GULFPORT ENERGY CORP - Quarter Report: 2023 September (Form 10-Q)

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 September 30, 2023


☐			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)		(IRS 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 October 26, 2023, 18,625,834 shares of the registrant’s common stock were outstanding.

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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. Basis of Presentation	10

	2. Property and Equipment	11

	3. Debt	12

	4. Mezzanine Equity	14

	5. Equity	15

	6. Stock-Based Compensation	16

	7. Restructuring Costs	18

	8. Earnings (Loss) Per Share	18

	9. Commitments and Contingencies	20

	10. Derivative Instruments	21

	11. Fair Value Measurements	26

	12. Revenue from Contracts with Customers	27

	13. Leases	28

	14. Income Taxes	29

	15. Related Party Transactions	30

	16. Subsequent Events	30

Item 2.	Management’s Discussion and Analysis of Financial Conditions and Results of Operations	31

	2023 Operational and Financial Highlights	32

	2023 Production and Drilling Activity	33

	Comparison of Quarter-to-Date	35

	Comparison of Year-to-Date	39

	Liquidity and Capital Resources	44

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	48

Item 4.	Controls and Procedures	49

PART II OTHER INFORMATION

Item 1.	Legal Proceedings	50

Item 1A.	Risk Factors	50

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	50

Item 3.	Defaults Upon Senior Securities	50

Item 4.	Mine Safety Disclosures	50

Item 5.	Other Information	50

Item 6.	Exhibits	51

Signatures		52

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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. Agreement dated May 17, 2021 between the Company, 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 2026.

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 the Company, 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.

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.

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.

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 Existing Credit Facility, as amended by the Joinder, Commitment Increase and Borrowing Base Redetermination Agreement, and Third Amendment to Credit Agreement dated as of May 1, 2023.

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.

Existing 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 to date.

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.

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

Indentures. Collectively, the 1145 Indenture and the 4(a)(2) Indenture governing the 2026 Senior Notes.

LIBOR. London Interbank Offered Rate.

LOE. Lease operating expenses.

Marcellus. Refers to the Marcellus Play that includes the hydrocarbon bearing rock formations commonly referred to as the Marcellus formation located in the Appalachian Basin of the United States and Canada. Our acreage is located primarily in Belmont County in eastern Ohio.

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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 $650 million of Gulfport's outstanding common stock. It is authorized to extend through December 31, 2024, and may be suspended from time to time, modified, extended or discontinued by the Board of Directors at any time.

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.

Successor. The post-emergence from bankruptcy reorganized organization for periods subsequent to May 17, 2021.

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 the war in Ukraine and the Israel-Hamas war on our business, our industry and the global economy, estimated future net revenues from oil and gas reserves and the present value thereof, future capital expenditures (including the amount and nature thereof), 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, 2022 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)


	September 30, 2023		December 31, 2022
Assets
Current assets:
Cash and cash equivalents	$	8,325	$	7,259
Accounts receivable—oil, natural gas, and natural gas liquids sales	106,731		278,404
Accounts receivable—joint interest and other	12,364		21,478
Prepaid expenses and other current assets	8,173		7,621
Short-term derivative instruments	136,706		87,508
Total current assets	272,299		402,270
Property and equipment:
Oil and natural gas properties, full-cost method
Proved oil and natural gas properties	2,802,653		2,418,666
Unproved properties	196,947		178,472
Other property and equipment	8,120		6,363
Total property and equipment	3,007,720		2,603,501
Less: accumulated depletion, depreciation and amortization	(784,635)		(545,771)
Total property and equipment, net	2,223,085		2,057,730
Other assets:
Long-term derivative instruments	32,687		26,525
Deferred tax asset	554,741		—
Operating lease assets	17,466		26,713
Other assets	36,668		21,241
Total other assets	641,562		74,479
Total assets	$	3,136,946	$	2,534,479
Liabilities, Mezzanine Equity and Stockholders’ Equity
Current liabilities:
Accounts payable and accrued liabilities	$	310,584	$	437,384
Short-term derivative instruments	50,947		343,522
Current portion of operating lease liabilities	12,932		12,414
Total current liabilities	374,463		793,320
Non-current liabilities:
Long-term derivative instruments	54,020		118,404
Asset retirement obligation	34,270		33,171
Non-current operating lease liabilities	4,534		14,299
Long-term debt	644,324		694,155
Total non-current liabilities	737,148		860,029
Total liabilities	$	1,111,611	$	1,653,349
Commitments and contingencies (Note 9)
Mezzanine Equity:
Preferred stock - $0.0001 par value, 110.0 thousand shares authorized, 45.3 thousand issued and outstanding at September 30, 2023, and 52.3 thousand issued and outstanding at December 31, 2022	45,329		52,295
Stockholders’ Equity:
Common stock - $0.0001 par value, 42.0 million shares authorized, 18.7 million issued and outstanding at September 30, 2023, and 19.1 million issued and outstanding at December 31, 2022	2		2
Additional paid-in capital	379,102		449,243
Common stock held in reserve, 62.0 thousand shares at September 30, 2023, and 62.0 thousand shares at December 31, 2022	(1,996)		(1,996)
Retained Earnings	1,603,339		381,872
Treasury stock, at cost - 3.7 thousand shares at September 30, 2023, and 3.9 thousand shares at December 31, 2022	(441)		(286)
Total stockholders’ equity	$	1,980,006	$	828,835
Total liabilities, mezzanine equity and stockholders’ equity	$	3,136,946	$	2,534,479

See accompanying notes to consolidated financial statements.

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GULFPORT ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands)

(Unaudited)


	Three Months Ended September 30, 2023		Three Months Ended September 30, 2022
REVENUES:
Natural gas sales	$	177,401	$	585,596
Oil and condensate sales	22,896		36,050
Natural gas liquid sales	26,953		44,351
Net gain (loss) on natural gas, oil and NGL derivatives	39,417		(474,895)
Total revenues	266,667		191,102
OPERATING EXPENSES:
Lease operating expenses	15,627		15,363
Taxes other than income	7,216		16,529
Transportation, gathering, processing and compression	86,602		89,234
Depreciation, depletion and amortization	79,505		64,419
General and administrative expenses	9,894		8,752
Accretion expense	639		673
Total operating expenses	199,483		194,970
INCOME (LOSS) FROM OPERATIONS	67,184		(3,868)
OTHER EXPENSE (INCOME):
Interest expense	14,919		15,461
Other, net	(1,438)		(857)
Total other expense	13,481		14,604
INCOME (LOSS) BEFORE INCOME TAXES	53,703		(18,472)
INCOME TAX BENEFIT:
Current	—		—
Deferred	(554,741)		—
Total income tax benefit	(554,741)		—
NET INCOME (LOSS)	$	608,444	$	(18,472)
Dividends on preferred stock	(1,133)		(1,309)
Participating securities - preferred stock	(89,756)		—
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCKHOLDERS	$	517,555	$	(19,781)

NET INCOME (LOSS) PER COMMON SHARE:
Basic	$	27.72	$	(1.01)
Diluted	$	27.37	$	(1.01)
Weighted average common shares outstanding—Basic	18,670		19,635
Weighted average common shares outstanding—Diluted	18,954		19,635

See accompanying notes to consolidated financial statements.

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GULFPORT ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands)

(Unaudited)


	Nine Months Ended September 30, 2023		Nine Months Ended September 30, 2022
REVENUES:
Natural gas sales	$	619,181	$	1,529,898
Oil and condensate sales	76,212		111,298
Natural gas liquid sales	92,935		143,741
Net gain (loss) on natural gas, oil and NGL derivatives	514,266		(1,436,317)
Total revenues	1,302,594		348,620
OPERATING EXPENSES:
Lease operating expenses	51,644		47,246
Taxes other than income	25,849		45,679
Transportation, gathering, processing and compression	259,883		261,778
Depreciation, depletion and amortization	238,747		189,305
General and administrative expenses	27,238		24,128
Restructuring costs	4,762		—
Accretion expense	2,117		2,057
Total operating expenses	610,240		570,193
INCOME (LOSS) FROM OPERATIONS	692,354		(221,573)
OTHER EXPENSE (INCOME):
Interest expense	42,402		43,679
Other, net	(20,492)		(11,385)
Total other expense	21,910		32,294
INCOME (LOSS) BEFORE INCOME TAXES	670,444		(253,867)
INCOME TAX BENEFIT:
Current	—		—
Deferred	(554,741)		—
Total income tax benefit	(554,741)		—
NET INCOME (LOSS)	$	1,225,185	$	(253,867)
Dividends on preferred stock	(3,718)		(4,136)
Participating securities - preferred stock	(180,394)		—
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCKHOLDERS	$	1,041,073	$	(258,003)

NET INCOME (LOSS) PER COMMON SHARE:
Basic	$	55.72	$	(12.58)
Diluted	$	55.08	$	(12.58)
Weighted average common shares outstanding—Basic	18,686		20,514
Weighted average common shares outstanding—Diluted	18,937		20,514

See accompanying notes to consolidated financial statements.

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GULFPORT ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(In thousands)

(Unaudited)


				Common Stock Held in Reserve			Treasury Stock		Paid-in Capital		Retained Earnings (Accumulated Deficit)		Total Stockholders’ Equity
	Common Stock
	Shares	Amount		Shares	Amount
Balance at January 1, 2022	21,537	$	2	(938)	$	(30,216)	$	—	$	692,521	$	(112,829)	$	549,478
Net loss	—	—		—	—		—		—		(491,975)		(491,975)
Conversion of preferred stock	1	—		—	—		—		18		—		18
Stock compensation	—	—		—	—		—		1,755		—		1,755
Repurchase of common stock under Repurchase Program	(378)	—		—	—		(5,318)		(30,194)		—		(35,512)
Issuance of common stock held in reserve	—	—		876	28,220		—		—		—		28,220
Issuance of restricted stock, net of shares withheld for income taxes	2	—		—	—		—		(80)		—		(80)
Dividends on preferred stock	—	—		—	—		—		(1,447)		—		(1,447)
Balance at March 31, 2022	21,162	$	2	(62)	$	(1,996)	$	(5,318)	$	662,573	$	(604,804)	$	50,457
Net income	—	—		—	—		—		—		256,580		256,580
Conversion of preferred stock	342	—		—	—		—		4,706		—		4,706
Stock compensation	—	—		—	—		—		2,145		—		2,145
Issuance of restricted stock, net of shares withheld for income taxes	8	—		—	—		—		(325)		—		(325)
Repurchase of common stock under Repurchase Program	(1,382)	—		—	—		(2,491)		(125,019)		—		(127,510)
Dividends on preferred stock	—	—		—	—		—		(1,380)		—		(1,380)
Balance at June 30, 2022	20,130	$	2	(62)	$	(1,996)	$	(7,809)	$	542,700	$	(348,224)	$	184,673
Net loss	—	—		—	—		—		—		(18,472)		(18,472)
Conversion of preferred stock	60	—		—	—		—		827		—		827
Stock compensation	—	—		—	—		—		2,398		—		2,398
Issuance of restricted stock, net of shares withheld for income taxes	39	—		—	—		—		(1,192)		—		(1,192)
Repurchase of common stock under Repurchase Program	(827)	—		—	—		6,029		(70,578)		—		(64,549)
Dividends on preferred stock	—	—		—	—		—		(1,309)		—		(1,309)
Balance at September 30, 2022	19,402	$	2	(62)	$	(1,996)	$	(1,780)	$	472,846	$	(366,696)	$	102,376

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GULFPORT ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY CONTINUED

(In thousands)

(Unaudited)


				Common Stock Held in Reserve			Treasury Stock		Paid-in Capital		Retained Earnings (Accumulated Deficit)		Total Stockholders’ Equity
	Common Stock
	Shares	Amount		Shares	Amount
Balance at January 1, 2023	19,097	$	2	(62)	$	(1,996)	$	(286)	$	449,243	$	381,872	$	828,835
Net income	—	—		—	—		—		—		523,054		523,054
Stock compensation	—	—		—	—		—		3,069		—		3,069
Repurchase of common stock under Repurchase Program	(457)	—		—	—		(201)		(33,001)		—		(33,202)
Issuance of restricted stock, net of shares withheld for income taxes	3	—		—	—		—		(287)		—		(287)
Dividends on preferred stock	—	—		—	—		—		—		(1,307)		(1,307)
Balance at March 31, 2023	18,643	$	2	(62)	$	(1,996)	$	(487)	$	419,024	$	903,619	$	1,320,162
Net income	—	—		—	—		—		—		93,687		93,687
Conversion of preferred stock	431	—		—	—		—		5,836		—		5,836
Stock compensation	—	—		—	—		—		3,834		—		3,834
Repurchase of common stock under Repurchase Program	(448)	—		—	—		487		(43,117)		—		(42,630)
Issuance of restricted stock, net of shares withheld for income taxes	32	—		—	—		—		(1,493)		—		(1,493)
Dividends on preferred stock	—	—		—	—		—		(2)		(1,278)		(1,280)
Balance at June 30, 2023	18,658	$	2	(62)	$	(1,996)	$	—	$	384,082	$	996,028	$	1,378,116
Net income	—	—		—	—		—		—		608,444		608,444
Conversion of preferred stock	81	—		—	—		—		1,130		—		1,130
Stock compensation	—	—		—	—		—		3,521		—		3,521
Repurchase of common stock under Repurchase Program	(72)	—		—	—		(441)		(8,220)		—		(8,661)
Issuance of restricted stock, net of shares withheld for income taxes	33	—		—	—		—		(1,411)		—		(1,411)
Dividends on preferred stock	—	—		—	—		—		—		(1,133)		(1,133)
Balance at September 30, 2023	18,700	$	2	(62)	$	(1,996)	$	(441)	$	379,102	$	1,603,339	$	1,980,006

See accompanying notes to consolidated financial statements.

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GULFPORT ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)


	Nine Months Ended September 30, 2023		Nine Months Ended September 30, 2022
Cash flows from operating activities:
Net income (loss)	$	1,225,185	$	(253,867)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation and amortization	238,747		189,305
Net (gain) loss on derivative instruments	(514,266)		1,436,317
Net cash receipts (payments) on settled derivative instruments	101,947		(799,416)
Deferred income tax benefit	(554,741)		—
Other, net	13,270		8,303
Changes in operating assets and liabilities, net	57,538		(29,560)
Net cash provided by operating activities	567,680		551,082
Cash flows from investing activities:
Additions to oil and natural gas properties	(421,132)		(331,994)
Proceeds from sale of oil and natural gas properties	2,647		3,210
Other, net	(1,496)		(536)
Net cash used in investing activities	(419,981)		(329,320)
Cash flows from financing activities:
Principal payments on Credit Facility	(748,000)		(1,512,000)
Borrowings on Credit Facility	698,000		1,527,000
Debt issuance costs and loan commitment fees	(6,965)		(211)
Dividends on preferred stock	(3,718)		(4,136)
Repurchase of common stock under Repurchase Program	(82,757)		(225,791)
Other, net	(3,193)		(1,597)
Net cash used in financing activities	(146,633)		(216,735)
Net increase in cash and cash equivalents	1,066		5,027
Cash and cash equivalents at beginning of period	7,259		3,260
Cash and cash equivalents at end of period	$	8,325	$	8,287

See accompanying notes to consolidated financial statements.

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GULFPORT ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1.BASIS OF PRESENTATION

Description of Company

Gulfport Energy Corporation (the "Company" or "Gulfport") is an independent natural gas-weighted exploration and production company focused on the production of natural gas, crude oil and NGL in the United States. 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 and periods as of and for the three and nine months ended September 30, 2023, and the three and nine months ended September 30, 2022. The Company's annual report on Form 10-K for the year ended December 31, 2022, 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.

Accounts Payable and Accrued Liabilities

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


	September 30, 2023		December 31, 2022
Revenue payable and suspense	$	154,200	$	222,721
Accounts payable	45,526		37,807
Accrued transportation, gathering, processing and compression	34,368		56,138
Accrued capital expenditures	25,501		36,464
Accrued contract rejection damages and shares held in reserve	1,996		40,996
Other accrued liabilities	48,993		43,258
Total accounts payable and accrued liabilities	$	310,584	$	437,384

Other, net (in thousands)

Other, net in the Company's consolidated statements of operations for the nine months ended September 30, 2023, included $17.8 million related to the interim TC claim distribution and a $1 million administrative payment to Rover as part of the executed settlement. The distribution and settlement is more fully described in Note 9. The timing and amount of any future distributions to Gulfport are not certain, and the total amount will be impacted by the liquidating trust's distributions and resolution of other remaining bankruptcy claims. Additionally, Other, net included a $5.0 million recoupment of previously placed collateral for certain firm transportation commitments during our Chapter 11 filing.

Other, net in the Company's consolidated statements of operations for the nine months ended September 30, 2022, included $11.5 million related to the TC claim distribution received as discussed in Note 9. Additionally, Other, net included a $5.1 million payment to settle certain gas imbalance positions and a $5.2 million receipt of funds from a litigation settlement.

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


	Nine Months Ended September 30, 2023		Nine Months Ended September 30, 2022
Supplemental disclosure of cash flow information:
Interest payments, net of amounts capitalized	$	29,073	$	30,102
Changes in operating assets and liabilities, net:
Accounts receivable - oil and natural gas sales	$	171,673	$	(84,674)
Accounts receivable - joint interest and other	9,114		(14,947)
Accounts payable and accrued liabilities	(123,657)		65,648
Prepaid expenses	356		3,061
Other assets	52		1,352
Total changes in operating assets and liabilities, net	$	57,538	$	(29,560)
Supplemental disclosure of non-cash transactions:
Capitalized stock-based compensation	$	3,023	$	2,141
Asset retirement obligation capitalized	$	505	$	53
Asset retirement obligation removed due to divestiture and settlements	$	(1,267)	$	(7)
Release of common stock held in reserve	$	—	$	28,220

2.PROPERTY AND EQUIPMENT

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


	September 30, 2023		December 31, 2022
Proved oil and natural gas properties	$	2,802,653	$	2,418,666
Unproved properties	196,947		178,472
Other depreciable property and equipment	7,734		5,977
Land	386		386
Total property and equipment	3,007,720		2,603,501
Accumulated DD&A	(784,635)		(545,771)
Property and equipment, net	$	2,223,085	$	2,057,730

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. The Company did not record an impairment of its oil and natural gas properties for the three or nine months ended September 30, 2023 or 2022.

Certain general and administrative costs are capitalized to the full cost pool and represent management’s estimate of costs incurred directly related to exploration and development activities. All general and administrative costs not capitalized are charged to expense as they are incurred. Capitalized general and administrative costs were approximately $5.7 million and $16.2 million, for the three and nine months ended September 30, 2023, respectively, and $4.9 million and $14.6 million for the three and nine months ended September 30, 2022, 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.

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


	September 30, 2023		December 31, 2022
Utica	$	169,314	$	147,370
SCOOP	27,633		31,102
Total unproved properties	$	196,947	$	178,472

Asset Retirement Obligation

The following table provides a reconciliation of the Company’s asset retirement obligation for the nine months ended September 30, 2023 and 2022 (in thousands):


	Nine Months Ended September 30, 2023		Nine Months Ended September 30, 2022
Asset retirement obligation, beginning of period	$	33,171	$	28,264
Liabilities incurred	505		53
Liabilities settled	(604)		—
Liabilities removed due to divestitures	(919)		(7)
Accretion expense	2,117		2,057
Total asset retirement obligation, end of period	$	34,270	$	30,367

3.DEBT

Debt consisted of the following items as of September 30, 2023 and December 31, 2022 (in thousands):


	September 30, 2023		December 31, 2022
8.0% senior unsecured notes due 2026	$	550,000	$	550,000
Credit Facility due 2027	95,000		145,000
Net unamortized debt issuance costs	(676)		(845)
Total debt, net	644,324		694,155
Less: current maturities of long-term debt	—		—
Total long-term debt, net	$	644,324	$	694,155

Credit Facility

On October 14, 2021, the Company entered into the Existing Credit Facility with JPMorgan Chase Bank, N.A., as administrative agent, and various lender parties. The Existing Credit Facility provided for an aggregate maximum principal amount of up to $1.5 billion. The Existing Credit Facility also provides for a $175.0 million sublimit of the aggregate commitments that is available for the issuance of letters of credit.

The borrowing base is redetermined semiannually on or around May 1 and November 1 of each year. On October 27, 2023, the Company completed its semi-annual borrowing base redetermination as discussed in Note 16.

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On May 2, 2022, the Company completed its semi-annual borrowing base redetermination and entered into the Amendment to Borrowing Base Redetermination Agreement and First Amendment to our Credit Agreement, which amended the Existing Credit Facility. The amendment, among other things, (a) increased the borrowing base under the Credit Facility from $850 million to $1.0 billion with the elected commitments remaining at $700 million, (b) amended certain covenants related to hedging to ease certain requirements and limitations, (c) amended the covenants governing restricted payments to (i) increase the Net Leverage Ratio allowing unlimited restricted payments from 1.00 to 1.00 to 1.25 to 1.00 and (ii) permit additional restricted payments to redeem preferred equity until December 31, 2022 provided certain leverage, no event of default or borrowing base deficiency and availability tests were met, and (d) provided for the transition from a LIBOR to a SOFR benchmark, with a 10 basis point credit spread adjustment for all tenors.

On October 31, 2022, the Company completed its semi-annual borrowing base redetermination and entered into the Borrowing Base Reaffirmation Agreement and Second Amendment to our Credit Agreement, which amended the Existing Credit Facility. The amendment, among other things, reaffirmed the borrowing base under the Credit Facility at $1.0 billion and the elected commitments at $700 million.

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 Existing Credit Facility (as amended, the “Credit Facility”). The Third Amendment, among other things, (a) increased the aggregate elected commitment amounts under the Credit Facility from $700 million to $900 million, (b) increased the borrowing base under the Credit Facility from $1 billion to $1.1 billion, (c) increased the excess cash threshold under the Credit Facility from $45 million to $75 million, and (d) extended the maturity date under the Credit Facility from October 14, 2025 to the earlier of (i) May 1, 2027 and (ii) the 91st day prior to the maturity date of the 2026 Senior Notes or any other permitted senior notes or any permitted refinancing debt under the Credit Facility having an aggregate outstanding principal amount equal to or exceeding $100 million; provided that such notes have not been refinanced, redeemed or repaid in full on or prior to such 91st day.

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 2.75% 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. The Company is 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 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 3.25 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 September 30, 2023, the Company had $95.0 million outstanding borrowings under the Credit Facility, $66.9 million in letters of credit outstanding and was in compliance with all covenants under the credit agreement.

For the three and nine months ended September 30, 2023 and 2022, the Credit Facility bore interest at a weighted average rate of 8.28%, 8.05%, 5.41% and 4.42%, respectively.

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2026 Senior Notes

On the Emergence Date, pursuant to the terms of the Plan, the Company issued $550 million aggregate principal amount of its 8.0% senior notes due 2026. The notes are guaranteed on a senior unsecured basis by each of the Company's subsidiaries that guarantee the Credit Facility. Interest on the 2026 Senior Notes is payable semi-annually, on June 1 and December 1 of each year. The 2026 Senior Notes were issued under the Indentures, dated as of May 17, 2021, by and among the Issuer, UMB Bank, National Association, as trustee, and the Guarantors and mature on May 17, 2026.

The covenants of the 1145 Indenture (other than the payment covenant) require that the Company comply with the covenants of the 4(a)(2) Indenture, as amended. The 4(a)(2) Indenture contains covenants limiting the Issuer’s and its restricted subsidiaries’ ability to (i) incur additional debt, (ii) pay dividends or distributions in respect of certain equity interests or redeem, repurchase or retire certain equity interests or subordinated indebtedness, (iii) make certain investments, (iv) create restrictions on distributions from restricted subsidiaries, (v) engage in specified sales of assets, (vi) enter into certain transactions among affiliates, (vii) engage in certain lines of business, (viii) engage in consolidations, mergers and acquisitions, (ix) create unrestricted subsidiaries and (x) incur or create liens. These covenants contain important exceptions, limitations and qualifications. At any time that the 2026 Senior Notes are rated investment grade, certain covenants will be terminated and cease to apply.

Capitalization of Interest

The Company capitalized $1.1 million and $3.0 million in interest expense for the three and nine months ended September 30, 2023, respectively. The Company did not capitalize interest expense for the three and nine months ended September 30, 2022.

Fair Value of Debt

At September 30, 2023, the carrying value of the outstanding debt represented by the 2026 Senior Notes was $549.3 million. Based on the quoted market prices (Level 1), the fair value of the 2026 Senior Notes was determined to be $550.6 million at September 30, 2023.

4.MEZZANINE EQUITY

On the Emergence Date, 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 (the "Liquidation Preference").

Preferred Stock

On the Emergence Date, the Successor issued 55,000 shares of preferred stock.

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

Each holder of shares of preferred stock has the right (the “Conversion Right”), at its option and at any time, to convert all or a portion of the shares of preferred stock that it holds into a number of shares of common stock equal to the quotient obtained by dividing (x) the product obtained by multiplying (i) the Liquidation Preference times (ii) an amount equal to one (1) plus the Per Share Makewhole Amount (as defined in the Preferred Terms) on the date of conversion, by (y) $14.00 per share (as may be adjusted under the Preferred Terms). The shares of preferred stock outstanding at September 30, 2023 would convert to approximately 3.2 million shares of common stock if all holders of preferred stock exercised their Conversion Right.

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Gulfport shall have the right, but not the obligation, to 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) (y) if the date of such redemption is on or prior to the three year anniversary of the Emergence Date, the sum of the Liquidation Preference plus the sum of all unpaid PIK Dividends through the three year anniversary of the Emergence Date, or (x) if the date of such redemption is after the three year anniversary of the Emergence Date, the Liquidation Preference (the “Redemption Price”).

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

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

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

Dividends and Conversions

During the three and nine months ended September 30, 2023, the Company paid $1.1 million and $3.7 million, respectively, of cash dividends to holders of our preferred stock.

The following table summarizes activity of the Company’s preferred stock for the nine months ended September 30, 2023:


			Conversion of Preferred Stock
Preferred stock at December 31, 2022			52,295
First quarter 2023			—
Second quarter 2023			(5,836)
Third quarter 2023			(1,130)
Preferred stock at September 30, 2023			45,329

5.EQUITY

Common Stock

On the Emergence Date, 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 2022, approximately 876,000 shares in the Disputed Claims Reserve at December 31, 2021 were issued to certain claimants. As of September 30, 2023, approximately 62,000 shares continue to be held in the Disputed Claims Reserve and may be issued upon finalization of remaining claims.

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Common Stock Offering

On June 26, 2023, Gulfport completed an underwritten public offering of 1.5 million shares of its common stock by certain stockholders at a price to the public of $95.00 per share. Gulfport did not sell any of its common stock as part of this offering and did not receive any proceeds from the sale of the shares sold by the selling stockholders.

Concurrent with the closing of the offering, Gulfport purchased 263,158 shares of its common stock at $95.00 per share. The repurchase was part of the Company's existing Repurchase Program discussed below.

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 and subsequently increased the authorization to $300 million. On February 27, 2023, the Board of Directors approved an increase to the authorization up to $400 million, extending the Repurchase Program through March 31, 2024. On September 20, 2023, the Board of Directors approved an increase to the authorization up to $650 million, extending the Repurchase Program through December 31, 2024. Purchases under the Repurchase Program may be made from time to time in open market or privately negotiated transactions, and will be subject to available liquidity, market conditions, credit agreement restrictions, applicable legal requirements, contractual obligations and other factors. The Repurchase Program does not require the Company to acquire any specific number of shares of common stock. The Company intends to purchase shares under the Repurchase Program with available funds while maintaining sufficient liquidity to fund its capital development program. The Repurchase Program may be suspended from time to time, modified, extended or discontinued by the Board of Directors at any time.

The following table summarizes activity under the Repurchase Program for the nine months ended September 30, 2023 (number of shares and dollar value of shares purchased shown in thousands):


	Total Number of Shares Purchased	Dollar Value of Shares Purchased		Average Price Paid Per Share
First quarter 2023	459	$	32,873	$	71.61
Second quarter 2023	442	41,358		$	93.67
Third quarter 2023	76	8,681		$	113.97
Total	977	$	82,912	$	84.88

As of September 30, 2023, the Company has repurchased 3.9 million shares for $333.7 million at a weighted average price of $86.07 per share since the inception of the Repurchase Program.

6.STOCK-BASED COMPENSATION

As of the Emergence Date, the Board of Directors adopted the Incentive Plan with a share reserve of 2.8 million shares of common stock. The Incentive Plan provides for the grant of incentive stock options, nonstatutory stock options, restricted stock, restricted stock units, stock appreciation rights, dividend equivalents and performance awards or any combination of the foregoing. The Company has granted both restricted stock units and performance vesting restricted stock units to employees and directors pursuant to the Incentive Plan, as discussed below.

During the three and nine months ended September 30, 2023, the Company's stock-based compensation expense was $3.5 million and $9.2 million, of which the Company capitalized $1.2 million and $3.0 million, respectively, relating to its exploration and development efforts. During the three and nine months ended September 30, 2022, the Company's stock-based compensation expense was $2.4 million and $6.3 million, of which the Company capitalized $0.8 million and $2.1 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 September 30, 2023, the Company has awarded an aggregate of approximately 368,891 restricted stock units and approximately 274,624 performance vesting restricted stock units under the Incentive Plan.

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The following tables summarizes activity for the nine months September 30, 2023 and 2022:


	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, 2023	197,772	$	77.49	190,804	$	52.15
Granted	43,415	77.84		68,726	56.57
Vested	(11,608)	70.86		—	—
Forfeited/canceled	(971)	87.68		(5,069)	47.67
Unvested shares as of March 31, 2023	228,608	$	77.85	254,461	$	53.43
Granted	55,041	94.53		15,094	66.66
Vested	(43,088)	86.28		—	—
Forfeited/canceled	(1,401)	89.08		(10,731)	50.69
Unvested shares as of June 30, 2023	239,160	$	80.10	258,824	$	54.32
Granted	6,319	109.82		—	—
Vested	(46,823)	67.17		—	—
Forfeited/canceled	(4,761)	92.93		(853)	47.67
Unvested shares as of September 30, 2023	193,895	$	83.88	257,971	$	54.34


	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, 2022	198,413	$	66.04	153,138	$	48.54
Granted	2,154	73.83		—	—
Vested	(3,074)	65.75		—	—
Forfeited/canceled	(1,157)	66.89		—	—
Unvested shares as of March 31, 2022	196,336	$	67.16	153,138	$	48.54
Granted	76,038	97.55		37,666	66.82
Vested	(10,817)	63.53		—	—
Forfeited/canceled	(3,752)	75.70		—	—
Unvested shares as of June 30, 2022	257,805	$	75.37	190,804	$	52.15
Granted	—	—		—	—
Vested	(52,701)	66.18		—	—
Forfeited/canceled	(3,265)	85.36		—	—
Unvested shares as of September 30, 2022	201,839	$	77.60	190,804	$	52.15

Restricted Stock Units

Restricted stock units awarded under the Incentive Plan generally vest over a period of 3 or 4 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 September 30, 2023, was $13.5 million. The expense is expected to be recognized over a weighted average period of 2.05 years.

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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 total shareholder return ("TSR") and (ii) the Company's relative total shareholder return ("RTSR") for the performance period. Participants will earn from 0% to 200% of the target award based on the Company's TSR and RTSR ranking compared to the TSR of the companies in the Company's designated peer group at the end of the performance period. Awards will be earned and vested at the end of a three-year performance period, subject to earlier termination of the performance period in the event of a change in control. The grant date fair values were determined using the Monte Carlo simulation method and are being recorded ratably over the performance period.

The table below summarizes the assumptions used in the Monte Carlo simulation to determine the grant date fair value of awards granted during the nine months ended September 30, 2023:


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

Unrecognized compensation expense as of September 30, 2023, related to performance vesting restricted shares was $6.3 million. The expense is expected to be recognized over a weighted average period of 1.81 years.

7.RESTRUCTURING COSTS

During the nine months ended September 30, 2023, Gulfport recognized $4.8 million in personnel-related restructuring expenses associated with changes in the organizational structure and leadership team resulting from the appointment of Gulfport's new CEO in January 2023. Of these expenses, $1.3 million resulted from accelerated vesting of certain share-based grants, which are non-cash charges.

The following table summarizes the personnel-related restructuring expenses for the nine months ended September 30, 2023 (in thousands):


	Personnel-Related Restructuring Expenses
First quarter 2023	$	1,869
Second quarter 2023	2,893
Third quarter 2023	—
Total	$	4,762

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.

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There were 0.3 million shares of restricted stock that were considered dilutive for each of the three and nine months ended September 30, 2023. There were no shares of restricted stock that were considered dilutive for the three and nine months ended September 30, 2022. There were 3.2 million potential shares of common stock issuable due to the Company's convertible preferred stock for each of the three and nine months ended September 30, 2023. There were 3.7 million potential shares of common stock issuable due to the Company's convertible preferred stock for each of the three and nine months ended September 30, 2022. There were 1.2 million and 1.5 million shares of restricted stock that were considered anti-dilutive during the three and nine months ended September 30, 2022, respectively.

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 September 30, 2023		Three Months Ended September 30, 2022
Net income (loss)	$	608,444	$	(18,472)
Dividends on preferred stock	(1,133)		(1,309)
Participating securities - preferred stock(1)	(89,756)		—
Net income (loss) attributable to common stockholders	$	517,555	$	(19,781)
Re-allocation of participating securities	1,147		—
Diluted net income (loss) attributable to common stockholders	$	518,702	$	(19,781)
Basic Shares	18,670		19,635
Dilutive Shares	18,954		19,635
Basic EPS	$	27.72	$	(1.01)
Dilutive EPS	$	27.37	$	(1.01)

_____________________

(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.


	Nine Months Ended September 30, 2023		Nine Months Ended September 30, 2022
Net income (loss)	$	1,225,185	$	(253,867)
Dividends on preferred stock	(3,718)		(4,136)
Participating securities - preferred stock(1)	(180,394)		—
Net income (loss) attributable to common stockholders	$	1,041,073	$	(258,003)
Re-allocation of participating securities	2,043		—
Diluted net income (loss) attributable to common stockholders	$	1,043,116	$	(258,003)
Basic Shares	18,686		20,514
Dilutive Shares	18,937		20,514
Basic EPS	$	55.72	$	(12.58)
Dilutive EPS	$	55.08	$	(12.58)

_____________________

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9.COMMITMENTS AND CONTINGENCIES

Commitments

Future 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 September 30, 2023, are set forth in the table below (in thousands):


Remaining 2023	$	56,061
2024	219,434
2025	137,795
2026	134,324
2027	136,492
Thereafter	737,104
Total	$	1,421,210

Other Operational Commitments

The Company entered into various contractual commitments to purchase inventory and other material to be used in future activities. The Company's commitment to purchase these materials spans 2023 and 2024, with approximately $19.8 million remaining in 2023 and $23.5 million for 2024.

Contingencies

Litigation and Regulatory Proceedings

As part of its Chapter 11 Cases and restructuring efforts, the Company filed motions to reject certain firm transportation agreements between the Company and affiliates of TC Energy Corporation ("TC") and Rover Pipeline LLC ("Rover"). During the third quarter of 2021, Gulfport finalized a settlement agreement with TC that was approved by the Bankruptcy Court on September 21, 2021. Pursuant to the settlement agreement, Gulfport and TC agreed that the firm transportation contracts between them would be rejected without any further payment or obligation by either party, and TC assigned its damages claims from such rejection to Gulfport. In exchange, Gulfport agreed to make a payment of $43.8 million in cash to TC. The $43.8 million was paid on October 7, 2021. Gulfport expects to receive distributions for a significant portion of such amounts through future distributions with respect to the assigned claims pursuant to the terms of the Plan that became effective in May 2021. Any future distributions will be recognized once received by Gulfport. In February 2022, Gulfport received an initial distribution of $11.5 million from the above-mentioned claim, which is included in Other, net in the accompanying consolidated statements of operations.

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During the first quarter of 2023, Gulfport finalized a settlement agreement with Rover that was approved by the Bankruptcy Court on February 21, 2023. Pursuant to the settlement agreement, Gulfport and Rover agreed that the firm transportation contracts between them would be rejected. The Bankruptcy Court Order provided Rover will: (a) receive an allowed $85.9 million Class 4A General Unsecured Claim (the “Rover Unsecured Claim”), (b) receive an administrative claim of $1.0 million payable by Gulfport, and (c) draw the full amount of its credit assurance. Gulfport paid the $1.0 million administrative claim during the first quarter, and has no further obligations to Rover. The Rover Unsecured Claim will receive distributions under the Plan payable from the liquidating trust, not Gulfport. On February 24, 2023, Gulfport received an additional $17.8 million interim distribution for its TC claim. The timing and amount of any future distributions to Gulfport are not certain, and the total amount received will be impacted by the liquidating trust’s distributions and resolution of other remaining bankruptcy claims. These payments are included in Other, net in the accompanying consolidated statements of operations.

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 Marcellus and Utica shale geological formations and allege that Defendants have willfully trespassed and illegally produced oil, natural gas, and other hydrocarbon products beyond these respective formations. Plaintiffs seek the full value of any production from below the Marcellus and Utica 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 for amounts allegedly owed to the plaintiffs through 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.

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.

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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.

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 September 30, 2023.


	Index	Daily Volume	Weighted Average Price
Natural Gas		(MMBtu/d)	($/MMBtu)
Remaining 2023	NYMEX Henry Hub	280,000	$	4.36
2024	NYMEX Henry Hub	324,973	$	4.05
2025	NYMEX Henry Hub	110,000	$	4.09

Oil		(Bbl/d)	($/Bbl)
Remaining 2023	NYMEX WTI	3,000	$	74.47
2024	NYMEX WTI	500	$	77.50

NGL		(Bbl/d)	($/Bbl)
Remaining 2023	Mont Belvieu C3	3,000	$	38.07
2024	Mont Belvieu C3	2,000	$	30.30

Each two-way price 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.

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The Company has entered into natural gas and crude oil costless collars based off the NYMEX Henry Hub and NYMEX WTI indices. Below is a summary of the Company's costless collar positions as of September 30, 2023.


	Index	Daily Volume	Weighted Average Floor Price		Weighted Average Ceiling Price
Natural Gas		(MMBtu/d)	($/MMBtu)		($/MMBtu)
Remaining 2023	NYMEX Henry Hub	285,000	$	2.93	$	4.78
2024	NYMEX Henry Hub	180,000	$	3.43	$	5.49
2025	NYMEX Henry Hub	100,000	$	3.62	$	4.54

Oil		(Bbl/d)	($/Bbl)		($/Bbl)
2024	NYMEX WTI	1,000	$	62.00	$	80.00

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 September 30, 2023.


	Index	Daily Volume	Weighted Average Price
Natural Gas		(MMBtu/d)	($/MMBtu)
Remaining 2023	NYMEX Henry Hub	407,925	$	3.21
2024	NYMEX Henry Hub	202,000	$	3.33
2025	NYMEX Henry Hub	193,315	$	5.80

In addition, the Company has entered into natural gas basis swap positions. These instruments are arrangements that guarantee a fixed price differential to NYMEX Henry Hub from a specified delivery point. The Company receives the fixed price differential and pays the floating market price differential to the counterparty for the hedged community. As of September 30, 2023, 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 2023	Rex Zone 3	NYMEX Plus Fixed Spread	140,000	$	(0.22)
Remaining 2023	NGPL TXOK	NYMEX Plus Fixed Spread	80,000	$	(0.35)
Remaining 2023	TETCO M2	NYMEX Plus Fixed Spread	210,000	$	(0.91)
2024	Rex Zone 3	NYMEX Plus Fixed Spread	150,000	$	(0.15)
2024	NGPL TXOK	NYMEX Plus Fixed Spread	70,000	$	(0.31)
2024	TETCO M2	NYMEX Plus Fixed Spread	89,945	$	(0.91)

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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 September 30, 2023 and December 31, 2022 (in thousands):


	September 30, 2023		December 31, 2022
Short-term derivative asset	$	136,706	$	87,508
Long-term derivative asset	32,687		26,525
Short-term derivative liability	(50,947)		(343,522)
Long-term derivative liability	(54,020)		(118,404)
Total commodity derivative position	$	64,426	$	(347,893)

Gains and Losses

The following table presents the gain and loss recognized in net gain (loss) on natural gas, oil and NGL derivatives in the accompanying consolidated statements of operations for the three and nine months ended September 30, 2023 and 2022 (in thousands):


	Net gain (loss) on derivative instruments
	Three Months Ended September 30, 2023		Three Months Ended September 30, 2022
Natural gas derivatives - fair value gains (losses)	$	4,534	$	(161,532)
Natural gas derivatives - settlement gains (losses)	48,522		(354,084)
Total gains (losses) on natural gas derivatives	53,056		(515,616)

Oil derivatives - fair value (losses) gains	(8,414)		33,545
Oil derivatives - settlement losses	(2,130)		(9,035)
Total (losses) gains on oil and condensate derivatives	(10,544)		24,510

NGL derivatives - fair value (losses) gains	(5,763)		19,043
NGL derivatives - settlement gains (losses)	2,668		(2,832)
Total (losses) gains on NGL derivatives	(3,095)		16,211

Total gains (losses) on natural gas, oil and NGL derivatives	$	39,417	$	(474,895)

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	Net gain (loss) on derivative instruments
	Nine Months Ended September 30, 2023		Nine Months Ended September 30, 2022
Natural gas derivatives - fair value gains (losses)	$	416,473	$	(659,193)
Natural gas derivatives - settlement gains (losses)	97,794		(754,177)
Total gains (losses) on natural gas derivatives	514,267		(1,413,370)

Oil derivatives - fair value (losses) gains	(1,424)		8,076
Oil derivatives - settlement losses	(2,204)		(31,460)
Total losses on oil and condensate derivatives	(3,628)		(23,384)

NGL derivatives - fair value (losses) gains	(2,730)		14,216
NGL derivatives - settlement gains (losses)	6,357		(13,779)
Total gains on NGL derivatives	3,627		437

Total gains (losses) on natural gas, oil and NGL derivatives	$	514,266	$	(1,436,317)

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 September 30, 2023
	Gross Assets (Liabilities) Presented in the Consolidated Balance Sheets		Gross Amounts Subject to Master Netting Agreements		Net Amount
Derivative assets	$	169,393	$	(52,741)	$	116,652
Derivative liabilities	$	(104,967)	$	52,741	$	(52,226)


	As of December 31, 2022
	Gross Assets (Liabilities) Presented in the Consolidated Balance Sheets		Gross Amounts Subject to Master Netting Agreements		Net Amount
Derivative assets	$	114,033	$	(80,345)	$	33,688
Derivative liabilities	$	(461,926)	$	80,345	$	(381,581)

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.

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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.

Financial assets and liabilities

The following tables summarize the Company’s financial and non-financial assets and liabilities by valuation level as of September 30, 2023 and December 31, 2022 (in thousands):


	September 30, 2023
	Level 1		Level 2		Level 3
Assets:
Derivative instruments	$	—	$	169,393	$	—
Contingent consideration arrangement	—		—		3,100
Total assets	$	—	$	169,393	$	3,100
Liabilities:
Derivative instruments	$	—	$	104,967	$	—


	December 31, 2022
	Level 1		Level 2		Level 3
Assets:
Derivative instruments	$	—	$	114,033	$	—
Contingent consideration arrangement	—		—		4,900
Total assets	$	—	$	114,033	$	4,900
Liabilities:
Derivative instruments	$	—	$	461,926	$	—

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.

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The Company's SCOOP water infrastructure sale, which closed in the first quarter of 2020, included a contingent consideration arrangement. As of September 30, 2023, the fair value of the contingent consideration was $3.1 million, of which $0.2 million is included in prepaid expenses and other assets and $2.9 million is included in other assets in the accompanying consolidated balance sheets. The fair value of the contingent consideration arrangement is calculated using discounted cash flow techniques and is based on internal estimates of the Company's future development program and water production levels. Given the unobservable nature of the inputs, the fair value measurement of the contingent consideration arrangement is deemed to use Level 3 inputs. The Company has elected the fair value option for this contingent consideration arrangement and, therefore, records changes in fair value in earnings. The Company did not recognize a gain or loss for the three months ended September 30, 2023, and recognized a loss of $1.2 million for the nine months ended September 30, 2023 with respect to this contingent consideration arrangement. The Company recognized losses of $0.3 million and $0.4 million for the three and nine months ended September 30, 2022, respectively, with respect to this contingent consideration arrangement. These fair value changes are included in other expense (income) 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 2 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.

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.

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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 $106.7 million and $278.4 million as of September 30, 2023 and December 31, 2022, respectively, and are reported in accounts receivable - oil and natural gas sales, 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.

The Company has entered into contracts for drilling rigs with varying terms with third parties to ensure operational continuity, cost control and rig availability in its operations. The Company has concluded its drilling rig contracts are operating leases as the assets are identifiable and the Company has the right to control the identified assets. At September 30, 2023, the Company had one active long-term drilling rig contract.

The Company rents office space for its corporate headquarters, field locations and certain other equipment from third parties, which expire at various dates through 2026. 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.

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Future amounts due under operating lease liabilities as of September 30, 2023 were as follows (in thousands):


Remaining 2023	$	3,423
2024	13,439
2025	836
2026	561
2027	10
Total lease payments	$	18,269
Less: imputed interest	(804)
Total	$	17,465

The tables below summarize lease costs for the periods presented (in thousands):


	Three Months Ended September 30, 2023		Three Months Ended September 30, 2022
Operating lease cost	$	3,443	$	187

Short-term lease cost	5,112		8,035
Total lease cost(1)	$	8,555	$	8,222


	Nine Months Ended September 30, 2023		Nine Months Ended September 30, 2022
Operating lease cost	$	10,329	$	287

Short-term lease cost	22,410		26,817
Total lease cost(1)	$	32,739	$	27,104

_____________________

(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.

Supplemental cash flow information related to leases was as follows (in thousands):


	Nine Months Ended September 30, 2023		Nine Months Ended September 30, 2022
Cash paid for amounts included in the measurement of lease liabilities
Operating cash flows from operating leases	$	5,313	$	354

The weighted-average remaining lease term as of September 30, 2023 was 1.45 years. The weighted-average discount rate used to determine the operating lease liability as of September 30, 2023 was 6.71%.

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.

For the nine months ended September 30, 2023, the Company's effective tax rate for the period was (83)%, which differs from the statutory rate of 21% primarily as a result of the partial release of the valuation allowance on the Company's deferred tax assets.

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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 estimates a $701.5 million and $17.4 million reduction in the related valuation allowance associated with its federal and state deferred tax assets, respectively, will be recognized throughout the year.

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

Concurrent with the closing of the offering transaction discussed in Note 5, the Company purchased 215,060 shares of its common stock from Silver Point Capital, L.P. for approximately $20.4 million. The repurchase was part of the Company's Repurchase Program. Upon closing of the transaction on June 26, 2023, the repurchased common stock was cancelled.

16.SUBSEQUENT EVENTS

Credit Facility Redetermination

On October 27, 2023, the Company 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.

Natural Gas, Oil and NGL Derivative Instruments

Subsequent to September 30, 2023, as of October 26, 2023, the Company entered into the following derivative contracts:

Period

Type of Derivative Instrument

Index

Daily Volume

Weighted
Average Price

Natural Gas

(MMBtu/d)

($/MMBtu)

2024

Costless Collars

NYMEX Henry Hub

45,000

$3.10 / $3.77

2024

Basis Swaps

TETCO M2

50,000

$(0.99)

2025

Swaps

NYMEX Henry Hub

40,000

$4.04

NGL

(Bbl/d)

($/Bbl)

2024

Swaps

Mont Belvieu C3

500

$30.03

2025

Swaps

Mont Belvieu C3

1,000

$30.03

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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, 2022 (“2022 Form 10-K”) and analyzes the changes in the results of operations between the periods of July 1, 2023 through September 30, 2023, January 1, 2023 through September 30, 2023, July 1, 2022 through September 30, 2022 and January 1, 2022 through September 30, 2022. 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

Leadership Changes

In January 2023, our CEO Tim Cutt, resigned his position as CEO. Mr. Cutt, who served as CEO and Chairman since 2021, retained his position of Chairman of the Board of Directors. Subsequent to Mr. Cutt's resignation, Gulfport named John Reinhart CEO and Director, effective January 24, 2023. In addition, Matthew Rucker joined Gulfport's leadership team as Senior Vice President of Operations.

In April 2023, Gulfport named Michael Hodges Executive Vice President and Chief Financial Officer. William Buese resigned as Executive Vice President and Chief Financial Officer of the Company on April 1, 2023. Mr. Buese remained with the Company as an adviser until his termination on May 3, 2023.

Effective August 2, 2023, Matthew B. Willrath was promoted to Vice President and Chief Accounting Officer. Prior to the promotion, Mr. Willrath served as our Vice President and Controller and has been with Gulfport Energy since February 2020.

Credit Facility

On October 27, 2023, 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.

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Common Stock Offering

Share Repurchase Program

On September 20, 2023, the Company's Board of Directors approved an increase to the authorized common stock Repurchase Program from $400 million to $650 million, extending the Repurchase Program through December 31, 2024. During the three months ended September 30, 2023, the Company repurchased 76,170 shares for $8.7 million at a weighted average price of $113.97 per share. As of September 30, 2023, the Company repurchased 3.9 million shares for $333.7 million at a weighted average price of $86.07 per share since the inception of the Repurchase Program.

Inflation, Rising Interest Rates and Changes in Commodity Prices

The annual rate of inflation in the United States continues to be elevated as compared to historical averages. The Federal Reserve has tightened monetary policy by approving a series of increases to the Federal Funds Rate. Furthermore, the Chairman of the Federal Reserve signaled that the Federal Reserve would continue to take necessary action to bring inflation down and to ensure price stability. The inflationary environment has impacted interest rates on our Credit Facility borrowings throughout 2022 and into 2023. Interest rates on our Credit Facility borrowings have increased from a weighted average of 5.41% and 4.42% for the three and nine months ended September 30, 2022, respectively, to 8.28% and 8.05% for the three and nine months ended September 30, 2023, respectively. Additional increases in interest rates may have a negative impact on the Company’s ability to continue to execute its business strategy.

Our revenues, the value of our assets, and our ability to obtain bank loans or additional capital on attractive terms have been and will continue to be affected by changes in natural gas, oil and NGL prices and the costs to produce our reserves. Natural gas, oil and NGL prices are subject to significant fluctuations that are beyond our ability to control or predict. Certain of our capital expenditures and expenses are affected by general inflation and we expect costs for 2023 to continue to be a function of supply and demand; however, we do not expect inflation to significantly impact cash flow in 2023 as a result of commitments that were entered into during 2022.

Impact of the War in Ukraine and the Israel-Hamas War

The invasion of Ukraine by Russia and the sanctions imposed in response to the crisis have increased volatility in the global financial markets and are expected to have further global economic consequences, including disruptions of the global energy markets and the amplification of inflation and supply chain constraints. Other armed conflicts, including the ongoing Israel-Hamas war, may result in further disruptions in the global economic environment. The ultimate impact of the war in Ukraine and the Israel-Hamas war will depend on future developments and the timing and extent to which normal economic and operating conditions resume.

2023 Operational and Financial Highlights

During the third quarter of 2023, we had the following notable achievements:

•Reported total net production of 1,056.9 MMcfe per day.

•Drilled and completed Marcellus two-well pad in Belmont County, Ohio.

•Turned to sales 5 gross (4.87 net) operated wells.

•Generated $156.3 million of operating cash flows.

•Expanded the Repurchase Program authorization from $400 million to $650 million.

•Repurchased 76,170 shares for $8.7 million at a weighted average price of $113.97 per share.

•Reaffirmed the $1.1 billion borrowing base and $900 million elected commitment under our Credit Facility.

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2023 Production and Drilling Activity

Production Volumes


	Three Months Ended September 30, 2023	Three Months Ended September 30, 2022
Natural gas (Mcf/day)
Utica	795,191	597,027
SCOOP	176,161	218,633

Total	971,352	815,660
Oil and condensate (Bbl/day)
Utica	528	646
SCOOP	2,667	3,721

Total	3,195	4,366
NGL (Bbl/day)
Utica	2,271	2,458
SCOOP	8,790	9,714

Total	11,061	12,172
Combined (Mcfe/day)
Utica	811,985	615,649
SCOOP	244,902	299,239

Total	1,056,887	914,888
Totals may not sum or recalculate due to rounding.

Our total net production averaged approximately 1,056.9 MMcfe per day during the three months ended September 30, 2023, as compared to 914.9 MMcfe per day during the three months ended September 30, 2022. The 16% increase in production per day is largely the result of our 2022 and 2023 development programs.

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	Nine Months Ended September 30, 2023	Nine Months Ended September 30, 2022
Natural gas (Mcf/day)
Utica	755,372	664,967
SCOOP	198,616	200,847

Total	953,989	865,814
Oil and condensate (Bbl/day)
Utica	558	689
SCOOP	3,256	3,539

Total	3,813	4,228
NGL (Bbl/day)
Utica	2,466	2,252
SCOOP	9,921	9,275

Total	12,387	11,526
Combined (Mcfe/day)
Utica	773,512	682,611
SCOOP	277,676	277,730

Total	1,051,188	960,341
Totals may not sum or recalculate due to rounding.

Our total net production averaged approximately 1,051.2 MMcfe per day during the nine months ended September 30, 2023, as compared to 960.3 MMcfe per day during the nine months ended September 30, 2022. The 9% increase in production per day is largely the result of our 2022 and 2023 development programs.

Utica. We spud five gross (4.99 net) wells in the Utica during the three months ended September 30, 2023. In addition, we commenced sales on five gross (4.87 net) operated wells.

As of October 26, 2023, we had two operated drilling rigs running in Ohio drilling the Utica formation.

SCOOP. We did not spud or commence sales on any operated wells in the SCOOP during the three months ended September 30, 2023.

As of October 26, 2023, 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 September 30, 2023 and 2022

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 September 30, 2023 as compared to the three months ended September 30, 2022. Some totals below may not sum or recalculate due to rounding.


	Three Months Ended September 30, 2023		Three Months Ended September 30, 2022
Natural gas sales
Natural gas production volumes (MMcf)	89,364		75,041
Natural gas production volumes (MMcf) per day	971		816
Total sales	$	177,401	$	585,596
Average price without the impact of derivatives ($/Mcf)	$	1.99	$	7.80
Impact from settled derivatives ($/Mcf)	$	0.54	$	(4.72)
Average price, including settled derivatives ($/Mcf)	$	2.53	$	3.08

Oil and condensate sales
Oil and condensate production volumes (MBbl)	294		402
Oil and condensate production volumes (MBbl) per day	3		4
Total sales	$	22,896	$	36,050
Average price without the impact of derivatives ($/Bbl)	$	77.90	$	89.75
Impact from settled derivatives ($/Bbl)	$	(7.25)	$	(22.49)
Average price, including settled derivatives ($/Bbl)	$	70.65	$	67.26

NGL sales
NGL production volumes (MBbl)	1,018		1,120
NGL production volumes (MBbl) per day	11		12
Total sales	$	26,953	$	44,351
Average price without the impact of derivatives ($/Bbl)	$	26.49	$	39.61
Impact from settled derivatives ($/Bbl)	$	2.62	$	(2.53)
Average price, including settled derivatives ($/Bbl)	$	29.11	$	37.08

Natural gas, oil and condensate and NGL sales
Natural gas equivalents (MMcfe)	97,234		84,170
Natural gas equivalents (MMcfe) per day	1,057		915
Total sales	$	227,250	$	665,997
Average price without the impact of derivatives ($/Mcfe)	$	2.34	$	7.91
Impact from settled derivatives ($/Mcfe)	$	0.50	$	(4.35)
Average price, including settled derivatives ($/Mcfe)	$	2.84	$	3.56

Production Costs:
Average lease operating expenses ($/Mcfe)	$	0.16	$	0.18
Average taxes other than income ($/Mcfe)	$	0.07	$	0.20
Average transportation, gathering, processing and compression ($/Mcfe)	$	0.89	$	1.06
Total LOE, taxes other than income and midstream costs ($/Mcfe)	$	1.12	$	1.44

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


	Three Months Ended September 30, 2023		Three Months Ended September 30, 2022		% Change
Natural gas	$	177,401	$	585,596	(70)	%
Oil and condensate	22,896		36,050		(36)	%
NGL	26,953		44,351		(39)	%
Natural gas, oil and condensate and NGL sales	$	227,250	$	665,997	(66)	%

The decrease in natural gas sales without the impact of derivatives when comparing the three months ended September 30, 2023, to the three months ended September 30, 2022, was due to a 75% decrease in realized prices, partially offset by a 19% increase in sales volumes. The realized price change was primarily driven by the decrease in the average Henry Hub gas index from $8.20 per Mcf in the three months ended September 30, 2022, to $2.55 per Mcf during the three months ended September 30, 2023.

The decrease in oil and condensate sales without the impact of derivatives when comparing the three months ended September 30, 2023, to the three months ended September 30, 2022, was due to a 13% decrease in realized prices and a 27% decrease in sales volumes. The realized price change was primarily driven by the decrease in the average WTI crude index from $91.55 per barrel in the three months ended September 30, 2022, to $82.26 per barrel during the three months ended September 30, 2023.

The decrease in NGL sales without the impact of derivatives when comparing the three months ended September 30, 2023, to the three months ended September 30, 2022, was due to a 33% decrease in realized prices and a 9% decrease in sales volumes. The realized price change was primarily driven by the decrease in the average Mont Belvieu NGL index from $42.10 per barrel in the three months ended September 30, 2022, to $28.27 per barrel during the three months ended September 30, 2023.

Natural Gas, Oil and NGL Derivatives (in thousands)


	Three Months Ended September 30, 2023		Three Months Ended September 30, 2022
Natural gas derivatives - fair value gains (losses)	$	4,534	$	(161,532)
Natural gas derivatives - settlement gains (losses)	48,522		(354,084)
Total gains (losses) on natural gas derivatives	53,056		(515,616)

Oil derivatives - fair value (losses) gains	(8,414)		33,545
Oil derivatives - settlement losses	(2,130)		(9,035)
Total (losses) gains on oil and condensate derivatives	(10,544)		24,510

NGL derivatives - fair value (losses) gains	(5,763)		19,043
NGL derivatives - settlement gains (losses)	2,668		(2,832)
Total (losses) gains on NGL derivatives	(3,095)		16,211

Total gains (losses) on natural gas, oil and NGL derivatives	$	39,417	$	(474,895)

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 change in the total gain (loss) for the three months ended September 30, 2023 compared to the three months ended September 30, 2022, was primarily the result of a decrease in futures pricing for oil, natural gas, and NGLs. 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 September 30, 2023		Three Months Ended September 30, 2022		% Change
Lease operating expenses
Utica	$	10,343	$	9,977	4	%
SCOOP	5,284		5,386		(2)	%

Total lease operating expenses	$	15,627	$	15,363	2	%

Lease operating expenses per Mcfe
Utica	$	0.14	$	0.18	(22)	%
SCOOP	0.23		0.20		15	%

Total lease operating expenses per Mcfe	$	0.16	$	0.18	(12)	%

The increase in our total LOE for the three months ended September 30, 2023 compared to the three months ended September 30, 2022, was primarily the result of a 16% increase in production offset by cost reductions. The decrease in per unit LOE is primarily the result of increased production and cost reductions.

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


	Three Months Ended September 30, 2023		Three Months Ended September 30, 2022		% Change
Production taxes	$	5,897	$	13,622	(57)	%
Property taxes	1,163		1,526		(24)	%
Other	156		1,381		(89)	%
Total taxes other than income	$	7,216	$	16,529	(56)	%
Total taxes other than income per Mcfe	$	0.07	$	0.20	(62)	%

The decrease in total and per unit taxes other than income for the three months ended September 30, 2023 compared to the three months ended September 30, 2022, was primarily related to a decrease in production taxes resulting from the decrease in our natural gas, oil and NGL revenues excluding the impact of hedges discussed above.

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


	Three Months Ended September 30, 2023		Three Months Ended September 30, 2022		% Change
Transportation, gathering, processing and compression	$	86,602	$	89,234	(3)	%
Transportation, gathering, processing and compression per Mcfe	$	0.89	$	1.06	(16)	%

Transportation, gathering, processing and compression for the three months ended September 30, 2023 compared to the three months ended September 30, 2022 decreased on a per unit basis primarily as a result of lower minimum volume commitments as a result of our 16% increase in production.

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


	Three Months Ended September 30, 2023		Three Months Ended September 30, 2022		% Change
Depreciation, depletion and amortization of oil and gas properties	$	79,166	$	64,099	24	%
Depreciation, depletion and amortization of other property and equipment	339		320		6	%
Total depreciation, depletion and amortization	$	79,505	$	64,419	23	%
Depreciation, depletion and amortization per Mcfe	$	0.82	$	0.77	7	%

The increase in total and per unit depreciation, depletion and amortization of our oil and gas properties for the three months ended September 30, 2023 compared to the three months ended September 30, 2022, was primarily the result of our drilling and development activities subsequent to the third quarter of 2022.

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


	Three Months Ended September 30, 2023		Three Months Ended September 30, 2022		% Change
General and administrative expenses, gross	$	18,983	$	17,015	12	%
Reimbursed from third parties	(3,431)		(3,339)		3	%
Capitalized general and administrative expenses	(5,658)		(4,924)		15	%
General and administrative expenses, net	$	9,894	$	8,752	13	%
General and administrative expenses, net per Mcfe	$	0.10	$	0.10	(2)	%

The increase in general and administrative expenses for the three months ended September 30, 2023 compared to the three months ended September 30, 2022, was primarily driven by increases in employee headcount and compensation.

Interest Expense (in thousands, except per unit)


	Three Months Ended September 30, 2023		Three Months Ended September 30, 2022		% Change
Interest on 2026 Senior Notes	$	11,000	$	11,053	—	%
Interest expense on Credit Facility	4,088		3,712		10	%
Amortization of loan costs	927		676		37	%
Capitalized interest	(1,115)		—		100	%
Other	19		20		(5)	%
Total interest expense	$	14,919	$	15,461	(4)	%
Interest expense per Mcfe	$	0.15	$	0.18	(16)	%

Interest expense on our Credit Facility increased 10% for the three months ended September 30, 2023 compared to the three months ended September 30, 2022, as a result of increased interest rates resulting from the current inflationary environment. Amortization of loan costs increased by 37% for the three months ended September 30, 2023 compared to the three months ended September 30, 2022, as a result of the Third Amendment to the Credit Facility which increased the elected commitments and borrowing base. See Note 3 of our consolidated financial statements for further details of our Credit Facility. The Company also capitalized $1.1 million in interest expense for the three months ended September 30, 2023 and did not capitalize interest expense for the three months ended September 30, 2022.

Income Taxes

We recorded an income tax benefit of $554.7 million for the three months ended September 30, 2023. The income tax benefit related to the partial release of the valuation allowance maintained against our net deferred tax asset position. We did not record any income tax expense for the three months ended September 30, 2022, as a result of maintaining a full valuation allowance against our net deferred tax asset. See Note 14 of our consolidated financial statements for further discussion of our income tax benefit.

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Comparison of the Nine Month Periods Ended September 30, 2023 and 2022

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 nine months ended September 30, 2023 as compared to the nine months ended September 30, 2022. Some totals below may not sum or recalculate due to rounding.


	Nine Months Ended September 30, 2023		Nine Months Ended September 30, 2022
Natural gas sales
Natural gas production volumes (MMcf)	260,439		236,367
Natural gas production volumes (MMcf) per day	954		866
Total sales	$	619,181	$	1,529,898
Average price without the impact of derivatives ($/Mcf)	$	2.38	$	6.47
Impact from settled derivatives ($/Mcf)	$	0.37	$	(3.19)
Average price, including settled derivatives ($/Mcf)	$	2.75	$	3.28

Oil and condensate sales
Oil and condensate production volumes (MBbl)	1,041		1,154
Oil and condensate production volumes (MBbl) per day	4		4
Total sales	$	76,212	$	111,298
Average price without the impact of derivatives ($/Bbl)	$	73.21	$	96.42
Impact from settled derivatives ($/Bbl)	$	(2.29)	$	(27.26)
Average price, including settled derivatives ($/Bbl)	$	70.92	$	69.16

NGL sales
NGL production volumes (MBbl)	3,382		3,147
NGL production volumes (MBbl) per day	12		12
Total sales	$	92,935	$	143,741
Average price without the impact of derivatives ($/Bbl)	$	27.48	$	45.68
Impact from settled derivatives ($/Bbl)	$	1.88	$	(4.38)
Average price, including settled derivatives ($/Bbl)	$	29.36	$	41.30

Natural gas, oil and condensate and NGL sales
Natural gas equivalents (MMcfe)	286,974		262,173
Natural gas equivalents (MMcfe) per day	1,051		960
Total sales	$	788,328	$	1,784,937
Average price without the impact of derivatives ($/Mcfe)	$	2.75	$	6.81
Impact from settled derivatives ($/Mcfe)	$	0.35	$	(3.05)
Average price, including settled derivatives ($/Mcfe)	$	3.10	$	3.76

Production Costs:
Average lease operating expenses ($/Mcfe)	$	0.18	$	0.18
Average taxes other than income ($/Mcfe)	$	0.09	$	0.17
Average transportation, gathering, processing and compression ($/Mcfe)	$	0.91	$	1.00
Total LOE, taxes other than income and midstream costs ($/Mcfe)	$	1.18	$	1.35

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


	Nine Months Ended September 30, 2023		Nine Months Ended September 30, 2022		% Change
Natural gas	$	619,181	$	1,529,898	(60)	%
Oil and condensate	76,212		111,298		(32)	%
NGL	92,935		143,741		(35)	%
Natural gas, oil and condensate and NGL sales	$	788,328	$	1,784,937	(56)	%

The decrease in natural gas sales without the impact of derivatives when comparing the nine months ended September 30, 2023, to the nine months ended September 30, 2022, was due to a 63% decrease in realized prices, partially offset by a 10% increase in sales volumes. The realized price change was primarily driven by the decrease in the average Henry Hub gas index from $6.77 per Mcf in the nine months ended September 30, 2022, to $2.69 per Mcf in the nine months ended September 30, 2023.

The decrease in oil and condensate sales without the impact of derivatives when comparing the nine months ended September 30, 2023, to the nine months ended September 30, 2022, was due to a 24% decrease in realized prices and a 10% decrease in sales volumes. The realized price change was driven by the decrease in the average WTI crude index from $98.09 per barrel in the nine months ended September 30, 2022, to $77.39 per barrel in the nine months ended September 30, 2023.

The decrease in NGL sales without the impact of derivatives when comparing the nine months ended September 30, 2023, to the nine months ended September 30, 2022, was due to a 40% decrease in realized prices, partially offset by a 7% increase in NGL sales volumes. The realized price change was driven by the decrease in the average Mont Belvieu NGL index from $49.27 per barrel in the nine months ended September 30, 2022, to $29.83 per barrel in the nine months ended September 30, 2023.

Natural Gas, Oil and NGL Derivatives (in thousands)


	Nine Months Ended September 30, 2023		Nine Months Ended September 30, 2022
Natural gas derivatives - fair value gains (losses)	$	416,473	$	(659,193)
Natural gas derivatives - settlement gains (losses)	97,794		(754,177)
Total gains (losses) on natural gas derivatives	514,267		(1,413,370)

Oil derivatives - fair value (losses) gains	(1,424)		8,076
Oil derivatives - settlement losses	(2,204)		(31,460)
Total losses on oil and condensate derivatives	(3,628)		(23,384)

NGL derivatives - fair value (losses) gains	(2,730)		14,216
NGL derivatives - settlement gains (losses)	6,357		(13,779)
Total gains on NGL derivatives	3,627		437

Total gains (losses) on natural gas, oil and NGL derivatives	$	514,266	$	(1,436,317)

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 nine months ended September 30, 2023 compared to the nine months ended September 30, 2022, was primarily the result of a significant decrease in futures pricing for oil, natural gas, and NGLs. 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)


	Nine Months Ended September 30, 2023		Nine Months Ended September 30, 2022		% Change
Lease operating expenses
Utica	$	33,354	$	32,794	2	%
SCOOP	18,290		14,452		27	%

Total lease operating expenses	$	51,644	$	47,246	9	%

Lease operating expenses per Mcfe
Utica	$	0.16	$	0.18	(11)	%
SCOOP	0.24		0.19		26	%

Total lease operating expenses per Mcfe	$	0.18	$	0.18	—	%

The increase in total LOE for the nine months ended September 30, 2023 compared to the nine months ended September 30, 2022, was primarily the result of a 9% increase in production. LOE per unit for the nine months ended September 30, 2023 was consistent with the nine months ended September 30, 2022.

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


	Nine Months Ended September 30, 2023		Nine Months Ended September 30, 2022		% Change
Production taxes	$	19,616	$	36,714	(47)	%
Property taxes	4,802		5,311		(10)	%
Other	1,431		3,654		(61)	%
Total taxes other than income	$	25,849	$	45,679	(43)	%
Total taxes other than income per Mcfe	$	0.09	$	0.17	(48)	%

The decrease in total and per unit taxes other than income for the nine months ended September 30, 2023 compared to the nine months ended September 30, 2022, was primarily related to a decrease in production taxes resulting from the decrease in our natural gas, oil and NGL revenues excluding the impact of hedges discussed above.

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


	Nine Months Ended September 30, 2023		Nine Months Ended September 30, 2022		% Change
Transportation, gathering, processing and compression	$	259,883	$	261,778	(1)	%
Transportation, gathering, processing and compression per Mcfe	$	0.91	$	1.00	(9)	%

Transportation, gathering, processing and compression for the nine months ended September 30, 2023 compared to the nine months ended September 30, 2022 decreased on a per unit basis primarily as a result of lower minimum volume commitments as a result of our 9% increase in production.

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


	Nine Months Ended September 30, 2023		Nine Months Ended September 30, 2022		% Change
Depreciation, depletion and amortization of oil and gas properties	$	237,874	$	188,324	26	%
Depreciation, depletion and amortization of other property and equipment	873		981		(11)	%
Total depreciation, depletion and amortization	$	238,747	$	189,305	26	%
Depreciation, depletion and amortization per Mcfe	$	0.83	$	0.72	15	%

The increase in total and per unit depreciation, depletion and amortization of our oil and gas properties for the nine months ended September 30, 2023 compared to the nine months ended September 30, 2022, was primarily the result of our drilling and development activities subsequent to the third quarter of 2022.

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


	Nine Months Ended September 30, 2023		Nine Months Ended September 30, 2022		% Change
General and administrative expenses, gross	$	53,814	$	48,630	11	%
Reimbursed from third parties	(10,390)		(9,874)		5	%
Capitalized general and administrative expenses	(16,186)		(14,628)		11	%
General and administrative expenses, net	$	27,238	$	24,128	13	%
General and administrative expenses, net per Mcfe	$	0.09	$	0.09	3	%

The increase in total general and administrative expenses for the nine months ended September 30, 2023 compared to the nine months ended September 30, 2022, was primarily driven by increases in employee headcount and compensation as well as legal expenses related to the continued administration of our Chapter 11 filing and settlement of firm transportation agreement as noted in Note 9 of our consolidated financial statements.

Restructuring Costs

During the first and second quarters of 2023, Gulfport recognized $4.8 million in personnel-related restructuring expenses associated with changes in the organizational structure and leadership team resulting from the appointment of Gulfport's new CEO in January 2023. Of these expenses, $1.3 million resulted from accelerated vesting of share-based grants, which are non-cash charges. There are no remaining employee termination liabilities for the impacted employees.

Interest Expense (in thousands, except per unit)


	Nine Months Ended September 30, 2023		Nine Months Ended September 30, 2022		% Change
Interest on 2026 Senior Notes	$	33,000	$	33,155	—	%
Interest expense on Credit Facility	9,921		8,476		17	%
Amortization of loan costs	2,323		2,009		16	%
Capitalized interest	(2,954)		—		100	%
Other	112		39		187	%
Total interest expense	$	42,402	$	43,679	(3)	%
Interest expense per Mcfe	$	0.15	$	0.17	(11)	%

Interest expense on our Credit Facility increased 17% for the nine months ended September 30, 2023 compared to the nine months ended September 30, 2022, as a result of increased interest rates resulting from the current inflationary environment. The Company also capitalized $3.0 million in interest expense for the nine months ended September 30, 2023 and did not capitalize interest expense for the nine months ended September 30, 2022.

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Other, net (in thousands)


	Nine Months Ended September 30, 2023		Nine Months Ended September 30, 2022		% Change
Other, net	$	(20,492)	$	(11,385)	80	%

Other, net in the Company's consolidated statements of operations for the nine months ended September 30, 2023, included $17.8 million related to the interim TC claim distribution and a $1 million administrative payment to Rover as part of the executed settlement. The distribution and settlement is more fully described in Note 9 of our consolidated financial statements. The timing and amount of any future distributions to Gulfport are not certain, and the total amount will be impacted by the liquidating trust's distributions and resolution of other remaining bankruptcy claims. Additionally, Other, net included a $5.0 million recoupment of previously placed collateral for certain firm transportation commitments during our Chapter 11 filing.

Other, net in the Company's consolidated statements of operations for the nine months ended September 30, 2022, included $11.5 million related to the initial TC claim distribution as discussed in Note 9 of our consolidated financial statements. Additionally, Other, net included a $5.1 million payment to settle certain gas imbalance positions and a $5.2 million receipt of funds from a litigation settlement.

Income Taxes

We recorded an income tax benefit of $554.7 million for the nine months ended September 30, 2023. The income tax benefit related to the partial release of the valuation allowance maintained against our net deferred tax asset position. We did not record any income tax expense for the nine months ended September 30, 2022, as a result of maintaining a full valuation allowance against our net deferred tax asset. See Note 14 of our consolidated financial statements for further discussion of our income tax benefit.

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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 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 nine months ended September 30, 2023, our primary sources of capital resources and liquidity have consisted of internally generated cash flows from operations, and our primary uses of cash have been for development of our oil and natural gas properties and share repurchases.

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

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 3 of our consolidated financial statements for further discussion of our debt obligations, including the principal and carrying amounts of our senior notes.

As of September 30, 2023, we had $8.3 million of cash and cash equivalents, $95.0 million of borrowings under our Credit Facility, $66.9 million of letters of credit outstanding, and $550 million of outstanding 2026 Senior Notes. Our total principal amount of funded debt as of September 30, 2023 was $645.0 million.

As of October 26, 2023 we had $8.8 million of cash and cash equivalents, $59.0 million in borrowings under our Credit Facility, $60.9 million of letters of credit outstanding, and $550 million of outstanding 2026 Senior Notes.

Debt. On May 2, 2022, the Company completed its semi-annual borrowing base redetermination and entered into the Amendment to Borrowing Base Redetermination Agreement and First Amendment to our Credit Agreement, which amended the Existing Credit Facility. The amendment, among other things, (a) increased the borrowing base under the Credit Facility from $850 million to $1.0 billion with elected commitments remaining at $700 million, (b) amended certain covenants related to hedging to ease certain requirements and limitations and (c) amended the covenants governing restricted payments to (i) increase the Net Leverage Ratio allowing unlimited restricted payments from 1.00 to 1.00 to 1.25 to 1.00 and (ii) permit additional restricted payments to redeem preferred equity until December 31, 2022 provided certain leverage, no event of default or borrowing base deficiency and availability tests are met and (d) provided for the transition from a LIBOR to a SOFR benchmark, with a 10 basis point credit spread adjustment for all tenors.

On October 27, 2023, 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.

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Additionally, on the Emergence Date, pursuant to the terms of the Plan, we issued our 2026 Senior Notes. The 2026 Senior Notes are guaranteed on a senior unsecured basis by each of the Company's subsidiaries that guarantee the Credit Facility.

See Note 3 of our consolidated financial statements for additional discussion of our outstanding debt.

Preferred Dividends. As discussed in Note 4 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.

During the three and nine months ended September 30, 2023, the Company paid $1.1 million and $3.7 million, respectively, of cash dividends to holders of our preferred stock compared to $1.3 million and $4.1 million in the three and nine months ended September 30, 2022, respectively.

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

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.

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 nine months ended September 30, 2023, the Company's incurred capital expenditures totaled $385.5 million, of which $319.2 million related to drilling and completion activities, $41.4 million related to maintenance leasehold and land investment and $24.9 million related to discretionary acreage acquisitions.

Our drilling and completion capital expenditures for 2023 are currently estimated to be in the range of $385 million to $395 million. Also, we currently expect to spend approximately $50 million to $60 million in 2023 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 2023 and 2024. We expect this capital program to result in approximately 1,045 to 1,055 MMcfe per day of production in 2023.

Additionally, we are pursuing accretive acreage opportunities that expand our resource depth and provide optionality to our near term development plans and intend to allocate approximately $40 million in discretionary acreage acquisitions.

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Sources and Uses of Cash

The following table presents the major changes in cash and cash equivalents for the nine months ended September 30, 2023 and 2022 (in thousands):


	Nine Months Ended September 30, 2023		Nine Months Ended September 30, 2022
Net cash provided by operating activities	$	567,680	$	551,082
Additions to oil and natural gas properties	(421,132)		(331,994)
Debt activity, net	(50,000)		15,000
Repurchases of common stock	(82,757)		(225,791)
Preferred stock dividends	(3,718)		(4,136)
Other	(9,007)		866
Net change in cash and cash equivalents	$	1,066	$	5,027
Cash and cash equivalents at end of period	$	8,325	$	8,287

Net cash provided by operating activities. Net cash flow provided by operating activities was $567.7 million for the nine months ended September 30, 2023, as compared to $551.1 million for the nine months ended September 30, 2022. The increase was primarily the result of a decrease in cash payments from settled derivative instruments due to decreased realized commodities pricing.

Additions to oil and natural gas properties. During the nine months ended September 30, 2023, we spud 13 gross (12.0 net) operated wells and commenced sales from 16 gross (15.0 net) operated wells in the Utica for a total incurred cost of approximately $282.0 million. During the nine months ended September 30, 2023, we spud and commenced sales from two gross (1.7 net) operated wells in the SCOOP for a total incurred cost of approximately $32.0 million.

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 nine months ended September 30, 2023 and 2022, were as follows (in thousands):


	Nine Months Ended September 30, 2023		Nine Months Ended September 30, 2022
Oil and Natural Gas Property Cash Expenditures:
Drilling and completion costs	$	339,170	$	291,926
Leasehold acquisitions	65,845		27,086
Other	16,117		12,982
Total oil and natural gas property expenditures	$	421,132	$	331,994

Debt activity, net. In the nine months ended September 30, 2023, the Company had $698.0 million and $748.0 million in borrowings and repayments, respectively, on its Credit Facility. As of October 26, 2023 the Company had $59.0 million in borrowings outstanding on its Credit Facility.

Repurchases of common stock. During the nine months ended September 30, 2023, the Company repurchased 976,769 shares for approximately $82.9 million under the Repurchase Program at a weighted average price of $84.88 per share. For the same period in 2022, the Company repurchased 2,607,059 shares for $227.6 million at a weighted average price of $87.29 per share. As of October 26, 2023, we repurchased 3.9 million shares for approximately $334.6 million under the Repurchase Program at a weighted average price of $86.14 per share.

Preferred stock dividends. During the nine months ended September 30, 2023, the Company paid $3.7 million of cash dividends to holders of our preferred stock compared to $4.1 million in the nine months ended September 30, 2022.

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Other. During the nine months ended September 30, 2023, the Company paid other expenses of $9.0 million, as compared to other expenses of $0.9 million paid during the nine months ended September 30, 2022. The increase was primarily related to a $6.8 million increase in debt issuance costs as a result of the Third Amendment to the Credit Facility which increased the commitment and redetermined its borrowing base, as discussed in Note 3 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, 2022.

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 September 30, 2023, our material off-balance sheet arrangements and transactions include $66.9 million in letters of credit outstanding against our Credit Facility and $37.5 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. Additionally, the Company entered into various contractual commitments to purchase inventory and other material to be used in future activities. The Company's commitment to purchase these materials spans 2023 and 2024, with approximately $19.8 million remaining in 2023 and $23.5 million for 2024. 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 September 30, 2023, there have been no significant changes in our critical accounting policies from those disclosed in our 2022 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 September 30, 2023, 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 September 30, 2023, we had a net asset derivative position of $64.4 million as compared to a net liability derivative position of $347.9 million as of December 31, 2022. Utilizing actual derivative contractual volumes, a 10% increase in underlying commodity prices would have increased our liability by approximately $112.8 million, while a 10% decrease in underlying commodity prices would have decreased our liability by approximately $109.5 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 September 30, 2023, we had $95.0 million outstanding borrowings under our Credit Facility which bore interest at a weighted average rate of 8.05% for the nine months ended September 30, 2023. As of September 30, 2023, 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 September 30, 2023, 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 September 30, 2023, 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, 2022.


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 September 30, 2023 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(2)	Approximate maximum dollar value of shares that may yet be purchased under the plans or programs(2)
July 1 - July 31	8,709	$	106.40	—	$	75,000,000
August 1 - August 31	44,323	$	111.94	40,605	$	70,463,000
September 1 - September 30	36,078	$	116.53	35,565	$	316,319,000
Total	89,110	$	113.26	76,170

_____________________

(1) We repurchased and canceled 8,709, 3,718 and 513 shares of our common stock at a weighted average price of $106.40, $113.99 and $118.39 to satisfy tax withholding requirements incurred upon the vesting of restricted stock unit awards during July, August and September 2023, respectively.

(2) In September 2023 our Board of Directors approved an increase to the authorized stock repurchase program from $400 million to $650 million. The stock repurchase program extends through December 31, 2024. At September 30, 2023, there was approximately $316.3 million that may yet be repurchased under the $650.0 million approved amount.


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 September 30, 2023, none of our officers 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".

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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

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.

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: November 1, 2023


GULFPORT ENERGY CORPORATION

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