UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)


☒			ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, ~~2024~~2025


☐			TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File Number 001-19514

Gulfport Energy Corporation

(Exact name of registrant as specified in its charter)


Delaware		86-3684669
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)
713 Market Drive
Oklahoma City,	Oklahoma	73114
(Address of principal executive offices)		(Zip Code)

(405) 252-4600

(Registrant telephone number, including area code)

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

Title of each class

Trading Symbol(s)

Name of each exchange on which registered

Common Stock, $0.0001 par value per share

GPOR

The New York Stock Exchange

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

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

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

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

Yes ☒ No ☐

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

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

Smaller reporting company ☐ Emerging growth company ☐

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

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

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐

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Index to Financial Statements

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐

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

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by the court. Yes ☒ No ☐

The aggregate market value of our common stock held by non-affiliates on June 30, ~~2024~~2025 was approximately $23.01 billion. As of February 2019, ~~2025~~2026, there were 1718,~~894~~558,~~932~~415 shares of our $0.0001 par value common stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of Gulfport Energy Corporation’s Proxy Statement for the ~~2025~~2026 Annual Meeting of Stockholders are incorporated by reference in Items 10, 11, 12, 13 and 14 of Part III of this Form 10-K.

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Index to Financial Statements

GULFPORT ENERGY CORPORATION

TABLE OF CONTENTS

		Page
FORWARD-LOOKING STATEMENTS		1
SUMMARY RISK FACTORS		2
PART I		4
ITEM 1.	BUSINESS	4
ITEM 1A.	RISK FACTORS	20
ITEM 1B.	UNRESOLVED STAFF COMMENTS	36
ITEM 1C.	CYBERSECURITY	36
ITEM 2.	PROPERTIES	38
ITEM 3.	LEGAL PROCEEDINGS	38
ITEM 4.	MINE SAFETY DISCLOSURES	38
PART II		39
ITEM 5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	39
ITEM 6.	RESERVED	40
ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	40
	RESULTS OF OPERATIONS	43
	LIQUIDITY AND CAPITAL RESOURCES	4847
	CRITICAL ACCOUNTING POLICIES AND ESTIMATES	53
ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	54
ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	5756
ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	9794
ITEM 9A.	CONTROLS AND PROCEDURES	9794
ITEM 9B.	OTHER INFORMATION	9996
ITEM 9C.	DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS	9996
PART III		9996
ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	9996
ITEM 11.	EXECUTIVE COMPENSATION	9996
ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	9996
ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	9996
ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES	9996
PART IV		~~100~~97
ITEM 15.	EXHIBITS AND FINANCIAL STATEMENT SCHEDULES	~~100~~97
ITEM 16.	FORM 10-K SUMMARY	~~104~~101
Signatures		~~105~~102

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Index to Financial Statements

DEFINITIONS

Unless the context otherwise indicates, references to “us,” “we,” “our,” “ours,” “Gulfport,” the “Company” and “Registrant” refer to Gulfport Energy Corporation and its consolidated subsidiaries. All monetary values, other than per unit and per share amounts, are stated in thousands of U.S. dollars unless otherwise specified. In addition, the following are other abbreviations and definitions of certain terms used within this Annual Report on Form 10-K: 1145 Indenture. Indenture dated May 17, 2021 between Gulfport Operating, UMB Bank, National Association, as trustee, and the guarantors party thereto, under section 1145 of the Bankruptcy Code for our 8.0% Senior Notes due 2026. ~~2026~~ Senior Notes. 8.000% Senior Notes due May 17, 2026. ~~2026 Senior Notes Indentures. Collectively, the 1145 Indenture and the 4(a)(2) Indenture governing the 2026 Senior Notes.~~ 2029 Senior Notes. 6.~~750~~75% Senior Notes due September 1, 2029. 2029 Senior Notes Indenture. Indenture dated September 13, 2024 between Gulfport Operating, UMB Bank, National Association, as trustee, and the guarantors party thereto. 4(a)(2) Indenture. Certain eligible holders made an election entitling such holders to receive senior notes issued pursuant to an indenture, dated as of May 17, 2021, by and among Gulfport Operating, UMB Bank, National Association, as trustee, and the guarantors party thereto, under Section 4(a)(2) of the Securities Act of 1933, as amended (the “Securities Act”) as opposed to its share of the up to $550 million aggregate principal amount of our Senior Notes due 2026. The 4(a)(2) Indenture’s terms are substantially similar to the terms of the 1145 Indenture. The primary differences between the terms of the 4(a)(2) Indenture and the terms of the 1145 Indenture are that (i) affiliates of the Issuer holding 4(a)(2) Notes are permitted to vote in determining whether the holders of the required principal amount of indenture securities have concurred in any direction or consent under the 4(a)(2) Indenture, while affiliates of the Issuer holding 1145 Notes will not be permitted to vote on such matters under the 1145 Indenture, (ii) the covenants of the 1145 Indenture (other than the payment covenant) require that the Issuer comply with the covenants of the 4(a)(2) Indenture, as amended, and (iii) the 1145 Indenture requires that the 1145 Securities be redeemed pro rata with the 4(a)(2) Securities and that the 1145 Indenture be satisfied and discharged if the 4(a)(2) Indenture is satisfied and discharged. ASC. Accounting Standards Codification. ASU. Accounting Standards Update. Bankruptcy Code. Chapter 11 of Title 11 of the United States Code. Bankruptcy Court. The United States Bankruptcy Court for the Southern District of Texas. Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to crude oil or other liquid hydrocarbons. Bcf. One billion cubic feet of natural gas. Bcfe. One billion cubic feet of natural gas equivalent, with one barrel of NGL and crude oil being equivalent to 6,000 cubic feet of natural gas. Board of Directors (Board). The board of directors of Gulfport Energy Corporation. ~~Bps. Basis points.~~ Btu. British thermal unit, which represents the amount of energy needed to heat one pound of water by one degree Fahrenheit and can be used to describe the energy content of fuels. Chapter 11 Cases. Voluntary petitions filed on November 13, 2020 by Gulfport Energy Corporation, Gator Marine, Inc., Gator Marine Ivanhoe, Inc., Grizzly Holdings, Inc., Gulfport Appalachia, LLC, Gulfport Midcon, LLC, Gulfport Midstream Holdings, LLC, Jaguar Resources LLC, Mule Sky LLC, Puma Resources, Inc. and Westhawk Minerals LLC. CODM. Chief Operating Decision Maker. Completion. The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas, oil and NGL. Credit Facility. The Third Amended and Restated Credit Agreement with JPMorgan Chase Bank, N.A. as administrative agent and various lender parties, providing for a senior secured reserve-‑based revolving credit facility effective as of October 14, 2021, as amended most recently by the ~~Commitment Increase,~~ Borrowing Base Reaffirmation Agreement, and ~~Fourth~~Fifth Amendment to Credit Agreement dated asOctober ~~of September 12~~30, ~~2024~~2025. DD&A. Depreciation, depletion and amortization. Debtors. Collectively, Gulfport Energy Corporation, Gator Marine, Inc., Gator Marine Ivanhoe, Inc., Grizzly Holdings, Inc., Gulfport Appalachia, LLC, Gulfport Midcon, LLC, Gulfport Midstream Holdings, LLC, Jaguar Resources LLC, Mule Sky LLC, Puma Resources, Inc. and Westhawk Minerals LLC. Developed Acreage. The number of acres allocated or assignable to productive wells or wells capable of production. Development Well. A well drilled within the proved area of a natural gas or crude oil reservoir to the depth of a stratigraphic horizon known to be productive. Disputed Claims Reserve. Reserve used to settle any pending claims of unsecured creditors that were in dispute as of the effective date of the Plan. Emergence Date. Gulfport filed for voluntary reorganization under Chapter 11 of the Bankruptcy Code on November 13, 2020, and subsequently operated as a debtor-in-possession, in accordance with applicable provisions of the Bankruptcy Code, until its emergence on May 17, 2021. Exploratory Well. A well drilled to find crude oil or natural gas in an unproved area, to find a new reservoir in an existing field previously found to be productive of crude oil or natural gas in another reservoir, or to extend a known reservoir beyond the proved area. FASB. Financial Accounting Standards Board.

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Index to Financial Statements

Debtors. Collectively, Gulfport Energy Corporation, Gator Marine, Inc., Gator Marine Ivanhoe, Inc., Grizzly Holdings, Inc., Gulfport Appalachia, LLC, Gulfport Midcon, LLC, Gulfport Midstream Holdings, LLC, Jaguar Resources LLC, Mule Sky LLC, Puma Resources, Inc. and Westhawk Minerals LLC. Developed Acreage. The number of acres allocated or assignable to productive wells or wells capable of production. Development Well. A well drilled within the proved area of a natural gas or crude oil reservoir to the depth of a stratigraphic horizon known to be productive. Disputed Claims Reserve. Reserve used to settle any pending claims of unsecured creditors that were in dispute as of the effective date of the Plan. Emergence Date. Gulfport filed for voluntary reorganization under Chapter 11 of the Bankruptcy Code on November 13, 2020, and subsequently operated as a debtor-in-possession, in accordance with applicable provisions of the Bankruptcy Code, until its emergence on May 17, 2021. Exploratory Well. A well drilled to find crude oil or natural gas in an unproved area, to find a new reservoir in an existing field previously found to be productive of crude oil or natural gas in another reservoir, or to extend a known reservoir beyond the proved area. FASB. Financial Accounting Standards Board. GAAP. Accounting principles generally accepted in the United States of America. Grizzly. Grizzly Oil Sands ULC. Grizzly Holdings. Grizzly Holdings Inc. Gross Acres or Gross Wells. Refers to the total acres or wells in which a working interest is owned. Guarantors. All existing consolidated subsidiaries that guarantee the Company's Credit Facility or certain other debt. Gulfport Operating. Gulfport Energy Operating Corporation. Held By Production. Refers to an oil and gas lease continued into its secondary term for so long as a producing oil and/or gas well is located on any portion of the leased premises or lands pooled therewith. Horizontal Drilling. A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled horizontally within a specified interval. Incentive Plan. Gulfport Energy Corporation 2021 Stock Incentive Plan, effective on the Emergence Date. IRC. The Internal Revenue Code of 1986, as amended. ~~LIBOR. London Interbank Offered Rate.~~ LOE. Lease operating expenses. Marcellus. Refers to the Marcellus Play that includes the hydrocarbon bearing rock formations commonly referred to as the Marcellus formation located in the Appalachian Basin of the United States and Canada. Our acreage is located primarily in Belmont, Jefferson and Monroe County in eastern Ohio. MBbl. One thousand barrels of crude oil, condensate or natural gas liquids. Mcf. One thousand cubic feet of natural gas. Mcfe. One thousand cubic feet of natural gas equivalent, with one barrel of NGL and crude oil being equivalent to 6,000 cubic feet of natural gas. MMBbl. One million barrels of crude oil, condensate or natural gas liquids. MMBtu. One million British thermal units. MMcf. One million cubic feet of natural gas. MMcfe. One million cubic feet of natural gas equivalent, with one barrel of NGL and crude oil being equivalent to 6,000 cubic feet of natural gas. Natural Gas Liquids (NGL). Hydrocarbons in natural gas that are separated from the gas as liquids through the process of absorption, condensation, adsorption or other methods in gas processing or cycling plants. Natural gas liquids primarily include ethane, propane, butane, isobutene, pentane, hexane and natural gasoline. Net Acres or Net Wells. Refers to the sum of the fractional working interests owned in gross acres or gross wells. Net Revenue Interest (NRI). An interest in an oil and natural gas property entitling the owner to a share of oil, natural gas or NGL production. NYMEX. New York Mercantile Exchange. OCC. Oklahoma Corporation Commission. Parent. Gulfport Energy Corporation. Plan. The Amended Joint Chapter 11 Plan of Reorganization of Gulfport Energy Corporation and Its Debtor Subsidiaries. Predecessor. The pre-emergence from bankruptcy organization for periods on or prior to May 17, 2021. Productive Well. A well found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes. Proved Developed Reserves (PDP). Reserves expected to be recovered through existing wells with existing equipment and operating methods. Proved Reserves. Quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible, from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

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Index to Financial Statements

Net Revenue Interest (NRI). An interest in an oil and natural gas property entitling the owner to a share of oil, natural gas or NGL production. NYMEX. New York Mercantile Exchange. OCC. Oklahoma Corporation Commission. Parent. Gulfport Energy Corporation. Plan. The Amended Joint Chapter 11 Plan of Reorganization of Gulfport Energy Corporation and Its Debtor Subsidiaries. Predecessor. The pre-emergence from bankruptcy organization for periods on or prior to May 17, 2021. Productive Well. A well found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes. Proved Developed Reserves (PDP). Reserves expected to be recovered through existing wells with existing equipment and operating methods. Proved Reserves. Quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible, from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. Proved Undeveloped Reserves (PUD). Proved reserves expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for completion. Reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having proved undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. PV-10. Present net value of estimated future net revenues, discounted at 10%. Repurchase Program. A stock repurchase program to acquire up to $1.5 billion of Gulfport's outstanding common stock. It is authorized to extend through December 31, ~~2025~~2026, and may be suspended from time to time, modified, extended or discontinued by the Board of Directors at any time. Reservoir. A porous and permeable underground formation containing a natural accumulation of producible crude oil and/or natural gas that is confined by impermeable rock or water barriers and is separate from other reservoirs. Royalty Interest. Refers to the ownership of a percentage of the resources or revenues produced from a crude oil or natural gas property. A royalty interest owner does not bear exploration, development, or operating expenses associated with drilling and producing a crude oil or natural gas property. RTSR. Relative total shareholder return. SCOOP. Refers to the South Central Oklahoma Oil Province, a term used to describe a defined area that encompasses many of the top hydrocarbon producing counties in Oklahoma within the Anadarko basin. The SCOOP Play mainly targets the Devonian to Mississippian aged Woodford, Sycamore and Springer formations. Our acreage is primarily in Garvin, Grady and Stephens Counties. SEC. The United States Securities and Exchange Commission. Section 382. Internal Revenue Code Section 382. SOFR. Secured Overnight Financing Rate. Standardized Measure. Standardized measure of discounted future net cash flows. ~~Successor. The post-emergence from bankruptcy reorganized organization for periods subsequent to May 17, 2021.~~ Tcfe. One trillion cubic feet of natural gas equivalent, with one barrel of NGL and crude oil being equivalent to 6,000 cubic feet of natural gas. TSR. Total shareholder return. Undeveloped Acreage. Lease or mineral acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of crude oil and/or natural gas. USEPA. United States Environmental Protection Agency. Utica. Refers to the Utica Play that includes the hydrocarbon bearing rock formations commonly referred to as the Utica formation located in the Appalachian Basin of the United States and Canada. Our acreage is located primarily in Belmont, Harrison, Jefferson and Monroe Counties in eastern Ohio. Working Interest (WI). The operating interest which gives the owner the right to drill, produce and conduct operating activities on the property and a share of production. WTI. Refers to West Texas Intermediate.

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Utica. Refers to the Utica Play that includes the hydrocarbon bearing rock formations commonly referred to as the Utica formation located in the Appalachian Basin of the United States and Canada. Our acreage is located primarily in Belmont, Harrison, Jefferson and Monroe Counties in eastern Ohio. Working Interest (WI). The operating interest which gives the owner the right to drill, produce and conduct operating activities on the property and a share of production. WTI. Refers to West Texas Intermediate.

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Index to Financial Statements

FORWARD-LOOKING STATEMENTS

This Form 10-K may include forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and the Private Securities Litigation Reform Act of 1995, that are subject to risks and uncertainties. These statements involve known and unknown risks, uncertainties and other factors that may cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by the forward-looking statements. In some cases, you can identify forward looking statements by terms such as “may,” “will,” “should,” “could,” “would,” “expects,” “plans,” “anticipates,” “intends,” “believes,” “estimates,” “projects,” “predicts,” “potential” and similar expressions intended to identify forward-looking statements. All statements, other than statements of historical facts, included in this Form 10-K that address activities, events or developments that we expect or anticipate will or may occur in the future, including ~~the expected impact of the war in Ukraine and the conflict in the Middle East on our business, our industry and the global economy,~~ estimated future production and net revenues from oil and gas reserves and the present value thereof, future capital expenditures (including the amount and nature thereof and the information under the heading “~~2025~~2026 Outlook”), share repurchases, business strategy and measures to implement strategy, competitive strength, goals, expansion and growth of our business and operations, plans, references to future success, reference to intentions as to future matters and other such matters are forward-looking statements.

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

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

All forward-looking statements, expressed or implied, included in this Annual Report are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.

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

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

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SUMMARY RISK FACTORS

Financial, Liquidity and Commodity Price Risks

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

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

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

•Our debt and other financial commitments may limit our financial and operating flexibility.

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

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

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

Industry, Business and Operational Risks

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

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

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

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

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

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

•Multi-well pad drilling may result in volatility in our operating results and delay the conversion of our PUD reserves.

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

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

•All of our producing properties are located in eastern Ohio and central Oklahoma, making us vulnerable to risks associated with operating in only these regions.

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

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

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

•We are required to pay fees to some of our midstream service providers based on minimum volumes regardless of actual volume throughput.

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

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

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

•We may engage in acquisition and divestiture activities that involve substantial risks.

Environmental, Legal and Regulatory Risks

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

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

•Increased attention to ~~Environmental,~~sustainability ~~Social and Governance (“ESG”)~~ matters may impact our business, financial results, or stock price.

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

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

Risks Associated with an Investment in Us

•The market price of our securities is subject to volatility.

•Future sales or the availability for sale of substantial amounts of our common stock, or the perception that these sales may occur, could adversely affect the trading price of our common stock and could impair our ability to raise capital through future sales of equity securities.

•Certain of our stockholders own a significant portion of our outstanding equity securities, and their interests may not always coincide with the interests of other holders of the common stock.

•There may be future dilution of our common stock, which could adversely affect the market price of our common stock.

•Our amended and restated certificate of incorporation provides, subject to certain exceptions, that the Court of Chancery of the State of Delaware will be the sole and exclusive forum for certain stockholder litigation matters, which could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers, employees or stockholders.

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PART I


ITEM 1.			BUSINESS

Our Business

Gulfport is an independent natural gas-weighted exploration and production company with assets primarily located in the Appalachia and Anadarko basins. Our principal ~~properties~~operations ~~are~~target ~~located in eastern Ohio targeting~~ the Utica and Marcellus ~~and~~formations in ~~central~~eastern ~~Oklahoma~~Ohio ~~targeting~~and the SCOOP Woodford and Springer formations in central Oklahoma. Gulfport's Predecessor was incorporated in the State of Delaware in July 1997. Our corporate headquarters are located in Oklahoma City, Oklahoma and shares of Gulfport's common stock trade on the New York Stock Exchange (“NYSE”) under the ticker symbol “GPOR”. Our corporate strategy is focused on the economic development of our asset base in an effort to generate sustainable free cash flow.

As of December 31, ~~2024~~2025, we had 4.03 Tcfe of proved reserves with a Standardized Measure of $13.754 billion and a PV-10 of $13.766 billion. See “Definitions” above for our definition of PV-10 (a non-GAAP financial measure) and “Oil, Natural Gas and NGL Reserves and Estimation” below for a reconciliation of our standardized measure of discounted future net cash flows (the most directly comparable GAAP measure) to PV-10.

Information About Us

Our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act are made available free of charge on the Investor Relations page of our website at www.gulfportenergy.com as soon as reasonably practicable after such material is electronically filed with, or furnished to, the SEC. From time to time, we also post announcements, updates, events, investor information and presentations on our website in addition to copies of our recent news releases. Information contained on our website, or on other websites that may be linked to our website, is not incorporated by reference into this annual report on Form 10-K and should not be considered part of this report or any other filing that we make with the SEC.

Emergence From Voluntary Reorganization Under Chapter 11 of the Bankruptcy Code

On November 13, 2020, we, and certain of our subsidiaries, filed voluntary petitions for relief under Chapter 11 of Title 11 of the United States Code in the United States Bankruptcy Court for the Southern District of Texas. The ~~Chapter 11 Cases were administered jointly under the caption In re Gulfport Energy Corporation, et al., Case No. 20-35562 (DRJ). The~~ Bankruptcy Court confirmed the Plan and entered the confirmation order on April 28, 2021, and the Debtors emerged from the Chapter 11 Cases on the Emergence Date. On May 18, 2021, we began trading on the NYSE under the symbol “GPOR”.

Business Strategy

Gulfport aims to create sustainable value through the economic development of our significant resource plays in the Utica/Marcellus and SCOOP operating areas. Our strategy is to develop our assets in a safe, environmentally responsible manner, while generating sustainable cash flow, ~~improving~~enhancing margins and operating efficiencies and returning capital to shareholders. To ~~accomplish~~achieve these goals, we generally allocate capital to projects we believe offer the highest rate of return and we deploy leading drilling and completion techniques and technologies in our development efforts. We believe our plan to generate free cash flow on an annual basis will allow us to further strengthen our balance sheet, return capital to shareholders and increase our resource depth through incremental leasehold opportunities that provide optionality to our future development plans.

~~2025~~2026 Outlook

Our ~~2025~~2026 capital expenditure program is expected to be in a range of $~~370~~400 million to $~~395~~430 million, including $35 million to $40 million on maintenance land and seismic investments. In the Utica, we intend to complete drilling on approximately 1718 gross (17.05 net) operated horizontal wells and commence sales on approximately 2220 gross (2119.95 net) operated horizontal wells. In the Marcellus, we intend to complete drilling on approximately 86 gross (85.06 net) ~~operated horizontal wells~~ and commence sales on approximately 4 gross (4.0 net) operated horizontal wells. In the SCOOP, we intend to complete drilling ~~on approximately two gross (1.8 net) operated horizontal wells~~ and commence sales on ~~two~~approximately 2 gross (1.87 net) operated horizontal wells. We expect to fund these expenditures with our operating cash flow and borrowings under our Credit Facility.

We expect this ~~drilling~~development program to result in approximately 1~~,040~~.030 to 1~~,065~~.055 ~~MMcfe~~Bcfe per day of production in ~~2025~~2026.

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Index to Financial Statements

Additionally, in ~~2025~~2026, we expect ato ~~continuation~~continue ofreturning ~~shareholder~~capital ~~return~~to ~~actions~~shareholders through our Repurchase Program. During ~~2024~~2025, we repurchased 1.28 million shares for $~~184~~336.53 million at a weighted average price of $~~153~~188.3565 per share, leaving $~~415~~579.96 million remaining on our Repurchase Program, which expires on December 31, ~~2025~~2026.

Operating Areas

Utica/Marcellus - The Utica covers hydrocarbon-bearing rock formations located in the Appalachian Basin of the United States and Canada. We have approximately ~~208~~223,000 net reservoir acres located primarily in Belmont, Harrison, Jefferson and Monroe Counties in eastern Ohio where the Utica ranges in thickness from 600 to over 750 feet.

The Marcellus covers hydrocarbon-bearing rock formations that generally overlay the Utica in Ohio. We have identified approximately 2035,~~500~~000 net reservoir acres of our existing leasehold for Marcellus development and have 2225 PUD Marcellus locations ~~within our Utica operating area~~. In ~~2023~~2025 we drilled, completed, and turned to sales ~~two~~our ~~Marcellus~~first ~~wells~~four ~~and~~well ~~have~~development ~~plans~~pad toin ~~drill~~the ~~eight~~ Marcellus ~~wells and complete and turn to sales four Marcellus wells in 2025~~. Our Marcellus development area is approximately 3,500 to 4,500 feet shallower than the Utica. ~~During 2024, we produced approximately 842 MMcfe per day net to our interests in Utica/Marcellus and it accounted for approximately 80% of our total production.~~

SCOOP - The SCOOP is a defined area that encompasses many of the top hydrocarbon producing counties in Oklahoma within the Anadarko Basin. The SCOOP play mainly targets the Devonian to Mississippian aged Woodford, Sycamore and Springer formations. We have approximately 73,000 net reservoir acres (comprised of approximately 43,000 in the Woodford formation and approximately 30,000 in the Springer formation) located primarily in Garvin, Grady and Stephens Counties. The Woodford Shale across our position ranges in thickness from 200 to over 400 feet and directly overlies the Hunton Limestone and underlies the Sycamore formation, both of which are also locally productive reservoirs. The Sycamore formation consists of hydrocarbon-bearing interbedded shales and siliceous limestones ranging in thickness from 150 to over 450 feet and is overlain by the Caney Shale. The Springer formation across our position is comprised of a series of lenticular sand and shale units. The primary targets are a series of porous, low clay and organic-rich packages within the Goddard Shale member ranging in thickness from 50 to over 250 feet. During ~~2024~~2025, we produced approximately ~~212~~841 MMcfe per day net to our interests in ~~the~~Utica/Marcellus ~~SCOOP~~ and it accounted for approximately 2081% of our total production.

SCOOP - The SCOOP is a defined area that encompasses many of the top hydrocarbon producing counties in Oklahoma within the Anadarko Basin. The SCOOP play mainly targets the Devonian to Mississippian aged Woodford, Sycamore and Springer formations. We have approximately 74,000 net reservoir acres (comprised of approximately 44,000 in the Woodford formation and approximately 30,000 in the Springer formation) located primarily in Garvin, Grady and Stephens Counties. The Woodford Shale across our position ranges in thickness from 200 to over 400 feet and directly overlies the Hunton Limestone and underlies the Sycamore formation, both of which are also locally productive reservoirs. The Sycamore formation consists of hydrocarbon-bearing interbedded shales and siliceous limestones ranging in thickness from 150 to over 450 feet and is overlain by the Caney Shale. The Springer formation across our position is comprised of a series of lenticular sand and shale units. The primary targets are a series of porous, low clay and organic-rich packages within the Goddard Shale member ranging in thickness from 50 to over 250 feet.

During 2025, we produced approximately 197 MMcfe per day net to our interests in the SCOOP and it accounted for approximately 19% of our total production.

Oil, Natural Gas and NGL Reserves and Estimation

Reserve engineering is a subjective process of estimating volumes of economically recoverable oil, natural gas and NGL that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. As a result, the reserve estimates of different engineers often vary. In addition, the results of drilling, testing and production may justify revisions of such estimates. Accordingly, reserve estimates often differ from the quantities of oil and natural gas that are ultimately recovered. Estimates of economically recoverable oil and natural gas and of future net revenues are based on a number of variables and assumptions, all of which may vary from actual results, including geologic interpretation, prices and future production rates and costs. See Item 1A. “Risk Factors” contained elsewhere in this Form 10-K.

As discussed above, the process of estimating oil, natural gas and NGL reserves is complex and requires significant judgment. As a result, we have developed internal policies and controls for estimating and recording reserves. Estimates of proved developed and undeveloped reserves and related information are presented in accordance with the requirements of the SEC's rules for the Modernization of Oil and Gas Reporting. These rules permit the use of reliable technologies to estimate and categorize reserves and require the use of the unweighted average of the first-of-the-month commodity prices, adjusted for location and quality differentials, for the prior 12 months (unless contractual arrangements designate the price) to calculate economic producibility of reserves and the discounted cash flows reported as the Standardized Measure of Future Net Cash Flows Relating to Proved Reserves. Reliable technologies were used to support the undeveloped locations in the Utica/Marcellus and SCOOP operating areas. The Company used public and proprietary geologic and engineering data to establish continuity of the formation and its producing properties. This data included performance data, seismic data, open hole log information, petro-physical analysis of log data, mud logs, log cross-sections, gas sample analysis, statistical analysis and measurements of total organic content and thermal maturity. In our development area, these data demonstrated consistent and continuous reservoir characteristics. Refer to Note 20 of our consolidated financial statements for more information pertaining to our proved reserves and the preparation of such estimates.

Our Senior Vice President of Reservoir Engineering is primarily responsible for overseeing the preparation of all of our reserve estimates. He is a petroleum engineer with over 28 years of reservoir and operations experience. In addition, our geoscience staff has approximately 51 years combined industry experience and our reservoir staff has approximately 61 years combined experience.

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Index to Financial Statements

~~During~~Our ~~2024,~~Senior ~~our~~Vice ~~total~~President ~~net natural gas, NGLs and oil proved reserves estimates attributable to the Company's interests were prepared by our engineers and Netherland, Sewell & Associates, Inc. (“NSAI”) conducted an audit~~ of ~~the~~Reservoir ~~proved~~Engineering ~~reserves as of December 31, 2024. NSAI~~ is anprimarily ~~independent~~responsible ~~petroleum engineering firm and were selected~~ for ~~their~~overseeing ~~historical experience and geographic expertise in engineering similar resources. In~~ the ~~course~~preparation of ~~its~~all ~~audit, NSAI conducted a detailed review~~ of ~~properties~~our ~~making~~reserve ~~up approximately 85% of the total proved reserves and accounting for approximately 95% of the present worth of those reserves~~estimates. ~~The~~He estimates prepared by the Company and audited by NSAI were within the recommended 10% tolerance threshold set forth in the Standards Pertaining to the Estimation and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers A copy of the summary reserve report is ~~included~~a ~~as Exhibit 99.1 to this Annual Report on Form 10-K. Our internal staff of~~ petroleum ~~engineers~~engineer ~~and geoscience professionals work closely~~ with ~~NSAI~~30 toyears ~~ensure the integrity, accuracy and timeliness~~ of ~~the~~reservoir ~~data used to calculate our proved reserves. Our internal technical team members meet with NSAI periodically throughout the year to discuss the assumptions~~ and ~~methods~~operations ~~used in the proved reserve estimation process~~experience. AsIn ~~needed~~addition, ~~we provide historical information to NSAI for~~ our ~~properties~~geoscience ~~such~~staff ashas ~~ownership~~approximately ~~interest,~~58 ~~oil~~years ~~and~~combined ~~gas~~industry ~~production,~~experience ~~well test data, commodity prices, operating~~ and ~~development~~our ~~costs~~reservoir ~~and~~staff ~~other~~also ~~considerations,~~has ~~including~~approximately ~~availability~~58 ~~and costs of infrastructure and status of permits. Reserve estimates for the~~ years ~~ended~~combined ~~2023 and 2022, were prepared by NSAI for 100% of our operating areas~~experience.

During 2025, our total net natural gas, NGLs and oil proved reserves estimates attributable to the Company's interests were prepared by the Company and Netherland, Sewell & Associates, Inc. (“NSAI”) conducted an audit of the proved reserves as of December 31, 2025. NSAI is an independent petroleum engineering firm and was selected for their historical experience and geographic expertise in engineering similar resources. In the course of its audit, NSAI conducted a detailed review of properties making up approximately 86% of the total proved reserves and accounting for approximately 88% of the present worth of those reserves. The estimates prepared by the Company and audited by NSAI were within the recommended 10% tolerance threshold set forth in the Standards Pertaining to the Estimation and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. A copy of the summary reserve report is included as Exhibit 99.1 to this Annual Report on Form 10-K. Our internal staff of petroleum engineers and geoscience professionals work closely with NSAI to ensure the integrity, accuracy and timeliness of the data used to calculate our proved reserves. Our internal technical team members meet with NSAI periodically throughout the year to discuss the assumptions and methods used in the proved reserve estimation process. As needed, we provide historical information to NSAI for our properties such as ownership interest, oil and gas production, well test data, commodity prices, operating and development costs and other considerations, including availability and costs of infrastructure and status of permits.

Reserve estimates for the year ended 2024 were prepared by the Company and audited by NSAI as of December 31, 2024. Reserve estimates for the year ended 2023 were prepared by NSAI for 100% of our operating areas.

Internal Controls Over Proved Reserve Estimates

Our proved reserve estimates are prepared in accordance with our internal control procedures. These procedures, which are intended to ensure reliability of reserve estimations, include the following:

•review and verification of historical production, operating, marketing and capital data, which data is based on actual production as reported by us;

•verification of property ownership by our land department;

•audit of year-end reserve estimates by NSAI;

•direct reporting responsibilities by our reservoir engineering department to our Chief Executive Officer;

•review by our reservoir engineering department of all of our reported proved reserves at the close of each quarter, including the review of all significant reserve changes and all new proved undeveloped reserves additions;

•provision of quarterly updates to our Board of Directors regarding operational data, including production, drilling and completion activity levels and any significant changes in our reserves;

•annual review by our Board of Directors of our year-end reserve report and year-over-year changes in our proved reserves;

•annual review by our senior management of adjustments to our previously adopted development plan and considerations involved in making such adjustments, including the substitution, removal or deferral of PUD locations; and

•annual review and approval by our senior management and our Board of Directors of a multi-year development plan.

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Index to Financial Statements

The tables below set forth information as of December 31, ~~2024~~2025, with respect to our estimated proved developed and undeveloped oil, natural gas and NGL reserves, the associated estimated future net revenue, the PV-10 and the standardized measure. None of the estimated future net revenue, PV-10 nor the standardized measure are intended to represent the current market value of the estimated oil, natural gas and NGL reserves we own. All of our estimated reserves are located within the United States.

December 31, 2024

December 31, 2025

Oil(MMBbl)

Natural Gas(Bcf)

NGL (MMBbl)

Total (Bcfe)

Utica & Marcellus

Proved developed(1)

1,~~427~~717

812

1,~~498~~818

Proved undeveloped(1)

1314

1,189

3639

1,~~480~~510

Total proved(1)

1719

2,~~616~~906

4452

23,~~978~~328

SCOOP

Proved developed

~~451~~440

2321

~~611~~587

Proved undeveloped

~~289~~266

1310

~~380~~338

Total proved

~~740~~707

3631

~~991~~925

Total

Proved developed

12,~~879~~157

3133

2,~~109~~404

Proved undeveloped

1516

1,~~478~~455

4950

1,~~861~~848

Total proved

2224

3,~~356~~612

8083

34,~~969~~253

Totals may not sum or recalculate due to rounding.

_____________________

(1) Includes approximately 1226 Bcfe and ~~174~~210 Bcfe of net developed and undeveloped reserves, respectively, located in the Marcellus target formation.

December 31, 2024

December 31, 2025

Proved Developed

Proved Undeveloped

Total Proved

($ in millions)

Estimated future net revenue(1)

13,~~620~~816

13,~~876~~145

36,~~496~~961

Present value of estimated future net revenue (PV-10)(1)

12,~~059~~291

~~699~~1,331

13,~~757~~622

Standardized measure(1)

$3,403

~~1,747~~

Totals may not sum due to rounding.

_____________________

(1) Estimated future net revenue represents the estimated future revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using prices and costs under existing economic conditions as of December 31, ~~2024~~2025, and assuming commodity prices as set forth below. For the purpose of determining prices used in our reserve reports, we used the unweighted arithmetic average of the prices on the first day of each month within the 12-month period ended December 31, ~~2024~~2025. The prices used in our PV-10 measure were the average WTI Spot price of $7666.3201 per barrel and the average Henry Hub Spot price of $23.1339 per MMBtu, before basis differential adjustments. These prices should not be interpreted as a prediction of future prices, nor do they reflect the value of our commodity derivative instruments in place as of December 31, ~~2024~~2025. The amounts shown do not give effect to non-property-related expenses, such as corporate general and administrative expenses and debt service, or to depreciation, depletion and amortization. The present value of estimated future net revenue typically differs from the standardized measure because the former does not include the effects of estimated future income tax expense of $10219 million as of December 31, ~~2024~~2025.

Management uses PV-10, which is calculated without deducting estimated future income tax expenses, as a measure of the value of the Company's current proved reserves and to compare relative values among peer companies. We also understand that securities analysts and rating agencies use this measure in similar ways. While estimated future net revenue and the present value thereof are based on prices, costs and discount factors which may be consistent from company to company, the standardized measure of discounted future net cash flows is dependent on the unique tax situation of each individual company. PV-10 should not be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows or any other measure of a company's financial or operating performance presented in accordance with GAAP.

A reconciliation of the standardized measure of discounted future net cash flows to PV-10 is presented above. Neither PV-10 nor the standardized measure of discounted future net cash flows purport to represent the fair value of our proved oil and gas reserves.

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Index to Financial Statements

The following table summarizes the changes in our estimated proved reserves during ~~2024~~2025 (in Bcfe):

Proved Reserves, December 31, 2023			4,214
Sales of oil and natural gas reserves in place			—
Extensions and discoveries			547
Revisions of prior reserve estimates			(406)
Current production			(386)
Proved Reserves, December 31, 2024			3,969
Sales of oil and natural gas reserves in place			—
Extensions and discoveries			701
Revisions of prior reserve estimates			(38)
Current production			(379)
Proved Reserves, December 31, 2025			4,253
Total may not sum due to rounding.

Extensions and discoveries. These are additions to our proved reserves that result from extension of the proved acreage of previously discovered reservoirs through additional drilling in periods subsequent to discovery. Extensions of approximately ~~547~~701 Bcfe of proved reserves were primarily attributable to the continued development of our Utica/Marcellus and SCOOP acreage. We added 4635 PUD locations in the Utica/Marcellus which included 3328 Utica locations for ~~341~~382 Bcfe and 137 Marcellus locations for 9262 Bcfe. We also added 11 operated locations in the Utica to PDP which were not previously booked for 119 Bcfe. In the SCOOP, we added 166 PUD locations for ~~114~~138 Bcfe.

Revisions of prior reserve estimates. Revisions represent changes in previous reserve estimates, either upward or downward, resulting from development plan changes, new information normally obtained from development drilling and production history or a change in economic factors, such as commodity prices, operating costs or development costs.

We experienced total downward revisions of ~~406~~38 Bcfe in estimated proved reserves. These consisted of upward revisions of 16255 Bcfe as a result of positive well performance and 171 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 488 Bcfe which were associated with commodity price changes. Commodity prices experienced volatility throughout ~~2024~~2025 and the 12-month unweighted average of the first-day-of-the-month price for natural gas ~~decreased~~increased from $2.6413 per MMBtu for ~~2023~~2024 to $23.1339 per MMBtu for ~~2024~~2025, the 12-month average WTI spot price for ~~NGL~~crude oil decreased from $3176.4232 per barrel for ~~2023~~2024 to $3166.3001 per barrel for ~~2024~~2025, and the ~~12-month~~calculated average weighted price for ~~crude~~NGL ~~oil~~over the remaining lives of the properties decreased from $7831.2130 per barrel for ~~2023~~2024 to $7630.3217 per barrel for ~~2024~~2025. Additionally, ~~downward~~there were upward revisions of ~~172~~161 Bcfe due to an increase in working interest and net revenue interest as a result of our successful leasing efforts throughout 2025. These were ~~primarily~~offset by downward revisions of 185 Bcfe and 129 Bcfe as a result of development schedule changes ~~with~~and ~~some~~ PUD well design changes, respectively. The schedule changes moved the development of 119 Utica~~/Marcellus~~ PUD locations and 64 SCOOP PUD locations beyond the SEC requirement of ~~developing~~development ~~these~~within ~~wells~~ five years from initial booking and while these locations are excluded from our SEC reserves report, they remain in our longer-term development plan. ~~The~~Design changes primarily include well spacing and lateral length updates with a portion of these volumes now to be developed with locations outside of the SEC designated five-year development time frame. These development schedule and design changes reflect our ongoing commitment to optimizing the long-term plan to best develop our ~~asset~~assets and maximize cash flow and overall economic returns. ~~These locations excluded from our SEC reserves report remain in Gulfport's development plan.~~ Finally, ~~upward~~downward revisions of 67141 Bcfe were a result of a combination of various economic ~~assumption~~assumptions and well performance updates.

Additional information regarding estimates of proved reserves, proved developed reserves and proved undeveloped reserves at December 31, ~~2024~~2025, ~~2023~~2024 and ~~2022~~2023, and changes in proved reserves during the last three years are contained in the Supplemental Information on Oil and Gas Exploration and Production Activities, or Supplemental Information, in Note 20 of our consolidated financial statements.

Proved Undeveloped Reserves

As of December 31, ~~2024~~2025, our PUDs totaled 1,~~478~~455 Bcf of natural gas, 1516 MMBbl of oil and 4950 MMBbl of NGL, for a total of 1,~~861~~848 Bcfe. Approximately 8082% and 2018% of our PUD reserves at year-end ~~2024~~2025 were located in Utica/Marcellus and SCOOP, respectively. Our PUDs will be converted from undeveloped to developed as the applicable wells commence production or when there are no material incremental completion capital expenditures associated with such proved developed reserves.

We record PUD locations only after a development plan has been approved by our senior management and Board of Directors to complete the associated development drilling within five years from the time of initial booking. The PUD locations identified in our development plan are determined based on an analysis of the information that we have available at that time. After a development plan has been adopted, we may periodically make adjustments to the approved development plan due to events and circumstances that have occurred subsequent to the time the plan was approved. These circumstances may include changes in commodity price outlook and costs, delays in the availability of infrastructure, well permitting delays and new data from recently completed wells.

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Index to Financial Statements

~~The~~We ~~following~~record ~~table~~PUD ~~summarizes~~locations only after a development plan has been approved by our senior management and Board of Directors to complete the ~~changes~~associated development drilling within five years from the time of initial booking. The PUD locations identified in our ~~estimated~~development ~~proved~~plan ~~undeveloped~~are ~~reserves~~determined ~~during~~based ~~2024~~on (an analysis of the information that we have available at that time. After a development plan has been adopted, we may periodically make adjustments to the approved development plan due to events and circumstances that have occurred subsequent to the time the plan was approved. These circumstances may include changes in ~~Bcfe):~~commodity price outlook and costs, delays in the availability of infrastructure, well permitting delays and new data from recently completed wells.

Proved Undeveloped Reserves, December 31, 2023			2,011
Sales of oil and natural gas reserves in place			—
Extensions and discoveries			547
Conversion to proved developed reserves			(341)
Revisions of prior reserve estimates			(357)
Proved Undeveloped Reserves, December 31, 2024			1,861
Total may not sum due to rounding.

The following table summarizes the changes in our estimated proved undeveloped reserves during 2025 (in Bcfe):

Extensions and discoveries. Our extensions of approximately 547 Bcfe were primarily attributed to the addition of 62 PUD locations as a result of our current five-year development plan that is focused on generating sustainable cash flow. These additions included 46 PUD locations in the Utica/Marcellus and 16 PUD locations in the SCOOP.


Proved Undeveloped Reserves, December 31, 2024			1,861
Sales of oil and natural gas reserves in place			—
Extensions and discoveries			582
Conversion to proved developed reserves			(417)
Revisions of prior reserve estimates			(177)
Proved Undeveloped Reserves, December 31, 2025			1,848
Total may not sum due to rounding.

~~Conversion~~Extensions toand ~~proved developed reserves~~discoveries. Our ~~2024~~extensions ~~development~~of ~~activities~~approximately ~~resulted~~582 inBcfe were primarily attributed to the ~~conversion~~addition of ~~approximately~~41 ~~341~~PUD ~~Bcfe~~locations ~~into~~as ~~proved~~a ~~developed~~result ~~producing~~of ~~reserves,~~our ~~attributable~~current tofive-year 16development plan that is focused on generating sustainable cash flow. These additions included 35 PUD locations in the Utica/Marcellus and 56 PUD locations in the SCOOP. ~~These 21 PUDs represent a conversion rate of 13% for 2024.~~

~~Revision~~Conversion ofto ~~prior reserve estimates. We experienced total downward revisions of 357 Bcfe in estimated~~ proved ~~undeveloped~~developed reserves. ~~This~~Our ~~included~~2025 ~~300~~development ~~Bcfe~~activities ofresulted ~~downward~~in ~~revisions associated with commodity price changes. Commodity prices experienced volatility throughout 2024 and~~ the ~~12-month~~conversion ~~average~~of ~~price~~approximately ~~for~~417 ~~natural~~Bcfe ~~gas~~into ~~decreased~~proved ~~from~~developed ~~$2.64~~producing ~~per MMBtu for 2023 to $2.13 per MMBtu for 2024~~reserves, ~~the~~attributable ~~12-month average price for NGL decreased from $31.42 per barrel for 2023~~ to $31~~.30~~ ~~per~~PUD ~~barrel~~locations 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 Bcfe were associated with changes in ~~our development schedule. The schedule changes moved~~ the ~~development of 11~~ Utica/Marcellus ~~PUD locations~~ and 611 ~~SCOOP~~ PUD locations ~~beyond~~in the ~~SEC requirement of developing PUDs five years from initial booking~~SCOOP. ~~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~~42 ~~excluded~~PUDs ~~from~~represent ~~our~~a ~~SEC~~conversion ~~reserves~~rate ~~report remain in Gulfport's development plan. These downward revisions were offset by upward revisions~~ of ~~116~~28% ~~Bcfe~~for ~~in estimated proved reserves from a combination of changes including working interest and net revenue interest and well forecasts~~2025.

~~Costs~~Revision ~~incurred~~of ~~relating~~prior toreserve estimates. We experienced total downward revisions of 177 Bcfe in estimated proved undeveloped reserves. This included 182 Bcfe and 84 Bcfe of downward revisions associated with changes in our development schedule changes and PUD well design changes, respectively. The schedule changes moved the development of ~~PUDs~~9 ~~were~~Utica ~~approximately~~PUD ~~$326.~~locations and 4 ~~million~~ SCOOP PUD locations beyond the SEC requirement of development within five years from initial booking and while these locations are excluded from our SEC reserves report, they remain in ~~2024~~our longer-term development plan. Design changes primarily include well spacing and lateral length updates with a portion of these volumes now to be developed with locations outside of the SEC designated five-year development time frame. These development schedule and design changes reflect our ongoing commitment to optimizing the long-term plan to best develop our assets and maximize cash flow and overall economic returns. These downward revisions were offset by upward revisions of 89 Bcfe in estimated proved reserves from a combination of changes including working interest and net revenue interest, well forecasts and price changes.

~~All~~Costs ~~PUD~~incurred ~~locations~~relating ~~included in our 2024 reserve report are scheduled~~ to bethe ~~drilled~~development ~~within~~of ~~five~~PUDs ~~years~~were ofapproximately ~~initial~~$235.9 million ~~booking~~in 2025.

AsAll ofPUD ~~December 31,~~locations ~~2024,~~included ~~1.20%~~in of our ~~total~~2025 ~~proved~~reserve ~~reserves~~report ~~were~~are ~~classified~~scheduled asto ~~proved~~be ~~developed~~drilled ~~non-producing~~within five years of initial booking.

As of December 31, 2025, 1.77% of our total proved reserves were classified as proved developed non-producing.

PV-10 Sensitivities

As noted above, our proved reserves at December 31, ~~2024~~2025, were calculated using prices based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for ~~2024~~2025 of $7666.3201 per barrel and $23.1339 per MMBtu. Holding production and development costs constant, if SEC pricing were $8372.9561 per barrel and $23.3473 per MMBtu, or a 10% increase, this would have resulted in an increase of 8738 Bcfe of our total proved reserves and a $0.5477 billion increase in PV-10 value at December 31, ~~2024~~2025. Holding production and development costs constant, if SEC pricing were $6859.6941 per barrel and $13.9205 per MMBtu, or a 10% decrease, this would have resulted in a decrease of ~~494~~54 Bcfe of our total proved reserves and a $0.5177 billion decrease in PV-10 value at December 31, ~~2024~~2025. For the low price scenario ~~128~~132 PUDs were PV-10 economic.

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Index to Financial Statements

Acreage

The following table presents our total gross and net developed and undeveloped acres as of December 31, ~~2024~~2025:

DevelopedAcreage

UndevelopedAcreage

Field

Gross

Net

Gross

Net

Utica & Marcellus

~~161~~170,~~391~~209

~~133~~142,~~638~~239

7783,~~387~~069

7480,~~359~~294

SCOOP

4950,~~922~~735

3536,~~896~~174

910,~~829~~689

7,~~134~~680

Total

~~211~~220,~~313~~944

~~169~~178,~~534~~413

8793,~~216~~758

8187,~~493~~974

Of our leases that are not held by production or held by other applicable lease provisions, most have a five-year primary term, and many ofinclude ~~which~~an ~~include~~optional ~~options~~right to extend the primary term for an additional three or five years. We manage lease expirations to ensure that we do not experience unintended material expirations. Our leasehold management efforts include scheduling our operations to establish production in paying quantities in order to hold leases prior to the expiration dates, paying the prescribed lease extension payments, planning non-core divestitures or strategic acreage trades with other operators to high-grade our lease inventory and ~~letting~~voluntarily ~~some~~allowing certain leases to expire that are no longer part of our development plans. The following table sets forth the potential expiration periods of gross and net undeveloped leasehold acres as of December 31, ~~2024~~2025:

	Undeveloped Acres
Years Ending December 31,	Gross Acres	Net Acres
	Gross Acres	Net Acres
2025	2,203	2,195
2026	2,827	2,806
2026	3,682	3,661
2027	1,672	1,636
2027	2,812	2,775
2028	10,048	10,042
After 2027	18,673	18,667
After 2028	19,930	19,930
Held by production	59,~~846~~281	5453,~~195~~560
Total	8793,~~216~~758	8187,~~493~~974

Productive Wells

The following table presents our total gross and net productive wells, expressed separately for oil and gas, as of December 31, ~~2024~~2025:

NRI/WI

ProductiveOil Wells

ProductiveGas Wells

Total Wells

Field

Percentages

Gross

Net

Gross

Net

Gross

Net

Utica & Marcellus

4950.6625/6061.8458

1569

525.155

~~712~~697

~~437~~446.2

~~727~~766

~~442~~471.47

SCOOP

2120.4186/2625.4982

~~119~~129

1213.233

~~531~~518

~~159~~153.928

~~650~~647

~~172~~167.1

Total(1)

~~143~~215

1738.48

1,~~411~~380

~~597~~600.10

1,~~554~~595

~~614~~638.58

_____________________

(1) We also have override/royalty interests in ~~177~~182 wells with an average NRI of 0.6%, which are not material to our operations. Totals may not sum due to rounding.

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Drilling Activity

The following table sets forth information with respect to operated wells drilled during the periods indicated. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled, quantities of reserves found or economic value. Productive wells are those that produce commercial quantities of hydrocarbons, regardless of whether they produce a reasonable rate of return.

	Year Ended December 31,
	2024		2023		2022
	2025		2024		2023
	Gross	Net	Gross	Net	Gross	Net
Development:
Productive	2129	1928.87	2421	2119.98	2524	21.79
Dry	—	—	—	—	—	—
Total	2129	1928.87	2421	2119.98	2524	21.79
Exploratory:
Productive	—	—	—	—	—	—
Dry	—	—	—	—	—	—
Total	—	—	—	—	—	—

The following table presents activity by operating area for the year ended December 31, ~~2024~~2025:

	Operated				Non-Operated
Field	Drilled		Turned to Sales		Drilled		Turned to Sales
	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Utica & Marcellus(1)	1827.0	1726.49	1630.0	1530.40	168.0	0.1	814.0	0.10
SCOOP(2)	32.0	21.48	32.0	21.48	18.0	0.21	1623.0	0.12
Total	2129.0	1928.87	1932.0	1731.8	3426.0	0.32	2437.0	0.2

_____________________

(1) Of the 1827 gross operated wells drilled in ~~2024~~2025, 1022 were completed as producing wells and ~~eight~~five were in various stages of drilling and completion as of December 31, ~~2024~~2025.

(2) The ~~three~~two gross operated wells that were drilled in ~~2024~~2025 were completed as producing wells as of December 31, ~~2024~~2025.

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Production, Prices and Production Costs

The following table presents our production volumes, average prices received and average production costs during the periods indicated (sales totals in thousands):

	Year Ended December 31, 2024		Year Ended December 31, 2023		Year Ended December 31, 2022
	Year Ended December 31, 2025		Year Ended December 31, 2024		Year Ended December 31, 2023
Natural gas sales
Natural gas production volumes (MMcf)	~~354~~338,~~154~~296		~~350~~354,~~306~~154		~~322~~350,~~366~~306
Natural gas production volumes (MMcf) per day	~~968~~927		~~960~~968		~~883~~960
Total sales	$	~~714~~1,~~160~~056,429	$	~~831~~714,~~812~~160	$	1831,~~998,452~~812
Average price without the impact of derivatives ($/Mcf)	$	23.0212	$	2.3702	$	62.2037
Impact from settled derivatives ($/Mcf)	$	0.8014	$	0.4280	$	(30.~~11)~~42
Average price, including settled derivatives ($/Mcf)	$	23.8226	$	2.7982	$	32.0979
Oil and condensate sales
Oil and condensate production volumes (MBbl)	12,~~459~~260		1,~~363~~459		1,~~610~~363
Oil and condensate production volumes (MBbl) per day	46		4		4
Total sales	$	~~101~~133,~~589~~644	$	99101,~~854~~589	$	~~147~~99,~~444~~854
Average price without the impact of derivatives ($/Bbl)	$	6959.6412	$	7369.2764	$	9173.5827
Impact from settled derivatives ($/Bbl)	$	04.1104	$	(20.~~53)~~11	$	(242.3253)
Average price, including settled derivatives ($/Bbl)	$	6963.7516	$	7069.7475	$	6770.2674
NGL sales
NGL production volumes (MBbl)	34,~~818~~554		43,~~386~~818		4,~~483~~386
NGL production volumes (MBbl) per day	1012		1210		12
Total sales	$	~~112~~133,~~855~~454	$	~~119~~112,~~717~~855	$	~~184~~119,~~963~~717
Average price without the impact of derivatives ($/Bbl)	$	29.5630	$	~~27.~~29.56	$	4127.2629
Impact from settled derivatives ($/Bbl)	$	(0.5607)	$	2(0.0756)	$	(2.~~80)~~07
Average price, including settled derivatives ($/Bbl)	$	29.0023	$	29.3600	$	3829.4636
Natural gas, oil and condensate and NGL sales
Natural gas equivalents (MMcfe)	~~385~~379,~~814~~182		~~384~~385,~~802~~814		~~358~~384,~~924~~802
Natural gas equivalents (MMcfe) per day	1,~~054~~039		1,054		~~983~~1,054
Total sales	$	~~928~~1,~~604~~323,527	$	1928,~~051,383~~604	$	21,~~330~~051,~~859~~383
Average price without the impact of derivatives ($/Mcfe)	$	23.4149	$	2.7341	$	62.4973
Impact from settled derivatives ($/Mcfe)	$	0.7315	$	0.4073	$	(20.~~94)~~40
Average price, including settled derivatives ($/Mcfe)	$	3.1464	$	3.1314	$	3.5513
Production Costs:
Average lease operating expenses ($/Mcfe)	$	0.1822	$	0.18	$	0.18
Average taxes other than income ($/Mcfe)	0.08		0.0908		0.1709
Average transportation, gathering, processing and compression ($/Mcfe)	0.9195		0.91		10.0091
Total lease operating expenses, midstream costs and taxes other than income ($/Mcfe)	$	1.1725	$	1.17	$	1.3417
Totals may not sum or recalculate due to rounding.

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The following table provides a summary of our production, average sales prices and average production costs for oil and gas fields containing 15% or more of our total proved reserves as of December 31, ~~2024~~2025:

	Year Ended December 31, 2024		Year Ended December 31, 2023		Year Ended December 31, 2022
	Year Ended December 31, 2025		Year Ended December 31, 2024		Year Ended December 31, 2023
Utica & Marcellus
Net Production
Natural gas (MMcf)	~~296~~283,~~548~~667		~~279~~296,~~428~~548		~~246~~279,~~123~~428
Oil (MBbl)	~~847~~1,729		~~255~~847		~~244~~255
NGL (MBbl)	12,~~072~~183		~~856~~1,072		~~885~~856
Total (MMcfe)	~~308~~307,~~060~~137		~~286~~308,~~095~~060		~~252~~286,~~895~~095
Average price without the impact of derivatives:
Natural gas ($/Mcf)	$	13.9911	$	21.3499	$	62.1434
Oil ($/Bbl)	$	6658.8406	$	7066.1884	$	9070.6018
NGL ($/Bbl)	$	3734.0187	$	3337.6301	$	4833.2163
Production Costs:
Average lease operating expenses ($/Mcfe)	$	0.1620	$	0.16	$	0.1716
Average taxes other than income ($/Mcfe)	0.0605		0.0506		0.0605
Average transportation, gathering, processing and compression ($/Mcfe)	0.9396		0.9793		10.0897
Total lease operating expenses, midstream costs and taxes other than income ($/Mcfe)	$	1.1521	$	1.1815	$	1.3118
SCOOP
Net Production
Natural gas (MMcf)	5754,~~605~~629		7057,~~878~~605		7670,~~242~~878
Oil (MBbl)	~~612~~531		~~1,108~~612		1,~~366~~108
NGL (MBbl)	2,~~746~~371		32,~~530~~746		3,~~598~~530
Total (MMcfe)	7772,~~753~~045		9877,~~707~~753		~~106~~98,~~024~~707
Average price without the impact of derivatives:
Natural gas ($/Mcf)	$	23.1319	$	2.5313	$	62.3853
Oil ($/Bbl)	$	7362.5159	$	73.9851	$	9173.7198
NGL ($/Bbl)	$	2624.6518	$	2526.7665	$	3925.5676
Production Costs:
Average lease operating expenses ($/Mcfe)	$	0.2831	$	0.2528	$	0.2025
Average taxes other than income ($/Mcfe)	0.1317		0.1713		0.3817
Average transportation, gathering, processing and compression ($/Mcfe)	0.8388		0.7383		0.7873
Total lease operating expenses, midstream costs and taxes other than income ($/Mcfe)	$	1.2436	$	1.1524	$	1.3615

Our Investments

Grizzly Oil Sands. We, through our wholly-owned subsidiary Grizzly Holdings Inc., own a 24.5% interest in Grizzly. As of December 31, ~~2024~~2025, Grizzly had approximately ~~830~~639,000 net acres under lease in the Athabasca, Peace River, and Cold Lake ~~oil sands~~ regions of Alberta, Canada. Grizzly's operations have been suspended since 2015. Additionally, Grizzly had no proved reserves as of December 31, ~~2024~~2025. We elected to cease funding capital calls in 2019, and we have no obligation to fund any future projects Grizzly may consider pursuing. Failure to fund capital calls will lead to continued dilution of our equity ownership interest in Grizzly.

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Marketing

The principal function of our marketing operations is to provide natural gas, oil and NGL marketing services, including securing and negotiating commodity transactions, gathering, hauling, processing and transportation services, contract administration and nomination services for production from Gulfport-marketed wells. Generally, natural gas and NGL production is sold to purchasers under both spot and term transactions. Oil production is sold under both spot and term transactions with the majority of our sales contracts being shorter term in nature.

We have entered into long-term gathering, processing and transportation contracts with various parties that reserve capacity for fixed, determinable quantities of production over specified periods of time. Some contracts require us to make payments for any shortfalls in delivering or transporting minimum volumes under these commitments. In addition, we periodically enter into a variety of oil, natural gas and NGL purchase and sale contracts with third parties for various commercial purposes, including risk mitigation and satisfaction of our firm transportation delivery commitments. These marketing activities often enhance the value of our production by aggregating volumes and allowing improved flexibility in relation to deal structure, size and counterparty exposure whether through intermediary markets or direct end markets. See Note 17 of our consolidated financial statements for further discussion of our commitments.

Major Customers

Our total natural gas, oil and NGL sales, before the effects of hedging, to major customers (purchasers in excess of 10% of total natural gas, oil and NGL sales) for the years ended December 31, ~~2024~~2025, ~~2023~~2024 and ~~2022~~2023 were as follows:

	% of Sales
Year Ended December 31, 2025
Customer A	14	%
Year Ended December 31, 2024
Vitol Inc.	15	%
Customer A	15	%
Year Ended December 31, 2023
Vitol Inc.	12	%
Customer A	12	%
Year Ended December 31, 2022
ECO-Energy	20	%
Clearwater	11	%

Competition

The oil and natural gas industry is intensely competitive, and we compete with many other companies that have greater resources than we have. Competition can negatively impact our ability to successfully source quality vendors, service providers, employees and contractors to secure optimal pipeline access and end markets in which to sell our production, to acquire new properties, and our search for, and the development of, reserves. Many of our competitors not only explore for and produce oil and natural gas, but also have midstream and further downstream operations and market a variety of hydrocarbon products on a regional, national or worldwide basis. In addition, oil and natural gas compete with other forms of energy available to customers, primarily based on price. These alternate forms of energy include renewable sources such as wind or solar energy in addition to coal and fuel oils. Changes in the availability or price of oil and natural gas or other forms of energy, as well as business conditions, conservation, legislation, regulations and the ability to convert to alternate fuels and other forms of energy may affect the demand for oil and natural gas.

Seasonality

Gulfport drills and completes wells throughout the year, but adverse weather conditions can impact drilling, completion, and field operations, as well as third-party midstream and downstream pipeline operations, which can impact overall production volumes. Seasonal anomalies can minimize or exaggerate the impact on these operations, while extreme weather events can materially constrain our operations for short periods of time.

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Title to Oil and Natural Gas Properties

It is customary in the oil and natural gas industry to make only a preliminary review of title to undeveloped oil and natural gas leases at the time they are acquired and to obtain more extensive title examinations at the time we are preparing to develop the undeveloped leases and when acquiring producing properties. In future acquisitions, we will conduct title examinations on material portions of such properties in a manner generally consistent with industry practice. Certain of our oil and natural gas properties may be subject to certain imperfections in title, encumbrances, easements, servitudes or other restrictions, none of which, in management's opinion, will in the aggregate materially restrict our operations.

Regulation - Environment, Health and Safety

Exploration and Production, Environmental, Health and Safety, and Occupational Laws and Regulations

Our operations are subject to federal, tribal, state, and local laws and regulations. These laws and regulations relate to matters that include, but are not limited to, the following:

•reporting of workplace injuries and illnesses;

•industrial hygiene monitoring;

•worker protection and workplace safety;

•approval or permits to drill and to conduct operations;

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

•calculation and disbursement of royalty payments and production taxes;

•seismic operations and data;

•location, drilling, cementing and casing of wells;

•well design and construction of pad and equipment;

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

•method of completing wells;

•hydraulic fracturing;

•water withdrawal;

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

•emergency response, contingency plans and spill prevention plans;

•air emissions and fluid discharges;

•climate change;

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

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

•plugging and abandoning of wells; and

•transportation of production.

~~In recent years~~Federal, ~~federal,~~ state and local governments have periodically taken steps to reduce emissions of greenhouse gases (“GHG”). We consider the costs of environmental, safety and health protection and compliance to be necessary, manageable parts of our business. We have been able to plan for and comply with environmental, safety and health laws and regulations without materially altering our operating strategy or incurring significant unreimbursed expenditures. However, based on policy and regulatory trends and increasingly stringent laws, our capital expenditures and operating expenses related to compliance with the protection of the environment, safety and health have increased over the years and may continue to increase. We cannot predict with any reasonable degree of certainty our future exposure concerning such matters. See the “Risk Factors” described in Item 1A. of this report for further discussion of governmental regulation and ongoing regulatory changes, including with respect to environmental matters. ~~We cannot predict with any reasonable degree of certainty our future exposure concerning such matters.~~

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Our operations are also subject to conservation regulations, including the regulation of the size of drilling and spacing units or proration units, the number of wells that may be drilled in a unit, the rate of production allowable from oil and gas wells, and the unitization or pooling of oil and gas properties. In the United States, some states allow the compulsory pooling or integration of tracts to facilitate exploration and development. Other states rely on voluntary pooling of lands and leases which may make it more difficult to develop oil and gas properties. In addition, federal and state conservation laws generally limit the venting or flaring of natural gas, and state conservation laws impose certain requirements regarding the ratable purchase of production. These regulations often impose additional operational costs to us and can also limit the amounts of oil and gas we can produce from our wells and the number of wells or the locations at which we can drill.

Regulatory proposals in some states and local communities have been initiated to require or make more stringent the permitting and compliance requirements for hydraulic fracturing operations. Federal and state agencies have continued to assess the potential impacts of hydraulic fracturing, which could spur further action toward federal, state and/or local legislation and regulation. Further restrictions of hydraulic fracturing could reduce the amount of natural gas, oil and NGL that we are ultimately able to produce in commercial quantities from our properties.

Certain of our U.S. natural gas and oil leases are granted or approved by the federal government and administered by the Bureau of Land Management (“BLM”) or Bureau of Indian Affairs (“BIA”) of the Department of the Interior. Such leases require compliance with detailed federal regulations and orders that regulate, among other matters, drilling and operations on lands covered by these leases and calculation and disbursement of royalty payments to the federal government, tribes or tribal members. The federal government has been particularly active in recent years in evaluating and, in some cases, promulgating new rules and regulations regarding competitive lease bidding, venting and flaring, oil and gas measurement and royalty payment obligations for production from federal lands. If future developments result in additional restrictions on drilling, limitations on the availability of leases, or restrictions on the ability to obtain required permits, it could have a material adverse impact on our operations. Permitting activities on federal lands are also subject to frequent delays.

Delays in obtaining permits or an inability to obtain new permits or permit renewals could inhibit our ability to execute our drilling and production plans. Failure to comply with applicable regulations or permit requirements could result in revocation of our permits, inability to obtain new permits and the imposition of fines and penalties.

Operating Hazards and Insurance

The oil and natural gas business involves a variety of operating risks, including the risk of fire, explosions, blow-outs, pipe failure, abnormally pressured formations and environmental hazards such as oil spills, natural gas leaks, ruptures or discharges of toxic gases. If any of these should occur, we could incur legal defense costs and could suffer substantial losses due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigation and penalties, and suspension of operations. Our horizontal and deep drilling activities involve greater risk of mechanical problems than vertical and shallow drilling operations.

We maintain a control of well insurance policy with a minimum limit of $25 million for single well limits and $37.5 million limit for multi-well pads. This policy insures against certain sudden and accidental risks associated with drilling, completing and operating our wells. This insurance may not be adequate to cover all losses or exposure to liability. We also carry a $51 million comprehensive general liability and umbrella insurance program. In addition, we maintain a $10 million pollution liability insurance policy providing coverage for gradual pollution related risks and in excess of the general liability policy for sudden and accidental pollution risks. We provide workers' compensation insurance coverage to employees in all states in which we operate, as well as auto liability for our company vehicles. While we believe these policies are customary in the industry, they do not provide complete coverage against all operating risks, and policy limits scale to our working interest percentage in certain situations. In addition, our insurance does not cover penalties or fines that may be assessed by a governmental authority. A loss not fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows. Our insurance coverage may not be sufficient to cover every claim made against us or may not be commercially available for purchase in the future.

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Index to Financial Statements

We have prepared and have in place spill prevention control and countermeasure plans for each of our principal facilities in response to federal and state requirements. The plans go through a technical review every five years and are updated as necessary. As required by applicable regulations, our facilities are built with secondary containment systems to capture potential releases. We also own additional spill kits with oil booms and absorbent pads that are readily available, if needed. In addition, we have emergency response companies on retainer. These companies specialize in the clean-up of hydrocarbons as a result of spills, blow-outs and natural disasters, and are on call to us 24 hours a day, seven days a week when their services are needed. We pay these companies a retainer plus additional amounts when they provide us with clean up services. Our aggregate payments for the retainer and clean-up services during each of ~~2024~~2025, ~~2023~~2024 and ~~2022~~2023 were immaterial. While these companies have been able to meet our service needs when required from time to time in the past, it is possible that the ability of one or more of them to provide services to us in the future, if and when needed, could be hindered or delayed in the event of a widespread disaster. However, in light of the areas in which we operate and the nature of our production, we believe other companies would be available to us in the event our primary remediation companies are unable to perform.

Human Capital Management

Employees

As of December 31, ~~2024~~2025, we had ~~235~~245 employees, an increase of approximately 45% from the ~~226~~235 employees as of December 31, ~~2023~~2024. All of our employees are non-bargaining.

The attraction and retention of qualified employees continues to be one of our highest priorities. We focus on making substantive improvements to key areas that impact our employees. During ~~2024~~2025, we continued making significant investments in our talent management and retention processes, including increasing funds allocated to annual salary increases, short-term incentive payments, long-term incentive equity awards, 401(k) matches for eligible employees, and other enhancements to our benefits offerings. We remain committed to providing fair and competitive compensation programs and adequate development and advancement opportunities to our employees. We believe these practices serve as talent acquisition and retention tools, as our employees' continued engagement and commitment to the Company is critical to our success.

Over the course of ~~2024~~2025, Gulfport continued to develop and revise Company policies, including those intended to implement our Business Code of Conduct and Ethics, which provides a framework for how we interact with our employees, vendors and other stakeholders when conducting our operations. To that end, we provided all of our employees with annual trainings focused on the guidelines, rules, and principles that must be followed when acting on the Company's behalf. We remain committed to maintaining the highest standards of business ethics.

Health, Safety & Environment

Safety is at the forefront of everything we do. We have a robust annual training program, including environmental, health, and safety topics. Our safety program, WORK SAFE, is comprised of twelve key topics including critical tasks and cultural conditions. We hold regular safety briefings to discuss daily operations and routinely have safety stand-down meetings highlighting potential risks. Every employee is empowered to use their stop-work authority to cease operating if work is being performed in an unsafe manner. We monitor employee safety by establishing annual company-wide key safety metrics tied to leading indicators (i.e., incident reporting and investigations, hazard observations, safety and health meetings) and lagging indicators (i.e., injury rates and preventable motor vehicle accidents).

As part of our focus on continuous improvement, we monitor and communicate key environmental and safety metrics both internally and externally. Trend analysis guides us to make operational changes and policy updates as necessary to protect our employees, the public and the environment. We establish and carefully track key environmental and safety metrics that are a component of every employee’s incentive compensation opportunity annually.

We have established several programs to ensure that our employees and external partners are appropriately trained to perform the critical work we do safely and effectively. We continued to reinforce our WORK SAFE program and provided training to leaders on reinforcement strategies. Additionally, we continued the WORK GREEN program, which focuses on protecting the air, land and water where we operate and includes community-based volunteer events targeting environmental clean-up and habitat improvement initiatives. An environmental training on the elements of WORK GREEN was created and delivered to all employees.

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Training & Development

Gulfport invests in our employees' professional growth to build strong teams and develop leaders for today and the future. We build our dynamic team of industry-leading professionals by engaging them in interesting and rewarding work and providing training and development opportunities. We utilize training sessions with content developed by experts in the safety, legal, information security, and regulatory compliance fields, and we offer a blend of training sessions through both computer-based modules and live, instructor-led sessions. We believe our training efforts support a compliant safety-first mindset in everything we do. We continue to provide professional and workplace-related training resources to employees through universities, electronic content services and specialized courses related to our industry through our tuition reimbursement program or third-party providers.

Executive Officers

John Reinhart, President, Chief Executive Officer and Director

On January 18, 2023, the Board of Directors appointed Mr. Reinhart, 5657, as President, Chief Executive Officer and Director, effective as of January 24, 2023. Mr. Reinhart joined the Company with over two decades of oil and gas industry leadership experience. Most recently, he served as President, Chief Executive Officer and member of the board of directors of Montage Resources Corporation where he led actions that positioned Montage as an attractive strategic partner with sufficient scale, low debt profile and achievement of top-quartile operational and financial metrics. Mr. Reinhart previously served as President, Chief Executive Officer and member of the board of directors of Blue Ridge Mountain Resources and as Chief Operating Officer at Ascent Resources. He started his oil and gas career at Schlumberger before joining Chesapeake Energy Corporation, where he held operations roles with increasing responsibility. Mr. Reinhart began his career in the United States Army, serving tours in Panama and Iraq. Mr. Reinhart graduated from West Virginia University with a Bachelor of Science degree in Mechanical Engineering.

Michael Hodges, Executive Vice President and Chief Financial Officer

On April 3, 2023, the Board of Directors appointed Mr. Hodges, 4647, as Executive Vice President and Chief Financial Officer. Most recently, Mr. Hodges served as Senior Vice President, Finance and Accounting at Leon Capital Group. Prior to joining Leon Capital, he was the Executive Vice President and Chief Financial Officer for Montage Resources Corporation until its merger with Southwestern Energy Company in November 2020. From 2012 until joining Montage Resources in 2018, Mr. Hodges served as the Chief Financial Officer for three upstream energy companies focused on near-term value creation through the acquisition and early-stage development of oil and natural gas resources. Mr. Hodges received his Bachelor of Business Administration in Finance from the University of Oklahoma and a Master of Science in Energy Management from Oklahoma City University and is a Certified Public Accountant in the State of Oklahoma.

Patrick Craine, Executive Vice President and Chief Legal and Administrative Officer

Mr. Craine, 5253, has served as Chief Legal and Administrative Officer since June 2021 and joined Gulfport as Executive Vice President, General Counsel and Corporate Secretary in May 2019. Prior to joining the Company, Mr. Craine served as Deputy General Counsel – Chief Risk and Compliance Officer at Chesapeake Energy Corporation. Prior to joining Chesapeake in 2013, Mr. Craine was a partner with Bracewell LLP, a global law firm, where his practice focused on securities and corporate regulatory matters and investigations. Before Mr. Craine entered private practice, he served as a lawyer with the U.S. Securities and Exchange Commission and the Financial Industry Regulatory Authority where he held leadership positions in their Oil and Gas Task Forces. Mr. Craine has over 25 years of extensive senior-level experience handling a broad range of securities, corporate, regulatory, governance, compliance and litigation matters, with particular expertise in the energy industry. Mr. Craine received his Bachelor of Arts degree, summa cum laude, Phi Beta Kappa, from Wabash College, and his Juris Doctorate, cum laude, from the Southern Methodist University Dedman School of Law.

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Matthew Rucker, Executive Vice President and Chief Operating Officer

Mr. Rucker, 3940, joined Gulfport as the Senior Vice President of Operations in March 2023. On February 24, 2025, Matthew Rucker was promoted to Executive Vice President and Chief Operating Officer. He joined Gulfport from Javelin Energy Partners where he previously served as Vice President of Production Operations starting in August 2022. Mr. Rucker joined Javelin in July 2022 as the Vice President of Business Development. Prior to joining Javelin, Mr. Rucker served as the Executive Vice President, Chief Operating Officer for Montage Resources Corporation following Montage’s successful business combination transaction with Blue Ridge Mountain Resources in June 2020. Prior to Montage, Mr. Rucker served as Vice President, Resource Planning and Development of Blue Ridge from 2016 to 2020. Prior to joining Blue Ridge, Mr. Rucker served as a Production Superintendent for Chesapeake Energy Corporation from January 2014 to October 2016, overseeing Chesapeake’s Utica Shale production. As a member of Chesapeake’s Eastern Division leadership team, Mr. Rucker focused on the safe and efficient optimization of production in the Utica Shale and led an operating team of over 45 employees. During his service at Chesapeake, Mr. Rucker held several engineering positions in the Marcellus and Utica Shale asset teams within reservoir, primarily focused on strategic joint ventures, divestitures, acquisitions and resource development planning. Mr. Rucker received his Bachelor of Science degree in Petroleum Engineering from Marietta College and a Master of Business Administration in Energy from Texas Christian University. He serves on the Marietta College Industry Advisory Council and is a member of the Society of Petroleum Engineers.

Michael Sluiter, Senior Vice President of Reservoir Engineering

Mr. Sluiter, 5253, joined Gulfport ~~as the Senior Vice President of Reservoir Engineering~~ in December 2018 from Noble Energy, Inc., where he ~~most~~held ~~recently~~various ~~served~~engineering asand ~~the~~leadership positions from March 2007 to November 2018, including Permian Basin Business Unit Manager., ~~Prior~~Appalachian toReservoir ~~that~~Engineering ~~role~~Supervisor, heand ~~spent~~Business ~~over~~Development 17Engineering ~~years~~Advisor. ~~developing~~Prior ~~his~~to ~~skills~~joining ~~and~~Noble ~~expertise~~Energy, inMr. ~~unconventional~~Sluiter ~~resource~~worked ~~development,~~for ~~reservoir~~Santos ~~engineering~~Ltd., ~~subsurface~~at ~~development,~~the ~~business~~Australian ~~development/M&A,~~headquarters ~~and~~in ~~leadership~~Adelaide atand ~~Noble~~in ~~Energy~~Houston, ~~Santos~~primarily ~~Australia~~focused on petroleum engineering and ~~Santos~~planning ~~USA.~~functions Mr. Sluiter began his career as a wireline field services engineer for Schlumberger, ~~in Thailand~~Inc. ~~Mr.~~and ~~Sluiter~~holds is a ~~graduate~~Bachelor of ~~the~~Science ~~University~~degree ofin ~~Sydney,~~Chemical ~~Australia,~~Engineering ~~with~~from athe ~~Bachelor~~University of ~~Science~~Sydney, ~~degree in Chemical Engineering~~Australia.

Lester Zitkus, Senior Vice President of Land

Mr. Zitkus, 5960, has served as Senior Vice President of Land since January 2017 and joined the Company as Vice President of Land in March 2014. Prior to joining the Company, Mr. Zitkus served as an independent consultant from October 2013 to March 2014 and as Vice President of Land for Chesapeake Energy Corporation from May 2007 to October 2013. During his 20-year tenure with Equitable Resources Inc. (now EQT Corp.), he held various positions, including Vice President of Operations and Senior Vice President of Land, between 1987 and 2007. He holds a degree in Mineral Land Management from the University of Evansville. Mr. Zitkus is a member of the American Association of Professional Landmen and Past Regional Director of the Independent Petroleum Association of America.

There isare no family ~~relationship~~relationships ~~between~~among ~~any of~~ our executive officers or between any ofexecutive ~~them~~officer and ~~the~~any ~~Company's~~member of the Board of Directors. ~~The~~Each executive ~~officers~~officer ~~serve~~serves at the ~~pleasure~~discretion of the ~~Company's~~ Board of Directors.

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ITEM 1A.			RISK FACTORS

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

Financial, Liquidity and Commodity Price Risks

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

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

Historically, the markets for natural gas, oil and NGL have been volatile, and they are likely to continue to be volatile. For example, during ~~2023~~2024, WTI prices ranged from $66.6173 to $9387.6769 per barrel and the Henry Hub spot market price of natural gas ranged from $1.7421 to $313.7820 per MMBtu. During ~~2024~~2025, WTI prices ranged from $6655.7344 to $8780.6973 per barrel and the Henry Hub spot market price of natural gas ranged from $12.2165 to $139.2086 per MMBtu.

Wide fluctuations in natural gas, oil and NGL prices may result from factors that are beyond our control, including:

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

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

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

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

•the expected rates of declining current production;

•the price and availability of alternative fuels;

•technological advances and changing consumer attitudes affecting energy consumption;

•risks associated with operating drilling rigs;

•the effectiveness of worldwide conservation measures;

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

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

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

•the price and level of foreign imports and exports, including as a result of U.S. trade policy;

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

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

•political or economic instability or armed conflict in oil and natural gas producing regions;

•weather conditions;

•acts of terrorism; and

•domestic and global economic conditions.

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These factors and the volatility of the energy markets make it extremely difficult to predict future natural gas, oil and NGL price movements with any certainty. Even with natural gas, oil and NGL derivatives currently in place to mitigate price risks associated with a portion of our ~~2025~~future cash flows, we have substantial exposure to natural gas prices, and to a lesser extent, oil and NGL prices, in ~~2025~~2026 and beyond. In addition, a prolonged extension of lower prices could reduce the quantities of reserves that we may economically produce. This may result in our having to make substantial downward adjustments to our estimated proved reserves. If this occurs or if our production estimates change or our exploration or development activities are curtailed, full cost accounting rules may require us to write-down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties.

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

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

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

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

Our earnings are exposed to interest rate risk associated with borrowings under our Credit Facility, which is structured under floating rate terms. As such, our interest expense is sensitive to fluctuations in the SOFR benchmark. For the year ended December 31, ~~2024~~2025, amounts borrowed under our Credit Facility bore interest at the weighted average rate of 86.2353%. A 1% increase in the average interest rate would increase our interest expense by approximately $01.45 million based on outstanding borrowings under our Credit Facility at December 31, ~~2024~~2025. An increase in our interest rate at the time we have variable interest rate borrowings outstanding under our Credit Facility will increase our costs, which may have a material adverse effect on our results of operations and financial condition. As of December 31, ~~2024~~2025, we did not hedge our interest rate risk.

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Our debt and other financial commitments may limit our financial and operating flexibility.

Our total principal debt was approximately $~~713~~797.70 million at December 31, ~~2024~~2025. We also had various commitments for leases, drilling contracts, derivative contracts, firm transportation, and purchase obligations for services, products and properties. Our financial commitments could have important consequences to our business, including, but not limited to, limiting our ability to fund future working capital and capital expenditures, to engage in future acquisitions or development activities, to pay dividends, to repurchase shares of our common stock, or to otherwise realize the value of our assets and opportunities fully because of the need to dedicate a substantial portion of our cash flows from operations to make payments on our debt or to comply with restrictive terms of our debt. Higher levels of debt may make us more vulnerable to general adverse economic and industry conditions. Additionally, the agreement governing our credit facility and the indentures governing our senior notes contain a number of covenants that impose constraints on us, including requirements to comply with certain financial covenants and restrictions on our ability to dispose of assets, make certain investments, incur liens and additional debt, and engage in consolidations, mergers and acquisitions. A downgrade in our credit rating could significantly increase our collateral requirements for commercial contracts and derivatives and restrict or limit our access to trade credit or capital. If commodity prices decline and we reduce our level of capital spending and production declines or we incur additional impairment expense or the value of our proved reserves declines, we may not be able to incur additional indebtedness, may need to repay outstanding indebtedness and may not be in compliance with the financial covenants in our debt instruments in the future. Refer to “Management's Discussion and Analysis of Financial Condition and Results of Operations” in Part II, Item 7 of this Annual Report on Form 10-K and Note 4 of our consolidated financial statements for more information regarding the financial covenants and our Credit Facility.

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

Our future success depends upon our ability to find, develop or acquire additional oil and natural gas reserves that are economically recoverable. Our proved reserves will generally decline as reserves are depleted, except to the extent that we conduct successful exploration or development activities or acquire properties containing proved reserves, or both. We have made and expect to make in the future substantial capital expenditures in our business and operations for the development, production, exploration and acquisition of oil and natural gas reserves.

Historically, we have financed capital expenditures primarily with cash flow from operations and borrowings under our revolving credit facility. Our cash flow from operations and access to capital are subject to a number of variables, including:

•our proved reserves;

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

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

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

•our ability to borrow under our credit facility.

We cannot assure you that our operations and other capital resources will provide cash in sufficient amounts to maintain planned or future levels of capital expenditures. In the event our capital expenditure requirements at any time are greater than the amount of capital we have available, we could be required to seek additional sources of capital through a variety of means. We cannot guarantee that we will be able to obtain debt or equity financing on terms favorable to us, or at all.

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

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

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

Under the full cost method of accounting for oil and gas properties, we are required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the oil and gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes or the cost center ceiling. If the net book value reduced by the related net deferred income tax liability exceeds the ceiling, an impairment or non-cash write-down is required. A ceiling test impairment can result in a significant loss for a particular period. Once incurred, a write-down of oil and natural gas properties is not reversible at a later date, even if oil or gas prices increase. Future non-cash asset impairments could negatively affect our results of operations.

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

As of December 31, ~~2024~~2025, we had a net operating loss, or NOL, carryforward of approximately $1.65 billion for federal income tax purposes. If we were to experience an “ownership change,” as determined under IRC Section 382, our ability to offset taxable income arising after the ownership change with NOLs generated prior to the ownership change would be limited, possibly substantially. In general, an ownership change would establish an annual limitation on the amount of our pre-change NOLs we could utilize to offset our taxable income in any future taxable year to an amount generally equal to the value of our stock immediately prior to the ownership change multiplied by the long-term tax-exempt rate for the month in which such ownership change occurs. In general, an ownership change will occur if there is a cumulative increase in our ownership of more than 50 percentage points by one or more “5% shareholders” (as defined in the Internal Revenue Code) at any time during a rolling three-year period.

Industry, Business and Operational Risks

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

We face competition in every aspect of our business, including buying and selling reserves and leases, obtaining goods and services needed to operate our business and marketing natural gas, oil or NGL. Competitors include multinational oil companies, independent production companies and individual producers and operators. Some of our competitors have greater financial and other resources than we do and may have greater access to the capital and credit markets. Many of these companies not only explore for and produce oil and natural gas but also carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. As a result, these competitors may be able to address these competitive factors more effectively or weather industry downturns more easily than we can. We also face indirect competition from alternative energy sources, including wind, solar and electric power.

~~Our~~In ~~performance~~addition, ~~depends largely on~~ the ~~talents~~oil and ~~efforts~~gas ofindustry ~~highly~~is ~~skilled~~characterized ~~individuals~~by ~~and~~rapid ontechnological ~~our~~change ~~ability~~and tothe ~~attract~~introduction of new ~~employees~~products and ~~to retain and motivate our existing employees~~services. ~~Competition~~Competitors inthat ~~our~~develop ~~industry~~or ~~for~~adopt ~~qualified~~new ~~employees~~technologies ismore ~~intense.~~quickly Ifmay wegain ~~are~~a ~~unsuccessful~~significant inadvantage, ~~attracting~~which ~~and~~could ~~retaining~~require ~~skilled~~us ~~employees~~to ~~and~~incur ~~managerial~~substantial ~~talent,~~costs ~~our ability~~ to ~~compete~~remain ~~effectively may be diminished~~competitive. WeSome ~~also~~industry ~~compete~~participants ~~for~~have ~~the~~greater ~~equipment~~financial, ~~required to explore~~technical, ~~develop~~ and ~~operate~~personnel ~~properties. Typically~~resources, ~~during~~enabling ~~times~~them ofto ~~rising~~implement ~~commodity~~innovations ~~prices,~~sooner ~~drilling~~ and ~~operating~~more ~~costs~~effectively ~~will~~than ~~also~~we ~~increase~~can. ~~During~~Our ~~these~~ability ~~periods,~~to ~~there~~respond isto ~~often~~these achanges ~~shortage~~in ofa ~~drilling~~timely ~~rigs~~ and ~~other~~cost ~~oilfield~~efficient ~~equipment~~manner ~~and~~is ~~services~~uncertain, ~~which~~and ~~could~~if ~~adversely~~technologies ~~affect~~we ~~our~~rely ~~ability~~on tobecome ~~execute~~obsolete, our ~~development~~business, ~~plans~~financial oncondition, aor ~~timely~~results ~~basis~~of operations could be materially and ~~within~~adversely ~~budget~~affected.

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

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

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

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

As of December 31, ~~2024~~2025, approximately 4743% of our total estimated proved reserves were PUDs and may not be ultimately developed or produced. Recovery of PUDs requires significant capital expenditures and successful drilling operations. The reserve data included in the reserve reports ofaudited ~~our~~by an independent petroleum ~~engineers~~engineering firm assume that substantial capital expenditures are required to develop such reserves. Estimated development costs may not equal our actual costs, development may not occur as scheduled and results may not be as estimated. Delays in the development of our reserves, further decreases in commodity prices or increases in costs to drill and develop such reserves will reduce the future net revenues of our estimated proved undeveloped reserves and may result in some projects becoming uneconomical. If we choose not to develop our PUDs, or if we are not otherwise able to successfully develop them, we will be required to remove them from our reported proved reserves. In addition, under the SEC's reserve reporting rules, because PUDs generally may be booked only if they relate to wells scheduled to be drilled within five years of the date of booking, we may be required to remove any PUDs that are not developed within this five-year time frame.

You should not assume that the present values included in this report represent the current market value of our estimated reserves. In accordance with SEC requirements, the estimates of our present values are based on prices and costs as of the date of the estimates. The price on the date of estimate is calculated as the average natural gas and oil price during the 12 months ending in the current reporting period, determined as the unweighted arithmetic average of prices on the first day of each month within the 12-month period. The December 31, ~~2024~~2025 present value is based on a $23.1339 per MMBtu of gas price and a $7666.3201 per Bbl of oil price, before considering basis differential adjustments. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of an estimate.

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

•actual prices we receive for oil and natural gas;

•the amount and timing of actual production;

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

•changes in governmental regulations or taxation.

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

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

We have a substantial inventory of undeveloped properties. Development and exploratory drilling and production activities are subject to many risks, including the risk that commercially productive reservoirs will not be discovered. Acquiring oil and natural gas properties requires us to assess reservoir and infrastructure characteristics, including recoverable reserves, development and operating costs and potential environmental and other liabilities. Such assessments are inexact and inherently uncertain. In connection with the assessments, we perform a review of the subject properties, but such a review will not necessarily reveal all existing or potential problems. In the course of our due diligence, we may not inspect every well or pipeline. We cannot necessarily observe structural and environmental problems, such as pipe corrosion, when an inspection is made. We may not be able to obtain contractual indemnities from the seller for liabilities created prior to our purchase of the property. We may be required to assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform in accordance with our expectations.

We acquire unproven properties that we believe will enhance our growth potential and increase our earnings over time. However, we cannot assure you that all prospects will be economically viable or that we will not abandon our initial investments. Additionally, there can be no assurance that undeveloped properties acquired by us will be profitably developed, that new wells drilled by us in prospects that we pursue will be productive, or that we will recover all or any portion of our investment in such undeveloped properties or wells.

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

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

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

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

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

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

Leases on oil and natural gas properties typically have a term of three to five years, after which they expire unless a lease contains an optional right to extend its term or, prior to expiration, a well is drilled and production of hydrocarbons in paying quantities is established. In addition, many of our oil and natural gas leases require us to drill wells that are commercially productive, and if we are unsuccessful in drilling such wells, we could lose our rights under such leases. Although approximately 8684% of our Utica/Marcellus acreage is held by existing production, the remaining acreage is subject to expiration. Of the remaining 1416% of our Utica/Marcellus acreage not held by production, approximately 7% will be subject to expiration in ~~2025~~2026, 124% in ~~2026~~2027, 928% in ~~2027~~2028 and approximately 7261% thereafter, although a portion of our Utica/Marcellus leases generally grant us the right to extend ~~these~~the ~~leases~~term for an additional three or five-year period. Approximately 99% of our SCOOP acreage is held by existing production; the remaining acreage is subject to expiration. Although we seek to actively manage our undeveloped leasehold properties, our drilling plans for these areas are subject to change based upon various factors, including drilling results, oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints and regulatory approvals. Low commodity prices may cause us to delay our drilling plans and, as a result, lose our right to develop ~~the~~certain ~~related properties~~leases. The cost to renew expiring leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms or at all. If we are unable to fund ~~renewals~~the cost of renewing expiring leases, ~~we could lose~~ portions of our leasehold acreage could expire and our actual drilling activities may differ materially from our current expectations, which could adversely affect our business.

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

Our oil and gas properties can become damaged, our operations may be curtailed, delayed or canceled and the costs of such operations may increase as a result of a variety of factors, including, but not limited to:

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

•loss of drilling fluid circulation;

•equipment failures or accidents;

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

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

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migration of fracturing fluids, including chemical additives;

•adverse weather conditions and natural disasters, such as tornadoes, earthquakes, hurricanes and extreme temperatures, which may be exacerbated by climate change;

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

•restricted takeaway capacity for our production, including due to inadequate midstream infrastructure or constrained downstream markets;

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

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

•shortages or delays in the availability of services or delivery of equipment; and

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

The occurrence of one or more of these factors could result in a partial or total loss of our investment in a particular property, as well as significant liabilities.

While we may maintain insurance against some, but not all, of the risks described above, our insurance may not be adequate to cover casualty losses or liabilities, and our insurance does not cover penalties or fines that may be assessed by a governmental authority. For certain risks, such as political risk, business interruption, cybersecurity breaches, war, terrorism and piracy, we have limited or no insurance coverage. Also, in the future we may not be able to obtain insurance at premium levels that justify its purchase. The occurrence of a significant uninsured claim, a claim in excess of the insurance coverage limits maintained by us or a claim at a time when we are not able to obtain liability insurance could have a material adverse effect on our ability to conduct normal business operations and on our financial condition, results of operations or cash flow. We may not be able to secure additional insurance or bonding that might be required by new governmental regulations. This may cause us to restrict our operations, which might severely impact our financial position. A loss not fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows.

Multi-well pad drilling may result in volatility in our operating results and delay the conversion of our PUD reserves.

We utilize multi-well pad drilling where practical. ~~For example, in the Utica/Marcellus we drill multiple wells from a single pad.~~ Wells drilled on a pad are not turned to sales until all wells on the pad are drilled and cased and the drilling rig is moved from the location. In addition, existing wells that offset newly drilled wells may be temporarily shut in during the drilling and completion process. As a result, multi-well pad drilling delays the completion of wells and the commencement of production from new wells and may negatively affect the production from existing offset wells, all of which may cause volatility in our operating results from period to period. Finally, delays in completion of wells may impact planned conversion of PUD reserves to PDP reserves.

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

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

•the timing and amount of capital expenditures;

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

•the operator's expertise and financial resources;

•approval of other participants in drilling wells;

•selection of technology; and

•the rate of production of the reserves.

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

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

Water is an essential component of oil and natural gas production during the drilling, and in particular, hydraulic fracturing, process. Our inability to locate sufficient amounts of water, or dispose of or recycle water used in our exploration and production operations, could adversely impact our operations. For water sourcing, we first seek to use non-potable water supplies for our operational needs. In certain areas, there may be insufficient local aquifer capacity to provide a source of water for drilling activities. Water must then be obtained from other sources and transported to the drilling site. An inability to secure sufficient amounts of water or to dispose of or recycle the water used in our operations could adversely impact our operations in certain areas. The imposition of new environmental regulations could further restrict our ability to conduct operations such as hydraulic fracturing by restricting the disposal of things such as produced water and drilling fluids.

All of our producing properties are located in eastern Ohio and central Oklahoma, making us vulnerable to risks associated with operating in only these regions.

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

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

The largest purchaser of our oil and natural gas during the year ended December 31, ~~2024~~2025, accounted for approximately 1514% of our total natural gas, oil and NGL revenues. If this purchaser or one or more other significant purchasers, ~~are~~is unable to satisfy its contractual obligations, we may be unable to sell such production to other customers on terms we consider acceptable. Further, the inability of one or more of our customers to pay amounts owed to us could adversely affect our business, financial condition, results of operations and cash flows.

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

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

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

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

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With respect to our Utica/Marcellus acreage where we are focusing a portion of our exploration and development activity, operations may be delayed due to challenges in obtaining rights-of-way and acquiring necessary state and federal permitting and the completion of facilities by our midstream service provider. Capital constraints could limit the construction of new pipelines and gathering systems and the providing or expansion of trucking services by third parties in the Utica/Marcellus and the other areas in which we operate. As a result, we may experience delays or curtailments in producing and selling our natural gas, oil and NGL. In such event, we might have to shut in or curtail our wells awaiting a pipeline connection or capacity or sell natural gas, oil or NGL production at significantly lower prices than those quoted on NYMEX or than we currently project, which would adversely affect our results of operations.

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

We are required to pay fees to some of our midstream service providers based on minimum volumes regardless of actual volume throughput.

We have contracts with some of our third-party service providers for gathering, processing and transportation services with minimum volume delivery commitments under which we are obligated to pay certain fees on minimum volumes regardless of actual volume throughput. As of December 31, ~~2024~~2025, our aggregate long-term contractual obligation under these agreements was approximately $1.10 billion. These fees could be significant and may have a material adverse effect on our results of operations.

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

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

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

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

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

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

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

We may engage in acquisition and divestiture activities that involve substantial risks.

We may make acquisitions that complement or expand our current areas of operations. If we are unable to make attractive acquisitions, our future growth could be limited. Furthermore, even if we do make acquisitions, they may not result in an increase in our cash flow from operations or otherwise result in the benefits anticipated due to various risks, including, but not limited to:

•mistaken estimates or assumptions about reserves, potential drilling locations, revenues and costs, including synergies and the overall costs of equity or debt;

•difficulties in integrating the operations, technologies, products and personnel of the acquired assets or business; and

•unknown and unforeseen liabilities or other issues related to any acquisition for which contractual protections prove inadequate, including environmental liabilities and title defects.

In addition, from time to time, we may sell or otherwise dispose of certain of our properties or businesses as a result of an evaluation of our asset portfolio or to help enhance our liquidity. These transactions also have inherent risks, including possible delays in closing, the risk of lower-than-expected sales proceeds for the disposed assets or businesses and potential post-closing claims for indemnification. Moreover, volatility in commodity prices may result in fewer potential bidders, unsuccessful sales efforts and a higher risk that buyers may seek to terminate a transaction prior to closing.

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Environmental, Legal and Regulatory Risks

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

Our operations are subject to extensive federal, state, tribal, local and other laws, rules and regulations, including with respect to environmental matters, worker health and safety, wildlife conservation, the gathering and transportation of oil, gas and NGL, conservation policies, reporting obligations, royalty payments, unclaimed property and the imposition of taxes. Such regulations include requirements for permits to drill and to conduct other operations and for provision of financial assurances (such as bonds) covering drilling, completion and well operations. If permits are not issued, or if unfavorable restrictions or conditions are imposed on our drilling or completion activities, we may not be able to conduct our operations as planned. For example, in March 2024, the United States Environmental Protection Agency (“USEPA”), issued its final methane rules to reduce methane emissions from both new and existing oil and natural gas facilities and the Inflation Reduction Act of 2022 (“IRA 2022”) established the Methane Emissions Reduction Program, which imposes a charge on methane emissions from the same facilities, the rule for which was finalized in November 2024. ~~Further~~However, the ~~Bureau~~methane ~~for~~emissions ~~Land~~charge ~~Management~~rule (was repealed in February 2025 and the imposition of the charge under the IRA 2022 was postponed until 2034 under the One Big Beautiful Bill Act of July 2025. In December 2025, the USEPA issued a final rule extending several compliance deadlines and timeframes associated with the 2024 methane rules. Further, the BLM) issued a final Methane Waste Prevention Rule on April 10, 2024. The rule adds additional requirements for operators on federal and Indian leases and includes new air quality requirements along with waste prevention provisions. In November 2025, BLM announced it will delay enforcement of two provisions of the Waste Prevention Rule that had been scheduled to take effect in December 2025 as it reviews the underlying rule and considers revisions. Litigation challenging the 2024 rule is currently held in abeyance. Constrained supply chain for environmental control devices along with the significant estimated costs of compliance with these new and proposed rules could have a material impact on our operations. We may be required to make large, sometimes unexpected, expenditures to comply with applicable governmental laws, rules, regulations, permits or orders.

In addition, changes in public policy have affected, and in the future could further affect, our operations. Regulatory changes could, among other things, restrict production levels, impose price controls, alter environmental protection requirements and increase taxes, royalties and other amounts payable to the government. Our operating and compliance costs could increase further if existing laws and regulations are revised or reinterpreted or if new laws and regulations become applicable to our operations. We do not expect that any of these laws and regulations will affect our operations materially differently than they would affect other companies with similar operations, size and financial strength. Although we are unable to predict changes to existing laws and regulations, such changes could significantly impact our profitability, financial condition and liquidity. As is discussed below this is particularly true of changes related to pipeline safety, seismic activity, hydraulic fracturing, climate change and endangered species designations. As of January 2025, however, the Trump Administration issued a series of executive orders that signal a shift in the United States' energy polices, including directing federal agencies to identify and exercise emergency authorities to facilitate conventional energy production, transportation, and refining, and call for the use of emergency regulations to expedite energy infrastructure projects, promote energy exploration and production on federal lands and waters, and mandate a review of existing regulations that may burden domestic energy development.

Pipeline Safety. The pipeline assets owned by our midstream service providers are subject to stringent and complex regulations related to pipeline safety and integrity management. The Pipeline and Hazardous Materials Safety Administration (“PHMSA”) has established a series of rules that require pipeline operators to develop and implement integrity management programs for gas, NGL and condensate transmission pipelines as well as certain low stress pipelines and gathering lines transporting hazardous liquids, such as oil, that, in the event of a failure, could affect “high consequence areas”.” Recent PHMSA rules have also extended certain requirements for integrity assessments and leak detections beyond high consequence areas. Further, legislation funding PHMSA through 2023 requires the agency to engage in additional rulemaking to amend the integrity management program, emergency response plan, operation and maintenance manual, and pressure control recordkeeping requirements for gas distribution operators; to create new leak detection and repair program obligations; and to set new minimum federal safety standards for onshore gas gathering lines. At this time, we cannot predict the cost of these requirements or other potential new or amended regulations, but they could be significant, and any such costs incurred by our midstream service providers could result in increased midstream gathering and processing expenses for us. Moreover, violations of pipeline safety regulations by our midstream service providers could result in the imposition of significant penalties which may impact the cost or availability of pipeline capacity necessary for our operations.

Seismic Activity. Earthquakes in some of our operating areas and elsewhere have prompted concerns about seismic activity and possible relationships with the energy industry. For example, the OCC issued guidance to operators in the SCOOP and STACK areas for management of certain seismic activity that may be related to hydraulic fracturing or water disposal activities. Legislative and regulatory initiatives intended to address these concerns may result in additional levels of regulation or other requirements that could lead to operational delays, increase our operating and compliance costs or otherwise adversely affect our operations. In addition, we could be subject to third-party lawsuits seeking damages or other remedies as a result of alleged induced seismic activity in our areas of operation.

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~~Hydraulic~~Seismic ~~Fracturing~~Activity. ~~Several~~Earthquakes ~~states~~in ~~have~~some ~~adopted~~of orour ~~are~~operating ~~considering~~areas ~~adopting~~and ~~regulations~~elsewhere ~~that~~have ~~could~~prompted ~~impose~~concerns ~~more~~about ~~stringent~~seismic ~~permitting,~~activity ~~public~~and ~~disclosure~~possible orrelationships ~~well~~with ~~construction~~the ~~requirements~~energy ~~on hydraulic fracturing operations~~industry. ~~Three~~For ~~states (New York~~example, ~~Maryland and Vermont) have banned~~ the ~~use~~OCC ofissued ~~high-volume~~guidance ~~hydraulic fracturing. In addition~~ to ~~state~~operators ~~laws,~~in ~~some~~the ~~local~~SCOOP ~~municipalities~~and ~~have~~STACK ~~adopted~~areas orfor ~~are~~management ~~considering~~of ~~adopting~~certain ~~land~~seismic ~~use~~activity ~~restrictions, such as city ordinances,~~ that may ~~restrict~~be orrelated ~~prohibit~~to ~~the~~hydraulic ~~performance~~fracturing ~~of well drilling in general~~ or ~~hydraulic~~water ~~fracturing~~disposal ~~in particular~~activities. ~~There~~Legislative ~~have also been certain governmental reviews that focus on deep shale~~ and ~~other~~regulatory ~~formation~~initiatives ~~completion~~intended ~~and~~to ~~production~~address ~~practices,~~these ~~including~~concerns ~~hydraulic fracturing. Governments~~ may ~~continue~~result toin ~~study~~additional ~~hydraulic~~levels ~~fracturing. We cannot predict the outcome~~ of ~~future~~regulation ~~studies,~~or ~~but~~other ~~based~~requirements onthat ~~the~~could ~~results~~lead ~~of these studies~~ to ~~date~~operational delays, ~~federal~~increase ~~and~~our ~~state~~operating ~~legislatures~~ and ~~agencies~~compliance ~~may~~costs ~~seek to further regulate~~ or ~~even~~otherwise ~~ban~~adversely ~~hydraulic~~affect ~~fracturing~~our ~~activities~~operations. In addition, ifwe ~~existing~~could ~~laws~~be ~~and~~subject ~~regulations with regard~~ to ~~hydraulic~~third-party ~~fracturing~~lawsuits ~~are~~seeking ~~revised~~damages or ~~reinterpreted~~other orremedies ifas ~~new~~a ~~laws~~result ~~and~~of ~~regulations~~alleged ~~become~~induced ~~applicable~~seismic toactivity ~~our~~in ~~operations through judicial or administrative actions,~~ our ~~business,~~areas ~~financial condition, results~~ of ~~operations and cash flows could be adversely affected~~operation.

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

We cannot predict whether additional federal, state or local laws or regulations applicable to hydraulic fracturing will be enacted in the future and, if so, what actions any such laws or regulations would require or prohibit. If additional levels of regulation or permitting requirements were imposed on hydraulic fracturing operations, our business and operations could be subject to delays, increased operating and compliance costs and potential bans. Additional regulation could also lead to greater opposition to hydraulic fracturing, including litigation.

Climate Change. Continuing political and social attention to the issue of climate change has resulted in legislative, regulatory and other initiatives to reduce greenhouse gas emissions, such as carbon dioxide and methane, and incentivizing energy conservation or the use of alternative energy sources. Policy makers at both the federal and state levels have introduced legislation and proposed new regulations designed to quantify and limit the emission of greenhouse gases through inventories, limitations or taxes on greenhouse gas emissions and encourage consumers to the alternative energy sources. The IRA 2022, both imposes new climate related requirements on oil and gas operations and appropriates significant federal funding for renewable energy initiatives. Also, for the first time ever, the law imposes a fee on GHG emissions from certain facilities. The emissions fee and funding provisions of the IRA 2022 could increase our operating costs and accelerate the transition away from fossil fuels, which could in turn adversely affect our business, results of operations and financial position. OnUnder ~~January~~the 26Trump Administration, ~~2024~~however, ~~the~~there ~~Biden~~has ~~Administration~~been ~~paused~~a ~~approvals~~shift ~~for~~away ~~pending~~from ~~and~~the ~~future~~previous ~~applications~~administration's toGHG ~~export~~program. ~~liquified~~For ~~natural~~example, ~~gas~~in ~~(LNG)~~February on2025, ~~non-FTA~~the ~~countries~~U.S. OnHouse ~~January~~and ~~20,~~Senate ~~2025,~~approved ~~President~~a ~~Trump~~joint ~~issued~~resolution anof ~~executive~~disapproval ~~order~~under ~~reversing~~ the ~~pause~~Congressional ~~implemented~~Review byAct to repeal the ~~Biden~~methane ~~Administration~~emissions charge rule, ~~resuming~~which President Trump signed into law. In September 2025, the ~~processing~~USEPA ofannounced ~~export~~a ~~permit~~proposal ~~applications~~to ~~for~~end ~~new~~the ~~LNG~~GHG ~~projects.~~Reporting ~~Additionally,~~Program infor ~~January~~all ~~2025~~sectors ~~President~~except ~~Trump~~petroleum ~~signed~~and ~~executive~~natural ~~orders~~gas ~~that,~~systems ~~among~~(excluding ~~other~~reporting ~~things~~for natural gas distribution, ~~direct~~which ~~federal~~would ~~executive~~also ~~departments~~be ~~and~~eliminated ~~agencies~~under tothe ~~initiate~~proposal) aand ~~regulatory~~deferring ~~freeze~~reporting for ~~certain~~petroleum ~~rules~~and ~~that~~natural ~~have~~gas ~~not~~systems ~~taken~~until ~~effect,~~2034. ~~pending~~In ~~review~~December by2025, the ~~newly~~USEPA ~~appointed~~issued ~~agency~~a ~~head,~~final rule extending several compliance deadlines and ~~call~~timeframes ~~upon~~associated ~~the~~with ~~USEPA~~its to2024 ~~submit~~methane arules. ~~report~~On onFebruary 12, 2026, the ~~continuing~~USEPA ~~applicability~~announced the repeal of its ~~endangerment~~2009 ~~finding~~“Endangerment ~~for~~Finding” ~~GHGs~~ under the Clean Air Act, ~~and~~which ~~issue~~found ~~guidance~~that onGHGs endanger the ~~“social~~public ~~cost~~health and welfare of ~~carbon”~~current and future generations and emissions of GHGs from motor vehicles contribute to ~~consider~~GHG ~~whether~~pollution. ~~such~~The ~~metric~~repeal ~~should~~calls beinto ~~eliminated~~question EPA's authority to regulate GHGs, ~~and~~as ~~pause~~well ~~the~~as ~~disbursement~~EPA's prior scientific assessment of ~~funds~~climate ~~appropriated~~change ~~through~~risks. Litigation regarding the ~~IRA~~repeal ~~2022.~~is ~~The~~anticipated and it is unclear how the repeal will impact onEPA's ~~these~~regulation of GHG emissions going forward. However, state and local GHG initiatives may continue despite shifts in the federal ~~actions~~approach ~~remain~~to ~~unclear~~climate change.

States in which we operate have imposed venting and flaring limitations designed to reduce methane emissions from oil and gas exploration and production activities. Legislative and state initiatives to date have generally focused on the development of cap and trade or carbon tax programs. Renewable energy standards (also referred to as renewable portfolio standards) require electric utilities to provide a specified minimum percentage of electricity from eligible renewable resources, with potential increases to the required percentage over time. The development of a federal renewable energy standard, or the development of additional or more stringent renewable energy standards at the state level or other initiatives to incentivize the use of renewable energy could reduce the demand for oil and gas, thereby adversely impacting our earnings, cash flows and financial position. Cap and trade programs offer greenhouse gas emission allowances that are gradually reduced over time. A cap and trade program or expanded use of cap and trade programs at the state level could impose direct costs on us through the purchase of allowances and could impose indirect costs by incentivizing consumers to shift away from fossil fuels. In addition, federal or state carbon taxes could directly increase our costs of operation and similarly incentivize consumers to shift away from fossil fuels.

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Index to Financial Statements

InStates ~~addition,~~in ~~activists~~which ~~concerned~~we ~~about~~operate ~~the~~have ~~potential~~imposed ~~effects~~venting ofand ~~climate~~flaring ~~change~~limitations ~~have~~designed ~~directed~~to ~~their~~reduce ~~attention~~methane atemissions ~~sources~~from ofoil ~~funding~~and ~~for~~gas ~~fossil-fuel~~exploration ~~energy~~and ~~companies,~~production ~~which~~activities. ~~has~~Legislative ~~resulted~~and instate ~~certain~~initiatives ~~financial~~to ~~institutions,~~date ~~funds~~have ~~and~~generally ~~other~~focused ~~sources~~on the development of ~~capital~~cap ~~restricting~~and trade or ~~eliminating~~carbon ~~their~~tax ~~investment~~programs. inRenewable ~~oil~~energy ~~and~~standards ~~natural~~(also ~~gas~~referred ~~activities.~~to ~~Ultimately,~~as ~~this~~renewable ~~could~~portfolio ~~make~~standards) itrequire ~~more~~electric ~~difficult~~utilities to ~~secure~~provide ~~funding~~a ~~for~~specified ~~exploration~~minimum ~~and~~percentage ~~production~~of ~~activities.~~electricity ~~Members~~from ofeligible ~~the~~renewable ~~investment~~resources, ~~community~~with ~~have~~potential ~~also~~increases ~~begun~~ to ~~screen~~the ~~companies~~required ~~such~~percentage asover ~~ours~~time. ~~for~~The ~~sustainability~~development ~~performance,~~of ~~including~~a ~~practices~~federal ~~related~~renewable toenergy ~~greenhouse~~standard, ~~gases~~or ~~and~~the ~~climate~~development ~~change,~~of ~~before~~additional ~~investing~~or inmore ~~our~~stringent ~~common~~renewable ~~units.~~energy ~~Any~~standards ~~efforts~~at tothe ~~improve~~state ~~our~~level ~~sustainability~~or ~~practices~~other ininitiatives ~~response~~ to ~~these~~incentivize ~~pressures~~the ~~may~~use ~~increase~~of ~~our~~renewable ~~costs,~~energy ~~and~~could wereduce ~~may~~the bedemand ~~forced~~for tooil ~~implement~~and ~~technologies~~gas, ~~that~~thereby ~~are~~adversely ~~not~~impacting ~~economically~~our ~~viable~~earnings, tocash ~~improve~~flows ~~our~~and ~~sustainability~~financial ~~performance~~position. Cap and totrade ~~meet~~programs ~~the~~offer ~~specific~~greenhouse ~~requirements~~gas toemission ~~perform~~allowances ~~services~~that ~~for~~are ~~certain~~gradually ~~customers.~~reduced Ifover wetime. ~~are~~A ~~unable~~cap toand ~~meet~~trade ~~the~~program ~~ESG~~or ~~standard~~expanded oruse ~~investment,~~of ~~lending,~~cap ~~ratings,~~and ortrade ~~voting~~programs ~~criteria~~at ~~and~~the ~~policies~~state ~~set~~level bycould ~~these~~impose ~~parties,~~direct wecosts ~~may~~on ~~lose~~us ~~investors,~~through ~~investors~~the ~~may~~purchase ~~allocate~~of aallowances ~~portion~~and ofcould ~~their~~impose ~~capital~~indirect ~~away~~costs ~~from~~by ~~us,~~incentivizing weconsumers ~~may~~to ~~become~~shift aaway ~~target~~from ~~for~~fossil ~~ESG-focused~~fuels. ~~activism~~In addition, ~~our~~federal ~~cost~~or ofstate ~~capital~~carbon ~~may~~taxes ~~increase,~~could ~~the~~directly ~~price~~increase of our ~~securities~~costs ~~may~~of beoperation ~~negatively~~and ~~impacted,~~similarly ~~and~~incentivize ~~our~~consumers ~~reputation~~to ~~may~~shift ~~also~~away befrom ~~negatively~~fossil ~~affected~~fuels.

In addition, activists concerned about the potential effects of climate change have directed their attention at sources of funding for fossil-fuel energy companies, which has resulted in certain financial institutions, funds and other sources of capital restricting or eliminating their investment in oil and natural gas activities. Ultimately, this could make it more difficult to secure funding for exploration and production activities. Members of the investment community have also begun to screen companies such as ours for sustainability performance, including practices related to greenhouse gases and climate change, before investing in our common units. Any efforts to improve our sustainability practices in response to these pressures may increase our costs, and we may be forced to implement technologies that are not economically viable to improve our sustainability performance and to meet the specific requirements to perform services for certain customers. If we are unable to meet the sustainability standard or investment, lending, ratings, or voting criteria and policies set by these parties, we may lose investors, investors may allocate a portion of their capital away from us, we may become a target for sustainability-focused activism, our cost of capital may increase, the price of our securities may be negatively impacted, and our reputation may also be negatively affected.

These various legislative, regulatory and other activities addressing greenhouse gas emissions could adversely affect our business, including by imposing reporting obligations on, or limiting emissions of greenhouse gases from, our equipment and operations, which could require us to incur costs to reduce emissions of greenhouse gases associated with our operations. Limitations on greenhouse gas emissions could also adversely affect demand for oil and gas, which could lower the value of our reserves and have a material adverse effect on our profitability, financial condition and liquidity. Furthermore, increasing attention to climate change risks has resulted in increased likelihood of governmental investigations and private litigation, which could increase our costs or otherwise adversely affect our business.

Severe weather events, such as storms, hurricanes, droughts, or floods, which may be exacerbated by climate change, could have an adverse effect on our operations and could increase our costs. Potential adverse effects could include damages to our facilities, the costs of less efficient or non-routine operating practices necessitated by weather events, or increased costs for insurance coverage. If climate changes result in more intense or frequent severe weather events, the physical and disruptive effects could have a material adverse impact on our operations and assets.

Air Emissions. The US Federal Clean Air Act and associated state laws and regulations restrict the emission of air pollutants from many sources, including oil and natural gas operations. New facilities may be required to obtain permits before operations can commence, and existing facilities may be required to obtain additional permits, and incur capital costs, in order to remain in compliance. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the Clean Air Act and associated state laws and regulations. In general, we believe that compliance with the Clean Air Act and similar state laws and regulations will not have a material impact on our operations or financial condition.

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

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

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

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In our Utica/Marcellus and SCOOP operations, we make an effort to reuse/recycle all produced water from production and completion activities through our fracture stimulation operations when active. While our objective is to recycle or share 100% of all produced water, we do inject water into third-party commercially operated disposal wells in line with all state and federal mandated practices and cease produced water recycle whenever fracture stimulation operations are idle once sharing opportunities with other operators have been exhausted. In the state of Ohio, all water used during drilling operations is disposed of through injection into third-party salt water disposal wells regulated by applicable state agencies.

Increased attention to ~~ESG~~sustainability matters may impact our business, financial results, or stock price.

InStandards ~~recent~~and ~~years,~~expectations ~~increasing~~regarding ~~attention~~carbon ~~has~~accounting ~~been given to corporate activities related to ESG matters in public discourse~~ and the ~~investment~~processes ~~community. A number of advocacy groups, both domestically and internationally, have campaigned~~ for ~~governmental~~measuring and ~~private~~counting ~~action~~GHG toemissions ~~promote change at public companies related to ESG matters, including through the investment~~ and ~~voting~~GHG ~~practices~~emission ofreductions ~~investment~~are ~~advisers~~evolving, ~~public pension funds, activist investors, universities~~ and ~~other~~it ~~members~~is ofpossible ~~the~~that ~~investing~~our ~~community.~~approach ~~These~~to ~~activities~~measuring ~~include~~both ~~increasing~~our ~~attention~~emissions and ~~demands~~our ~~for~~approaches ~~action related~~ to ~~climate~~reducing ~~change,~~emissions ~~advocating~~may ~~for changes to companies’ boards of directors~~be, ~~and~~either ~~promoting~~currently ~~the~~by ~~use~~some ofstakeholders ~~energy~~or ~~saving~~at ~~building~~some ~~materials.~~future ~~On January 20~~point, ~~2025,~~considered ~~however,~~inconsistent ~~President~~with ~~Trump~~common ~~signed~~or anbest ~~executive~~practices. ~~order~~A failure to ~~withdraw~~comply ~~the~~with ~~United~~investor ~~States~~or ~~from~~customer ~~the~~expectations ~~Paris~~and ~~Agreement~~standards, ~~marking~~which aare ~~significant~~evolving, ~~shift~~or inif ~~U.S.~~we ~~federal~~are ~~climate~~perceived ~~policy. Pursuant~~ to ~~the~~not ~~terms~~have ofresponded ~~the~~appropriately ~~Paris~~to ~~Agreement,~~ the ~~withdrawal~~growing ~~will~~concern ~~take~~for ~~effect~~sustainability ~~on January 27~~issues, ~~2026.~~regardless ~~State~~of ~~and~~whether ~~local~~there ~~GHG~~is ~~initiatives~~a ~~may~~legal ~~continue~~requirement ~~despite~~to ~~the~~do ~~U.S.~~so, ~~withdrawal~~could ~~from~~cause ~~the~~reputational ~~Paris~~harm ~~Agreement. A potential global transition~~ to ~~a low carbon economy may result in reduced demand for~~ our ~~oil~~business, ~~natural~~increase ~~gas~~our ~~and~~risk ~~NGL,~~of ~~reduced profits~~litigation, ~~increased investigations~~ and ~~litigation, each of which~~ could have ~~negative~~a ~~impacts~~material adverse effect on our ~~access~~results toof ~~capital markets~~operations.

In addition, weorganizations ~~note~~ that ~~standards~~provide ~~and~~information ~~expectations~~to ~~regarding~~investors ~~carbon~~on ~~accounting~~corporate ~~and~~governance ~~the processes for measuring~~ and ~~counting~~related ~~GHG~~matters ~~emissions~~have ~~and~~developed ~~GHG~~ratings ~~emission~~systems ~~reductions~~for ~~are~~evaluating ~~evolving,~~companies ~~and~~on ittheir ~~is possible that our~~ approach to ~~measuring~~sustainability ~~both~~matters. ~~our~~These ~~emissions~~ratings ~~and~~are ~~our~~used ~~approaches to reducing emissions may be, either currently~~ by some ~~stakeholders~~investors orto atinform ~~some~~their ~~future~~investment ~~point,~~and ~~considered~~voting ~~inconsistent~~decisions. ~~with~~We ~~common~~may ortake ~~best~~certain ~~practices.~~actions ~~A failure~~ to ~~comply~~improve ~~with~~the ~~investor~~sustainability orprofile ~~customer~~of ~~expectations~~our company and/or ~~standards~~products, ~~which~~but ~~are~~we ~~evolving,~~cannot orguarantee ifthat wesuch ~~are~~actions ~~perceived~~will ~~to not~~ have ~~responded appropriately to~~ the ~~growing~~desired ~~concern~~effect. ~~for~~Unfavorable ~~ESG~~sustainability ~~issues,~~ratings ~~regardless~~may oflead ~~whether~~to ~~there~~increased isnegative ainvestor ~~legal~~sentiment ~~requirement~~toward tous doand ~~so,~~our ~~could~~industry ~~cause~~and ~~reputational harm~~ to ~~our~~the ~~business,~~diversion ~~increase~~of ~~our~~investment ~~risk~~to ofother ~~litigation~~industries, ~~and~~which could have a ~~material~~negative ~~adverse~~impact ~~effect~~ on our ~~results~~stock price and our access to and costs of ~~operations~~capital.

In addition, organizations that provide information to investors on corporate governance and related matters have developed ratings systems for evaluating companies on their approach to ESG matters. These ratings are used by some investors to inform their investment and voting decisions. We may take certain actions to improve the ESG profile of our company and/or products, but we cannot guarantee that such actions will have the desired effect. Unfavorable ESG ratings may lead to increased negative investor sentiment toward us and our industry and to the diversion of investment to other industries, which could have a negative impact on our stock price and our access to and costs of capital.

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

From time to time, legislation has been proposed that, if enacted into law, would make significant changes to U.S. federal and state income tax laws affecting the oil and gas industry. For example, legislative proposals have been introduced in the U.S. Congress in the past that, if enacted, would (i) eliminate the immediate deduction for intangible drilling and development costs, (ii) repeal the percentage depletion allowance for oil and natural gas properties, and (iii) extend the amortization period for certain geological and geophysical expenditures. No accurate prediction can be made as to whether any such legislative changes will be proposed or enacted in the future or, if enacted, what the specific provisions or the effective date of any such legislation would be. In addition, at the state level, legislative changes imposing increased taxes on oil and gas production have periodically been considered in Ohio and Oklahoma. These proposed changes in the U.S. federal and state tax law, if adopted, or other similar changes that would impose additional tax on our activities or reduce or eliminate deductions currently available with respect to natural gas and oil exploration, development or similar activities, could adversely affect our business, results of operations, financial condition and cash flows.

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

The regulatory environment surrounding data privacy and protection is constantly evolving and can be subject to significant change. New laws and regulations governing data privacy and the unauthorized disclosure of confidential information pose increasingly complex compliance challenges and potentially elevate our costs as we collect, use, share, and store personal data related to royalty owners. Any failure to comply with these laws and regulations could result in significant penalties and legal liability. For example, the California Consumer Privacy Act (“CCPA”), as amended by the California Privacy Rights Act (“CPRA”), establishes certain transparency rules and creates new data privacy rights for individuals, including limitations on our use of certain sensitive personal information and more ability for individuals to control the purposes for which their data is shared with third parties. The CPRA also provides for statutory fines for data security breaches or other CPRA violations. Meanwhile, many other states enacted, and others have considered, privacy laws like the CPRA. We will continue to monitor and assess the impact of these state laws, which may impose substantial penalties for violations, impose significant costs for investigations and compliance, require us to change our business practices, allow private class-action litigation and carry significant potential liability for our business should we fail to comply with any such applicable laws.

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

Risks Associated with an Investment in Us

The market price of our securities is subject to volatility.

The market price of our common stock could be subject to wide fluctuations in response to, and the level of trading that develops with our common stock may be affected by, numerous factors, many of which are beyond our control. These factors include, among other things, future sales of additional stock and changes in our capital structure, compliance with governmental regulations and taxation laws, actual or anticipated variations in our operating results and cash flow, allocation of free cash flow including any determination by our board of directors regarding repurchasing stock, the nature and content of our earnings releases, announcements or events that impact our products, customers, competitors or markets, business conditions in our markets and the general state of the securities markets and the market for energy-related stocks, as well as general economic and market conditions and other factors that may affect our future results, including those described in this Part I, Item 1A. of this Annual Report on Form 10-K.

Future sales or the availability for sale of substantial amounts of our common stock, or the perception that these sales may occur, could adversely affect the trading price of our common stock and could impair our ability to raise capital through future sales of equity securities.

A significant percentage of our common stock is held by a single investor. In connection with our emergence from bankruptcy protection in 2021, we entered into the Registration Rights Agreement pursuant to which we have agreed to file a registration statement with the SEC to facilitate potential future sales of our common stock by such investors. Sales of a substantial number of shares of our common stock in the public markets, or even the perception that these sales might occur (such as upon the filing of the aforementioned registration statement), could impair our ability to raise capital through a future sale of, or pay for acquisitions using, our equity securities.

We cannot predict the effect that future sales of our common stock will have on the price at which the common stock trades. Sales of substantial amounts of our common stock, or the perception that such sales could occur, may adversely affect the trading price of our common stock.

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Certain of our stockholders own a significant portion of our outstanding equity securities and their interests may not always coincide with the interests of other holders of the common stock.

A large percentage of our equity is held by a relatively small number of investors. As a result, these investors could have significant influence over all matters presented to our stockholders for approval, including election and removal of our directors, change in control transactions and the outcome of all actions requiring majority stockholder approval.

The interests of these investors may not always coincide with the interests of the other holders of the common stock, and the concentration of control in these investors may limit other stockholders' ability to influence corporate matters. The concentration of ownership and voting power of these investors may also delay, defer or even prevent an acquisition by a third -party or other change of control transactions of our Company. This may make some transactions more difficult or impossible without their support, even if such events are in the best interests of our other stockholders. In addition, the concentration of voting power may adversely affect the trading price and liquidity of the common stock.

There may be future dilution of our common stock, which could adversely affect the market price of our common stock.

We are not restricted from issuing additional shares of our common stock. In the future, we may issue shares of our common stock to raise cash for future capital expenditures, acquisitions or for general corporate purposes. We may also issue securities that are convertible into, exchangeable for or that represent the right to receive our common stock. Lastly, we currently issue restricted stock units and performance vesting restricted stock units to certain employees and directors as part of their compensation. Any of these events will dilute our shareholders' ownership interest in Gulfport and may reduce our earnings per share and have an adverse effect on the price of our common stock.

Our amended and restated certificate of incorporation provides, subject to certain exceptions, that the Court of Chancery of the State of Delaware will be the sole and exclusive forum for certain stockholder litigation matters, which could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers, employees or stockholders.

Our amended and restated certificate of incorporation provides, subject to limited exceptions, that the Court of Chancery of the State of Delaware will, to the fullest extent permitted by law, be the sole and exclusive forum for (i) any derivative action or proceeding brought on our behalf; (ii) any action asserting a claim of breach of a fiduciary duty owed by any of our directors or officers to us, our stockholders, our creditors or other constituents; (iii) any action asserting a claim against us, any director or our officers arising pursuant to any provision of the DGCL, our certificate of incorporation or our by-laws; or (iv) any action asserting a claim against us, any director or our officers that is governed by the internal affairs doctrine. This choice of forum provision may limit a stockholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with us or any of our directors or officers or stockholders which may discourage lawsuits with respect to such claims. Alternatively, if a court were to find the choice of forum provision contained in our certificate of incorporation to be inapplicable or unenforceable in an action, we may incur additional costs associated with resolving such action in other jurisdictions, which could have a material adverse effect on our business, financial condition and results of operations.


ITEM 1B.			UNRESOLVED STAFF COMMENTS

None.


ITEM 1C.			CYBERSECURITY

Enterprise Risk Management

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.

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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~~combined ~~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~~endpoints ~~points~~ with End Point Detection and Response solutions. We continue to invest and align advances in technology to strengthen our security posture. ~~This~~During ~~year~~2025, weour ~~implemented~~investment ~~tools~~focused ~~that~~on ~~provide~~continuous ~~additional~~improvement ~~visibility~~in ~~into~~cyber ~~lateral~~detections ~~movement, enhancements~~ for ~~multifactor~~our ~~authentication,~~operations ~~and~~technology ~~patching of servers. Cyber risks and incidents are categorized by severity~~environment, ~~evaluated~~threat ~~for materiality, responded to based on defined incident response playbooks~~ and ~~then~~vulnerability ~~remediated~~management ~~accordingly. We perform organized tabletop exercises to test these practices~~ and ~~identify~~data ~~areas~~loss ~~where opportunities for improvement can occur~~prevention.

WeCyber ~~acknowledge~~risks ~~that—even~~and ~~with~~incidents ~~advanced security tools—we~~ are ~~only~~categorized asby ~~strong~~severity, asevaluated ~~the~~for ~~people~~materiality, ~~that~~responded ~~use~~to ~~our~~based ~~technology.~~on ~~That~~defined isincident ~~why~~response weplaybooks ~~design phishing simulations~~ and ~~require~~then ~~multiple~~remediated ~~security trainings for every employee annually~~accordingly. ~~Our~~We ~~partnerships~~perform ~~with~~organized ~~law~~tabletop ~~enforcement,~~exercises ~~the~~to ~~Oil~~test ~~and~~these ~~Natural~~practices ~~Gas Information Sharing Center~~ and ~~our~~identify ~~third~~areas ~~party~~where ~~partners~~opportunities ~~continually~~for ~~mature~~improvement ~~our cyber program as threats evolve~~exist.

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 training courses 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 to 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

As of December 31, ~~2024~~2025, and for the past five years, we have identified no security incidents or breaches that are material, or likely to be material, to our business strategy, results or financial condition.

Cybersecurity Governance

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.

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Board of Director Oversight

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.


ITEM 2.			PROPERTIES

Information regarding our properties is included in Item 1 and in the Supplemental Information on Oil and Gas Exploration and Production Activities in Note 20 of our consolidated financial statements.


ITEM 3.			LEGAL PROCEEDINGS

The Company is involved in various commercial and regulatory claims, litigation and other legal proceedings that arise in the ordinary course of its business.

While the ultimate outcome of the pending proceedings, disputes or claims, and any resulting impact on us, cannot be predicted with certainty, we believe that none of these matters, if ultimately decided adversely, will have a material adverse effect on our financial condition, cash flows or results of operations.

The information with respect to this Item 3. “Legal Proceedings” is set forth in Note 18 of our consolidated financial statements.


ITEM 4.			MINE SAFETY DISCLOSURES

Not applicable.

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PART II


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

Common Stock

Shares of our common stock are listed on the NYSE under the symbol “GPOR”. See Note 6 of our consolidated financial statements for further discussion of our common stock.

Shareholders

At the close of business on February 1211, ~~2025~~2026, there were approximately 2034,~~947~~358 holders of record of our common stock.

Dividends

During the years ended December 31, ~~2024~~2025, ~~2023~~2024 and ~~2022~~2023, the Company has not paid dividends on our common stock. The declaration and payment of any future common stock dividend will be at the full discretion of the Board of Directors and will depend on our financial results, cash requirements, future prospects and other factors deemed relevant by our Board. Our Credit Facility also requires us to meet certain financial covenants at the time dividend payments are made.

During the years ended December 31, ~~2024~~2025, ~~2023~~2024 and ~~2022~~2023, the Company paid $41.27 million, $4.82 million and $5.4.8 million, respectively, of cash dividends to holders of our preferred stock. During the third quarter of 2025, the Company redeemed its remaining outstanding preferred stock and no cash dividends were paid after September 5, 2025 (the “Redemption Date”).

Issuer Purchases of Equity Securities

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 $1.05 billion and extended through December 31, ~~2025~~2026. 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. As of December 31, ~~2024~~2025, the Company had repurchased 57.64 million shares for $~~584~~920.14 million at a weighted average price of $~~104~~125.8819 per share since the inception of the Repurchase Program.

The following table provides a summary of our common stock repurchase activity for the three months ended December 31, ~~2024~~2025:

Period

Total Number of Shares Purchased(1)

Average Price Paid per Share

Total number of shares purchased as part of publicly announced plans or programs

Approximate maximum dollar value of shares that may yet be purchased under the plans or programs

October 1 - October 31

~~115~~179,~~448~~419

~~146~~183.6693

~~115~~179,~~403~~419

~~129~~681,~~071~~611,000

November 1 - November 30

~~221~~219,~~208~~614

~~169~~209.1446

~~221~~219,~~208~~614

~~441~~635,~~657~~611,000

December 1 - December 31

~~154~~265,~~569~~630

~~166~~210.8283

~~154~~265,~~557~~617

~~415~~579,~~874~~611,000

Total

~~491~~664,~~225~~663

~~163~~203.1311

~~491~~664,~~168~~650

_____________________

(1) We repurchased and canceled 4513 ~~and 12~~ shares of our common stock at a weighted average price of $~~143~~201.6985 ~~and $174.48~~ to satisfy tax withholding requirements incurred upon the vesting of restricted stock unit awards during ~~October and~~ December ~~2024, respectively~~2025.

Recent Sales of Unregistered Securities

None.

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Stock Performance Graph

The following Performance Graph and related information shall not be deemed “soliciting material” or to be “filed” with the Securities and Exchange Commission, nor shall such information be incorporated by reference into any future filings under the Securities Act of 1933 or Securities Exchange Act of 1934, each as amended, except to the extent that the Company specifically incorporates it by reference into such filings.

The performance graph below illustrates changes over the period of May 19, 2021, through December 31, ~~2024~~2025, in cumulative total stockholder return on the common stock as measured against the cumulative total return of the S&P 500 Index and the S&P Oil & Gas Exploration and Production Index. The graph tracks the performance of a $100 investment in our common stock and in each index (with the reinvestment of all dividends for the index securities) from May 19, 2021, to December 31, ~~2024~~2025.


ITEM 6.			[RESERVED]


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

The following discussion and analysis represents management’s perspective of our business, financial condition and overall performance. This information is intended to provide investors with an understanding of our past performance, current financial condition and outlook for the future and should be read in conjunction with “Item 8. “Financial Statements and Supplementary Data” of this report. The following information updates the discussion of Gulfport's financial condition provided in its ~~2023~~2024 Annual Report on Form 10-K filing and compares the results of operations for the year ended December 31, ~~2024~~2025 to the year ended December 31, ~~2023~~2024. Discussions of our results from ~~2022~~2023 to ~~2023~~2024 that are not included in this Form 10-K can be found in “Management's Discussion and Analysis of Financial Condition and Results of Operations” in Part II, Item 7 of our Annual Report on Form 10-K for the year ended December 31, ~~2023~~2024.

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Overview

Gulfport is an independent natural gas-weighted exploration and production company with assets primarily located in the Appalachia and Anadarko basins. Our principal ~~properties~~operations ~~are~~target ~~located in eastern Ohio targeting~~ the Utica and Marcellus ~~and~~formations in ~~central~~eastern ~~Oklahoma~~Ohio ~~targeting~~and the SCOOP Woodford and Springer formations in central Oklahoma. Our strategy is to develop our assets in a safe, environmentally responsible manner, while generating sustainable cash flow, improving margins and operating efficiencies and returning capital to shareholders. To accomplish these goals, we generally allocate capital to projects we believe offer the highest rate of return and we deploy leading drilling and completion techniques and technologies in our development efforts.

Recent Developments

~~Long-Term~~Share ~~Debt~~Repurchase Program and ~~Credit~~Redemption ~~Facility~~of Preferred Stock

InOn ~~September~~August ~~2024~~4, ~~Gulfport Operating purchased approximately 95%~~2025, ~~or $524.3 million of~~ the ~~2026~~Company's ~~Senior~~Board ~~Notes~~of inDirectors aapproved ~~tender~~an ~~offer~~increase ~~using~~to the ~~net~~authorized ~~proceeds~~Repurchase ~~received~~Program from ~~the issuance of~~ $~~650~~1.0 billion ~~million~~to ~~of its 2029 Senior Notes~~$1.5 billion ~~The~~(including ~~net~~the ~~impact~~redemption of ~~these~~preferred ~~transactions~~stock ~~resulted~~noted inbelow) ~~the~~and ~~Company~~extended ~~extending~~ the ~~maturity~~authorization ofthrough ~~substantially~~December ~~all~~31, ~~of the senior notes from~~ 2026 ~~to 2029~~.

~~Additionally,~~On onAugust ~~September 12~~5, ~~2024~~2025, ~~the~~Gulfport ~~Company~~issued ~~entered~~a ~~into~~notice ~~the~~of ~~Commitment~~redemption ~~Increase,~~for ~~Borrowing~~its ~~Base~~preferred ~~Reaffirmation~~stock ~~Agreement,~~for ~~and~~cash. ~~Fourth~~During ~~Amendment~~the toperiod ~~Credit~~between ~~Agreement (~~the ~~“Fourth~~date ~~Amendment”),~~of ~~which~~notice ~~amended~~of the ~~Company’s~~redemption ~~Third Amended~~ and ~~Restated~~the ~~Credit~~Redemption ~~Agreement. The Fourth Amendment~~Date, ~~among other things~~28,907 ~~(a)~~shares ~~increased~~of ~~the~~preferred ~~aggregate~~stock ~~elected~~were ~~commitment~~converted ~~amounts~~into ~~under~~approximately ~~the~~2.1 ~~Credit~~million ~~Facility~~shares toof $1common stock.~~0 billion,~~ ~~(b)~~On ~~reaffirmed~~ the ~~borrowing~~Redemption ~~base~~Date, ~~under~~ the ~~Credit~~Company ~~Facility~~redeemed atthe ~~$1.1 billion~~remaining 2,449 ~~(c)~~shares ~~extended~~of ~~the~~preferred ~~maturity~~stock ~~date~~for ~~under~~cash ~~the~~totaling ~~Credit~~$31.3 million. ~~Facility~~Additionally, todirect ~~September~~transaction-related ~~12,~~costs ~~2028,~~of ~~and~~$1.1 ~~(d)~~million ~~reduced~~were ~~the~~incurred ~~pricing~~as ~~grid~~part 50of ~~bps~~the redemption.

~~Stock~~During the year ended December 31, 2025, the Company repurchased 1.8 million shares for $336.3 million at a weighted average price of $188.65 per share. As of December 31, 2025, the Company repurchased 7.4 million shares for $920.4 million at a weighted average price of $125.19 per share since the inception of the Repurchase Program.

OnCredit November 4, 2024, the Company's Board of Directors approved an increase to the authorized Repurchase Program from $650.0 million to $1.0 billion and extended the authorization through December 31, 2025. During the year ended December 31, 2024, the Company repurchased 1.2 million shares for $184.5 million at a weighted average price of $153.35 per share. As of December 31, 2024, the Company 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.Facility

On October 30, 2025, the Company entered into the Borrowing Base Reaffirmation Agreement and Fifth Amendment to Credit Agreement (the “Fifth Amendment”). The facility provides for a borrowing base of $1.1 billion and aggregate elected commitments of $1.0 billion.

Tariffs and Trading Relationships

In 2025 and 2026, the U.S. government threatened, announced and, in certain cases, rescinded, tariffs on several foreign jurisdictions and imports into the United States, which led, and may continue to lead, to the imposition of retaliatory tariffs and other measures taken by foreign jurisdictions. There is significant uncertainty as to the scope and durability of existing and future tariff measures, as well as the ultimate effects of the tariffs on economic conditions.

One Big Beautiful Bill Act

On July 4, 2025, the President signed into law the legislation commonly referred to as the One Big Beautiful Bill Act (“OBBBA”), which introduces significant changes to U.S. federal tax law. Key provisions of the OBBBA that are relevant to the Company include modifications to the limitations on the deductibility of interest expense under Section 163(j) of the Internal Revenue Code and adjustments to bonus depreciation rules.

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~~2024~~2025 Operational and Financial Highlights

During ~~2024~~2025, we had the following notable achievements:

•Reported total net production of 1,~~054~~039 MMcfe per day.

•Generated $~~650~~803.02 million of operating cash flows.

•Turned to sales 1932 gross operated (1731.8 net) wells.

•~~Expanded~~Redeemed ~~common~~outstanding ~~share~~preferred ~~repurchase~~stock, ~~program~~simplifying toour ~~$1.0~~capital ~~billion~~structure and ~~returned~~eliminating ~~$184.5~~future ~~million~~dividend toobligations ~~shareholders~~on ~~through~~ the ~~repurchase~~preferred ~~of 1~~stock.~~2 million shares at a weighted average price of $153.35 per share.~~

•~~Extended~~Expanded common share repurchase program to $1.5 billion and returned $336.3 million to shareholders through the ~~maturity~~repurchase of ~~substantially~~1.8 ~~all~~million ~~long-term~~shares ~~senior~~(including ~~notes~~the ~~from~~underlying ~~2026~~shares toof ~~2029~~common stock into which the preferred stock was convertible) at a weighted average price of $188.65 per share.

•~~Extended~~Maintained ~~the~~a ~~maturity~~strong ofbalance ~~the~~sheet ~~Credit~~and ~~Facility~~low tofinancial ~~2028~~leverage, ~~and~~exiting ~~increased~~ the ~~available~~year ~~commitments~~with ~~under~~total ~~the~~liquidity ~~Credit~~of ~~Facility by~~ $~~100~~806.1 million.

•~~Exited~~Achieved ~~the~~MIQ ~~year~~certification ~~with~~for ~~total~~all ~~liquidity~~Appalachia ofassets ~~$899.7~~for ~~million~~the third consecutive year.

•~~Achieved~~Reported ~~MIQ~~year-end ~~certification~~estimated ~~for~~net ~~all~~proved ~~Appalachian~~reserves ~~assets~~of ~~for~~4.3 ~~the second consecutive year~~Tcfe.

•Reported year-end estimated net proved reserves of 4.0 Tcfe.

Business and Industry Outlook

The Company's primary focus going into ~~2025~~2026 is its continued attention on reducing cycle times and operating costs to improve margins and ultimately ~~support~~enhance our expected free cash flow generation. ~~We are committed to an emphasis on sustainability and we will continue to prioritize safety, environmental stewardship, and maintaining strong relationships with the communities in which we operate.~~ Throughout the year, we plan to maintain capital discipline, prioritizing free cash flow generation and preserving our strong financial position, while returning capital to shareholders and increasing our resource depth through incremental leasehold opportunities.

In ~~2024~~2025, natural gas prices continued to be volatile as spot prices ranged from $12.2165 to $139.2086 per MMBtu. Henry Hub averaged $23.1952 per MMBtu in ~~2024~~2025 vs $2.5319 per MMBtu in ~~2023~~2024. As we look into ~~2025~~2026, we expect continued volatility in natural gas prices. To mitigate our exposure to commodity market volatility and to help provide a level of certainty around our financial strength, we have entered into a combination of natural gas swaps and collars, representing approximately 4652% of our expected ~~2025~~2026 gas production, at an average floor price of $3.5974 per Mcf.

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Results of Operations

Comparison of the Year Ended December 31, ~~2024~~2025 and ~~2023~~2024

We reported net ~~loss~~income of $~~261~~427.48 million for the year ended December 31, ~~2024~~2025, compared to a net ~~income~~loss of $1261.54 ~~billion~~million for the year ended December 31, ~~2023~~2024. The material changes that led to the ~~decrease~~increase in net ~~loss~~income are further discussed by category on the following pages. Some totals and changes throughout the below section may not sum or recalculate due to rounding.

Natural Gas, Oil and Condensate and NGL Production and Pricing (sales totals in thousands)

	Year Ended December 31, 2024		Year Ended December 31, 2023
	Year Ended December 31, 2025		Year Ended December 31, 2024
Natural gas (MMcf/day)
Utica & Marcellus production volumes	~~810~~777		~~766~~810
SCOOP production volumes	~~157~~150		~~194~~157
Total production volumes	~~968~~927		~~960~~968
Total sales	$	~~714~~1,~~160~~056,429	$	~~831~~714,~~812~~160
Average price without the impact of derivatives ($/Mcf)	$	23.0212	$	2.3702
Impact from settled derivatives ($/Mcf)	$	0.8014	$	0.4280
Average price, including settled derivatives ($/Mcf)	$	23.8226	$	2.7982
Oil and condensate (MBbl/day)
Utica & Marcellus production volumes	25		12
SCOOP production volumes	21		32
Total production volumes	46		4
Total sales	$	~~101~~133,~~589~~644	$	99101,~~854~~589
Average price without the impact of derivatives ($/Bbl)	$	6959.6412	$	7369.2764
Impact from settled derivatives ($/Bbl)	$	04.1104	$	(20.~~53)~~11
Average price, including settled derivatives ($/Bbl)	$	6963.7516	$	7069.7475
NGL (MBbl/day)
Utica & Marcellus production volumes	36		23
SCOOP production volumes	86		108
Total production volumes	1012		1210
Total sales	$	~~112~~133,~~855~~454	$	~~119~~112,~~717~~855
Average price without the impact of derivatives ($/Bbl)	$	29.5630	$	~~27.~~29.56
Impact from settled derivatives ($/Bbl)	$	(0.5607)	$	2(0.0756)
Average price, including settled derivatives ($/Bbl)	$	29.0023	$	29.3600
Total (MMcfe/day)
Utica & Marcellus production volumes	~~842~~841		~~784~~842
SCOOP production volumes	~~212~~197		~~270~~212
Total production volumes	1,~~054~~039		1,054
Total sales	$	~~928~~1,~~604~~323,527	$	1928,~~051,383~~604
Average price without the impact of derivatives ($/Mcfe)	$	23.4149	$	2.7341
Impact from settled derivatives ($/Mcfe)	$	0.7315	$	0.4073
Average price, including settled derivatives ($/Mcfe)	$	3.1464	$	3.1314

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Year Ended December 31, 2024

Year Ended December 31, 2023

% Change

Year Ended December 31, 2025

Year Ended December 31, 2024

% Change

Natural gas

~~714~~1,~~160~~056,429

~~831~~714,~~812~~160

~~(14)~~48

Oil and condensate

~~101~~133,~~589~~644

99101,~~854~~589

232

NGL

~~112~~133,~~855~~454

~~119~~112,~~717~~855

~~(6)~~18

Total natural gas, oil and condensate and NGL sales

~~928~~1,~~604~~323,527

1928,~~051,383~~604

~~(12)~~43

The ~~decrease~~increase in natural gas sales without the impact of derivatives when comparing the year ended December 31, ~~2024~~2025, to the year ended December 31, ~~2023~~2024, was primarily due to a 1555% ~~decrease~~increase in realized natural gas prices, partially offset by a 14% ~~increase~~decrease in sales volumes. The realized price change was primarily driven by the ~~decrease~~increase in the average Henry Hub gas index from $2.7427 per Mcf in the year ended December 31, ~~2023~~2024, to $23.2743 per Mcf during the year ended December 31, ~~2024~~2025. The 14% ~~increase~~decrease in natural gas production was primarily due to natural declines partially offset by our ~~2023~~2024 and ~~2024~~2025 development programs inand the ~~Utica/Marcellus~~impact ~~partially~~of ~~offset~~unplanned, bythird-party ~~natural~~midstream ~~declines~~outages and ~~limited activity in the SCOOP~~constraints.

The increase in oil and condensate sales without the impact of derivatives when comparing the year ended December 31, ~~2024~~2025, to the year ended December 31, ~~2023~~2024, was due to a 755% increase in sales volumes, partially offset by a 515% decrease in realized oil prices. The 755% increase in oil and condensate production was primarily due to commencement of sales on new wells targeting the Utica and Marcellus liquids ~~window~~windows. The realized price change was primarily driven by the decrease in the average WTI crude index from $7775.6272 per barrel in the year ended December 31, ~~2023~~2024, to $7564.7281 per barrel during the year ended December 31, ~~2024~~2025.

The ~~decrease~~increase in NGL sales without the impact of derivatives when comparing the year ended December 31, ~~2024~~2025, to the year ended December 31, ~~2023~~2024, was due to a 1319% ~~decrease~~increase in NGL sales volumes, partially offset by ana 81% ~~increase~~decrease in realized prices. The 1319% ~~decrease~~increase in NGL production was primarily due to ~~natural~~commencement ~~declines~~of ~~and~~sales ~~limited~~on ~~2023~~new ~~development~~wells intargeting the ~~SCOOP.~~Utica ~~The~~and ~~realized~~Marcellus ~~price~~liquids ~~change was primarily driven by the increase in the average Mont Belvieu NGL index from $30~~windows.07 ~~per barrel in the year ended December 31, 2023, to $32.73 per barrel during the year ended December 31, 2024.~~

Natural Gas, Oil and NGL Derivatives (in thousands)

The total natural gas, oil and NGL volumes hedged for the year ended December 31, 2025 and 2024, represented approximately 73% and 80%, respectively, of our total sales volumes for the applicable year.


	Year Ended December 31, 2025		Year Ended December 31, 2024
Natural gas derivatives - fair value gains (losses)	$	39,010	$	(251,019)
Natural gas derivatives - settlement gains	47,705		284,626
Total gains on natural gas derivatives	86,715		33,607

Oil and condensate derivatives - fair value (losses) gains	(3,468)		2,351
Oil and condensate derivatives - settlement gains	9,124		166
Total gains on oil and condensate derivatives	5,656		2,517

NGL derivatives - fair value gains (losses)	7,017		(4,442)
NGL derivatives - settlement losses	(332)		(2,155)
Total gains (losses) on NGL derivatives	6,685		(6,597)

Total gains on natural gas, oil and NGL derivatives	$	99,056	$	29,527

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~~Natural~~We ~~Gas~~recognize fair value changes on our natural gas, ~~Oil~~oil and NGL ~~Derivatives~~derivative (instruments in ~~thousands~~each reporting period. The changes in fair value resulted from new positions and settlements that occurred during each period, as well as the relationship between contract prices and the associated forward curves. The change in the total gain for the year ended December 31, 2025 compared to the year ended December 31, 2024, was primarily the result of changes in futures pricing for oil, natural gas, and NGLs during each period. The net fair value gains of our hedging program totaled $42.6 million for the year ended December 31, 2025 compared to losses of $253.1 million for the year ended December 31, 2024. Settlement gains (losses) in the table above represent realized cash gains or losses to the instruments described in Note 12 of our consolidated financial statements. Our hedging program generated cash receipts of $56.5 million for the year ended December 31, 2025, compared to cash receipts of $282.6 million for the year ended December 31, 2024.

The total natural gas, oil and NGL volumes hedged for the year ended December 31, 2024 and 2023, represented approximately 80% and 95%, respectively, of our total sales volumes for the applicable year.

	Year Ended December 31, 2024		Year Ended December 31, 2023
Natural gas derivatives - fair value (losses) gains	$	(251,019)	$	584,563
Natural gas derivatives - settlement gains	284,626		146,381
Total gains on natural gas derivatives	33,607		730,944
Oil and condensate derivatives - fair value gains	2,351		5,971
Oil and condensate derivatives - settlement gains (losses)	166		(3,272)
Total gains on oil and condensate derivatives	2,517		2,699
NGL derivatives - fair value losses	(4,442)		(2,414)
NGL derivatives - settlement (losses) gains	(2,155)		9,090
Total (losses) gains on NGL derivatives	(6,597)		6,676
Total gains on natural gas, oil and NGL derivatives	$	29,527	$	740,319

We recognize fair value changes on our natural gas, oil and NGL derivative instruments in each reporting period. The changes in fair value resulted from new positions and settlements that occurred during each period, as well as the relationship between contract prices and the associated forward curves. The significant change in the total gain for the year ended December 31, 2024 compared to the year ended December 31, 2023, was primarily the result of changes in futures pricing for oil, natural gas, and NGLs during each period. The fair value losses of our hedging program totaled $253.1 million for the year ended December 31, 2024 compared to gains of $588.1 million for the year ended December 31, 2023. Settlement gains (losses) in the table above represent realized cash gains or losses to the instruments described in Note 12 of our consolidated financial statements. Our hedging program generated cash receipts of $282.6 million for the year ended December 31, 2024, compared to cash receipts of $152.2 million for the year ended December 31, 2023.

Lease Operating Expenses (in thousands, except per unit)

	Year Ended December 31, 2024		Year Ended December 31, 2023		% Change
	Year Ended December 31, 2025		Year Ended December 31, 2024		% Change
Lease operating expenses
Utica & Marcellus	$	4861,~~321~~661	$	4448,~~394~~321	928	%
SCOOP	2122,~~791~~581		2421,~~254~~791		~~(10)~~4	%
Total lease operating expenses	$	7084,~~112~~242	$	6870,~~648~~112	220	%
Lease operating expenses per Mcfe
Utica & Marcellus	$	0.1620	$	0.16	—25	%
SCOOP	0.2831		0.2528		1211	%
Total lease operating expenses per Mcfe	$	0.1822	$	0.18	—22	%

The increase in total LOE and per unit LOE for the year ended December 31, ~~2024~~2025, compared to the year ended December 31, ~~2023~~2024, was primarily the result of ~~increased~~an ~~production~~increase in ~~Utica/Marcellus~~water ashauling, ~~described~~repairs ~~above~~and maintenance and labor expenses in our Utica operations.

Taxes Other Than Income (in thousands, except per unit)


	Year Ended December 31, 2025		Year Ended December 31, 2024		% Change
Production taxes	$	21,408	$	19,385	10	%
Property taxes	5,527		8,174		(32)	%
Other	2,973		2,178		37	%
Total taxes other than income	$	29,908	$	29,737	1	%
Total taxes other than income per Mcfe	$	0.08	$	0.08	—	%

The total and per unit taxes other than income for the year ended December 31, 2025, compared to the year ended December 31, 2024, remained consistent.

Transportation, Gathering, Processing and Compression (in thousands, except per unit)


	Year Ended December 31, 2025		Year Ended December 31, 2024		% Change
Transportation, gathering, processing and compression	$	358,938	$	351,237	2	%
Transportation, gathering, processing and compression per Mcfe	$	0.95	$	0.91	4	%

Transportation, gathering, processing and compression for the year ended December 31, 2025, compared to the year ended December 31, 2024, increased on a total and per unit basis primarily as a result of an increase in the proportion of natural gas liquids and oil and condensate production.

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Taxes Other Than Income (in thousands, except per unit)

	Year Ended December 31, 2024		Year Ended December 31, 2023		% Change
Production taxes	$	19,385	$	25,564	(24)	%
Property taxes	8,174		6,160		33	%
Other	2,178		1,993		9	%
Total taxes other than income	$	29,737	$	33,717	(12)	%
Total taxes other than income per Mcfe	$	0.08	$	0.09	(11)	%

The decrease in total and per unit taxes other than income for the year ended December 31, 2024, compared to the year ended December 31, 2023, was primarily related to a decrease in production taxes resulting from the decrease in our natural gas, oil and NGL revenues excluding the impact of hedges discussed above.

Transportation, Gathering, Processing and Compression (in thousands, except per unit)

	Year Ended December 31, 2024		Year Ended December 31, 2023		% Change
Transportation, gathering, processing and compression	$	351,237	$	348,631	1	%
Transportation, gathering, processing and compression per Mcfe	$	0.91	$	0.91	—	%

Transportation, gathering, processing and compression for the year ended December 31, 2024, compared to the year ended December 31, 2023, increased in total primarily as a result of our small increase in production.

Depreciation, Depletion and Amortization (in thousands, except per unit)

	Year Ended December 31, 2024		Year Ended December 31, 2023		% Change
	Year Ended December 31, 2025		Year Ended December 31, 2024		% Change
Depreciation, depletion and amortization of oil and gas properties	$	~~324~~302,~~078~~024	$	~~318~~324,~~473~~078	2(7)	%
Depreciation, depletion and amortization of other property and equipment	12,~~645~~138		1,~~242~~645		3230	%
Total depreciation, depletion and amortization	$	~~325~~304,~~723~~162	$	~~319~~325,~~715~~723	2(7)	%
Total depreciation, depletion and amortization per Mcfe	$	0.8480	$	0.8384	1(5)	%

~~Depreciation~~The total and per unit depreciation, depletion and amortization of our oil and gas properties for the year ended December 31, ~~2024~~2025, compared to the year ended December 31, ~~2023~~2024, ~~increased~~decreased 2% primarily due to a lower depletion rate resulting from a decline in our amortization base from the ~~result~~full ofcost ceiling test impairments recorded during 2024, combined with a decrease in our ~~drilling~~production. Our production decreased primarily due to natural declines and ~~development~~the ~~activities~~impact ~~during~~of ~~2023~~unplanned, third-party midstream outages and constraints, partially offset by our 2024 and 2025 development programs.

Impairment of Oil and Natural Gas Properties

At September 30, 2024 and December 31, 2024, the net book value of our oil and gas properties exceeded the calculated ceiling. As a result, we recorded a non-cash ceiling test impairment of $30.5 million in the third quarter and $342.7 million in the fourth quarter of 2024. The ~~impairment~~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 12-month average trailing price for natural gas in the third quarter and fourth quarter of 2024 was $2.21 per MMBtu and $2.13 MMBtu, respectively.

AtWe ~~December 31,~~did ~~2024,~~not ~~the~~incur ~~net~~an ~~book~~impairment ~~value~~ of ~~our~~ oil and natural gas properties ~~exceeded~~during ~~the~~any ~~calculated ceiling. As a result, we recorded a non-cash ceiling test impairment of $342.7 million in the fourth~~ quarter ~~of 2024. The impairment 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~~2025. ~~The 12-month average trailing price for natural gas in the fourth quarter of 2024 was $2.13 per MMBtu.~~

General and Administrative Expenses (in thousands, except per unit)


	Year Ended December 31, 2025		Year Ended December 31, 2024		% Change
General and administrative expenses, gross	$	84,004	$	82,478	2	%
Reimbursed from third parties	(16,269)		(14,582)		12	%
Capitalized general and administrative expenses	(25,247)		(25,338)		—	%
General and administrative expenses, net	$	42,488	$	42,558	—	%
General and administrative expenses, net per Mcfe	$	0.11	$	0.11	—	%

The increase in total and per unit general and administrative expenses for the year ended December 31, 2025, compared to the year ended December 31, 2024, was primarily driven by increases in employee compensation and legal expense related to the matters disclosed in Note 18 of our consolidated financial statements.

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Lower natural gas, oil and NGL prices can reduce the value of our 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.

We did not record an impairment during any quarter in 2023.

General and Administrative Expenses (in thousands, except per unit)

	Year Ended December 31, 2024		Year Ended December 31, 2023		% Change
General and administrative expenses, gross	$	82,478	$	75,180	10	%
Reimbursed from third parties	(14,582)		(13,770)		6	%
Capitalized general and administrative expenses	(25,338)		(22,810)		11	%
General and administrative expenses, net	$	42,558	$	38,600	10	%
General and administrative expenses, net per Mcfe	$	0.11	$	0.10	10	%

The increase in total and per unit general and administrative expenses for the year ended December 31, 2024, compared to the year ended December 31, 2023, was primarily driven by increases in employee compensation and headcount.

Restructuring Costs

During the year ended December 31, 2023, Gulfport recognized $4.8 million in personnel-related restructuring expenses associated with changes in the organizational structure and leadership team resulting from the appointment of Gulfport's new CEO in January 2023. Of these expenses, $1.3 million resulted from accelerated vesting of share-based grants, which are non-cash charges. The organizational changes were completed in the second quarter of 2023 and there are no remaining employee termination liabilities associated with these changes.

Interest Expense (in thousands, except per unit)

	Year Ended December 31, 2024		Year Ended December 31, 2023		% Change
	Year Ended December 31, 2025		Year Ended December 31, 2024		% Change
Interest on 2026 Senior Notes	$	~~31,417~~777	$	4431,~~000~~417	(2998)	%
Interest on 2029 Senior Notes	1343,~~163~~875		—13,163		~~100~~233	%
Interest on Credit Facility	149,~~143~~390		1314,~~810~~143		2(34)	%
Amortization of loan costs	45,~~208~~258		34,~~256~~208		2925	%
Capitalized interest	(46,~~771~~154)		(4,~~147~~771)		1529	%
Other	1,~~822~~131		~~150~~1,822		~~1115~~(38)	%
Total interest expense	$	5954,~~982~~277	$	5759,~~069~~982	5(10)	%
Interest expense per Mcfe	$	0.1614	$	0.1516	7(13)	%

~~Due~~Total ~~to the tender offer for the 2026 Senior Notes in the third quarter of 2024 described below,~~ interest ~~paid~~expense ~~on the 2026 Senior Notes decreased 29%~~ for the year ended December 31, ~~2024~~2025, decreased 10% compared to the year ended December 31, ~~2023~~2024. The ~~Company~~decrease ~~also~~was ~~paid~~primarily ~~$13.2~~due ~~million~~to oflower ~~interest~~borrowings onand ~~the~~a ~~2029~~reduced ~~Senior~~interest ~~Notes~~rate ~~for the year ended December 31, 2024. Interest expense~~ on our Credit Facility. ~~increased~~In ~~2% for~~ the ~~year~~third ~~ended~~quarter ~~December 31,~~of 2024, ~~compared~~we toretired the ~~year~~2026 ~~ended~~Senior ~~December 31,~~Notes ~~2023,~~and asissued athe ~~result~~2029 ofSenior ~~a higher average balance outstanding~~Notes. ~~Amortization~~Although ofthe ~~loan~~interest ~~costs~~rate ~~increased~~on ~~29%~~the ~~for~~2029 ~~the~~Senior ~~year~~Notes ~~ended~~is ~~December 31,~~lower ~~2024,~~than ~~compared~~that toof the ~~year~~2026 ~~ended~~Senior ~~December 31~~Notes, ~~2023,~~the ashigher aprincipal ~~result~~balance oflargely offset the ~~Third~~effect ~~Amendment~~of to the ~~Credit~~lower ~~Facility~~interest ~~which~~rate, ~~increased~~resulting ~~the~~in ~~elected~~little ~~commitments~~overall ~~and~~impact ~~borrowing~~on ~~base~~interest ~~and~~expense ~~the~~between ~~Fourth~~periods. ~~Amendment~~We tocapitalized ~~the~~$6.2 ~~Credit~~million ~~Facility~~of ~~which~~interest ~~increased~~during the ~~elected~~period, ~~commitments.~~compared ~~The~~to ~~Company also capitalized~~ $4.8 million ~~and~~in $4the prior year.1 ~~million~~See inNote ~~interest~~4 ~~expense~~of our consolidated financial statements for ~~the~~further ~~years~~details ~~ended~~regarding ~~December 31~~our Credit Facility, ~~2024~~issuance of the 2029 Senior Notes and ~~2023,~~retirement ~~respectively~~of the 2026 Senior Notes.

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Index to Financial Statements

Loss on Debt Extinguishment

In September 2024, Gulfport Operating purchased and retired $524.3 million of the 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.

~~Other,~~Income ~~net (in thousands)~~Taxes

			Year Ended December 31, 2024						Year Ended December 31, 2023						% Change
Other, net			$	7,336					$	(27,982)					(126)		%

On July 4, 2025, the OBBBA, which includes a broad range of tax reform provisions, was signed into law in the United States. We completed our assessment of the OBBBA's provision and incorporated the applicable impacts into our current tax expense and deferred tax assets and liabilities. The provisions did not have a significant effect on the Company’s tax positions for the current period.

~~Other,~~For ~~net in~~ the ~~Company's consolidated statements of operations for the~~ year ended December 31, ~~2024~~2025, ~~included~~our ~~approximately~~effective ~~$4.9 million~~tax ~~related~~rate towas ~~changes~~21.26% inand ~~the~~an ~~Company's~~income ~~legal~~tax ~~reserves~~expense ~~for~~of ~~certain~~$115.5 ~~litigation~~million. ~~and~~For ~~regulatory~~the ~~proceedings.~~year ~~Additionally~~ended December 31, ~~Other~~2024, ~~net~~our ~~included~~effective ~~approximately~~tax $1rate was 17.~~9 million~~66% ~~write-down~~and ofan ~~certain~~income tax benefit of ~~its~~$56.1 ~~pipe~~million. ~~inventory~~See ~~that~~Note ~~the~~10 ~~Company~~of ~~does~~our ~~not~~consolidated ~~expect~~financial tostatements ~~utilize~~for infurther ~~its~~discussion ~~drilling~~of ~~and~~our ~~completion~~income ~~activities~~tax expense.

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.

Income Taxes (in thousands)

For the year ended December 31, 2024, we had an effective tax rate of 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. The higher effective tax rate for the year ended December 31, 2024 is primarily related to the valuation allowance the Company released during the third quarter of 2023. See Note 10 of our consolidated financial statements for further discussion of our income tax benefit.

Liquidity and Capital Resources

Overview. We strive to maintain sufficient liquidity to ensure financial flexibility, withstand commodity price volatility, fund our development projects, operations and capital expenditures and return capital to shareholders. We utilize derivative contracts to reduce the financial impact of commodity price volatility and provide a level of certainty to the Company’s cash flows. We generally fund our operations, planned capital expenditures and any share repurchases with cash flow from our operating activities, cash on hand, and borrowings under our Credit Facility. Additionally, we may access debt and equity markets and sell properties to enhance our liquidity. There is no guarantee that the debt or equity capital markets will be available to us on acceptable terms or at all.

For the year ended December 31, ~~2024~~2025, our primary sources of capital resources and liquidity have consisted of internally generated cash flows from operations and access to the debt markets, and our primary uses of cash have been for development of our oil and natural gas properties, share repurchases, interest payments, dividend payments on our preferred stock and discretionary acreage acquisitions.

We believe our annual free cash flow generation, borrowing capacity under the Credit Facility and cash on hand will provide sufficient liquidity to fund our operations, capital expenditures, interest expense and share repurchases during the next 12 months and the foreseeable future.47

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Index to Financial Statements

To the extent actual operating results, realized commodity prices or uses of cash differ from our assumptions, our liquidity could be adversely affected. See Note 4 of our consolidated financial statements for further discussion of our debt obligations, including principal and carrying amounts of our senior notes.

As of December 31, ~~2024~~2025, we had $1.58 million of cash and cash equivalents compared to $1.95 million as of December 31, ~~2023~~2024, and a net working capital deficit of $~~114~~115.29 million as of December 31, ~~2024~~2025, compared to net working ~~capital~~deficit of $52114.42 million as of December 31, ~~2023~~2024. As of December 31, ~~2024~~2025, our net working capital deficit includes no debt due in the next 12 months. Our total principal amount of funded debt as of December 31, ~~2024~~2025, was $~~713~~797.70 million compared to $~~668~~713.07 million as of December 31, ~~2023~~2024. See Note 4 of our consolidated financial statements for further discussion of our debt obligations, including principal and carrying amounts of our senior notes.

As of February 2019, ~~2025~~2026, we had $32.1 million of cash and cash equivalents, $10219.0 million borrowings under our Credit Facility, $6348.97 million of letters of credit outstanding, ~~$25.7 million of outstanding 2026 Senior Notes~~ and $650.0 million of outstanding 2029 Senior Notes.

Debt. In May ~~2021~~2025, we ~~issued~~redeemed the remaining $25.7 million principal amount of our 8.00% senior unsecured notes due 2026 ~~Senior~~at ~~Notes~~par. ~~The~~As ~~2026~~of ~~Senior~~December ~~Notes~~31, ~~are~~2025, ~~guaranteed~~we onhad a$650.0 million of our 6.75% senior unsecured ~~basis~~notes bydue ~~each~~2029, ofwhich ~~the~~is ~~Company’s~~classified ~~subsidiaries~~as ~~that~~long‑term ~~guarantee~~on our consolidated balance sheet. Based on amounts outstanding at year‑end, anticipated annual cash interest payments on our fixed‑rate debt total approximately $43.9 million. In October 2025, we entered into the Fifth Amendment to our Credit ~~Facility~~Agreement, which reaffirmed the borrowing base at $1.1 Inbillion and maintained elected commitments at $1.0 billion, with a maturity date of September ~~2024~~12, ~~Gulfport~~2028. ~~Operating~~As ~~purchased~~of ~~approximately~~December ~~95%~~31, or2025, we had $~~524~~147.3 0 million of borrowings outstanding, no letters of ~~the~~credit ~~2026~~issued, ~~Senior~~and ~~Notes~~were in acompliance ~~tender~~with ~~offer~~all ~~using~~financial ~~net~~covenants. ~~proceeds~~At ~~received~~year‑end, ~~from~~we ~~the~~had ~~private~~approximately ~~placement~~$804.3 million of availability under the ~~2029~~Credit ~~Senior~~Facility, ~~Notes.~~which ~~This~~remains ~~resulted~~subject into ~~extending~~semi‑annual ~~the~~borrowing ~~maturity~~base ofredeterminations ~~substantially~~based ~~all~~primarily ofon ~~our~~projected ~~senior~~future ~~notes~~cash ~~from~~flows, ~~2026~~with tothe ~~2029.~~next scheduled redetermination occurring in the spring of 2026.

~~Additionally,~~We onmay ~~May~~continue ~~1, 2023, the Company entered into that certain Joinder, Commitment Increase and Borrowing Base Redetermination Agreement, and Third Amendment~~ to ~~Credit~~use ~~Agreement (the “Third Amendment”) which amended the Company’s Credit Facility. The Third Amendment, among other things, (~~a) ~~increased~~combination ~~the~~of ~~aggregate elected commitment amounts under the Credit Facility to $900 million, (b) increased the borrowing base under the Credit Facility to $1.1 billion, (c) increased the excess~~ cash ~~threshold under the Credit Facility to $75 million~~, ~~and~~borrowings ~~(d) extended the maturity date under the Credit Facility from October 14, 2025 to the earlier of (i) May 1, 2027~~ and ~~(ii)~~issuances ~~the 91st day prior to the maturity date~~ of ~~the~~our ~~2026~~common ~~Senior~~stock ~~Notes~~ or ~~any~~ other ~~permitted~~securities ~~senior~~to ~~notes~~retire orour ~~any~~outstanding ~~permitted refinancing~~ debt ~~under~~through ~~the~~privately ~~Credit~~negotiated ~~Facility~~transactions, ~~having~~open anmarket ~~aggregate outstanding principal amount equal to or exceeding $100 million; provided that such notes have not been refinanced~~repurchases, ~~redeemed~~tender oroffers ~~repaid in full on~~ or ~~prior to such 91st day. On April 18~~otherwise, ~~2024,~~but ~~Gulfport~~we ~~completed~~are ~~its semi-annual borrowing base redetermination~~ under ~~its~~no ~~Credit~~obligation ~~Facility~~to ~~during~~do ~~which the borrowing base was reaffirmed at $1~~so.~~1 billion with elected commitments remaining at $900 million.~~

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.

We may continue to use a combination of cash, borrowings and issuances of our common stock or other securities to retire our outstanding debt and preferred stock through privately negotiated transactions, open market repurchases, redemptions, tender offers or otherwise, but we are under no obligation to do so.

See Note 4 of our consolidated financial statements for additional discussion of our outstanding debt.

Dividends on Preferred Stock. As discussed in Note 5 of our consolidated financial statements, holders of preferred stock ~~are~~were 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”). We ~~currently~~had ~~have~~ the option to pay either cash dividends or PIK Dividends on a quarterly basis. On September 5, 2025, the Company redeemed all of its outstanding preferred stock. During the years ended December 31, 2025 and 2024, the Company paid $1.7 million and $4.2 million, respectively, of cash dividends to holders of our preferred stock. No cash dividends were paid after the Redemption Date.

~~During~~Supplemental ~~the~~Guarantor ~~years~~Financial ~~ended~~Information. ~~December 31~~The 2029 Senior Notes are guaranteed on a senior unsecured basis by Gulfport and certain of Gulfport’s wholly owned subsidiaries (collectively, ~~2024~~the “2029 Senior Notes Guarantors” and, ~~2023~~together with the 2026 Senior Notes Guarantors, the ~~Company~~“Guarantors”) ~~paid~~and certain future subsidiaries of Gulfport that become borrowers or guarantors under any credit agreement with an aggregate principal amount outstanding or commitment amount in excess of $~~4.2~~15 million. The 2029 Senior Notes Guarantors are 100% owned by the Parent, and $4the guarantees are full, unconditional, joint and several.8 ~~million~~There are no significant restrictions on the ability of the Parent or the 2029 Senior Notes Guarantors to obtain funds from each other in the form of a dividend or loan. The guarantees rank (i) senior in right of payment to any future subordinated indebtedness of Gulfport Operating or the 2029 Senior Notes Guarantors, ~~respectively~~(ii) pari passu in right of payment with all existing and future unsecured senior indebtedness of Gulfport Operating or the 2029 Senior Notes Guarantors, (iii) effectively junior to any secured indebtedness of ~~cash~~Gulfport ~~dividends~~Operating or the 2029 Senior Notes Guarantors, including indebtedness under the credit agreement, to ~~holders~~the extent of ~~our~~the ~~preferred~~value ~~stock~~of the collateral securing such indebtedness, and (iv) structurally subordinated in right of payment to all indebtedness and other liabilities of Gulfport Operating’s subsidiaries that are not 2029 Senior Notes Guarantors.

4948

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Index to Financial Statements

Supplemental Guarantor Financial Information. The 2026 Senior Notes are guaranteed on a senior unsecured basis by all existing consolidated subsidiaries that guarantee our Credit Facility or certain other debt (the “2026 Senior Notes Guarantors”). The 2026 Senior Notes are not guaranteed by Grizzly Holdings or Mule Sky, LLC. The 2026 Senior Notes Guarantors are 100% owned by the Parent, and the guarantees are full, unconditional, joint and several. There are no significant restrictions on the ability of the Parent or the 2026 Senior Notes Guarantors to obtain funds from each other in the form of a dividend or loan. The guarantees rank equally in the right of payment with all of the senior indebtedness of the subsidiary guarantors and senior in the right of payment to any future subordinated indebtedness of the subsidiary guarantors. The 2026 Senior Notes and the guarantees are effectively subordinated to all of our and the subsidiary guarantors' secured indebtedness (including all borrowings and other obligations under our amended and restated credit agreement) to the extent of the value of the collateral securing such indebtedness, and structurally subordinated to all indebtedness and other liabilities of any of our subsidiaries that do not guarantee the 2026 Senior Notes.

The 2029 Senior Notes are guaranteed on a senior unsecured basis by Gulfport and certain of Gulfport’s wholly owned subsidiaries (collectively, the “2029 Senior Notes Guarantors” and, together with the 2026 Senior Notes Guarantors, the “Guarantors”) and certain future subsidiaries of Gulfport that become borrowers or guarantors under any credit agreement with an aggregate principal amount outstanding or commitment amount in excess of $15 million. The 2029 Senior Notes Guarantors are 100% owned by the Parent, and the guarantees are full, unconditional, joint and several. There are no significant restrictions on the ability of the Parent or the 2029 Senior Notes Guarantors to obtain funds from each other in the form of a dividend or loan. The guarantees rank (i) senior in right of payment to any future subordinated indebtedness of Gulfport Operating or the 2029 Senior Notes Guarantors, (ii) pari passu in right of payment with all existing and future unsecured senior indebtedness of Gulfport Operating or the 2029 Senior Notes Guarantors, (iii) effectively junior to any secured indebtedness of Gulfport Operating or the 2029 Senior Notes Guarantors, including indebtedness under the credit agreement, to the extent of the value of the collateral securing such indebtedness, and (iv) structurally subordinated in right of payment to all indebtedness and other liabilities of Gulfport Operating’s subsidiaries that are not 2029 Senior Notes Guarantors.

SEC Regulation S-X Rule 13-01 requires the presentation of “Summarized Financial Information” to replace the “Condensed Consolidating Financial Information” required under Rule 3-10. Rule 13-01 allows the omission of Summarized Financial Information if assets, liabilities and results of operations of the Guarantors are not materially different than the corresponding amounts presented in our consolidated financial statements. The Parent and Guarantor subsidiaries comprise our material operations. Therefore, we concluded that the presentation of the Summarized Financial Information is not required as our Summarized Financial Information of the Guarantors is not materially different from our consolidated financial statements.

Derivatives and Hedging Activities. Our results of operations and cash flows are impacted by changes in market prices for natural gas, oil and NGL. To mitigate a portion of the exposure to adverse market changes, we have entered into various derivative instruments. Our natural gas, oil and NGL derivative activities, when combined with our sales of natural gas, oil and NGL, allow us to predict with greater certainty the total revenue we will receive. See Item 7A. “Quantitative and Qualitative Disclosures About Market Risk” for further discussion on the impact of commodity price risk on our financial position. Additionally, see Note 12 of our consolidated financial statements for further discussion of derivatives and hedging activities.

Subsequent to December 31, ~~2024~~2025 and as of February 2019, ~~2025~~2026, we entered into the following natural gas, oil, and NGL derivative contracts:

Period	Type of Derivative Instrument	Index	Daily Volume	WeightedAverage Price
Natural Gas			(MMBtu/d)	($/MMBtu)
2025	Swaps	NYMEX Henry Hub	18,301	$3.85
2026	Swaps	NYMEX Henry Hub	36,603	$3.86
2026	Basis Swaps	Rex Zone 3	40,000	$(0.17)
2027	Swaps	NYMEX Henry Hub	40,000	$3.80
2027	Basis Swaps	TETCO M2	50,000	$(0.80)
2027	Basis Swaps	Rex Zone 3	30,000	$(0.22)
2027	Basis Swaps	NGPL TXOK	30,000	$(0.34)
Oil			(Bbl/d)	($/Bbl)
2025	Swaps	NYMEX WTI	1,000	$70.87
2026	Costless Collars	NYMEX WTI	1,125	$55.00 / $71.18
2027	Costless Collars	NYMEX WTI	300	$55.00 / $68.00

50Contractual and Commercial Obligations. The following table sets forth our contractual and commercial obligations at December 31, 2025 (in thousands):

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	Payment due by period
Contractual Obligations	Total		2026		2027-2028		2029-2030		2031 and Thereafter
Long-term debt(1):
Principal	$	797,000	$	—	$	147,000	$	650,000	$	—
Interest	200,084		53,048		103,161		43,875		—
Firm transportation and gathering contracts(2)	1,037,663		138,975		269,992		253,586		375,110
Other operational commitments(3)	16,409		16,409		—		—		—
Operating lease liabilities(4)	571		561		10		—		—
Total contractual cash obligations(5)	$	2,051,727	$	208,993	$	520,163	$	947,461	$	375,110

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Index to Financial Statements

Contractual and Commercial Obligations. The following table sets forth our contractual and commercial obligations at December 31, 2024 (in thousands):

	Payment due by period
Contractual Obligations	Total		2025		2026-2027		2028-2029		2030 and Thereafter
Long-term debt(1):
Principal	$	713,702	$	—	$	25,702	$	688,000	$	—
Interest	220,923		44,481		88,692		87,750		—
Firm transportation and gathering contracts(2)	1,147,946		140,434		270,729		273,366		463,417
Other operational commitments(3)	13,791		13,791		—		—		—
Operating lease liabilities(4)	6,228		5,657		571		—		—
Total contractual cash obligations(5)	$	2,102,590	$	204,363	$	385,694	$	1,049,116	$	463,417

(1) The maturities of our debt obligations and associated interest reflect their original expiration dates and do not reflect any acceleration due to any events of default pertaining to these obligations. See Note 4 of our consolidated financial statements for a description of our long-term debt.

(2) See Note 17 of our consolidated financial statements for further discussion of our firm transportation and gathering commitments.

(3) See Note 17 of our consolidated financial statements for a description of our other operational commitments.

(4) See Note 9 of our consolidated financial statements for a description of our operating lease liabilities.

(5) This table does not include derivative liabilities or the estimated discounted cost for future abandonment of oil and natural gas properties. See Notes 12 and 3 of our consolidated financial statements, respectively.

Off-balance Sheet Arrangements. We may enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. As of December 31, 2024, our material off-balance sheet arrangements and transactions include $63.8 million in letters of credit outstanding against our Credit Facility and $44.9 million in surety bonds issued. Both the letters of credit and surety bonds are being used as financial assurance, primarily for certain firm transportation agreements. Additionally, 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. There are no other transactions, arrangements or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect our liquidity or availability of our capital resources. See Note 17 of our consolidated financial statements for further discussion of the various financial guarantees we have issued. 49

Capital Expenditures. Our capital expenditures have historically been related to the execution of our drilling and completion activities in addition to certain lease acquisition activities. Our capital investment strategy is focused on prudently developing our existing properties to generate sustainable cash flow considering current and forecasted commodity prices. For the year ended December 31, 2024, the Company's incurred capital expenditures totaled $430.1 million, of which $327.4 million related to drilling and completion activities, $57.9 million related to maintenance leasehold and land investment and $44.8 million related to discretionary acreage acquisitions.

Our drilling and completion capital expenditures for 2025 are currently estimated to be in the range of $335 million to $355 million. Also, we currently expect to spend approximately $35 million to $40 million in 2025 for maintenance leasehold and land investment, which is focused on near-term drilling programs and facilitating increases in our working interests and lateral footage in units we plan to drill in 2025, 2026 and 2027. We expect this capital program to result in approximately 1,040 to 1,065 MMcfe per day of production in 2025.

Commodity Price Risk. The volatility of the energy markets makes it extremely difficult to predict future oil and natural gas price movements with any certainty. During 2024, WTI prices ranged from $66.73 to $87.69 per barrel and the Henry Hub spot market price of natural gas ranged from $1.21 to $13.20 per MMBtu. During 2023, WTI prices ranged from $66.61 to $93.67 per barrel and the Henry Hub spot market price of natural gas ranged from $1.74 to $3.78 per MMBtu. If the prices of oil and natural gas decline further, our operations, financial condition and level of expenditures for the development of our oil and natural gas reserves may be materially and adversely affected. In addition, lower oil and natural gas prices may reduce the amount of oil and natural gas that we can produce economically. This may result in our having to make substantial downward adjustments to our estimated proved reserves. If this occurs or if our production estimates change or our exploration or development activities are curtailed, full cost accounting rules may require us to write-down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties. Reductions in commodity prices and/or our reserves could also negatively impact the borrowing base under our revolving credit facility, which could limit our liquidity and ability to fund development activities.

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Index to Financial Statements

~~See~~Off-balance ~~Item~~Sheet 7AArrangements. ~~“Quantitative~~We ~~and~~may ~~Qualitative~~enter ~~Disclosures~~into ~~about~~off-balance ~~Market~~sheet ~~Risk”~~arrangements ~~for~~and ~~further~~transactions ~~information~~that ~~regarding~~can ~~our~~give ~~open~~rise ~~derivative~~to ~~instruments~~material atoff-balance sheet obligations. As of December 31, ~~2024~~2025, our material off-balance sheet arrangements and transactions include $48.7 million in letters of credit outstanding against our Credit Facility and $45.3 million in surety bonds issued. Both the letters of credit and surety bonds are being used as financial assurance, primarily for certain firm transportation agreements. Additionally, the Company entered into various contractual commitments to purchase material and services to be used in future drilling and completion activities. There are no other transactions, arrangements or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect our liquidity or availability of our capital resources. See Note 17 of our consolidated financial statements for further discussion of the various financial guarantees we have issued.

Capital Expenditures. Our capital expenditures have historically been related to the execution of our drilling and completion activities in addition to certain lease acquisition activities. Our capital investment strategy is focused on prudently developing our existing properties to generate sustainable cash flow considering current and forecasted commodity prices. For the year ended December 31, 2025, the Company's incurred capital expenditures totaled $526.1 million related to operated activities, of which $428.4 million related to drilling and completion activities, $34.8 million related to maintenance leasehold and land investment and $62.9 million related to discretionary acreage acquisitions.

Our drilling and completion capital expenditures for 2026 are currently estimated to be in the range of $365 million to $390 million. Also, we currently expect to spend approximately $35 million to $40 million in 2026 for maintenance land and seismic investments, primarily focused on near-term drilling programs and facilitating increases in our working interests and lateral footage in units we plan to drill in 2026, 2027 and 2028. We expect this capital program to result in approximately 1.030 to 1.055 Bcfe per day of production in 2026.

Commodity Price Risk. The volatility of the energy markets makes it extremely difficult to predict future oil and natural gas price movements with any certainty. During 2025, WTI prices ranged from $55.44 to $80.73 per barrel and the Henry Hub spot market price of natural gas ranged from $2.65 to $9.86 per MMBtu. During 2024, WTI prices ranged from $66.73 to $87.69 per barrel and the Henry Hub spot market price of natural gas ranged from $1.21 to $13.20 per MMBtu. If the prices of oil and natural gas continue to be volatile, our operations, financial condition and level of expenditures for the development of our oil and natural gas reserves may be materially and adversely affected. In addition, lower oil and natural gas prices may reduce the amount of oil and natural gas that we can produce economically. This may result in our having to make substantial downward adjustments to our estimated proved reserves. If this occurs or if our production estimates change or our exploration or development activities are curtailed, full cost accounting rules may require us to write-down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties. Reductions in commodity prices and/or our reserves could also negatively impact the borrowing base under our revolving credit facility, which could limit our liquidity and ability to fund development activities.

See Item 7A. “Quantitative and Qualitative Disclosures about Market Risk” for further information regarding our open derivative instruments at December 31, 2025.

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Index to Financial Statements

Sources and Uses of Cash

The following table presents the major changes in cash and cash equivalents for the year ended December 31, ~~2024~~2025 and ~~2023~~2024 (in thousands):

	Year Ended December 31, 2024		Year Ended December 31, 2023
	Year Ended December 31, 2025		Year Ended December 31, 2024
Net cash provided by operating activities	$	~~650~~803,~~033~~193	$	~~723~~650,~~181~~033
Additions to oil and natural gas properties	(~~454~~527,~~098~~569)		(~~537~~454,~~360~~098)
Debt activity, net	3283,~~761~~298		~~(27~~32,~~000)~~761
Debt issuance and loan commitment fees	(~~14,933~~35)		(714,~~068~~933)
Repurchases of common stock	(~~184~~304,~~477~~961)		(~~149~~184,~~165~~477)
Dividends on preferred stock	(4,230)		(4,840)
Redemption of preferred stock	(32,423)		—
Shares exchanged for tax withholdings	(23,614)		(3,207)
Net cash payments on performance vesting restricted stock units	(12,297)		—
Other	(1,898)		129
Dividends on preferred stock	(1,666)		(4,230)
Net change in cash and cash equivalents	$	(456)	$	(5,330)
Shares exchanged for tax withholdings	(5,579)		(23,614)
Cash and cash equivalents at end of period	$	1,473	$	1,929
Other	(1,621)		(1,898)
Net change in cash and cash equivalents	$	340	$	(456)
Cash and cash equivalents at end of period	$	1,813	$	1,473

Net cash provided by operating activities. Net cash provided by operating activities was $~~650~~803.02 million for the year ended December 31, ~~2024~~2025, compared to $~~723~~650.20 million for the year ended December 31, ~~2023~~2024. The ~~decrease~~increase was primarily the result of a ~~decrease~~increase in our natural gas revenues.

Additions to oil and natural gas properties. During the year ended December 31, ~~2024~~2025, we spud 2024 gross (1923.79 net) operated wells and commenced sales from 1630 gross (1530.40 net) operated wells targeting the Utica ~~formation~~and Marcellus formations for a total cost incurred of approximately $~~259~~401.80 million. During the year ended December 31, ~~2024~~2025, we did not spud ~~2 gross~~any ~~(1.8 net)~~ operated wells and commenced sales from 32 gross (21.48 net) operated wells in the SCOOP for a total incurred cost of approximately $6327.85 million. Additionally, the Company incurred $5734.98 million related to maintenance leasehold and land investment and $4462.89 million related to discretionary acreage acquisitions.

Drilling and completion costs discussed above reflect incurred costs while drilling and completion costs presented in the table below reflect cash payments for drilling and completions. Incurred capital expenditures and cash capital expenditures may vary from period to period due to the cash payment cycle. Cash capital expenditures for the year ended December 31, ~~2024~~2025 and ~~2023~~2024, were as follows (in thousands):

	Year Ended December 31, 2024		Year Ended December 31, 2023
	Year Ended December 31, 2025		Year Ended December 31, 2024
Oil and Natural Gas Property Cash Expenditures:
Drilling and completion costs	$	~~325~~404,~~129~~239	$	~~413~~325,~~258~~129
Leasehold acquisitions	~~102~~95,~~630~~610		~~101~~102,~~191~~630
Other	2627,~~339~~720		2226,~~911~~339
Total oil and natural gas property expenditures	$	~~454~~527,~~098~~569	$	~~537~~454,~~360~~098

Debt activity, net. During the year ended December 31, ~~2024~~2025, the Company had $~~956~~1.04 ~~million~~billion and $1.02 billion in borrowings and repayments, respectively, on its Credit Facility. In ~~September~~May ~~2024~~2025, the Company ~~purchased~~redeemed ~~$524.3 million of~~ the ~~2026~~remaining ~~Senior Notes in a tender offer. The retirement of the 2026 Senior Notes resulted in a loss on debt extinguishment of~~ $1325.47 million, ~~which included cash costs of $12.9 million. The Company also issued $650.0 million aggregate~~ principal amount of its ~~6.750%~~2026 ~~senior~~Senior ~~notes~~Notes ~~due~~at ~~2029~~par. As of February 2019, ~~2025~~2026, the Company had $10219.0 million in borrowings outstanding on its Credit Facility.

Debt issuance and loan commitment fees. During the year ended December 31, 2024, the Company incurred $14.9 million of debt issuance and loan commitment fees, related to the issuance of the 2029 Senior Notes and the Fourth Amendment to the Credit Facility. See Note 4 of our consolidated financial statements for further discussion of the long-term debt activity.

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Repurchases of common stock. During the year ended December 31, 2025, the Company repurchased 1.8 million shares for approximately $336.3 million under the Repurchase Program at a weighted average price of $188.65 per share. For the same period in 2024, the Company repurchased 1.2 million shares for $184.5 million at a weighted average price of $153.35 per share.

Redemption of preferred stock. On August 5, 2025, Gulfport issued a notice of redemption for its preferred stock for cash. During the period between the date of the notice of redemption and the Redemption Date, 28,907 shares of preferred stock were converted into approximately 2.1 million shares of common stock. On the Redemption Date, the Company redeemed the remaining 2,449 shares of preferred stock for cash totaling $31.3 million. Additionally, direct transaction-related costs of $1.1 million were incurred as part of the redemption. See Note 5 of our consolidated financial statements for further discussion of the redemption of preferred stock.

Net cash payments on performance vesting restricted stock units. During the year ended December 31, 2025, the Company settled certain performance vesting restricted stock units awards that were granted in 2022 in cash for $12.3 million, as discussed in Note 7 of our consolidated financial statements.

Dividends on preferred stock. During the year ended December 31, 2025, the Company paid $1.7 million of cash dividends to holders of our preferred stock compared to $4.2 million in the year ended December 31, 2024. No cash dividends were paid after the Redemption Date.

Shares exchanged for tax withholdings. During the year ended December 31, 2025, the Company paid $5.6 million of shares exchanged for tax withholdings compared to $23.6 million in the year ended December 31, 2024. The decrease was primarily due to lower aggregate fair value of vested awards as discussed in Note 7 of our consolidated financial statements.

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Debt issuance and loan commitment fees. During the year ended December 31, 2024, the Company incurred debt issuance and loan commitment fees of $14.9 million, as compared to $7.1 million during the year ended December 31, 2023. The increase was primarily related to the issuance of the 2029 Senior Notes and the Fourth Amendment to the Credit Facility. See Note 4 of our consolidated financial statements for further discussion of the long-term debt activity.

Repurchases of common stock. During the year ended December 31, 2024, the Company repurchased 1.2 million shares for approximately $184.5 million under the Repurchase Program at a weighted average price of $153.35 per share. For the same period in 2023, the Company repurchased 1.5 million shares for $148.9 million at a weighted average price of $101.53 per share. As of February 20, 2025, we repurchased 5.6 million shares for approximately $593.2 million under the Repurchase Program at a weighted average price of $105.57 per share.

Dividends on preferred stock. During the year ended December 31, 2024, the Company paid $4.2 million of cash dividends to holders of our preferred stock compared to $4.8 million in the year ended December 31, 2023.

Shares exchanged for tax withholdings. During the year ended December 31, 2024, the Company paid $23.6 million of shares exchanged for tax withholdings compared to $3.2 million in the year ended December 31, 2023. The increase in shares traded for taxes was primarily due to the vesting of certain PSU awards as discussed in Note 7 of our consolidated financial statements.

Other. During the year ended December 31, 2024, the Company incurred other expenses of $1.9 million, as compared to other income of $0.1 million paid during the year ended December 31, 2023. The change was primarily related to proceeds from sales of oil and gas properties of $2.6 million during the year ended December 31, 2023.

Critical Accounting Policies and Estimates

The preparation of financial statements in accordance with accounting principles generally accepted in the United States require us to make estimates and assumptions. The accounting estimates and assumptions we consider to be most significant to our financial statements are discussed below. Our management has discussed each critical accounting estimate with the Audit Committee of our Board of Directors.

Oil and Natural Gas Properties. We use the full cost method of accounting for oil and natural gas operations. Accordingly, all costs, including non-productive costs and certain general and administrative costs directly associated with acquisition, exploration and development of oil and natural gas properties, are capitalized.

Under the full cost method, capitalized costs are amortized on a composite unit-of-production method based on proved oil and natural gas reserves. If we maintain the same level of production year over year, the depreciation, depletion and amortization expense may be significantly different if our estimate of remaining reserves or future development costs changes significantly.

We review the carrying value of our oil and natural gas properties under the full cost method of accounting prescribed by the SEC on a quarterly basis. This quarterly review is referred to as a ceiling test.

Two primary factors impacting this test are reserve estimates and the unweighted arithmetic average of the prices on the first day of each month within the 12-month period ended December 31, ~~2024~~2025. Downward revisions to estimates of oil and natural gas reserves and/or unfavorable prices can have a material impact on the present value of estimated future net revenues. Any excess of the net book value, less deferred income taxes, is generally written off as an expense. ~~During~~The ~~2024, the~~ Company ~~recognized ceiling test impairments of $373.2 million and~~ did not record an impairment of its oil and natural gas properties for the year ended December 31, ~~2023~~2025 and recognized ceiling test impairments of $373.2 million during 2024. See Oil and Natural Gas Properties in Note 1 of our consolidated financial statements for further information on the full cost method of accounting.

Oil, Natural Gas and NGL Reserves. Estimates of oil and natural gas reserves and their values, future production rates, future development costs and commodity pricing differentials are the most significant of our estimates. The accuracy of any reserve estimate is a function of the quality of data available and of engineering and geological interpretation and judgment. In addition, estimates of reserves may be revised based on actual production, results of subsequent exploration and development activities, recent commodity prices, operating costs and other factors. These revisions could materially affect our financial statements. The volatility of commodity prices results in increased uncertainty inherent in these estimates and assumptions. Changes in natural gas, oil or NGL prices could result in actual results differing significantly from our estimates. See Note 20 of our consolidated financial statements for further information.

Income Taxes. We use the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (1) temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities and (2) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income during the period the rate change is enacted. Deferred tax assets are recognized in the year in which realization becomes determinable. 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 that 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 that it is more likely than not that a portion of the Company's federal and state deferred tax assets will be utilized.

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

Derivative Instruments. We seek to reduce our exposure to unfavorable changes in natural gas, oil and NGL prices, which are subject to significant and often volatile fluctuation, by entering into over-the-counter fixed price swaps, basis swaps, costless collars and various types of option contracts. All derivative instruments are recognized as assets or liabilities in the balance sheet, measured at fair value. We estimate the fair value of all derivative instruments using industry-standard models that considered various assumptions including current market and contractual prices for the underlying instruments, implied volatility, time value, nonperformance risk, as well as other relevant economic measures.

The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and the resulting designation. Our current commodity derivative instruments are not designated as hedges for accounting purposes. Accordingly, the changes in fair value are recognized in the consolidated statements of operations in the period of change. Gains and losses on derivatives are included in cash flows from operating activities.


ITEM 7A.			QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Natural Gas, Oil and Natural Gas Liquids Derivative Instruments. Our results of operations and cash flows are impacted by changes in market prices for natural gas, oil and NGL. To mitigate a portion of our exposure to adverse price changes, we have entered into various derivative instruments. Our natural gas, oil and NGL derivative activities, when combined with our sales of natural gas, oil and NGL, allow us to predict with greater certainty the revenue we will receive. We believe our derivative instruments continue to be highly effective in achieving our risk management objectives.

Our general strategy for protecting short-term cash flow and attempting to mitigate exposure to adverse natural gas, oil and NGL price changes is to hedge into strengthening natural gas, oil and NGL futures markets when prices reach levels that management believes provide reasonable risk-adjusted rates of return and protect the financial position of the Company. Information we consider in forming an opinion about future prices includes general economic conditions, industrial output levels and expectations, producer breakeven cost structures, liquefied natural gas trends, oil and natural gas storage inventory levels, industry decline rates for base production and weather trends. Executive management is involved in all risk management activities and the Board of Directors reviews our derivative program at its quarterly board meetings.

We use derivative instruments to achieve our risk management objectives, including swaps, options and costless collars. All of these are described in more detail below. We typically use swaps for a large portion of the oil and natural gas price risk we hedge. We have also sold calls in the past to take advantage of premiums associated with market price volatility.

We determine the notional volume potentially subject to derivative contracts by reviewing our overall estimated future production levels, which are derived from extensive examination of existing producing reserve estimates and estimates of estimated production from new drilling. Production forecasts are updated at least monthly and adjusted if necessary to actual results and activity levels. We do not enter into derivative contracts for volumes in excess of our share of forecasted production. The actual fixed prices on our derivative instruments is derived from the reference prices from third-party indices such as NYMEX. All of our commodity derivative instruments are net settled based on the difference between the fixed price as stated in the contract and the floating price, resulting in a net amount due to or from the counterparty.

We review our derivative positions continuously and if future market conditions change and prices are at levels we believe could jeopardize the effectiveness of a position, we mitigate this risk by either negotiating a cash settlement with our counterparty, restructuring the position or entering a new trade that effectively reverses the current position. The factors we consider in closing or restructuring a position before the settlement date are consistent with those we review when deciding to enter the original derivative position.

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Our general strategy for protecting short-term cash flow and attempting to mitigate exposure to adverse natural gas, oil and NGL price changes is to hedge into strengthening natural gas, oil and NGL futures markets when prices reach levels that management believes provide reasonable rates of return on our invested capital. Information we consider in forming an opinion about future prices includes general economic conditions, industrial output levels and expectations, producer breakeven cost structures, liquefied natural gas trends, oil and natural gas storage inventory levels, industry decline rates for base production and weather trends. Executive management is involved in all risk management activities and the Board of Directors reviews our derivative program at its quarterly board meetings.

We determine the notional volume potentially subject to derivative contracts by reviewing our overall estimated future production levels, which are derived from extensive examination of existing producing reserve estimates and estimates of estimated production from new drilling. Production forecasts are updated at least monthly and adjusted if necessary to actual results and activity levels. We do not enter into derivative contracts for volumes in excess of our share of forecasted production, and if production estimates were lowered for future periods and derivative instruments are already executed for some volume above the new production forecasts, the positions are typically reversed. The actual fixed prices on our derivative instruments is derived from the reference prices from third-party indices such as NYMEX. All of our commodity derivative instruments are net settled based on the difference between the fixed price as stated in the contract and the floating-price, resulting in a net amount due to or from the counterparty.

We review our derivative positions continuously and if future market conditions change and prices are at levels we believe could jeopardize the effectiveness of a position, we will mitigate this risk by either negotiating a cash settlement with our counterparty, restructuring the position or entering a new trade that effectively reverses the current position. The factors we consider in closing or restructuring a position before the settlement date are identical to those we review when deciding to enter the original derivative position.

We have determined the fair value of our derivative instruments utilizing established index prices, volatility curves, discount factors and option pricing models. These estimates are compared to counterparty valuations for reasonableness. Derivative transactions are also subject to the risk that counterparties will be unable to meet their obligations. This non-performance risk is considered in the valuation of our derivative instruments, but to date has not had a material impact on the values of our derivatives. The values we report in our financial statements are as of a point in time and subsequently change as these estimates are revised to reflect actual results, changes in market conditions and other factors. See Note 15 of our consolidated financial statements for further discussion of the fair value measurements associated with our derivatives.

As of December 31, ~~2024~~2025, our natural gas, oil, and NGL derivative instruments consisted of the following types of instruments:

•Swaps: We receive a fixed price and pay a floating market price to the counterparty for the hedged commodity. ~~In exchange for higher fixed prices on certain of our swap trades, we may sell call options.~~

•Basis Swaps: These instruments are arrangements that guarantee a fixed price differential to NYMEX from a specified delivery point. We receive the fixed price differential and pay the floating market price differential to the counterparty for the hedged commodity.

•Costless Collars: Each two-way price collar has a set floor and ceiling price for the hedged production. If the applicable monthly price indices are outside of the ranges set by the floor and ceiling prices in the various collars, the Company will cash-settle the difference with the counterparty.

~~•Call~~Our ~~Options:~~hedge Wearrangements ~~sell,~~may ~~and~~expose ~~occasionally~~us ~~buy,~~to ~~call~~risk ~~options~~of financial loss in ~~exchange~~certain ~~for~~circumstances, aincluding ~~premium~~instances where production is less than expected or commodity prices increase. At ~~the~~December 31, ~~time~~2025, we had a net asset derivative position of ~~settlement~~$29.7 million, ifcompared ~~the~~to ~~market~~a ~~price~~net ~~exceeds~~liability ~~the~~derivative ~~fixed~~position ~~price~~of $12.9 million as of ~~the~~December 31, ~~call~~2024. ~~option~~Utilizing actual derivative contractual volumes, wea ~~pay~~10% ~~the~~increase ~~counterparty~~in ~~the~~underlying ~~excess~~commodity onprices ~~sold~~would ~~call~~have ~~options~~decreased our asset by approximately $80.9 million, ~~and~~while wea 10% decrease in underlying commodity prices would ~~receive~~have ~~the~~increased ~~excess~~our onasset ~~bought~~by ~~call~~approximately ~~options~~$80.9 Ifmillion. ~~the~~However, ~~market~~any ~~price~~realized ~~settles~~derivative ~~below~~gain or loss would be substantially offset by a decrease or increase, respectively, in the ~~fixed~~actual ~~price~~sales value of production covered by the ~~call~~derivative ~~option~~instrument. For more information regarding the Company's commodity derivative transactions, norefer ~~payment~~to isNote ~~due~~12 ~~from~~of ~~either~~our ~~party~~consolidated financial statements.

Counterparty Credit Risk. The Company routinely monitors and manages its exposure to counterparty risk related to derivative contracts by requiring specific minimum credit standards for all counterparties, actively monitoring counterparties public credit ratings, and avoiding concentration of credit exposure by transacting with multiple counterparties. The Company's commodity derivative contract counterparties are typically financial institutions with investment-grade credit ratings. The Company enters into International Swap Dealers Association Master Agreements (“ISDA”) with each of its derivative counterparties prior to executing derivative contracts. The terms of the ISDA provide, among other things, the Company and the counterparties with rights of set-off upon the occurrence of defined acts of default by either the Company or counterparty to a derivative contract.

Interest Rate Risk. Our Credit Facility is structured under floating rate terms, as advances under these facilities may be in the form of either base rate loans or term benchmark loans. As such, our interest expense is sensitive to fluctuations in the prime rates in the United States or, if the term benchmark rates are elected, the term benchmark rates. At December 31, 2025, we had $147.0 million in borrowings outstanding under our Credit Facility which bore interest at the weighted average rate of 6.53% for the year ended December 31, 2025. A 1% increase in the average interest rate would increase interest expense by approximately $1.5 million based on outstanding borrowings under our Credit Facility at December 31, 2025. As of December 31, 2025, we did not have any interest rate swaps to hedge our interest risks.

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Index to Financial Statements

Our hedge arrangements may expose us to risk of financial loss in certain circumstances, including instances where production is less than expected or commodity prices increase. At December 31, 2024, we had a net liability derivative position of $12.9 million, compared to a net asset derivative position of $240.2 million as of December 31, 2023. Utilizing actual derivative contractual volumes, a 10% increase in underlying commodity prices would have increased our liability by approximately $82.3 million, while a 10% decrease in underlying commodity prices would have decreased our liability by approximately $81.8 million. However, any realized derivative gain or loss would be substantially offset by a decrease or increase, respectively, in the actual sales value of production covered by the derivative instrument. For more information regarding the Company's commodity derivative transactions, refer to Note 12 of our consolidated financial statements.

Interest Rate Risk. Our Credit Facility is structured under floating rate terms, as advances under these facilities may be in the form of either base rate loans or term benchmark loans. As such, our interest expense is sensitive to fluctuations in the prime rates in the United States or, if the term benchmark rates are elected, the term benchmark rates. At December 31, 2024, we had $38.0 million in borrowings outstanding under our Credit Facility which bore interest at the weighted average rate of 8.23% for the year ended December 31, 2024. A 1% increase in the average interest rate would increase interest expense by approximately $0.4 million based on outstanding borrowings under our Credit Facility at December 31, 2024. As of December 31, 2024, we did not have any interest rate swaps to hedge our interest risks.

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ITEM 8.			FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO FINANCIAL STATEMENTS

						Page
Report of Independent Registered Public Accounting Firm (PCAOB ID Number 248)						5857
Consolidated Balance Sheets						6059
Consolidated Statements of Operations						6160
Consolidated Statements of Stockholders' Equity						6261
Consolidated Statements of Cash Flows						6362
Notes to Consolidated Financial Statements						6463
1. Summary of Significant Accounting Policies						6463
2. Segment Information						6967
3. Property and Equipment						7068
4. Long-Term Debt						7170
5. Mezzanine Equity						7471
6. Equity						7572
7. Stock-Based Compensation						7673
8. Revenue From Contracts With Customers						7875
9. Leases						7976
10. Income Taxes						8077
11. Earnings Per Share						8279
12. Derivative Instruments						8279
13. Restructuring Costs						8682
14. Investments						8682
15. Fair Value Measurements						8683
16. Related Party Transactions						8884
17. Commitments						8884
18. Contingencies						8986
19. Subsequent Events						9188
20. Supplemental Information On Oil And Gas Exploration And Production Activities (Unaudited)						9188

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Report of Independent Registered Public Accounting Firm

Board of Directors and Stockholders

Gulfport Energy Corporation

Opinion on the financial statements

We have audited the accompanying consolidated balance sheets of Gulfport Energy Corporation (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, ~~2024~~2025 and ~~2023~~2024, the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, ~~2024~~2025, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, ~~2024~~2025 and ~~2023~~2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, ~~2024~~2025, in conformity with accounting principles generally accepted in the United States of America.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Company’s internal control over financial reporting as of December 31, ~~2024~~2025, based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”), and our report dated February 2625, ~~2025~~2026 expressed an unqualified opinion.

Basis for opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical audit matter

The critical audit matter communicated below is a matter arising from the current period audit of the ~~consolidated~~ financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

~~Depletion~~Depreciation, ~~depreciation~~depletion and amortization expense and potential impairment of oil and natural gas properties impacted by the Company’s estimation of proved reserves

As described further in Note 1 and Note 3 to the consolidated financial statements, the Company uses the full cost method of accounting for oil and natural gas ~~operations~~properties. This accounting method requires management to make estimates of proved reserves and related future net cash flows to compute and record depreciation, depletion, ~~depreciation~~ and amortization, as well as to assess potential impairment of oil and natural gas properties (the full cost ceiling test). To estimate the volume of proved oil and natural gas reserve quantities, management makes significant estimates and assumptions including forecasting the production decline rate of producing properties and forecasting the ~~timing and~~ volume of production associated with the Company’s development plan for proved undeveloped properties. In addition, the estimation of proved reserves is also impacted by management’s judgments and estimates regarding the financial performance of wells associated with those proved reserves to determine if wells are expected to be economical under the appropriate pricing assumptions that are required in the estimation of ~~depletion,~~proved ~~depreciation and amortization expense and assessment of potential impairment~~reserves. We ~~identified the estimation of proved reserves as it relates to the~~

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identified the estimation of proved reserves as it relates to the recognition of depreciation, depletion, ~~depreciation~~ and amortization expense and the assessment of potential impairment as a critical audit matter.

The principal consideration for our determination that the estimation of proved reserves is a critical audit matter isin that relatively minor changes in certain inputs and assumptions that are necessary to estimate the volume and future cash flows of the Company’s proved reserves could have a significant impact on the measurement of depreciation, depletion, ~~depreciation~~ and amortization expense and the assessment of potential impairment. In turn, auditing those inputs and assumptions required subjective and complex auditor judgment.

Our audit procedures related to the estimation of proved reserves included the following, among others:

•Tested the design and operating effectiveness of internal controls relating to management’s estimation of proved reserves for the purpose of estimating depreciation, depletion, ~~depreciation~~ and amortization expense and assessment of potential impairment for the Company’s oil and natural gas properties.

•Evaluated the independence, objectivity, and professional qualifications of the ~~Company’s reserves specialist~~specialists, made inquiries of those reservoir engineers regarding the process followed and judgments made to estimate the Company’s proved reserve volumes and read the report prepared by the Company’s third-party reserve specialist.

•Evaluated ~~sensitive~~significant inputs and assumptions used to determine proved reserve volumes and other cash flow inputs and assumptions ~~that are derived from the Company’s accounting records~~, such as historical production, historical pricing differentials, operating costs, estimated future development ~~costs~~cost, and ownership interest for reasonableness. We tested management’s process for determining the assumptions, including examining the underlying support, on a sample basis where applicable. Specifically, our audit procedures involved testing management’s assumptions as follows:

◦Compared the estimated pricing differentials used in the reserve report to realized prices related to revenue transactions recorded in the current year;

◦Tested the ~~model used to~~ estimate ~~the~~of operating costs on a disaggregated basis at year -end and compared to historical operating costs;

◦Tested the model used to determine the future development costs and compared and estimated future development costs used in the reserve report to amounts expended for recently drilled and completed wells, where applicable;

◦Tested the working and net revenue ~~interests~~interest used in the reserve report by inspecting land and division order records;

◦Assessed forecasted production estimated by (i) comparing prior year forecasted production amounts to current year actual results and (ii) comparing forecasted production amounts in the current year reserve report to the actual historical production amounts in the current year, in total and for a sample of individual wells;

◦Evaluated the Company’s evidence supporting the proved undeveloped properties reflected in the reserve report by examining historical conversion rates and support for the Company’s ability to fund and intent to develop the proved undeveloped properties; and

◦Applied analytical procedures to the reserve report by comparing to historical actual results and to the prior year’s reserve report.

/s/ GRANT THORNTON LLP

We have served as the Company's auditor since 2005.

Oklahoma City, Oklahoma

February 2625, ~~2025~~2026

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GULFPORT ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS

(In thousands)

	December 31, 2024		December 31, 2023
	December 31, 2025		December 31, 2024
Assets
Current assets:
Cash and cash equivalents	$	1,~~473~~813	$	1,~~929~~473
Accounts receivable—oil, natural gas, and natural gas liquids sales	~~155~~184,~~942~~649		~~122~~155,~~479~~942
Accounts receivable—joint interest and other	89,~~727~~282		228,~~221~~727
Prepaid expenses and other current assets	7,~~086~~952		167,~~951~~086
Short-term derivative instruments	5845,~~085~~155		~~233~~58,~~226~~085
Total current assets	~~231~~248,~~313~~851		~~396~~231,~~806~~313
Property and equipment:
Oil and natural gas properties, full-cost method
Proved oil and natural gas properties	3,~~349~~902,~~805~~539		23,~~904~~349,~~519~~805
Unproved properties	~~221~~232,~~650~~959		~~204~~221,~~233~~650
Other property and equipment	1113,~~291~~008		911,~~165~~291
Total property and equipment	34,~~582~~148,~~746~~506		3,~~117~~582,~~917~~746
Less: accumulated depletion, depreciation, amortization and impairment	(1,~~564~~868,~~475~~481)		(~~865~~1,~~618~~564,475)
Total property and equipment, net	2,~~018~~280,~~271~~025		2,~~252~~018,~~299~~271
Other assets:
Long-term derivative instruments	615,~~003~~303		476,~~566~~003
Deferred tax asset	~~581~~465,~~233~~738		~~525~~581,~~156~~233
Operating lease assets	~~6,099~~561		146,~~299~~099
Other assets	2219,~~778~~062		3122,~~487~~778
Total other assets	~~616~~500,~~113~~664		~~618~~616,~~508~~113
Total assets	$	23,~~865~~029,~~697~~540	$	32,~~267~~865,~~613~~697
Liabilities, Mezzanine Equity and Stockholders’ Equity
Current liabilities:
Accounts payable and accrued liabilities	$	~~298~~342,~~081~~382	$	~~309~~298,~~532~~081
Short-term derivative instruments	4121,~~889~~865		2141,~~963~~889
Current portion of operating lease liabilities	~~5,538~~550		125,~~959~~538
Total current liabilities	~~345~~364,~~508~~797		~~344~~345,~~454~~508
Non-current liabilities:
Long-term derivative instruments	358,~~081~~916		1835,~~602~~081
Asset retirement obligation	32,~~949~~912		2932,~~941~~949
Non-current operating lease liabilities	~~561~~10		~~1,340~~561
Long-term debt	~~702~~788,~~857~~187		~~667~~702,~~382~~857
Total non-current liabilities	~~771~~830,~~448~~025		~~717~~771,~~265~~448
Total liabilities	1,~~116~~194,~~956~~822		1,~~061~~116,~~719~~956
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
Preferred stock - $0.0001 par value, 110.0 thousand shares authorized, 0 issued and outstanding at December 31, 2025, and 37.3 thousand issued and outstanding at December 31, 2024	—		37,348
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
Common stock - $0.0001 par value, 42.0 million shares authorized, 18.8 million issued and outstanding at December 31, 2025, and 17.8 million issued and outstanding at December 31, 2024	2		2
Additional paid-in capital	~~129,059~~—		~~315~~129,~~726~~059
Common stock held in reserve, 0 shares at December 31, 2024, and 62.0 thousand shares at December 31, 2023	—		(1,996)
Retained earnings	1,834,716		1,582,332
Retained earnings	1,582,332		1,847,948
Total stockholders’ equity	1,834,718		1,711,393
Total stockholders’ equity	1,711,393		2,161,680
Total liabilities, mezzanine equity and stockholders’ equity	$	3,029,540	$	2,865,697
Total liabilities, mezzanine equity and stockholders’ equity	$	2,865,697	$	3,267,613

See accompanying notes to consolidated financial statements.

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GULFPORT ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands)

	Year Ended December 31, 2024		Year Ended December 31, 2023		Year Ended December 31, 2022
	Year Ended December 31, 2025		Year Ended December 31, 2024		Year Ended December 31, 2023
REVENUES:
Natural gas sales	$	~~714~~1,~~160~~056,429	$	~~831~~714,~~812~~160	$	1831,~~998,452~~812
Oil and condensate sales	~~101~~133,~~589~~644		99101,~~854~~589		~~147~~99,~~444~~854
Natural gas liquid sales	~~112~~133,~~855~~454		~~119~~112,~~717~~855		~~184~~119,~~963~~717
Net gain (loss) on natural gas, oil and NGL derivatives	29,527		740,319		(999,747)
Net gain on natural gas, oil and NGL derivatives	99,056		29,527		740,319
Total revenues	~~958~~1,~~131~~422,583		1958,~~791,702~~131		1,~~331~~791,~~112~~702
OPERATING EXPENSES:
Lease operating expenses	7084,~~112~~242		6870,~~648~~112		6468,~~790~~648
Taxes other than income	29,~~737~~908		3329,~~717~~737		6033,~~139~~717
Transportation, gathering, processing and compression	~~351~~358,~~237~~938		~~348~~351,~~631~~237		~~357~~348,~~246~~631
Depreciation, depletion and amortization	~~325~~304,~~723~~162		~~319~~325,~~715~~723		~~267~~319,~~761~~715
Impairment of oil and natural gas properties	~~373,214~~—		—373,214		—
General and administrative expenses	42,~~558~~488		3842,~~600~~558		3538,~~304~~600
Restructuring costs	—		~~4,762~~—		—4,762
Accretion expense	2,~~307~~421		2,~~782~~307		2,~~746~~782
Total operating expenses	1822,~~194,888~~159		~~816~~1,~~855~~194,888		~~787~~816,~~986~~855
(LOSS) INCOME FROM OPERATIONS	(236,757)		974,847		543,126
INCOME (LOSS) FROM OPERATIONS	600,424		(236,757)		974,847
OTHER EXPENSE (INCOME):
Interest expense	5954,~~982~~277		5759,~~069~~982		5957,~~773~~069
Loss on debt extinguishment	~~13,388~~—		—13,388		—
Other, net	72,~~336~~842		~~(27~~7,~~982)~~336		(1127,~~348~~982)
Total other expense	8057,~~706~~119		2980,~~087~~706		4829,~~425~~087
(LOSS) INCOME BEFORE INCOME TAXES	(317,463)		945,760		494,701
INCOME (LOSS) BEFORE INCOME TAXES	543,305		(317,463)		945,760
INCOME TAX BENEFIT:
INCOME TAX EXPENSE (BENEFIT):
Current	—		—		—
Deferred	~~(56~~115,~~077)~~495		(~~525~~56,~~156~~077)		—(525,156)
Total income tax benefit	(56,077)		(525,156)		—
Total income tax expense (benefit)	115,495		(56,077)		(525,156)
NET (LOSS) INCOME	(261,386)		1,470,916		494,701
NET INCOME (LOSS)	427,810		(261,386)		1,470,916
Dividends on preferred stock	(41,~~230~~666)		(4,~~840~~230)		(54,~~444~~840)
Participating securities - preferred stock	—		(212,360)		(76,401)
Deemed dividend on preferred stock	(29,986)		—		—
NET (LOSS) INCOME ATTRIBUTABLE TO COMMON STOCKHOLDERS	$	(265,616)	$	1,253,716	$	412,856
Participating securities - preferred stock	—		—		(212,360)
NET (LOSS) INCOME PER COMMON SHARE:
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCKHOLDERS	$	396,158	$	(265,616)	$	1,253,716
Basic	$	(14.72)	$	67.24	$	20.45
NET INCOME (LOSS) PER COMMON SHARE:
Diluted	$	(14.72)	$	66.46	$	20.32
Basic	$	21.74	$	(14.72)	$	67.24
Weighted average common shares outstanding—Basic	18,050		18,645		20,185
Diluted	$	21.48	$	(14.72)	$	66.46
Weighted average common shares outstanding—Diluted	18,050		18,902		20,347
Weighted average common shares outstanding—Basic	18,223		18,050		18,645
Weighted average common shares outstanding—Diluted	18,440		18,050		18,902

See accompanying notes to consolidated financial statements.

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GULFPORT ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(In thousands)

	Common Stock			Common Stock Held in Reserve			Treasury Stock		Paid-inCapital		Retained Earnings ~~(AccumulatedDeficit)~~		Total Stockholders’Equity
	Shares	Amount		Shares	Amount
Balance at January 1, 2022	21,537	$	2	(938)	$	(30,216)	$	—	$	692,521	$	(112,829)	549,478
Balance at January 1, 2023	19,097	$	2	(62)	$	(1,996)	$	(286)	$	449,243	$	381,872	828,835
Net income	—	—		—	—		—		—		494,701		494,701
Conversion of preferred stock	407	—		—	—		—		5,601		—		5,601
Stock compensation	—	—		—	—		—		8,670		—		8,670
Repurchase of common stock under Repurchase Program	(2,896)	—		—	—		(286)		(250,482)		—		(250,768)
Issuance of common stock held in reserve	—	—		876	28,220		—		—		—		28,220
Issuance of common stock upon vesting of share-based awards	68	—		—	—		—		—		—		—
Common stock withheld for income taxes on share-based awards	(19)	—		—	—		—		(1,623)		—		(1,623)
Dividends on preferred stock	—	—		—	—		—		(5,444)		—		(5,444)
Balance at December 31, 2022	19,097	$	2	(62)	$	(1,996)	$	(286)	$	449,243	$	381,872	$	828,835
Net income	—	—		—	—		—		—		1,470,916		1,470,916
Conversion of preferred stock	593	—		—	—		—		8,081		—		8,081
Stock compensation	—	—		—	—		—		13,525		—		13,525
Repurchase of common stock under Repurchase Program	(1,470)	—		—	—		286		(151,912)		—		(151,626)
Issuance of common stock upon vesting of share-based awards	102	—		—	—		—		—		—		—
Common stock withheld for income taxes on share-based awards	(34)	—		—	—		—		(3,207)		—		(3,207)
Dividends on preferred stock	—	—		—	—		—		(4)		(4,840)		(4,844)
Balance at December 31, 2023	18,288	$	2	(62)	$	(1,996)	$	—	$	315,726	$	1,847,948	$	2,161,680
Net loss	—	—		—	—		—		—		(261,386)		(261,386)
Conversion of preferred stock	500	—		—	—		—		6,866		—		6,866
Stock compensation	—	—		—	—		—		16,355		—		16,355
Repurchase of common stock under Repurchase Program	(1,203)	—		—	—		—		(186,271)		—		(186,271)
Issuance of common stock held in reserve	—	—		62	1,996		—		—		—		1,996
Issuance of common stock upon vesting of share-based awards	363	—		—	—		—		—		—		—
Common stock withheld for income taxes on share-based awards	(150)	—		—	—		—		(23,614)		—		(23,614)
Dividends on preferred stock	—	—		—	—		—		(3)		(4,230)		(4,233)
Balance at December 31, 2024	17,798	$	2	—	$	—	$	—	$	129,059	$	1,582,332	$	1,711,393
Net income	—	—		—	—		—		—		427,810		427,810
Conversion of preferred stock	2,555	—		—	—		—		34,899		—		34,899
Redemption of preferred stock	—	—		—	—		—		—		(29,986)		(29,986)
Stock compensation	—	—		—	—		—		18,143		—		18,143
Net cash payments on performance vesting restricted stock units	—	—		—	—		—		(12,297)		—		(12,297)
Repurchase of common stock under Repurchase Program	(1,603)	—		—	—		—		(164,216)		(143,774)		(307,990)
Issuance of common stock upon vesting of share-based awards	91	—		—	—		—		—		—		—
Common stock withheld for income taxes on share-based awards	(31)	—		—	—		—		(5,579)		—		(5,579)
Dividends on preferred stock	—	—		—	—		—		(9)		(1,666)		(1,675)
Balance at December 31, 2025	18,810	$	2	—	$	—	$	—	$	—	$	1,834,716	$	1,834,718

See accompanying notes to consolidated financial statements.

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GULFPORT ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

	Year Ended December 31, 2024		Year Ended December 31, 2023		Year Ended December 31, 2022
	Year Ended December 31, 2025		Year Ended December 31, 2024		Year Ended December 31, 2023
Cash flows from operating activities:
Net (loss) income	$	(261,386)	$	1,470,916	$	494,701
Net income (loss)	$	427,810	$	(261,386)	$	1,470,916
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation and amortization	~~325~~304,~~723~~162		~~319~~325,~~715~~723		~~267~~319,~~761~~715
Impairment of oil and natural gas properties	~~373,214~~—		—373,214		—
Loss on debt extinguishment	~~13,388~~—		—13,388		—
Net (gain) loss on derivative instruments	(29,527)		(740,319)		999,747
Net gain on derivative instruments	(99,056)		(29,527)		(740,319)
Net cash receipts (payments) on settled derivative instruments	282,637		152,199		(1,053,810)
Net cash receipts on settled derivative instruments	56,497		282,637		152,199
Deferred income tax benefit	(56,077)		(525,156)		—
Deferred income tax expense (benefit)	115,495		(56,077)		(525,156)
Stock-based compensation expense	1012,~~958~~156		910,~~480~~958		59,~~723~~480
Other, net	68,~~315~~599		76,~~645~~315		57,~~528~~645
Changes in operating assets and liabilities, net	(1522,~~212~~470)		28(15,~~701~~212)		1928,~~427~~701
Net cash provided by operating activities	~~650~~803,~~033~~193		~~723~~650,~~181~~033		~~739~~723,~~077~~181
Cash flows from investing activities:
Additions to oil and natural gas properties	(~~454~~527,~~098~~569)		(~~537~~454,~~360~~098)		(~~460~~537,~~780~~360)
Proceeds from sale of oil and natural gas properties	~~225~~150		~~2,659~~225		32,~~360~~659
Other, net	(21,~~120~~762)		(2,~~526~~120)		(~~875~~2,526)
Net cash used in investing activities	(~~455~~529,~~993~~181)		(~~537~~455,~~227~~993)		(~~458~~537,~~295~~227)
Cash flows from financing activities:
Principal payments on Credit Facility	(1,~~036~~246,000)		(~~998~~1,036,000)		(2998,~~082,~~000)
Borrowings on Credit Facility	~~956~~1,355,000		~~971~~956,000		2971,~~063,~~000
Issuance of 2029 Senior Notes	~~650,000~~—		—650,000		—
Early retirement of 2026 Senior Notes	(~~524~~25,~~298~~702)		—(524,298)		—
Premium paid on 2026 Senior Notes	~~(12,941)~~—		—(12,941)		—
Debt issuance costs and loan commitment fees	(~~14,933~~35)		(714,~~068~~933)		(~~234~~7,068)
Dividends on preferred stock	(41,~~230~~666)		(4,~~840~~230)		(54,~~444~~840)
Repurchase of common stock under Repurchase Program	(105,344)		(108,735)		(250,482)
Redemption of preferred stock	(32,423)		—		—
Repurchase of common stock under Repurchase Program - related party	(79,133)		(40,430)		—
Repurchase of common stock under Repurchase Program	(279,961)		(105,344)		(108,735)
Shares exchanged for tax withholdings	(23,614)		(3,207)		(1,623)
Repurchase of common stock under Repurchase Program - related party	(25,000)		(79,133)		(40,430)
Other, net	(3)		(4)		—
Net cash payments on performance vesting restricted stock units	(12,297)		—		—
Net cash used in financing activities	(194,496)		(191,284)		(276,783)
Shares exchanged for tax withholdings	(5,579)		(23,614)		(3,207)
Net change in cash and cash equivalents	(456)		(5,330)		3,999
Other, net	(9)		(3)		(4)
Cash and cash equivalents at beginning of period	1,929		7,259		3,260
Net cash used in financing activities	(273,672)		(194,496)		(191,284)
Cash and cash equivalents at end of period	$	1,473	$	1,929	$	7,259
Net change in cash and cash equivalents	340		(456)		(5,330)
Cash and cash equivalents at beginning of period	1,473		1,929		7,259
Cash and cash equivalents at end of period	$	1,813	$	1,473	$	1,929

See accompanying notes to consolidated financial statements.

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GULFPORT ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.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~~Gulfport ~~Holdings~~Appalachia ~~Inc.~~LLC, ~~Jaguar~~Gulfport ~~Resources~~MidCon LLC, ~~Gator~~Puma ~~Marine,~~Resources Inc., ~~Gator Marine Ivanhoe, Inc.,~~ Westhawk Minerals LLC, ~~Puma~~Grizzly ~~Resources,~~Holdings Inc., ~~Gulfport~~Mule ~~Appalachia~~Sky LLC, ~~Gulfport~~and ~~Midstream Holdings, LLC,~~ Gulfport ~~MidCon,~~LA ~~LLC and Mule Sky LLC~~Inc. 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 Note 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~~2025 and December 31, ~~2023~~2024.

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Oil and Natural 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. There were no impairments recognized in 2025 and 2023. 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 oil and NGL barrels to gas equivalents 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~~233.70 million and $~~204~~221.27 million at December 31, ~~2024~~2025 and December 31, ~~2023~~2024, 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 32 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.

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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~~2022. As of December 31, ~~2024~~2025, 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.

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Derivative Instruments

The Company utilizes commodity derivatives to manage the price risk associated with forecasted sale of its natural gas, crude oil and 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
	Year Ended December 31, 2025		Year Ended December 31, 2024		Year Ended December 31, 2023
Supplemental disclosure of cash flow information:
Interest payments, net of amounts capitalized	$	4647,~~406~~758	$	5346,~~820~~406	$	5753,~~685~~820
Cash payments (income taxes)
Federal taxes	$	1,200	$	—	$	—
State taxes	$	—	$	—	$	—
Changes in operating assets and liabilities, net:
Accounts receivable - oil, natural gas, and natural gas liquids sales	~~(33,463)~~$	(28,707)	~~155,925~~$	(33,463)	~~(45,550)~~$	155,925
Accounts receivable - joint interest and other	~~13,494~~(555)		~~(743)~~13,494		(~~1,095~~743)
Accounts payable and accrued liabilities	48,~~067~~193		~~(126~~4,~~329)~~067		59(126,~~879~~329)
Prepaid expenses	~~667~~(1,412)		~~(215)~~667		~~4,863~~(215)
Other assets	2311		6323		~~1,330~~63
Total changes in operating assets and liabilities, net	$	(1522,~~212~~470)	$	28(15,~~701~~212)	$	1928,~~427~~701
Supplemental disclosure of non-cash transactions:
Capitalized stock-based compensation	$	5,~~397~~987	$	45,~~046~~397	$	24,~~948~~046
Asset retirement obligation capitalized	~~682~~$	559	~~588~~$	682	~~2,169~~$	588
Asset retirement obligation removed due to divestiture and settlements	—$	(1,587)	~~(1,267)~~$	—	~~(7)~~$	(1,267)
Asset retirement obligation revisions	19$	9	~~(5,077)~~$	19	~~2,072~~$	(5,077)
Release of common stock held in reserve	~~1,996~~$	—	—$	1,996	~~28,220~~$	—
Unamortized 2026 Senior Notes debt issuance costs	~~447~~$	—	—$	447	—$	—

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Accounts Payable and Accrued Liabilities

Accounts payable and accrued liabilities consisted of the following (in thousands):

	December 31, 2024		December 31, 2023
	December 31, 2025		December 31, 2024
Revenue payable and suspense	$	~~139~~157,~~703~~532	$	~~148~~139,~~598~~703
Accounts payable	3453,~~668~~107		4334,~~517~~668
Accrued capital expenditures	20,229		38,322
Accrued transportation, gathering, processing, and compression	38,544		36,170
Accrued transportation, gathering, processing, and compression	36,170		32,849
Accrued capital expenditures	30,873		20,229
Accrued contract rejection damages and shares held in reserve	—		1,996
Other accrued liabilities	62,326		67,311
Other accrued liabilities	67,311		44,250
Total accounts payable and accrued liabilities	$	342,382	$	298,081
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.

Recent Accounting Pronouncements

In ~~November~~December 2023, the FASB issued ASU 2023-0709, ~~Segment~~Income ~~Reporting (Topic 280)~~Taxes: Improvements to ~~Reportable~~Income ~~Segment~~Tax Disclosures (Topic ~~280~~740). The ~~amendments~~amendment ~~require~~requires annual disclosure ~~for~~of ~~each~~additional ~~reportable~~categories ~~segment,~~of ~~the~~information ~~significant~~about ~~expense~~federal, ~~categories~~state, and ~~amounts~~foreign ~~that~~income ~~are~~taxes ~~regularly~~in ~~provided~~the torate ~~the~~reconciliation ~~CODM~~table and ~~included~~to provide more details about the reconciling items in ~~each~~some ~~reported~~categories ~~measure~~if ofthe aitems ~~segment’s~~meet ~~profit~~a orquantitative ~~loss~~threshold. Additionally, ~~this~~the ~~ASU~~amendment ~~enhances~~requires ~~interim~~ disclosure ~~requirements~~of annual income taxes paid (net of refunds received) disaggregated by federal, state, and ~~provides~~foreign ~~new~~taxes ~~segment~~and ~~disclosure~~to ~~requirements~~disaggregate ~~for~~the ~~entities~~information ~~with~~by ajurisdiction ~~single~~based ~~reportable~~on ~~segment~~a quantitative threshold. The Company retrospectively adopted ASU 2023-0709 during the year ended December 31, ~~2024~~2025. See Note 210, ~~Segment~~Income ~~Information~~Taxes, 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.

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2.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 income (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):~~ 67

	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.

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The following table presents selected financial information with respect to the Company's one operating segment for the years ended December 31, 2025, 2024 and 2023 (in thousands):


	Year Ended December 31, 2025		Year Ended December 31, 2024		Year Ended December 31, 2023
Total revenues	$	1,422,583	$	958,131	$	1,791,702
Significant segment expenses:
Lease operating expenses	84,242		70,112		68,648
Taxes other than income	29,908		29,737		33,717
Transportation, gathering, processing and compression	358,938		351,237		348,631
Depreciation, depletion, and amortization	304,162		325,723		319,715
Impairment of oil and gas properties	—		373,214		—
General and administrative	42,488		42,558		38,600
Interest expense	54,277		59,982		57,069
Other segment expenses(1)	5,263		23,031		(20,438)
Income tax expense (benefit)	115,495		(56,077)		(525,156)
Total significant segment expenses	994,773		1,219,517		320,786
Net income (loss)	$	427,810	$	(261,386)	$	1,470,916

Capital expenditures(2)	$	565,273	$	464,492	$	521,187

_____________________

(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.

3.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
	December 31, 2025		December 31, 2024
Proved oil and natural gas properties	$	3,~~349~~902,~~805~~539	$	23,~~904~~349,~~519~~805
Unproved properties	~~221~~232,~~650~~959		~~204~~221,~~233~~650
Other depreciable property and equipment	1012,~~905~~622		810,~~779~~905
Land	386		386
Total property and equipment	34,~~582~~148,~~746~~506		3,~~117~~582,~~917~~746
Accumulated DD&A and impairment	(1,~~564~~868,~~475~~481)		(~~865~~1,~~618~~564,475)
Property and equipment, net	$	2,~~018~~280,~~271~~025	$	2,~~252~~018,~~299~~271

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. At December 31, 2025, the net book value of the Company's oil and gas properties was below the calculated ceiling. As a result, the Company did not record an impairment of its oil and natural gas properties for the year ended December 31, 2025. 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.68

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

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~~The~~General ~~following~~and isadministrative acosts ~~summary~~capitalized ofto ~~Gulfport~~the full cost pool represent management’s ~~oil~~estimate of costs incurred directly related to exploration and ~~natural~~development ~~gas~~activities ~~properties~~such as geological and other administrative costs associated with overseeing the exploration and development activities. All general and administrative costs not ~~subject~~directly associated with exploration and development activities were charged to ~~amortization~~expense as ofthey were incurred. Capitalized general and administrative costs were approximately $25.2 million, $25.3 million and $22.8 million for the years ended December 31, 2025, 2024 (and 2023, respectively. The average depletion rate per Mcfe, which is a function of capitalized costs, future development costs and the related underlying reserves in ~~thousands):~~the periods presented, was $0.80, $0.84 and $0.83 per Mcfe for the years ended December 31, 2025, 2024 and 2023, respectively.

	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 following table summarizes the Company’s non-producing properties excluded from amortization by area (in thousands):


	December 31, 2025		December 31, 2024
Utica & Marcellus	$	210,185	$	197,513
SCOOP	22,774		24,137
Total unproved properties	$	232,959	$	221,650

The following is a summary of Gulfport’s oil and natural gas properties not subject to amortization as of December 31, 2025 (in thousands):


	Costs Incurred in
	2025		2024		2023		Prior to 2023		Total
Acquisition costs	$	65,239	$	58,722	$	58,002	$	41,715	$	223,678
Exploration costs	—		—		—		—		—
Development costs	3,820		1,246		418		—		5,484
Capitalized interest	3,612		185		—		—		3,797
Total oil and natural gas properties not subject to amortization	$	72,671	$	60,153	$	58,420	$	41,715	$	232,959

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~~2025 and ~~2023~~2024 (in thousands):

	Year Ended December 31, 2024		Year Ended December 31, 2023
	Year Ended December 31, 2025		Year Ended December 31, 2024
Asset retirement obligation, beginning of period	$	2932,~~941~~949	$	3329,~~171~~941
Liabilities incurred	~~682~~559		~~588~~682
Liabilities settled	—(3,026)		~~(604)~~—
Liabilities removed due to divestitures	—		(919)
Accretion expense	2,421		2,307
Accretion expense	2,307		2,782
Revisions in estimated cash flows(1)	9		19
Revisions in estimated cash flows(1)	19		(5,077)
Asset retirement obligation, end of period	$	32,912	$	32,949
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.

~~4.LONG-TERM DEBT~~69

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

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~~2029~~4.LONG-TERM ~~Senior Notes~~ DEBT

InLong-term ~~September~~debt ~~2024,~~consisted ~~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~~following ~~and~~items ~~each~~as of ~~the Company's subsidiaries that guarantee the Credit Facility. Interest on the 2029 Senior Notes is payable semi-annually~~December 31, on2025 ~~March 1~~ and ~~September~~2024 1(in ~~of each year, beginning on March 1, 2025.~~ thousands):

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.


	December 31, 2025		December 31, 2024
6.75% senior unsecured notes due 2029	$	650,000	$	650,000
8.00% senior unsecured notes due 2026	—		25,702
Credit Facility due 2028	147,000		38,000
Net unamortized debt issuance costs	(8,813)		(10,845)
Total debt, net	788,187		702,857
Less: current maturities of long-term debt	—		—
Total long-term debt, net	$	788,187	$	702,857

~~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~~In September 2024, Gulfport Operating completed a private offering of $650.0 million aggregate principal amount of 6.75% 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 is payable semi-annually, on March 1 and September 1 of each year, beginning on March 1, 2025.

~~In May 2021, Gulfport Operating issued $550 million aggregate principal amount of its 8.0% senior notes due 2026.~~ The ~~notes~~2029 ~~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~~2029 Senior Notes ~~Indentures~~Indenture, dated as of ~~May~~September 1713, ~~2021~~2024, by and among ~~the~~Gulfport ~~Issuer~~Operating, UMB Bank, National Association, as trustee, and the Guarantors ~~and mature on May 17, 2026~~.

The ~~covenants~~2029 ofSenior ~~the~~Notes ~~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~~Gulfport ~~Issuer~~Operating’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~~payments, ~~(v)~~and engage in ~~specified sales of assets, (vi) enter into~~ certain ~~transactions~~other ~~among affiliates~~transactions, ~~(vii)~~subject ~~engage~~to inexceptions ~~certain lines of business, (viii) engage in consolidations, mergers~~ and ~~acquisitions, (ix) create unrestricted subsidiaries and (x) incur or create liens~~qualifications. ~~These~~Certain covenants ~~contain~~will ~~important~~be ~~exceptions,~~suspended ~~limitations~~if ~~and qualifications. At any time that~~ the ~~2026~~2029 Senior Notes ~~are~~achieve ~~rated~~ investment grade, ~~certain covenants will be terminated and cease to apply~~ratings.

AsThe ~~noted~~net ~~above,~~proceeds infrom ~~September~~the ~~2024~~2029 Senior Notes offering, ~~Gulfport~~together ~~Operating~~with ~~purchased~~cash on hand were used to purchase and ~~retired~~retire $524.3 million of its 2026 Senior Notes in a tender offer ~~using~~and ~~net~~to ~~proceeds~~repay ~~from~~a portion of the ~~2029~~Company's ~~Senior~~outstanding ~~Notes~~borrowings ~~offering~~under the Credit Facility. The ~~2026~~tender ~~Senior~~offer ~~Notes~~resulted ~~were~~in ~~tendered~~a at$13.4 million anloss ~~average~~on ~~price~~debt ~~equal~~extinguishment. toIn ~~102.3%~~May of2025, the ~~principal~~Company ~~amount.~~redeemed ~~The~~the ~~retirement~~remaining balance of ~~the~~its 2026 Senior Notes, ~~resulted~~at inpar afor ~~loss~~$25.7 million. onNo ~~debt~~additional ~~extinguishment~~fees ofor ~~$13.4 million,~~penalties ~~which~~were ~~included~~incurred ~~cash~~as ~~costs~~a result of ~~$12~~the early redemption.~~9 million.~~

Credit Facility

OnThe ~~May~~Company 1,maintains ~~2023,~~a ~~the~~senior ~~Company~~secured ~~entered~~reserve-based ~~into~~revolving ~~that~~credit ~~certain~~facility ~~Joinder,~~under ~~Commitment~~its ~~Increase~~Third Amended and Restated Credit Agreement, as amended most recently by the Borrowing Base ~~Redetermination~~Reaffirmation Agreement, and ~~Third~~Fifth Amendment to Credit Agreement (the “~~Third~~Fifth Amendment”) ~~which~~dated ~~amended~~October ~~the~~30, ~~Company’s Credit Facility~~2025. The ~~Third~~facility ~~Amendment,~~provides ~~among~~for ~~other~~a ~~things,~~borrowing ~~(a)~~base ~~increased~~of ~~the~~$1.1 billion and aggregate elected ~~commitment~~commitments ~~amounts~~of ~~under~~$1.0 billion. ~~the~~The ~~Credit~~facility ~~Facility~~matures ~~from~~on ~~$700 million~~September to12, ~~$900 million~~2028, ~~(b)~~is ~~increased~~secured by substantially all of the ~~borrowing~~Company’s ~~base~~assets and is guaranteed by the Company's material domestic subsidiaries. Borrowings under the ~~Credit~~facility ~~Facility~~bear ~~from~~interest, ~~$1 billion~~at tothe ~~$1.1 billion~~Company’s election, ~~(c)~~at ~~increased~~a rate equal to either the ~~excess~~SOFR ~~cash~~benchmark ~~threshold~~plus ~~under~~an ~~the~~applicable ~~Credit~~margin ~~Facility~~ranging from ~~$45 million~~2.25% to ~~$75 million,~~3.25% ~~and~~per ~~(d)~~annum ~~extended~~or ~~the~~a ~~maturity~~base ~~date~~rate ~~under~~plus ~~the~~an ~~Credit~~applicable ~~Facility~~margin ranging from ~~October~~1.25% 14to 2.25% per annum, ~~2025~~in toeach ~~the~~case ~~earlier~~based ofon ~~(i)~~borrowing ~~May~~base 1,utilization. ~~2027~~The ~~and~~Company ~~(ii)~~also ~~the~~pays ~~91st~~a ~~day~~commitment ~~prior~~fee ranging from 0.375% to 0.50% per annum on the ~~maturity~~average ~~date~~daily unused portion of the ~~2026~~elected ~~Senior~~commitments. ~~Notes~~The orcredit ~~any~~agreement ~~other~~contains ~~permitted~~customary ~~senior~~affirmative ~~notes~~and ornegative ~~any~~covenants, ~~permitted~~including ~~refinancing~~financial ~~debt~~covenants ~~under~~requiring the ~~Credit~~Company ~~Facility~~to ~~having~~maintain ana ~~aggregate~~net ~~outstanding~~funded ~~principal~~leverage ~~amount~~ratio ~~equal~~of tonot ormore ~~exceeding~~than ~~$100 million;~~3.50 ~~provided~~to ~~that~~1.00 ~~such~~and ~~notes~~a ~~have~~current ~~not~~ratio ~~been~~of ~~refinanced,~~at ~~redeemed~~least or1.00 ~~repaid~~to in1.00, ~~full~~measured onas orof ~~prior~~the tolast ~~such~~day ~~91st~~of ~~day~~each fiscal quarter.

OnAs ~~April~~of 18December 31, ~~2024~~2025, ~~Gulfport~~the ~~completed~~Company ~~its~~had ~~semi-annual~~$147.0 ~~borrowing~~million ~~base~~outstanding ~~redetermination~~borrowings ~~during~~under ~~which~~ the ~~borrowing~~Credit ~~base~~Facility, ~~was~~$48.7 ~~reaffirmed~~million atin ~~$1.1 billion~~letters of credit outstanding and was in compliance with ~~elected~~all ~~commitments~~covenants ~~remaining~~under atthe ~~$900 million~~credit agreement.

72For the years ended December 31, 2025 and 2024, the Credit Facility bore interest at a weighted average rate of 6.53% and 8.23%, respectively.

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Index to Financial Statements

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.

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~~2025, ~~2023~~2024 and ~~2022~~2023 (in thousands):

Year Ended December 31, 2024

Year Ended December 31, 2023

Year Ended December 31, 2022

Year Ended December 31, 2025

Year Ended December 31, 2024

Year Ended December 31, 2023

Cash paid for interest

5153,~~177~~913

5751,~~967~~177

57,~~685~~967

Change in accrued interest

91,~~368~~260

~~(7)~~9,368

(~~826~~7)

Capitalized interest

(46,~~771~~154)

(4,~~147~~771)

—(4,147)

Amortization of loan costs

45,~~208~~258

34,~~256~~208

23,~~914~~256

Other

—

Total interest expense

5954,~~982~~277

5759,~~069~~982

5957,~~773~~069

73The Company capitalized $6.2 million, $4.8 million and $4.1 million in interest expense for the years ended December 31, 2025, 2024 and 2023, respectively, to undeveloped oil and natural gas properties.

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Index to Financial Statements

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~~2025, the carrying value of the outstanding debt represented by the ~~2026 Senior Notes and~~ 2029 Senior Notes ~~were~~was approximately $25641.~~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 $26672.03 million ~~and $655.0 million, respectively,~~ at December 31, ~~2024~~2025.

5.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 Series A Convertible Preferred Stock ("preferred stock").

~~Holders~~Prior to the redemption of the preferred stock ~~are~~noted below, holders of preferred stock were 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~~had ~~has~~ the option to pay either cash dividends or PIK Dividends on a quarterly basis.

Each holder of shares of preferred stock ~~has~~had 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~~The ~~may~~preferred ~~redeem~~stock ~~all,~~had ~~but~~no ~~not~~stated ~~less~~maturity ~~than~~and ~~all,~~would ofremain ~~the~~ outstanding ~~shares~~indefinitely ofunless ~~preferred~~repurchased ~~stock~~or redeemed by ~~notice~~Gulfport toor ~~the~~converted ~~holders~~into ofcommon ~~preferred~~ stock,. atThe ~~the greater of (i) the aggregate value of the~~ preferred stock, ~~calculated~~was byclassified ~~the Current Market Price (~~as ~~defined~~mezzanine equity in the ~~Preferred~~accompanying ~~Terms)~~consolidated ofbalance ~~the~~sheets ~~number~~due ~~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”)~~features.

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.71

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.

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Index to Financial Statements

~~The~~Redemption ~~following table summarizes activity~~ of ~~the~~Preferred ~~Company’s preferred stock for the years ended December 31, 2024 and 2023:~~Stock

	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

On August 5, 2025, Gulfport issued a notice of redemption for its preferred stock for cash. During the period between the date of the notice of redemption and September 5, 2025 (the “Redemption Date”), 28,907 shares of preferred stock were converted into approximately 2.1 million shares of common stock and reclassified from mezzanine equity to stockholders' equity. On the Redemption Date, the Company redeemed the remaining 2,449 shares of preferred stock for cash totaling $31.3 million. Additionally, direct transaction-related costs of $1.1 million were incurred as part of the redemption. The excess of the cash settlement and direct transaction-related costs over the carrying value of the redeemed shares of preferred stock, totaling approximately $29.9 million, was treated as a deemed dividend and recorded as a reduction to retained earnings. The cash outflows related to the preferred stock redemption and associated fees are presented within financing activities on the consolidated statement of cash flows. The deemed dividend reduced net income available to common shareholders and impacted the calculation of earnings per share for the year ended December 31, 2025.

Dividends and Conversions

During the years ended December 31, 2025, 2024 and 2023 the Company paid $1.7 million, $4.2 million and $4.8 million, respectively, of cash dividends to holders of our preferred stock. No cash dividends were paid after the Redemption Date.

The following table summarizes activity of the Company’s preferred stock for the years ended December 31, 2025 and 2024:


	2025	2024
Preferred stock as of January 1	37,348	44,214
Conversion of preferred stock	(4,461)	(11)
Preferred stock as of March 31	32,887	44,203
Conversion of preferred stock	(1,531)	(415)
Preferred stock as of June 30	31,356	43,788
Conversion of preferred stock	(28,907)	(43)
Redemption of preferred stock	(2,449)	—
Preferred stock as of September 30	—	43,745
Conversion of preferred stock	—	(6,397)
Preferred stock as of December 31	—	37,348

6.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~~72

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.

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Index to Financial Statements

Stock ~~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

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 $1.5 billion, including the cash redemption of preferred stock noted previously, and extended through December 31, 2026. 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.

AsThe offollowing ~~December 31,~~table ~~2024,~~summarizes ~~the~~activity ~~Company~~under ~~has~~the ~~repurchased~~Repurchase ~~5.6~~Program ~~million shares~~ for ~~$584.1~~the ~~million~~year atended aDecember 31, ~~weighted~~2025 ~~average~~(number ~~price~~ of ~~$104.88~~shares ~~per~~and ~~share~~dollar ~~since~~value ~~the~~of ~~inception~~shares ofpurchased ~~the~~shown ~~Repurchase~~in ~~Program.~~thousands):


	Total Number of Shares Purchased	Dollar Value of Shares Purchased		Average Price Paid Per Share
First quarter 2025	341	$	60,000	$	176.13
Second quarter 2025	339	65,000		191.80
Third quarter 2025(1)	438	76,263		174.01
Fourth quarter 2025	665	134,999		203.11
Total	1,783	$	336,262	$	188.65

_____________________

(1) Amounts include cash redemption of 2,449 shares of preferred stock (equivalent to 179,666 shares of common stock on an as-converted basis), totaling $31.3 million at $174.22 price per share. See Note 5 for further discussion of the Company's redemption of its preferred stock.

As of December 31, 2025, the Company has repurchased 7.4 million shares for $920.4 million at a weighted average price of $125.19 per share since the inception of the Repurchase Program.

7.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~~2025 and ~~2023~~2024, the Company's stock-based compensation expense was $1618.41 million and $1216.34 million of which the Company capitalized $56.40 million and $45.04 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~~2025, the Company has awarded an aggregate of approximately ~~444~~516,~~493~~677 restricted stock units and approximately ~~462~~539,~~982~~972 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.

7673

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Index to Financial Statements

The following table summarizes activity for the years ended December 31, ~~2022~~2023, ~~2023~~2024 and ~~2024~~2025:

	Number ofUnvestedRestricted Stock Units	WeightedAverageGrant DateFair Value		Number ofUnvestedPerformance Vesting Restricted Stock Units	WeightedAverageGrant DateFair Value
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~~143.7909		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~~111.6729	178,139	$	92.06
Granted	72,184	173.62		76,990	119.33
Vested	(90,720)	105.59		(71,948)	66.82
Forfeited/canceled	(4,812)	140.83		—	—
Unvested shares as of December 31, 2025	143,666	$	145.22	183,181	$	113.44

_____________________

(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~~2025, ~~2023~~2024 and ~~2022~~2023, was approximately $5628.89 million, $956.98 million and $59.9 million, respectively, based on the stock price at the time of vesting.

In the second quarter of 2025, upon vesting, the Company settled in cash performance vesting restricted stock units awards that were granted in 2022. These awards vested at 200% of target due to the Company's performance during the performance period. The awards were classified as equity awards from the grant date as they were intended to be settled in shares. The Company has no history or stated policy of settling such awards in cash, and there is no implied obligation to do so in the future. The total cash outflow related to this settlement was $12.3 million.

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~~2025, was $12.17 million. The expense is expected to be recognized over a weighted average period of 1.7273 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:~~74

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

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Index to Financial Statements

~~Unrecognized~~The ~~compensation~~table ~~expense~~below assummarizes ofthe ~~December 31,~~assumptions ~~2024,~~used ~~related~~in tothe ~~performance~~Monte ~~vesting~~Carlo ~~restricted~~simulation ~~shares~~to ~~was~~determine ~~$8.0~~the ~~million.~~grant ~~The~~date ~~expense~~fair isvalue ~~expected~~of toawards begranted ~~recognized~~during ~~over~~the ayears ~~weighted~~ended ~~average~~December 31, ~~period~~2023, of2024 ~~1.73~~and ~~years.~~2025:


Grant date	January 24, 2023	March 3, 2023	April 3, 2023	March 1, 2024	March 1, 2025
Forecast period (years)	3	3	3	3	3
Risk-free interest rates	3.88%	4.64%	3.79%	4.36%	3.99%
Implied equity volatility	87.2%	86.4%	70.8%	46.7%	44.6%
Stock price on the date of grant	$72.99	$82.20	$79.50	$142.00	$169.80

Unrecognized compensation expense as of December 31, 2025, related to performance vesting restricted shares was $7.6 million. The expense is expected to be recognized over a weighted average period of 1.60 years.

8.REVENUE FROM CONTRACTS WITH CUSTOMERS

Revenue Recognition

The Company’s revenues are primarily derived from the sale of natural gas, oil and condensate and NGL. 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 $184.6 million, $155.9 million and $122.5 million as of December 31, 2025, 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 as of December 31, 2025, 2024 and 2023.

~~Prior-Period Performance Obligations~~ 75

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.

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Index to Financial Statements

Prior-Period Performance Obligations

9.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 historically 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~~2025, the Company ~~had~~did ~~one~~not have any active long-term drilling rig ~~contract~~contracts. These agreements typically include renewal options at the end of the initial term. Due to the nature of the Company's drilling schedules and potential volatility in commodity prices, the Company is unable to determine at contract commencement with reasonable certainty if the renewal options will be exercised; therefore, renewal options are not considered in the lease term for drilling contracts. The operating lease liabilities associated with these rig commitments, when applicable, are based on the minimum contractual obligations, primarily standby rates, and do not include variable amounts based on actual activity in a given period. Pursuant to the full cost method of accounting, these costs are capitalized as part of oil and natural gas properties on the accompanying consolidated balance sheets. A portion of drilling costs are borne by other interest owners in our wells.

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~~2025, were as follows (in thousands):

2025	$	5,657
2026	561
2027	10
2028	—
2029	—
Total lease payments	$	6,228
2030	—
Less: imputed interest	(129)
Total lease payments	571
Total	$	6,099
Less: imputed interest	(10)
Total	561

7976

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Lease costs incurred for the years ended December 31, ~~2024~~2025 and ~~2023~~2024 consisted of the following (in thousands):

	Year Ended December 31, 2024		Year Ended December 31, 2023
	Year Ended December 31, 2025		Year Ended December 31, 2024
Operating lease cost	$	122,~~828~~053	$	1312,~~752~~828
Variable lease cost	—		—
Short-term lease cost	2631,~~817~~547		2826,~~691~~817
Total lease cost(1)	$	3933,~~645~~600	$	4239,~~443~~645

_____________________

(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~~2025, was 0.7671 years. The weighted-average discount rate used to determine the operating lease liability as of December 31, ~~2024~~2025, was 6.2510%.

10.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 expense and benefits were as follows (in thousands):

	Year Ended December 31, 2024		Year Ended December 31, 2023		Year Ended December 31, 2022
	Year Ended December 31, 2025		Year Ended December 31, 2024		Year Ended December 31, 2023
Current:
State	$	—	$	—	$	—
Federal	—		—		—
Deferred:
State	~~11,747~~71		~~(26~~11,~~704)~~747		—(26,704)
Federal	~~(67~~115,~~824)~~424		(~~498~~67,~~452~~824)		—(498,452)
Total income tax benefit provision	$	(56,077)	$	(525,156)	$	—
Total income tax expense (benefit) provision	$	115,495	$	(56,077)	$	(525,156)

A reconciliation of the statutory federal income tax amount to the recorded expense (benefit) follows (in thousands):

	Year Ended December 31, 2024		Year Ended December 31, 2023			Year Ended December 31, 2022
	Year Ended December 31, 2025					Year Ended December 31, 2024				Year Ended December 31, 2023
Income (loss) before federal income taxes	$	(317,463)	$	945,760		$	494,701
	Amount		Percent			Amount		Percent		Amount		Percent
Expected income tax at statutory rate	(66,668)		198,610			103,887
Income (loss) before federal income taxes	$	543,305				$	(317,463)			$	945,760
State income taxes	4,765		(2,581)			2,227
U.S. federal statutory tax rate	114,094		21.00		%	(66,668)		21.00	%	198,610		21.00	%
Remeasurement of state deferred tax asset	54		—			13,869
State and local income taxes, net of federal income tax effect(1)	(479)		(0.09)		%	8,939		(2.82)	%	(26,018)		(2.75)	%
Return to provision	5,800		(5,592)			(17,075)
Valuation allowances	(56)		(0.01)		%	(259)		0.08	%	(699,730)		(73.99)	%
Other differences	1,857		1,982			1,117
Nontaxable or nondeductible items	1,745		0.32		%	1,857		(0.58)	%	1,982		0.21	%
Change in valuation allowance due to current year activity	(1,885)		(717,575)			(104,025)
Tax credits	191		0.04		%	—		—	%	—		—	%
Income tax benefit recorded	$	(56,077)	$	(525,156)		$	—
Other adjustments	—		—		%	54		(0.02)	%	—		—	%
Income tax expense (benefit) recorded	$	115,495	21.26		%	$	(56,077)	17.66	%	$	(525,156)	(55.53)	%

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._____________________

80(1) For 2025, 2024 and 2023, state taxes in Oklahoma contributed to the majority (greater than 50 percent) of the tax effect in this category.

For the year ended December 31, 2025, the Company's effective tax rate was 21.26% and an income tax expense of $115.5 million. For the year ended December 31, 2024, the Company's effective tax rate was 17.66% and an income tax benefit of $56.1 million. The higher effective income tax rate for the year ended December 31, 2025, is primarily related to the impact of state and local taxes during the year ended December 31, 2024.

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Index to Financial Statements

The tax effects of temporary differences and net operating loss carryforwards, which give rise to deferred tax assets and liabilities at December 31, ~~2024~~2025 and ~~December 31,~~2024 ~~2023~~ are estimated as follows (in thousands):

	Year Ended December 31, 2024		Year Ended December 31, 2023
	Year Ended December 31, 2025		Year Ended December 31, 2024
Deferred tax assets:
Net operating loss carryforward and tax credits	$	~~345~~330,~~770~~805	$	~~399~~345,~~017~~770
Oil and gas property basis difference	~~194~~123,~~412~~496		~~143~~194,~~769~~412
Investment in pass through entities	65,~~210~~385		6865,~~114~~210
Stock-based compensation expense	12,~~821~~223		1,~~262~~821
Change in fair value of derivative instruments	~~6,106~~—		—6,106
Other assets	5633,~~849~~491		5256,~~730~~849
Total deferred tax assets	~~670~~555,~~168~~400		~~664~~670,~~892~~168
Valuation allowance for deferred tax assets	(8382,~~695~~637)		(8583,~~757~~695)
Deferred tax assets, net of valuation allowance	~~586~~472,~~473~~763		~~579~~586,~~135~~473
Deferred tax liabilities:
Change in fair value of derivative instruments	36,~~401~~232		503,~~448~~401
Right of use asset	~~1,281~~118		31,~~003~~281
Other	~~558~~675		~~528~~558
Total deferred tax liabilities	57,~~240~~025		535,~~979~~240
Net deferred tax asset	$	~~581~~465,~~233~~738	$	~~525~~581,~~156~~233

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 $8382.76 million valuation allowance associated with its federal and state deferred tax assets. The Company does not currently have forecasted revenues in the jurisdictions that relate to these 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 $1.65 billion as of December 31, ~~2024~~2025. ~~These~~The federal net operating loss carryforwards of approximately $~~264~~186.50 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~~2025 federal NOL carryforwards of $1.3 billion have no expiration. The Company also has state net operating loss carryovers of approximately $~~394~~473.58 million that will begin to expire in ~~2025~~2026.

As of December 31, ~~2024~~2025, we had no liability for uncertain tax positions.

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11.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~~During ~~were~~the ~~0.3~~year ~~million~~ended December 31, 2025, the Company redeemed 2,449 shares of ~~restricted~~preferred stock ~~that~~for ~~were~~cash ~~considered~~totaling ~~anti-dilutive~~$31.3 million. ~~for~~Additionally, ~~the~~direct ~~year~~transaction-related ~~ended~~costs ~~December 31,~~of ~~2024~~$1.1 million ~~There~~ were ~~0.3~~incurred ~~million~~as ~~and~~part 0of the redemption.2 ~~million~~The ~~shares~~excess of ~~restricted~~the ~~stock~~cash ~~that~~settlement ~~were~~and ~~considered~~direct ~~dilutive~~transaction-related ~~for~~costs over the ~~years~~carrying ~~ended~~value ~~December 31,~~of ~~2023~~the ~~and~~redeemed ~~2022,~~shares ~~respectively.~~of ~~There~~preferred ~~were~~stock, ~~2.7~~totaling ~~million,~~approximately 3$29.2 9 million, ~~and~~was ~~3.7~~treated ~~million~~as ~~potential~~a ~~shares~~deemed ofdividend ~~common~~and ~~stock~~recorded ~~issuable~~as ~~due~~a reduction to ~~the~~retained ~~Company's~~earnings. ~~convertible~~The ~~preferred~~deemed ~~stock~~dividend ~~for~~reduced ~~the~~net ~~years~~income ~~ended~~available ~~December 31,~~to ~~2024,~~common ~~2023~~shareholders and ~~2022,~~impacted ~~respectively.~~both basic and diluted earnings per share.

~~Reconciliations~~Restricted ofstock awards resulted in 0.2 million dilutive shares for the ~~components~~year ofended ~~basic~~December 31, 2025, 0.3 million anti-dilutive shares for the year ended December 31, 2024, and ~~diluted~~0.3 ~~net~~million ~~(loss)~~dilutive ~~income~~shares ~~per~~year ended December 31, 2023. There were 2.7 million and 3.2 million potential shares of common ~~share~~stock ~~are~~issuable ~~presented~~due into the ~~table~~Company's ~~below~~convertible ~~(in~~preferred ~~thousands):~~stock for the years ended December 31, 2024 and 2023, respectively. The Company redeemed all outstanding preferred stock during the year ended December 31, 2025.

	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

Reconciliations of the components of basic and diluted net income (loss) per common share are presented in the table below (in thousands):


	Year Ended December 31, 2025		Year Ended December 31, 2024		Year Ended December 31, 2023
Net income (loss)	$	427,810	$	(261,386)	$	1,470,916
Dividends on preferred stock	(1,666)		(4,230)		(4,840)
Deemed dividend on preferred stock(1)	(29,986)		—		—
Participating securities - preferred stock(2)	—		—		(212,360)
Net income (loss) attributable to common stockholders	$	396,158	$	(265,616)	$	1,253,716
Re-allocation of participating securities	—		—		2,475
Diluted net income (loss) attributable to common stockholders	$	396,158	$	(265,616)	$	1,256,191
Basic Shares	18,223		18,050		18,645
Dilutive Shares	18,440		18,050		18,902

Filing Compare · GULFPORT ENERGY CORP