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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)


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

For the quarterly period ended June 30, 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 Number)
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 whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes ý No ¨

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (Section 232.405 of this chapter) during the preceding 12 months (or such shorter period that the registrant was required to submit such files). Yes ý No ¨

Indicate by check mark 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 ý Accelerated filer ¨ Non-accelerated filer ¨

Smaller reporting company ☐ Emerging growth company ☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for 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 is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ý

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Sections 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court.

Yes ý No ¨

As of July 30, 2025, 17,561,724 shares of the registrant’s common stock were outstanding.

Table of Contents

GULFPORT ENERGY CORPORATION

TABLE OF CONTENTS


		Page
PART I FINANCIAL INFORMATION

Item 1.	Consolidated Financial Statements (Unaudited):	4

	Consolidated Balance Sheets	4

	Consolidated Statements of Operations	5

	Consolidated Statements of Stockholders’ Equity	7

	Consolidated Statements of Cash Flows	9

	Notes to Consolidated Financial Statements	10

	1. Summary of Significant Accounting Policies	10

	2. Segment Information	11

	3. Property and Equipment	13

	4. Long-Term Debt	14

	5. Mezzanine Equity	16

	6. Equity	17

	7. Stock-Based Compensation	18

	8. Earnings (Loss) Per Share	20

	9. Commitments and Contingencies	21

	10. Derivative Instruments	23

	11. Fair Value Measurements	27

	12. Revenue from Contracts with Customers	29

	13. Leases	29

	14. Income Taxes	31

	15. Related Party Transactions	31

	16. Subsequent Events	32

Item 2.	Management’s Discussion and Analysis of Financial Conditions and Results of Operations	33

	2025 Operational and Financial Highlights	34

	2025 Production and Drilling Activity	34

	Comparison of Quarter-to-Date	36

	Comparison of Year-to-Date	41

	Liquidity and Capital Resources	45

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	49

Item 4.	Controls and Procedures	50

PART II OTHER INFORMATION

Item 1.	Legal Proceedings	51

Item 1A.	Risk Factors	51

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	51

Item 3.	Defaults Upon Senior Securities	51

Item 4.	Mine Safety Disclosures	51

Item 5.	Other Information	51

Item 6.	Exhibits	52

Signatures		54

Table of Contents

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 Quarterly Report on Form 10-Q:

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. 8.0% 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% 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.

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.

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 by the Commitment Increase, Borrowing Base Reaffirmation Agreement, and Fourth Amendment to Credit Agreement dated as of September 12, 2024.

DD&A. Depreciation, depletion and amortization.

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.

FASB. Financial Accounting Standards Board.

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GAAP. Accounting principles generally accepted in the United States of America.

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.

Incentive Plan. Gulfport Energy Corporation 2021 Stock Incentive Plan effective on the Emergence Date.

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 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.

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 fractional working interests owned in gross acres or gross wells.

NYMEX. New York Mercantile Exchange.

Parent. Gulfport Energy Corporation.

Plan. The Amended Joint Chapter 11 Plan of Reorganization of Gulfport Energy Corporation and Its Debtor Subsidiaries.

Repurchase Program. A stock repurchase program to acquire up to $1 billion of Gulfport's outstanding common stock. It is authorized to extend through December 31, 2025, and may be suspended from time to time, modified, extended or discontinued by the Board of Directors at any time.

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.

SOFR. Secured Overnight Financing Rate.

TSR. Total shareholder return.

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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Cautionary Note Regarding Forward-Looking Statements

This Form 10-Q 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-Q that address activities, events or developments that we expect or anticipate will or may occur in the future, including the expected impact of U.S. trade policy and its impact on broader economic conditions, 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), 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-Q 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” in our Annual Report on Form 10-K for the year ended December 31, 2024 and elsewhere in this Form 10-Q. All forward-looking statements speak only as of the date of this Form 10-Q.

All forward-looking statements, expressed or implied, included in this Quarterly 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 Quarterly 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 Quarterly Report on Form 10-Q.

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GULFPORT ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS

(In thousands)

(Unaudited)


	June 30, 2025		December 31, 2024
Assets
Current assets:
Cash and cash equivalents	$	3,794	$	1,473
Accounts receivable—oil, natural gas, and natural gas liquids sales	128,614		155,942
Accounts receivable—joint interest and other	11,748		8,727
Prepaid expenses and other current assets	9,576		7,086
Short-term derivative instruments	44,191		58,085
Total current assets	197,923		231,313
Property and equipment:
Oil and natural gas properties, full-cost method
Proved oil and natural gas properties	3,669,584		3,349,805
Unproved properties	211,626		221,650
Other property and equipment	12,278		11,291
Total property and equipment	3,893,488		3,582,746
Less: accumulated depletion, depreciation and amortization	(1,703,691)		(1,564,475)
Total property and equipment, net	2,189,797		2,018,271
Other assets:
Long-term derivative instruments	20,906		6,003
Deferred tax asset	529,844		581,233
Operating lease assets	956		6,099
Other assets	20,031		22,778
Total other assets	571,737		616,113
Total assets	$	2,959,457	$	2,865,697
Liabilities, Mezzanine Equity and Stockholders’ Equity
Current liabilities:
Accounts payable and accrued liabilities	$	335,631	$	298,081
Short-term derivative instruments	53,184		41,889
Current portion of operating lease liabilities	804		5,538
Total current liabilities	389,619		345,508
Non-current liabilities:
Long-term derivative instruments	44,793		35,081
Asset retirement obligation	32,703		32,949
Non-current operating lease liabilities	153		561
Long-term debt	695,154		702,857
Total non-current liabilities	772,803		771,448
Total liabilities	$	1,162,422	$	1,116,956
Commitments and contingencies (Note 9)
Mezzanine equity:
Preferred stock - $0.0001 par value, 110.0 thousand shares authorized, 31.4 thousand issued and outstanding at June 30, 2025, and 37.3 thousand issued and outstanding at December 31, 2024	31,356		37,348
Stockholders’ equity:
Common stock - $0.0001 par value, 42.0 million shares authorized, 17.6 million issued and outstanding at June 30, 2025, and 17.8 million issued and outstanding at December 31, 2024	2		2
Additional paid-in capital	1,509		129,059
Retained earnings	1,764,668		1,582,332
Treasury stock, at cost - 2.5 thousand shares at June 30, 2025 and 0 shares at December 31, 2024	(500)		—
Total stockholders’ equity	$	1,765,679	$	1,711,393
Total liabilities, mezzanine equity and stockholders’ equity	$	2,959,457	$	2,865,697

See accompanying notes to consolidated financial statements.

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GULFPORT ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands)

(Unaudited)


	Three Months Ended June 30, 2025		Three Months Ended June 30, 2024
REVENUES:
Natural gas sales	$	241,236	$	144,458
Oil and condensate sales	41,543		19,127
Natural gas liquid sales	28,736		26,147
Net gain (loss) on natural gas, oil and NGL derivatives	136,101		(8,615)
Total revenues	447,616		181,117
OPERATING EXPENSES:
Lease operating expenses	17,628		15,817
Taxes other than income	7,556		7,018
Transportation, gathering, processing and compression	86,508		86,529
Depreciation, depletion and amortization	73,643		78,553
General and administrative expenses	10,926		10,752
Accretion expense	587		567
Total operating expenses	196,848		199,236
INCOME (LOSS) FROM OPERATIONS	250,768		(18,119)
OTHER EXPENSE:
Interest expense	13,731		15,158
Other, net	901		522
Total other expense	14,632		15,680
INCOME (LOSS) BEFORE INCOME TAXES	236,136		(33,799)
INCOME TAX EXPENSE (BENEFIT):
Current	274		—
Deferred	51,396		(7,587)
Total income tax expense (benefit)	51,670		(7,587)
NET INCOME (LOSS)	$	184,466	$	(26,212)
Dividends on preferred stock	(804)		(1,095)
Participating securities - preferred stock	(20,622)		—
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCKHOLDERS	$	163,040	$	(27,307)
NET INCOME (LOSS) PER COMMON SHARE:
Basic	$	9.21	$	(1.51)
Diluted	$	9.12	$	(1.51)
Weighted average common shares outstanding—Basic	17,707		18,144
Weighted average common shares outstanding—Diluted	17,907		18,144

See accompanying notes to consolidated financial statements.

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GULFPORT ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands)

(Unaudited)


	Six Months Ended June 30, 2025		Six Months Ended June 30, 2024
REVENUES:
Natural gas sales	$	522,742	$	332,744
Oil and condensate sales	72,802		40,828
Natural gas liquid sales	59,553		54,253
Net (loss) gain on natural gas, oil and NGL derivatives	(10,447)		36,521
Total revenues	644,650		464,346
OPERATING EXPENSES:
Lease operating expenses	37,911		32,625
Taxes other than income	14,182		15,278
Transportation, gathering, processing and compression	169,378		173,148
Depreciation, depletion and amortization	139,265		158,576
General and administrative expenses	19,927		19,950
Accretion expense	1,205		1,122
Total operating expenses	381,868		400,699
INCOME FROM OPERATIONS	262,782		63,647
OTHER EXPENSE:
Interest expense	27,087		30,161
Other, net	199		397
Total other expense	27,286		30,558
INCOME BEFORE INCOME TAXES	235,496		33,089
INCOME TAX EXPENSE:
Current	105		—
Deferred	51,389		7,266
Total income tax expense	51,494		7,266
NET INCOME	$	184,002	$	25,823
Dividends on preferred stock	(1,666)		(2,200)
Participating securities - preferred stock	(20,385)		(3,469)
NET INCOME ATTRIBUTABLE TO COMMON STOCKHOLDERS	$	161,951	$	20,154
NET INCOME PER COMMON SHARE:
Basic	$	9.10	$	1.11
Diluted	$	9.01	$	1.09
Weighted average common shares outstanding—Basic	17,793		18,169
Weighted average common shares outstanding—Diluted	18,009		18,573

See accompanying notes to consolidated financial statements.

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GULFPORT ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(In thousands)

(Unaudited)


	Common Stock			Common Stock Held in Reserve			Treasury Stock		Paid-in Capital		Retained Earnings		Total Stockholders’ Equity
	Shares	Amount		Shares	Amount
Balance at January 1, 2024	18,288	$	2	(62)	$	(1,996)	$	—	$	315,726	$	1,847,948	$	2,161,680
Net income	—	—		—	—		—		—		52,035		52,035
Conversion of preferred stock	1	—		—	—		—		11		—		11
Stock compensation	—	—		—	—		—		3,587		—		3,587
Repurchase of common stock under Repurchase Program	(210)	—		—	—		—		(29,788)		—		(29,788)
Issuance of common stock held in reserve	—	—		62	1,996		—		—		—		1,996
Issuance of common stock upon vesting of share-based awards	18	—		—	—		—		—		—		—
Common stock withheld for income taxes on share-based awards	(8)	—		—	—		—		(1,086)		—		(1,086)
Dividends on preferred stock	—	—		—	—		—		—		(1,105)		(1,105)
Balance at March 31, 2024	18,089	$	2	—	$	—	$	—	$	288,450	$	1,898,878	$	2,187,330
Net loss	—	—		—	—		—		—		(26,212)		(26,212)
Conversion of preferred stock	30	—		—	—		—		415		—		415
Stock compensation	—	—		—	—		—		4,990		—		4,990
Repurchase of common stock under Repurchase Program	(156)	—		—	—		(698)		(24,319)		—		(25,017)
Issuance of common stock upon vesting of share-based awards	303	—		—	—		—		—		—		—
Common stock withheld for income taxes on share-based awards	(129)	—		—	—		—		(20,498)		—		(20,498)
Dividends on preferred stock	—	—		—	—		—		—		(1,095)		(1,095)
Balance at June 30, 2024	18,137	$	2	—	$	—	$	(698)	$	249,038	$	1,871,571	$	2,119,913

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GULFPORT ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY CONTINUED

(In thousands)

(Unaudited)


	Common Stock			Common Stock Held in Reserve			Treasury Stock		Paid-in Capital		Retained Earnings		Total Stockholders’ Equity
	Shares	Amount		Shares	Amount
Balance at January 1, 2025	17,798	$	2	—	$	—	$	—	$	129,059	$	1,582,332	$	1,711,393
Net loss	—	—		—	—		—		—		(464)		(464)
Conversion of preferred stock	324	—		—	—		—		4,461		—		4,461
Stock compensation	—	—		—	—		—		4,538		—		4,538
Repurchase of common stock under Repurchase Program	(329)	—		—	—		(2,192)		(58,409)		—		(60,601)
Issuance of common stock upon vesting of share-based awards	40	—		—	—		—		—		—		—
Common stock withheld for income taxes on share-based awards	(17)	—		—	—		—		(2,962)		—		(2,962)
Dividends on preferred stock	—	—		—	—		—		(4)		(862)		(866)
Balance at March 31, 2025	17,816	$	2	—	$	—	$	(2,192)	$	76,683	$	1,581,006	$	1,655,499
Net income	—	—		—	—		—		—		184,466		184,466
Conversion of preferred stock	113	—		—	—		—		1,531		—		1,531
Stock compensation	—	—		—	—		—		4,870		—		4,870
Net cash payments on performance vesting restricted stock units	—	—		—	—		—		(12,297)		—		(12,297)
Repurchase of common stock under Repurchase Program	(348)	—		—	—		1,692		(67,009)		—		(65,317)
Issuance of common stock upon vesting of share-based awards	39	—		—	—		—		—		—		—
Common stock withheld for income taxes on share-based awards	(12)	—		—	—		—		(2,266)		—		(2,266)
Dividends on preferred stock	—	—		—	—		—		(3)		(804)		(807)
Balance at June 30, 2025	17,608	$	2	—	$	—	$	(500)	$	1,509	$	1,764,668	$	1,765,679

See accompanying notes to consolidated financial statements.

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GULFPORT ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)


	Six Months Ended June 30, 2025		Six Months Ended June 30, 2024
Cash flows from operating activities:
Net income	$	184,002	$	25,823
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion, depreciation and amortization	139,265		158,576
Net loss (gain) on derivative instruments	10,447		(36,522)
Net cash receipts on settled derivative instruments	9,550		156,065
Deferred income tax expense	51,389		7,266
Stock-based compensation expense	6,303		5,746
Other, net	3,850		3,024
Changes in operating assets and liabilities, net	3,877		(8,491)
Net cash provided by operating activities	408,683		311,487
Cash flows from investing activities:
Additions to oil and natural gas properties	(253,000)		(244,851)
Other, net	(965)		(1,647)
Net cash used in investing activities	(253,965)		(246,498)
Cash flows from financing activities:
Principal payments on Credit Facility	(414,000)		(511,000)
Borrowings on Credit Facility	431,000		523,000
Early retirement of 2026 Senior Notes	(25,702)		—
Debt issuance costs and loan commitment fees	—		(106)
Dividends on preferred stock	(1,666)		(2,200)
Repurchase of common stock under Repurchase Program	(109,500)		(38,793)
Repurchase of common stock under Repurchase Program - related party	(15,000)		(15,002)
Net cash payments on performance vesting restricted stock units	(12,297)		—
Shares exchanged for tax withholdings	(5,228)		(21,584)
Other, net	(4)		—
Net cash used in financing activities	(152,397)		(65,685)
Net change in cash and cash equivalents	2,321		(696)
Cash and cash equivalents at beginning of period	1,473		1,929
Cash and cash equivalents at end of period	$	3,794	$	1,233

See accompanying notes to consolidated financial statements.

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GULFPORT ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1.SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Description of Company

Gulfport Energy Corporation (the "Company" or "Gulfport") 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 accompanying unaudited condensed consolidated financial statements of Gulfport were prepared in accordance with GAAP and the rules and regulations of the SEC.

This Quarterly Report on Form 10-Q (this “Form 10-Q”) relates to the financial position as of June 30, 2025, the results of operations for the three and six months ended June 30, 2025 and 2024 and the cash flows for the six months ended June 30, 2025 and 2024. The Company's annual report on Form 10-K for the year ended December 31, 2024, should be read in conjunction with this Form 10-Q. The accompanying unaudited consolidated financial statements reflect all normal recurring adjustments which, in the opinion of management, are necessary for a fair statement of our condensed consolidated financial statements and accompanying notes and include the accounts of our wholly-owned subsidiaries. Intercompany accounts and balances have been eliminated. The accompanying consolidated financial statements have been prepared assuming the Company will continue as a going concern.

Recent Accounting Pronouncements

In December 2023, the FASB issued ASU 2023-09, Income Taxes: Improvements to Income Tax Disclosures (Topic 740). The amendment requires entities to disclose on an annual basis 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. The ASU is effective for annual periods beginning after December 15, 2024, and the resulting new annual disclosure requirements will be reflected in our annual report on Form 10-K for the year ending December 31, 2025.

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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Accounts Payable and Accrued Liabilities

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


	June 30, 2025		December 31, 2024
Revenue payable and suspense	$	138,545	$	139,703
Accounts payable	58,998		34,668
Accrued capital expenditures	47,312		20,229
Accrued transportation, gathering, processing and compression	36,280		36,170
Other accrued liabilities	54,496		67,311
Total accounts payable and accrued liabilities	$	335,631	$	298,081

Supplemental Cash Flow and Non-Cash Information (in thousands)


	Six Months Ended June 30, 2025		Six Months Ended June 30, 2024
Supplemental disclosure of cash flow information:
Interest payments, net of amounts capitalized	$	23,191	$	28,263
Income taxes paid	$	2,400	$	—
Changes in operating assets and liabilities, net:
Accounts receivable - oil, natural gas, and natural gas liquid sales	$	27,328	$	28,133
Accounts receivable - joint interest and other	(3,021)		1,011
Accounts payable and accrued liabilities	(17,329)		(37,017)
Prepaid expenses	(3,060)		(649)
Other assets	(41)		31
Total changes in operating assets and liabilities, net	$	3,877	$	(8,491)
Supplemental disclosure of non-cash transactions:
Capitalized stock-based compensation	$	3,105	$	2,830
Asset retirement obligation capitalized	222		375
Asset retirement obligation removed due to settlements	(1,030)		—
Release of common stock held in reserve	—		1,996

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), which is reported on the consolidated statement of operations.

The measure of segment assets is reported on the consolidated balance sheets as “total assets”.

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The following tables present selected financial information with respect to the Company's one operating segment for the three and six months ended June 30, 2025 and 2024 (in thousands):


	Three Months Ended June 30, 2025		Three Months Ended June 30, 2024
Total revenues	$	447,616	$	181,117
Significant segment expenses
Lease operating expenses	17,628		15,817
Taxes other than income	7,556		7,018
Transportation, gathering, processing and compression	86,508		86,529
Depreciation, depletion, and amortization	73,643		78,553
General and administrative	10,926		10,752
Interest expense	13,731		15,158
Other segment expenses(1)	1,488		1,089
Income tax expense (benefit)	51,670		(7,587)
Total significant segment expenses	263,150		207,329
Net income (loss)	$	184,466	$	(26,212)

Capital expenditures(2)	$	139,543	$	149,733

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(1) Other segment expenses include “Accretion expense” and “Other, net” from the consolidated statements of operations.

(2) Capital expenditures include capitalized general and administrative costs and capitalized interest expense.


	Six Months Ended June 30, 2025		Six Months Ended June 30, 2024
Total revenues	$	644,650	$	464,346
Significant segment expenses
Lease operating expenses	37,911		32,625
Taxes other than income	14,182		15,278
Transportation, gathering, processing and compression	169,378		173,148
Depreciation, depletion, and amortization	139,265		158,576
General and administrative	19,927		19,950
Interest expense	27,087		30,161
Other segment expenses(1)	1,404		1,519
Income tax expense	51,494		7,266
Total significant segment expenses	460,648		438,523
Net income	$	184,002	$	25,823

Capital expenditures(2)	$	309,568	$	282,808

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(1) Other segment expenses include “Accretion expense” 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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3.PROPERTY AND EQUIPMENT

The major categories of property and equipment and related accumulated DD&A are as follows (in thousands):


	June 30, 2025		December 31, 2024
Proved oil and natural gas properties	$	3,669,584	$	3,349,805
Unproved properties	211,626		221,650
Other depreciable property and equipment	11,892		10,905
Land	386		386
Total property and equipment	3,893,488		3,582,746
Accumulated DD&A	(1,703,691)		(1,564,475)
Property and equipment, net	$	2,189,797	$	2,018,271

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 June 30, 2025 and 2024, 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 three or six months ended June 30, 2025 or 2024.

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 are charged to expense as they are incurred. Capitalized general and administrative costs were approximately $6.4 million and $12.7 million, for the three and six months ended June 30, 2025, respectively, and $6.3 million and $12.0 million for the three and six months ended June 30, 2024, respectively.

The Company evaluates the costs excluded from its amortization calculation at least annually. Individually insignificant unevaluated properties are grouped for evaluation and periodically transferred to evaluated properties over a timeframe consistent with their expected development schedule.

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


	June 30, 2025		December 31, 2024
Utica & Marcellus	$	188,190	$	197,513
SCOOP	23,436		24,137
Total unproved properties	$	211,626	$	221,650

Asset Retirement Obligation

The following table provides a reconciliation of the Company’s asset retirement obligation for the six months ended June 30, 2025 and 2024 (in thousands):


	Six Months Ended June 30, 2025		Six Months Ended June 30, 2024
Asset retirement obligation, beginning of period	$	32,949	$	29,941
Liabilities incurred	222		375
Liabilities settled	(1,673)		—
Accretion expense	1,205		1,122
Total asset retirement obligation, end of period	$	32,703	$	31,438

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4.LONG-TERM DEBT

Long-term debt consisted of the following items as of June 30, 2025 and December 31, 2024 (in thousands):


	June 30, 2025		December 31, 2024
6.750% senior unsecured notes due 2029	$	650,000	$	650,000
8.0% senior unsecured notes due 2026	—		25,702
Credit Facility due 2028	55,000		38,000
Net unamortized debt issuance costs	(9,846)		(10,845)
Total debt, net	695,154		702,857
Less: current maturities of long-term debt	—		—
Total long-term debt, net	$	695,154	$	702,857

2029 Senior Notes

In September 2024, Gulfport Operating completed a private offering of $650.0 million aggregate principal amount of 6.750% senior notes due September 1, 2029. The 2029 Senior Notes are guaranteed on a senior unsecured basis by the Company and each of the Company's subsidiaries that guarantee the Credit Facility. Interest on the 2029 Senior Notes is payable semi-annually, on March 1 and September 1 of each year.

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 and mature on September 1, 2029.

The 2029 Senior Notes Indenture contains covenants limiting Gulfport Operating’s and its restricted subsidiaries’ ability to (i) incur additional debt, (ii) make certain restricted payments, (iii) make certain investments, (iv) create restrictions on distributions from restricted subsidiaries, (v) engage in specified sales of assets, (vi) enter into certain transactions among affiliates, (vii) engage in consolidations, mergers and acquisitions, (viii) create unrestricted subsidiaries and (ix) incur or create liens. These covenants contain important exceptions, limitations and qualifications. At any time that the 2029 Senior Notes are rated investment grade, certain covenants will be terminated and cease to apply.

2026 Senior Notes

In May 2021, Gulfport Operating issued $550 million aggregate principal amount of its 8.0% senior notes due 2026. The notes were 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 was payable semi-annually, on June 1 and December 1 of each year. The 2026 Senior Notes were issued under the 2026 Senior Notes Indentures, dated as of May 17, 2021, by and among the Issuer, UMB Bank, National Association, as trustee, and the Guarantors and were scheduled to mature on May 17, 2026.

As noted above, in September 2024, Gulfport Operating purchased and retired $524.3 million of its 2026 Senior Notes in a tender offer using net proceeds from the 2029 Senior Notes offering. In May 2025, the Company redeemed the remaining balance of its 2026 Senior Notes, at par for $25.7 million. No additional fees or penalties were incurred as a result of the early redemption.

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Credit Facility

On May 1, 2023, the Company entered into that certain Joinder, Commitment Increase and Borrowing Base Redetermination Agreement, and Third Amendment to Credit Agreement (the “Third Amendment”) which amended the Company’s Credit Facility. The Third Amendment, among other things, (a) increased the aggregate elected commitment amounts under the Credit Facility from $700 million to $900 million, (b) increased the borrowing base under the Credit Facility from $1.0 billion to $1.1 billion, (c) increased the excess cash threshold under the Credit Facility from $45 million to $75 million, and (d) extended the maturity date under the Credit Facility from October 14, 2025, to the earlier of (i) May 1, 2027 and (ii) the 91st day prior to the maturity date of the 2026 Senior Notes or any other permitted senior notes or any permitted refinancing debt under the Credit Facility having an aggregate outstanding principal amount equal to or exceeding $100 million; provided that such notes have not been refinanced, redeemed or repaid in full on or prior to such 91st day. On April 18, 2024, Gulfport completed its semi-annual borrowing base redetermination during which the borrowing base was reaffirmed at $1.1 billion with elected commitments remaining at $900 million.

Prior to the Fourth Amendment (as defined below), the Credit Facility bore interest at a rate equal to, at the Company’s election, either (a) SOFR benchmark plus an applicable margin that varies from 2.75% to 3.75% per annum or (b) a base rate plus an applicable margin that varies from 1.75% to 2.75% per annum, based on borrowing base utilization. Prior to the Fourth Amendment, the Company was required to pay a commitment fee of 0.50% per annum on the average daily unused portion of the current aggregate commitments under the Credit Facility. The Company was also required to pay customary letter of credit and fronting fees.

Prior to the Fourth Amendment, the Credit Facility required the Company to maintain as of the last day of each fiscal quarter (i) a net funded leverage ratio of less than or equal to 3.25 to 1.00, and (ii) a current ratio of greater than or equal to 1.00 to 1.00.

On September 12, 2024, the Company entered into the Commitment Increase, Borrowing Base Reaffirmation Agreement, and Fourth Amendment to Credit Agreement (the “Fourth Amendment”), which amended the Company’s Third Amended and Restated Credit Agreement. The Fourth Amendment, among other things, (a) increased the aggregate elected commitment amounts under the Credit Facility to $1.0 billion, (b) reaffirmed the borrowing base under the Credit Facility at $1.1 billion, (c) extended the maturity date under the Credit Facility to September 12, 2028, and (d) reduced the pricing grid by 50 bps. On May 5, 2025, Gulfport completed its semi-annual borrowing base redetermination under its Credit Facility during which the borrowing base was reaffirmed at $1.1 billion with elected commitments remaining at $1.0 billion.

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 June 30, 2025, the Company had $55.0 million outstanding borrowings under the Credit Facility, $63.9 million in letters of credit outstanding and was in compliance with all covenants under the credit agreement.

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For the three and six months ended June 30, 2025, the Credit Facility bore interest at a weighted average rate of 6.77% and 6.77%, respectively. For the three and six months ended June 30, 2024, the Credit Facility bore interest at a weighted average rate of 8.33% and 8.33%, respectively.

The borrowing base is redetermined semiannually on or around May 1 and November 1 of each year.

Capitalization of Interest

The Company capitalized $1.4 million and $2.9 million in interest expense for the three and six months ended June 30, 2025, respectively and $1.2 million and $2.4 million for the three and six months ended June 30, 2024, respectively.

Fair Value of Debt

At June 30, 2025, the carrying value of the outstanding debt represented by the 2029 Senior Notes was $640.2 million. Based on the quoted market prices (Level 1), the fair value of the 2029 Senior Notes was determined to be $667.5 million at June 30, 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 ("the preferred stock").

Holders of preferred stock are entitled to receive cumulative quarterly dividends at a rate of 10% per annum of the Liquidation Preference with respect to cash dividends and 15% per annum of the Liquidation Preference with respect to dividends paid in kind as additional shares of preferred stock (“PIK Dividends”). Gulfport currently has the option to pay either cash dividends or PIK Dividends on a quarterly basis.

Each holder of shares of preferred stock has the right (the “Conversion Right”), at its option and at any time, to convert all or a portion of the shares of preferred stock that it holds into a number of shares of common stock equal to the quotient obtained by dividing (x) the product obtained by multiplying (i) the Liquidation Preference times (ii) an amount equal to one (1) plus the Per Share Makewhole Amount (as defined in the Preferred Terms) on the date of conversion, by (y) $14.00 per share (as may be adjusted under the Preferred Terms). The shares of preferred stock outstanding at June 30, 2025 would convert to approximately 2.2 million shares of common stock if all holders of preferred stock exercised their Conversion Right.

Gulfport may redeem all, but not less than all, of the outstanding shares of preferred stock by notice to the holders of preferred stock, at the greater of (i) the aggregate value of the preferred stock, calculated by the Current Market Price (as defined in the Preferred Terms) of the number of shares of common stock into which, subject to redemption, such preferred stock would have been converted if such shares were converted pursuant to the Conversion Right at the time of such redemption and (ii) the Liquidation Preference (the “Redemption Price”).

Following the Emergence Date, if there is a Fundamental Change (as defined in the Preferred Terms), Gulfport is required to redeem all, but not less than all, of the outstanding shares of preferred stock by cash payment of the Redemption Price per share of preferred stock within three (3) business days of the occurrence of such Fundamental Change. Notwithstanding the foregoing, in the event of a redemption pursuant to the preceding sentence, if Gulfport lacks sufficient cash to redeem all outstanding shares of preferred stock, the Company is required to redeem a pro rata portion of each holder’s shares of preferred stock.

The preferred stock has no stated maturity and will remain outstanding indefinitely unless repurchased or redeemed by Gulfport or converted into common stock.

The preferred stock has been classified as mezzanine equity in the accompanying consolidated balance sheets due to the redemption features noted above.

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Dividends and Conversions

The Company paid $0.8 million and $1.7 million of cash dividends to holders of our preferred stock during the three and six months ended June 30, 2025, respectively, and $1.1 million and $2.2 million during the three and six months ended June 30, 2024, respectively.

The following table summarizes activity of the Company’s preferred stock for the six months ended June 30, 2025 and 2024:


	Six Months Ended June 30, 2025	Six Months Ended June 30, 2024
Preferred stock, beginning of period	37,348	44,214
Conversion of preferred stock	(5,992)	(426)
Preferred stock, end of period	31,356	43,788

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.

Share 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 was subsequently increased to $1.0 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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The following tables summarize activity under the Repurchase Program for the three and six months ended June 30, 2025 and 2024 (dollar value of shares purchased shown in thousands):


	Three Months Ended June 30, 2025		Three Months Ended June 30, 2024
Total number of shares purchased	338,886		160,622
Dollar value of shares purchased	$	65,000	$	25,000
Average price paid per share	$	191.80	$	155.65


	Six Months Ended June 30, 2025		Six Months Ended June 30, 2024
Total number of shares purchased	679,550		370,697
Dollar value of shares purchased	$	125,000	$	54,492
Average price paid per share	$	183.95	$	147.00

As of June 30, 2025, the Company has repurchased 6.2 million shares for $709.1 million at a weighted average price of $113.48 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 equal to 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 three and six months ended June 30, 2025, the Company's stock-based compensation expense was $4.9 million and $9.4 million, respectively, of which the Company capitalized $1.6 million and $3.1 million, respectively, relating to its exploration and development efforts. During the three and six months ended June 30, 2024, the Company's stock-based compensation expense was $5.0 million and $8.6 million, respectively, of which the Company capitalized $1.6 million and $2.8 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 June 30, 2025, the Company has awarded an aggregate of approximately 516,354 restricted stock units and approximately 539,972 performance vesting restricted stock units under the Incentive Plan.

The following tables summarize activity for the six months ended June 30, 2025 and 2024:


	Number of Unvested Restricted Stock Units	Weighted Average Grant Date Fair Value		Number of Unvested Performance Vesting Restricted Stock Units	Weighted Average Grant Date Fair Value
Unvested shares as of January 1, 2025	167,014	$	115.67	178,139	$	92.06
Granted	61,350	169.80		41,016	165.39
Vested	(40,011)	112.93		—	—
Forfeited/canceled	(1,288)	126.93		—	—
Unvested shares as of March 31, 2025	187,065	$	133.93	219,155	$	105.78
Granted(1)	10,511	195.92		35,974	66.82
Vested	(39,463)	104.36		(71,948)	66.82
Forfeited/canceled	(994)	144.69		—	—
Unvested shares as of June 30, 2025	157,119	$	145.44	183,181	$	113.44

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(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 absolute TSR performance and RTSR performance compared to peers.


	Number of Unvested Restricted Stock Units	Weighted Average Grant Date Fair Value		Number of Unvested Performance Vesting Restricted Stock Units	Weighted Average Grant Date Fair Value
Unvested shares as of January 1, 2024	193,602	$	83.89	255,578	$	54.40
Granted	69,436	152.54		58,346	156.00
Vested	(17,720)	75.96		—	—
Forfeited/canceled	(747)	99.88		—	—
Unvested shares as of March 31, 2024	244,571	$	103.91	313,924	$	73.28
Granted(1)	6,040	155.61		130,012	48.65
Vested	(37,665)	95.83		(265,797)	48.65
Forfeited/canceled	(989)	117.19		—	—
Unvested shares as of June 30, 2024	211,957	$	106.75	178,139	$	92.06

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The aggregate fair value of share-based awards that vested during the three and six months ended June 30, 2025, was approximately $19.8 million and $26.8 million, respectively, based on the stock price at the time of vesting. During the three and six months ended June 30, 2024, the aggregate fair value of share-based awards that vested was approximately $48.1 million and $49.2 million, respectively, based on the stock price at the time of vesting.

In the three months ended June 30, 2025, upon vesting, the Company settled performance vesting restricted stock units awards that were granted in 2022 in cash. 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 June 30, 2025, was $18.3 million. The expense is expected to be recognized over a weighted average period of 2.08 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.

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The table below summarizes the assumptions used in the Monte Carlo simulation to determine the grant date fair value of awards granted during the six months ended June 30, 2025 and 2024:


Grant date	March 1, 2024	March 1, 2025
Forecast period (years)	3	3
Risk-free interest rates	4.36%	3.99%
Implied equity volatility	46.70%	44.60%

Unrecognized compensation expense as of June 30, 2025, related to performance vesting restricted shares was $11.1 million. The expense is expected to be recognized over a weighted average period of 1.94 years.

8.EARNINGS (LOSS) PER SHARE

Basic income or loss per share attributable to common stockholders is computed as (i) net income or loss less (ii) dividends paid to holders of preferred stock less (iii) net income or loss attributable to participating securities divided by (iv) weighted average basic shares outstanding. Diluted net income or loss per share attributable to common stockholders is computed as (i) basic net income or loss attributable to common stockholders plus (ii) diluted adjustments to income allocable to participating securities divided by (iii) weighted average diluted shares outstanding. The "if-converted" method is used to determine the dilutive impact for the Company's convertible preferred stock and the treasury stock method is used to determine the dilutive impact of unvested restricted stock.

There were 0.2 million and 0.2 million shares of restricted stock that were considered dilutive for the three and six months ended June 30, 2025, respectively. There were 0.3 million shares of restricted stock that were considered anti-dilutive for the three months ended June 30, 2024, and 0.4 million shares of restricted stock that were considered dilutive for the six months ended June 30, 2024. There were 2.2 million potential shares of common stock issuable due to the Company's convertible preferred stock as of June 30, 2025. There were 3.1 million potential shares of common stock issuable due to the Company's convertible preferred stock as of June 30, 2024.

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


	Three Months Ended June 30, 2025		Three Months Ended June 30, 2024
Net income (loss)	$	184,466	$	(26,212)
Dividends on preferred stock	(804)		(1,095)
Participating securities - preferred stock(1)	(20,622)		—
Net income (loss) attributable to common stockholders	$	163,040	$	(27,307)
Re-allocation of participating securities	205		—
Diluted net (loss) income attributable to common stockholders	$	163,245	$	(27,307)
Basic Shares	17,707		18,144
Dilutive Shares	17,907		18,144
Basic EPS	$	9.21	$	(1.51)
Dilutive EPS	$	9.12	$	(1.51)

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(1) Preferred stock represents participating securities because it participates in any dividends on shares of common stock on a pari passu, pro rata basis. However, preferred stock does not participate in undistributed net losses.

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	Six Months Ended June 30, 2025		Six Months Ended June 30, 2024
Net income	$	184,002	$	25,823
Dividends on preferred stock	(1,666)		(2,200)
Participating securities - preferred stock(1)	(20,385)		(3,469)
Net income attributable to common stockholders	$	161,951	$	20,154
Re-allocation of participating securities	217		64
Diluted net income attributable to common stockholders	$	162,168	$	20,218
Basic Shares	17,793		18,169
Dilutive Shares	18,009		18,573
Basic EPS	$	9.10	$	1.11
Dilutive EPS	$	9.01	$	1.09

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9.COMMITMENTS AND CONTINGENCIES

Commitments

Firm Transportation and Gathering Agreements

The Company has contractual commitments with midstream and pipeline companies for future gathering and transportation of natural gas from the Company's producing wells to downstream markets. Under certain of these agreements, the Company has minimum daily volume commitments. The Company is also obligated under certain of these arrangements to pay a demand charge for firm capacity rights on pipeline systems regardless of the amount of pipeline capacity utilized by the Company. If the Company does not utilize the capacity, it often can release it to other counterparties, thus reducing the cost of these commitments. Working interest owners and royalty interest owners, where appropriate, will be responsible for their proportionate share of these costs. Commitments related to future firm transportation and gathering agreements are not recorded as obligations in the accompanying consolidated balance sheets; however, costs associated with utilized future firm transportation and gathering agreements are reflected in the Company's estimates of proved reserves.

A summary of these commitments at June 30, 2025, are set forth in the table below (in thousands):


Remaining 2025	$	70,370
2026	136,581
2027	135,953
2028	138,121
2029	139,383
Thereafter	493,813
Total	$	1,114,221

Future Firm Sales Commitments

The Company has entered into various firm sales contracts to deliver and sell natural gas. The Company expects to fulfill its delivery commitments primarily with production from proved developed reserves. The Company's operated production has generally been sufficient to satisfy its delivery commitments during the periods presented, and it expects its operated production will continue to be the primary means of fulfilling its future commitments. However, where the Company's operated production is not sufficient to satisfy its delivery commitments, it can and may use spot market purchases to satisfy the commitments.

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A summary of these volume commitments at June 30, 2025, are set forth in the table below (MMBtu per day):


Remaining 2025			80,000
2026			75,000
2027			13,000
2028			—
Thereafter			—
Total			168,000

Contingencies

The Company is involved in a number of litigation and regulatory proceedings including those described below. Many of these proceedings are in early stages, and many of them seek or may seek damages and penalties, the amount of which is indeterminate. The Company's total accrued liabilities in respect of litigation and regulatory proceedings is determined on a case-by-case basis and represents an estimate of probable losses after considering, among other factors, the progress of each case or proceeding, its experience and the experience of others in similar cases or proceedings, and the opinions and views of legal counsel. Significant judgment is required in making these estimates and their final liabilities may ultimately be materially different. In accordance with ASC Topic 450, Contingencies, an accrual is recorded for a material loss contingency when its occurrence is probable and damages are reasonably estimable based on the anticipated most likely outcome or the minimum amount within a range of possible outcomes.

Litigation and Regulatory Proceedings

The Company, along with other oil and gas companies, have been named as a defendant in a number of lawsuits where Plaintiffs assert their respective leases are limited to the Utica/Marcellus shale geological formations and allege that Defendants have willfully trespassed and illegally produced oil, natural gas, and other hydrocarbon products beyond these respective formations. They also allege that Defendants engaged in conversion and were unjustly enriched. Plaintiffs seek the full value of any production from below the Utica/Marcellus shale formations, unspecified damages from the diminution of value to their mineral estate, unspecified punitive damages, and the payment of reasonable attorney fees, legal expenses, and interest. On April 27, 2021, the Bankruptcy Court for the Southern District of Texas approved a settlement agreement in which the plaintiffs fully released the Company from all claims that accrued and any damages related to the period before the effective date of the Company’s Chapter 11 plan, which occurred on May 17, 2021. The plaintiffs are continuing to pursue alleged damages after May 17, 2021.

The Company received Notice and Finding of Violations (“NOV/FOVs”) from the USEPA alleging violations of the Clean Air Act at 17 locations in Ohio between 2013 and 2019. On January 22, 2020, the Company entered a Consent Decree with the Department of Justice and USEPA addressing Gulfport's failure to capture and control air emissions from storage vessels and to comply with associated inspection, recordkeeping, and reporting requirements. During the process of terminating the Consent Decree, the Company was informed that there were untimely repairs on a number of locations subject to the Company's Consent Decree that failed to comply with Subpart OOOO or Permit to Install and Operate Applications. On July 31, 2024, the Company received a NOV/FOV from USEPA related to the alleged untimely repairs. While these repairs have been completed, resolution of the matter may result in monetary sanctions exceeding $300,000.

In November 2020, Robert T. Stephenson and Sandra J. Bass, as the Successor Co-Trustees of the Robert L. Stephenson Living Trust, dated January 28, 2004, and express trust; and Norma E. Stephenson, Trustee of the Norma E. Stephenson Living Trust, dated July 29, 1991, and express trust filed an action against the Company in the District Court of Grady County in the State of Oklahoma. In June 2021 the case was removed to the United States District Court for the Western District of Oklahoma. The complaint alleges that the Company has failed to comply with a Letter Agreement from April 1979 granting an overriding royalty interest covering 16 sections (approximately 10,240 acres). The plaintiffs seek quiet title, declaratory judgment, breach of contract, specific performance, and damages under the Oklahoma Production Revenue Standards Act. Given the nature of this matter, the Company is unable to reasonably estimate the total possible loss or ranges of loss. The Company believes it has strong defenses to these claims and intends to vigorously defend this matter; however, an adverse decision could have a material effect on the Company, its financial condition, results of operations, and cash flows.

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In January 2025, Grace E. Moore Great Grandchildren Trust of 2006, Joseph Gorsha, Damon Faldowski, Damon Faldowski II, and Mark Faldowski, individually and on behalf of all others similarly situated, filed a class action against Gulfport and another natural gas producer in the United States District Court, Southern District of Ohio, Eastern Division. The lawsuit alleges, among other things, that defendants underpaid royalties to the plaintiffs in connection with the production and sale of natural gas and NGL involving a variety of lease forms. The lawsuit seeks compensatory damages, injunctive relief regarding royalty payment practices, restitution, disgorgement of profits, prejudgment interest, post-judgment interest, attorney’s fees, and costs. In April 2025, the United States Court of Appeals for the Sixth Circuit ruled that another operator in Ohio could not deduct certain processing and fractionation charges under one lease form that included a version of a market enhancement clause. Given the preliminary nature of this action, we are currently unable to estimate what liability may result from this matter.

Business Operations

The Company is involved in various lawsuits and disputes incidental to its business operations, including commercial disputes, personal injury claims, royalty claims, property damage claims and contract actions.

Environmental Contingencies

The nature of the oil and gas business carries with it certain environmental risks for Gulfport and its subsidiaries. Gulfport and its subsidiaries have implemented various policies, programs, procedures, training and audits to reduce and mitigate environmental risks. The Company conducts periodic reviews, on a company-wide basis, to assess changes in its environmental risk profile. Environmental reserves are established for environmental liabilities for which economic losses are probable and reasonably estimable. The Company manages its exposure to environmental liabilities in acquisitions by using an evaluation process that seeks to identify pre-existing contamination or compliance concerns and address the potential liability. Depending on the extent of an identified environmental concern, it may, among other things, exclude a property from the transaction, require the seller to remediate the property to its satisfaction in an acquisition or agree to assume liability for the remediation of the property.

Other Matters

Based on management’s current assessment, they are of the opinion that no pending or threatened lawsuit or dispute relating to its business operations is likely to have a material adverse effect on their future consolidated financial position, results of operations or cash flows. The final resolution of such matters could exceed amounts accrued, however, and actual results could differ materially from management’s estimates.

10.DERIVATIVE INSTRUMENTS

Natural Gas, Oil and NGL Derivative Instruments

The Company seeks to mitigate risks related to unfavorable changes in natural gas, oil and NGL prices, which are subject to significant and often volatile fluctuation, by entering into over-the-counter fixed price swaps, basis swaps, costless collars and various types of option contracts. These contracts allow the Company to mitigate the impact of declines in future natural gas, oil and NGL prices by effectively locking in a floor price for a certain level of the Company’s production. However, these hedge contracts also limit the benefit to the Company in periods of favorable price movements.

The volume of production subject to commodity derivative instruments and the mix of the instruments are frequently evaluated and adjusted by management in response to changing market conditions. Gulfport may enter into commodity derivative contracts up to limitations set forth in its Credit Facility. The Company generally enters into commodity derivative contracts for approximately 30% to 70% of its forecasted current year annual production by the end of the first quarter of each fiscal year. The Company typically enters into commodity derivative contracts for the next 12 to 36 months. Gulfport does not enter into commodity derivative contracts for speculative purposes.

The Company does not currently have any commodity derivative transactions that have margin requirements or collateral provisions that would require payments prior to the scheduled settlement dates. The Company's commodity derivative contract counterparties are typically financial institutions and energy trading firms with investment-grade credit ratings. Gulfport routinely monitors and manages its exposure to counterparty risk by requiring specific minimum credit standards for all counterparties, actively monitoring counterparties' public credit ratings and avoiding the concentration of credit exposure by transacting with multiple counterparties. The Company has master netting agreements with some counterparties that allow the offsetting of receivables and payables in a default situation. As of June 30, 2025, our commodity derivative contracts were spread among 12 counterparties.

Fixed price swaps require that the Company receive a fixed price and pay a floating market price to the counterparty for the hedged commodity. They are settled monthly based on differences between the fixed price specified in the contract and the referenced settlement price. When the referenced settlement price is less than the price specified in the contract, the Company receives an amount from the counterparty based on the price difference multiplied by the volume. Similarly, when the referenced settlement price exceeds the price specified in the contract, the Company pays the counterparty an amount based on the price difference multiplied by the volume.

The Company has entered into natural gas, crude oil and NGL fixed price swap contracts based off the NYMEX Henry Hub, NYMEX WTI and Mont Belvieu C3 indices. Below is a summary of the Company’s open fixed price swap positions as of June 30, 2025.


	Index	Daily Volume	Weighted Average Price
Natural Gas		(MMBtu/d)	($/MMBtu)
Remaining 2025	NYMEX Henry Hub	270,000	$	3.82
2026	NYMEX Henry Hub	250,000	$	3.77
2027	NYMEX Henry Hub	80,000	$	3.94

Oil		(Bbl/d)	($/Bbl)
Remaining 2025	NYMEX WTI	3,000	$	73.29

NGL		(Bbl/d)	($/Bbl)
Remaining 2025	Mont Belvieu C3	3,000	$	29.89
2026	Mont Belvieu C3	2,496	$	30.91

Each two-way costless collar has a set floor and ceiling price for the hedged production. They are settled monthly based on differences between the floor and ceiling prices specified in the contract and the referenced settlement price. If the applicable monthly price indices are outside of the ranges set by the floor and ceiling prices in the collar contracts, the Company will cash-settle the difference with the hedge counterparty. When the referenced settlement price is less than the floor price in the contract, the Company receives an amount from the counterparty based on the price difference multiplied by the hedged contract volume. Similarly, when the referenced settlement price exceeds the ceiling price specified in the contract, the Company pays the counterparty an amount based on the price difference multiplied by the hedged contract volume. No payment is due from either party if the referenced settlement price is within the range set by the floor and ceiling prices.

The Company has entered into natural gas costless collars based off the NYMEX Henry Hub index. Below is a summary of the Company's costless collar positions as of June 30, 2025.


	Index	Daily Volume	Weighted Average Floor Price		Weighted Average Ceiling Price
Natural Gas		(MMBtu/d)	($/MMBtu)		($/MMBtu)
Remaining 2025	NYMEX Henry Hub	240,000	$	3.42	$	4.27
2026	NYMEX Henry Hub	170,000	$	3.63	$	4.48
2027	NYMEX Henry Hub	80,000	$	3.75	$	4.28

From time to time, the Company has sold natural gas call options in exchange for a premium, and used the associated premiums received to enhance the fixed price for a portion of the fixed price natural gas swaps. Each sold call option has an established ceiling price. If at the time of settlement the referenced settlement price exceeds the ceiling price, the Company pays its counterparty an amount equal to the difference between the referenced settlement price and the price ceiling multiplied by the hedged contract volumes. No payment is due from either party if the referenced settlement price is below the price ceiling. Below is a summary of the Company's open sold call option positions as of June 30, 2025.

Index

Daily Volume

Weighted Average Price

Natural Gas

(MMBtu/d)

($/MMBtu)

Remaining 2025

NYMEX Henry Hub

186,739

5.84

In addition, the Company has entered into natural gas basis swap positions. These instruments are arrangements that guarantee a fixed price differential to NYMEX Henry Hub from a specified delivery point. The Company receives the fixed price differential and pays the floating market price differential to the counterparty for the hedged commodity. As of June 30, 2025, the Company had the following natural gas basis swap positions open:


	Gulfport Pays	Gulfport Receives	Daily Volume	Weighted Average Fixed Spread
Natural Gas			(MMBtu/d)	($/MMBtu)
Remaining 2025	Rex Zone 3	NYMEX Plus Fixed Spread	110,000	$	(0.20)
Remaining 2025	NGPL TXOK	NYMEX Plus Fixed Spread	40,000	$	(0.29)
Remaining 2025	TETCO M2	NYMEX Plus Fixed Spread	230,000	$	(0.96)
Remaining 2025	Transco Station 85	NYMEX Plus Fixed Spread	10,000	$	0.45
Remaining 2025	TGP 500	NYMEX Plus Fixed Spread	20,000	$	0.41
2026	Rex Zone 3	NYMEX Plus Fixed Spread	80,000	$	(0.18)
2026	NGPL TXOK	NYMEX Plus Fixed Spread	30,000	$	(0.30)
2026	TETCO M2	NYMEX Plus Fixed Spread	130,000	$	(0.98)
2026	Transco Station 85	NYMEX Plus Fixed Spread	10,000	$	0.56
2026	TGP 500	NYMEX Plus Fixed Spread	20,000	$	0.56

Balance Sheet Presentation

The Company reports the fair value of derivative instruments on the consolidated balance sheets as derivative instruments under current assets, noncurrent assets, current liabilities and noncurrent liabilities on a gross basis. The Company determines the current and noncurrent classification based on the timing of expected future cash flows of individual trades. The following table presents the fair value of the Company’s derivative instruments on a gross basis at June 30, 2025 and December 31, 2024 (in thousands):


	June 30, 2025		December 31, 2024
Short-term derivative asset	$	44,191	$	58,085
Long-term derivative asset	20,906		6,003
Short-term derivative liability	(53,184)		(41,889)
Long-term derivative liability	(44,793)		(35,081)
Total commodity derivative position	$	(32,880)	$	(12,882)

Gains and Losses

The following tables present the gain and loss recognized in net gain (loss) on natural gas, oil and NGL derivatives in the accompanying consolidated statements of operations for the three and six months ended June 30, 2025 and 2024 (in thousands):


	Net gain (loss) on derivative instruments
	Three Months Ended June 30, 2025		Three Months Ended June 30, 2024
Natural gas derivatives - fair value gains (losses)	$	108,909	$	(99,871)
Natural gas derivatives - settlement gains	17,295		91,251
Total gains (losses) on natural gas derivatives	126,204		(8,620)

Oil derivatives - fair value gains	2,315		595
Oil derivatives - settlement gains (losses)	2,411		(271)
Total gains on oil and condensate derivatives	4,726		324

NGL derivatives - fair value gains (losses)	5,437		(82)
NGL derivatives - settlement losses	(266)		(237)
Total gains (losses) on NGL derivatives	5,171		(319)

Total gains (losses) on natural gas, oil and NGL derivatives	$	136,101	$	(8,615)


	Net gain (loss) on derivative instruments
	Six Months Ended June 30, 2025		Six Months Ended June 30, 2024
Natural gas derivatives - fair value losses	$	(24,755)	$	(111,349)
Natural gas derivatives - settlement gains	8,270		157,702
Total (losses) gains on natural gas derivatives	(16,485)		46,353

Oil derivatives - fair value gains (losses)	2,309		(1,865)
Oil derivatives - settlement gains (losses)	2,915		(259)
Total gains (losses) on oil and condensate derivatives	5,224		(2,124)

NGL derivatives - fair value gains (losses)	2,449		(6,330)
NGL derivatives - settlement losses	(1,635)		(1,378)
Total gains (losses) on NGL derivatives	814		(7,708)

Total (losses) gains on natural gas, oil and NGL derivatives	$	(10,447)	$	36,521

Offsetting of Derivative Assets and Liabilities

As noted above, the Company records the fair value of derivative instruments on a gross basis. The following tables present the gross amounts of recognized derivative assets and liabilities in the consolidated balance sheets and the amounts that are subject to offsetting under master netting arrangements with counterparties, all at fair value (in thousands):


	As of June 30, 2025
	Gross Assets (Liabilities) Presented in the Consolidated Balance Sheets		Gross Amounts Subject to Master Netting Agreements		Net Amount
Derivative assets	$	65,097	$	(61,261)	$	3,836
Derivative liabilities	$	(97,977)	$	61,261	$	(36,716)


	As of December 31, 2024
	Gross Assets (Liabilities) Presented in the Consolidated Balance Sheets		Gross Amounts Subject to Master Netting Agreements		Net Amount
Derivative assets	$	64,088	$	(49,343)	$	14,745
Derivative liabilities	$	(76,970)	$	49,343	$	(27,627)

Concentration of Credit Risk

By using derivative instruments that are not traded on an exchange, the Company is exposed to the credit risk of its counterparties. Credit risk is the risk of loss from counterparties not performing under the terms of the derivative instrument. When the fair value of a derivative instrument is positive, the counterparty is expected to owe the Company, which creates credit risk. To minimize the credit risk in derivative instruments, it is the Company’s policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers. The Company’s derivative contracts are spread between multiple counterparties to lessen its exposure to any individual counterparty. Additionally, the Company uses master netting agreements to minimize credit risk exposure. The creditworthiness of the Company’s counterparties is subject to periodic review. None of the Company’s derivative instrument contracts contain credit-risk related contingent features. Other than as provided by the Company’s revolving credit facility, the Company is not required to provide credit support or collateral to any of its counterparties under its derivative instruments, nor are the counterparties required to provide credit support to the Company.

11.FAIR VALUE MEASUREMENTS

The Company records certain financial and non-financial assets and liabilities on the balance sheet at fair value. Fair value is the price that would be received to sell an asset or paid to transfer a liability (exit price) in an orderly transaction between market participants at the measurement date. Market or observable inputs are the preferred sources of values, followed by assumptions based on hypothetical transactions in the absence of market inputs. Fair value measurements are classified and disclosed in one of the following categories:

Level 1 – Quoted prices (unadjusted) in active markets for identical assets and liabilities that the Company has the ability to access at the measurement date.

Level 2 – Quoted prices in active markets for similar assets and liabilities, quoted prices for identical or similar instruments in markets that are not active and model-derived valuations whose inputs are observable or whose significant value drivers are observable.

Level 3 – Significant inputs to the valuation model are unobservable.

Valuation techniques that maximize the use of observable inputs are favored. Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the fair value hierarchy. Reclassifications of fair value between Level 1, Level 2 and Level 3 of the fair value hierarchy, if applicable, are made at the end of each quarter.

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Financial assets and liabilities

The following tables summarize the Company’s financial and non-financial assets and liabilities by valuation level as of June 30, 2025 and December 31, 2024 (in thousands):


	June 30, 2025
	Level 1		Level 2		Level 3
Assets:
Derivative instruments	$	—	$	65,097	$	—
Contingent consideration arrangement	—		—		2,100
Total assets	$	—	$	65,097	$	2,100
Liabilities:
Derivative instruments	$	—	$	97,977	$	—


	December 31, 2024
	Level 1		Level 2		Level 3
Assets:
Derivative instruments	$	—	$	64,088	$	—
Contingent consideration arrangement	—		—		2,700
Total assets	$	—	$	64,088	$	2,700
Liabilities:
Derivative instruments	$	—	$	76,970	$	—

The Company estimates the fair value of all derivative instruments using industry-standard models that consider various assumptions, including current market and contractual prices for the underlying instruments, implied volatility, time value, nonperformance risk, as well as other relevant economic measures. Substantially all of these inputs are observable in the marketplace throughout the full term of the instrument and can be supported by observable data.

The Company's SCOOP water infrastructure sale, which closed in the first quarter of 2020, included a contingent consideration arrangement. As of June 30, 2025, the fair value of the contingent consideration was $2.1 million, of which $0.1 million is included in prepaid expenses and other assets and $2.0 million is included in other assets in the accompanying consolidated balance sheets. The fair value of the contingent consideration arrangement is calculated using discounted cash flow techniques and is based on internal estimates of the Company's future development program and water production levels. Given the unobservable nature of the inputs, the fair value measurement of the contingent consideration arrangement is deemed to use Level 3 inputs. The Company records changes in fair value in earnings. The fair value of the contingent consideration arrangement decreased $0.4 million and $0.5 million for the three and six months ended June 30, 2025. The Company did not recognize a gain or loss for the three and six months ended June 30, 2024 with respect to this contingent consideration arrangement. These fair value changes are included in Other, net in the accompanying consolidated statements of operations.

Non-financial assets and liabilities

The initial measurement of asset retirement obligations at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with oil and gas properties. Given the unobservable nature of the inputs, including plugging costs and reserve lives, the initial measurement of the asset retirement obligation liability is deemed to use Level 3 inputs. See Note 3 for further discussion of the Company’s asset retirement obligations.

Fair value of other financial instruments

The carrying amounts on the accompanying consolidated balance sheet for cash and cash equivalents, accounts receivable, and accounts payable and accrued liabilities are carried at cost, which approximates market value due to their short-term nature. Long-term debt related to the Company's Credit Facility is carried at cost, which approximates market value based on the borrowing rates currently available to the Company with similar terms and maturities.

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12.REVENUE FROM CONTRACTS WITH CUSTOMERS

Revenue Recognition

The Company’s revenues are primarily derived from the sale of natural gas, oil, 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 $128.6 million and $155.9 million as of June 30, 2025 and December 31, 2024, respectively, and are reported in accounts receivable - oil, natural gas, and natural gas liquids sales in the accompanying consolidated balance sheets. The Company currently has no assets or liabilities related to its revenue contracts, including no upfront or rights to deficiency payments.

Prior-Period Performance Obligations

The Company records revenue in the month production is delivered to the purchaser. However, settlement statements for certain sales may be received for 30 to 90 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production that was delivered to the purchaser and the price that will be received for the sale of the product. The differences between the estimates and the actual amounts for product sales is recorded in the month that payment is received from the purchaser. For each of the periods presented, revenue recognized in the reporting periods related to performance obligations satisfied in prior reporting periods was not material.

13.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.

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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. At June 30, 2025, the Company did not have any active long-term drilling rig contracts.

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 June 30, 2025 were as follows (in thousands):


Remaining 2025	$	418
2026	561
2027	10
2028	—
2029	—
Total lease payments	$	989
Less: imputed interest	(33)
Total	$	956

Lease costs incurred for the three and six months ended June 30, 2025 and 2024, consisted of the following (in thousands):


	Three Months Ended June 30, 2025		Three Months Ended June 30, 2024
Operating lease cost	$	209	$	3,403
Variable lease cost	—		—
Short-term lease cost	7,472		5,998
Total lease cost(1)	$	7,681	$	9,401


	Six Months Ended June 30, 2025		Six Months Ended June 30, 2024
Operating lease cost	$	1,635	$	6,806
Variable lease cost	—		—
Short-term lease cost	16,382		15,949
Total lease cost(1)	$	18,017	$	22,755

_____________________

(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 June 30, 2025 was 1.20 years. The weighted average discount rate used to determine the operating lease liability as of June 30, 2025 was 6.10%.

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14.INCOME TAXES

The Company records its quarterly tax provision based on an estimate of the annual effective tax rate expected to apply to continuing operations for the various jurisdictions in which it operates. The tax effects of certain items, such as tax rate changes, significant unusual or infrequent items, and certain changes in the assessment of the realizability of deferred taxes, are recognized as discrete items in the period in which they occur and are excluded from the estimated annual effective tax rate.

The Company's effective income tax rate was 21.9% and 21.9% for the three and six months ended June 30, 2025, respectively, and 22.8% and 22.0% for the three and six months June 30, 2024, respectively. The difference between the actual rate and the statutory rate for the three and six months ended June 30, 2025 is primarily related to the deferred state tax expense recorded during the period.

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. The Company has an $82.6 million valuation allowance associated with its federal and state deferred tax assets.

The Company will continue to evaluate both the positive and negative evidence on a quarterly basis in determining the need for a valuation allowance with respect to the deferred 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.

15.RELATED PARTY TRANSACTIONS

Share Repurchase Program

On March 20, 2024, the Company purchased 97,219 shares of its common stock from Silver Point Capital, L.P. for approximately $15.0 million. The repurchase is part of the Company's existing share Repurchase Program. Upon closing of the transaction on March 22, 2024, the repurchased common stock was canceled.

On May 14, 2025, the Company purchased 76,986 shares of its common stock from Silver Point Capital, L.P. for approximately $15.0 million. The repurchase is part of the Company's existing share Repurchase Program. Upon closing of the transaction on May 20, 2025, the repurchased common stock was canceled.

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16.SUBSEQUENT EVENTS

Natural Gas, Oil and NGL Derivative Instruments

Subsequent to June 30, 2025, as of July 30, 2025, the Company entered into the following derivative contracts:

Period

Type of Derivative Instrument

Index

Daily Volume

Weighted
Average Price

Natural Gas

(MMBtu/d)

($/MMBtu)

2027

Costless Collar

NYMEX Henry Hub

10,000

$3.75 / $4.52

2027

Swaps

NYMEX Henry Hub

10,000

$4.04

2027

Basis Swaps

TETCO M2

20,000

$(0.97)

2027

Basis Swaps

NGPL TXOK

10,000

$(0.29)

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 may be relevant to the Company include modifications to the limitations on the deductibility of interest expense under Section 163(j) of the Internal Revenue Code, changes to the treatment of research and development expenditures under Section 174A of the Internal Revenue Code and adjustments to bonus depreciation rules.

The Company is currently assessing the potential impact of the OBBBA. The effects of the legislation will be reflected in the Company’s financial statements in the period that includes the enactment date, which is the third quarter of 2025.

Expanded Common Stock Repurchase Program

On August 4, 2025, the Company's Board of Directors approved an increase to the authorized Repurchase Program from $1.0 billion to $1.5 billion (including the redemption of preferred stock noted below) and extended the authorization through December 31, 2026.

Redemption of Preferred Stock

On August 5, 2025, Gulfport issued a notice of redemption for its preferred stock for cash. The optional redemption will be effective on September 5, 2025 (the "Redemption Date") with respect to any shares of the preferred stock that have not been converted and remain outstanding at that date. Shares of preferred stock may be converted to common stock pursuant to their terms up to, but not including, the Redemption Date. The total cash amount payable by Gulfport in connection with the redemption will vary depending on the number of shares of preferred stock converted prior to the Redemption Date and the price of Gulfport's common stock.

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ITEM 2.MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Introduction

Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A) is intended to provide the reader of the financial statements with a narrative from the perspective of management on the financial condition, results of operations, liquidity and certain other factors that may affect the Company's operating results. MD&A should be read in conjunction with the financial statements and related Notes included in Part I, Item 1 of this Quarterly Report on Form 10-Q.

The following information updates the discussion of Gulfport’s financial condition provided in its Annual Report on Form 10-K for the year ended December 31, 2024 (“2024 Form 10-K”) and analyzes the changes in the results of operations between the periods of April 1, 2025 through June 30, 2025, January 1, 2025 through June 30, 2025, April 1, 2024 through June 30, 2024 and January 1, 2024 through June 30, 2024. For definitions of commonly used natural gas and oil terms found in this Quarterly Report on Form 10-Q, please refer to the “Definitions” provided in this report.

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 are located in eastern Ohio targeting the Utica and Marcellus and in central Oklahoma targeting the SCOOP Woodford and Springer formations. 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 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

Credit Facility

On May 5, 2025, Gulfport completed its semi-annual borrowing base redetermination under its Credit Facility during which the borrowing base was reaffirmed at $1.1 billion with elected commitments remaining at $1.0 billion.

Share Repurchase Program and Redemption of Preferred Stock

During the three months ended June 30, 2025, the Company repurchased 338,886 shares for $65.0 million at a weighted average price of $191.80 per share. As of June 30, 2025, the Company repurchased 6.2 million shares for $709.1 million at a weighted average price of $113.48 per share since the inception of the Repurchase Program.

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Tariffs and Trading Relationships

Since the initial U.S. government announcement regarding tariffs in April 2025, the U.S. government has subsequently announced and modified, delayed or rescinded multiple tariffs on several foreign jurisdictions, which has increased uncertainty regarding the ultimate effect of the tariffs on economic conditions. For example, the U.S. government has recently threatened 30% tariffs on imports from certain countries (including Mexico and the European Union), and certain other countries have likewise threatened, and in some cases implemented, tariffs on U.S. goods. Current uncertainties about tariffs and their effects on trading relationships may affect costs for and availability of raw materials, contribute to inflation in the markets in which we operate, delay access to capital markets and increase the likelihood of an economic downturn. Although we are continuing to monitor the economic effects of such announcements, as well as opportunities to mitigate their related impacts, costs and other effects associated with the tariffs and retaliatory tariffs remain uncertain pending their implementation.

2025 Operational and Financial Highlights

During the second quarter of 2025, we had the following notable achievements:

•Reported total net production of 1,006.3 MMcfe per day.

•Turned to sales 14 gross (13.8 net) operated wells.

•Generated $231.4 million of operating cash flows.

•Repurchased 338,886 shares for $65.0 million at a weighted average price of $191.80 per share.

•Exited the quarter with total liquidity of $884.9 million.

2025 Production and Drilling Activity

Production Volumes


	Three Months Ended June 30, 2025	Three Months Ended June 30, 2024
Natural gas (Mcf/day)
Utica & Marcellus	736,420	816,935
SCOOP	154,939	155,552
Total	891,359	972,487
Oil and condensate (Bbl/day)
Utica & Marcellus	6,135	977
SCOOP	1,708	1,770
Total	7,843	2,747
NGL (Bbl/day)
Utica & Marcellus	4,555	2,349
SCOOP	6,759	7,845
Total	11,313	10,195
Combined (Mcfe/day)
Utica & Marcellus	800,557	836,892
SCOOP	205,742	213,245
Total	1,006,299	1,050,137
Totals may not sum or recalculate due to rounding.

Our total net production averaged approximately 1,006.3 MMcfe per day during the three months ended June 30, 2025, as compared to 1,050.1 MMcfe per day during the three months ended June 30, 2024. Production per day declined primarily due to natural declines resulting from the timing of our 2024 and 2025 development programs and the impact of unplanned, third-party midstream outages and constraints.

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	Six Months Ended June 30, 2025	Six Months Ended June 30, 2024
Natural gas (Mcf/day)
Utica & Marcellus	711,829	814,146
SCOOP	152,907	158,879
Total	864,735	973,025
Oil and condensate (Bbl/day)
Utica & Marcellus	5,005	1,163
SCOOP	1,565	1,875
Total	6,570	3,038
NGL (Bbl/day)
Utica & Marcellus	4,028	2,165
SCOOP	6,614	7,948
Total	10,641	10,113
Combined (Mcfe/day)
Utica & Marcellus	766,023	834,112
SCOOP	201,979	217,817
Total	968,002	1,051,929
Totals may not sum or recalculate due to rounding.

Our total net production averaged approximately 968.0 MMcfe per day during the six months ended June 30, 2025, as compared to 1,051.9 MMcfe per day during the six months ended June 30, 2024. Production per day declined primarily due to natural declines partially offset by our 2024 and 2025 development programs and the impact of unplanned, third-party midstream outages and constraints.

Utica/Marcellus. We spud four gross (4.0 net) wells targeting the Utica formation during the three months ended June 30, 2025. In addition, we commenced sales on eight gross (8.0 net) operated Utica wells and four gross (4.0 net) operated Marcellus wells.

As of July 30, 2025, we had one operated drilling rig running in Ohio drilling the Utica formation.

SCOOP. We did not spud any operated wells in the SCOOP during the three months ended June 30, 2025. We commenced sales on two gross (1.8 net) operated SCOOP wells.

As of July 30, 2025, we did not have an operated drilling rig running in the SCOOP.

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RESULTS OF OPERATIONS

Comparison of the Three Month Periods Ended June 30, 2025 and 2024

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

The following table summarizes our natural gas, oil and condensate and NGL production and related pricing for the three months ended June 30, 2025 as compared to the three months ended June 30, 2024. Some totals below may not sum or recalculate due to rounding.


	Three Months Ended June 30, 2025		Three Months Ended June 30, 2024
Natural gas sales
Natural gas production volumes (MMcf)	81,114		88,496
Natural gas production volumes (MMcf) per day	891		972
Total sales	$	241,236	$	144,458
Average price without the impact of derivatives ($/Mcf)	$	2.97	$	1.63
Impact from settled derivatives ($/Mcf)	$	0.22	$	1.03
Average price, including settled derivatives ($/Mcf)	$	3.19	$	2.66

Oil and condensate sales
Oil and condensate production volumes (MBbl)	714		250
Oil and condensate production volumes (MBbl) per day	8		3
Total sales	$	41,543	$	19,127
Average price without the impact of derivatives ($/Bbl)	$	58.20	$	76.51
Impact from settled derivatives ($/Bbl)	$	3.38	$	(1.08)
Average price, including settled derivatives ($/Bbl)	$	61.58	$	75.43

NGL sales
NGL production volumes (MBbl)	1,030		928
NGL production volumes (MBbl) per day	11		10
Total sales	$	28,736	$	26,147
Average price without the impact of derivatives ($/Bbl)	$	27.91	$	28.18
Impact from settled derivatives ($/Bbl)	$	(0.26)	$	(0.25)
Average price, including settled derivatives ($/Bbl)	$	27.65	$	27.93

Natural gas, oil and condensate and NGL sales
Natural gas equivalents (MMcfe)	91,573		95,562
Natural gas equivalents (MMcfe) per day	1,006		1,050
Total sales	$	311,515	$	189,732
Average price without the impact of derivatives ($/Mcfe)	$	3.40	$	1.99
Impact from settled derivatives ($/Mcfe)	$	0.21	$	0.94
Average price, including settled derivatives ($/Mcfe)	$	3.61	$	2.93

Production Costs:
Average lease operating expenses ($/Mcfe)	$	0.19	$	0.17
Average taxes other than income ($/Mcfe)	$	0.08	$	0.07
Average transportation, gathering, processing and compression ($/Mcfe)	$	0.94	$	0.91
Total lease operating expenses, taxes other than income and midstream costs ($/Mcfe)	$	1.22	$	1.14

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Natural Gas, Oil and Condensate and NGL Sales (in thousands)


	Three Months Ended June 30, 2025		Three Months Ended June 30, 2024		% Change
Natural gas	$	241,236	$	144,458	67	%
Oil and condensate	41,543		19,127		117	%
NGL	28,736		26,147		10	%
Natural gas, oil and condensate and NGL sales	$	311,515	$	189,732	64	%

The increase in natural gas sales without the impact of derivatives, when comparing the three months ended June 30, 2025 to the three months ended June 30, 2024 was due to a 82% increase in realized prices, partially offset by a 8% decrease in sales volumes. The realized price change was primarily driven by the increase in the average Henry Hub gas index from $1.89 per Mcf in the three months ended June 30, 2024, to $3.44 per Mcf during the three months ended June 30, 2025. The 8% decrease in natural gas production was primarily due to natural declines partially offset by our 2024 and 2025 development programs and the impact of unplanned, third-party midstream outages and constraints.

The increase in oil and condensate sales without the impact of derivatives, when comparing the three months ended June 30, 2025 to the three months ended June 30, 2024, was due to a 186% increase in sales volumes, partially offset by a 24% decrease in realized prices. The 186% increase in oil and condensate production was primarily due to commencement of sales on new wells targeting the Utica liquids window. The realized price change was primarily driven by the decrease in the average WTI crude index from $80.57 per barrel in the three months ended June 30, 2024, to $63.74 per barrel during the three months ended June 30, 2025.

The increase in NGL sales without the impact of derivatives, when comparing the three months ended June 30, 2025 to the three months ended June 30, 2024, was due to a 11% increase in sales volumes. The 11% increase in NGL production was primarily due to commencement of sales on new wells targeting the Utica liquids window.

Natural Gas, Oil and NGL Derivatives (in thousands)


	Three Months Ended June 30, 2025		Three Months Ended June 30, 2024
Natural gas derivatives - fair value gains (losses)	$	108,909	$	(99,871)
Natural gas derivatives - settlement gains	17,295		91,251
Total gains (losses) on natural gas derivatives	126,204		(8,620)

Oil derivatives - fair value gains	2,315		595
Oil derivatives - settlement gains (losses)	2,411		(271)
Total gains on oil and condensate derivatives	4,726		324

NGL derivatives - fair value gains (losses)	5,437		(82)
NGL derivatives - settlement losses	(266)		(237)
Total gains (losses) on NGL derivatives	5,171		(319)

Total gains (losses) on natural gas, oil and NGL derivatives	$	136,101	$	(8,615)

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 (loss) for the three months ended June 30, 2025 compared to the three months ended June 30, 2024, was primarily the result of changes in futures pricing for oil, natural gas, and NGLs during each period. See Note 10 of our consolidated financial statements for hedged volumes and pricing.

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Lease Operating Expenses (in thousands, except per unit)


	Three Months Ended June 30, 2025		Three Months Ended June 30, 2024		% Change
Lease operating expenses
Utica & Marcellus	$	12,421	$	10,717	16	%
SCOOP	5,207		5,100		2	%
Total lease operating expenses	$	17,628	$	15,817	11	%

Lease operating expenses per Mcfe
Utica & Marcellus	$	0.17	$	0.14	21	%
SCOOP	0.28		0.26		8	%
Total lease operating expenses per Mcfe	$	0.19	$	0.17	16	%

The increase in our total LOE for the three months ended June 30, 2025 compared to the three months ended June 30, 2024, was primarily the result of an increase in water hauling and labor expenses throughout our operations.

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


	Three Months Ended June 30, 2025		Three Months Ended June 30, 2024		% Change
Production taxes	$	5,316	$	4,661	14	%
Property taxes	1,554		1,919		(19)	%
Other	686		438		57	%
Total taxes other than income	$	7,556	$	7,018	8	%
Total taxes other than income per Mcfe	$	0.08	$	0.07	12	%

The increase in total and per unit taxes other than income for the three months ended June 30, 2025 compared to the three months ended June 30, 2024, was primarily related to an increase in production taxes resulting from the increase 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)


	Three Months Ended June 30, 2025		Three Months Ended June 30, 2024		% Change
Transportation, gathering, processing and compression	$	86,508	$	86,529	—	%
Transportation, gathering, processing and compression per Mcfe	$	0.94	$	0.91	4	%

Transportation, gathering, processing and compression for the three months ended June 30, 2025 compared to the three months ended June 30, 2024, increased on a per unit basis primarily as a result of an increase in the proportion of natural gas liquids and oil and condensate sales.

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


	Three Months Ended June 30, 2025		Three Months Ended June 30, 2024		% Change
Depreciation, depletion and amortization of oil and gas properties	$	73,123	$	78,230	(7)	%
Depreciation, depletion and amortization of other property and equipment	520		323		61	%
Total depreciation, depletion and amortization	$	73,643	$	78,553	(6)	%
Depreciation, depletion and amortization per Mcfe	$	0.80	$	0.82	(2)	%

Depreciation, depletion and amortization of our oil and gas properties for the three months ended June 30, 2025 compared to the three months ended June 30, 2024, decreased primarily due to a lower depletion rate resulting from a decline in our amortization base from the full cost ceiling test impairments incurred during 2024, combined with a decrease in our production as noted above.

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


	Three Months Ended June 30, 2025		Three Months Ended June 30, 2024		% Change
General and administrative expenses, gross	$	21,639	$	20,786	4	%
Reimbursed from third parties	(4,280)		(3,705)		16	%
Capitalized general and administrative expenses	(6,433)		(6,329)		2	%
General and administrative expenses, net	$	10,926	$	10,752	2	%
General and administrative expenses, net per Mcfe	$	0.12	$	0.11	6	%

The increase in general and administrative expenses for the three months ended June 30, 2025 compared to the three months ended June 30, 2024, was primarily driven by increases in employee compensation and legal expense related to the matters disclosed in Note 9 of our consolidated financial statements.

Interest Expense (in thousands, except per unit)


	Three Months Ended June 30, 2025		Three Months Ended June 30, 2024		% Change
Interest on 2026 Senior Notes	$	263	$	11,000	(98)	%
Interest on 2029 Senior Notes	10,969		—		100	%
Interest expense on Credit Facility	2,322		3,857		(40)	%
Amortization of loan costs	1,313		949		38	%
Capitalized interest	(1,447)		(1,241)		17	%
Other	311		593		(48)	%
Total interest expense	$	13,731	$	15,158	(9)	%
Interest expense per Mcfe	$	0.15	$	0.16	(5)	%

Due to the tender offer for the 2026 Senior Notes in the third quarter of 2024 and the redemption of the remaining balance in the second quarter of 2025, interest paid on the 2026 Senior Notes decreased 98% for the three months ended June 30, 2025 compared to the three months ended June 30, 2024. The Company also incurred $11.0 million of interest on the 2029 Senior Notes for the three months ended June 30, 2025. Interest expense on our Credit Facility decreased 40% for the three months ended June 30, 2025 compared to the three months ended June 30, 2024, as a result of a lower average interest rate and balance outstanding. Amortization of loan costs increased 38% for the three months ended June 30, 2025 compared to the three months ended June 30, 2024, as a result of the Fourth Amendment to the Credit Facility and the issuance of the 2029 Senior Notes. See Note 4 of our consolidated financial statements for further details of our Credit Facility and 2029 Senior Notes. The Company also capitalized $1.4 million and $1.2 million in interest expense for the three months ended June 30, 2025 and June 30, 2024, respectively.

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Income Taxes

We recorded income tax expense of $51.7 million and income tax benefit of $7.6 million for the three months ended June 30, 2025 and June 30, 2024, respectively. See Note 14 of our consolidated financial statements for further discussion of our income tax expense.

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Comparison of the Six Month Periods Ended June 30, 2025 and 2024

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

The following table summarizes our natural gas, oil and condensate, and NGL production and related pricing for the six months ended June 30, 2025 as compared to the six months ended June 30, 2024. Some totals below may not sum or recalculate due to rounding.


	Six Months Ended June 30, 2025		Six Months Ended June 30, 2024
Natural gas sales
Natural gas production volumes (MMcf)	156,517		177,091
Natural gas production volumes (MMcf) per day	865		973
Total sales	$	522,742	$	332,744
Average price without the impact of derivatives ($/Mcf)	$	3.34	$	1.88
Impact from settled derivatives ($/Mcf)	$	0.05	$	0.89
Average price, including settled derivatives ($/Mcf)	$	3.39	$	2.77

Oil and condensate sales
Oil and condensate production volumes (MBbl)	1,189		553
Oil and condensate production volumes (MBbl) per day	7		3
Total sales	$	72,802	$	40,828
Average price without the impact of derivatives ($/Bbl)	$	61.22	$	73.84
Impact from settled derivatives ($/Bbl)	$	2.46	$	(0.46)
Average price, including settled derivatives ($/Bbl)	$	63.68	$	73.38

NGL sales
NGL production volumes (MBbl)	1,926		1,841
NGL production volumes (MBbl) per day	11		10
Total sales	$	59,553	$	54,253
Average price without the impact of derivatives ($/Bbl)	$	30.92	$	29.48
Impact from settled derivatives ($/Bbl)	$	(0.85)	$	(0.75)
Average price, including settled derivatives ($/Bbl)	$	30.07	$	28.73

Natural gas, oil and condensate and NGL sales
Natural gas equivalents (MMcfe)	175,208		191,451
Natural gas equivalents (MMcfe) per day	968		1,052
Total sales	$	655,097	$	427,825
Average price without the impact of derivatives ($/Mcfe)	$	3.74	$	2.23
Impact from settled derivatives ($/Mcfe)	$	0.05	$	0.82
Average price, including settled derivatives ($/Mcfe)	$	3.79	$	3.05

Production Costs:
Average lease operating expenses ($/Mcfe)	$	0.22	$	0.17
Average taxes other than income ($/Mcfe)	$	0.08	$	0.08
Average transportation, gathering, processing and compression ($/Mcfe)	$	0.97	$	0.90
Total lease operating expenses, taxes other than income and midstream costs ($/Mcfe)	$	1.26	$	1.15

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Natural Gas, Oil and Condensate and NGL Sales (in thousands)


	Six Months Ended June 30, 2025		Six Months Ended June 30, 2024		% Change
Natural gas	$	522,742	$	332,744	57	%
Oil and condensate	72,802		40,828		78	%
NGL	59,553		54,253		10	%
Natural gas, oil and condensate and NGL sales	$	655,097	$	427,825	53	%

The increase in natural gas sales without the impact of derivatives, when comparing the six months ended June 30, 2025 to the six months ended June 30, 2024, was due to a 78% increase in realized prices, partially offset by a 12% decrease in sales volumes. The realized price change was primarily driven by the increase in the average Henry Hub gas index from $2.07 per Mcf in the six months ended June 30, 2024, to $3.55 per Mcf in the six months ended June 30, 2025. The 12% decrease in natural gas production was primarily due to natural declines partially offset by our 2024 and 2025 development programs and the impact of unplanned, third-party midstream outages and constraints.

The increase in oil and condensate sales without the impact of derivatives, when comparing the six months ended June 30, 2025 to the six months ended June 30, 2024, was due to a 115% increase in sales volumes, partially offset by a 17% decrease in realized prices. The 115% increase in oil and condensate production was primarily due to commencement of sales on new wells targeting the Utica liquids window. The realized price change was driven by the decrease in the average WTI crude index from $78.77 per barrel in the six months ended June 30, 2024, to $67.58 per barrel in the six months ended June 30, 2025.

The increase in NGL sales without the impact of derivatives, when comparing the six months ended June 30, 2025 to the six months ended June 30, 2024, was due to a 5% increase in sales volumes and a 5% increase in realized prices. The 5% increase in NGL production was primarily due to commencement of sales on new wells targeting the Utica liquids window.

Natural Gas, Oil and NGL Derivatives (in thousands)


	Six Months Ended June 30, 2025		Six Months Ended June 30, 2024
Natural gas derivatives - fair value losses	$	(24,755)	$	(111,349)
Natural gas derivatives - settlement gains	8,270		157,702
Total (losses) gains on natural gas derivatives	(16,485)		46,353

Oil derivatives - fair value gains (losses)	2,309		(1,865)
Oil derivatives - settlement gains (losses)	2,915		(259)
Total gains (losses) on oil and condensate derivatives	5,224		(2,124)

NGL derivatives - fair value gains (losses)	2,449		(6,330)
NGL derivatives - settlement losses	(1,635)		(1,378)
Total gains (losses) on NGL derivatives	814		(7,708)

Total (losses) gains on natural gas, oil and NGL derivatives	$	(10,447)	$	36,521

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 (loss) gain for the six months ended June 30, 2025 compared to the six months ended June 30, 2024, was primarily the result of changes in futures pricing for oil, natural gas, and NGLs during each period. See Note 10 of our consolidated financial statements for hedged volumes and pricing.

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Lease Operating Expenses (in thousands, except per unit)


	Six Months Ended June 30, 2025		Six Months Ended June 30, 2024		% Change
Lease operating expenses
Utica & Marcellus	$	26,013	$	21,480	21	%
SCOOP	11,898		11,145		7	%
Total lease operating expenses	$	37,911	$	32,625	16	%

Lease operating expenses per Mcfe
Utica & Marcellus	$	0.19	$	0.14	36	%
SCOOP	0.33		0.28		18	%
Total lease operating expenses per Mcfe	$	0.22	$	0.17	27	%

The increase in our total and per unit LOE for the six months ended June 30, 2025 compared to the six months ended June 30, 2024, was primarily the result of an increase in water hauling, labor and costs associated with weather operations.

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


	Six Months Ended June 30, 2025		Six Months Ended June 30, 2024		% Change
Production taxes	$	10,753	$	9,708	11	%
Property taxes	1,982		4,529		(56)	%
Other	1,447		1,041		39	%
Total taxes other than income	$	14,182	$	15,278	(7)	%
Total taxes other than income per Mcfe	$	0.08	$	0.08	1	%

The decrease in total taxes other than income for the six months ended June 30, 2025 compared to the six months ended June 30, 2024, was primarily related to a decrease in property taxes partially offset by increased production taxes resulting from the increase in revenues noted above.

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


	Six Months Ended June 30, 2025		Six Months Ended June 30, 2024		% Change
Transportation, gathering, processing and compression	$	169,378	$	173,148	(2)	%
Transportation, gathering, processing and compression per Mcfe	$	0.97	$	0.90	7	%

Transportation, gathering, processing and compression for the six months ended June 30, 2025 compared to the six months ended June 30, 2024 increased on a per unit basis primarily as a result of an increase in the proportion of natural gas liquids and oil and condensate sales and an 8% decrease in total production volumes as noted above.

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


	Six Months Ended June 30, 2025		Six Months Ended June 30, 2024		% Change
Depreciation, depletion and amortization of oil and gas properties	$	138,213	$	157,911	(12)	%
Depreciation, depletion and amortization of other property and equipment	1,052		665		58	%
Total depreciation, depletion and amortization	$	139,265	$	158,576	(12)	%
Depreciation, depletion and amortization per Mcfe	$	0.79	$	0.83	(4)	%

The total and per unit depreciation, depletion and amortization of our oil and gas properties for the six months ended June 30, 2025 compared to the six months ended June 30, 2024, decreased primarily due to a lower depletion rate resulting from a decline in our amortization base from the full cost ceiling test impairments recorded during 2024, combined with a decrease in our production as noted above.

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


	Six Months Ended June 30, 2025		Six Months Ended June 30, 2024		% Change
General and administrative expenses, gross	$	40,838	$	39,228	4	%
Reimbursed from third parties	(8,246)		(7,243)		14	%
Capitalized general and administrative expenses	(12,665)		(12,035)		5	%
General and administrative expenses, net	$	19,927	$	19,950	—	%
General and administrative expenses, net per Mcfe	$	0.11	$	0.10	9	%

The increase in general and administrative expenses for the six months ended June 30, 2025 compared to the six months ended June 30, 2024, was primarily driven by increases in employee compensation and legal expense related to the matters disclosed in Note 9 of our consolidated financial statements.

Interest Expense (in thousands, except per unit)


	Six Months Ended June 30, 2025		Six Months Ended June 30, 2024		% Change
Interest on 2026 Senior Notes	$	777	$	22,000	(96)	%
Interest on 2029 Senior Notes	21,938		—		100	%
Interest expense on Credit Facility	4,007		7,578		(47)	%
Amortization of loan costs	2,613		1,894		38	%
Capitalized interest	(2,877)		(2,372)		21	%
Other	629		1,061		(41)	%
Total interest expense	$	27,087	$	30,161	(10)	%
Interest expense per Mcfe	$	0.15	$	0.16	(2)	%

Due to the tender offer for the 2026 Senior Notes in the third quarter of 2024 and the redemption of the remaining balance in the second quarter of 2025, interest paid on the 2026 Senior Notes decreased 96% for the six months ended June 30, 2025 compared to the six months ended June 30, 2024. The Company also incurred $21.9 million of interest on the 2029 Senior Notes for the six months ended June 30, 2025. Interest expense on our Credit Facility decreased 47% for the six months ended June 30, 2025 compared to the six months ended June 30, 2024, as a result of a lower average interest rate and balance outstanding. Amortization of loan costs increased 38% for the six months ended June 30, 2025 compared to the six months ended June 30, 2024, as a result of the Fourth Amendment to the Credit Facility and the issuance of the 2029 Senior Notes. See Note 4 of our consolidated financial statements for further details of our Credit Facility and 2029 Senior Notes. The Company also capitalized $2.9 million and $2.4 million in interest expense for the six months ended June 30, 2025 and June 30, 2024, respectively.

Income Taxes

We recorded income tax expense of $51.5 million and $7.3 million for the six months ended June 30, 2025 and June 30, 2024, respectively. See Note 14 of our consolidated financial statements for further discussion of our income tax expense.

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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 or redemptions 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 three and six months ended June 30, 2025, our primary sources of capital resources and liquidity have consisted of internally generated cash flows from operations and access to debt markets, and our primary uses of cash have been for development of our oil and natural gas properties, share repurchases and dividend payments on our preferred stock.

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 or redemptions during the next 12 months and the foreseeable future.

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 the principal and carrying amounts of our senior notes.

As of June 30, 2025, we had $3.8 million of cash and cash equivalents, $55.0 million of outstanding borrowings under our Credit Facility, $63.9 million of letters of credit outstanding, and $650.0 million of outstanding 2029 Senior Notes. Our total principal amount of funded debt as of June 30, 2025 was $705.0 million.

As of July 30, 2025 we had $3.0 million of cash and cash equivalents, $29.0 million in borrowings under our Credit Facility, $63.9 million of letters of credit outstanding, and $650 million of outstanding 2029 Senior Notes.

Debt. In May 2021, we issued our 2026 Senior Notes. The 2026 Senior Notes were guaranteed on a senior unsecured basis by each of the Company's subsidiaries that guarantee the Credit Facility. In September 2024, Gulfport Operating purchased approximately 95%, or $524.3 million, of the 2026 Senior Notes in a tender offer using net proceeds received from the private placement of the 2029 Senior Notes. In May 2025, the Company redeemed the remaining balance of its 2026 Senior Notes at par for $25.7 million. No additional fees or penalties were incurred as a result of the early redemption.

Additionally, on May 1, 2023, the Company entered into that certain Joinder, Commitment Increase and Borrowing Base Redetermination Agreement, and Third Amendment to Credit Agreement (the “Third Amendment”) which amended the Company’s Credit Facility. The Third Amendment, among other things, (a) increased the aggregate elected commitment amounts under the Credit Facility 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 (d) extended the maturity date under the Credit Facility from October 14, 2025 to the earlier of (i) May 1, 2027 and (ii) the 91st day prior to the maturity date of the 2026 Senior Notes or any other permitted senior notes or any permitted refinancing debt under the Credit Facility having an aggregate outstanding principal amount equal to or exceeding $100 million; provided that such notes have not been refinanced, redeemed or repaid in full on or prior to such 91st day. On April 18, 2024, Gulfport completed its semi-annual borrowing base redetermination under its Credit Facility during which the borrowing base was reaffirmed at $1.1 billion with elected commitments remaining at $900 million.

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

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Dividends on Preferred Stock. As discussed in Note 5 of our consolidated financial statements, holders of preferred stock are entitled to receive cumulative quarterly dividends at a rate of 10% per annum of the Liquidation Preference with respect to cash dividends and 15% per annum of the Liquidation Preference with respect to dividends paid in kind as additional shares of preferred stock (“PIK Dividends”). We currently have the option to pay either cash dividends or PIK Dividends on a quarterly basis.

Redemption of Preferred Stock. On August 5, 2025, Gulfport issued a notice of redemption for its preferred stock for cash. The optional redemption will be effective on the Redemption Date with respect to any shares of the preferred stock that have not been converted and remain outstanding at that date. Shares of preferred stock may be converted to common stock pursuant to their terms up to, but not including, the Redemption Date. The total cash amount payable by Gulfport in connection with the redemption will vary depending on the number of shares of preferred stock converted prior to the Redemption Date and the price of Gulfport's common stock.

Supplemental Guarantor Financial Information. The 2026 Senior Notes were 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 were not guaranteed by Grizzly Holdings or Mule Sky, LLC. The 2026 Senior Notes Guarantors were 100% owned by the Parent, and the guarantees are full, unconditional, joint and several. There were 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 were 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 3 Quantitative and Qualitative Disclosures About Market Risk for further discussion on the impact of commodity price risk on our financial position. Additionally, see Note 10 of our consolidated financial statements for further discussion of derivatives and hedging activities.

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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 six months ended June 30, 2025, the Company's incurred capital expenditures totaled $290.8 million related to operated activities, of which $266.7 million related to drilling and completion activities, $17.2 million related to maintenance leasehold and land investment and $6.9 million related to discretionary acreage acquisitions.

Our operated drilling and completion capital expenditures for 2025 are currently estimated to be in the range of $335.0 million to $355.0 million. Also, we currently expect to spend approximately $35.0 million to $40.0 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. Our capital program is expected to deliver 1,040 to 1,065 MMcfe per day of production in 2025; due to the impact of unplanned, third-party midstream outages and constraints we are currently trending toward the low end of our production guidance range.

Additionally, we are pursuing accretive acreage opportunities that expand our resource footprint and provide optionality to our near-term development plans and intend to allocate approximately $75.0 million to $100.0 million in discretionary acreage acquisitions for 2025 and early 2026.

Sources and Uses of Cash

The following table presents the major changes in cash and cash equivalents for the six months ended June 30, 2025 and 2024 (in thousands):


	Six Months Ended June 30, 2025		Six Months Ended June 30, 2024
Net cash provided by operating activities	$	408,683	$	311,487
Additions to oil and natural gas properties	(253,000)		(244,851)
Debt activity, net	(8,702)		12,000
Repurchases of common stock	(124,500)		(53,795)
Net cash payments on performance vesting restricted stock units	(12,297)		—
Shares exchanged for tax withholdings	(5,228)		(21,584)
Dividends on preferred stock	(1,666)		(2,200)
Other	(969)		(1,753)
Net change in cash and cash equivalents	$	2,321	$	(696)
Cash and cash equivalents at end of period	$	3,794	$	1,233

Net cash provided by operating activities. Net cash flow provided by operating activities was $408.7 million for the six months ended June 30, 2025, as compared to $311.5 million for the six months ended June 30, 2024. The increase was primarily the result of increases in natural gas revenues.

Additions to oil and natural gas properties. During the six months ended June 30, 2025, we spud 12 gross (12.0 net) operated wells and commenced sales from 19 gross (19.0 net) operated wells in the Utica and Marcellus for a total incurred cost of approximately $244.4 million. During the six months ended June 30, 2025, we completed drilling and commenced sales from two gross (1.8 net) operated wells in the SCOOP for a total incurred cost of approximately $22.3 million.

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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 six months ended June 30, 2025 and 2024, were as follows (in thousands):


	Six Months Ended June 30, 2025		Six Months Ended June 30, 2024
Oil and Natural Gas Property Cash Expenditures:
Drilling and completion costs	$	215,498	$	178,864
Leasehold acquisitions	22,429		53,291
Other	15,073		12,696
Total oil and natural gas property expenditures	$	253,000	$	244,851

Debt activity, net. In the six months ended June 30, 2025, the Company had $431.0 million and $414.0 million in borrowings and repayments, respectively, on its Credit Facility. In May 2025, the Company redeemed the remaining balance of its 2026 Senior Notes at par for $25.7 million. No additional fees or penalties were incurred as a result of the early redemption. The final payment, including accrued interest, totaled $26.6 million. As of July 30, 2025 the Company had $29.0 million in borrowings outstanding on its Credit Facility.

Repurchases of common stock. During the six months ended June 30, 2025, the Company repurchased 679,550 shares for approximately $125.0 million under the Repurchase Program at a weighted average price of $183.95 per share. For the same period in 2024, the Company repurchased 370,697 shares for $54.5 million at a weighted average price of $147.00 per share. As of July 30, 2025, we repurchased 6.3 million shares for approximately $718.7 million under the Repurchase Program at a weighted average price of $114.03 per share.

Net cash payments on performance vesting restricted stock units. During the six months ended June 30, 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 six months ended June 30, 2025, the Company paid $1.7 million of cash dividends to holders of our preferred stock compared to $2.2 million in the six months ended June 30, 2024.

Shares exchanged for tax withholdings. During the six months ended June 30, 2025, the Company paid $5.2 million of shares exchanged for tax withholdings compared to $21.6 million in the six months ended June 30, 2024. The decrease was primarily due to lower aggregate fair value of vested awards during the six months ended June 30, 2025 compared to the six months ended June 30, 2024, as discussed in Note 7 of our consolidated financial statements.

Contractual and Commercial Obligations

We have various contractual obligations in the normal course of our operations and financing activities, as discussed in Note 9 of our consolidated financial statements. There have been no other material changes to our contractual obligations from those disclosed in our Annual Report on Form 10-K for the year ended December 31, 2024.

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 June 30, 2025, our material off-balance sheet arrangements and transactions include $63.9 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 on certain firm transportation agreements. There are no other transactions, arrangements or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect our liquidity or availability of our capital resources. See Note 9 of our consolidated financial statements for further discussion of the various financial guarantees we have issued.

Critical Accounting Policies and Estimates

As of June 30, 2025, there have been no significant changes in our critical accounting policies from those disclosed in our 2024 Annual Report on Form 10-K.

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ITEM 3.			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 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 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, 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 11 of our consolidated financial statements for further discussion of the fair value measurements associated with our derivatives.

As of June 30, 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.

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•Call Options: We sell, and occasionally buy, call options in exchange for a premium. At the time of settlement, if the market price exceeds the fixed price of the call option, we pay the counterparty the excess on sold call options, and we would receive the excess on bought call options. If the market price settles below the fixed price of the call option, no payment is due from either party.

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 June 30, 2025, we had a net liability derivative position of $32.9 million as compared to a net liability derivative position of $12.9 million as of December 31, 2024. Utilizing actual derivative contractual volumes, a 10% increase in underlying commodity prices would have increased our liability by approximately $99.3 million, while a 10% decrease in underlying commodity prices would have decreased our liability by approximately $98.8 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.

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 June 30, 2025, we had $55.0 million outstanding borrowings under our Credit Facility which bore interest at a weighted average rate of 6.77% for the six months ended June 30, 2025. As of June 30, 2025, we did not have any interest rate swaps to hedge interest rate risks.


ITEM 4.			CONTROLS AND PROCEDURES

Evaluation of Disclosure Control and Procedures. Under the supervision of our Chief Executive Officer and our Chief Financial Officer, and with participation of management, we have established disclosure controls and procedures that are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. The disclosure controls and procedures are also intended to ensure that such information is accumulated and communicated to management, including our Chief Executive Officer and our Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosures.

As of June 30, 2025, an evaluation was performed under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Exchange Act. Based upon our evaluation, our Chief Executive Officer and our Chief Financial Officer have concluded that, as of June 30, 2025, our disclosure controls and procedures are effective.

In designing and evaluating the Company's disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable, and not absolute, assurance that the objectives of the control system will be met. In addition, the design of any control system is based in part upon certain assumptions about the likelihood of future events and the application of judgment in evaluating the cost-benefit relationship of possible controls and procedures. Because of these and other inherent limitations of control systems, there is only reasonable assurance that the Company's controls will succeed in achieving their goals under all potential future conditions.

Changes in Internal Control over Financial Reporting. There have not been any changes in our internal control over financial reporting that occurred during our last fiscal quarter that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting.

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PART II


ITEM 1.			LEGAL PROCEEDINGS

The information with respect to this Item 1. Legal Proceedings is set forth in Note 9 of our consolidated financial statements.


ITEM 1A.			RISK FACTORS

Our business has many risks. Factors that could materially adversely affect our business, financial condition, operating results or liquidity and the trading price of our common stock or senior notes are described below and under "Risk Factors" in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2024.


ITEM 2.			UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Unregistered Sales of Equity Securities

None.

Issuer Repurchases of Equity Securities

Our common stock repurchase activity for the three months ended June 30, 2025 was as follows:


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
April 1 - April 30	49,264	$	171.91	43,913	$	348,374,000
May 1 - May 31	250,865	$	194.51	244,206	$	300,874,000
June 1 - June 30	50,767	$	196.98	50,767	$	290,874,000
Total	350,896	$	191.70	338,886

_____________________

(1) We repurchased and canceled 5,351 and 6,659 shares of our common stock at a weighted average price of $181.13 and $194.68 to satisfy tax withholding requirements incurred upon the vesting of restricted stock unit awards during April and May 2025, respectively.


ITEM 3.			DEFAULTS UPON SENIOR SECURITIES

None.


ITEM 4.			MINE SAFETY DISCLOSURES

Not applicable.


ITEM 5.			OTHER INFORMATION

Trading Arrangements

During the three months ended June 30, 2025, none of our officers (as defined in Rule 16a-1(f) of the Exchange Act) or directors adopted or terminated any contract, instruction or written plan for the purchase or sale of our securities that was intended to satisfy the affirmative defense conditions of Rule 10b5-1(c) or any "non-Rule 10b5-1 trading arrangement"(as defined in Item 408 of Regulation S-K).

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ITEM 6.			EXHIBITS

INDEX OF EXHIBITS

Incorporated by Reference

Exhibit Number

Description

Form

SEC File Number

Exhibit

Filing Date

Filed or Furnished Herewith

2.1

Amended Joint Chapter 11 Plan of Reorganization of Gulfport Energy Corporation and its Debtor Subsidiaries, dated April 14, 2021.

8-K

001-19514

2.2

4/29/2021

3.1

Amended and Restated Certificate of Incorporation of Gulfport Energy Corporation.

8-K

000-19514

3.1

5/17/2021

3.2

A mend ment to the Amended and Restated Certificate of In corporation of Gulfport Energy Corporation.

8-K

000-19514

3.1

5/23/2025

3.3

Amended and Restated Bylaws of Gulfport Energy Corporation.

8-K

000-19514

3.2

5/17/2021

31.1

Certification of Chief Executive Officer of the Registrant pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended.

31.2

Certification of Chief Financial Officer of the Registrant pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended.

32.1

Certification of Chief Executive Officer of the Registrant pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and Section 1350 of Chapter 63 of Title 18 of the United States Code.

32.2

Certification of Chief Financial Officer of the Registrant pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and Section 1350 of Chapter 63 of Title 18 of the United States Code.

101.INS

XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.

101.SCH

XBRL Taxonomy Extension Schema Document.

101.CAL

XBRL Taxonomy Extension Calculation Linkbase Document.

101.DEF

XBRL Taxonomy Extension Definition Linkbase Document.

101.LAB

XBRL Taxonomy Extension Labels Linkbase Document.

101.PRE

XBRL Taxonomy Extension Presentation Linkbase Document.

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104

Cover Page Interactive Data File - the cover page interactive data file does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.

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SIGNATURES

In accordance with Section 13 or 15(d) of the Exchange Act, the registrant caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Date: August 6, 2025


GULFPORT ENERGY CORPORATION

By:						/s/ Michael Hodges
						Michael Hodges Chief Financial Officer

GULFPORT ENERGY CORP 10-Q