) 2025 Swaps NYMEX Henry Hub 18,301 $3.85 2026 Basis Swaps Rex Zone 3 40,000 $(0.17) Oil (Bbl/d) ($/Bbl) 2025 Swaps NYMEX WTI 1,000 $70.87

Pay vs Performance Disclosure

Pay vs Performance Disclosure - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Pay vs Performance Disclosure
Net (loss) income	$ (261,386)	$ 1,470,916	$ 494,701

Insider Trading Arrangements

Insider Trading Arrangements	3 Months Ended
	Dec. 31, 2024
Trading Arrangements, by Individual
Rule 10b5-1 Arrangement Adopted	false
Non-Rule 10b5-1 Arrangement Adopted	false
Rule 10b5-1 Arrangement Terminated	false
Non-Rule 10b5-1 Arrangement Terminated	false

Insider Trading Policies and Pr

Insider Trading Policies and Procedures	12 Months Ended
	Dec. 31, 2024
Insider Trading Policies and Procedures [Line Items]
Insider Trading Policies and Procedures Adopted	true

Cybersecurity Risk Management a

Cybersecurity Risk Management and Strategy Disclosure	12 Months Ended
	Dec. 31, 2024
Cybersecurity Risk Management, Strategy, and Governance [Line Items]
Cybersecurity Risk Management Processes for Assessing, Identifying, and Managing Threats [Text Block]	Gulfport increasingly relies on digital technology to optimize our business. As our reliance on technology expands, we are exposed to additional cyber-risks, which we focus on assessing, identifying, and managing. These risks include, but are not limited to: financial risks, operational risks, safety concerns, employee and owner personal information and violation of data privacy or security laws. Managing Material Risks & Integrated Overall Risk Management We take an integrated approach to assessing and identifying cybersecurity risks and threats. At the corporate level, cybersecurity is identified as a key risk within our Enterprise Risk Management (ERM) program. Our management of cyber risk is based on the National Institute of Standards and Technology’s (NIST) cybersecurity framework. While the NIST cybersecurity framework is our foundation, we combine that with the Center for Internet Security’s (CIS) control framework. We utilize a defense-in-depth approach, layering security starting with cloud-based tools through our perimeter all the way to the client and server end points with End Point Detection and Response solutions. We continue to invest and align advances in technology to strengthen our security posture. This year we implemented tools that provide additional visibility into lateral movement, enhancements for multifactor authentication, and patching of servers. Cyber risks and incidents are categorized by severity, evaluated for materiality, responded to based on defined incident response playbooks and then remediated accordingly. We perform organized tabletop exercises to test these practices and identify areas where opportunities for improvement can occur. We acknowledge that—even with advanced security tools—we are only as strong as the people that use our technology. That is why we design phishing simulations and require multiple security trainings for every employee annually. Our partnerships with law enforcement, the Oil and Natural Gas Information Sharing Center and our third party partners continually mature our cyber program as threats evolve. Engaging Third Parties on Risk Management Recognizing the complexity and evolving nature of cybersecurity risk, we leverage strategic external partnerships to assess and mitigate cybersecurity threats to us. For example, in addition to our security analysts, we partner with third parties that provide 24/7 security operations monitoring, enhancing our response time. We are also audited by third parties for compliance with information security standards and assess vulnerabilities annually, providing additional expertise that strengthens our security posture. Managing Third Party Risk We also recognize the risks associated with the use of vendors, service providers and other third parties that provide information system services to us, process information on our behalf, or have access to our information systems, and we have processes in place to oversee and manage these risks. We maintain ongoing monitoring to ensure compliance with our cybersecurity standards. Risks from Cybersecurity Incidents
Cybersecurity Risk Management Processes Integrated [Flag]	true
Cybersecurity Risk Management Processes Integrated [Text Block]	Gulfport increasingly relies on digital technology to optimize our business. As our reliance on technology expands, we are exposed to additional cyber-risks, which we focus on assessing, identifying, and managing. These risks include, but are not limited to: financial risks, operational risks, safety concerns, employee and owner personal information and violation of data privacy or security laws.
Cybersecurity Risk Management Third Party Engaged [Flag]	true
Cybersecurity Risk Third Party Oversight and Identification Processes [Flag]	true
Cybersecurity Risk Materially Affected or Reasonably Likely to Materially Affect Registrant [Flag]	false
Cybersecurity Risk Board of Directors Oversight [Text Block]	We involve multiple levels of oversight as a part of our approach to cybersecurity risk management.
Cybersecurity Risk Board Committee or Subcommittee Responsible for Oversight [Text Block]	Board of Director Oversight
Cybersecurity Risk Process for Informing Board Committee or Subcommittee Responsible for Oversight [Text Block]	The Audit Committee receives a detailed cybersecurity update annually from the Chief Information Officer and receives a cybersecurity update quarterly through the ERM program as a key risk.
Cybersecurity Risk Role of Management [Text Block]	Our current CIO has 20 years of industry experience and over 10 years of experience with the development, training and controls of effective global enterprise cybersecurity programs. The CIO’s responsibilities include but are not limited to: (i) reviewing our enterprise risk register and functional risk register; (ii) maintaining adequate processes to manage the identified risks under our cybersecurity program; (iii) analyzing logs of cybersecurity threats and vulnerabilities; (iv) overseeing prevention, detection, mitigation and remediation efforts; and (v) developing, maintaining, and ensuring team familiarity with the above‑mentioned incident response plan. Additionally, we maintain an experienced information technology team at the employee level that supports our Chief Information Officer in implementing our cybersecurity program and internal reporting, security and mitigation functions.
Cybersecurity Risk Management Positions or Committees Responsible [Flag]	true
Cybersecurity Risk Management Positions or Committees Responsible [Text Block]	We involve multiple levels of oversight as a part of our approach to cybersecurity risk management. Risk Management Personnel Cybersecurity remains a top identified enterprise-wide risk for our business and is overseen by our Chief Information Officer who is responsible for identifying and mitigating information security risks. Our current CIO has 20 years of industry experience and over 10 years of experience with the development, training and controls of effective global enterprise cybersecurity programs. The CIO’s responsibilities include but are not limited to: (i) reviewing our enterprise risk register and functional risk register; (ii) maintaining adequate processes to manage the identified risks under our cybersecurity program; (iii) analyzing logs of cybersecurity threats and vulnerabilities; (iv) overseeing prevention, detection, mitigation and remediation efforts; and (v) developing, maintaining, and ensuring team familiarity with the above‑mentioned incident response plan. Additionally, we maintain an experienced information technology team at the employee level that supports our Chief Information Officer in implementing our cybersecurity program and internal reporting, security and mitigation functions. Board of Director Oversight
Cybersecurity Risk Management Expertise of Management Responsible [Text Block]	Our current CIO has 20 years of industry experience and over 10 years of experience with the development, training and controls of effective global enterprise cybersecurity programs.
Cybersecurity Risk Process for Informing Management or Committees Responsible [Text Block]	The Audit Committee receives a detailed cybersecurity update annually from the Chief Information Officer and receives a cybersecurity update quarterly through the ERM program as a key risk.
Cybersecurity Risk Management Positions or Committees Responsible Report to Board [Flag]	true

SUMMARY OF SIGNIFICANT ACCOUN_2

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)	12 Months Ended
	Dec. 31, 2024
Accounting Policies [Abstract]
Basis of Presentation	Basis of Presentation The consolidated financial statements included in this Annual Report are prepared in accordance with GAAP and the rules and regulations of the SEC.
Risks and Uncertainties	Risks and Uncertainties The Company's revenue, profitability and future growth are substantially dependent upon the prevailing and future prices for oil, gas and NGL, which are affected by many factors outside of Gulfport’s control, including changes in market supply and demand. Field-level prices received for Gulfport’s production have historically been volatile and may be subject to significant fluctuations in the future. The Company's derivative contracts serve to mitigate in part the effect of this price volatility on the Company's cash flows, and the Company has derivative contracts in place for a portion of its expected future natural gas, crude oil and NGL production. See Note 12
Principles of Consolidation	Principles of Consolidation The consolidated financial statements include the Company and its wholly-owned subsidiaries, Gulfport Energy Operating Corporation, 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 and Mule Sky LLC. All intercompany balances and transactions are eliminated in consolidation.
Segments	Segments
Cash and Cash Equivalents	Cash and Cash Equivalents The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents for purposes of the consolidated financial statements.
Accounts Receivable	Accounts Receivable
Oil and Gas Properties	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 to 18 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 non-cash write-down 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. The Company recognized ceiling test impairments of $373.2 million during the year ended December 31, 2024. There were no impairments recognized in 2023 or 2022. 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 $221.7 million and $204.2 million at December 31, 2024 and December 31, 2023, 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	Other Property and Equipment Other property and equipment is recorded at cost. The Company expenses maintenance and repairs in the period incurred. 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.
Net Income (Loss) per Common Share	Net Income (Loss) per Common Share
Income Taxes	Income Taxes The amount of income taxes recorded by Gulfport requires interpretations of complex rules and regulations of various tax jurisdictions throughout the United States. 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 state jurisdictions. With few exceptions, the Company is no longer subject to U.S. federal, state and local income tax examinations by tax authorities for years prior to 2021. As of December 31, 2024, 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. See Note 10
Revenue Recognition	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. Gathering, processing and compression fees attributable to gas processing, as well as any transportation fees, including firm transportation fees, incurred to deliver the product to the purchaser, are presented as transportation, gathering, processing and compression in the accompanying consolidated statements of operations. Revenue is measured based on consideration specified in the contract with the customer, and excludes any amounts collected on behalf of third parties. These contracts typically include variable consideration that is based on pricing tied to market indices and volumes delivered in the current month. As such, this market pricing may be constrained (i.e., not estimable) at the inception of the contract but will be recognized based on the applicable market pricing, which will be known upon transfer of the goods to the customer. The payment date is usually within 30 days of the end of the calendar month in which the commodity is delivered. The recognition of gains or losses on derivative instruments is outside the scope of ASC 606, Revenue from Contracts with Customers 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.
Accounting for Stock-based Compensation	Accounting for Stock-based Compensation
Derivative Instruments	Derivative Instruments
Use of Estimates	Use of Estimates
Reclassification	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 income (loss) or total operating cash flows.
Recent Accounting Pronouncements	Recent Accounting Pronouncements In November 2023, the FASB issued ASU 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures (Topic 280). The amendments require disclosure for each reportable segment, the significant expense categories and amounts that are regularly provided to the CODM and included in each reported measure of a segment’s profit or loss. Additionally, this ASU enhances interim disclosure requirements and provides new segment disclosure requirements for entities with a single reportable segment. The Company adopted ASU 2023-07 during the year ended December 31, 2024. See Note 2 , Segment Information, for further detail. In December 2023, the FASB issued ASU 2023-09, Income Taxes: Improvements to Income Tax Disclosures (Topic 740). The amendment requires annual disclosure of additional categories of information about federal, state, and foreign income taxes in the rate reconciliation table and to provide more details about the reconciling items in some categories if the items meet a quantitative threshold. Additionally, the amendment requires disclosure of annual income taxes paid (net of refunds received) disaggregated by federal, state, and foreign taxes and to disaggregate the information by jurisdiction based on a quantitative threshold. ASU 2023-09 is effective for the Company’s annual reporting periods beginning after December 15, 2024, with early adoption permitted, and should be applied on a prospective basis, with a retrospective option. The Company is currently evaluating the effect the adoption of ASU 2023-09 will have on its disclosures and does not expect it to have a material impact on its consolidated financial statements. In November 2024, the FASB issued ASU 2024-03, Disaggregation of Income Statement Expenses, which requires disclosures about specific types of expenses included in the expense captions presented on the face of the income statement as well as disclosures about selling expenses. ASU 2024-03 is effective for annual reporting periods beginning after December 15, 2026, and interim reporting periods beginning after December 15, 2027. The requirements will be applied prospectively with the option for retrospective application. The Company is currently evaluating the impact that the adoption of this accounting standard will have on its financial disclosures.

SUMMARY OF SIGNIFICANT ACCOUN_3

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)	12 Months Ended
	Dec. 31, 2024
Accounting Policies [Abstract]
Schedule of Cash Flow, Supplemental Disclosures	Supplemental Cash Flow and Non-Cash Information (in thousands) Year Ended December 31, 2024 Year Ended December 31, 2023 Year Ended December 31, 2022 Supplemental disclosure of cash flow information: Interest payments, net of amounts capitalized $ 46,406 $ 53,820 $ 57,685 Changes in operating assets and liabilities, net: Accounts receivable - oil, natural gas, and natural gas liquids sales (33,463) 155,925 (45,550) Accounts receivable - joint interest and other 13,494 (743) (1,095) Accounts payable and accrued liabilities 4,067 (126,329) 59,879 Prepaid expenses 667 (215) 4,863 Other assets 23 63 1,330 Total changes in operating assets and liabilities, net $ (15,212) $ 28,701 $ 19,427 Supplemental disclosure of non-cash transactions: Capitalized stock-based compensation $ 5,397 $ 4,046 $ 2,948 Asset retirement obligation capitalized 682 588 2,169 Asset retirement obligation removed due to divestiture and settlements — (1,267) (7) Asset retirement obligation revisions 19 (5,077) 2,072 Release of common stock held in reserve 1,996 — 28,220 Unamortized 2026 Senior Notes debt issuance costs 447 — —
Schedule of Accounts Payable and Accrued Liabilities	Accounts payable and accrued liabilities consisted of the following (in thousands): December 31, 2024 December 31, 2023 Revenue payable and suspense $ 139,703 $ 148,598 Accounts payable 34,668 43,517 Accrued capital expenditures 20,229 38,322 Accrued transportation, gathering, processing, and compression 36,170 32,849 Accrued contract rejection damages and shares held in reserve — 1,996 Other accrued liabilities 67,311 44,250 Total accounts payable and accrued liabilities $ 298,081 $ 309,532

SEGMENT INFORMATION (Tables)

SEGMENT INFORMATION (Tables)	12 Months Ended
	Dec. 31, 2024
Segment Reporting [Abstract]
Schedule of Segment Reporting	The following table presents selected financial information with respect to the Company's one operating segment for the years ended December 31, 2024, 2023 and 2022 (in thousands): Year Ended December 31, 2024 Year Ended December 31, 2023 Year Ended December 31, 2022 Total revenues $ 958,131 $ 1,791,702 $ 1,331,112 Significant segment expenses Lease operating expenses 70,112 68,648 64,790 Taxes other than income 29,737 33,717 60,139 Transportation, gathering, processing and compression 351,237 348,631 357,246 Depreciation, depletion, and amortization 325,723 319,715 267,761 Impairment of oil and gas properties 373,214 — — General and administrative 42,558 38,600 35,304 Interest expense 59,982 57,069 59,773 Other segment expenses (1) 23,031 (20,438) (8,602) Income tax benefit (56,077) (525,156) — Total significant segment expenses 1,219,517 320,786 836,411 Net (loss) income $ (261,386) $ 1,470,916 $ 494,701 Capital expenditures (2) $ 464,492 $ 521,187 $ 470,396 _____________________ (1) Other segment expenses include “Restructuring costs”, “Accretion expense”, “Loss on debt extinguishment”, and “Other, net” from the consolidated statements of operations. (2) Capital expenditures include capitalized general and administrative costs and capitalized interest expense.

PROPERTY AND EQUIPMENT (Tables)

PROPERTY AND EQUIPMENT (Tables)	12 Months Ended
	Dec. 31, 2024
Property, Plant and Equipment [Abstract]
Schedule of Property and Equipment	The major categories of property and equipment and related accumulated DD&A are as follows (in thousands): December 31, 2024 December 31, 2023 Proved oil and natural gas properties $ 3,349,805 $ 2,904,519 Unproved properties 221,650 204,233 Other depreciable property and equipment 10,905 8,779 Land 386 386 Total property and equipment 3,582,746 3,117,917 Accumulated DD&A and impairment (1,564,475) (865,618) Property and equipment, net $ 2,018,271 $ 2,252,299
Schedule of Oil and Gas Properties Not Subject to Amortization	The following table summarizes the Company’s non-producing properties excluded from amortization by area (in thousands): December 31, 2024 December 31, 2023 Utica & Marcellus $ 197,513 $ 177,888 SCOOP 24,137 26,345 Total unproved properties $ 221,650 $ 204,233 The following is a summary of Gulfport’s oil and natural gas properties not subject to amortization as of December 31, 2024 (in thousands): Costs Incurred in 2024 2023 2022 Prior to 2022 Total Acquisition costs $ 58,742 $ 58,002 $ 17,288 $ 82,695 $ 216,727 Exploration costs — — — — — Development costs 1,472 556 — — 2,028 Capitalized interest 2,895 — — — 2,895 Total oil and natural gas properties not subject to amortization $ 63,109 $ 58,558 $ 17,288 $ 82,695 $ 221,650
Schedule of Asset Retirement Obligation	The following table provides a reconciliation of the Company's asset retirement obligation for the years ended December 31, 2024 and 2023 (in thousands): Year Ended December 31, 2024 Year Ended December 31, 2023 Asset retirement obligation, beginning of period $ 29,941 $ 33,171 Liabilities incurred 682 588 Liabilities settled — (604) Liabilities removed due to divestitures — (919) Accretion expense 2,307 2,782 Revisions in estimated cash flows (1) 19 (5,077) Asset retirement obligation, end of period $ 32,949 $ 29,941 _____________________ (1) Revisions represent changes in the present value of liabilities resulting from changes in estimated costs.

LONG-TERM DEBT (Tables)

LONG-TERM DEBT (Tables)	12 Months Ended
	Dec. 31, 2024
Long-Term Debt, Unclassified [Abstract]
Schedule of Long-Term Debt	Long-term debt consisted of the following items as of December 31, 2024 and 2023 (in thousands): December 31, 2024 December 31, 2023 6.750% senior unsecured notes due 2029 $ 650,000 $ — 8.0% senior unsecured notes due 2026 25,702 550,000 Credit Facility due 2028 38,000 — Credit Facility due 2027 — 118,000 Net unamortized debt issuance costs (10,845) (618) Total debt, net 702,857 667,382 Less: current maturities of long-term debt — — Total long-term debt, net $ 702,857 $ 667,382
Schedule of Interest Expense	The following schedule shows the components of interest expense for the years ended December 31, 2024, 2023 and 2022 (in thousands): Year Ended December 31, 2024 Year Ended December 31, 2023 Year Ended December 31, 2022 Cash paid for interest $ 51,177 $ 57,967 $ 57,685 Change in accrued interest 9,368 (7) (826) Capitalized interest (4,771) (4,147) — Amortization of loan costs 4,208 3,256 2,914 Other — — — Total interest expense $ 59,982 $ 57,069 $ 59,773

MEZZANINE EQUITY (Tables)

MEZZANINE EQUITY (Tables)	12 Months Ended
	Dec. 31, 2024
Equity [Abstract]
Schedule of Movement on Temporary Equity	The following table summarizes activity of the Company’s preferred stock for the years ended December 31, 2024 and 2023: Year Ended December 31, 2024 Year Ended December 31, 2023 Preferred stock, beginning of period 44,214 52,295 Issuance of preferred stock — — Conversion of preferred stock (6,866) (8,081) Preferred stock, end of period 37,348 44,214

EQUITY (Tables)

EQUITY (Tables)	12 Months Ended
	Dec. 31, 2024
Equity [Abstract]
Schedule of Stockholders Equity	The following table summarizes activity under the Repurchase Program for the year ended December 31, 2024 (number of shares and dollar value of shares purchased shown in thousands): Total Number of Shares Purchased Dollar Value of Shares Purchased Average Price Paid Per Share First quarter 2024 210 $ 29,492 $ 140.39 Second quarter 2024 161 25,000 155.65 Third quarter 2024 341 49,862 146.17 Fourth quarter 2024 491 80,123 163.13 Total 1,203 $ 184,477 $ 153.35

STOCK-BASED COMPENSATION (Table

STOCK-BASED COMPENSATION (Tables)	12 Months Ended
	Dec. 31, 2024
Share-Based Payment Arrangement, Noncash Expense [Abstract]
Schedule of Restricted Stock Award and Unit Activity	The following table summarizes activity for the years ended December 31, 2022, 2023 and 2024: Number of Weighted Number of Weighted Unvested shares as of December 31, 2021 198,413 $ 66.04 153,138 $ 48.54 Granted 78,192 96.90 37,666 66.82 Vested (67,564) 65.91 — — Forfeited/canceled (11,269) 80.11 — — Unvested shares as of December 31, 2022 197,772 $ 77.49 190,804 $ 52.15 Granted 104,901 88.59 83,820 58.39 Vested (101,804) 75.75 — — Forfeited/canceled (7,267) 91.61 (19,046) 49.37 Unvested shares as of December 31, 2023 193,602 $ 83.89 255,578 $ 54.40 Granted (1) 75,476 152.79 188,358 81.90 Vested (96,942) 81.14 (265,797) 48.65 Forfeited/canceled (5,122) 114.91 — — Unvested shares as of December 31, 2024 167,014 $ 115.67 178,139 $ 92.06 _____________________ (1) The table includes the impacts of performance share units granted in a prior year that vested higher than 100% of target due to the Company's TSR performance compared to peers.
Schedule of Grant Date Fair Value of Awards Granted	The table below summarizes the assumptions used in the Monte Carlo simulation to determine the grant date fair value of awards granted during the years ended December 31, 2022, 2023 and 2024: Grant date April 29, 2022 January 24, 2023 March 3, 2023 April 3, 2023 March 1, 2024 Forecast period (years) 3 3 3 3 3 Risk-free interest rates 2.87% 3.88% 4.64% 3.79% 4.36% Implied equity volatility 88.4% 87.2% 86.4% 70.8% 46.7% Stock price on the date of grant $93.98 $72.99 $82.20 $79.50 $142.00

LEASES (Tables)

LEASES (Tables)	12 Months Ended
	Dec. 31, 2024
Leases [Abstract]
Schedule of Operating Lease Liability	Future amounts due under operating lease liabilities as of December 31, 2024, were as follows (in thousands): 2025 $ 5,657 2026 561 2027 10 2028 — 2029 — Total lease payments $ 6,228 Less: imputed interest (129) Total $ 6,099
Schedule of Lease Cost	Lease costs incurred for the years ended December 31, 2024 and 2023 consisted of the following (in thousands): Year Ended December 31, 2024 Year Ended December 31, 2023 Operating lease cost $ 12,828 $ 13,752 Variable lease cost — — Short-term lease cost 26,817 28,691 Total lease cost (1) $ 39,645 $ 42,443 _____________________ (1) The majority of the Company's total lease cost was capitalized to the full cost pool, and the remainder was included in either lease operating expenses or general and administrative expenses in the accompanying consolidated statements of operations.

INCOME TAXES (Tables)

INCOME TAXES (Tables)	12 Months Ended
	Dec. 31, 2024
Income Tax Disclosure [Abstract]
Schedule of Income Tax Provision (Benefit)	The components of income tax benefits were as follows (in thousands): Year Ended December 31, 2024 Year Ended December 31, 2023 Year Ended December 31, 2022 Current: State $ — $ — $ — Federal — — — Deferred: State 11,747 (26,704) — Federal (67,824) (498,452) — Total income tax benefit provision $ (56,077) $ (525,156) $ —
Schedule of Reconciliation to the Statutory Federal Income Tax	A reconciliation of the statutory federal income tax amount to the recorded benefit follows (in thousands): Year Ended December 31, 2024 Year Ended December 31, 2023 Year Ended December 31, 2022 Income (loss) before federal income taxes $ (317,463) $ 945,760 $ 494,701 Expected income tax at statutory rate (66,668) 198,610 103,887 State income taxes 4,765 (2,581) 2,227 Remeasurement of state deferred tax asset 54 — 13,869 Return to provision 5,800 (5,592) (17,075) Other differences 1,857 1,982 1,117 Change in valuation allowance due to current year activity (1,885) (717,575) (104,025) Income tax benefit recorded $ (56,077) $ (525,156) $ —
Schedule of Deferred Tax Assets and Liabilities	The tax effects of temporary differences and net operating loss carryforwards, which give rise to deferred tax assets and liabilities at December 31, 2024 and December 31, 2023 are estimated as follows (in thousands): Year Ended December 31, 2024 Year Ended December 31, 2023 Deferred tax assets: Net operating loss carryforward and tax credits $ 345,770 $ 399,017 Oil and gas property basis difference 194,412 143,769 Investment in pass through entities 65,210 68,114 Stock-based compensation expense 1,821 1,262 Change in fair value of derivative instruments 6,106 — Other assets 56,849 52,730 Total deferred tax assets 670,168 664,892 Valuation allowance for deferred tax assets (83,695) (85,757) Deferred tax assets, net of valuation allowance 586,473 579,135 Deferred tax liabilities: Change in fair value of derivative instruments 3,401 50,448 Right of use asset 1,281 3,003 Other 558 528 Total deferred tax liabilities 5,240 53,979 Net deferred tax asset $ 581,233 $ 525,156

EARNINGS (LOSS) PER SHARE (Tabl

EARNINGS (LOSS) PER SHARE (Tables)	12 Months Ended
	Dec. 31, 2024
Earnings Per Share [Abstract]
Schedule of Earnings (Loss) Per Share	Reconciliations of the components of basic and diluted net (loss) income per common share are presented in the table below (in thousands): Year Ended December 31, 2024 Year Ended December 31, 2023 Year Ended December 31, 2022 Net (loss) income $ (261,386) $ 1,470,916 $ 494,701 Dividends on preferred stock (4,230) (4,840) (5,444) Participating securities - preferred stock (1) — (212,360) (76,401) Net (loss) income attributable to common stockholders $ (265,616) $ 1,253,716 $ 412,856 Re-allocation of participating securities — 2,475 512 Diluted net (loss) income attributable to common stockholders $ (265,616) $ 1,256,191 $ 413,368 Basic Shares 18,050 18,645 20,185 Dilutive Shares 18,050 18,902 20,347 Basic EPS $ (14.72) $ 67.24 $ 20.45 Dilutive EPS $ (14.72) $ 66.46 $ 20.32 _____________________ (1) Preferred stock represents participating securities because it participates in any dividends on shares of common stock on a pari passu , pro rata basis. However, preferred stock does not participate in undistributed net losses.

DERIVATIVE INSTRUMENTS (Tables)

DERIVATIVE INSTRUMENTS (Tables)	12 Months Ended
	Dec. 31, 2024
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Open Fixed Price Swap Positions	Below is a summary of the Company's open fixed price swap positions as of December 31, 2024: Index Daily Volume Weighted Natural Gas (MMBtu/d) ($/MMBtu) 2025 NYMEX Henry Hub 250,000 $ 3.82 2026 NYMEX Henry Hub 200,000 $ 3.64 Oil (Bbl/d) ($/Bbl) 2025 NYMEX WTI 2,000 $ 74.50 NGL (Bbl/d) ($/Bbl) 2025 Mont Belvieu C3 2,504 $ 29.97 2026 Mont Belvieu C3 496 $ 29.51 Index Daily Volume Weighted Average Floor Price Weighted Average Ceiling Price Natural Gas (MMBtu/d) ($/MMBtu) ($/MMBtu) 2025 NYMEX Henry Hub 220,000 $ 3.37 $ 4.23 2026 NYMEX Henry Hub 90,000 $ 3.35 $ 4.10 Index Daily Volume Weighted Average Ceiling Price Natural Gas (MMBtu/d) ($/MMBtu) 2025 NYMEX Henry Hub 193,315 $ 5.80
Schedule of Natural Gas Basis Swap Positions	As of December 31, 2024, the Company had the following natural gas basis swap positions open: Gulfport Pays Gulfport Receives Daily Volume Weighted Average Fixed Spread Natural Gas (MMBtu/d) ($/MMBtu) 2025 Rex Zone 3 NYMEX Plus Fixed Spread 110,000 $ (0.20) 2025 NGPL TXOK NYMEX Plus Fixed Spread 40,000 $ (0.29) 2025 TETCO M2 NYMEX Plus Fixed Spread 230,000 $ (0.96) 2025 Transco Station 85 NYMEX Plus Fixed Spread 5,000 $ 0.38 2025 TGP 500 NYMEX Plus Fixed Spread 10,000 $ 0.31 2026 Rex Zone 3 NYMEX Plus Fixed Spread 40,000 $ (0.19) 2026 NGPL TXOK NYMEX Plus Fixed Spread 30,000 $ (0.30) 2026 TETCO M2 NYMEX Plus Fixed Spread 130,000 $ (0.98) 2026 Transco Station 85 NYMEX Plus Fixed Spread 5,000 $ 0.52 2026 TGP 500 NYMEX Plus Fixed Spread 10,000 $ 0.54 Subsequent to December 31, 2024 and as of February 20, 2025, the Company entered into the following derivative contracts: Period Type of Derivative Instrument Index Daily Volume Weighted Natural Gas (MMBtu/d) ($/MMBtu) 2025 Swaps NYMEX Henry Hub 18,301 $3.85 2026 Basis Swaps Rex Zone 3 40,000 $(0.17) Oil (Bbl/d) ($/Bbl) 2025 Swaps NYMEX WTI 1,000 $70.87
Schedule of Derivative Instruments On a Gross Basis	The following table presents the fair value of the Company's derivative instruments on a gross basis at December 31, 2024 and December 31, 2023 (in thousands): December 31, 2024 December 31, 2023 Short-term derivative asset $ 58,085 $ 233,226 Long-term derivative asset 6,003 47,566 Short-term derivative liability (41,889) (21,963) Long-term derivative liability (35,081) (18,602) Total commodity derivative position $ (12,882) $ 240,227
Schedule of Net Gain (Loss) On Derivatives	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, 2024, 2023 and 2022 (in thousands): Year Ended December 31, 2024 Year Ended December 31, 2023 Year Ended December 31, 2022 Natural gas derivatives - fair value (losses) gains $ (251,019) $ 584,563 $ 32,797 Natural gas derivatives - settlement gains (losses) 284,626 146,381 (1,002,098) Total gains (losses) on natural gas derivatives 33,607 730,944 (969,301) Oil and condensate derivatives - fair value gains 2,351 5,971 6,618 Oil and condensate derivatives - settlement gains (losses) 166 (3,272) (39,163) Total gains (losses) on oil and condensate derivatives 2,517 2,699 (32,545) NGL derivatives - fair value (losses) gains (4,442) (2,414) 14,648 NGL derivatives - settlement (losses) gains (2,155) 9,090 (12,549) Total (losses) gains on NGL derivatives (6,597) 6,676 2,099 Total gains (losses) on natural gas, oil and NGL derivatives $ 29,527 $ 740,319 $ (999,747)
Schedule of Recognized Derivative Assets	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 (in thousands): As of December 31, 2024 Gross Assets (Liabilities) Presented in the Consolidated Balance Sheets Gross Amounts Subject to Master Netting Agreements Net Amount Derivative assets $ 64,088 $ (49,343) $ 14,745 Derivative liabilities $ (76,970) $ 49,343 $ (27,627) As of December 31, 2023 Gross Assets (Liabilities) Presented in the Consolidated Balance Sheets Gross Amounts Subject to Master Netting Agreements Net Amount Derivative assets $ 280,792 $ (30,866) $ 249,926 Derivative liabilities $ (40,565) $ 30,866 $ (9,699)
Schedule of Recognized Derivative Liabilities	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 (in thousands): As of December 31, 2024 Gross Assets (Liabilities) Presented in the Consolidated Balance Sheets Gross Amounts Subject to Master Netting Agreements Net Amount Derivative assets $ 64,088 $ (49,343) $ 14,745 Derivative liabilities $ (76,970) $ 49,343 $ (27,627) As of December 31, 2023 Gross Assets (Liabilities) Presented in the Consolidated Balance Sheets Gross Amounts Subject to Master Netting Agreements Net Amount Derivative assets $ 280,792 $ (30,866) $ 249,926 Derivative liabilities $ (40,565) $ 30,866 $ (9,699)

FAIR VALUE MEASUREMENTS (Tables

FAIR VALUE MEASUREMENTS (Tables)	12 Months Ended
	Dec. 31, 2024
Fair Value Disclosures [Abstract]
Schedule of Fair Value Measurements	The following tables summarize the Company’s financial and non-financial assets and liabilities by valuation level as of December 31, 2024 and December 31, 2023 (in thousands): December 31, 2024 Level 1 Level 2 Level 3 Assets: Derivative instruments $ — $ 64,088 $ — Contingent consideration arrangement $ — $ — $ 2,700 Total assets $ — $ 64,088 $ 2,700 Liabilities: Derivative instruments $ — $ 76,970 $ — December 31, 2023 Level 1 Level 2 Level 3 Assets: Derivative instruments $ — $ 280,792 $ — Contingent consideration arrangement $ — $ — $ 2,900 Total assets $ — $ 280,792 $ 2,900 Liabilities: Derivative instruments $ — $ 40,565 $ —

RELATED PARTY TRANSACTIONS (Tab

RELATED PARTY TRANSACTIONS (Tables)	12 Months Ended
	Dec. 31, 2024
Related Party Transactions [Abstract]
Schedule of The Following Table Summarizes the Company's Purchases of its Common Stock	The following table summarizes the Company's purchases of its common stock from Silver Point Capital, L.P. for the years ended December 31, 2023 and 2024 (dollar value of shares purchased shown in thousands): Date of Transaction Shares Repurchased Repurchase Amount Closing Date June 22, 2023 (1) 215,060 $ 20,430 June 26, 2023 December 07, 2023 146,455 $ 20,000 December 11, 2023 March 19, 2024 97,219 $ 15,002 March 19, 2024 September 19, 2024 170,000 $ 24,863 September 25, 2024 November 21, 2024 150,000 $ 26,340 December 03, 2024 December 19, 2024 79,410 $ 12,929 December 26, 2024 _____________________ (1) Concurrent with the closing of the June 2023 offering transaction discussed in Note 6 .

COMMITMENTS (Tables)

COMMITMENTS (Tables)	12 Months Ended
	Dec. 31, 2024
Commitments and Contingencies Disclosure [Abstract]
Schedule of Future Service Commitments	A summary of these commitments at December 31, 2024, are set forth in the table below (in thousands): 2025 $ 140,434 2026 134,281 2027 136,448 2028 136,604 2029 136,762 Thereafter 463,417 Total $ 1,147,946 A summary of these volume commitments at December 31, 2024, are set forth in the table below (MMBtu per day): 2025 68,000 2026 75,000 2027 12,000 2028 — Thereafter — Total 155,000
Schedule of Contributions Expenses	The following table summarizes the contributions expenses related to this plan for the years ended December 31, 2024, 2023 and 2022 (in thousands): Year Ended December 31, 2024 Year Ended December 31, 2023 Year Ended December 31, 2022 Contributions expense $ 1,749 $ 1,549 $ 1,386

SUPPLEMENTAL INFORMATION ON O_2

SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES (UNAUDITED) (Tables)	12 Months Ended
	Dec. 31, 2024
Extractive Industries [Abstract]
Schedule of Capitalized Costs Related to Oil and Gas Producing Activities	Capitalized Costs Related to Oil and Gas Producing Activities (in thousands) Year Ended December 31, 2024 Year Ended December 31, 2023 Proved properties $ 3,349,805 $ 2,904,519 Unproved properties 221,650 204,233 Total oil and natural gas properties 3,571,455 3,108,752 Accumulated depletion and amortization (1,559,546) (862,253) Net capitalized costs $ 2,011,909 $ 2,246,499
Schedule of Cost Incurred in Oil and Gas Property Acquisition and Development Activities	Costs Incurred in Oil and Gas Property Acquisition, Development and Exploratory Activities (in thousands) Year Ended December 31, 2024 Year Ended December 31, 2023 Year Ended December 31, 2022 Acquisition $ 89,646 $ 93,905 $ 29,675 Development 373,284 419,431 441,458 Exploratory — — — Total $ 462,930 $ 513,336 $ 471,133
Schedule of Results of Operations for Oil and Gas Production Activities	The results of operations exclude general office overhead and interest expense attributable to oil and gas production. Year Ended December 31, 2024 Year Ended December 31, 2023 Year Ended December 31, 2022 Revenues $ 928,604 $ 1,051,383 $ 2,330,859 Production costs (451,086) (450,996) (482,175) Depletion (324,078) (318,473) (266,449) Impairment (373,214) — — Income tax benefit 56,077 525,156 — Results of operations from producing activities $ (163,697) $ 807,070 $ 1,582,235 Depletion per Mcf of gas equivalent (Mcfe) $ 0.84 $ 0.83 $ 0.74
Schedule of Oil and Gas Reserves	These estimates are reviewed annually and revised, either upward or downward, as warranted by additional performance data. Oil (MMBbl) Natural Gas (Bcf) NGL (MMBbl) Natural Gas Equivalent (Bcfe) Proved Reserves December 31, 2021 16 3,478 54 3,898 Purchases of reserves — — — — Extensions and discoveries 3 391 5 439 Sales of reserves — — — — Revisions of prior reserve estimates — 66 — 70 Current production (2) (322) (4) (359) December 31, 2022 18 3,612 54 4,048 Purchases of reserves — — — — Extensions and discoveries 6 875 14 996 Sales of reserves — — — — Revisions of prior reserve estimates (4) (411) (1) (445) Current production (1) (350) (4) (385) December 31, 2023 19 3,725 63 4,214 Purchases of reserves — — — — Extensions and discoveries 5 398 20 547 Sales of reserves — — — — Revisions of prior reserve estimates — (413) 1 (406) Current production (1) (354) (4) (386) December 31, 2024 22 3,356 80 3,969 Proved developed reserves December 31, 2021 8 1,928 31 2,165 December 31, 2022 9 2,034 34 2,295 December 31, 2023 6 1,980 31 2,203 December 31, 2024 7 1,879 31 2,109 Proved undeveloped reserves December 31, 2021 8 1,550 22 1,733 December 31, 2022 9 1,578 20 1,752 December 31, 2023 12 1,746 32 2,011 December 31, 2024 15 1,478 49 1,861 Totals may not sum or recalculate due to rounding.
Schedule of Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves	The following table summarizes estimated future net cash flows from natural gas and crude oil reserves (in millions): Year Ended December 31, 2024 Year Ended December 31, 2023 Year Ended December 31, 2022 Future cash flows $ 10,474 $ 12,338 $ 26,677 Future development and abandonment costs (1,498) (1,625) (1,588) Future production costs (5,268) (5,641) (5,872) Future production taxes (212) (303) (553) Future income taxes (23) (63) (2,609) Future net cash flows 3,473 4,706 16,055 10% discount to reflect timing of cash flows (1,726) (2,323) (7,776) Standardized measure of discounted future net cash flows $ 1,747 $ 2,383 $ 8,279 Totals may not sum or recalculate due to rounding.
Schedule of Future Costs to Settle Asset Retirement Obligations	The following table summarizes the total of all future costs to settle asset retirement obligations that are included in future development and abandonment costs above (in millions): Year Ended December 31, 2024 Year Ended December 31, 2023 Year Ended December 31, 2022 Future asset retirement obligations $ 240 $ 229 $ 222
Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves	Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves The principal source of change in the standardized measure of discounted future net cash flows relating to proved reserves is presented in the table below (in millions): Year Ended December 31, 2024 Year Ended December 31, 2023 Year Ended December 31, 2022 Sales and transfers of oil and gas produced, net of production costs $ (478) $ (600) $ (1,849) Net changes in prices, production costs, and development costs (910) (7,181) 5,130 Acquisition of oil and gas reserves in place — — — Extensions and discoveries 368 581 941 Previously estimated development costs incurred during the period 211 263 204 Revisions of previous quantity estimates, less related production costs (21) (278) 154 Sales of oil and gas reserves in place — — (1) Accretion of discount 238 828 414 Net changes in income taxes 16 1,219 (1,067) Change in production rates and other (60) (728) 215 Total change in standardized measure of discounted future net cash flows $ (636) $ (5,896) $ 4,141

SUBSEQUENT EVENTS (Tables)

SUBSEQUENT EVENTS (Tables)	12 Months Ended
	Dec. 31, 2024
Subsequent Events [Abstract]
Schedule of Natural Gas Basis Swap Positions	As of December 31, 2024, the Company had the following natural gas basis swap positions open: Gulfport Pays Gulfport Receives Daily Volume Weighted Average Fixed Spread Natural Gas (MMBtu/d) ($/MMBtu) 2025 Rex Zone 3 NYMEX Plus Fixed Spread 110,000 $ (0.20) 2025 NGPL TXOK NYMEX Plus Fixed Spread 40,000 $ (0.29) 2025 TETCO M2 NYMEX Plus Fixed Spread 230,000 $ (0.96) 2025 Transco Station 85 NYMEX Plus Fixed Spread 5,000 $ 0.38 2025 TGP 500 NYMEX Plus Fixed Spread 10,000 $ 0.31 2026 Rex Zone 3 NYMEX Plus Fixed Spread 40,000 $ (0.19) 2026 NGPL TXOK NYMEX Plus Fixed Spread 30,000 $ (0.30) 2026 TETCO M2 NYMEX Plus Fixed Spread 130,000 $ (0.98) 2026 Transco Station 85 NYMEX Plus Fixed Spread 5,000 $ 0.52 2026 TGP 500 NYMEX Plus Fixed Spread 10,000 $ 0.54 Subsequent to December 31, 2024 and as of February 20, 2025, the Company entered into the following derivative contracts: Period Type of Derivative Instrument Index Daily Volume Weighted Natural Gas (MMBtu/d) ($/MMBtu) 2025 Swaps NYMEX Henry Hub 18,301 $3.85 2026 Basis Swaps Rex Zone 3 40,000 $(0.17) Oil (Bbl/d) ($/Bbl) 2025 Swaps NYMEX WTI 1,000 $70.87

SUMMARY OF SIGNIFICANT ACCOUN_4

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Narrative (Details)		3 Months Ended					12 Months Ended
	Feb. 24, 2023 USD ($)	Dec. 31, 2024 USD ($)	Sep. 30, 2024 USD ($)	Dec. 31, 2023 USD ($)	Jun. 30, 2023 USD ($)	Mar. 31, 2023 USD ($)	Dec. 31, 2024 USD ($) segment	Dec. 31, 2023 USD ($)	Dec. 31, 2022 USD ($)
Summary Of Significant Accounting Policies [Line Items]
Number of reportable segments | segment							1
Accounts receivable, collection period							30 days
Allowance for doubtful accounts		$ 0		$ 0			$ 0	$ 0
Impairment of oil and natural gas properties		342,700,000	$ 30,500,000				$ 373,214,000	0	$ 0
Conversion ratio, gas to barrels of oil (in Mcf of gas)							0.16667
Unproved properties		221,650,000		204,233,000			$ 221,650,000	$ 204,233,000
Unrecognized tax benefits that would impact effective tax rate		$ 0					0
Change in legal reserves							4,900,000
Administrative claim						$ 1,000,000
Noninterest income	$ 17,800,000			$ 8,300,000
Proceeds from plan of reorganization, recoupment of collateral					$ 5,000,000
Pipe Inventory
Summary Of Significant Accounting Policies [Line Items]
Change in legal reserves							$ 1,900,000
Minimum
Summary Of Significant Accounting Policies [Line Items]
Useful life		3 years					3 years
Minimum | Restricted stock
Summary Of Significant Accounting Policies [Line Items]
Vesting period							1 year
Maximum
Summary Of Significant Accounting Policies [Line Items]
Useful life		30 years					30 years
Maximum | Restricted stock
Summary Of Significant Accounting Policies [Line Items]
Vesting period							3 years

SUMMARY OF SIGNIFICANT ACCOUN_5

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Schedule of Supplemental Cash and Non Cash Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Supplemental disclosure of cash flow information:
Interest payments, net of amounts capitalized	$ 46,406	$ 53,820	$ 57,685
Changes in operating assets and liabilities, net:
Accounts receivable - oil, natural gas, and natural gas liquids sales	(33,463)	155,925	(45,550)
Accounts receivable - joint interest and other	13,494	(743)	(1,095)
Accounts payable and accrued liabilities	4,067	(126,329)	59,879
Prepaid expenses	667	(215)	4,863
Other assets	23	63	1,330
Total changes in operating assets and liabilities, net	(15,212)	28,701	19,427
Supplemental disclosure of non-cash transactions:
Capitalized stock-based compensation	5,397	4,046	2,948
Asset retirement obligation capitalized	682	588	2,169
Asset retirement obligation removed due to divestiture and settlements	0	(1,267)	(7)
Asset retirement obligation revisions	19	(5,077)	2,072
Release of common stock held in reserve	1,996	0	28,220
Unamortized 2026 Senior Notes debt issuance costs	$ 447	$ 0	$ 0

SUMMARY OF SIGNIFICANT ACCOUN_6

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Schedule of Accounts Payable and Accrued Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2024	Dec. 31, 2023
Accounting Policies [Abstract]
Revenue payable and suspense	$ 139,703	$ 148,598
Accounts payable	34,668	43,517
Accrued capital expenditures	20,229	38,322
Accrued transportation, gathering, processing, and compression	36,170	32,849
Accrued contract rejection damages and shares held in reserve	0	1,996
Other accrued liabilities	67,311	44,250
Total accounts payable and accrued liabilities	$ 298,081	$ 309,532

SEGMENT INFORMATION - Narrative

SEGMENT INFORMATION - Narrative (Details)	12 Months Ended
	Dec. 31, 2024 segment
Segment Reporting [Abstract]
Number of reportable segments	1

SEGMENT INFORMATION - Schedule

SEGMENT INFORMATION - Schedule of Financial Information (Details) - USD ($)	3 Months Ended		12 Months Ended
	Dec. 31, 2024	Sep. 30, 2024	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Segment Reporting Information [Line Items]
Total revenues			$ 958,131,000	$ 1,791,702,000	$ 1,331,112,000
Lease operating expenses			70,112,000	68,648,000	64,790,000
Taxes other than income			29,737,000	33,717,000	60,139,000
Transportation, gathering, processing and compression			351,237,000	348,631,000	357,246,000
Depreciation, depletion, and amortization			325,723,000	319,715,000	267,761,000
Impairment of oil and gas properties	$ 342,700,000	$ 30,500,000	373,214,000	0	0
General and administrative			42,558,000	38,600,000	35,304,000
Interest expense			59,982,000	57,069,000	59,773,000
Income tax benefit			(56,077,000)	(525,156,000)	0
Net income (loss)			(261,386,000)	1,470,916,000	494,701,000
Capital expenditures			464,492,000	521,187,000	470,396,000
Reportable Segments
Segment Reporting Information [Line Items]
Total revenues			958,131,000	1,791,702,000	1,331,112,000
Lease operating expenses			70,112,000	68,648,000	64,790,000
Taxes other than income			29,737,000	33,717,000	60,139,000
Transportation, gathering, processing and compression			351,237,000	348,631,000	357,246,000
Depreciation, depletion, and amortization			325,723,000	319,715,000	267,761,000
Impairment of oil and gas properties			373,214,000	0	0
General and administrative			42,558,000	38,600,000	35,304,000
Interest expense			59,982,000	57,069,000	59,773,000
Other segment expenses			23,031,000	(20,438,000)	(8,602,000)
Income tax benefit			(56,077,000)	(525,156,000)	0
Total significant segment expenses			1,219,517,000	320,786,000	836,411,000
Net income (loss)			$ (261,386,000)	$ 1,470,916,000	$ 494,701,000

PROPERTY AND EQUIPMENT - Schedu

PROPERTY AND EQUIPMENT - Schedule of Property and Equipment (Details) - USD ($) $ in Thousands	Dec. 31, 2024	Dec. 31, 2023
Property, Plant and Equipment [Abstract]
Proved oil and natural gas properties	$ 3,349,805	$ 2,904,519
Unproved properties	221,650	204,233
Other depreciable property and equipment	10,905	8,779
Land	386	386
Total property and equipment	3,582,746	3,117,917
Accumulated DD&A and impairment	(1,564,475)	(865,618)
Total property and equipment, net	$ 2,018,271	$ 2,252,299

PROPERTY AND EQUIPMENT - Narrat

PROPERTY AND EQUIPMENT - Narrative (Details)	3 Months Ended		12 Months Ended
	Dec. 31, 2024 USD ($) $ / MMBTU	Sep. 30, 2024 USD ($)	Dec. 31, 2024 USD ($) $ / MMcfe $ / MMBTU	Dec. 31, 2023 USD ($) $ / MMcfe	Dec. 31, 2022 USD ($) $ / MMcfe
Property, Plant and Equipment [Line Items]
Impairment of oil and natural gas properties	$ 342,700,000	$ 30,500,000	$ 373,214,000	$ 0	$ 0
Weighted average ceiling price (in usd per MMBtu) | $ / MMBTU	2.13		2.13
Capitalized general and administrative costs			$ 25,300,000	$ 22,800,000	$ 20,200,000
Depletion per Mcf of gas equivalent (usd per Mcfe) | $ / MMcfe			0.84	0.83	0.74
Non producing leases extension term			5 years
Minimum
Property, Plant and Equipment [Line Items]
Expected number of years amortization will commence			3 years
Maximum
Property, Plant and Equipment [Line Items]
Expected number of years amortization will commence			5 years

PROPERTY AND EQUIPMENT - Sche_2

PROPERTY AND EQUIPMENT - Schedule of Non-producing Properties (Details) - USD ($) $ in Thousands	Dec. 31, 2024	Dec. 31, 2023
Property, Plant and Equipment [Line Items]
Total unproved properties	$ 221,650	$ 204,233
Utica & Marcellus
Property, Plant and Equipment [Line Items]
Total unproved properties	197,513	177,888
SCOOP
Property, Plant and Equipment [Line Items]
Total unproved properties	$ 24,137	$ 26,345

PROPERTY AND EQUIPMENT - Sche_3

PROPERTY AND EQUIPMENT - Schedule of Oil and Gas Properties Not Subject to Amortization (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Property, Plant and Equipment [Abstract]
Acquisition costs	$ 58,742	$ 58,002	$ 17,288	$ 82,695
Exploration costs	0	0	0
Development costs	1,472	556	0
Capitalized interest	2,895	0	0
Total oil and natural gas properties not subject to amortization	63,109	58,558	$ 17,288	$ 82,695
Acquisition costs, total	216,727
Exploration costs, total	0
Development costs, total	2,028
Capitalized interest, total	2,895
Capitalized costs of oil and natural gas properties excluded from amortization	$ 221,650	$ 204,233

PROPERTY AND EQUIPMENT - Sche_4

PROPERTY AND EQUIPMENT - Schedule of Asset Retirement Obligation (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligation, beginning of period	$ 29,941	$ 33,171
Liabilities incurred	682	588
Liabilities settled	0	(604)
Liabilities removed due to divestitures	0	(919)
Accretion expense	2,307	2,782	$ 2,746
Revisions in estimated cash flows	19	(5,077)	2,072
Asset retirement obligation, end of period	$ 32,949	$ 29,941	$ 33,171

LONG-TERM DEBT - Schedule of Lo

LONG-TERM DEBT - Schedule of Long-Term Debt (Details) - USD ($) $ in Thousands	Dec. 31, 2024	Sep. 30, 2024	Dec. 31, 2023	May 17, 2021
Debt Instrument [Line Items]
Net unamortized debt issuance costs	$ (10,845)		$ (618)
Total debt, net	702,857		667,382
Less: current maturities of long-term debt	0		0
Long-term debt	702,857		667,382
2029 Senior Notes | Senior Notes
Debt Instrument [Line Items]
Long-term debt	650,000		0
Total debt, net	$ 639,200
Stated interest rate	6.75%	6.75%
2026 Senior Notes | Senior Notes
Debt Instrument [Line Items]
Long-term debt	$ 25,702		550,000
Total debt, net	$ 25,700
Stated interest rate	8%			8%
New Credit Facility | Unsecured Debt
Debt Instrument [Line Items]
Long-term debt	$ 38,000		0
Credit Facility Due 2027 | Unsecured Debt
Debt Instrument [Line Items]
Long-term debt	$ 0		$ 118,000

LONG-TERM DEBT - Narrative (Det

LONG-TERM DEBT - Narrative (Details) - USD ($)					1 Months Ended	12 Months Ended
	Sep. 12, 2024	Oct. 27, 2023	May 01, 2023	Oct. 31, 2022	Sep. 30, 2024	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022	May 17, 2021
Debt Instrument [Line Items]
Loss on debt extinguishment						$ 13,388,000	$ 0	$ 0
Capitalized interest						(4,771,000)	(4,147,000)	0
Long-term debt						$ 702,857,000	667,382,000
Oil and gas properties
Debt Instrument [Line Items]
Capitalized interest								$ 0
2029 Senior Notes | Senior Notes
Debt Instrument [Line Items]
Debt instrument, amount					$ 650,000,000
Stated interest rate					6.75%	6.75%
Long-term debt						$ 650,000,000	0
Long-term debt						639,200,000
2029 Senior Notes | Senior Notes | Level 1
Debt Instrument [Line Items]
Carrying value of notes						$ 655,000,000
2026 Senior Notes | Senior Notes
Debt Instrument [Line Items]
Debt instrument, amount									$ 550,000,000
Stated interest rate						8%			8%
Debt instrument, repurchase amount					$ 524,300,000
Debt instrument, redemption price, percentage					102.30%
Loss on debt extinguishment					$ 13,400,000
Payment for debt extinguishment or debt prepayment cost					$ 12,900,000
Long-term debt						$ 25,702,000	$ 550,000,000
Long-term debt						25,700,000
2026 Senior Notes | Senior Notes | Level 1
Debt Instrument [Line Items]
Carrying value of notes						26,000,000
2026 Senior Notes | Revolving credit facility | Line of Credit
Debt Instrument [Line Items]
Long-term debt			$ 100,000,000
New Credit Facility | Revolving credit facility
Debt Instrument [Line Items]
Line of credit facility, commitment fee amount	$ 1,000,000,000	$ 900,000,000	900,000,000	$ 700,000,000
Borrowing base	$ 1,100,000,000	$ 1,100,000,000	1,100,000,000	1,000,000,000
Line of credit facility, excess cash threshold			$ 75,000,000	$ 45,000,000
Long-term debt						$ 38,000,000
Unused capacity, commitment fee percentage						0.50%
Debt instrument net funded leverage ratio	350%					325%
Debt instrument current ratio	100%					100%
Letters of credit outstanding						$ 63,800,000
Weight average interest rate						8.23%	8.15%
New Credit Facility | Revolving credit facility | Minimum
Debt Instrument [Line Items]
Unused capacity, commitment fee percentage	0.375%
New Credit Facility | Revolving credit facility | Maximum
Debt Instrument [Line Items]
Unused capacity, commitment fee percentage	0.50%
New Credit Facility | Secured Overnight Financing Rate (SOFR) | Revolving credit facility | Minimum
Debt Instrument [Line Items]
Variable interest rate (in percent)	2.25%					2.75%
New Credit Facility | Secured Overnight Financing Rate (SOFR) | Revolving credit facility | Maximum
Debt Instrument [Line Items]
Variable interest rate (in percent)	3.25%					3.75%
New Credit Facility | Base Rate | Revolving credit facility | Minimum
Debt Instrument [Line Items]
Variable interest rate (in percent)	1.25%					1.75%
New Credit Facility | Base Rate | Revolving credit facility | Maximum
Debt Instrument [Line Items]
Variable interest rate (in percent)	2.25%					2.75%

LONG-TERM DEBT - Schedule of To

LONG-TERM DEBT - Schedule of Total Interest Expense (Details) - USD ($)	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Long-Term Debt, Unclassified [Abstract]
Cash paid for interest	$ 51,177,000	$ 57,967,000	$ 57,685,000
Change in accrued interest	9,368,000	(7,000)	(826,000)
Capitalized interest	(4,771,000)	(4,147,000)	0
Amortization of loan costs	4,208,000	3,256,000	2,914,000
Other	0	0	0
Interest expense	$ 59,982,000	$ 57,069,000	$ 59,773,000

MEZZANINE EQUITY - Narrative (D

MEZZANINE EQUITY - Narrative (Details) - USD ($) $ / shares in Units, $ in Thousands		5 Months Ended	12 Months Ended
	May 17, 2021	May 17, 2021	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Class of Stock [Line Items]
Common stock, shares authorized (in shares)	42,000,000	42,000,000	42,000,000	42,000,000
Common stock, par value (in dollars per share)	$ 0.0001	$ 0.0001	$ 0.0001	$ 0.0001
Redeemable 12% cumulative preferred stock, shares authorized (in shares)	110,000	110,000	110,000	110,000
Temporary equity, par or stated value (in dollars per share)	$ 0.0001	$ 0.0001	$ 0.0001	$ 0.0001
Temporary equity, liquidation preference (in usd per share)	$ 1,000	$ 1,000
Preferred stock Series A, issued (in shares)	55,000	55,000
Preferred stock, dividend rate		10%
Preferred stock, dividend rate, percentage, pain-in-kind		15%
Preferred stock, convertible, conversion price (in usd per share)	$ 14	$ 14
Payment period	3 days
Dividends on preferred stock			$ (4,230)	$ (4,840)	$ (5,444)
Series A Convertible Preferred Stock
Class of Stock [Line Items]
Anti-dilutive common shares excluded from calculation of earnings per share (in shares)			2,700,000	3,200,000	3,700,000

MEZZANINE EQUITY - Schedule of

MEZZANINE EQUITY - Schedule of Dividends (Details) - shares	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Increase (Decrease) in Temporary Equity [Roll Forward]
Temporary equity, beginning shares outstanding (in shares)	44,214	52,295
Issuance of preferred stock (in shares)	0	0
Conversion of preferred stock (in shares)	6,866	8,081
Temporary equity, ending shares outstanding (in shares)	37,348	44,214

EQUITY - Narrative (Details)

EQUITY - Narrative (Details) - USD ($)			3 Months Ended				12 Months Ended
	Dec. 14, 2023	Jun. 26, 2023	Dec. 31, 2024	Sep. 30, 2024	Jun. 30, 2024	Mar. 31, 2024	Dec. 31, 2024	Jan. 31, 2024	Dec. 31, 2023	Sep. 20, 2023	Nov. 30, 2021	May 17, 2021
Class of Stock [Line Items]
Common stock, shares authorized (in shares)			42,000,000				42,000,000		42,000,000			42,000,000
Common stock, par value (in dollars per share)			$ 0.0001				$ 0.0001		$ 0.0001			$ 0.0001
Redeemable 12% cumulative preferred stock, shares authorized (in shares)			110,000				110,000		110,000			110,000
Temporary equity, par or stated value (in dollars per share)			$ 0.0001				$ 0.0001		$ 0.0001			$ 0.0001
Temporary equity, liquidation preference (in usd per share)												$ 1,000
Common stock, shares issued (in shares)			17,800,000				17,800,000		18,300,000			19,800,000
Stock repurchased during period (in shares)		263,158	491,000	341,000	161,000	210,000	1,203,000
Average price paid per share (in usd per share)		$ 95	$ 163.13	$ 146.17	$ 155.65	$ 140.39	$ 153.35
Stock repurchase program, authorized amount										$ 1,000,000,000	$ 100,000,000
Stock repurchased during period, value			$ 80,123,000	$ 49,862,000	$ 25,000,000	$ 29,492,000	$ 184,477,000
Repurchase Program
Class of Stock [Line Items]
Stock repurchased during period (in shares)							5,600,000
Average price paid per share (in usd per share)							$ 104.88
Stock repurchased during period, value							$ 584,100,000
Underwritten Public Offering
Class of Stock [Line Items]
Number of shares issued in transaction (in shares)	653,464	1,500,000
Sale of stock, price per share (in dollars per share)	$ 128.21	$ 95
Disputed Claims Reserve | Common Stock
Class of Stock [Line Items]
Plan of reorganization, number of shares issued (in shares)								62,000				1,700,000
Plan of reorganization, number of shares outstanding			0				0

EQUITY - Schedule of Repurchase

EQUITY - Schedule of Repurchase Agreements (Details) - USD ($) $ / shares in Units, $ in Thousands		3 Months Ended				12 Months Ended
	Jun. 26, 2023	Dec. 31, 2024	Sep. 30, 2024	Jun. 30, 2024	Mar. 31, 2024	Dec. 31, 2024
Equity [Abstract]
Total number of shares purchased (in shares)	263,158	491,000	341,000	161,000	210,000	1,203,000
Dollar Value of Shares Purchased		$ 80,123	$ 49,862	$ 25,000	$ 29,492	$ 184,477
Average price paid per share (in usd per share)	$ 95	$ 163.13	$ 146.17	$ 155.65	$ 140.39	$ 153.35

STOCK-BASED COMPENSATION - Narr

STOCK-BASED COMPENSATION - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	May 17, 2021
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common stock, capital shares reserved for future issuance (in shares)	0	62,000
2021 Stock Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common stock, capital shares reserved for future issuance (in shares)					2,800,000
Restricted Stock Units (RSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total shares awarded (in shares)	167,014	193,602	197,772	198,413
Fair value of vested awards	$ 56.8	$ 9.9	$ 5.9
Unrecognized compensation expense to be expected	$ 12.1
Extension term	1 year 8 months 19 days
Restricted Stock Units (RSUs) | 2021 Stock Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation cost	$ 16.4	12.3
Capitalized stock-based compensation	$ 5.4	$ 4
Total shares awarded (in shares)	444,493
Restricted Stock Units (RSUs) | Minimum | Employee | 2021 Stock Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period	3 years
Restricted Stock Units (RSUs) | Minimum | Director | 2021 Stock Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period	1 year
Restricted Stock Units (RSUs) | Maximum | Director | 2021 Stock Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period	4 years
Performance Shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total shares awarded (in shares)	178,139	255,578	190,804	153,138
Unrecognized compensation expense to be expected	$ 8
Extension term	1 year 8 months 23 days
Performance Shares | 2021 Stock Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total shares awarded (in shares)	462,982
Percent of target based award, minimum	0%
Percent of target based award, maximum	200%
Vesting period (in years)	3 years

STOCK-BASED COMPENSATION - Sche

STOCK-BASED COMPENSATION - Schedule of Restricted Stock Award and Unit Activity (Details) - $ / shares	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Restricted Stock Units (RSUs)
Number of Unvested Restricted Stock Units
Beginning of period (in shares)	193,602	197,772	198,413
Granted (in shares)	75,476	104,901	78,192
Vested (in shares)	(96,942)	(101,804)	(67,564)
Forfeited/canceled (in shares)	(5,122)	(7,267)	(11,269)
End of period (in shares)	167,014	193,602	197,772
Weighted Average Grant Date Fair Value
Beginning of period (in dollars per share)	$ 83.89	$ 77.49	$ 66.04
Granted (in dollars per share)	152.79	88.59	96.90
Vested (in dollars per share)	81.14	75.75	65.91
Forfeited/canceled (in dollars per share)	114.91	91.61	80.11
End of period (in dollars per share)	$ 115.67	$ 83.89	$ 77.49
Performance Shares
Number of Unvested Restricted Stock Units
Beginning of period (in shares)	255,578	190,804	153,138
Granted (in shares)	188,358	83,820	37,666
Vested (in shares)	(265,797)	0	0
Forfeited/canceled (in shares)	0	(19,046)	0
End of period (in shares)	178,139	255,578	190,804
Weighted Average Grant Date Fair Value
Beginning of period (in dollars per share)	$ 54.40	$ 52.15	$ 48.54
Granted (in dollars per share)	81.90	58.39	66.82
Vested (in dollars per share)	48.65	0	0
Forfeited/canceled (in dollars per share)	0	49.37	0
End of period (in dollars per share)	$ 92.06	$ 54.40	$ 52.15

STOCK-BASED COMPENSATION - Sc_2

STOCK-BASED COMPENSATION - Schedule of Grant Date Fair Value of Awards (Details) - Performance Shares - 2021 Stock Incentive Plan - $ / shares	Mar. 01, 2024	Apr. 03, 2023	Mar. 03, 2023	Jan. 24, 2023	Apr. 29, 2022
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Forecast period (years)	3 years	3 years	3 years	3 years	3 years
Risk-free interest rates	4.36%	3.79%	4.64%	3.88%	2.87%
Implied equity volatility	46.70%	70.80%	86.40%	87.20%	88.40%
Stock price on the date of grant (in usd per share)	$ 142	$ 79.50	$ 82.20	$ 72.99	$ 93.98

REVENUE FROM CONTRACTS WITH C_2

REVENUE FROM CONTRACTS WITH CUSTOMERS (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Revenue from Contract with Customer [Abstract]
Accounts receivable—oil, natural gas, and natural gas liquids sales	$ 155,942	$ 122,479
Performance obligation description	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.

LEASES - Narrative (Details)

LEASES - Narrative (Details)	12 Months Ended
	Dec. 31, 2024 Contract
Lessee, Lease, Description [Line Items]
Number of lease contract	1
Weighted average remaining lease term	9 months 3 days
Weighted-average discount rate - operating lease	6.25%
Minimum
Lessee, Lease, Description [Line Items]
Lease term	1 year
Maximum
Lessee, Lease, Description [Line Items]
Lease term	5 years
Drilling Rig
Lessee, Lease, Description [Line Items]
Lease term	1 year

LEASES - Schedule of Maturities

LEASES - Schedule of Maturities of Lease Liabilities (Details) $ in Thousands	Dec. 31, 2024 USD ($)
Leases [Abstract]
2025	$ 5,657
2026	561
2027	10
2028	0
2029	0
Total lease payments	6,228
Less: imputed interest	(129)
Total	$ 6,099

LEASES - Schedule of Lease Cost

LEASES - Schedule of Lease Cost (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Leases [Abstract]
Operating lease cost	$ 12,828	$ 13,752
Variable lease cost	0	0
Short-term lease cost	26,817	28,691
Total lease cost	$ 39,645	$ 42,443

INCOME TAXES - Schedule of Comp

INCOME TAXES - Schedule of Components of Income Tax Expense (Benefit) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Current:
State	$ 0	$ 0	$ 0
Federal	0	0	0
Deferred:
State	11,747	(26,704)	0
Federal	(67,824)	(498,452)	0
Total income tax benefit	$ (56,077)	$ (525,156)	$ 0

INCOME TAXES - Schedule of Reco

INCOME TAXES - Schedule of Reconciliation of Statutory Federal Income Tax Amount (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Income Tax Disclosure [Abstract]
Income (loss) before federal income taxes	$ (317,463)	$ 945,760	$ 494,701
Expected income tax at statutory rate	(66,668)	198,610	103,887
State income taxes	4,765	(2,581)	2,227
Remeasurement of state deferred tax asset	54	0	13,869
Return to provision	5,800	(5,592)	(17,075)
Other differences	1,857	1,982	1,117
Change in valuation allowance due to current year activity	(1,885)	(717,575)	(104,025)
Total income tax benefit	$ (56,077)	$ (525,156)	$ 0

INCOME TAXES - Narrative (Detai

INCOME TAXES - Narrative (Details) - USD ($)	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Operating Loss Carryforwards [Line Items]
Effective tax rate	18%	(56.00%)	0%
Income tax benefit	$ 56,077,000	$ 525,156,000	$ 0
Valuation allowance of deferred tax assets	83,695,000	$ 85,757,000
NOL not subject to expiration	1,300,000,000
Unrecognized tax benefits	0
Federal
Operating Loss Carryforwards [Line Items]
Net operating loss carryforward	1,600,000,000
NOL subject to expiration	264,500,000
State
Operating Loss Carryforwards [Line Items]
Net operating loss carryforward	$ 394,500,000

INCOME TAXES - Schedule of Defe

INCOME TAXES - Schedule of Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2024	Dec. 31, 2023
Deferred tax assets:
Net operating loss carryforward and tax credits	$ 345,770	$ 399,017
Oil and gas property basis difference	194,412	143,769
Investment in pass through entities	65,210	68,114
Stock-based compensation expense	1,821	1,262
Change in fair value of derivative instruments	6,106	0
Other assets	56,849	52,730
Total deferred tax assets	670,168	664,892
Valuation allowance for deferred tax assets	(83,695)	(85,757)
Deferred tax assets, net of valuation allowance	586,473	579,135
Deferred tax liabilities:
Change in fair value of derivative instruments	3,401	50,448
Right of use asset	1,281	3,003
Other	558	528
Total deferred tax liabilities	5,240	53,979
Net deferred tax asset	$ 581,233	$ 525,156

EARNINGS (LOSS) PER SHARE (Deta

EARNINGS (LOSS) PER SHARE (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Net (loss) income	$ (261,386)	$ 1,470,916	$ 494,701
Dividends on preferred stock	(4,230)	(4,840)	(5,444)
Participating securities - preferred stock	0	(212,360)	(76,401)
Net (loss) income attributable to common stockholders	(265,616)	1,253,716	412,856
Re-allocation of participating securities	0	2,475	512
Diluted net (loss) income attributable to common stockholders	$ (265,616)	$ 1,256,191	$ 413,368
Basic shares (in shares)	18,050	18,645	20,185
Dilutive shares (in shares)	18,050	18,902	20,347
Basic EPS (in dollars per share)	$ (14.72)	$ 67.24	$ 20.45
Dilutive EPS (in dollars per share)	$ (14.72)	$ 66.46	$ 20.32
Restricted stock
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Dilutive shares (in shares)	300	300	200
Series A Convertible Preferred Stock
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Anti-dilutive common shares excluded from calculation of earnings per share (in shares)	2,700	3,200	3,700

DERIVATIVE INSTRUMENTS - Narrat

DERIVATIVE INSTRUMENTS - Narrative (Details)	12 Months Ended
	Dec. 31, 2024 counterparty
Derivative [Line Items]
Number of counterparties	12
Minimum
Derivative [Line Items]
Percentage of forecasted annual production	30%
Term of contract	12 months
Maximum
Derivative [Line Items]
Percentage of forecasted annual production	70%
Term of contract	36 months

DERIVATIVE INSTRUMENTS - Schedu

DERIVATIVE INSTRUMENTS - Schedule of Derivative Instruments (Details)	12 Months Ended
	Dec. 31, 2024 MMBTU $ / MMBTU $ / bbl bbl
Derivative [Line Items]
Weighted average ceiling price (in usd per MMBtu)	2.13
NYMEX Henry Hub Swap - 2025
Derivative [Line Items]
Daily Volume | MMBTU	250,000
Weighted average price of derivative swap (usd per MMBtu or Bbls)	3.82
NYMEX Henry Hub Swap - 2026
Derivative [Line Items]
Daily Volume | MMBTU	200,000
Weighted average price of derivative swap (usd per MMBtu or Bbls)	3.64
NYMEX WTI 2025
Derivative [Line Items]
Daily volume (Bbls/day) | bbl	2,000
Weighted average price of derivative swap (usd per MMBtu or Bbls) | $ / bbl	74.50
Mont Belvieu C3 - 2025
Derivative [Line Items]
Daily volume (Bbls/day) | bbl	2,504
Weighted average price of derivative swap (usd per MMBtu or Bbls) | $ / bbl	29.97
Mont Belvieu C3 - 2026
Derivative [Line Items]
Daily volume (Bbls/day) | bbl	496
Weighted average price of derivative swap (usd per MMBtu or Bbls) | $ / bbl	29.51
NYMEX Henry Hub Index 1
Derivative [Line Items]
Daily Volume | MMBTU	220,000
Weighted average floor price (in usd per MMBtu or bbl)	3.37
Weighted average ceiling price (in usd per MMBtu)	4.23
NYMEX Henry Hub Index 2
Derivative [Line Items]
Daily Volume | MMBTU	90,000
Weighted average floor price (in usd per MMBtu or bbl)	3.35
Weighted average ceiling price (in usd per MMBtu)	4.10
NYMEX Henry Hub - 2025 | Call option
Derivative [Line Items]
Daily Volume | MMBTU	193,315
Weighted average price of derivative swap (usd per MMBtu or Bbls)	5.80
Basis Swap, Rex Zone 3 - 2025
Derivative [Line Items]
Daily Volume | MMBTU	110,000
Weighted average price of derivative swap (usd per MMBtu or Bbls)	(0.20)
Basis Swap, NGPL TXOK - 2025
Derivative [Line Items]
Daily Volume | MMBTU	40,000
Weighted average price of derivative swap (usd per MMBtu or Bbls)	(0.29)
Basis Swap, TETCO M2 - 2025
Derivative [Line Items]
Daily Volume | MMBTU	230,000
Weighted average price of derivative swap (usd per MMBtu or Bbls)	(0.96)
Basis Swap, Transco Station 85 2025
Derivative [Line Items]
Daily Volume | MMBTU	5,000
Weighted average price of derivative swap (usd per MMBtu or Bbls)	0.38
Basis Swap, TGP 500 2025
Derivative [Line Items]
Daily Volume | MMBTU	10,000
Weighted average price of derivative swap (usd per MMBtu or Bbls)	0.31
Basis Swap, Rex Zone 3 2026
Derivative [Line Items]
Daily Volume | MMBTU	40,000
Weighted average price of derivative swap (usd per MMBtu or Bbls)	(0.19)
Basis Swap, NGPL TXOK 2026
Derivative [Line Items]
Daily Volume | MMBTU	30,000
Weighted average price of derivative swap (usd per MMBtu or Bbls)	(0.30)
Basis Swap, TETCO M2 2026
Derivative [Line Items]
Daily Volume | MMBTU	130,000
Weighted average price of derivative swap (usd per MMBtu or Bbls)	(0.98)
Basis Swap, Transco Station 85 2026
Derivative [Line Items]
Daily Volume | MMBTU	5,000
Weighted average price of derivative swap (usd per MMBtu or Bbls)	0.52
Basis Swap, TGP 500 2026
Derivative [Line Items]
Daily Volume | MMBTU	10,000
Weighted average price of derivative swap (usd per MMBtu or Bbls)	0.54

DERIVATIVE INSTRUMENTS - Sche_2

DERIVATIVE INSTRUMENTS - Schedule of Derivative Instruments in Statement of Financial Position (Details) - USD ($) $ in Thousands	Dec. 31, 2024	Dec. 31, 2023
Derivative [Line Items]
Short-term derivative asset	$ 58,085	$ 233,226
Long-term derivative asset	6,003	47,566
Short-term derivative liability	(41,889)	(21,963)
Long-term derivative liability	(35,081)	(18,602)
Commodity Derivative Instruments
Derivative [Line Items]
Short-term derivative asset	58,085	233,226
Long-term derivative asset	6,003	47,566
Short-term derivative liability	(41,889)	(21,963)
Long-term derivative liability	(35,081)	(18,602)
Total commodity derivative position	$ (12,882)	$ 240,227

DERIVATIVE INSTRUMENTS - Sche_3

DERIVATIVE INSTRUMENTS - Schedule of Gain (Loss) on Derivative Instruments (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Derivative [Line Items]
Total gains on natural gas, oil and NGL derivatives	$ 29,527	$ 740,319	$ (999,747)
Natural Gas
Derivative [Line Items]
Natural gas derivatives - fair value gains (losses)	(251,019)	584,563	32,797
Natural gas derivatives - settlement gains (losses)	284,626	146,381	(1,002,098)
Total gains on natural gas, oil and NGL derivatives	33,607	730,944	(969,301)
Oil
Derivative [Line Items]
Natural gas derivatives - fair value gains (losses)	2,351	5,971	6,618
Natural gas derivatives - settlement gains (losses)	166	(3,272)	(39,163)
Total gains on natural gas, oil and NGL derivatives	2,517	2,699	(32,545)
Natural gas liquids
Derivative [Line Items]
Natural gas derivatives - fair value gains (losses)	(4,442)	(2,414)	14,648
Natural gas derivatives - settlement gains (losses)	(2,155)	9,090	(12,549)
Total gains on natural gas, oil and NGL derivatives	$ (6,597)	$ 6,676	$ 2,099

DERIVATIVE INSTRUMENTS - Sche_4

DERIVATIVE INSTRUMENTS - Schedule of Offsetting (Details) - USD ($) $ in Thousands	Dec. 31, 2024	Dec. 31, 2023
Derivative assets
Derivative asset, gross asset	$ 64,088	$ 280,792
Derivative asset, netting adjustment	(49,343)	(30,866)
Derivative asset, net	14,745	249,926
Derivative liabilities
Derivative liability, gross liability	(76,970)	(40,565)
Derivative liability, netting adjustment	49,343	30,866
Derivative liability, net	$ (27,627)	$ (9,699)

RESTRUCTURING COSTS (Details)

RESTRUCTURING COSTS (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Restructuring and Related Activities [Abstract]
Restructuring costs	$ 0	$ 4,762	$ 0
Share-based accelerated cost		$ 1,300

INVESTMENTS (Details)

INVESTMENTS (Details) a in Thousands	12 Months Ended
	Dec. 31, 2024 a	Dec. 31, 2019 USD ($)	Dec. 31, 2023	May 17, 2021 USD ($)
Grizzly Oil Sands | Athabasca Peace River And Cold Lake Oil Sands Regions
Schedule of Equity Method Investments [Line Items]
Gas and oil area, reserve (acres) | a	830
Grizzly Oil Sands
Schedule of Equity Method Investments [Line Items]
Equity investment, ownership interest	24.50%		24.50%
Amount of cash paid for equity investments		$ 0
Equity Method Investments				$ 0

FAIR VALUE MEASUREMENTS - Sched

FAIR VALUE MEASUREMENTS - Schedule of Fair Value Measurements (Details) - USD ($) $ in Thousands	Dec. 31, 2024	Dec. 31, 2023
Assets:
Contingent consideration arrangement	$ 2,700
Level 1
Assets:
Derivative instruments	0	$ 0
Contingent consideration arrangement	0	0
Total assets	0	0
Liabilities:
Derivative instruments	0	0
Level 2
Assets:
Derivative instruments	64,088	280,792
Contingent consideration arrangement	0	0
Total assets	64,088	280,792
Liabilities:
Derivative instruments	76,970	40,565
Level 3
Assets:
Derivative instruments	0	0
Contingent consideration arrangement	2,700	2,900
Total assets	2,700	2,900
Liabilities:
Derivative instruments	$ 0	$ 0

FAIR VALUE MEASUREMENTS - Narra

FAIR VALUE MEASUREMENTS - Narrative (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Contingent consideration arrangement	$ 2,700
Contingent consideration, gain (loss) due to change in value	0	$ 1,400
Asset retirement obligation capitalized	682	$ 588
Prepaid Expenses and Other Current Assets
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Contingent consideration arrangement	500
Other Noncurrent Assets
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Contingent consideration arrangement	$ 2,200

RELATED PARTY TRANSACTIONS (Det

RELATED PARTY TRANSACTIONS (Details) - USD ($) $ in Thousands								3 Months Ended				12 Months Ended
	Dec. 19, 2024	Nov. 21, 2024	Sep. 19, 2024	Mar. 19, 2024	Dec. 07, 2023	Jun. 26, 2023	Jun. 22, 2023	Dec. 31, 2024	Sep. 30, 2024	Jun. 30, 2024	Mar. 31, 2024	Dec. 31, 2024
Related Party Transaction [Line Items]
Stock repurchased during period (in shares)						263,158		491,000	341,000	161,000	210,000	1,203,000
Stock repurchased during period, value								$ 80,123	$ 49,862	$ 25,000	$ 29,492	$ 184,477
Related Party
Related Party Transaction [Line Items]
Stock repurchased during period (in shares)	79,410	150,000	170,000	97,219	146,455		215,060
Stock repurchased during period, value	$ 12,929	$ 26,340	$ 24,863	$ 15,002	$ 20,000		$ 20,430

COMMITMENTS - Schedule of Futur

COMMITMENTS - Schedule of Future Service Commitments (Details) - Transportation Commitment $ in Thousands	Dec. 31, 2024 USD ($)
Other Commitments [Line Items]
2025	$ 140,434
2026	134,281
2027	136,448
2028	136,604
2029	136,762
Thereafter	463,417
Total	$ 1,147,946

COMMITMENTS - Schedule of Fut_2

COMMITMENTS - Schedule of Future Firm Sales Commitments (Details) - Future Firm Sales Commitments $ in Thousands	Dec. 31, 2024 USD ($)
Other Commitments [Line Items]
2025	$ 68
2026	75
2027	12
2028	0
Thereafter	0
Total	$ 155

COMMITMENTS - Narrative (Detail

COMMITMENTS - Narrative (Details) $ in Millions	12 Months Ended
	Dec. 31, 2024 USD ($)
Commitments [Line Items]
Maximum annual contributions per employee (401K Plan)	100%
Minimum matching employer contribution for 401K	6%
Purchase Inventory And Other Material
Commitments [Line Items]
Other commitment, to be paid, year one	$ 13.8

COMMITMENTS - Schedule of Contr

COMMITMENTS - Schedule of Contributions Expenses (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Commitments and Contingencies Disclosure [Abstract]
Contributions expense	$ 1,749	$ 1,549	$ 1,386

CONTINGENCIES - Narrative (Deta

CONTINGENCIES - Narrative (Details) $ in Thousands	Sep. 05, 2024 USD ($)	Dec. 31, 2024 a	Jul. 31, 2024 USD ($)
Loss Contingency [Abstract]
Estimate of possible loss			$ 300
Payments for legal settlements	$ 97,500
Area of land (in acres) | a		10,240

CONTINGENCIES - Sales to Major

CONTINGENCIES - Sales to Major Customers (Details) - Customer concentration risk - Revenue	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
One Customers
Product Information [Line Items]
Percentage of sales to major customers	15%	12%
Two Customers
Product Information [Line Items]
Percentage of sales to major customers			31%

SUPPLEMENTAL INFORMATION ON O_3

SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES (UNAUDITED) - Narrative (Details)	12 Months Ended
	Dec. 31, 2024 USD ($) Bcfe well $ / bbl $ / MMBTU	Dec. 31, 2023 USD ($) Bcfe well $ / MMBTU $ / bbl	Dec. 31, 2022 USD ($)	Dec. 31, 2022 $ / MMBTU	Dec. 31, 2022 Bcfe	Dec. 31, 2022 well	Dec. 31, 2022 $ / bbl	Dec. 31, 2021 $ / MMBTU $ / bbl
Reserve Quantities [Line Items]
Interest costs capitalized | $	$ 4,771,000	$ 4,147,000	$ 0
Capitalized general and administrative costs | $	$ 25,300,000	$ 22,800,000	$ 20,200,000
Increase (decrease) in reserve during the period	547,500	995.7			438.9
Estimated future costs to develop proved undeveloped reserves 2025 | $	$ 280,200,000
Estimated future costs to develop proved undeveloped reserves 2026 | $	318,800,000
Estimated future costs to develop proved undeveloped reserves 2027 | $	$ 259,200,000
Decline in performance
Reserve Quantities [Line Items]
Proved developed and undeveloped reserve, revision of previous estimate	(406,000)	444.9			(26.9)
Positive Well Performance
Reserve Quantities [Line Items]
Proved developed and undeveloped reserve, revision of previous estimate	16,200	24.9
Lower commodity prices
Reserve Quantities [Line Items]
Proved developed and undeveloped reserve, revision of previous estimate	(487,900)	(159.7)			47.7
Economic Assumptions
Reserve Quantities [Line Items]
Proved developed and undeveloped reserve, revision of previous estimate	(66,900)	(49.1)
Upward Revisions, Commodities
Reserve Quantities [Line Items]
Proved developed and undeveloped reserve, revision of previous estimate					69.7
Utica Shale
Reserve Quantities [Line Items]
Increase (decrease) in reserve during the period	340.7	789.2			295.9
Planned unit development | well	33	67				36
Utica Shale | Decline in performance
Reserve Quantities [Line Items]
Proved developed and undeveloped reserve, revision of previous estimate	171,200	293.9
Marcellus
Reserve Quantities [Line Items]
Increase (decrease) in reserve during the period	92.4	88.6			72.1
Planned unit development | well	13	12				8
SCOOP Properties
Reserve Quantities [Line Items]
Increase (decrease) in reserve during the period	114.4	110.4			65.4
Planned unit development | well	16	14				5
SCOOP Properties | Exclusion Of PUD Locations
Reserve Quantities [Line Items]
Planned unit development | well	6	8				5
Utica Field | Decline in performance
Reserve Quantities [Line Items]
Proved developed and undeveloped reserve, revision of previous estimate					144.5
Utica Field | Exclusion Of PUD Locations
Reserve Quantities [Line Items]
Planned unit development | well	11	36				4
Proved developed and undeveloped reserve, revision of previous estimate	(172.4)	(554.9)			(95.6)
Natural gas, per MMbtu
Reserve Quantities [Line Items]
Price per unit (usd per barrel or MMbtu) | $ / MMBTU	2.13	2.64		6.36				3.60
Natural gas liquids
Reserve Quantities [Line Items]
Price per unit (usd per barrel or MMbtu)	31.30	31.42		47.86			47.86	31.90
Natural Gas
Reserve Quantities [Line Items]
Price per unit (usd per barrel or MMbtu)	76.32	78.21		94.14			94.14	66.55

SUPPLEMENTAL INFORMATION ON O_4

SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES (UNAUDITED) - Schedule of Capitalized Costs Related to Oil and Gas Producing Activities (Details) - USD ($) $ in Thousands	Dec. 31, 2024	Dec. 31, 2023
Extractive Industries [Abstract]
Proved properties	$ 3,349,805	$ 2,904,519
Unproved properties	221,650	204,233
Total oil and natural gas properties	3,571,455	3,108,752
Accumulated depletion and amortization	(1,559,546)	(862,253)
Net capitalized costs	$ 2,011,909	$ 2,246,499

SUPPLEMENTAL INFORMATION ON O_5

SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES (UNAUDITED) - Schedule of Cost Incurred in Oil and Gas Property Acquisition Development and Exploratory Activities (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Extractive Industries [Abstract]
Acquisition	$ 89,646	$ 93,905	$ 29,675
Development	373,284	419,431	441,458
Exploratory	0	0	0
Total	$ 462,930	$ 513,336	$ 471,133

SUPPLEMENTAL INFORMATION ON O_6

SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES (UNAUDITED) - Schedule of Results of Operations for Oil and Gas Production Activities (Details)	3 Months Ended		12 Months Ended
	Dec. 31, 2024 USD ($)	Sep. 30, 2024 USD ($)	Dec. 31, 2024 USD ($) $ / MMcfe	Dec. 31, 2023 USD ($) $ / MMcfe	Dec. 31, 2022 USD ($) $ / MMcfe
Extractive Industries [Abstract]
Revenues			$ 928,604,000	$ 1,051,383,000	$ 2,330,859,000
Production costs			(451,086,000)	(450,996,000)	(482,175,000)
Depletion			(324,078,000)	(318,473,000)	(266,449,000)
Impairment	$ (342,700,000)	$ (30,500,000)	(373,214,000)	0	0
Income tax benefit			56,077,000	525,156,000	0
Results of operations from producing activities			$ (163,697,000)	$ 807,070,000	$ 1,582,235,000
Depletion per Mcf of gas equivalent (usd per Mcfe) | $ / MMcfe			0.84	0.83	0.74

SUPPLEMENTAL INFORMATION ON O_7

SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES (UNAUDITED) - Schedule of Oil and Gas Reserves (Details) - bbl	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning of the period	4,214,000,000	4,048,000,000	3,898,000,000
Purchases of reserves	0	0	0
Extensions and discoveries	547,000,000	996,000,000	439,000,000
Sales of reserves	0	0	0
Revisions of prior reserve estimates	(406,000,000)	(445,000,000)	70,000,000
Current production	(386,000,000)	(385,000,000)	(359,000,000)
End of period	3,969,000,000	4,214,000,000	4,048,000,000
Proved developed reserves (Volume)	2,109,000,000	2,203,000,000	2,295,000,000	2,165,000,000
Proved undeveloped reserves (Volume)	1,861,000,000	2,011,000,000	1,752,000,000	1,733,000,000
Oil
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning of the period	19,000,000	18,000,000	16,000,000
Purchases of reserves	0	0	0
Extensions and discoveries	5,000,000	6,000,000	3,000,000
Sales of reserves	0	0	0
Revisions of prior reserve estimates	0	(4,000,000)	0
Current production	(1,000,000)	(1,000,000)	(2,000,000)
End of period	22,000,000	19,000,000	18,000,000
Proved developed reserves (Volume)	7,000,000	6,000,000	9,000,000	8,000,000
Proved undeveloped reserves (Volume)	15,000,000	12,000,000	9,000,000	8,000,000
Natural Gas
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning of the period	3,725,000,000	3,612,000,000	3,478,000,000
Purchases of reserves	0	0	0
Extensions and discoveries	398,000,000	875,000,000	391,000,000
Sales of reserves	0	0	0
Revisions of prior reserve estimates	(413,000,000)	(411,000,000)	66,000,000
Current production	(354,000,000)	(350,000,000)	(322,000,000)
End of period	3,356,000,000	3,725,000,000	3,612,000,000
Proved developed reserves (Volume)	1,879,000,000	1,980,000,000	2,034,000,000	1,928,000,000
Proved undeveloped reserves (Volume)	1,478,000,000	1,746,000,000	1,578,000,000	1,550,000,000
Natural Gas Liquids
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning of the period	63,000,000	54,000,000	54,000,000
Purchases of reserves	0	0	0
Extensions and discoveries	20,000,000	14,000,000	5,000,000
Sales of reserves	0	0	0
Revisions of prior reserve estimates	1,000,000	(1,000,000)	0
Current production	(4,000,000)	(4,000,000)	(4,000,000)
End of period	80,000,000	63,000,000	54,000,000
Proved developed reserves (Volume)	31,000,000	31,000,000	34,000,000	31,000,000
Proved undeveloped reserves (Volume)	49,000,000	32,000,000	20,000,000	22,000,000

SUPPLEMENTAL INFORMATION ON O_8

SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES (UNAUDITED) - Schedule of Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves (Details) - USD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Extractive Industries [Abstract]
Future cash flows	$ 10,474	$ 12,338	$ 26,677
Future development and abandonment costs	(1,498)	(1,625)	(1,588)
Future production costs	(5,268)	(5,641)	(5,872)
Future production taxes	(212)	(303)	(553)
Future income taxes	(23)	(63)	(2,609)
Future net cash flows	3,473	4,706	16,055
10% discount to reflect timing of cash flows	(1,726)	(2,323)	(7,776)
Standardized measure of discounted future net cash flows	$ 1,747	$ 2,383	$ 8,279

SUPPLEMENTAL INFORMATION ON O_9

SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES (UNAUDITED) - Schedule of Future Costs to Settle Asset Retirement Obligations (Details) - USD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Extractive Industries [Abstract]
Future asset retirement obligations	$ 240	$ 229	$ 222

SUPPLEMENTAL INFORMATION ON _10

SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES (UNAUDITED) - Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Extractive Industries [Abstract]
Sales and transfers of oil and gas produced, net of production costs	$ (478)	$ (600)	$ (1,849)
Net changes in prices, production costs, and development costs	(910)	(7,181)	5,130
Acquisition of oil and gas reserves in place	0	0	0
Extensions and discoveries	368	581	941
Previously estimated development costs incurred during the period	211	263	204
Revisions of previous quantity estimates, less related production costs	(21)	(278)	154
Sales of oil and gas reserves in place	0	0	(1)
Accretion of discount	238	828	414
Net changes in income taxes	16	1,219	(1,067)
Change in production rates and other	(60)	(728)	215
Total change in standardized measure of discounted future net cash flows	$ (636)	$ (5,896)	$ 4,141

SUBSEQUENT EVENTS (Details)

SUBSEQUENT EVENTS (Details) - Subsequent Event	Feb. 20, 2025 MMBTU $ / MMBTU $ / barrel bbl
Swaps NYMEX Henry Hub
Subsequent Event [Line Items]
Daily Volume | MMBTU	18,301
Weighted average price of derivative swap (usd per MMBtu or Bbls) | $ / MMBTU	3.85
Basis Swaps, Rex Zone 3
Subsequent Event [Line Items]
Daily Volume | MMBTU	40,000
Weighted average price of derivative swap (usd per MMBtu or Bbls) | $ / MMBTU	(0.17)
Swaps, NYMEX WTI
Subsequent Event [Line Items]
Daily volume (Bbls/day) | bbl	1,000
Weighted average price of derivative swap (usd per MMBtu or Bbls) | $ / barrel	70.87