gpor-20220930

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, 2022


☐			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. (Check one):

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 27, 2022, 19,272,080 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 Comprehensive Income (Loss)	7

	Consolidated Statements of Stockholders’ Equity (Deficit)	8

	Consolidated Statements of Cash Flows	10

	Notes to Consolidated Financial Statements	11

	1. Basis of Presentation	11

	2. Property and Equipment	13

	3. Debt	14

	4. Mezzanine Equity and Equity	16

	5. Stock-Based Compensation	17

	6. Earnings Per Share	20

	7. Commitments and Contingencies	21

	8. Derivative Instruments	23

	9. Fair Value Measurements	27

	10. Revenue from Contracts with Customers	28

	11. Leases	29

	12. Income Taxes	31

	13. Subsequent Events	32

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

	2022 Operation and Financial Highlights	34

	2022 Production and Drilling Activity	34

	Comparison of Quarter-to-Date	36



	Comparison of Year-to-Date	41

	Liquidity and Capital Resources	46

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	50

Item 4.	Controls and Procedures	51

PART II OTHER INFORMATION

Item 1.	Legal Proceedings	52

Item 1A.	Risk Factors	52

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	52

Item 3.	Defaults Upon Senior Securities	52

Item 4.	Mine Safety Disclosures	52

Item 5.	Other Information	52

Item 6.	Exhibits	53

Signatures		54

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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 8.000% Senior Notes due 2026.















2026 Senior Notes. 8.000% Senior Notes due 2026.

4(a)(2) Indenture. Certain eligible holders have 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.



Bankruptcy Code. Chapter 11 of Title 11 of the United States Code.




Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to crude oil or other liquid hydrocarbons.



Btu. British thermal unit, which represents the amount of energy needed to heat one pound of water by one degree Fahrenheit and can be used to describe the energy content of fuels.



Chapter 11 Cases. Voluntary petitions filed on November 13, 2020 by Gulfport Energy Corporation, Gator Marine, Inc., Gator Marine Ivanhoe, Inc., Grizzly Holdings, Inc., Gulfport Appalachia, LLC, Gulfport Midcon, LLC, Gulfport Midstream Holdings, LLC, Jaguar Resources LLC, Mule Sky LLC, Puma Resources, Inc. and Westhawk Minerals LLC.

CODI. Cancellation of indebtedness income.

Completion. The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas, oil and NGL.

Credit Facility. The Third Amended and Restated Credit Agreement with JPMorgan Chase Bank, N.A. as administrative agent and various lender parties, providing for a new money senior secured reserve-based revolving credit facility effective as of October 14, 2021.

Current Successor Quarter. Period from July 1, 2022 through September 30, 2022.

Current Successor YTD Period. Period from January 1, 2022 through September 30, 2022.



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. May 17, 2021.









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 revolving credit facility or certain other debt.

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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.

IRC. The Internal Revenue Code of 1986, as amended.

LIBOR. London Interbank Offered Rate.

LOE. Lease operating expenses.

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.


MMBtu. One million British thermal units.

MMcf. One million cubic feet of natural gas.

MMcfe. One million cubic feet of natural gas equivalent.

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.












NYMEX. New York Mercantile Exchange.




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



Prior Combined YTD Period. Period from January 1, 2021 through September 30, 2021.

Prior Predecessor YTD Period. Period from January 1, 2021 through May 17, 2021.

Prior Successor Period. Period from May 18, 2021 through September 30, 2021.

Prior Successor Quarter. Period from July 1, 2021 through September 30, 2021











Repurchase Program. A stock repurchase program to acquire up to $300 million of Gulfport's outstanding common stock. It is authorized to extend through June 30, 2023, 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.

Section 382. Internal Revenue Code Section 382.



SOFR. Secured Overnight Financing Rate.






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 novel coronavirus disease (COVID-19) pandemic and the war in Ukraine 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, 2021 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)


	Successor
	September 30, 2022		December 31, 2021
Assets	(Unaudited)
Current assets:
Cash and cash equivalents	$	8,287	$	3,260
Accounts receivable—oil, natural gas, and natural gas liquids sales	317,528		232,854
Accounts receivable—joint interest and other	35,480		20,383
Prepaid expenses and other current assets	9,273		12,359
Short-term derivative instruments	53,342		4,695
Total current assets	423,910		273,551
Property and equipment:
Oil and natural gas properties, full-cost method
Proved oil and natural gas properties	2,303,728		1,917,833
Unproved properties	184,075		211,007
Other property and equipment	6,153		5,329
Total property and equipment	2,493,956		2,134,169
Less: accumulated depletion, depreciation and amortization	(467,485)		(278,341)
Total property and equipment, net	2,026,471		1,855,828
Other assets:

Long-term derivative instruments	24,335		18,664
Operating lease assets	3,060		322
Other assets	21,570		19,867
Total other assets	48,965		38,853
Total assets	$	2,499,346	$	2,168,232




Liabilities, Mezzanine Equity and Stockholders’ Equity
Current liabilities:
Accounts payable and accrued liabilities	$	466,563	$	394,011

Short-term derivative instruments	817,384		240,735
Current portion of operating lease liabilities	831		182

Total current liabilities	1,284,778		634,928
Non-current liabilities:
Long-term derivative instruments	299,150		184,580
Asset retirement obligation	30,367		28,264
Non-current operating lease liabilities	2,229		140
Long-term debt	728,101		712,946
Total non-current liabilities	1,059,847		925,930

Total liabilities	$	2,344,625	$	1,560,858
Commitments and contingencies (Note 7)
Mezzanine Equity:
Preferred stock - $0.0001 par value, 110.0 thousand shares authorized, 52.3 thousand issued and outstanding at September 30, 2022, and 57.9 thousand issued and outstanding at December 31, 2021	52,345		57,896
Stockholders’ Equity:
Common stock - $0.0001 par value, 42.0 million shares authorized, 19.4 million issued and outstanding at September 30, 2022, and 20.6 million issued and outstanding at December 31, 2021	2		2
Additional paid-in capital	472,846		692,521
Common stock held in reserve, 62 thousand shares at September 30, 2022, and 938 thousand shares at December 31, 2021	(1,996)		(30,216)
Accumulated deficit	(366,696)		(112,829)
Treasury stock, at cost - 20.4 thousand shares at September 30, 2022, and no shares at December 31, 2021	(1,780)		—
Total stockholders’ equity	$	102,376	$	549,478
Total liabilities, mezzanine equity and stockholders’ equity	$	2,499,346	$	2,168,232

See accompanying notes to consolidated financial statements.

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GULFPORT ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands)

(Unaudited)


	Successor
	Three Months Ended September 30, 2022		Three Months Ended September 30, 2021
REVENUES:
Natural gas sales	$	585,596	$	301,516
Oil and condensate sales	36,050		33,279
Natural gas liquid sales	44,351		45,153
Net loss on natural gas, oil and NGL derivatives	(474,895)		(622,476)
Total revenues	191,102		(242,528)
OPERATING EXPENSES:
Lease operating expenses	15,363		13,864
Taxes other than income	16,529		11,844
Transportation, gathering, processing and compression	89,234		84,435
Depreciation, depletion and amortization	64,419		62,573


General and administrative expenses	8,752		16,691
Restructuring and liability management expenses	—		2,858
Accretion expense	673		488

Total operating expenses	194,970		192,753
LOSS FROM OPERATIONS	(3,868)		(435,281)
OTHER EXPENSE (INCOME):
Interest expense	15,461		16,351





Other, net	(857)		9,031
Total other expense	14,604		25,382
LOSS BEFORE INCOME TAXES	(18,472)		(460,663)
Income tax expense	—		650
NET LOSS	$	(18,472)	$	(461,313)
Dividends on preferred stock	$	(1,309)	$	(2,095)

NET LOSS ATTRIBUTABLE TO COMMON STOCKHOLDERS	$	(19,781)	$	(463,408)

NET LOSS PER COMMON SHARE:
Basic	$	(1.01)	$	(22.50)
Diluted	$	(1.01)	$	(22.50)
Weighted average common shares outstanding—Basic	19,635		20,598
Weighted average common shares outstanding—Diluted	19,635		20,598

See accompanying notes to consolidated financial statements.

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GULFPORT ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands)

(Unaudited)


	Successor				Predecessor
	Nine Months Ended September 30, 2022		Period from May 18, 2021 through September 30, 2021		Period from January 1, 2021 through May 17, 2021
REVENUES:
Natural gas sales	$	1,529,898	$	413,234	$	344,390
Oil and condensate sales	111,298		50,866		29,106
Natural gas liquid sales	143,741		61,230		36,780
Net loss on natural gas, oil and NGL derivatives	(1,436,317)		(762,134)		(137,239)
Total revenues	348,620		(236,804)		273,037
OPERATING EXPENSES:
Lease operating expenses	47,246		17,980		19,524
Taxes other than income	45,679		16,900		12,349
Transportation, gathering, processing and compression	261,778		125,811		161,086
Depreciation, depletion and amortization	189,305		94,935		62,764
Impairment of oil and natural gas properties	—		117,813		—
Impairment of other property and equipment	—		—		14,568
General and administrative expenses	24,128		23,209		19,175
Restructuring and liability management expenses	—		2,858		—
Accretion expense	2,057		714		1,229

Total operating expenses	570,193		400,220		290,695
LOSS FROM OPERATIONS	(221,573)		(637,024)		(17,658)
OTHER EXPENSE (INCOME):
Interest expense	43,679		25,245		4,159



Loss from equity method investments, net	—		—		342
Reorganization items, net	—		—		(266,898)
Other, net	(11,385)		7,980		1,713
Total other expense (income)	32,294		33,225		(260,684)
(LOSS) INCOME BEFORE INCOME TAXES	(253,867)		(670,249)		243,026
Income tax expense (benefit)	—		650		(7,968)
NET (LOSS) INCOME	$	(253,867)	$	(670,899)	$	250,994
Dividends on preferred stock	$	(4,136)	$	(3,126)	$	—

NET (LOSS) INCOME ATTRIBUTABLE TO COMMON STOCKHOLDERS	$	(258,003)	$	(674,025)	$	250,994

NET (LOSS) INCOME PER COMMON SHARE:
Basic	$	(12.58)	$	(32.87)	$	1.56
Diluted	$	(12.58)	$	(32.87)	$	1.56
Weighted average common shares outstanding—Basic	20,514		20,507		160,834
Weighted average common shares outstanding—Diluted	20,514		20,507		160,834

See accompanying notes to consolidated financial statements.

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GULFPORT ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(In thousands)

(Unaudited)


	Successor
	Three Months Ended September 30, 2022		Three Months Ended September 30, 2021
Net loss	$	(18,472)	$	(461,313)


Other comprehensive income	—		—
Comprehensive loss	$	(18,472)	$	(461,313)


	Successor				Predecessor
	Nine Months Ended September 30, 2022		Period from May 18, 2021 through September 30, 2021		Period from January 1, 2021 through May 17, 2021
Net (loss) income	$	(253,867)	$	(670,899)	$	250,994
Foreign currency translation adjustment	—		—		2,570

Other comprehensive income	—		—		2,570
Comprehensive (loss) income	$	(253,867)	$	(670,899)	$	253,564

See accompanying notes to consolidated financial statements.

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GULFPORT ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (DEFICIT)

(In thousands)

(Unaudited)


				Common Stock Held in Reserve			Treasury Stock		Paid-in Capital		Accumulated Other Comprehensive (Loss) Income		Retained Earnings (Accumulated Deficit)		Total Stockholders’ Equity (Deficit)
	Common Stock
	Shares	Amount		Shares	Amount
Balance at January 1, 2021 (Predecessor)	160,762	$	1,607	—	$	—	$	—	$	4,213,752	$	(43,000)	$	(4,472,859)	$	(300,500)
Net income	—	—		—	—		—		—		—		8,780		8,780
Other comprehensive income	—	—		—	—		—		—		2,570		—		2,570
Stock compensation	—	—		—	—		—		1,419		—		—		1,419
Shares repurchased	(86)	(1)		—	—		—		(7)		—		—		(8)
Issuance of restricted stock	203	3		—	—		—		(2)		—		—		1
Balance at March 31, 2021 (Predecessor)	160,879	$	1,609	—	$	—	$	—	$	4,215,162	$	(40,430)	$	(4,464,079)	$	(287,738)
Net income	—	—		—	—		—		—		—		242,214		242,214
Issuance of restricted stock	25	—		—	—		—		—		—		—		—
Shares repurchased	(10)	—		—	—		—		—		—		—		—
Stock compensation	—	—		—	—		—		5,095		—		—		5,095
Accumulated other comprehensive income extinguishment	—	—		—	—		—		—		40,430		—		40,430
Cancellation of predecessor equity	(160,894)	(1,609)		—	—		—		(4,220,256)		—		4,221,865		—
Issuance of common stock	21,525	2		—	—		—		693,773		—		—		693,775
Shares of common stock held in reserve	—	—		(1,679)	(54,109)		—		—		—		—		(54,109)
Balance at May 17, 2021 (Predecessor)	21,525	$	2	(1,679)	$	(54,109)	$	—	$	693,774	$	—	$	—	$	639,667


Balance at May 18, 2021 (Successor)	21,525	$	2	(1,679)	$	(54,109)	$	—	$	693,774	$	—	$	—	$	639,667
Net loss	—	—		—	—		—		—		—		(209,586)		(209,586)
Release of common stock held in reserve	—	—		741	23,893		—		—		—		—		23,893
Conversion of preferred stock	10	—		—	—		—		147		—		—		147
Dividends on preferred stock	—	—		—	—		—		(1,031)		—		—		(1,031)
Balance at June 30, 2021 (Successor)	21,535	$	2	(938)	$	(30,216)	$	—	$	692,890	$	—	$	(209,586)	$	453,090
Net loss	—	—		—	—		—		—		—		(461,313)		(461,313)
Stock Compensation	—	—		—	—		—		1,387		—		—		1,387
Dividends on preferred stock	—	—		—	—		—		(2,095)		—		—		(2,095)
Balance at September 30, 2021 (Successor)	21,535	$	2	(938)	$	(30,216)	$	—	$	692,182	$	—	$	(670,899)	$	(8,931)

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GULFPORT ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (DEFICIT) CONTINUED

(In thousands)

(Unaudited)


				Common Stock Held in Reserve			Treasury Stock		Paid-in Capital		Accumulated Other Comprehensive (Loss) Income		Retained Earnings (Accumulated Deficit)		Total Stockholders’ Equity (Deficit)
	Common Stock
	Shares	Amount		Shares	Amount
Balance at January 1, 2022 (Successor)	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 (Successor)	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 (Successor)	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 (Successor)	19,402	$	2	(62)	$	(1,996)	$	(1,780)	$	472,846	$	—	$	(366,696)	$	102,376

See accompanying notes to consolidated financial statements.

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GULFPORT ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)


	Successor				Predecessor
	Nine Months Ended September 30, 2022		Period from May 18, 2021 through September 30, 2021		Period from January 1, 2021 through May 17, 2021
Cash flows from operating activities:
Net (loss) income	$	(253,867)	$	(670,899)	$	250,994
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depletion, depreciation and amortization	189,305		94,935		62,764
Impairment of oil and natural gas properties	—		117,813		—
Impairment of other property and equipment	—		—		14,568
Loss from equity investments	—		—		342

Net loss on derivative instruments	1,436,317		762,134		137,239
Net cash payments on settled derivative instruments	(799,416)		(99,574)		(3,361)
Non-cash reorganization items, net	—		—		(446,012)

Other, net	8,303		1,488		1,727
Changes in operating assets and liabilities, net	(29,560)		(41,260)		153,894
Net cash provided by operating activities	551,082		164,637		172,155
Cash flows from investing activities:
Additions to oil and natural gas properties	(331,994)		(119,306)		(102,330)
Proceeds from sale of oil and natural gas properties	3,210		600		15
Other, net	(536)		2,562		4,484
Net cash used in investing activities	(329,320)		(116,144)		(97,831)
Cash flows from financing activities:
Principal payments on pre-petition revolving credit facility	—		—		(318,961)
Borrowings on pre-petition revolving credit facility	—		—		26,050
Principal payments on Credit Facility	(1,512,000)		—		—
Borrowings on Credit Facility	1,527,000		—		—
Borrowings on exit credit facility	—		306,855		302,751
Principal payments on exit credit facility	—		(409,000)		—
Principal payments on DIP credit facility	—		—		(157,500)
Debt issuance costs and loan commitment fees	(211)		(1,225)		(7,100)
Dividends on preferred stock	(4,136)		—		—
Proceeds from issuance of preferred stock	—		—		50,000
Repurchase of common stock under Repurchase Program	(225,791)		—		—
Other, net	(1,597)		(55)		(8)
Net cash used in financing activities	(216,735)		(103,425)		(104,768)
Net increase (decrease) in cash, cash equivalents and restricted cash	5,027		(54,932)		(30,444)
Cash, cash equivalents and restricted cash at beginning of period	3,260		59,417		89,861
Cash, cash equivalents and restricted cash at end of period	$	8,287	$	4,485	$	59,417

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 in central Oklahoma targeting the SCOOP Woodford and SCOOP Springer formations. 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. The Company refers to the post-emergence reorganized organization in the condensed financial statements and footnotes as the "Successor" for periods subsequent to May 17, 2021, and the pre-emergence organization as "Predecessor" for periods on or prior to May 17, 2021.

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 months ended September 30, 2022 ("Current Successor Quarter"), as of and for the nine months ended September 30, 2022 ("Current Successor YTD Period"), May 18, 2021 through September 30, 2021 (“Prior Successor Period”), the three months ended September 30, 2021 ("Prior Successor Quarter"), and January 1, 2021 through May 17, 2021 (“Prior Predecessor YTD Period”). The Company's annual report on Form 10-K for the year ended December 31, 2021 (“2021 Form 10-K”) 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.

Voluntary Reorganization Under Chapter 11 of the Bankruptcy Code

In connection with the Company's emergence from bankruptcy and in accordance with ASC 852, the Company qualified for and applied fresh start accounting on the Emergence Date. For further information on the Company’s reorganization value and the resulting fresh start adjustments made on the Emergence Date, refer to the “Fresh Start Accounting” footnote in the notes to the consolidated financial statements in Item 8 of the Company’s 2021 Form 10-K.

Accounts Payable and Accrued Liabilities

Accounts payable and accrued liabilities consisted of the following at September 30, 2022 and December 31, 2021 (in thousands):


	Successor
	September 30, 2022		December 31, 2021
Accounts payable and other accrued liabilities	$	202,838	$	143,938
Revenue payable and suspense	222,729		180,857
Accrued contract rejection damages and shares held in reserve	40,996		69,216
Total accounts payable and accrued liabilities	$	466,563	$	394,011

Reorganization Items, Net

In the Prior Predecessor YTD Period, the Company incurred significant expenses related to its Chapter 11 filing. The amount of these items, which were incurred in reorganization items, net within the Company's accompanying consolidated

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statements of operations, significantly affected the Company's statements of operations. The Company also incurred adjustments for allowable claims related to its legal proceedings and executory contracts approved for rejection by the Bankruptcy Court.

The following table summarizes the components in reorganization items, net included in the Company's consolidated statements of operations for the Current Successor YTD Period, Prior Successor Period, and Prior Predecessor YTD Period (in thousands):


	Successor				Predecessor
	Nine Months Ended September 30, 2022		Period from May 18, 2021 through September 30, 2021		Period from January 1, 2021 through May 17, 2021
Legal and professional advisory fees	$	—	$	—	$	81,565
Net gain on liabilities subject to compromise	—		—		(575,182)
Fresh start adjustments, net	—		—		160,756
Elimination of predecessor accumulated other comprehensive income	—		—		40,430
Debt issuance costs	—		—		3,150
Other items, net	—		—		22,383
Reorganization items, net	$	—	$	—	$	(266,898)

Other, net

Other, net included in the Company's consolidated statements of operations for the Current Successor YTD period included $11.5 million related to the TC claim distribution received in February 2022 as discussed in Note 7.

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


	Successor				Predecessor
	Nine Months Ended September 30, 2022		Period from May 18, 2021 through September 30, 2021		Period from January 1, 2021 through May 17, 2021
Supplemental disclosure of cash flow information:
Cash paid for reorganization items, net	$	—	$	42,202	$	87,199
Interest payments	$	30,102	$	6,465	$	7,272
Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable - oil, natural gas, and natural gas liquids sales	$	(84,674)	$	(5,230)	$	(60,832)
(Increase) decrease in accounts receivable - joint interest and other	$	(14,947)	$	5,536	$	(3,005)
Increase (decrease) in accounts payable and accrued liabilities	$	65,648	$	(48,903)	$	79,193
Decrease in prepaid expenses	$	3,061	$	7,231	$	135,471
Decrease in other assets	$	1,352	$	106	$	3,067
Total changes in operating assets and liabilities	$	(29,560)	$	(41,260)	$	153,894
Supplemental disclosure of non-cash transactions:
Capitalized stock-based compensation	$	2,141	$	484	$	930
Asset retirement obligation capitalized	$	53	$	55	$	546
Asset retirement obligation removed due to divestiture	$	(7)	$	—	$	—
Interest capitalized	$	—	$	117	$	—

Release of common stock held in reserve	$	28,220	$	23,893	$	—
Foreign currency translation gain on equity method investments	$	—	$	—	$	2,570

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2.PROPERTY AND EQUIPMENT

The major categories of property and equipment and related accumulated DD&A and impairment as of September 30, 2022 and December 31, 2021 are as follows (in thousands):


	Successor
	September 30, 2022		December 31, 2021
Proved oil and natural gas properties	$	2,303,728	$	1,917,833
Unproved properties	184,075		211,007
Other depreciable property and equipment	5,767		4,943
Land	386		386
Total property and equipment	2,493,956		2,134,169
Accumulated DD&A and impairment	(467,485)		(278,341)
Property and equipment, net	$	2,026,471	$	1,855,828

Under the full cost method of accounting, the Company is required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the Company's oil and natural gas properties. At September 30, 2022, the net book value of the Company's oil and gas properties was below the calculated ceiling for the period leading up to September 30, 2022. As a result, the Company did not record an impairment of its oil and natural gas properties for the Current Successor Quarter. The Company recorded impairment of its oil and natural gas properties of $117.8 million for the Prior Successor Period. Upon the application of fresh start accounting, the value of the Company's oil and natural gas properties were determined using forward strip oil and natural gas prices as of the Emergence Date. These prices were higher than the 12-month weighted average prices used in the full cost ceiling limitation at June 30, 2021, which led to the Prior Successor Period impairment charge.

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 $4.9 million and $5.1 million for the Current Successor Quarter and Prior Successor Quarter, respectively. Capitalized general and administrative costs were approximately $14.6 million, $7.3 million, and $8.0 million for the Current Successor YTD Period, Prior Successor Period, and Prior Predecessor YTD Period, respectively.

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

The following table summarizes the Company’s non-producing properties excluded from amortization by area as of September 30, 2022:


	Successor
	September 30, 2022
	(In thousands)
Utica	$	151,856
SCOOP	32,219

Total unproved properties	$	184,075

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Asset Retirement Obligation

The following table provides a reconciliation of the Company’s asset retirement obligation for the Current Successor YTD Period (in thousands):


Asset retirement obligation at January 1, 2022 (Successor)	$	28,264
Liabilities incurred	53

Liabilities removed due to divestitures	(7)
Accretion expense	2,057

Asset retirement obligation at September 30, 2022	$	30,367

The following table provides a reconciliation of the Company’s asset retirement obligation for the Prior Predecessor YTD Period and Prior Successor Period (in thousands):


Asset retirement obligation at January 1, 2021 (Predecessor)	$	63,566
Liabilities incurred	546
Accretion expense	1,229
Ending balance as of May 17, 2021 (Predecessor)	65,341
Fresh start adjustments(1)	(46,257)


Asset retirement obligation at May 18, 2021 (Successor)	19,084
Liabilities incurred	56
Accretion expense	714
Asset retirement obligation at September 30, 2021	$	19,854

_____________________

(1) The Company recorded its asset retirement obligation at fair value as of the Emergence Date.

3.DEBT

Debt consisted of the following items as of September 30, 2022 and December 31, 2021 (in thousands):


	Successor
	September 30, 2022		December 31, 2021
Credit Facility	$	179,000	$	164,000
8.000% senior unsecured notes due 2026	550,000		550,000
Net unamortized debt issuance costs	(899)		(1,054)
Total debt, net	728,101		712,946
Less: current maturities of long-term debt	—		—
Total long-term debt, net	$	728,101	$	712,946

Credit Facility

On October 14, 2021, the Company entered into the Third Amended and Restated Credit Agreement with JPMorgan Chase Bank, N.A., as administrative agent, and various lender parties ("Credit Facility"). The Credit Facility provided for an aggregate maximum principal amount of up to $1.5 billion, an initial borrowing base of $850.0 million and an initial aggregate elected commitment amount of $700.0 million. The credit agreement also provides for a $175.0 million sublimit of the aggregate commitments that is available for the issuance of letters of credit. The Credit Facility matures October 14, 2025.

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On May 2, 2022, the Company completed its semi-annual borrowing base redetermination and entered into the first amendment to its credit agreement (“Amendment”). The Amendment, among other things, (a) increased the borrowing base under the Credit Agreement 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 are met, and (d) provide for the transition from a LIBOR to a SOFR benchmark, with a 10 basis point credit spread adjustment for all tenors.

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 borrowing base will be redetermined semiannually on or around May 1 and November 1 of each year. On October 31, 2022, the Company completed its semi-annual borrowing base redetermination as discussed in Note 13.

The credit agreement 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 agreement 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, 2022, the Company had $179.0 million outstanding borrowings under the Credit Facility, $113.2 million in letters of credit outstanding and was in compliance with all covenants under the Credit Facility.

As of September 30, 2022, the Credit Facility bore interest at a weighted average rate of 6.23%.

2026 Senior Notes

On the Emergence Date, pursuant to the terms of the Plan, the Company issued $550 million aggregate principal amount of its 8.000% 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.

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Fair Value of Debt

At September 30, 2022, the carrying value of the outstanding debt represented by the 2026 Senior Notes was $549.1 million. Based on the quoted market prices (Level 1), the fair value of the 2026 Senior Notes was determined to be $546.3 million at September 30, 2022.

4.MEZZANINE EQUITY AND 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 ("Liquidation Preference").

Mezzanine Equity

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 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 “Conversion Price”). The shares of preferred stock outstanding at September 30, 2022 would convert to approximately 3.7 million shares of common stock if all holders of preferred stock exercised their Conversion Right.

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.

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Dividends and Conversions

During the Current Successor YTD Period, the company paid $4.1 million of cash dividends to holders of our preferred stock.

The following table summarizes activity of the Company’s preferred stock for the Current Successor YTD Period:


Preferred stock at December 31, 2021						57,896

Conversion of preferred stock						(5,551)
Preferred stock at September 30, 2022						52,345

Equity

Common Stock

On the Emergence Date, all existing shares of the Predecessor's common stock were cancelled. The Successor 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, 2022, approximately 62,000 shares continue to be held in the Disputed Claims reserve and may be issued upon finalization of remaining claims.

Share Repurchase Program

In November 2021 the Company's Board of Directors approved a stock repurchase program to acquire up to $100 million of its common stock and increased the authorization from $100 million to $200 million in April 2022 and from $200 million to $300 million in July 2022 ("Repurchase Program"). 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 is authorized to extend through June 30, 2023, and 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 Current Successor Quarter and Current Successor YTD Period (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 2022	438	$	35,512	$	81.06
Second quarter 2022	1,416	127,510		90.06
Third quarter 2022	753	64,549		85.72
Total	2,607	$	227,571	$	87.29

5.STOCK-BASED COMPENSATION

On the Emergence Date, the Company's Predecessor common stock was cancelled and the Company's Successor common stock was issued. Accordingly, the Company's then existing stock-based compensation awards were also cancelled. Stock-based compensation for the Predecessor and Successor periods are not comparable.

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Successor Stock-Based Compensation

As of the Emergence Date, the board of directors adopted the Incentive Plan with a share reserve equal to 2.8 million shares of common stock. The Incentive Plan provides for the grant of incentive stock options, nonstatutory stock options, restricted stock, restricted stock units, stock appreciation rights, dividend equivalents and performance awards or any combination of the foregoing. The Company has granted both restricted stock units and performance vesting restricted stock units to employees and directors pursuant to the Incentive Plan, as discussed below. During the Current Successor Quarter and the Current Successor YTD Period, 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. During the Prior Successor Quarter and the Prior Successor Period, the Company's stock-based compensation expense was $1.4 million, of which the Company capitalized $0.5 million 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, 2022, the Company has awarded an aggregate of approximately 268,000 restricted stock units and approximately 191,000 performance vesting restricted stock units, net of forfeited awards, under the Incentive Plan.

The following table summarizes restricted stock unit activity for the Current Successor YTD Period:


	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

Successor Restricted Stock Units

Restricted stock units awarded under the Incentive Plan generally vest ratably over a period of 3 or 4 years in the case of employees and 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, 2022 was $14.1 million. The expense is expected to be recognized over a weighted average period of 2.38 years.

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Successor 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 over 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 Current Successor YTD Period:


Grant date			April 29, 2022
Forecast period (years)			3
Risk-free interest rates			2.9%
Implied equity volatility			88.4%
Stock price on the date of grant			$93.98

Unrecognized compensation expense as of September 30, 2022, related to performance vesting restricted shares was $6.5 million. The expense is expected to be recognized over a weighted average period of 1.95 years.

Predecessor Stock-Based Compensation

The Predecessor granted restricted stock units to employees and directors pursuant to the 2019 Amended and Restated Incentive Stock Plan (the "2019 Plan"). During the Prior Predecessor YTD Period, the Company’s stock-based compensation cost was $4.4 million, of which the Company capitalized $0.9 million, relating to its exploration and development efforts. Stock compensation costs, net of the amounts capitalized, are included in general and administrative expenses in the accompanying consolidated statements of operations.

The following table summarizes restricted stock unit activity for the Prior Predecessor YTD Period:


	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, 2021	1,702,513	$	4.74	840,595	$	4.07
Granted	—	—		—	—
Vested	(227,132)	8.45		—	—
Forfeited/canceled	(1,475,381)	4.16		(840,595)	4.07
Unvested shares as of May 17, 2021	—	$	—	—	$	—

Predecessor Restricted Stock Units

Restricted stock units awarded under the 2019 Plan generally vested over a period of one year in the case of directors and three years in the case of employees and vesting was dependent upon the recipient meeting applicable service requirements. Stock-based compensation costs are recorded ratably over the service period. The grant date fair value of restricted stock units represents the closing market price of the Company's common stock on the date of grant. All unrecognized compensation expense was recognized as of the Emergence Date.

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Predecessor Performance Vesting Restricted Stock Units

The Company previously awarded performance vesting restricted stock units to certain of its executive officers under the 2019 Plan. The number of shares of common stock issued pursuant to the award was based on RTSR. RTSR is an incentive measure whereby participants will earn from 0% to 200% of the target award based on the Company’s TSR ranking compared to the TSR of the companies in the Company’s designated peer group at the end of the performance period. Awards were to be earned and vested over a performance period measured from January 1, 2019 to December 31, 2021, subject to earlier termination of the performance period in the event of a change in control. All unrecognized compensation expense was recognized as of the Emergence Date.

6.EARNINGS PER SHARE

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

There were no potential shares of common stock that were considered dilutive for the Current Successor Quarter, Current Successor YTD Period, Prior Successor Period, Prior Successor Quarter, or Prior Predecessor YTD Period. There were 3.7 million shares of potential common shares issuable due to the Company's convertible preferred stock for each of the Current Successor Quarter and Current Successor YTD Period. There were 1.2 million and 1.5 million shares of restricted stock that were considered anti-dilutive during the Current Successor Quarter and Current Successor YTD Period, respectively.

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


	Successor
	Three Months Ended September 30, 2022		Three Months Ended September 30, 2021
Net loss	$	(18,472)	$	(461,313)
Dividends on preferred stock	(1,309)		(2,095)

Net loss attributable to common stockholders	$	(19,781)	$	(463,408)


Basic Shares	19,635		20,598

Basic and Dilutive EPS	$	(1.01)	$	(22.50)


	Successor				Predecessor
	Nine Months Ended September 30, 2022		Period from May 18, 2021 through September 30, 2021		Period from January 1, 2021 through May 17, 2021
Net (loss) income	$	(253,867)	$	(670,899)	$	250,994
Dividends on preferred stock	(4,136)		(3,126)		—

Net (loss) income attributable to common stockholders	$	(258,003)	$	(674,025)	$	250,994
Basic Shares	20,514		20,507		160,834
Basic and Dilutive EPS	$	(12.58)	$	(32.87)	$	1.56

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7.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, 2022 are set forth in the table below, excluding contracts in the process of being rejected as discussed in the Litigation and Regulatory Proceedings section below (in thousands):


Remaining 2022	$	58,483
2023	229,733
2024	220,708
2025	139,706
2026	136,235
Thereafter	889,674
Total	$	1,674,539

Contingencies

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

Litigation and Regulatory Proceedings

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") (jointly, the “Pending Motions to Reject”). 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 Gulfport and TC would be rejected without any further payment or obligation by Gulfport or TC, 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 to TC 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. The timing and amount of any future distributions are not certain, and the total amount received will be impacted by the bankruptcy trustee's distributions and other bankruptcy claims.

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The Pending Motions to Reject were removed to the United States District Court for the Southern District of Texas (the “District Court”) by TC and Rover prior to the TC settlement. On July 13, 2022, the District Court referred the Pending Motion to Reject with respect to Rover back to the Bankruptcy Court. The Company believes that the Pending Motion to Reject with respect to Rover will be ultimately granted, and that the Company does not have any ongoing obligation pursuant to the contract; however, if the Company is not permitted to reject the Rover firm transportation contract, it could be required to post additional credit assurance and be liable for demand charges, attorneys' fees and interest.

The Company has been named as a defendant in three separate complaints, two filed by Siltstone Resources, LLC, and the third filed by the Ohio Public Works Commission (OPWC) (together, the "Complaints"). The Complaints all arise from restrictive covenants in favor of OPWC generally prohibiting any transfer and any use inconsistent with a green park space. OPWC filed crossclaims against Gulfport in the Siltstone matters alleging that the transfer of the mineral rights and the development of oil and gas on the property violated these restrictive covenants. On June 19, 2018, October 25, 2019, and March 15, 2019, each trial court in the Complaints entered judgment in favor of the Company and other defendants, finding the restrictive covenants only applied to the surface estate. OPWC appealed each judgement to the respective Ohio Courts of Appeal where the trial court decisions were reversed in favor of OPWC. The Company and certain other parties to the Complaints appealed the appellate court decisions to the Ohio Supreme Court. On February 23, 2022, the Ohio Supreme Court affirmed the first appellate decision and remanded the case back to the trial court. The other two complaints are still pending before the Ohio Supreme Court. OPWC is seeking both injunctive relief to enforce the restrictive covenants and equitable relief. Liquidated damages were successfully discharged in the Company’s Chapter 11 proceedings through May 17, 2021. The scope and consequence of any injunctive relief that may be granted is not certain, but may have an adverse impact on the Company's operations associated with the leases subject to the Complaints.

In March 2020, Robert F. Woodley, individually and on behalf of all others similarly situated, filed a federal securities class action against the Company, David M. Wood, Keri Crowell and Quentin R. Hicks in the United States District Court for the Southern District of New York. The complaint alleges that the Company made materially false and misleading statements regarding the Company’s business and operations in violation of the federal securities laws and seeks unspecified damages, the payment of reasonable attorneys’ fees, expert fees and other costs, pre-judgment and post-judgment interest, and such other and further relief that may be deemed just and proper. On January 11, 2022, the court granted Gulfport's motion to dismiss and the case was closed by the court on February 14, 2022. The plaintiffs appealed the district court ruling, and the appellate court affirmed the lower court's motion to dismiss on October 27, 2022.

The Company, along with other oil and gas companies, have been named as a defendant in J&R Passmore, LLC, individually and on behalf of all others similarly situated, in the United States District Court for the Southern District of Ohio on December 6, 2018. 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.

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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 their environmental risk profile. Environmental reserves are established for environmental liabilities for which economic losses are probable and reasonably estimable. The Company manages its exposure to environmental liabilities in acquisitions by using an evaluation process that seeks to identify pre-existing contamination or compliance concerns and address the potential liability. Depending on the extent of an identified environmental concern, they may, among other things, exclude a property from the transaction, require the seller to remediate the property to their satisfaction in an acquisition or agree to assume liability for the remediation of the property.

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.

8.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, collars and various types of option contracts. These contracts allow the Company to mitigate the impact of declines in future natural gas, oil and NGL prices by effectively locking in a floor price for a certain level of the Company’s production. However, these hedge contracts also limit the benefit to the Company in periods of favorable price movements.

The volume of production subject to commodity derivative instruments and the mix of the instruments are frequently evaluated and adjusted by management in response to changing market conditions. Gulfport may enter into commodity derivative contracts up to limitations set forth in its Credit Facility. The Company generally enters into commodity derivative contracts for approximately 50% to 75% of its forecasted 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 24 months. Gulfport does not enter into commodity derivative contracts for speculative purposes.

Fixed price swaps are settled monthly based on differences between the fixed price specified in the contract and the referenced settlement price. When the referenced settlement price is less than the price specified in the contract, the Company receives an amount from the counterparty based on the price difference multiplied by the volume. Similarly, when the referenced settlement price exceeds the price specified in the contract, the Company pays the counterparty an amount based on the price difference multiplied by the volume. The prices contained in these fixed price swaps are based on the NYMEX Henry Hub for natural gas, the NYMEX WTI for oil and Mont Belvieu for propane.

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.

Below is a summary of the Company’s open fixed price swap positions as of September 30, 2022.


	Index	Daily Volume	Weighted Average Price
Natural Gas		(MMBtu/d)	($/MMBtu)
Remaining 2022	NYMEX Henry Hub	270,000	$	2.96
2023	NYMEX Henry Hub	165,014	$	3.64
2024	NYMEX Henry Hub	54,973	$	3.98

Oil		(Bbl/d)	($/Bbl)
Remaining 2022	NYMEX WTI	3,000	$	66.03
2023	NYMEX WTI	3,000	$	74.47

NGL		(Bbl/d)	($/Bbl)
Remaining 2022	Mont Belvieu C3	4,000	$	36.62
2023	Mont Belvieu C3	3,000	$	38.07

The Company entered into costless collars based off the NYMEX WTI and Henry Hub oil and natural gas indices. 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 hedge counterparty. Below is a summary of the Company's costless collar positions as of September 30, 2022.


	Index	Daily Volume	Weighted Average Floor Price		Weighted Average Ceiling Price
Natural Gas		(MMBtu/d)	($/MMBtu)		($/MMBtu)
Remaining 2022	NYMEX Henry Hub	389,500	$	2.54	$	2.96
2023	NYMEX Henry Hub	285,000	$	2.93	$	4.78
2024	NYMEX Henry Hub	80,000	$	3.63	$	7.02

Oil		(Bbl/d)	($/Bbl)		($/Bbl)
Remaining 2022	NYMEX WTI	1,500	$	55.00	$	60.00

In the third quarter of 2019, the Company sold call options in exchange for a premium, and used the associated premiums received to enhance the fixed price for a portion of the fixed price natural gas swaps primarily for 2020. Each short call option has an established ceiling price. When the referenced settlement price is above the price ceiling established by these short call options, the Company pays its counterparty an amount equal to the difference between the referenced settlement price and the price ceiling multiplied by the hedged contract volumes. 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, 2022.


	Index	Daily Volume	Weighted Average Price
Natural Gas		(MMBtu/d)	($/MMBtu)
Remaining 2022	NYMEX Henry Hub	152,675	$	2.90
2023	NYMEX Henry Hub	407,925	$	2.90
2024	NYMEX Henry Hub	202,000	$	3.33
2025	NYMEX Henry Hub	33,315	$	4.65

In addition, the Company entered into natural gas basis swap positions. As of September 30, 2022, the Company had the following natural gas swap positions open:

Gulfport Pays

Gulfport Receives

Daily Volume

Weighted Average Fixed Spread

Natural Gas

(MMBtu/d)

($/MMBtu)

2023

Rex Zone 3

NYMEX Plus Fixed Spread

40,000

(0.21)

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, 2022 and December 31, 2021 (in thousands):


	Successor
	September 30, 2022		December 31, 2021

Short-term derivative asset	$	53,342	$	4,695
Long-term derivative asset	24,335		18,664
Short-term derivative liability	(817,384)		(240,735)
Long-term derivative liability	(299,150)		(184,580)
Total commodity derivative position	$	(1,038,857)	$	(401,956)

Gains and Losses

The following tables present the gain and loss recognized in net loss on natural gas, oil and NGL derivatives in the accompanying consolidated statements of operations for the Current Successor Quarter, Current Successor YTD Period, Prior Successor Quarter, Prior Successor Period, and Prior Predecessor YTD Period (in thousands):


	Net loss on derivative instruments
	Successor
	Three Months Ended September 30, 2022		Three Months Ended September 30, 2021
Natural gas derivatives - fair value losses	$	(161,532)	$	(517,799)
Natural gas derivatives - settlement losses	(354,084)		(82,566)
Total losses on natural gas derivatives	(515,616)		(600,365)

Oil derivatives - fair value gains (losses)	33,545		(1,590)
Oil derivatives - settlement losses	(9,035)		(4,336)
Total gains (losses) on oil and condensate derivatives	24,510		(5,926)

NGL derivatives - fair value gains (losses)	19,043		(10,201)
NGL derivatives - settlement losses	(2,832)		(5,984)
Total gains (losses) on NGL derivatives	16,211		(16,185)

Total losses on natural gas, oil and NGL derivatives	$	(474,895)	$	(622,476)


	Net loss on derivative instruments
	Successor				Predecessor
	Nine Months Ended September 30, 2022		Period from May 18, 2021 through September 30, 2021		Period from January 1, 2021 through May 17, 2021
Natural gas derivatives - fair value losses	$	(659,193)	$	(638,063)	$	(123,080)
Natural gas derivatives - settlement losses	(754,177)		(89,255)		(3,362)
Total losses on natural gas derivatives	(1,413,370)		(727,318)		(126,442)

Oil derivatives - fair value gains (losses)	8,076		(6,947)		(6,126)
Oil derivatives - settlement losses	(31,460)		(4,336)		—
Total losses on oil and condensate derivatives	(23,384)		(11,283)		(6,126)

NGL derivatives - fair value gains (losses)	14,216		(17,549)		(4,671)
NGL derivatives - settlement losses	(13,779)		(5,984)		—
Total gains (losses) on NGL derivatives	437		(23,533)		(4,671)

Total losses on natural gas, oil and NGL derivatives	$	(1,436,317)	$	(762,134)	$	(137,239)

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):


	Successor
	As of September 30, 2022
	Gross Assets (Liabilities)		Gross Amounts
	Presented in the		Subject to Master		Net
	Consolidated Balance Sheets		Netting Agreements		Amount
Derivative assets	$	77,677	$	(72,718)	$	4,959
Derivative liabilities	$	(1,116,533)	$	72,718	$	(1,043,815)


	Successor
	As of December 31, 2021
	Gross Assets (Liabilities)		Gross Amounts
	Presented in the		Subject to Master		Net
	Consolidated Balance Sheets		Netting Agreements		Amount
Derivative assets	$	23,359	$	(20,265)	$	3,094
Derivative liabilities	$	(425,315)	$	20,265	$	(405,050)

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.

9.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, 2022 and December 31, 2021 (in thousands):


	Successor
	September 30, 2022
	Level 1		Level 2		Level 3
Assets:
Derivative instruments	$	—	$	77,677	$	—
Contingent consideration arrangement	—		—		4,900
Total assets	$	—	$	77,677	$	4,900
Liabilities:
Derivative instruments	$	—	$	1,116,533	$	—


	Successor
	December 31, 2021
	Level 1		Level 2		Level 3
Assets:
Derivative instruments	$	—	$	23,359	$	—
Contingent consideration arrangement	—		—		5,800
Total assets	$	—	$	23,359	$	5,800
Liabilities:
Derivative instruments	$	—	$	425,315	$	—

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The Company estimates the fair value of all derivative instruments using industry-standard models that consider various assumptions, including current market and contractual prices for the underlying instruments, implied volatility, time value, nonperformance risk, as well as other relevant economic measures. Substantially all of these inputs are observable in the marketplace throughout the full term of the instrument and can be supported by observable data. The Company adjusted the fair value of its derivative instruments as a fresh start adjustment at the Emergence Date as a result of changes in the Company's credit adjustment to reflect its new credit standing at emergence.

The Company's SCOOP water infrastructure sale, which closed in the first quarter of 2020, included a contingent consideration arrangement. As of September 30, 2022, the fair value of the contingent consideration was $4.9 million, of which $0.6 million is included in prepaid expenses and other assets and $4.3 million is included in other assets in the accompanying consolidated balance sheets. The fair value of the contingent consideration arrangement is calculated using discounted cash flow techniques and is based on internal estimates of the Company's future development program and water production levels. Given the unobservable nature of the inputs, the fair value measurement of the contingent consideration arrangement is deemed to use Level 3 inputs. The Company has elected the fair value option for this contingent consideration arrangement and, therefore, records changes in fair value in earnings. The Company recognized losses of $0.3 million and $1.2 million for the Current Successor Quarter and Prior Successor Quarter, respectively, with respect to this contingent consideration arrangement. The Company recognized losses of $0.4 million, $0.1 million and a nominal gain for the Current Successor YTD Period, Prior Successor Period, and Prior Predecessor YTD Period, 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.

10.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.

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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 renew automatically under the same provisions. For those contracts, the Company has utilized the practical expedient allowed in the revenue accounting standard that exempts the Company from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less.

For product sales that have a contract term greater than one year, the Company has utilized the practical expedient that exempts the Company from disclosure of the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product generally represents a separate performance obligation; therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. Currently, the Company's product sales that have a contractual term greater than one year have no long-term fixed consideration.

Contract Balances

Receivables from contracts with customers are recorded when the right to consideration becomes unconditional, generally when control of the product has been transferred to the customer. Receivables from contracts with customers were $317.5 million and $232.9 million as of September 30, 2022 and December 31, 2021, respectively, and are reported in accounts receivable - oil, natural gas, and natural gas liquids sales on the 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.

11.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. However, at September 30, 2022, the Company did not have any active long-term drilling rig contracts in place.

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 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. In July 2022, the Company moved its headquarters to a new location. The impact of the Company's new headquarters lease is reflected in the tables below.

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Discount Rate

As most of the Company's leases do not provide an implicit rate, the Company uses its incremental borrowing rate based on the information available at commencement date in determining the present value of lease payments. The Company's incremental borrowing rate reflects the estimated rate of interest that it would pay to borrow on a collateralized basis over a similar term an amount equal to the lease payments in a similar economic environment.

Future amounts due under operating lease liabilities as of September 30, 2022 were as follows (in thousands):


Remaining 2022	$	247
2023	966
2024	824
2025	824
2026	550
Total lease payments	$	3,411
Less: imputed interest	(351)
Total	$	3,060

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


	Successor
	Three Months Ended September 30, 2022		Three Months Ended September 30, 2021
Operating lease cost	$	187	$	10
Variable lease cost	—		—
Short-term lease cost	8,035		2,873
Total lease cost(1)	$	8,222	$	2,883


	Successor				Predecessor
	Nine Months Ended September 30, 2022		Period from May 18, 2021 through September 30, 2021		Period from January 1, 2021 through May 17, 2021
Operating lease cost	$	287	$	18	$	41
Variable lease cost	—		—		—
Short-term lease cost	26,817		5,033		4,496
Total lease cost(1)	$	27,104	$	5,051	$	4,537

_____________________

(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):


	Successor				Predecessor
	Nine Months Ended September 30, 2022		Period from May 18, 2021 through September 30, 2021		Period from January 1, 2021 through May 17, 2021
Cash paid for amounts included in the measurement of lease liabilities
Operating cash flows from operating leases	$	354	$	46	$	48

The weighted-average remaining lease term as of September 30, 2022 was 3.75 years. The weighted-average discount rate used to determine the operating lease liability as of September 30, 2022 was 5.90%.

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12.INCOME TAXES

On August 16, 2022, the U.S. enacted the Inflation Reduction Act of 2022, which, among other things, implements a 15% minimum tax on book income of certain large corporations, a 1% excise tax on net stock repurchases and several tax incentives to promote clean energy. Based on our current analysis of the provisions, we do not believe this legislation will have a material impact on our consolidated financial statements.

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, 2022, the Company's estimated annual effective tax rate remained nominal as a result of the valuation allowance on its deferred tax assets. The effective tax rate for the period was 0%, which differs from the statutory rate of 21% primarily as a result of the valuation allowance on the Company's deferred tax assets.

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 determined a full valuation allowance was necessary against its net deferred tax assets as of September 30, 2022.

The Company will continue to evaluate whether the valuation allowance is needed in future reporting periods. The valuation allowance will remain until it is determined that the net deferred tax assets are more likely than not to be realized. Future events or new evidence which may lead us to conclude that it is more likely than not that its net deferred tax assets will be realized include, but are not limited to, cumulative historical pre-tax earnings, improvements in oil prices, and taxable events that could result from one or more transactions. The valuation allowance does not prevent future utilization of the tax attributes if the Company recognizes taxable income. As long as the Company concludes that the valuation allowance against its net deferred tax assets is necessary, the Company likely will not have any additional deferred income tax expense or benefit.

Elements of the Plan provided that the Company’s indebtedness related to Predecessor Senior Notes and certain general unsecured claims were exchanged for New Common Stock in settlement of those claims. Absent an exception, a debtor recognizes CODI upon discharge of its outstanding indebtedness for an amount of consideration that is less than its adjusted issue price. The IRC provides that a debtor in a Chapter 11 bankruptcy case may exclude CODI from taxable income, but must reduce certain of its tax attributes by the amount of any CODI realized as a result of the consummation of a plan of reorganization. The amount of CODI realized by a taxpayer is determined based on the fair market value of the consideration received by the creditors in settlement of outstanding indebtedness. As a result of the market value of equity upon emergence from Chapter 11 bankruptcy proceedings, the estimated amount of CODI and historical interest expense haircut is approximately $661 million, which will reduce the value of the Company’s net operating losses. The actual reduction in tax attributes does not occur until the first day of the Company’s tax year subsequent to the date of emergence, or January 1, 2022. The reduction of net operating losses is expected to be fully offset by a corresponding decrease in valuation allowance.

Emergence from Chapter 11 bankruptcy proceedings resulted in a change in ownership for purposes of IRC Section 382. The Company is applying rules under IRC Section 382(l)(5) that allow the Company to mitigate the limitations imposed under the regulations with respect to the Company’s remaining tax attributes. The Company’s deferred tax assets and liabilities, prior to the valuation allowance, have been computed on such basis. Additionally, under IRC Section 382(l)(5), an ownership change subsequent to the Company’s emergence could severely limit or effectively eliminate its ability to realize the value of its tax attributes.

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13.SUBSEQUENT EVENTS

Credit Facility Redetermination

On October 31, 2022, the Company completed its semi-annual borrowing base redetermination during which the borrowing base was reconfirmed at $1.0 billion with the elected commitments remaining at $700 million.

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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, 2021 (“2021 Form 10-K”), and analyzes the changes in the results of operations between the periods of July 1, 2022 through September 30, 2022 (“Current Successor Quarter”), January 1, 2022 through September 30, 2022 ("Current Successor YTD Period"), July 1, 2021, through September 30, 2021 (“Prior Successor Quarter”), May 18, 2021 through September 30, 2021 ("Prior Successor Period"), and January 1, 2021 through May 17, 2021 ("Prior Predecessor YTD Period"). 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 and in our 2021 Form 10-K.

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 in central Oklahoma targeting the SCOOP Woodford and SCOOP 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

Share Repurchase Program

In November 2021 our board of directors approved a stock Repurchase Program to acquire up to $100 million of our outstanding common stock and increased the authorization from $100 million to $200 million in April 2022 and from $200 million to $300 million in July 2022 ("Repurchase Program"). Purchases under the Repurchase Program 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 us to acquire any specific number of shares of common stock. We intend to purchase shares under the Repurchase Program with available funds while maintaining sufficient liquidity to fund our capital development program. The Repurchase Program is authorized to extend through June 30, 2023 and may be suspended from time to time, modified, extended or discontinued by the board of directors at any time. Any shares of common stock repurchased are expected to be cancelled. As of September 30, 2022, 2,607,059 shares have been repurchased for approximately $227.6 million under the Repurchase Program at a weighted average price of $87.29 per share.

Inflation, Rising Interest Rates and Changes in Commodity Prices

The annual rate of inflation in the United States was measured at 8.2% in September 2022 by the Consumer Price Index, the highest in more than four decades. Inflation and increased commodity prices have caused drilling and completion costs to increase from the prior year. In addition, 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, including continued rate increases. The inflationary environment has impacted interest rates on our Credit Facility borrowings throughout 2022. Interest rates on our Credit Facility borrowings have increased from 3.21% at March 31, 2022 to 6.23% at September 30, 2022. 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 the remainder of 2022 to continue to be a function of supply and demand.

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Impact of the War in Ukraine

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 global energy markets and the amplification of inflation and supply chain constraints. The ultimate impact of the war in Ukraine will depend on future developments and the timing and extent to which normal economic and operating conditions resume.

2022 Operational and Financial Highlights

During the third quarter of 2022, we had the following notable achievements:

•Reported total net production of 914.9 MMcfe per day.

•Turned to sales nine gross (8.1 net) operated wells.

•Completed four-well Extreme pad in the Utica and brought online at a combined gross peak production rate of approximately 140 MMcfe per day.

•Generated $167.9 million of operating cash flows.

•Expanded the Repurchase Program authorization limit from $200 million to $300 million.

•Repurchased 753,074 shares for $64.5 million at a weighted average price of $85.72 per share.

2022 Production and Drilling Activity

Production Volumes


	Successor
	Three Months Ended September 30, 2022	Three Months Ended September 30, 2021
Natural gas (Mcf/day)
Utica	597,027	678,154
SCOOP	218,633	188,292
Other	—	—
Total	815,660	866,446
Oil and condensate (Bbl/day)
Utica	646	958
SCOOP	3,721	4,335
Other	—	78
Total	4,366	5,371
NGL (Bbl/day)
Utica	2,458	2,516
SCOOP	9,714	9,918
Other	—	—
Total	12,172	12,434
Combined (Mcfe/day)
Utica	615,649	698,998
SCOOP	299,239	273,812
Other	—	471
Total	914,888	973,281
Totals may not sum or recalculate due to rounding.

Our total net production averaged approximately 914.9 MMcfe per day during the Current Successor Quarter, as compared to 973.3 MMcfe per day during the Prior Successor Quarter. The 6% decrease in production per day is largely the result of the timing of our development activities in 2022 as compared to 2021 and natural decline on our existing base production.

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	Successor		Predecessor	Non-GAAP Combined
	Nine Months Ended September 30, 2022	Period from May 18, 2021 through September 30, 2021	Period from January 1, 2021 through May 17, 2021	Nine Months Ended September 30, 2021
Natural gas (Mcf/day)
Utica	664,960	682,596	780,791	731,873
SCOOP	200,847	190,305	126,294	158,182
Other	7	38	63	51
Total	865,814	872,939	907,148	890,106
Oil and condensate (Bbl/day)
Utica	688	1,012	1,336	1,175
SCOOP	3,539	4,493	2,508	3,497
Other	1	76	35	55
Total	4,228	5,581	3,879	4,727
NGL (Bbl/day)
Utica	2,251	2,588	2,638	2,613
SCOOP	9,275	9,645	6,200	7,916
Other	1	—	3	2
Total	11,526	12,233	8,841	10,531
Combined (Mcfe/day)
Utica	682,594	704,196	804,633	754,598
SCOOP	277,730	275,134	178,545	226,662
Other	17	498	288	392
Total	960,341	979,828	983,466	981,653
Totals may not sum or recalculate due to rounding.

Our total net production averaged approximately 960.3 MMcfe per day during the Current Successor YTD Period, as compared to 981.7 MMcfe per day during the Prior Combined YTD Period. The result is largely driven by fewer wells turned to sales in the Current Successor YTD Period versus the Prior Combined YTD Period.

Utica. We spud four gross (3.8 net) wells in the Utica during the Current Successor Quarter, three of which were being drilled at September 30, 2022. In addition, we completed twelve gross (11.7 net) operated wells. We did not participate in any additional wells that were drilled by other operators on our Utica acreage.

As of October 27, 2022, we had one operated drilling rig running in the Utica, and we expect to add a top-hole drilling rig during the fourth quarter of 2022.

SCOOP. We did not spud any wells in the SCOOP during the Current Successor Quarter. We participated in five gross (0.08 net) wells that were drilled by other operators on our SCOOP acreage.

As of October 27, 2022, we had no operated drilling rigs running in the SCOOP and we have concluded the 2022 drilling program.

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RESULTS OF OPERATIONS

Current Successor Quarter Compared to Prior Successor Quarter

Natural Gas, Oil 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 Current Successor Quarter and Prior Successor Quarter. Some totals below may not sum or recalculate due to rounding.


	Successor
	Three Months Ended September 30, 2022		Three Months Ended September 30, 2021
Natural gas sales
Natural gas production volumes (MMcf)	75,041		79,713
Natural gas production volumes (MMcf) per day	816		866
Total sales	$	585,596	$	301,516
Average price without the impact of derivatives ($/Mcf)	$	7.80	$	3.78
Impact from settled derivatives ($/Mcf)	$	(4.72)	$	(1.04)
Average price, including settled derivatives ($/Mcf)	$	3.08	$	2.74

Oil and condensate sales
Oil and condensate production volumes (MBbl)	402		494
Oil and condensate production volumes (MBbl) per day	4		5
Total sales	$	36,050	$	33,279
Average price without the impact of derivatives ($/Bbl)	$	89.75	$	67.37
Impact from settled derivatives ($/Bbl)	$	(22.49)	$	(8.77)
Average price, including settled derivatives ($/Bbl)	$	67.26	$	58.60

NGL sales
NGL production volumes (MBbl)	1,120		1,144
NGL production volumes (MBbl) per day	12		12
Total sales	$	44,351	$	45,153
Average price without the impact of derivatives ($/Bbl)	$	39.61	$	39.47
Impact from settled derivatives ($/Bbl)	$	(2.53)	$	(5.23)
Average price, including settled derivatives ($/Bbl)	$	37.08	$	34.24

Natural gas, oil and condensate and NGL sales
Natural gas equivalents (MMcfe)	84,170		89,542
Natural gas equivalents (MMcfe) per day	915		973
Total sales	$	665,997	$	379,948
Average price without the impact of derivatives ($/Mcfe)	$	7.91	$	4.24
Impact from settled derivatives ($/Mcfe)	$	(4.35)	$	(1.04)
Average price, including settled derivatives ($/Mcfe)	$	3.56	$	3.20

Production Costs:
Average lease operating expenses ($/Mcfe)	$	0.18	$	0.15
Average taxes other than income ($/Mcfe)	$	0.20	$	0.13
Average transportation, gathering, processing and compression ($/Mcfe)	$	1.06	$	0.94
Total lease operating expenses, midstream costs and taxes other than income ($/Mcfe)	$	1.44	$	1.22

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


	Successor
	Three Months Ended September 30, 2022		Three Months Ended September 30, 2021
Natural gas	$	585,596	$	301,516
Oil and condensate	36,050		33,279
NGL	44,351		45,153
Natural gas, oil and condensate and NGL sales	$	665,997	$	379,948

The increase in natural gas sales without the impact of derivatives when comparing the Current Successor Quarter to the Prior Successor Quarter was due to a 106% increase in realized natural gas prices partially offset by a 6% decrease in sales volumes. The realized price change was primarily driven by the significant increase in the average Henry Hub gas index from $4.01 per Mcf in the Prior Successor Quarter to $8.20 per Mcf during the Current Successor Quarter.

The increase in oil and condensate sales without the impact of derivatives when comparing the Current Successor Quarter to the Prior Successor Quarter was due to a 33% increase in realized prices, partially offset by a 19% decrease in sales volumes. The realized price change was driven by the significant increase in the average WTI crude index from $70.56 per barrel in the Prior Successor Quarter to $91.55 per barrel during the Current Successor Quarter.

The decrease in NGL sales without the impact of derivatives when comparing the Current Successor Quarter to the Prior Successor Quarter was due to a 2% decrease in production combined with comparable pricing from quarter to quarter.

Natural Gas, Oil and NGL Derivatives (in thousands)


	Successor
	Three Months Ended September 30, 2022		Three Months Ended September 30, 2021
Natural gas derivatives - fair value losses	$	(161,532)	$	(517,799)
Natural gas derivatives - settlement losses	(354,084)		(82,566)
Total losses on natural gas derivatives	$	(515,616)	$	(600,365)

Oil derivatives - fair value gains (losses)	$	33,545	$	(1,590)
Oil derivatives - settlement losses	(9,035)		(4,336)
Total gains (losses) on oil derivatives	$	24,510	$	(5,926)

NGL derivatives - fair value gains (losses)	$	19,043	$	(10,201)
NGL derivatives - settlement losses	(2,832)		(5,984)
Total gains (losses) on NGL derivatives	$	16,211	$	(16,185)

Total losses on natural gas, oil and NGL derivatives	$	(474,895)	$	(622,476)

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. See Note 8 of our consolidated financial statements for hedged volumes and pricing.

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Lease Operating Expenses (in thousands, except per unit)


	Successor
	Three Months Ended September 30, 2022		Three Months Ended September 30, 2021
Lease operating expenses
Utica	$	9,976	$	9,309
SCOOP	5,386		4,527
Other	1		28
Total lease operating expenses	$	15,363	$	13,864

Lease operating expenses per Mcfe
Utica	$	0.18	$	0.14
SCOOP	0.20		0.18
Other	—		0.65
Total lease operating expenses per Mcfe	$	0.18	$	0.15

The increase in total and per unit LOE when comparing the Current Successor Quarter to the Prior Combined Quarter was primarily the result of inflationary effects, increased water hauling, driven by recent wells turned to sales and increased disposal expenses throughout our Utica operations.

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


	Successor
	Three Months Ended September 30, 2022		Three Months Ended September 30, 2021
Production taxes	$	13,622	$	8,822
Property taxes	1,526		2,309
Other	1,381		713
Total taxes other than income	$	16,529	$	11,844
Total taxes other than income per Mcfe	$	0.20	$	0.13

The increase in total and per unit taxes other than income when comparing the Current Successor Quarter to the Prior Successor Quarter was primarily related to an increase in production taxes resulting from the significant increase in our natural gas, oil and NGL revenues excluding the impact of hedges discussed above.

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


	Successor
	Three Months Ended September 30, 2022		Three Months Ended September 30, 2021
Transportation, gathering, processing and compression	$	89,234	$	84,435
Transportation, gathering, processing and compression per Mcfe	$	1.06	$	0.94

The increase in total and per unit transportation, gathering, processing and compression when comparing the Current Successor Quarter to the Prior Successor Quarter was primarily related to an increase in minimum volume commitments, combined with an increase in rates on certain gathering and transportation systems.

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


	Successor
	Three Months Ended September 30, 2022		Three Months Ended September 30, 2021
Depreciation, depletion and amortization of oil and gas properties	$	64,099	$	61,922
Depreciation, depletion and amortization of other property and equipment	320		651
Total depreciation, depletion and amortization	$	64,419	$	62,573
Depreciation, depletion and amortization per Mcfe	$	0.77	$	0.70

The increase in total and per unit depreciation, depletion and amortization of our oil and gas properties when comparing the Current Successor Quarter to the Prior Successor Quarter was primarily the result of an increased depletion rate as a result of our drilling and development activities subsequent to the third quarter of 2021.

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


	Successor
	Three Months Ended September 30, 2022		Three Months Ended September 30, 2021
General and administrative expenses, gross	$	17,015	$	24,951
Reimbursed from third parties	(3,339)		(3,182)
Capitalized general and administrative expenses	(4,924)		(5,078)
General and administrative expenses, net	$	8,752	$	16,691
General and administrative expenses, net per Mcfe	$	0.10	$	0.19

The decrease in general and administrative expenses for the Current Successor Quarter compared to the Prior Successor Quarter was primarily driven by reduced legal and professional fees associated with our restructuring and our continued focus on our workforce and leadership structure to better align to our current operating environment.

Restructuring and Liability Management

During the Prior Successor Quarter, we incurred $2.8 million in restructuring charges related to reductions in workforce as we continued to align our workforce and leadership structure to our current operating environment.

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Interest Expense (in thousands, except per unit)


	Successor
	Three Months Ended September 30, 2022		Three Months Ended September 30, 2021
Interest on 2026 Senior Notes	$	11,053	$	11,049
Interest expense on Credit Facility	3,712		—
Amortization of loan costs	676		594
Interest on exit facility	—		2,458
Interest on first-out term loan	—		2,427


Other	20		(177)
Total interest expense	$	15,461	$	16,351
Interest expense per Mcfe	$	0.18	$	0.18

The change in interest expense was primarily due to the settlement of the exit facility and first-out term loan in the fourth quarter of 2021, which were replaced with the Credit Facility as discussed in Note 3 of our consolidated financial statements.

Income Taxes

We did not record any income tax expense for the Current Successor Quarter as a result of maintaining a full valuation allowance against our net deferred tax asset. See Note 12 of our consolidated financial statements for further details of our valuation allowance. We recorded an income tax expense of $0.7 million for the Prior Successor Quarter in our consolidated statement of operations as a result of an Oklahoma refund claim that was filed during the third quarter of 2021, resulting in an adjustment to the income tax benefit recorded during the Prior Predecessor YTD Period.

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Current Successor YTD Period Compared to Prior Successor Period and Prior Predecessor YTD Period

Natural Gas, Oil 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 Current Successor YTD Period, Prior Successor Period, Prior Predecessor YTD Period, and Prior Combined YTD Period. Some totals below may not sum or recalculate due to rounding.


	Successor				Predecessor		Non-GAAP Combined
	Nine Months Ended September 30, 2022		Period from May 18, 2021 through September 30, 2021		Period from January 1, 2021 through May 17, 2021		Nine Months Ended September 30, 2021
Natural gas sales
Natural gas production volumes (MMcf)	236,367		118,720		124,279		242,999
Natural gas production volumes (MMcf) per day	866		873		907		890
Total sales	$	1,529,898	$	413,234	$	344,390	$	757,624
Average price without the impact of derivatives ($/Mcf)	$	6.47	$	3.48	$	2.77	$	3.12
Impact from settled derivatives ($/Mcf)	$	(3.19)	$	(0.75)	$	(0.03)	$	(0.38)
Average price, including settled derivatives ($/Mcf)	$	3.28	$	2.73	$	2.74	$	2.74

Oil and condensate sales
Oil and condensate production volumes (MBbl)	1,154		759		531		1,290
Oil and condensate production volumes (MBbl) per day	4		6		4		5
Total sales	$	111,298	$	50,866	$	29,106	$	79,972
Average price without the impact of derivatives ($/Bbl)	$	96.42	$	67.02	$	54.81	$	61.99
Impact from settled derivatives ($/Bbl)	$	(27.26)	$	(5.71)	$	—	$	(3.36)
Average price, including settled derivatives ($/Bbl)	$	69.16	$	61.31	$	54.81	$	58.63

NGL sales
NGL production volumes (MBbl)	3,147		1,664		1,211		2,875
NGL production volumes (MBbl) per day	12		12		9		11
Total sales	$	143,741	$	61,230	$	36,780	$	98,010
Average price without the impact of derivatives ($/Bbl)	$	45.68	$	36.80	$	30.37	$	34.09
Impact from settled derivatives ($/Bbl)	$	(4.38)	$	(3.60)	$	—	$	(2.08)
Average price, including settled derivatives ($/Bbl)	$	41.30	$	33.20	$	30.37	$	32.01

Natural gas, oil and condensate and NGL sales
Natural gas equivalents (MMcfe)	262,173		133,257		134,735		267,992
Natural gas equivalents (MMcfe) per day	960		980		983		982
Total sales	$	1,784,937	$	525,330	$	410,276	$	935,606
Average price without the impact of derivatives ($/Mcfe)	$	6.81	$	3.94	$	3.05	$	3.49
Impact from settled derivatives ($/Mcfe)	$	(3.05)	$	(0.75)	$	(0.02)	$	(0.38)
Average price, including settled derivatives ($/Mcfe)	$	3.76	$	3.19	$	3.03	$	3.11

Production Costs:
Average lease operating expenses ($/Mcfe)	$	0.18	$	0.13	$	0.14	$	0.14
Average taxes other than income ($/Mcfe)	$	0.17	$	0.13	$	0.09	$	0.11
Average transportation, gathering, processing and compression ($/Mcfe)	$	1.00	$	0.94	$	1.20	$	1.07
Total lease operating expenses, midstream costs and taxes other than income ($/Mcfe)	$	1.35	$	1.20	$	1.43	$	1.32

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


	Successor				Predecessor		Non-GAAP Combined
	Nine Months Ended September 30, 2022		Period from May 18, 2021 through September 30, 2021		Period from January 1, 2021 through May 17, 2021		Nine Months Ended September 30, 2021
Natural gas	$	1,529,898	$	413,234	$	344,390	$	757,624
Oil and condensate	111,298		50,866		29,106		79,972
NGL	143,741		61,230		36,780		98,010
Natural gas, oil and condensate and NGL sales	$	1,784,937	$	525,330	$	410,276	$	935,606

The increase in natural gas sales without the impact of derivatives when comparing the Current Successor YTD Period to the Prior Combined YTD Period was due to a 107% increase in realized natural gas prices partially offset by a 3% decrease in sales volumes. The realized price change was driven by the significant increase in the average Henry Hub gas index from $3.18 per Mcf in the Prior Combined YTD Period to $6.77 per Mcf during the Current Successor YTD Period.

The increase in oil and condensate sales without the impact of derivatives when comparing the Current Successor YTD Period to the Prior Combined YTD Period was due to a 56% increase in realized prices and partially offset by an 11% decrease in sales volumes. The realized price change was driven by the significant increase in the average WTI crude index from $64.82 per barrel in the Prior Combined YTD Period to $98.09 per barrel during the Current Successor YTD Period.

The increase in NGL sales without the impact of derivatives when comparing the Current Successor YTD Period to the Prior Combined YTD Period was due to a 34% increase in realized prices combined with a 9% increase in NGL sales volumes. The realized price change was driven by the significant increase in the average Mont Belvieu NGL index from $35.76 per barrel in the Prior Combined YTD Period to $49.27 per barrel during the Current Successor YTD Period.

Natural Gas, Oil and NGL Derivatives (in thousands)


	Successor				Predecessor		Non-GAAP Combined
	Nine Months Ended September 30, 2022		Period from May 18, 2021 through September 30, 2021		Period from January 1, 2021 through May 17, 2021		Nine Months Ended September 30, 2021
Natural gas derivatives - fair value losses	$	(659,193)	$	(638,063)	$	(123,080)	$	(761,143)
Natural gas derivatives - settlement losses	(754,177)		(89,255)		(3,362)		(92,617)
Total losses on natural gas derivatives	$	(1,413,370)	$	(727,318)	$	(126,442)	$	(853,760)

Oil derivatives - fair value gains (losses)	$	8,076	$	(6,947)	$	(6,126)	$	(13,073)
Oil derivatives - settlement losses	(31,460)		(4,336)		—		(4,336)
Total losses on oil derivatives	$	(23,384)	$	(11,283)	$	(6,126)	$	(17,409)

NGL derivatives - fair value gains (losses)	$	14,216	$	(17,549)	$	(4,671)	$	(22,220)
NGL derivatives - settlement losses	(13,779)		(5,984)		—		(5,984)
Total gains (losses) on NGL derivatives	$	437	$	(23,533)	$	(4,671)	$	(28,204)

Total losses on natural gas, oil and NGL derivatives	$	(1,436,317)	$	(762,134)	$	(137,239)	$	(899,373)

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 increase in fair value losses is the result of a significant increase in futures pricing for oil, natural gas, and NGL at September 30, 2022. See Note 8 of our consolidated financial statements for hedged volumes and pricing.

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Lease Operating Expenses (in thousands, except per unit)


	Successor				Predecessor		Non-GAAP Combined
	Nine Months Ended September 30, 2022		Period from May 18, 2021 through September 30, 2021		Period from January 1, 2021 through May 17, 2021		Nine Months Ended September 30, 2021
Lease operating expenses
Utica	$	32,796	$	12,162	$	13,991	$	26,153
SCOOP	14,452		5,757		5,449		11,206
Other	(2)		61		84		145
Total lease operating expenses	$	47,246	$	17,980	$	19,524	$	37,504

Lease operating expenses per Mcfe
Utica	$	0.18	$	0.13	$	0.13	$	0.13
SCOOP	0.19		0.15		0.22		0.18
Other	(0.43)		0.90		2.15		1.36
Total lease operating expenses per Mcfe	$	0.18	$	0.13	$	0.14	$	0.14

The increase in total LOE during the Current Successor YTD Period compared to the Prior Combined YTD Period was primarily the result of inflationary effects, increased water hauling, driven by recent wells turned to sales and increased disposal expenses throughout our Utica operations.

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


	Successor				Predecessor		Non-GAAP Combined
	Nine Months Ended September 30, 2022		Period from May 18, 2021 through September 30, 2021		Period from January 1, 2021 through May 17, 2021		Nine Months Ended September 30, 2021
Production taxes	$	36,714	$	12,561	$	8,459	$	21,020
Property taxes	5,311		3,377		2,590		5,967
Other	3,654		962		1,300		2,262
Total taxes other than income	$	45,679	$	16,900	$	12,349	$	29,249
Total taxes other than income per Mcfe	$	0.17	$	0.13	$	0.09	$	0.11

The increase in total and per unit production taxes during the Current Successor YTD Period compared to the Prior Combined YTD Period was primarily related to an increase in production taxes resulting from the significant increase in our natural gas, oil and NGL revenues excluding the impact of hedges discussed above.

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


	Successor				Predecessor		Non-GAAP Combined
	Nine Months Ended September 30, 2022		Period from May 18, 2021 through September 30, 2021		Period from January 1, 2021 through May 17, 2021		Nine Months Ended September 30, 2021
Transportation, gathering, processing and compression	$	261,778	$	125,811	$	161,086	$	286,897
Transportation, gathering, processing and compression per Mcfe	$	1.00	$	0.94	$	1.20	$	1.07

The decrease in transportation, gathering, processing and compression during the Current Successor YTD Period compared to the Prior Combined YTD Period was primarily related to savings associated with rejected midstream contracts and renegotiation through the bankruptcy process.

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


	Successor				Predecessor
	Nine Months Ended September 30, 2022		Period from May 18, 2021 through September 30, 2021		Period from January 1, 2021 through May 17, 2021
Depreciation, depletion and amortization of oil and gas properties	$	188,324	$	93,959	$	60,831
Depreciation, depletion and amortization of other property and equipment	981		976		1,933
Total depreciation, depletion and amortization	$	189,305	$	94,935	$	62,764
Depreciation, depletion and amortization per Mcfe	$	0.72	$	0.71	$	0.47

The increase in depreciation, depletion and amortization of our oil and gas properties during the Current Successor YTD Period compared to the Prior Combined YTD Period was primarily the result of an increase in the depletion rate for the Current Successor YTD Period as a result of the fresh start valuations on our oil and gas properties.

Impairment of Oil and Gas Properties

As a result of the ceiling test performed at June 30, 2021, we incurred a $117.8 million impairment charge of oil and gas properties during the Prior Successor Period. Upon the application of fresh start accounting, the value of our oil and natural gas properties was determined using forward strip oil and natural gas prices as of the Emergence Date. These prices were higher than the 12-month weighted average prices used in the full cost ceiling limitation at June 30, 2021, which led to the Prior Successor Period impairment charge.

Impairment of Other Property and Equipment

We recognized a $14.6 million impairment charge on the Company's corporate headquarters during the Prior Predecessor YTD Period as a result of a change in the expected future use.

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


	Successor				Predecessor		Non-GAAP Combined
	Nine Months Ended September 30, 2022		Period from May 18, 2021 through September 30, 2021		Period from January 1, 2021 through May 17, 2021		Nine Months Ended September 30, 2021
General and administrative expenses, gross	$	48,630	$	34,818	$	32,152	$	66,970
Reimbursed from third parties	(9,874)		(4,355)		(4,957)		(9,312)
Capitalized general and administrative expenses	(14,628)		(7,254)		(8,020)		(15,274)
General and administrative expenses, net	$	24,128	$	23,209	$	19,175	$	42,384
General and administrative expenses, net per Mcfe	$	0.09	$	0.17	$	0.14	$	0.16

The decrease in total general and administrative expenses during the Current Successor YTD Period compared to the Prior Combined YTD Period was primarily driven by reduced legal and professional fees associated with our restructuring, and our continued focus on workforce and leadership structure to align to our current operating environment.

Restructuring and Liability Management

During the Prior Successor Period, we incurred $2.8 million in restructuring charges related to reductions in workforce as we continued to align our workforce and leadership structure to our current operating environment.

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Interest Expense (in thousands, except per unit)


	Successor				Predecessor
	Nine Months Ended September 30, 2022		Period from May 18, 2021 through September 30, 2021		Period from January 1, 2021 through May 17, 2021
Interest on 2026 Senior Notes	$	33,155	$	16,304	$	—
Interest expense on Credit Facility	8,476		—		—
Amortization of loan costs	2,009		1,014		—
Interest on exit facility	—		3,824		—
Interest on first-out term loan	—		3,664		—
Interest on DIP credit facility	—		—		3,104
Interest expense on pre-petition revolving credit facility	—		—		2,044
Other	39		439		(989)
Total interest expense	$	43,679	$	25,245	$	4,159
Interest expense per Mcfe	$	0.17	$	0.19	$	0.03

The increase in interest expense during the Current Successor YTD Period compared to the Prior Combined YTD Period was due to the changes in our debt structure upon emergence from Chapter 11.

Reorganization Items, Net

The following table summarizes the components in reorganization items, net recorded in our consolidated statements of operations for the Current Successor YTD Period, Prior Successor Period and Prior Predecessor YTD Period (in thousands):


	Successor				Predecessor
	Nine Months Ended September 30, 2022		Period from May 18, 2021 through September 30, 2021		Period from January 1, 2021 through May 17, 2021
Legal and professional advisory fees	$	—	$	—	$	81,565
Net gain on liabilities subject to compromise	—		—		(575,182)
Fresh start adjustments, net	—		—		160,756
Elimination of predecessor accumulated other comprehensive income	—		—		40,430
Debt issuance costs	—		—		3,150
Other items, net	—		—		22,383
Reorganization items, net	$	—	$	—	$	(266,898)

Other, net (in thousands)


	Successor				Predecessor		Non-GAAP Combined
	Nine Months Ended September 30, 2022		Period from May 18, 2021 through September 30, 2021		Period from January 1, 2021 through May 17, 2021		Nine Months Ended September 30, 2021
Other, net	$	(11,385)	$	7,980	$	1,713	$	9,693

The increase in other income when comparing the Current Successor YTD Period to the Prior Combined YTD Period was primarily due to settlement payment receipts as discussed in Note 7 of our consolidated financial statements.

Income Taxes

We recorded an income tax benefit of $7.3 million during the Prior Combined YTD Period as a result of an Oklahoma refund claim associated with an examination relating to historical tax returns that was filed in the third quarter of 2021.

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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. Since the Emergence Date, we have generally funded our operations, planned capital expenditures and any share repurchases with cash flow from our operating activities, cash on hand, and borrowings under our revolving 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 Current Successor Quarter, 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 any return of capital to shareholders during the next 12 months.

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, 2022, we had $8.3 million of cash and cash equivalents, $179.0 million of borrowings under our Credit Facility, $113.2 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, 2022 was $729.0 million.

As of October 27, 2022 we had $10.1 million of cash and cash equivalents, $57.0 million in borrowings under our Credit Facility, $113.2 million of letters of credit outstanding, and $550 million of outstanding 2026 Senior Notes.

Debt. On October 14, 2021, we entered into the Third Amended and Restated Credit Agreement with JPMorgan Chase Bank, N.A., as administrative agent, and various lender parties. The Credit Facility provides for an aggregate maximum principal amount of up to $1.5 billion, an initial borrowing base of $850.0 million and an initial aggregate elected commitment amount of $700.0 million. The credit agreement also provides for a $175.0 million sublimit of the aggregate commitments that is available for the issuance of letters of credit.

On May 2, 2022, we entered into the borrowing base redetermination agreement and first amendment to our credit agreement (“Amendment”) governing the Credit Facility. The Amendment, among other things, (a) increased the borrowing base under the New Credit Agreement from $850 million to $1.0 billion with aggregate elected lender commitments to remain 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 are met and (d) provide for the transition from a LIBOR to a SOFR benchmark, with a 10 basis point credit spread adjustment for all tenors.

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.

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Preferred Stock 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 (as defined below) 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 a cash or PIK dividend on a quarterly basis. Each share of preferred stock has a liquidation preference of $1,000 (the "Liquidation Preference"). The preferred stock has no stated maturity and will remain outstanding indefinitely unless repurchased or redeemed by the Company or converted into common stock.

During the Current Successor YTD Period the company paid $4.1 million of cash dividends to holders of our preferred stock.

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 8 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 Current Successor YTD Period, the Company's incurred capital expenditures totaled $346.7 million, of which $322.5 million related to drilling and completion activity and $24.2 million related to leasehold and land investment.

Our capital expenditures for 2022 are currently estimated to be approximately $415 million for drilling and completion expenditures. This includes the addition of a top-hole drilling rig in the Utica during the fourth quarter of 2022. This increased level of activity will allow for Gulfport to execute a continuous completion program during 2023, ultimately providing the opportunity for increased efficiencies and cost savings. In addition, we currently expect to spend approximately $35 million in 2022 for non-drilling and completion expenditures, which primarily includes leasehold acquisition, lease extension and lease maintenance payments in the Utica Shale. We expect this drilling program to result in approximately 975 to 1,000 MMcfe per day of production in 2022.

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Sources and Uses of Cash

The following table presents the major changes in cash and cash equivalents for the Current Successor YTD Period, Prior Successor Period, and Prior Predecessor YTD Period (in thousands):


	Successor				Predecessor
	Nine Months Ended September 30, 2022		Period from May 18, 2021 through September 30, 2021		Period from January 1, 2021 through May 17, 2021
Net cash provided by operating activities	$	551,082	$	164,637	$	172,155
Additions to oil and natural gas properties	(331,994)		(119,306)		(102,330)
Debt activity, net	15,000		(102,145)		(147,660)
Repurchases of common stock	(225,791)		—		—
Proceeds from issuance of preferred stock	—		—		50,000
Preferred stock dividends	(4,136)		—		—
Other	866		1,882		(2,609)
Net change in cash, cash equivalents and restricted cash	$	5,027	$	(54,932)	$	(30,444)
Cash, cash equivalents and restricted cash at end of period	$	8,287	$	4,485	$	59,417

Net Cash Provided by Operating Activities

Net cash flow provided by operating activities was $551.1 million for the Current Successor YTD Period as compared to $336.8 million for the Prior Combined YTD Period. The increase was primarily the result of an increase in cash receipts from our oil and natural gas purchasers due to increased realized commodities pricing. We also incurred significant charges related to our Chapter 11 reorganization in the Prior Predecessor YTD Period prior to our emergence in the second quarter of 2021.

Capital Expenditures

During the Current Successor YTD Period, we spud 11 gross (10.0 net) operated wells and commenced sales from 10 gross (8.5 net) operated wells in the Utica for a total incurred cost of approximately $207.4 million. During the Current Successor YTD Period, we spud six gross (4.3 net) operated wells and commenced sales from seven gross (6.0 net) operated wells in the SCOOP for a total incurred cost of approximately $101.4 million.

During the Current Successor YTD Period, we did not participate in any wells that were spud or turned to sales by other operators on our Utica acreage. In addition, 11 gross (0.07 net) wells were spud and 35 gross (2.7 net) wells were turned to sales by other operators on our SCOOP acreage during the Current Successor YTD Period.

Incurred capital expenditures and cash capital expenditures may vary from period to period due to the cash payment cycle. Cash capital expenditures for the Current Successor YTD Period, Prior Successor Period, and Prior Predecessor YTD Period were as follows (in thousands):


	Successor				Predecessor
	Nine Months Ended September 30, 2022		Period from May 18, 2021 through September 30, 2021		Period from January 1, 2021 through May 17, 2021
Oil and Natural Gas Property Cash Expenditures:
Drilling and completion costs	$	291,926	$	109,077	$	94,128
Leasehold acquisitions	27,086		3,474		2,752
Other	12,982		6,755		5,450
Total oil and natural gas property expenditures	$	331,994	$	119,306	$	102,330

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Debt Activity

In the Current Successor YTD Period, the Company's borrowing on its Credit Facility increased $15 million. As of October 27, 2022 the Company had $57.0 million in borrowings outstanding on its Credit Facility.

Interest rates on our Credit Facility borrowings have increased from 3.21% at March 31, 2022 to 6.23% at September 30, 2022. Additional increases in interest rates may have a negative impact on the Company’s operating cash flows.

Repurchases of Common Stock

During the Current Successor YTD Period, we repurchased 2,607,059 of our common shares for approximately $227.6 million under the Repurchase Program at a weighted average price of $87.29 per share. As of October 27, 2022, we repurchased 2,664,036 shares for approximately $232.8 million under the Repurchase Program at a weighted average price of $87.37 per share.

Issuance of Preferred Stock

During the Prior Predecessor YTD Period, we received approximately $50.0 million in proceeds related to our preferred stock issuance.

Preferred Stock Dividends

During the Current Successor YTD Period, the company paid $4.1 million of cash dividends to holders of our preferred stock.

Contractual and Commercial Obligations

We have various contractual obligations in the normal course of our operations and financing activities, as discussed in Note 7 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, 2021.

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, 2022, our material off-balance sheet arrangements and transactions include $113.2 million in letters of credit outstanding against our Credit Facility and $33.5 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. 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 7 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, 2022, there have been no significant changes in our critical accounting policies from those disclosed in our 2021 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 believe we have sufficient internal controls to prevent unauthorized trading.

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, taking 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 3rd 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 9 of our consolidated financial statements for further discussion of the fair value measurements associated with our derivatives.

As of September 30, 2022, 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 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, 2022, we had a net liability derivative position of $1,038.9 million as compared to a net liability derivative position of $402.0 million as of December 31, 2021. Utilizing actual derivative contractual volumes, a 10% increase in underlying commodity prices would have increased our liability by approximately $252.1 million, while a 10% decrease in underlying commodity prices would have decreased our liability by approximately $246.1 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 revolving amended and restated credit agreement is structured under floating rate terms, as advances under this facility may be in the form of either base rate loans or Eurodollar loans. As such, our interest expense is sensitive to fluctuations in the prime rates in the United States, or, if the Eurodollar rates are elected, the Eurodollar rates. At September 30, 2022, we had $179.0 million in borrowings outstanding under our Credit Facility which bore interest at a weighted average rate of 6.23%. As of September 30, 2022, 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, 2022, 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, 2022, 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 7 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, 2021.


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, 2022 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	373,665	$	80.49	364,465	$	107,681,000
August 1 - August 31	172,503	$	94.36	167,903	$	92,333,000
September 1 - September 30	220,706	$	90.18	220,706	$	72,429,000
Total	766,874	$	85.73	753,074

_____________________

(1) We repurchased and canceled approximately 9,200 and 4,600 shares of our common stock at a weighted average price of $84.69 and $89.79 to satisfy tax withholding requirements incurred upon the vesting of restricted stock unit awards during July and August 2022, respectively.

(2) In November 2021 our Board of Directors approved a stock repurchase program to acquire up to $100 million of its common stock. In April 2022, our Board of Directors approved an increase to the authorized common stock repurchase amounts under its Repurchase Program from $100 million to $200 million. In July 2022, our Board of Directors approved an increase to the authorized common stock repurchase amounts under its Repurchase Program from $200 million to $300 million. The stock repurchase program extends through June 30, 2023. At September 30, 2022, there was approximately $72.4 million that may yet be repurchased under $300 million approved amount.


ITEM 3.			DEFAULTS UPON SENIOR SECURITIES

None.


ITEM 4.			MINE SAFETY DISCLOSURES

Not applicable.


ITEM 5.			OTHER INFORMATION

None.

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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

10.1

Borrowing Base Reaffirmation Agreement and Second Amendment to Credit Agreement

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 2, 2022


GULFPORT ENERGY CORPORATION

By:						/s/ William Buese
						William Buese Chief Financial Officer