gpor-20210930

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, 2021


☐			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)
3001 Quail Springs Parkway
Oklahoma City,	Oklahoma	73134
(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 ¨ Accelerated filer ý 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 28, 2021, 20,585,964 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	6

	Consolidated Statements of Comprehensive Income (Loss)	8

	Consolidated Statements of Stockholders’ Equity (Deficit)	9

	Consolidated Statements of Cash Flows	11

	Notes to Consolidated Financial Statements	12

Item 2.	Management’s Discussion and Analysis of Financial Conditions and Results of Operations	48

	2021 Operation and Financial Highlights	49

	2021 Production and Drilling Activity	50

	Comparison of Quarter-to-Date	52

	Comparison of Year-to-Date	57

	Liquidity and Capital Resources	63

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	67

Item 4.	Controls and Procedures	69

PART II OTHER INFORMATION

Item 1.	Legal Proceedings	70

Item 1A.	Risk Factors	70

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	70

Item 3.	Defaults Upon Senior Securities	70

Item 4.	Mine Safety Disclosures	70

Item 5.	Other Information	70

Item 6.	Exhibits	71

Signatures		73

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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:





2023 Notes. 6.625% Senior Notes due 2023.

2024 Notes. 6.000% Senior Notes due 2024.

2025 Notes. 6.375% Senior Notes due 2025.

2026 Notes. 6.375% Senior Notes due 2026.

ASC. Accounting Standards Codification.

ASU. Accounting Standards Update.

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

Bankruptcy Court. The United States Bankruptcy Court for the Southern District of Texas.


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



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.

Building Loan. Loan agreement for our corporate headquarters scheduled to mature in June 2025.

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.



Current Combined YTD Period. Combined Current Successor YTD Period and Current Predecessor YTD Period.



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

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

Current Successor YTD Period. Period from May 18, 2021 through September 30, 2021.

DD&A. Depreciation, depletion and amortization.

Debtors. Collectively, Gulfport Energy Corporation, Gator Marine, Inc., Gator Marine Ivanhoe, Inc., Grizzly Holdings, Inc., Gulfport Appalachia, LLC, Gulfport Midcon, LLC, Gulfport Midstream Holdings, LLC, Jaguar Resources LLC, Mule Sky LLC, Puma Resources, Inc. and Westhawk Minerals LLC.



DIP Credit Facility. Senior secured superpriority debtor-in-possession revolving credit facility in an aggregate principal amount of $262.5 million.



Emergence Date. May 17, 2021.

Exit Credit Agreement. The Second Amended and Restated Credit Agreement with the Bank of Nova Scotia as lead administrative agent and various lender parties providing for the Exit Facility and the First-Out Term Loan.

Exit Credit Facility. Collectively, the First-Out Term Loan and the Exit Facility, with an initial borrowing base and elected commitment amount of up to $580 million.

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Exit Facility. Senior secured reserve-based revolving credit facility with The Bank of Nova Scotia as the lead arranger and administrative agent and various lender parties.

First-Out Term Loan. Senior secured term loan in an aggregate maximum principal amount of $180 million.

Grizzly. Grizzly Oil Sands ULC.

Grizzly Holdings. Grizzly Holdings Inc.

Gross Acres or Gross Wells. Refers to the total acres or wells in which a working interest is owned.

Guarantors. All existing consolidated subsidiaries that guarantee the Company's revolving credit facility or certain other debt.



Indentures. Collectively, the 1145 Indenture and the 4(a)(2) Indenture governing the Successor 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.







New Common Stock. $0.0001 par value common stock issued by the Successor on the Emergence Date.

New 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.

New Preferred Stock. $0.0001 par value preferred stock issued by the Successor on the Emergence Date.

NYMEX. New York Mercantile Exchange.


Petition Date. November 13, 2020.

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

Pre-Petition Revolving Credit Facility. Senior secured revolving credit facility, as amended, with The Bank of Nova Scotia as the lead arranger and administrative agent and certain lenders from time-to-time party thereto with a maximum facility amount of $580 million.

Prior Predecessor Quarter. Period from July 1, 2020 through September 30, 2020.

Prior Predecessor YTD Period. Period from January 1, 2020 through September 30, 2020.







Restructuring. Restructuring contemplated under the Restructuring Support Agreement including equitizing a significant portion of our pre-petition indebtedness and rejecting or renegotiating certain contracts.


RSA. Restructuring Support Agreement.

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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.


Predecessor Senior Notes. Collectively, the 2023 Notes, 2024 Notes, 2025 Notes and 2026 Notes.



Successor Senior Notes. 8.000% Senior Notes due 2026.




Utica. Refers to the hydrocarbon bearing rock 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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GULFPORT ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS

(In thousands, except share data)


	Successor		Predecessor
	September 30, 2021		December 31, 2020
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	4,485	$	89,861

Accounts receivable—oil and natural gas sales	185,941		119,879
Accounts receivable—joint interest and other	9,669		12,200

Prepaid expenses and other current assets	18,487		160,664
Short-term derivative instruments	2,142		27,146
Total current assets	220,724		409,750
Property and equipment:
Oil and natural gas properties, full-cost method
Proved oil and natural gas properties	1,831,762		9,359,866
Unproved properties	216,357		1,457,043
Other property and equipment	5,277		88,538
Total property and equipment	2,053,396		10,905,447
Less: accumulated depletion, depreciation and amortization	(212,403)		(8,819,178)
Total property and equipment, net	1,840,993		2,086,269
Other assets:
Equity investments	—		24,816
Long-term derivative instruments	961		322


Operating lease assets	34		342

Other assets	25,496		18,372
Total other assets	26,491		43,852
Total assets	$	2,088,208	$	2,539,871

See accompanying notes to consolidated financial statements.

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GULFPORT ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS–CONTINUED

(In thousands, except share data)


	Successor		Predecessor
	September 30, 2021		December 31, 2020
	(Unaudited)
Liabilities, Mezzanine Equity and Stockholders’ Equity (Deficit)
Current liabilities:
Accounts payable and accrued liabilities	$	436,172	$	244,903

Short-term derivative instruments	560,722		11,641
Current portion of operating lease liabilities	34		—

Current maturities of long-term debt	60,000		253,743
Total current liabilities	1,056,928		510,287
Non-current liabilities:
Long-term derivative instruments	272,935		36,604
Asset retirement obligation	19,854		—




Long-term debt, net of current maturities	689,502		—
Total non-current liabilities	982,291		36,604
Liabilities subject to compromise	—		2,293,480
Total liabilities	$	2,039,219	$	2,840,371
Commitments and contingencies (Note 9)

Mezzanine Equity:
New Preferred Stock - $0.0001 par value, 110 thousand shares authorized, 57.9 thousand issued and outstanding at September 30, 2021	57,920		—
Stockholders’ equity (deficit):
Predecessor common stock - $0.01 par value, 200.0 million shares authorized, 160.8 million issued and outstanding at December 31, 2020	—		1,607
Predecessor accumulated other comprehensive loss	—		(43,000)
New Common Stock - $0.0001 par value, 42.0 million shares authorized, 20.6 million issued and outstanding at September 30, 2021	2		—
Additional paid-in capital	692,182		4,213,752
New Common Stock held in reserve, 938 thousand shares	(30,216)		—
Accumulated deficit	(670,899)		(4,472,859)
Total stockholders’ deficit	$	(8,931)	$	(300,500)
Total liabilities, mezzanine equity and stockholders’ deficit	$	2,088,208	$	2,539,871

See accompanying notes to consolidated financial statements.

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GULFPORT ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share data)

(Unaudited)


	Successor		Predecessor
	Three Months Ended September 30, 2021		Three Months Ended September 30, 2020
REVENUES:
Natural gas sales	$	301,516	$	155,163
Oil and condensate sales	33,279		16,012
Natural gas liquid sales	45,153		18,824
Net loss on natural gas, oil and NGL derivatives	(622,476)		(53,823)
Total Revenues	(242,528)		136,176
OPERATING EXPENSES:
Lease operating expenses	13,864		13,393
Taxes other than income	11,844		6,102
Transportation, gathering, processing and compression	84,435		110,567
Depreciation, depletion and amortization	62,573		51,551
Impairment of oil and natural gas properties	—		270,874

General and administrative expenses	16,691		20,331
Restructuring and liability management expenses	2,858		8,984
Accretion expense	488		774

Total Operating Expenses	192,753		482,576
LOSS FROM OPERATIONS	(435,281)		(346,400)
OTHER EXPENSE:
Interest expense	16,351		34,321



Loss from equity method investments, net	—		153

Other, net	9,031		89
Total Other Expense	25,382		34,563
LOSS BEFORE INCOME TAXES	(460,663)		(380,963)
Income tax expense	650		—
NET LOSS	$	(461,313)	$	(380,963)
Dividends on New Preferred Stock	$	(2,095)	$	—

NET LOSS ATTRIBUTABLE TO COMMON STOCKHOLDERS	$	(463,408)	$	(380,963)

NET LOSS PER COMMON SHARE:
Basic	$	(22.50)	$	(2.37)
Diluted	$	(22.50)	$	(2.37)
Weighted average common shares outstanding—Basic	20,598		160,683
Weighted average common shares outstanding—Diluted	20,598		160,683

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GULFPORT ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS—CONTINUED

(In thousands, except per share data)

(Unaudited)


	Successor		Predecessor
	Period from May 18, 2021 through September 30, 2021		Period from January 1, 2021 through May 17, 2021		Nine Months Ended September 30, 2020
REVENUES:
Natural gas sales	$	413,234	$	344,390	$	456,859
Oil and condensate sales	50,866		29,106		47,553
Natural gas liquid sales	61,230		36,780		45,989
Net (loss) gain on natural gas, oil and NGL derivatives	(762,134)		(137,239)		71,414
Total Revenues	(236,804)		273,037		621,815
OPERATING EXPENSES:
Lease operating expenses	17,980		19,524		41,166
Taxes other than income	16,900		12,349		19,039
Transportation, gathering, processing and compression	125,811		161,086		334,789
Depreciation, depletion and amortization	94,935		62,764		194,369
Impairment of oil and natural gas properties	117,813		—		1,357,099
Impairment of other property and equipment	—		14,568		—
General and administrative expenses	23,209		19,175		45,719
Restructuring and liability management expenses	2,858		—		9,601
Accretion expense	714		1,229		2,270

Total Operating Expenses	400,220		290,695		2,004,052
LOSS FROM OPERATIONS	(637,024)		(17,658)		(1,382,237)
OTHER EXPENSE (INCOME):
Interest expense	25,245		4,159		99,677

Gain on debt extinguishment	—		—		(49,579)

Loss from equity method investments, net	—		342		10,987
Reorganization items, net	—		(266,898)		—
Other, net	7,979		1,711		8,957
Total Other Expense (Income)	33,224		(260,686)		70,042
(LOSS) INCOME BEFORE INCOME TAXES	(670,248)		243,028		(1,452,279)
Income tax expense (benefit)	650		(7,968)		7,290
NET (LOSS) INCOME	$	(670,898)	$	250,996	$	(1,459,569)
Dividends on New Preferred Stock	$	(3,126)	$	—	$	—

NET (LOSS) INCOME ATTRIBUTABLE TO COMMON STOCKHOLDERS	$	(674,024)	$	250,996	$	(1,459,569)

NET (LOSS) INCOME PER COMMON SHARE:
Basic	$	(32.87)	$	1.56	$	(9.12)
Diluted	$	(32.87)	$	1.56	$	(9.12)
Weighted average common shares outstanding—Basic	20,507		160,834		160,053
Weighted average common shares outstanding—Diluted	20,507		160,834		160,053

See accompanying notes to consolidated financial statements.

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GULFPORT ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(In thousands)

(Unaudited)


	Successor		Predecessor
	Three Months Ended September 30, 2021		Three Months Ended September 30, 2020
Net loss	$	(461,313)	$	(380,963)
Foreign currency translation adjustment	—		3,661

Other comprehensive income	—		3,661
Comprehensive loss	$	(461,313)	$	(377,302)


	Successor		Predecessor
	Period from May 18, 2021 through September 30, 2021		Period from January 1, 2021 through May 17, 2021		Nine Months Ended September 30, 2020
Net (loss) income	$	(670,898)	$	250,996	$	(1,459,569)
Foreign currency translation adjustment	—		—		(4,497)

Other comprehensive loss	—		—		(4,497)
Comprehensive (loss) income	$	(670,898)	$	250,996	$	(1,464,066)

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			Paid-in Capital		Accumulated Other Comprehensive (Loss) Income		Reined Earnings Accumulated Deficit		Total Stockholders’ Equity (Deficit)
	Common Stock
	Shares	Amount		Shares	Amount
Balance at January 1, 2020 (Predecessor)	159,711	$	1,597	—	$	—	$	4,207,554	$	(46,833)	$	(2,847,726)	$	1,314,592
Net Loss	—	—		—	—		—		—		(517,538)		(517,538)
Other Comprehensive Loss	—	—		—	—		—		(15,030)		—		(15,030)
Stock Compensation	—	—		—	—		2,104		—		—		2,104
Shares Repurchased	(80)	(1)		—	—		(78)		—		—		(79)
Issuance of Restricted Stock	211	2		—	—		(2)		—		—		—
Balance at March 31, 2020 (Predecessor)	159,842	$	1,598	—	$	—	$	4,209,578	$	(61,863)	$	(3,365,264)	$	784,049
Net Loss	—	$	—	—	$	—	$	—	$	—	$	(561,068)	$	(561,068)
Other Comprehensive Income	—	—		—	—		—		6,872		—		6,872
Stock Compensation	—	—		—	—		1,515		—		—		1,515
Shares Repurchased	(27)	—		—	—		(28)		—		—		(28)
Issuance of Restricted Stock	301	3		—	—		(3)		—		—		—
Balance at June 30, 2020 (Predecessor)	160,116	$	1,601	—	$	—	$	4,211,062	$	(54,991)	$	(3,926,332)	$	231,340
Net Loss	—	$	—	—	$	—	$	—	$	—	$	(380,963)	$	(380,963)
Other Comprehensive Income	—	—		—	—		—		3,661		—		3,661
Stock Compensation	—	—		—	—		1,314		—		—		1,314
Shares Repurchased	(136)	(2)		—	—		(127)		—		—		(129)
Issuance of Restricted Stock	782	8		—	—		(8)		—		—		—
Balance at September 30, 2020 (Predecessor)	160,762	$	1,607	—	$	—	$	4,212,241	$	(51,330)	$	(4,307,295)	$	(144,777)

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GULFPORT ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (DEFICIT) CONTINUED

(In thousands)

(Unaudited)


				Common Stock Held in Reserve			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 New Common Stock	21,525	2		—	—		693,773		—		—		693,775
Shares of New 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 New Common Stock Held in Reserve	—	—		741	23,893		—		—		—		23,893
Conversion of New Preferred Stock	10	—		—	—		147		—		—		147
Dividends on New 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 New Preferred Stock	—	—		—	—		(2,095)		—		—		(2,095)
Balance at September 30, 2021 (Successor)	21,535	$	2	(938)	$	(30,216)	$	692,182	$	—	$	(670,899)	$	(8,931)

See accompanying notes to consolidated financial statements.

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GULFPORT ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)


	Successor		Predecessor
	Period from May 18, 2021 through September 30, 2021		Period from January 1, 2021 through May 17, 2021		Nine Months Ended September 30, 2020
Cash flows from operating activities:
Net (loss) income	$	(670,898)	$	250,996	$	(1,459,569)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation and amortization	94,935		62,764		194,369
Impairment of oil and natural gas properties	117,813		—		1,357,099
Impairment of other property and equipment	—		14,568		—
Loss from equity investments	—		342		10,987
Gain on debt extinguishment	—		—		(49,579)
Net loss (gain) on derivative instruments	762,134		137,239		(71,414)
Net cash (payments) receipts on settled derivative instruments	(99,574)		(3,361)		225,364
Non-cash reorganization items, net	—		(446,012)		—
Deferred income tax expense	—		—		7,290
Other, net	1,487		1,725		12,753
Changes in operating assets and liabilities, net	(41,260)		153,894		(27,299)
Net cash provided by operating activities	164,637		172,155		200,001
Cash flows from investing activities:
Additions to oil and natural gas properties	(119,306)		(102,330)		(337,979)
Proceeds from sale of oil and natural gas properties	600		15		46,932
Other, net	2,562		4,484		351
Net cash used in investing activities	(116,144)		(97,831)		(290,696)
Cash flows from financing activities:
Principal payments on Pre-Petition Revolving Credit Facility	—		(318,961)		(372,000)
Borrowings on Pre-Petition Revolving Credit Facility	—		26,050		531,857
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	(1,225)		(7,100)		(633)
Repurchase of senior notes	—		—		(22,827)
Proceeds from issuance of New Preferred Stock	—		50,000		—

Other, net	(55)		(8)		(719)
Net cash (used in) provided by in financing activities	(103,425)		(104,768)		135,678
Net (decrease) increase in cash, cash equivalents and restricted cash	(54,932)		(30,444)		44,983
Cash, cash equivalents and restricted cash at beginning of period	59,417		89,861		6,060
Cash, cash equivalents and restricted cash at end of period	$	4,485	$	59,417	$	51,043

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 with assets primarily located in the Appalachia and Anadarko basins. 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, 2021 ("Current Successor Quarter"), May 18, 2021 through September 30, 2021 (“Current Successor YTD Period”), January 1, 2021 through May 17, 2021 (“Current Predecessor YTD Period”), the three months ended September 30, 2020 (“Prior Predecessor Quarter”) and the nine months ended September 30, 2020 ("Prior Predecessor YTD Period"). The Company's annual report on Form 10-K for the year ended December 31, 2020 (“2020 Form 10-K”) should be read in conjunction with this Form 10-Q. Except as disclosed herein, and with the exception of information in this report related to our emergence from Chapter 11 and the application of fresh start accounting, there has been no material change in the information disclosed in the notes to the consolidated financial statements included in the 2020 Form 10-K. 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.

Certain reclassifications have been made to prior period financial statements and related disclosures to conform to current period presentation. These reclassifications have no impact on previous reported total assets, total liabilities, net loss, total stockholders' deficit or total operating cash flows.

Voluntary Reorganization Under Chapter 11 of the Bankruptcy Code

On the Petition Date, the Debtors filed voluntary petitions of relief under the Bankruptcy Code in the United States Bankruptcy Court for the Southern District of Texas. The Chapter 11 Cases were administered jointly under the caption In re Gulfport Energy Corporation, et al., Case No. 20-35562 (DRJ).

The Bankruptcy Court confirmed the Plan and entered the confirmation order on April 28, 2021. The Debtors emerged from the Chapter 11 Cases on the Emergence Date. The Company's bankruptcy proceedings and related matters have been summarized below.

During the pendency of the Chapter 11 Cases, the Company continued to operate its business in the ordinary course as debtors-in-possession in accordance with the applicable provisions of the Bankruptcy Code. The Bankruptcy Court granted the first day relief requested by the Company that was designed primarily to mitigate the impact of the Chapter 11 Cases on its operations, vendors, suppliers, customers and employees. As a result, the Company was able to conduct normal business activities and satisfy all associated obligations for the period following the Petition Date and was also authorized to pay mineral interest owner royalties, employee wages and benefits, and certain vendors and suppliers in the ordinary course for goods and services provided prior to the Petition Date. During the pendency of the Chapter 11 Cases, all transactions outside the ordinary course of business required the prior approval of the Bankruptcy Court.

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Subject to certain specific exceptions under the Bankruptcy Code, the filing of the Chapter 11 Cases automatically stayed all judicial or administrative actions against the Company and efforts by creditors to collect on or otherwise exercise rights or remedies with respect to pre-petition claims. Absent an order from the Bankruptcy Court, substantially all of the Debtors’ pre-petition liabilities were subject to compromise and discharge under the Bankruptcy Code. The automatic stay was lifted on the Emergence Date.

The Company applied FASB ASC Topic 852 - Reorganizations ("ASC 852") in preparing the consolidated financial statements for the period ended May 17, 2021. ASC 852 specifies the accounting and financial reporting requirements for entities reorganizing through Chapter 11 bankruptcy proceedings. These requirements include distinguishing transactions associated with the reorganization separate from activities related to the ongoing operations of the business. Accordingly, pre-petition liabilities that may be impacted by the Chapter 11 proceedings were classified as liabilities subject to compromise on the consolidated balance sheet as of December 31, 2020. Additionally, certain expenses, realized gains and losses and provisions for losses that are realized or incurred during the Chapter 11 Cases are recorded as reorganization items, net. Refer to Note 3 for more information regarding reorganization items.

Accounts Payable and Accrued Liabilities

Accounts payable and accrued liabilities consisted of the following at September 30, 2021 and December 31, 2020:


	Successor		Predecessor
	September 30, 2021		December 31, 2020
Accounts payable and other accrued liabilities	$	159,080	$	120,275
Revenue payable and suspense	155,454		124,628
Accrued contract rejection damages and shares held in reserve	121,638		—
Total accounts payable and accrued liabilities	$	436,172	$	244,903

Recently Adopted Accounting Standards

In August 2020, the FASB issued ASU No. 2020-06, Debt—Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging— Contracts in Entity’s Own Equity (Subtopic 815-40): Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity. This new standard simplifies and adds disclosure requirements for the accounting and measurement of convertible instruments. It eliminates the treasury stock method for convertible instruments and requires application of the “if-converted” method for certain agreements. In addition, the standard eliminates the beneficial conversion and cash conversion accounting models that require separate accounting for embedded conversion features and the recognition of a debt discount and related amortization to interest expense of those embedded features.

The Company elected to early adopt this standard effective on the Emergence Date. The Company adopted the new standard using the modified retrospective approach transition method. No cumulative-effect adjustment to retained earnings was required upon adoption of the new standard. The consolidated financial statements for the Successor Period are presented under the new standard, while the predecessor periods and comparative periods are not adjusted and continue to be reported in accordance with the Company's historical accounting policy.

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Supplemental Cash Flow and Non-Cash Information


	Successor		Predecessor
	Period from May 18, 2021 through September 30, 2021		Period from January 1, 2021 through May 17, 2021		Nine Months Ended September 30, 2020
Supplemental disclosure of cash flow information:
Cash paid for reorganization items, net	$	42,202	$	87,199	$	—
Interest payments	6,465		7,272		73,979
Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable - oil and natural gas sales	(5,230)		(60,832)		28,767
(Increase) decrease in accounts receivable - joint interest and other	5,536		(3,005)		32,827
Increase (decrease) in accounts payable and accrued liabilities	(48,903)		79,193		(40,552)
(Increase) decrease in prepaid expenses	7,231		135,471		(45,620)
(Increase) decrease in other assets	106		3,067		(2,721)
Total changes in operating assets and liabilities	$	(41,260)	$	153,894	$	(27,299)
Supplemental disclosure of non-cash transactions:
Capitalized stock-based compensation	$	484	$	930	$	2,189
Asset retirement obligation capitalized	55		546		2,343
Asset retirement obligation removed due to divestiture	—		—		(2,033)
Interest capitalized	117		—		907
Fair value of contingent consideration asset on date of divestiture	—		—		23,090
Release of New Common Stock Held in Reserve	23,893		—		—
Foreign currency translation gain (loss) on equity method investments	—		2,570		(4,497)

2.CHAPTER 11 EMERGENCE

As described in Note 1, on November 13, 2020, the Debtors filed the Chapter 11 Cases and the Plan, which was subsequently amended, and entered the confirmation order on April 28, 2021. The Debtors then emerged from bankruptcy upon effectiveness of the Plan on May 17, 2021. Capitalized terms used but not defined herein shall have the meaning ascribed to them in the Plan.

Plan of Reorganization

In accordance with the Plan confirmed by the Bankruptcy Court, the following significant transactions occurred upon the Company's emergence from bankruptcy on May 17, 2021:

•Shares of the Predecessor's common stock outstanding immediately prior to the Emergence Date were cancelled, and on the Emergence Date, the Company issued 19,845,780 shares of New Common Stock and 55,000 shares of New Preferred Stock, which were the result of the transactions described below. The Company also entered into a registration rights agreement and amended its articles of incorporation and bylaws for the authorization of the New Common Stock and New Preferred Stock among other corporate governance actions. See Note 6 for further discussion of the Company's post-emergence equity;

•All outstanding obligations under the Predecessor Senior Notes were cancelled;

•The Predecessor effectuated certain restructuring transactions, including entering into a plan of Merger with Gulfport Merger Sub, Inc., a newly formed, wholly owned subsidiary of Gulfport ("Merger Sub"), pursuant to which Merger Sub was merged with and into Predecessor, resulting in the Predecessor becoming a wholly owned subsidiary of Gulfport;

•The Debtors entered into a Second Amended and Restated Credit Agreement (the "Exit Credit Agreement") with the Bank of Nova Scotia as administrative agent, various lender parties and acknowledged and agreed to by certain of Gulfport's subsidiaries, as guarantors, providing for (i) a new money senior secured reserve-based revolving credit facility in an aggregate maximum principal amount of up to $1.5 billion (the "Exit Facility"); (ii) a senior secured term loan in an aggregate maximum principal amount of up to $180 million (the "First-Out Term Loan") and together with the Exit Facility (the "Exit Credit Facility"), collectively with an initial borrowing base and elected commitment

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amount of up to $580 million (less the amount of any term loan deemed funded by any RBL Lender that is not a Consenting RBL Lender);

•The Company entered into an indenture to issue up to $550 million aggregate principal amount of its 8.000% senior notes due 2026, dated as of May 17, 2021, by and among the Issuer, UMB Bank, National Association, as trustee, and the guarantors party thereto (such indenture, the “1145 Indenture,” and such senior notes issued thereunder, the “1145 Notes”), under section 1145 of the Bankruptcy Code (“Section 1145”). Certain eligible holders have made an election (the “4(a)(2) Election”) entitling such holders to receive senior notes issued pursuant to an indenture, dated as of May 17, 2021, by and among the Issuer, UMB Bank, National Association, as trustee, and the guarantors party thereto (such indenture, the “4(a)(2) Indenture,” and such senior notes issued thereunder, the “4(a)(2) Notes”), under Section 4(a)(2) of the Securities Act of 1933, as amended as opposed to its share of the up to $550 million aggregate principal amount of 1145 Notes. The 4(a)(2) Indenture's terms are substantially similar to the terms of the 1145 Indenture. The 1145 Indenture and the 4(a)(2) Indenture are referred to together as the "Indentures". The 1145 Notes and the 4(a)(2) Notes are collectively referred to as the "Successor Senior Notes";

•The DIP Credit Facility indefeasibly converted into the Exit Facility, and all commitments under the DIP Credit Facility terminated. Each holder of an Allowed DIP Claim received, in full and final satisfaction, settlement, release, and discharge of, and in exchange for, each Allowed DIP Claim its Pro Rata share of participation in the Exit Credit Facility;

•Each holder of an Allowed Notes Claim received its pro rata share of 19,714,204 shares of New Common Stock, 54,967 shares of New Preferred Stock and New Unsecured Senior Notes.

•1,678,755 shares of New Common Stock were issued to the Disputed Claims reserve;

•Each holder of a Class 4A Claim greater than the Convenience Claim Threshold received its pro rata share of 119,679 shares of New Common Stock (which were issued to the Unsecured Claims Distribution Trust), $10 million in cash, subject to adjustment by the Unsecured Claims Distribution Trustee, and 100% of the Mammoth Shares;

•Each holder of a Class 4B claim greater than the Convenience Claim Threshold received its pro rata share of 11,897 shares of New Common Stock, 33 shares of New Preferred Stock, the Rights Offering Subscription Rights and the Successor Senior Notes.

•Each holder of a Convenience Class Claim will share in a $3 million cash distribution pool, which the Unsecured Claims Distribution Trustee may increase by an additional $2 million by reducing the Gulfport Parent Cash Pool;

•Each intercompany claim was cancelled on the Emergence Date and holders of intercompany interests received no recovery or distribution;

•The Company conducted a Rights Offering and issued 50,000 shares of New Preferred Stock at $1,000 per share to holders of claims against the Predecessor Subsidiaries, raising $50 million in proceeds. Additionally, 5,000 shares were issued to the Back Stop Commitment counterparties in lieu of cash consideration as per the Backstop Commitment Agreement.

•The Company adopted the Gulfport Energy Corporation 2021 Stock Incentive Plan (the "Incentive Plan") effective on the Emergence Date and reserved 2,828,123 shares of New Common Stock for issuance to Gulfport's employees and non-employee directors pursuant to equity incentive awards to be granted under the Incentive Plan.

Additionally, pursuant to the Plan confirmed by the Bankruptcy Court, the Company's post-emergence Board of Directors is comprised of five directors, including the Company's Chief Executive Officer, Timothy Cutt, and four non-employee directors, David Wolf, Guillermo Martinez, Jason Martinez and David Reganato.

Executory Contracts

Subject to certain exceptions, under the Bankruptcy Code the Debtors were entitled to assume, assign or reject certain executory contracts and unexpired leases subject to the approval of the Bankruptcy Court and fulfillment of certain other conditions. Generally, the rejection of an executory contract was treated as a pre-petition breach of such contract and, subject to certain exceptions, relieved the Debtors from performing future obligations under such contract but entitled the counterparty to a pre-petition general unsecured claim for damages caused by such deemed breach. Alternatively, the assumption of an

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executory contract or unexpired lease required the Debtors to cure existing monetary defaults under such executory contract or unexpired lease, if any, and provide adequate assurance of future performance. Accordingly, any description of an executory contract or unexpired lease with the Debtors in this document, including where applicable quantification of the Company’s obligations under such executory or unexpired lease of the Debtors, is qualified by any overriding rejection rights the Company has under the Bankruptcy Code. Further, nothing herein is or shall be deemed an admission with respect to any claim amounts or calculations arising from the rejection of any executory contract or unexpired lease and the Debtors expressly preserve all of their rights thereto. Refer to Note 9 for more information on potential future rejection damages related to general unsecured claims.

3.FRESH START ACCOUNTING

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. The Company qualified for fresh start accounting because (1) the holders of existing voting shares of the Company prior to the Emergence Date received less than 50% of the voting shares of the Successor's equity following its emergence from bankruptcy and (2) the reorganization value of the Company's assets immediately prior to confirmation of the Plan of approximately $2.3 billion was less than the post-petition liabilities and allowed claims of $3.1 billion.

In accordance with ASC 852, with the application of fresh start accounting, the Company allocated its reorganization value to its individual assets based on their estimated fair value in conformity with FASB ASC Topic 820 - Fair Value Measurements and FASB ASC Topic 805 - Business Combinations. Accordingly, the consolidated financial statements after May 17, 2021 are not comparable with the consolidated financial statements as of or prior to that date. The Emergence Date fair values of the Successor's assets and liabilities differ materially from their recorded values as reflected on the historical balance sheet of the Predecessor.

Reorganization Value

Reorganization value is derived from an estimate of enterprise value, or fair value of the Company's interest-bearing debt and stockholders' equity. Under ASC 852, reorganization value generally approximates fair value of the entity before considering liabilities and is intended to approximate the amount a willing buyer would pay for the assets immediately after the effects of a restructuring. As set forth in the disclosure statement, amended for updated pricing, and approved by the Bankruptcy Court, the enterprise value of the Successor was estimated to be between $1.3 billion and $1.9 billion. With the assistance of third-party valuation advisors, the Company determined the enterprise value and corresponding implied equity value of the Successor using various valuation approaches and methods, including: (i) income approach using a calculation of present value of future cash flows based on our financial projections, (ii) the market approach using selling prices of similar assets and (iii) the cost approach. Deferred income taxes were determined in accordance with FASB ASC Topic 740 - Income Taxes. For GAAP purposes, the Company valued the Successor's individual assets, liabilities and equity instruments and determined an estimate of the enterprise value within the estimated range. Management concluded that the best estimate of enterprise value was $1.6 billion. Specific valuation approaches and key assumptions used to arrive at reorganization value, and the value of discrete assets and liabilities resulting from the application of fresh start accounting, are described below in greater detail within the valuation process.

The enterprise value and corresponding implied equity value are dependent upon achieving the future financial results set forth in our valuation using an asset-based methodology of estimated proved reserves, undeveloped properties, and other financial information, considerations and projections, applying a combination of the income, cost and market approaches as of the fresh start reporting date of May 17, 2021. As estimates, assumptions, valuations and financial projections, including the fair value adjustments, the financial projections, the enterprise value and equity value projections, are inherently subject to significant uncertainties, the resolution of contingencies is beyond our control. Accordingly, there is no assurance that the estimates, assumptions, valuations or financial projections will be realized, and actual results could vary materially.

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The following table reconciles the enterprise value to the implied fair value of the Successor's equity as of the Emergence Date:


Enterprise Value	$	1,600,000
Plus: Cash and cash equivalents(1)	1,526
Less: Fair value of debt	(852,751)
Successor equity value(2)	$	748,775

(1) Restricted cash is not included in the above table.

(2) Inclusive of $55 million of mezzanine equity.

The following table reconciles the enterprise value to the reorganization value as of the Emergence Date:


Enterprise Value	$	1,600,000
Plus: Cash and cash equivalents(1)	1,526
Plus: Current and other liabilities	686,489
Plus: Asset retirement obligations	19,084
Less: Common stock reserved for settlement of claims post Emergence Date	(54,109)
Reorganization value of Successor assets	$	2,252,990

(1) Restricted cash is not included in the above table.

The fair values of our oil and natural gas properties, other property and equipment, derivative instruments, equity investments and asset retirement obligations were estimated as of the Emergence Date.

Oil and natural gas properties. The Company's principal assets are its oil and natural gas properties, which are accounted for under the full cost method of accounting. The Company determined the fair value of its oil and natural gas properties based on the discounted future net cash flows expected to be generated from these assets. Discounted cash flow models by operating area were prepared using the estimated future revenues and operating costs for all developed wells and undeveloped properties comprising the proved and unproved reserves. Significant inputs associated with the calculation of discounted future net cash flows include estimates of (i) recoverable reserves, (ii) production rates, (iii) future operating and development costs, (iv) future commodity prices escalated by an inflationary rate after seven years, adjusted for differentials and (v) a market-based weighted average cost of capital by operating area. The Company utilized NYMEX strip pricing, adjusted for differentials, to value the reserves. The NYMEX strip pricing inputs used are classified as Level 1 fair value assumptions and all other inputs are classified as Level 3 fair value assumptions. The discount rates utilized were derived using a weighted average cost of capital computation, which included an estimated cost of debt and equity for market participants with similar geographies and asset development type by operating area.

Other property and equipment. The fair value of other property and equipment, such as land, buildings, vehicles, computer equipment and other equipment, was maintained at net book value as the carrying value reasonably approximated the fair value of the assets.

Asset retirement obligations. In accordance with FASB ASC Topic 410 - Asset Retirement and Environmental Obligations ("ASC 410"), the asset retirement obligations associated with the Company's oil and gas assets was valued using the income approach. The fair value of the Company’s asset retirement obligations was revalued based upon estimated current reclamation costs for our assets with reclamation obligations, updated estimates of timing of reclamation obligations, an appropriate long-term inflation adjustment, and the Company's revised credit adjusted risk-free rate. The credit adjusted risk-free rate was based on an evaluation of an interest rate that equates to a risk-free interest rate adjusted for the effect of the Company's credit standing.

Derivative Instruments. The fair value of derivative instruments was adjusted based on the change in the Company’s credit rating reflecting the Company’s credit standing at the Emergence Date.

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Equity Investments. The fair value of the Company's investment in Grizzly Sands ULC was reduced by $27 million. The reduction in valuation was based upon the assessment of the investment by the Company's new management and its priority for future funding in its portfolio. In particular, Grizzly’s operations remained suspended, even with improvements in the pricing environment since its initial suspension in 2015. Additionally, the Company does not anticipate funding future capital calls which will lead to further dilution of its equity ownership interest.

Consolidated Balance Sheet

The following consolidated balance sheet is as of May 17, 2021. This consolidated balance sheet includes adjustments that reflect the consummation of the transactions contemplated by the Plan (reflected in the column “Reorganization Adjustments”) as well as fair value adjustments as a result of the adoption of fresh start accounting (reflected in the column “Fresh Start Adjustments”) as of the Emergence Date. The explanatory notes following the table below provide further details on the adjustments, including the assumptions and methods used to determine fair value for its assets and liabilities.


	As of May 17, 2021
	Predecessor		Reorganization Adjustments			Fresh Start Adjustments			Successor
	(In thousands)
Assets
Current assets:
Cash and cash equivalents	$	146,545	$	(145,019)	(a)	$	—		$	1,526
Restricted cash	—		57,891		(b)	—			57,891
Accounts receivable—oil and natural gas sales	180,711		—			—			180,711
Accounts receivable—joint interest and other	15,431		—			—			15,431
Prepaid expenses and other current assets	86,189		(60,894)		(c)	—			25,295
Short-term derivative instruments	3,324		—			141		(r)	3,465
Total current assets	432,200		(148,022)			141			284,319
Property and equipment:
Oil and natural gas properties, full-cost method
Proved oil and natural gas properties	9,558,121		—			(7,860,713)		(s)	1,697,408
Unproved properties	1,375,681		—			(1,145,507)		(s)	230,174
Other property and equipment	38,026		—			(31,133)		(t)	6,893
Total property and equipment	10,971,828		—			(9,037,353)			1,934,475
Accumulated depletion, depreciation and amortization	(8,870,723)		—			8,870,723		(u)	—
Total property and equipment, net	2,101,105		—			(166,630)			1,934,475
Other assets:
Equity investments	27,044		—			(27,044)		(v)	—
Long-term derivative instruments	7,468		—			715		(w)	8,183

Operating lease assets	47		—			—			47
Other assets	18,866		7,100		(d)	—			25,966
Total other assets	53,425		7,100			(26,329)			34,196
Total assets	$	2,586,730	$	(140,922)		$	(192,818)		$	2,252,990

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	Predecessor		Reorganization Adjustments			Fresh Start Adjustments			Successor
	(In thousands)
Liabilities and Stockholders’ Equity (Deficit)
Current liabilities:
Accounts payable and accrued liabilities	$	384,200	$	122,599	(e)	$	—		$	506,799

Short-term derivative instruments	96,116		—			2,784		(x)	98,900
Current portion of operating lease liabilities	—		38		(f)	—			38
Current maturities of long-term debt	280,251		(220,251)		(g)	—			60,000
Total current liabilities	760,567		(97,614)			2,784			665,737
Non-current liabilities:
Long-term derivative instruments	69,331		—			11,411		(y)	80,742
Asset retirement obligation	—		65,341		(h)	(46,257)		(z)	19,084
Non-current operating lease liabilities	—		9		(i)	—			9
Long-term debt, net of current maturities	—		792,751		(j)	—			792,751
Total non-current liabilities	69,331		858,101			(34,846)			892,586
Liabilities subject to compromise	2,224,449		(2,224,449)		(k)	—			—
Total liabilities	$	3,054,347	$	(1,463,962)		$	(32,062)		$	1,558,323
Commitments and contingencies (Note 9)
Mezzanine Equity:
New Preferred Stock	$	—	$	55,000	(l)	$	—		$	55,000
Stockholders’ equity (deficit):
Predecessor common stock	1,609		(1,609)		(m)	—			—
New Common Stock	—		2		(n)	—			2
Additional paid-in capital	4,215,838		(3,522,064)		(o)	—			693,774
New Common Stock held in reserve	—		(54,109)		(p)	—			(54,109)
Accumulated other comprehensive loss	(40,430)		40,430		(q)	—			—
Retained earnings (accumulated deficit)	(4,644,634)		4,805,390		(q)	(160,756)		(aa)	—
Total stockholders’ equity (deficit)	$	(467,617)	$	1,268,040		$	(160,756)		$	639,667
Total liabilities, mezzanine equity and stockholders’ equity (deficit)	$	2,586,730	$	(140,922)		$	(192,818)		$	2,252,990

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Reorganization Adjustments

(a)The table below reflects changes in cash and cash equivalents on the Emergence Date from implementation of the Plan:


Release of escrow funds by counterparties as a result of the Plan	$	63,068
New Preferred Stock rights offering proceeds	50,000
Funds required to rollover the DIP Credit Facility and Pre-Petition Revolving Credit Facility into the Exit Facility	(175,000)
Payment of accrued Pre-Petition Revolving Credit Facility and DIP Credit Facility interest	(1,022)
Payment of issuance costs related to the Exit Credit Facility	(10,250)
Funding of the Professional Fee Escrow	(43,891)
Payment of professional fees at Emergence Date	(7,964)
Transfer to restricted cash for the Unsecured Claims Distribution Trust	(1,000)
Transfer to restricted cash for the Convenience Claims Cash Pool	(3,000)
Transfer to restricted cash for the Parent Cash Pool	(10,000)
Payment of severance costs at Emergence Date	(5,960)
Net change in cash and cash equivalents	$	(145,019)

(b)Changes in restricted cash reflect the net effect of transfers from cash and cash equivalents for the Professional Fee Escrow and various claims class cash pools.

(c)Changes in prepaid expenses and other current assets include the following:


Release of escrow funds as a result of the Plan	$	(63,068)
Recognition of counterparty credits due to settlements effectuated at Emergence	4,247
Prepaid compensation earned at Emergence	(2,073)
Net change in prepaid expenses and other current assets	$	(60,894)

(d)Changes in other assets were due to capitalization of debt issuance costs related to the Exit Credit Facility.

(e)Changes in accounts payable and accrued liabilities included the following:


Payment of accrued Pre-Petition Revolving Credit Facility and DIP Credit Facility interest	$	(1,022)
Payment of professional fees at emergence	(7,964)
Accrued payable for claims to be settled via Unsecured Claims Distribution Trust	1,000
Accrued payable for claims to be settled via Convenience Claims Cash Pool	3,000
Accrued payable for claims to be settled via Parent Cash Pool	10,000
Professional fees payable at Emergence	18,047
Accrued payable for General Unsecured Claims against Gulfport Parent to be settled via 4A Claims distribution from common shares held in reserve	23,894
Accrued payable for General Unsecured Claims against Gulfport Subsidiary to be settled via 4B Claims distribution from common shares held in reserve	30,216
Reinstatement of payables due to Plan effects	45,428
Net change in accounts payable and accrued liabilities	$	122,599

(f)Changes to current operating lease liabilities reflect the reinstatement of lease liabilities due to contract assumptions.

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(g)Changes in the current maturities of long-term debt include the following:


Current portion of Term Notes issued under the Exit Facility	$	60,000
Payment of DIP Facility to effectuate Exit Facility	(157,500)
Transfer of post-petition RBL borrowings to Exit Facility	(122,751)
Net changes to current maturities of long-term debt	$	(220,251)

(h)Reflects the reclassification of asset retirement obligations from liabilities subject to compromise.

(i)Changes to non-current operating lease liabilities reflect the reinstatement of lease liabilities due to contract assumptions.

(j)Changes in long-term debt include the following:


Emergence Date draw on Exit Facility	$	122,751
Noncurrent portion of First-Out Term Loan issued under the Exit Credit Facility	120,000
Issuance of Successor Senior Notes	550,000
Net impact to long-term debt, net of current maturities	$	792,751

(k)On the Emergence Date, liabilities subject to compromise were settled in accordance with the Plan as follows:


General Unsecured Claims settled via Class 4A, 4B, and 5B distributions	$	74,098
Predecessor Senior Notes and associated interest	1,842,035
Pre-Petition Revolving Credit Facility	197,500
Reinstatement of Predecessor Claims as Successor liabilities	45,475
Reinstatement of Predecessor asset retirement obligations	65,341
Total liabilities subject to compromise settled in accordance with the Plan	$	2,224,449

The resulting gain on liabilities subject to compromise was determined as follows:


Pre-petition General Unsecured Claims Settled at Emergence	$	74,098
Predecessor Senior Notes Claims settled at Emergence	1,842,035
Pre-Petition Revolving Credit Facility	197,500
Rollover of Pre-Petition Revolving Credit Facility into Exit RBL Facility	(197,500)
Accrued payable for claims to be settled via Unsecured Claims Distribution Trust	(1,000)
Accrued payable for claims to be settled via Convenience Claims Cash Pool	(3,000)
Accrued payable for claims to be settled via Parent Cash Pool	(10,000)
Accrued payable for shares to be transferred to trust	(54,109)
Issuance of New Common Stock to settle Predecessor liabilities	(639,666)
Issuance of Successor Senior Notes in settlement of Class 4B and 5B claims	(550,000)
Gain on settlement of liabilities subject to compromise	$	658,358

(l)Changes to New Preferred Stock reflect the fair value of preferred shares issued in the Rights Offering.

(m)Changes in Predecessor common stock reflect the extinguishment of Predecessor equity as per the Plan.

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(n)Changes in New Common Stock included the following:


Issuance of common stock to settle General Unsecured Claims against Gulfport Parent (par value)	$	—
Issuance of common stock to settle General Unsecured Claims against Gulfport Subsidiaries (par value)	2
Common stock reserved for settlement of claims post Emergence Date (par value)	—
Net change to New Common Stock	$	2

(o)Changes to paid in capital included the following:


Issuance of common stock to settle General Unsecured Claims against Gulfport Parent	$	27,751
Issuance of common stock to settle General Unsecured Claims against Gulfport Subsidiaries	666,022
Extinguishment of Predecessor stock-based compensation	4,419
Extinguishment of Predecessor paid in capital	(4,220,256)
Net change to paid in capital	$	(3,522,064)

(p)New Common Stock held in reserve to settle Allowed General Unsecured Claims include:


Shares held in reserve to settle Allowed Claims against Gulfport Parent	(23,894)
Shares held in reserve to settle Allowed Claims against Gulfport Subsidiary	(30,215)
Total New Common Stock held in reserve	$	(54,109)

(q)Change to retained earnings (accumulated deficit) included the following


Gain on settlement of liabilities subject to compromise	$	658,358
Extinguishment of Predecessor common stock and paid in capital	4,221,864
Recognition of counterparty credits due to settlements effectuated at Emergence	4,247
Deferred compensation earned at Emergence	(2,073)
Extinguishment of Predecessor accumulated other comprehensive income	(40,430)
Write-off of debt issuance costs related to First-Out Term Loan	(3,150)
Severance costs incurred as a result of the Plan	(5,961)
Professional fees earned at Emergence	(18,047)
Rights offering backstop commitment fee	(5,000)
Extinguishment of Predecessor stock-based compensation	(4,418)
Net change to retained earnings (accumulated deficit)	$	4,805,390

Fresh Start Adjustments

(r)The change in fair value of short-term derivative instruments is due to the change in the Company's post-emergence credit rating.

(s)The change in oil and natural gas properties represents the fair value adjustment to the Company's properties due to the adoption of fresh start accounting.

(t)Predecessor accumulated depreciation and amortization for other property and equipment was net against the gross value of the assets with the adoption of fresh start accounting.

(u)Predecessor accumulated depreciation and amortization was eliminated with the adoption of fresh start accounting.

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(v)The change in equity investments is due to the fair value adjustment to the Company's Grizzly investment.

(w)The change in fair value of long-term derivative instruments is due to the change in the Company's post-emergence credit rating.

(x)The change in fair value of liabilities related to short-term derivative instruments is due to the change in the Company's post-emergence credit rating.

(y)The change in fair value of liabilities related to long-term derivative instruments is due to the change in the Company's post-emergence credit rating.

(z)The fair value of asset retirement obligations were reduced due to the change in the Company's credit adjusted risk-free rate and expected economic life estimates.

(aa)Changes to retained earnings represent the total impact of fresh start adjustments to the post-reorganization balance sheet.

Reorganization Items, Net

The Company has incurred significant expenses, gains and losses associated with the reorganization, primarily the gain on settlement of liabilities subject to compromise, provision for allowed claims and legal and professional fees incurred subsequent to the Chapter 11 filings for the restructuring process. The accrual for allowed claims primarily represents damages from contract rejections and settlements attributable to the midstream savings requirement as stipulated in the Plan. While the claims reconciliation process is ongoing, the estimate of liabilities related to the rejection of certain midstream contracts reflects the best estimate of the most probable outcomes of ongoing litigation and settlement negotiations. The amount of these items, which were incurred in reorganization items, net within the accompanying unaudited condensed consolidated statements of operations, have significantly affected the Company's statements of operations.

The following table summarizes the components in reorganization items, net included in the Company's unaudited consolidated statements of operations:


	Successor		Predecessor
	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)
Total reorganization items, net	$	—	$	266,898

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4.PROPERTY AND EQUIPMENT

The major categories of property and equipment and related accumulated DD&A and impairment as of September 30, 2021 and December 31, 2020 are as follows:


	Successor		Predecessor
	September 30, 2021		December 31, 2020
Proved oil and natural gas properties	$	1,831,762	$	9,359,866
Unproved properties	216,357		1,457,043
Other depreciable property and equipment	4,891		85,530
Land	386		3,008
Total property and equipment	2,053,396		10,905,447
Accumulated DD&A and impairment	(212,403)		(8,819,178)
Property and equipment, net	$	1,840,993	$	2,086,269

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, 2021, 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, 2021. As a result, the Company did not record an impairment of its oil and natural gas properties during the third quarter of 2021. The Company recorded impairment charges of $117.8 million for the Current Combined YTD Period. The Company recorded impairments of its oil and natural gas properties of $270.9 million and $1.4 billion for the Prior Predecessor Quarter and the Prior Predecessor YTD Period, respectively, as a result of the significant decrease in commodity prices.

Certain general and administrative costs are capitalized to the full cost pool and represent management’s estimate of costs incurred directly related to exploration and development activities. All general and administrative costs not capitalized are charged to expense as they are incurred. Capitalized general and administrative costs were approximately $5.1 million for the Current Successor Quarter, $7.3 million for the Current Successor YTD Period, and $8.0 million for the Current Predecessor YTD Period. Capitalized general and administrative costs were approximately $6.2 million and $19.8 million for the Prior Predecessor Quarter and the 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 unevaluated properties excluded from amortization by area at September 30, 2021:


	Successor
	September 30, 2021
	(In thousands)
Utica	$	179,449
SCOOP	36,905
Other	3
Total unproved properties	$	216,357

Impairment of Other Property and Equipment

During the Current Predecessor YTD Period, the Company recorded an impairment of $14.6 million related to its corporate headquarters as a result of changes in the expected future use.

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Asset Retirement Obligation

The following table provides a reconciliation of the Company’s asset retirement obligation for the periods presented:


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	37
Accretion expense	226
Asset retirement obligation at June 30, 2021	$	19,347
Liabilities incurred	19
Accretion expense	488
Asset retirement obligation at September 30, 2021	$	19,854

(1) See Note 3 for additional discussion of fresh start adjustments.

5.LONG-TERM DEBT

Long-term debt consisted of the following items as of September 30, 2021 and December 31, 2020:


	Successor		Predecessor
	September 30, 2021		December 31, 2020
Exit Facility	$	35,606	$	—
First-Out Term Loan	165,000		—
8.000% senior unsecured notes due 2026	550,000		—
DIP Credit Facility	—		157,500
Pre-Petition Revolving Credit Facility	—		292,910
6.625% senior unsecured notes due 2023	—		324,583
6.000% senior unsecured notes due 2024	—		579,568
6.375% senior unsecured notes due 2025	—		507,870
6.375% senior unsecured notes due 2026	—		374,617
Building Loan	—		21,914
Debt issuance costs	(1,104)		—
Total Debt	$	749,502	$	2,258,962
Less: current maturities of long-term debt	(60,000)		(253,743)
Less: amounts reclassified to liabilities subject to compromise	—		(2,005,219)
Total Debt reflected as long term	$	689,502	$	—

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Successor Debt

Our post-emergence debt consisted of the Exit Credit Facility and the Successor Senior Notes. Subsequent to the end of the third quarter of 2021, the Company amended and refinanced the Exit Credit Facility with the New Credit Facility.

New Credit Facility

On October 14, 2021, the Company entered into the New Credit Facility 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. See Note 17 for additional discussion of the New Credit Facility.

Exit Credit Facility

As discussed in Note 2, on the Emergence Date, pursuant to the terms of the Plan, the Company entered into the Exit Credit Agreement, which provided for (i) the Exit Facility in an aggregate principal amount of up to $1.5 billion and (ii) the First-Out Term Loan in an aggregate maximum amount of up to $180.0 million. The Exit Facility had an initial borrowing base and elected commitment amount of up to $580.0 million.

Loans drawn under the Exit Facility were not subject to amortization, while loans drawn under the First-Out Term Loan amortized with $15.0 million quarterly installments, commencing on the closing date and occurring every three months after the closing date. The Exit Credit Facility was schedule to mature on May 17, 2024.

As of September 30, 2021, the Exit Facility and the First-Out Term Loan bore interest at weighted average rates of 4.50% and 5.50%, respectively.

As of September 30, 2021, the Company had $35.6 million outstanding borrowings under the Exit Facility, $165 million outstanding borrowings under the First-Out Term Loan and $115.5 million in letters of credit outstanding. At September 30, 2021, the Company was in compliance with all covenants under its Exit Credit Facility.

Successor Senior Notes

As discussed in Note 2, 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 Exit Credit Facility and the New Credit Facility as discussed in Note 17.

Interest on the Successor Senior Notes will be payable semi-annually, on June 1 and December 1 of each year, commencing on December 1, 2021.

The Successor 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.

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 Successor Senior Notes are rated investment grade, certain covenants will be terminated and cease to apply.

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Chapter 11 Proceedings - Predecessor Debt

Filing of the Chapter 11 Cases constituted an event of default with respect to certain of our secured and unsecured debt obligations. As a result of the Chapter 11 Cases, the principal and interest due under these debt instruments became immediately due and payable. However, Section 362 of the Bankruptcy Code stayed the creditors from taking any action as a result of the default.

The principal amounts from the Predecessor Senior Notes, Building Loan and Pre-Petition Revolving Credit Facility, other than letters of credit drawn on the Pre-Petition Revolving Credit Facility after the Petition Date, have been classified as liabilities subject to compromise on the accompanying consolidated balance sheet as of December 31, 2020.

Debtor-in-Possession Credit Agreement

Pursuant to the RSA, the Consenting RBL Lenders agreed to provide the Company with a senior secured superpriority debtor-in-possession revolving credit facility in an aggregate principal amount of $262.5 million consisting of (a) $105 million of new money and (b) $157.5 million to roll up a portion of the existing outstanding obligations under the Pre-Petition Revolving Credit Facility. The terms and conditions of the DIP Credit Facility are set forth in that certain form of credit agreement governing the DIP Credit Facility. The proceeds of the DIP Credit Facility were used for, among other things, post-petition working capital, permitted capital investments, general corporate purposes, letters of credit, administrative costs, premiums, expenses and fees for the transactions contemplated by the Chapter 11 Cases and payment of court approved adequate protection obligations. On the Emergence Date, the DIP Facility was terminated and the lenders indefeasibly converted into the Exit Facility. Each holder of an allowed DIP Claim received, in full and final satisfaction, settlement, release, and discharge of, and in exchange for, each Allowed DIP Claim its Pro Rata share of participation in the Exit Credit Facility.

Pre-Petition Revolving Credit Facility

Prior to the Emergence Date, the Company had entered into a senior secured revolving credit facility agreement, as amended, with The Bank of Nova Scotia, as the lead arranger and administrative agent and certain lenders from time to time party thereto. The Pre-Petition Revolving Credit Facility had a borrowing base of $580 million. On the Emergence Date, the Pre-Petition Revolving Credit Facility was terminated and the lenders indefeasibly converted into the Exit Credit Facility. Each holder of an allowed claim under the Pre-Petition Revolving Credit Facility received, in full and final satisfaction, settlement, release, and discharge of, and in exchange for, each Allowed DIP Claim its Pro Rata share of participation in the Exit Credit Facility.

Predecessor Senior Notes

On the Emergence Date, all outstanding obligations under the Predecessor Senior Notes were cancelled in accordance with the Plan and each holder of an allowed unsecured notes claim received their pro-rata share of 19.7 million shares of New Common Stock and $550 million of the Successor Senior Notes.

Predecessor Building Loan

In June 2015, the Company entered into a loan for the construction of the Company's corporate headquarters in Oklahoma City, which was substantially completed in December 2016. On the Emergence Date, ownership of the Company's corporate headquarters reverted to the Building Loan lender and the Company entered into a short-term lease agreement for the headquarters with the lender. As a result, the building loan liability was discharged as of the Emergence Date.

Capitalization of Interest

The Company capitalized approximately $0.1 million of interest expense for the Current Successor YTD Period related to its unevaluated oil and natural gas properties. The Company did not capitalize interest expense for the Current Predecessor YTD Period. The Company capitalized approximately $0.2 million and $0.9 million in interest expense during the Prior Predecessor Quarter and the Prior Predecessor YTD Period, respectively.

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Fair Value of Debt

At September 30, 2021, the carrying value of the outstanding debt represented by the Successor Senior Notes was $548.9 million. Based on the quoted market prices (Level 1), the fair value of the Successor Senior Notes was determined to be $601.4 million at September 30, 2021.

6.EQUITY

As discussed in Note 2, the Company filed an amended and restated certificate of incorporation with the Delaware Secretary of State on the Emergence Date to provide for, among other things, (i) the authority to issue 42 million shares of New Common Stock with a par value of $0.0001 per share and (ii) the designation of 110,000 shares of New Preferred Stock, with a par value of $0.0001 per share and a liquidation preference of $1,000 per share.

New 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 New Common Stock and 1.7 million shares of New Common Stock were issued to the Disputed Claims reserve.

New Preferred Stock

On the Emergence Date, the Successor issued 55,000 shares of New Preferred Stock.

Holders of New 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 New Preferred Stock (“PIK Dividends”). Gulfport must pay PIK Dividends for so long as the quotient obtained by dividing (i) Total Net Funded Debt (as defined in the Exit Credit Facility) by (ii) the last twelve (12) months of EBITDAX (as defined in the Exit Credit Facility) calculated as at the applicable record date is equal to or greater than 1.50. If such ratio is less than 1.50 such dividend may be paid in either cash or as PIK Dividends, subject to certain conditions under the Company's credit agreement. This requirement with respect to PIK Dividends is no longer applicable upon the effective date of the New Credit Facility.

Each holder of shares of New 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 New 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 New Preferred Stock outstanding at September 30, 2021 would convert to 4.1 million shares of New Common Stock if all holders of New 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 New Preferred Stock by notice to the holders of New Preferred Stock, at the greater of (i) the aggregate value of the New 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 New 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 New Preferred Stock by cash payment of the Redemption Price per share of New 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 New Preferred Stock, the Company is required to redeem a pro rata portion of each holder’s shares of New Preferred Stock.

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The New Preferred Stock has no stated maturity and will remain outstanding indefinitely unless repurchased or redeemed by Gulfport or converted into Common Stock.

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

Dividends

On September 30, 2021, the company paid dividends on its New Preferred Stock, which included 2,065 shares of New Preferred Stock paid in kind and approximately $30 thousand of cash-in-lieu of fractional shares. The following table summarizes PIK dividends and conversions of the Company’s New Preferred Stock subsequent to the Emergence Date:


New Preferred Stock at May 18, 2021 (Successor)						55,000
Issuance of New Preferred Stock						1,006
Conversion of New Preferred Stock						(146)
New Preferred Stock at June 30, 2021						55,860
Issuance of New Preferred Stock						2,065
Conversion of New Preferred Stock						(5)
New Preferred Stock at September 30, 2021						57,920

7.STOCK-BASED COMPENSATION

As discussed in Note 2, on the Emergence Date, the Company's Predecessor common stock was cancelled and New Common Stock was issued. Accordingly, the Company's then existing stock-based compensation awards were also cancelled, which resulted in the recognition of previously unamortized expense of $4.4 million related to the cancelled awards on the date of cancellation, which was included in reorganization items, net on the accompanying consolidated statements of operations. Stock-based compensation for the Predecessor and Successor periods are not comparable.

Successor Stock-Based Compensation

As of the Emergence Date, the board of directors adopted the Incentive Plan with a share reserve equal to 2,828,123 shares of New 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 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 $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.

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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 May 18, 2021	—	$	—	—	$	—
Granted	198,755	65.92		141,697	47.67
Vested	—	—		—	—
Forfeited/canceled	—	—		—	—
Unvested shares as of September 30, 2021	198,755	$	65.92	141,697	$	47.67

Successor Restricted Stock Units

Restricted stock units awarded under the Incentive Plan generally vest over a period of 1 to 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, 2021 was $12.2 million. The expense is expected to be recognized over a weighted average period of 3.05 years.

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 performance period from May 17, 2021 to May 17, 2024, subject to earlier termination of the performance period in the event of a change in control. The grant date fair value was determined using the Monte Carlo simulation method and is being recorded ratably over the performance period. Expected volatilities utilized in the Monte Carlo model were estimated using a historical period consistent with the remaining performance period of approximately 3 years. The risk-free interest rate was based on the U.S. Treasury rate for a term commensurate with the expected life of the grant. The Company assumed a risk-free interest rate of 0.35% and expected volatility of 87.0% to estimate the fair value. Unrecognized compensation expense as of September 30, 2021, related to performance vesting restricted shares was $6.3 million. The expense is expected to be recognized over a weighted average period of 2.8 years.

Predecessor Stock-Based Compensation

The Company granted restricted stock units to employees and directors pursuant to the 2019 Amended and Restated Incentive Stock Plan ("2019 Plan"). During the Current 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. During the Prior Predecessor Quarter and the Prior Predecessor YTD Period, the Company’s stock-based compensation cost was $8.9 million and $13.2 million, respectively, of which the Company capitalized $0.3 million and $2.2 million, respectively, 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.

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The following table summarizes restricted stock unit activity for the Current 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.

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.

8.EARNINGS (LOSS) PER SHARE

Basic income or loss per share attributable to common stockholders is computed as (i) net income or loss less (ii) dividends paid to holders of New 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 New 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 YTD Period, Current Successor Quarter, Current Predecessor Quarter or the Current Predecessor YTD Period. There were 4.1 million shares of potential common shares issuable due to the Company's convertible New Preferred Stock that were considered anti-dilutive for the Current Successor YTD Period due to the Company's net loss. There were 0.1 million shares of restricted stock that were considered anti-dilutive during the Current Successor Quarter and Current Successor YTD Period due to the Company's net loss.

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


	Successor		Predecessor
	Three Months Ended September 30, 2021		Three Months Ended September 30, 2020

Net loss	$	(461,313)	$	(380,963)
Dividends on New Preferred Stock	(2,095)		—
Participating securities - New Preferred Stock(1)	—		—
Net loss attributable to common stockholders	$	(463,408)	$	(380,963)
Basic Shares	20,598		160,683
Basic and Dilutive EPS	$	(22.50)	$	(2.37)


	Successor		Predecessor
	Period from May 18, 2021 through September 30, 2021		Period from January 1, 2021 through May 17, 2021		Nine Months Ended September 30, 2020

Net (loss) income attributable to Gulfport	$	(670,898)	$	250,996	$	(1,459,569)
Dividends on New Preferred Stock	(3,126)		—		—
Participating securities - New Preferred Stock(1)	—		—		—
Net (loss) income attributable to common stockholders	$	(674,024)	$	250,996	$	(1,459,569)
Basic Shares	20,507		160,834		160,053
Basic and Dilutive EPS	$	(32.87)	$	1.56	$	(9.12)


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

9.COMMITMENTS AND CONTINGENCIES

Commitments

Future Firm Transportation and Gathering Agreements

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

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A summary of these commitments at September 30, 2021 are set forth in the table below, excluding contracts recently rejected or in the process of being rejected as discussed in the Litigation and Regulatory Proceedings section below:


	(In thousands)
Remaining 2021	$	61,609
2022	224,537
2023	222,730
2024	215,865
2025	137,116
Thereafter	977,616
Total	$	1,839,473

Future Firm Sales Commitments

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

A summary of these volume commitments at September 30, 2021 are set forth in the table below:


						(MMBtu per day)
Remaining 2021						16,000
2022						4,000

Contingencies

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

Litigation and Regulatory Proceedings

Commencement of the Chapter 11 Cases automatically stayed the proceedings and actions against us that are described below, in addition to actions seeking to collect pre-petition indebtedness or to exercise control over the property of the Company's bankruptcy estates. The Plan in the Chapter 11 Cases, which became effective on May 17, 2021, provided for the treatment of claims against the Company's bankruptcy estates, including pre-petition liabilities that had not been satisfied or addressed during the Chapter 11 Cases.

As part of its Chapter 11 Cases and restructuring efforts as discussed in Note 2, 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") or jointly as the “Pending Motions to Reject”. The Pending Motions to Reject were removed to the United States District Court for the Southern District of Texas. While the Pending Motions to Reject are litigated, the Company isn’t required to perform under these firm transportation agreements. 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

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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 and as of September 30, 2021 is presented in "Accounts payable and accrued liabilities" in the accompanying consolidated balance sheet. Gulfport expects to receive distributions for substantially all of the $43.8 million payment based on the assigned claims pursuant to Gulfport’s Chapter 11 plan of reorganization that became effective in May 2021. Any future distributions will be recognized once received by Gulfport. The Company believes that the remaining Pending Motion to Reject will be ultimately granted, and that the Company does not have any ongoing obligation pursuant to the contract; however, in the event that the Company is not permitted to reject the Rover firm transportation contract, it could be liable for demand charges, attorneys' fees and interest in excess of approximately $40 million.

The Company, along with a number of other oil and gas companies, has been named as a defendant in two separate complaints, one filed by the State of Louisiana and the Parish of Cameron in the 38th Judicial District Court for the Parish of Cameron on February 9, 2016, and the other filed by the State of Louisiana and the District Attorney for the 15th Judicial District of the State of Louisiana in the 15th Judicial District Court for the Parish of Vermilion on July 29, 2016 (together, the "Complaints"). The Complaints allege that certain of the defendants’ operations violated the State and Local Coastal Resources Management Act of 1978, as amended, and the rules, regulations, orders and ordinances adopted thereunder (the "CZM Laws") by causing substantial damage to land and waterbodies located in the coastal zone of the relevant Parish. The plaintiffs seek damages and other appropriate relief under the CZM Laws, including the payment of costs necessary to clear, re-vegetate, detoxify and otherwise restore the affected coastal zone of the relevant Parish to its original condition, actual restoration of such coastal zone to its original condition, and the payment of reasonable attorney fees and legal expenses and interest. The United States District Court for the Western District of Louisiana issued orders remanding the cases to their respective state court, and the defendants have appealed the remand orders to the 5th Circuit Court of Appeals. On September 9, 2021, the State of Louisiana and Cameron Parish dismissed all claims against Gulfport without prejudice.

In September 2019, a stockholder of Mammoth Energy filed a derivative action on behalf of Mammoth Energy against members of Mammoth Energy’s Board of Directors, including a director designated by the Company, and its significant stockholders, including the Company, in the United States District Court for the Western District of Oklahoma. The complaint alleges, among other things, that the members of Mammoth Energy’s Board of Directors breached their fiduciary duties and violated the Securities Exchange Act of 1934, as amended, in connection with Mammoth Energy’s activities in Puerto Rico following Hurricane Maria. The complaint seeks unspecified damages, the payment of reasonable attorney fees and legal expenses and interest and to force Mammoth Energy and its Board of Directors to make specified corporate governance reforms. On October 4, 2021, plaintiffs filed a stipulation and agreement of settlement to dismiss all claims against Gulfport that is pending approval by the trial court.

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 October 16, 2021, Gulfport filed a motion to dismiss that is currently pending before the trial court.

In December 2019, the Company filed a lawsuit against Stingray Pressure Pumping LLC, a subsidiary of Mammoth Energy (“Stingray”), for breach of contract and to terminate the Master Services Agreement for pressure pumping services, effective as of October 1, 2014, as amended (the “Master Services Agreement”), between Stingray and the Company. In March 2020, Stingray filed a counterclaim against the Company in the Superior Court of the State of Delaware. The counterclaim alleges that the Company has breached the Master Services Agreement. The counterclaim seeks actual damages, and Stingray filed claims in the Chapter 11 proceedings exceeding $80 million related to breach of contract damages, attorneys' fees and interest. In September 2021, Gulfport reached an agreement in principle with Stingray that fully resolves the litigation between the parties. Pursuant to the settlement, Stingray and Gulfport have agreed to drop all of the claims brought against each other in Delaware Court and Bankruptcy Court. On September 22, 2021, the parties announced to the bankruptcy court that all Stingray claims would be withdrawn. The parties are finalizing settlement documents.

In August 2020, Muskie filed an action against the Company in the Superior Court of the State of Delaware for breach of contract. The complaint alleges that the Company breached its obligation to purchase a certain amount of proppant sand each month or make designated shortfall payments under the Sand Supply Agreement, effective October 1, 2014, as amended (the “Sand Supply Agreement”), between Muskie and the Company, and seeks payment of unpaid shortfall payments, and Muskie

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filed a claim in the Chapter 11 proceedings for $3.4 million. On September 22, 2021, the parties announced to the bankruptcy court that an agreed claim for $3.1 million would resolve the matter. The parties are finalizing settlement documents.

In April 2020, Bryon Lefort, individually and on behalf of similarly situated individuals, filed an action against the Company in the United States District Court for the Southern District of Ohio Eastern Division. The complaint alleges that the Company violated the Fair Labor Standards Act (“FLSA”), the Ohio Wage Act and the Ohio Prompt Pay Act by classifying the plaintiffs as independent contractors and paying them a daily rate with no overtime compensation for hours worked in excess of 40 hours per week. The complaint seeks to recover unpaid regular and overtime wages, liquidated damages in an amount equal to six percent of all unpaid overtime compensation, the payment of reasonable attorney fees and legal expenses and pre-judgment and post-judgment interest, and such other damages that may be owed to the workers, and claims were filed in the Chapter 11 proceedings totaling $5.8 million. On October 1, 2021, the bankruptcy court approved the parties' settlement resolving all claims for a bankruptcy claim of approximately $0.7 million. Final dismissal is currently pending before the United States District Court for the Southern District of Ohio Eastern Division.

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.

Business Operations

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

Environmental Contingencies

The nature of the oil and gas business carries with it certain environmental risks for Gulfport and its subsidiaries. Gulfport and its subsidiaries have implemented various policies, programs, procedures, training and audits to reduce and mitigate environmental risks. The Company conducts periodic reviews, on a company-wide basis, to assess changes in 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.

10.DERIVATIVE INSTRUMENTS

Natural Gas, Oil and Natural Gas Liquids Derivative Instruments

Gulfport has established policies and procedures for managing commodity price volatility through the use of 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. The derivative instruments allow the Company to mitigate the impact of declines in future commodity prices by effectively locking in a floor price for a certain level of the Company’s production. However, these instruments also limit future gains from favorable price movements. The volume of commodity derivative instruments utilized by the Company may vary from year to year based on forecasted production.

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.

Below is a summary of the Company’s open fixed price swap positions as of September 30, 2021.


	Location	Daily Volume	Weighted Average Price
Natural Gas		(MMBtu/d)	($/MMBtu)
Remaining 2021	NYMEX Henry Hub	198,000	$	2.85
2022	NYMEX Henry Hub	140,740	$	2.88
2023	NYMEX Henry Hub	34,932	$	3.24

Oil		(Bbl/d)	($/Bbl)
Remaining 2021	NYMEX WTI	3,000	$	57.67
2022	NYMEX WTI	2,104	$	66.23

NGL		(Bbl/d)	($/Bbl)
Remaining 2021	Mont Belvieu C3	3,100	$	27.80
2022	Mont Belvieu C3	3,378	$	35.09

In the second half of 2019, the Company sold 2022 and 2023 natural gas call options in exchange for a premium and used the associated premiums to enhance the fixed price on certain natural gas swaps that settled in 2020. Each call option has an established ceiling price of $2.90/MMBtu. If monthly NYMEX natural gas prices settle above the $2.90/MMBtu ceiling price, the Company is required to pay the option counterparty an amount equal to the difference between the referenced NYMEX natural gas settlement price and $2.90/MMBtu multiplied by the hedged contract volumes.

Below is a summary of the Company's sold natural gas call option positions as of September 30, 2021.


	Location	Daily Volume	Weighted Average Price
Natural Gas		(MMBtu/d)	($/MMBtu)
2022	NYMEX Henry Hub	152,675	$	2.90
2023	NYMEX Henry Hub	627,675	$	2.90

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, 2021.


	Location	Daily Volume	Weighted Average Floor Price		Weighted Average Ceiling Price
Natural Gas		(MMBtu/d)	($/MMBtu)		($/MMBtu)
Remaining 2021	NYMEX Henry Hub	610,000	$	2.59	$	3.02
2022	NYMEX Henry Hub	406,747	$	2.58	$	2.91

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

In addition, the Company entered into natural gas basis swap hedge contracts. If the applicable monthly price indices are outside of the ranges set forth in the various natural gas basis swap contracts, the Company will cash-settle the difference with the hedge counterparty.

Below is a summary of the Company's natural gas basis swap positions as of September 30, 2021.

Gulfport Pays

Gulfport Receives

Daily Volume

Weighted Average Fixed Spread

Natural Gas

(MMBtu/d)

($/MMBtu)

Remaining 2021

Rex Zone 3

NYMEX Plus Fixed Spread

83,152

(0.12)

2022

Rex Zone 3

NYMEX Plus Fixed Spread

24,658

(0.10)

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, 2021 and December 31, 2020:


	Successor		Predecessor
	September 30, 2021		December 31, 2020

Short-term derivative asset	$	2,142	$	27,146
Long-term derivative asset	961		322
Short-term derivative liability	(560,722)		(11,641)
Long-term derivative liability	(272,935)		(36,604)
Total commodity derivative position	$	(830,554)	$	(20,777)

Gains and Losses

The following tables present the gain and loss recognized in net (loss) gain on natural gas, oil and NGL derivatives in the accompanying consolidated statements of operations:


	Net loss on derivative instruments
	Successor		Predecessor
	Three Months Ended September 30, 2021		Three Months Ended September 30, 2020
Natural gas derivatives - fair value losses	$	(517,799)	$	(84,390)
Natural gas derivatives - settlement (losses) gains	(82,566)		31,742
Total losses on natural gas derivatives	(600,365)		(52,648)

Oil and condensate derivatives - fair value (losses) gains	(1,590)		723
Oil and condensate derivatives - settlement losses	(4,336)		(1,505)
Total losses on oil and condensate derivatives	(5,926)		(782)

NGL derivatives - fair value losses	(10,201)		(288)
NGL derivatives - settlement losses	(5,984)		(105)
Total losses on NGL derivatives	(16,185)		(393)

Total losses on natural gas, oil and NGL derivatives	$	(622,476)	$	(53,823)


	Net (loss) gain on derivative instruments
	Successor		Predecessor
	Period from May 18, 2021 through September 30, 2021		Period from January 1, 2021 through May 17, 2021		Nine Months Ended September 30, 2020
Natural gas derivatives - fair value losses	$	(638,063)	$	(123,080)	$	(147,661)
Natural gas derivatives - settlement (losses) gains	(89,255)		(3,362)		176,555
Total (losses) gains on natural gas derivatives	(727,318)		(126,442)		28,894

Oil and condensate derivatives - fair value losses	(6,947)		(6,126)		(4,289)
Oil and condensate derivatives - settlement (losses) gains	(4,336)		—		48,444
Total (losses) gains on oil and condensate derivatives	(11,283)		(6,126)		44,155

NGL derivatives - fair value losses	(17,549)		(4,671)		(620)
NGL derivatives - settlement (losses) gains	(5,984)		—		366
Total losses on NGL derivatives	(23,533)		(4,671)		(254)

Contingent consideration arrangement - fair value losses	—		—		(1,381)
Total (losses) gains on natural gas, oil and NGL derivatives	$	(762,134)	$	(137,239)	$	71,414

Offsetting of Derivative Assets and Liabilities

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


	Successor
	As of September 30, 2021
	Gross Assets (Liabilities)		Gross Amounts
	Presented in the		Subject to Master		Net
	Consolidated Balance Sheets		Netting Agreements		Amount
Derivative assets	$	3,103	$	(3,103)	$	—
Derivative liabilities	$	(833,657)	$	3,103	$	(830,554)


	Predecessor
	As of December 31, 2020
	Gross Assets (Liabilities)		Gross Amounts
	Presented in the		Subject to Master		Net
	Consolidated Balance Sheets		Netting Agreements		Amount
Derivative assets	$	27,468	$	(25,730)	$	1,738
Derivative liabilities	$	(48,245)	$	25,730	$	(22,515)

Concentration of Credit Risk

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

11.FAIR VALUE MEASUREMENTS

The Company measures and discloses certain financial and non-financial assets and liabilities on the balance sheet at fair value in accordance with the provisions of ASC Topic 820, Fair Value Measurements and Disclosures. 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 in active markets for identical assets and liabilities.

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

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

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

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Financial assets and liabilities

The following tables summarize the Company’s financial and non-financial assets and liabilities by valuation level as of September 30, 2021 and December 31, 2020:


	Successor
	September 30, 2021
	Level 1		Level 2		Level 3
Assets:
Derivative Instruments	$	—	$	3,103	$	—
Contingent consideration arrangement	—		—		5,300
Total assets	$	—	$	3,103	$	5,300
Liabilities:
Derivative Instruments	$	—	$	833,657	$	—


	Predecessor
	December 31, 2020
	Level 1		Level 2		Level 3
Assets:
Derivative Instruments	$	—	$	27,468	$	—
Contingent consideration arrangement	—		—		6,200
Total assets	$	—	$	27,468	$	6,200
Liabilities:
Derivative Instruments	$	—	$	48,245	$	—

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. As discussed in Note 3, 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, 2021, the fair value of the contingent consideration was $5.3 million, of which $0.8 million is included in prepaid expenses and other assets and $4.5 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 a $1.2 million loss for the Current Successor Quarter, a $0.1 million loss for the Current Successor YTD Period, and a nominal gain for the Current Predecessor YTD Period, respectively, which is included in other expense (income) in the accompanying consolidated statements of operations. The Company recognized losses of $0.2 million and $3.1 million on changes in fair value of the contingent consideration during the Prior Predecessor Quarter and Prior Predecessor YTD Period, respectively. Settlements under the contingent consideration arrangement totaled $0.6 million during the Current Successor YTD Period, $0.2 million during the Current Predecessor YTD Period, and $0.3 million during the Prior Predecessor YTD Period, respectively.

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 4 for further discussion of the Company’s asset retirement obligations.

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As discussed in Note 4, the Company recorded an impairment during the Current Predecessor YTD Period on its corporate headquarters. The estimated fair value of the building was primarily based on third party estimates and, therefore, is deemed to use Level 3 inputs.

Fair value of other financial instruments

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

Chapter 11 Emergence and Fresh Start Accounting

On the Emergence Date, the Company adopted fresh start accounting, which resulted in the Company becoming a new entity for financial reporting purposes. Upon the adoption of fresh start accounting, the Company’s assets and liabilities were recorded at their fair values as of May 17, 2021. The inputs utilized in the valuation of the Company’s most significant asset, its oil and natural gas properties and related assets, included mostly unobservable inputs which fall within Level 3 of the fair value hierarchy. Such inputs included estimates of future oil and gas production from the Company’s reserve reports, commodity prices based on forward strip price curves (adjusted for basis differentials) as of May 17, 2021, operating and development costs, expected future development plans for the properties and discount rates based on a weighted-average cost of capital computation. The Company also recorded its asset retirement obligations at fair value as a result of fresh start accounting. The inputs utilized in valuing the asset retirement obligations were mostly Level 3 unobservable inputs, including estimated economic lives of oil and natural gas wells as of the Emergence Date, anticipated future plugging and abandonment costs and an appropriate credit-adjusted risk free rate to discount such costs. Refer to Note 3 for a detailed discussion of the fair value approaches used by the Company.

12.REVENUE FROM CONTRACTS WITH CUSTOMERS

Revenue Recognition

The Company’s revenues are primarily derived from the sale of natural gas, oil and condensate and NGL. Sales of natural gas, oil and condensate and NGL are recognized in the period that the performance obligations are satisfied. The Company generally considers the delivery of each unit (MMBtu or Bbl) to be separately identifiable and represents a distinct performance obligation that is satisfied at the time control of the product is transferred to the customer. Revenue is measured based on consideration specified in the contract with the customer, and excludes any amounts collected on behalf of third parties. These contracts typically include variable consideration that is based on pricing tied to market indices and volumes delivered in the current month. As such, this market pricing may be constrained (i.e., not estimable) at the inception of the contract but will be recognized based on the applicable market pricing, which will be known upon transfer of the goods to the customer. The payment date is usually within 30 days of the end of the calendar month in which the commodity is delivered.

Gathering, processing and compression fees attributable to gas processing, as well as any transportation fees, including firm transportation fees, incurred to deliver the product to the purchaser, are presented as transportation, gathering, processing and compression expense in the accompanying consolidated statements of operations.

Transaction Price Allocated to Remaining Performance Obligations

A significant number of the Company's product sales are short-term in nature generally through evergreen contracts with contract terms of one year or less. These contracts typically automatically renew under the same provisions. For those contracts, the Company has utilized the practical expedient allowed in the new 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

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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 $185.9 million and $119.9 million as of September 30, 2021 and December 31, 2020, respectively, and are reported in accounts receivable - oil and natural gas 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 the Current Predecessor YTD Period and the Current Successor YTD Period, revenue recognized in the reporting periods related to performance obligations satisfied in prior reporting periods was not material.

13.EQUITY INVESTMENTS

Investments accounted for by the equity method during the periods presented consisted of the following:


	Carrying value		Loss from equity method investments
	Predecessor		Predecessor
	December 31, 2020		Three Months Ended September 30, 2020		Period from January 1, 2021 through May 17, 2021		Nine Months Ended September 30, 2020
Investment in Grizzly Oil Sands ULC	$	24,816	$	(153)	$	(342)	$	(341)
Investment in Mammoth Energy	—		—		—		(10,646)

	$	24,816	$	(153)	$	(342)	$	(10,987)

Grizzly Oil Sands ULC

The Company, through its wholly owned subsidiary Grizzly Holdings, owns an approximate 24.5% interest in Grizzly, a Canadian unlimited liability company. As of September 30, 2021, Grizzly had approximately 830,000 acres under lease in the Athabasca, Peace River and Cold Lake oil sands regions of Alberta, Canada. The Company has not paid any cash calls since its decision to cease funding further capital calls in 2019. Grizzly’s functional currency is the Canadian dollar. For the Prior Predecessor Quarter and the Prior Predecessor YTD Period, the Company's investment in Grizzly increased by $3.7 million and decreased by $4.1 million, respectively, as a result of foreign currency translation gains and losses.

Effective as of the Emergence Date, the Company evaluated its investment in Grizzly and determined that the Company no longer has the ability to exercise significant influence over operating and financial policies of Grizzly. As such, the equity method of accounting for its investment was no longer applicable. As a result, the Company will use its previous carrying value of zero (as discussed below) as its initial basis and will subsequently measure at fair value while recording any changes in fair value in earnings.

As discussed in Note 3, the Company reduced the carrying value of its investment in Grizzly to zero upon the Emergence Date. The reduction in valuation was based upon the Company's new management's assessment of the investment and its priority for future funding in its portfolio. In particular, Grizzly’s operations remained suspended, even with improvements in the pricing environment since its initial suspension in 2015. Additionally, the Company does not anticipate funding future capital calls, which will lead to further dilution of its equity ownership interest.

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Mammoth Energy Services, Inc.

As discussed in Note 2, the Company's previously owned shares of the outstanding common stock of Mammoth Energy were used to settle Class 4A claims. The Company's investment carrying value was reduced to zero in the first quarter of 2020 due to the Company's share of cumulative net loss and impairments and the carrying value remained at zero through the Emergence Date.

14.RESTRUCTURING AND LIABILITY MANAGEMENT

In the third quarter of 2021, the Company announced and completed a workforce reduction representing approximately 3% of its headcount. Charges related to the reduction in workforce primarily consisted of one-time employee-related termination benefits. Additionally, the Company incurred charges related to financial and legal advisors engaged to assist with the evaluation of a range of liability management alternatives during the Prior Predecessor Quarter and Prior Predecessor YTD Period.

The following table summarizes the restructuring and liability management charges incurred:


	Successor		Predecessor
	Three months ended September 30, 2021		Three months ended September 30, 2020
Reduction in workforce	$	2,858	$	1,460
Liability management	—		7,524
Total restructuring and liability management	$	2,858	$	8,984


	Successor		Predecessor
	Period from May 18, 2021 through September 30, 2021		Period from January 1, 2021 through May 17, 2021		Nine months ended September 30, 2020
Reduction in workforce	$	2,858	$	—	$	1,460
Liability management	—		—		8,141
Total restructuring and liability management	$	2,858	$	—	$	9,601

15.LEASES

Nature of Leases

The Company has operating leases on certain equipment and field offices 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 with varying terms for drilling rigs. 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, 2021, the Company did not have any active long-term drilling rig contracts in place.

The Company rents office space for its corporate headquarters and field locations and certain other equipment from third parties, which expire at various dates through 2022. 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. The lease for the Company's corporate headquarters has a primary term of one year and is classified as a short-term operating lease.

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

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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.

Maturities of operating lease liabilities as of September 30, 2021 were as follows:


	(In thousands)
Remaining 2021	$	10
2022	25



Total lease payments	$	35
Less: Imputed interest	(1)
Total	$	34

The table below summarizes lease cost for the periods presented:


	Successor		Predecessor
	Three Months Ended September 30, 2021		Three Months Ended September 30, 2020
Operating lease cost	$	10	$	1,692

Variable lease cost	—		245

Short-term lease cost	2,873		2,259
Total lease cost(1)	$	2,883	$	4,196


	Successor		Predecessor
	Period from May 18, 2021 through September 30, 2021		Period from January 1, 2021 through May 17, 2021		Nine Months Ended September 30, 2020
Operating lease cost	$	18	$	41	$	7,970

Variable lease cost	—		—		705

Short-term lease cost	5,033		4,496		7,698
Total lease cost(1)	$	5,051	$	4,537	$	16,373


(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:


	Successor		Predecessor
	Period from May 18, 2021 through September 30, 2021		Period from January 1, 2021 through May 17, 2021		Nine Months Ended September 30, 2020
Cash paid for amounts included in the measurement of lease liabilities
Operating cash flows from operating leases	$	46	$	48	$	109
Investing cash flow from operating leases	—		—		9,786
Investing cash flow from operating leases—related party	—		—		6,800

The weighted-average remaining lease term as of September 30, 2021 was 0.89 years. The weighted-average discount rate used to determine the operating lease liability as of September 30, 2021 was 3.98%.

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16.INCOME TAXES

As discussed in Note 2, 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 is approximately $708.8 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. As of September 30, 2021, the Company had an estimated federal net operating loss carryforward of approximately $1.2 billion after giving effect to the estimated reduction in tax attributes as discussed above.

Emergence from Chapter 11 bankruptcy proceedings resulted in a change in ownership for purposes of IRC Section 382. The Company currently expects to apply rules under IRC Section 382(l)(5) that would 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. Taxpayers who qualify for this provision may, at their option, elect not to apply the election. If the provision does not apply, the Company’s ability to realize the value of its tax attributes would be subject to limitation and the amount of deferred tax assets and liabilities, prior to the valuation allowance, may differ. 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.

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 both May 17, 2021 and September 30, 2021.

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.

For the Current Predecessor YTD Period, the Company has an effective tax rate of (3.4)% and an income tax benefit of $8.0 million. The tax benefit is entirely attributable to an Oklahoma refund claim associated with an examination relating to historical tax returns. The effective tax rate differs from the statutory tax rate due to the Company’s valuation allowance position and the permanent adjustments relating to the Chapter 11 Emergence. For the Current Successor YTD Period, the Company has an effective tax rate of (0.01)% and tax expense of $0.7 million. The tax expense is entirely attributable to the Oklahoma refund claim that was filed during the third quarter of 2021, resulting in an adjustment to the benefit recorded during the Current Predecessor YTD Period. We did not record any additional income tax expense for the Current Successor YTD Period as a result of maintaining a full valuation allowance against our net deferred tax asset. For the Prior Predecessor Quarter, the Company had an effective tax rate of 0% and tax expense of zero due to the Company’s valuation allowance position. For the Prior Predecessor YTD Period, the Company had an effective tax rate of (0.5)% and tax expense of $7.3 million as a result of the sale of assets and a corresponding adjustment to the valuation allowance on remaining state net operating loss carryforwards.

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17.SUBSEQUENT EVENTS

New 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 ("New Credit Facility"). The New 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. The New Credit Facility amended and refinanced the Exit Credit Facility.

The borrowing base will be redetermined semiannually on or around May 1 and November 1 of each year, with the first scheduled redetermination to be on or around May 1, 2022. The New Credit Facility matures in October 2025.

The New Credit Facility bears interest at a rate equal to, at the Company’s election, either (a) LIBOR 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 New Credit Facility will mature on October 14, 2025. 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 New Credit Facility. The Company is also required to pay customary letter of credit and fronting fees.

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 New 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.

Share Repurchase Program

On November 1, 2021, the Company's Board of Directors approved a stock repurchase program to acquire up to $100.0 million of its New Common Stock ("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 New Common Stock. The Company intends to purchase shares under the Repurchase Program opportunistically with available funds while maintaining sufficient liquidity to fund its capital development program. The Repurchase Program is authorized to extend through December 31, 2022 and may be suspended from time to time, modified, extended or discontinued by the board of directors at any time. Any shares of New Common Stock repurchased are expected to be cancelled.

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Natural Gas and Oil Derivative Instruments

Subsequent to September 30, 2021 and as of October 28, 2021, the Company entered into the following natural gas derivative contracts:

Type of Derivative Instrument

Index

Daily Volume

Weighted
Average Price

Natural Gas

(MMBtu/d)

($/MMBtu)

November 2021 - December 2021

Basis Swap

ONG Minus Inside FERC

20,000

$0.50

January 2022 - March 2022

Basis Swap

ONG Minus Inside FERC

20,000

$0.50

January 2023 - December 2023

Fixed price swap

NYMEX Henry Hub

30,000

$3.58

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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, 2020 (“2020 Form 10-K”), and analyzes the changes in the results of operations between the periods of May 18, 2021 through September 30, 2021 (“Current Successor YTD Period”), January 1, 2021, through May 17, 2021 (“Current Predecessor YTD Period”), the three months ended September 30, 2021 ("Current Successor Quarter"), the three months ended September 30, 2020 (“Prior Predecessor Quarter”) and the nine months ended September 30, 2020 ("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 2020 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 formation and in central Oklahoma targeting the SCOOP Woodford and SCOOP Springer formations. Our strategy is to develop our assets in a manner that generates sustainable cash flow and improves margins and operating efficiencies, while improving our Environmental, Social and Governance ("ESG") and safety performance. 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. We believe our plan to generate free cash flow on an annual basis will allow us to further strengthen our balance sheet and ultimately return capital to shareholders.

Our results of operations as reported in our consolidated financial statements for the Current Successor Quarter, Current Successor YTD Period, and the Current Predecessor YTD Period are in accordance with GAAP. Although GAAP requires that we report on our results for these periods separately, management views our operating results for the nine months ended September 30, 2021 by combining the results of the Current Successor YTD Period and the Current Predecessor YTD Period ("Current Combined YTD Period") because management believes such presentation provides the most meaningful comparison of our results to prior periods. We do not believe reviewing these periods in isolation would be useful in identifying any trends in or reaching any conclusions regarding our overall operating performance. We believe the key performance indicators such as operating revenues and operating expenses for the Current Successor YTD Period combined with the Current Predecessor YTD Period provide more meaningful comparisons to other periods and are useful in understanding operational trends. Additionally, there were no changes in policies between the periods and any material impacts as a result of fresh start accounting were included within the discussion of these changes. These combined results do not comply with GAAP and have not been prepared as pro forma results under applicable regulations, but are presented because we believe they provide the most meaningful comparison of our results to prior periods.

Recent Developments

Emergence from voluntary reorganization under Chapter 11

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

Although we are no longer a debtor-in-possession, we operated as debtors-in-possession through the pendency of the Chapter 11 Cases. See Note 1 and Note 2 of the notes to our consolidated financial statements included in Item 1 of Part I of this report for a complete discussion of the Chapter 11 Cases.

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We believe we have emerged from the Chapter 11 Cases as a fundamentally stronger company, built to generate sustainable free cash flow with a strengthened balance sheet. As a result of the Chapter 11 Cases, we reduced our total indebtedness by $1.4 billion by issuing equity in a reorganized entity to the holders of our unsecured notes and allowed general unsecured claimants.

Chief Executive Officer

On September 2, 2021, we reached agreement with Timothy Cutt, effective immediately, to fully assume the role of Chief Executive Officer, dropping the "Interim" designation from his title.

New Credit Facility

On October 14, 2021, we entered into the New Credit Facility 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 New Credit Facility amends and refinances the Exit Credit Facility. See Note 17 for additional discussion of the New Credit Facility.

Share Repurchase Program

On November 1, 2021, our board of directors has approved a stock Repurchase Program to acquire up to $100.0 million of our outstanding New Common Stock. 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 us to acquire any specific number of shares of New Common Stock. We intend to purchase shares under the Repurchase Program opportunistically with available funds while maintaining sufficient liquidity to fund our capital development program. The Repurchase Program is authorized to extend through December 31, 2022 and may be suspended from time to time, modified, extended or discontinued by the board of directors at any time. Any shares of New Common Stock repurchased are expected to be cancelled.

COVID-19 Pandemic and Impact on Global Demand for Oil and Natural Gas

As a result of our business continuity measures, we have not experienced significant disruptions in executing our business operations due to COVID-19. While we did not experience significant disruptions to our operations in the first nine months of 2021, we are unable to predict the impact on our business, including our cash flows, liquidity, and results of operations in future periods due to numerous uncertainties. Restrictions may cause us, our suppliers and other business counterparties to experience operational delays, or delays in the delivery of materials and supplies. We expect the principal areas of operational risk for us are the availability and reliability of service providers and potential supply chain disruption. Additionally, the operations of our midstream service providers, on whom we rely for the transmission, gathering and processing of a significant portion of our produced natural gas, NGL and oil, may be disrupted or suspended in response to containing the outbreak, or the difficult economic environment may lead to the bankruptcy or closing of the facilities and infrastructure of our midstream service providers. This may result in substantial discount in the prices we receive for our produced natural gas, NGL and oil or result in the shut-in of producing wells or the delay or discontinuance of development plans for our properties.

We cannot predict the full impact that COVID-19 or the significant disruption and volatility currently being experienced in the oil and natural gas markets will have on our business, cash flows, liquidity, financial condition and results of operations at this time, due to numerous uncertainties. The ultimate impacts will depend on future developments and the timing and extent to which normal economic and operating conditions resume.

2021 Operational and Financial Highlights

During the third quarter of 2021, we had the following notable achievements:

•In September 2021, we finalized a settlement agreement with TC Energy Corporation ("TC") which rejected the firm transportation contracts between us and TC without any further payment or obligation by us or TC. As a result of the settlement agreement, TC assigned its damages claims from such rejection to us. In exchange, we agreed to make a payment of $43.8 million in cash to TC. We expect to recover all, or substantially all, of such amount through future

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distributions with respect to the assigned claims, with a material portion expected to be received in the next twelve months.

•In September 2021, we also reached an agreement in principle with Stingray Pressure Pumping LLC that fully resolves the longstanding litigation between the parties.

•In September 2021, we completed the six-well Angelo pad in the Utica. In early October 2021, we brought the pad online at a combined gross production rate of 250 MMcfe per day.

•On October 14, 2021, we amended and refinanced our Exit Credit Facility with the New Credit Facility. The amendment increased our elected commitment from $580 million to $700 million and increased our liquidity by more than $160 million.

2021 Production and Drilling Activity

Production Volumes


	Successor	Predecessor
	Three Months Ended September 30, 2021	Three Months Ended September 30, 2020
Natural gas (Mcf/day)
Utica	678,154	763,387
SCOOP	188,292	139,233
Other	—	40
Total	866,446	902,660
Oil and condensate (Bbl/day)
Utica	958	1,579
SCOOP	4,335	3,204
Other	78	57
Total	5,371	4,840
NGL (Bbl/day)
Utica	2,516	2,917
SCOOP	9,918	7,128
Other	—	2
Total	12,434	10,047
Combined (Mcfe/day)
Utica	698,998	790,363
SCOOP	273,812	201,227
Other	471	393
Total	973,281	991,983

Our total net production averaged approximately 973.3 MMcfe per day during the Current Successor Quarter, as compared to 992.0 MMcfe per day during the Prior Predecessor Quarter. The 2% decrease in production is largely the result of a decrease in the Utica due to timing of development activity in 2021 compared to the Prior Predecessor Quarter. We anticipate an increase in total net production during the fourth quarter of 2021 driven by our six-well Angelo development in the Utica turning to sales.

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	Successor	Predecessor	Non-GAAP Combined	Predecessor
	Period from May 18, 2021 through September 30, 2021	Period from January 1, 2021 through May 17, 2021	Nine Months Ended September 30, 2021	Nine Months Ended September 30, 2020
Natural gas (Mcf/day)
Utica	682,596	780,791	731,873	774,705
SCOOP	190,305	126,294	158,182	152,595
Other	38	63	51	44
Total	872,939	907,148	890,106	927,344
Oil and condensate (Bbl/day)
Utica	1,012	1,336	1,175	829
SCOOP	4,493	2,508	3,497	4,185
Other	76	35	55	73
Total	5,581	3,879	4,727	5,087
NGL (Bbl/day)
Utica	2,588	2,638	2,613	2,882
SCOOP	9,645	6,200	7,916	8,167
Other	—	3	2	1
Total	12,233	8,841	10,531	11,050
Combined (Mcfe/day)
Utica	704,196	804,633	754,598	796,972
SCOOP	275,134	178,545	226,662	226,705
Other	498	288	392	488
Total	979,828	983,466	981,653	1,024,165

Our total net production averaged approximately 981.7 MMcfe per day during the Current Combined YTD Period, as compared to 1,024.2 MMcfe per day during the Prior Predecessor YTD Period. The 4% decrease in production is largely the result of a decrease in development activity in the Utica due to timing of development activity in 2021 when compared to the Prior Predecessor YTD Period.

Utica. We spud 12 gross (11.6 net) wells in the Utica during the Current Combined YTD Period, of which four were producing, two were being drilled, and six were in various stages of operations at September 30, 2021. In addition, we completed 11 gross and net operated wells. We did not participate in any additional wells that were drilled by other operators on our Utica acreage.

As of October 28, 2021, we had two operated drilling rigs running in the Utica, which we expect will continue through the remainder of 2021.

SCOOP. We spud four gross (3.9 net) wells in the SCOOP during the Current Combined YTD Period, of which one was being drilled and three were waiting on completion. In addition, we completed 11 gross (9.3 net) operated wells. We also participated in an additional 15 gross (1.6 net) wells that were drilled by other operators on our SCOOP acreage.

As of October 28, 2021, we had one operated drilling rig running in the SCOOP. We expect to add one operated drilling rig in the SCOOP in the fourth quarter of 2021.

RESULTS OF OPERATIONS

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Current Successor Quarter Compared to Prior Predecessor Quarter

Natural Gas, Oil and NGL Production and Pricing

The following table summarizes our oil and condensate, natural gas and NGL production and related pricing for the Current Successor Quarter as compared to the Prior Predecessor Quarter: Some totals throughout below sections may not sum or recalculate due to rounding.


	Successor		Predecessor
	Three Months Ended September 30, 2021		Three Months Ended September 30, 2020
Natural gas sales
Natural gas production volumes (MMcf)	79,713		83,045
Natural gas production volumes (MMcf/d)	866		903
Total sales	$	301,516	$	155,163
Average price without the impact of derivatives ($/Mcf)	$	3.78	$	1.87
Impact from settled derivatives ($/Mcf)	$	(1.04)	$	0.38
Average price, including settled derivatives ($/Mcf)	$	2.74	$	2.25

Oil and condensate sales
Oil and condensate production volumes (MBbl)	494		445
Oil and condensate production volumes (MBbl/d)	5		5
Total sales	$	33,279	$	16,012
Average price without the impact of derivatives ($/Bbl)	$	67.37	$	35.96
Impact from settled derivatives ($/Bbl)	$	(8.77)	$	(3.38)
Average price, including settled derivatives ($/Bbl)	$	58.60	$	32.58

NGL sales
NGL production volumes (MBbl)	1,144		924
NGL production volumes (MBbl/d)	12		10
Total sales	$	45,153	$	18,824
Average price without the impact of derivatives ($/Bbl)	$	39.47	$	20.37
Impact from settled derivatives ($/Bbl)	$	(5.23)	$	—
Average price, including settled derivatives ($/Bbl)	$	34.24	$	20.37

Natural gas, oil and condensate and NGL sales
Natural gas equivalents (MMcfe)	89,542		91,262
Natural gas equivalents (MMcfe/d)	973		992
Total sales	$	379,948	$	189,999
Average price without the impact of derivatives ($/Mcfe)	$	4.24	$	2.08
Impact from settled derivatives ($/Mcfe)	$	(1.04)	$	0.33
Average price, including settled derivatives ($/Mcfe)	$	3.20	$	2.41

Production Costs:
Average lease operating expenses ($/Mcfe)	$	0.15	$	0.15
Average taxes other than income ($/Mcfe)	$	0.13	$	0.07
Average transportation, gathering, processing and compression ($/Mcfe)	$	0.94	$	1.21
Total lease operating expenses, midstream costs and taxes other than income ($/Mcfe)	$	1.22	$	1.43

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Natural Gas, Oil and NGL Sales


	Successor		Predecessor
	Three Months Ended September 30, 2021		Three Months Ended September 30, 2020
Natural gas	$	301,516	$	155,163
Oil and condensate	33,279		16,012
NGL	45,153		18,824
Natural gas, oil and NGL sales	$	379,948	$	189,999

The increase in natural gas sales without the impact of derivatives when comparing the Current Successor Quarter to the Prior Predecessor Quarter was due to a 102% increase in realized natural gas prices, partially offset by a 4% decrease in sales volumes. The realized price change was driven by the significant increase in the average Henry Hub gas index from $1.98 per Mcf in the Prior Predecessor Quarter to $4.01 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 Predecessor Quarter was due to an 87% increase in realized prices combined with an 11% increase in sales volumes. The realized price change was driven by the significant increase in the average WTI crude index from $40.77 per barrel in the Prior Predecessor Quarter to $70.56 per barrel during the Current Successor Quarter.

The increase in NGL sales without the impact of derivatives when comparing the Current Successor Quarter to the Prior Predecessor Quarter was due to a 94% increase in realized prices combined with a 24% increase in NGL sales volumes. The realized price change was driven by the significant increase in the average Mont Belvieu NGL index from $15.70 per barrel in the Prior Predecessor Quarter to $42.84 per barrel during the Current Successor Quarter.

Natural Gas, Oil and NGL Derivatives


	Successor		Predecessor
	Three Months Ended September 30, 2021		Three Months Ended September 30, 2020
Natural gas derivatives - fair value losses	$	(517,799)	$	(84,390)
Natural gas derivatives - settlement (losses) gains	(82,566)		31,742
Total losses on natural gas derivatives	(600,365)		(52,648)

Oil and condensate derivatives - fair value (losses) gains	(1,590)		723
Oil and condensate derivatives - settlement losses	(4,336)		(1,505)
Total losses on oil and condensate derivatives	(5,926)		(782)

NGL derivatives - fair value losses	(10,201)		(288)
NGL derivatives - settlement losses	(5,984)		(105)
Total losses on NGL derivatives	(16,185)		(393)


Total losses on natural gas, oil and NGL derivatives	$	(622,476)	$	(53,823)

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 losses compared to the Prior Predecessor Quarter result from the increase in both realized and futures pricing for oil, natural gas, and NGL. See Note 10 for hedged volumes and pricing.

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Lease Operating Expenses


	Successor		Predecessor
	Three Months Ended September 30, 2021		Three Months Ended September 30, 2020
Lease operating expenses
Utica	$	9,309	$	10,284
SCOOP	4,527		3,226
Other	28		(117)
Total lease operating expenses	$	13,864	$	13,393

Lease operating expenses per Mcfe
Utica	$	0.14	$	0.14
SCOOP	0.18		0.17
Other	0.65		(3.16)
Total lease operating expenses per Mcfe	$	0.15	$	0.15

LOE and LOE per Mcfe for the Current Successor Quarter were consistent compared to the Prior Predecessor Quarter.

Taxes Other Than Income


	Successor		Predecessor
	Three Months Ended September 30, 2021		Three Months Ended September 30, 2020
Production taxes	$	8,822	$	4,028
Property taxes	2,309		1,881
Other	713		193
Total taxes other than income	$	11,844	$	6,102
Total taxes other than income per Mcfe	$	0.13	$	0.07

The increase in total and per unit production taxes was primarily related to the significant increase in revenues and realized prices.

Transportation, Gathering, Processing and Compression


	Successor		Predecessor
	Three Months Ended September 30, 2021		Three Months Ended September 30, 2020
Transportation, gathering, processing and compression	$	84,435	$	110,567
Transportation, gathering, processing and compression per Mcfe	$	0.94	$	1.21

The decrease in total and per unit transportation, gathering, processing and compression was primarily related to savings associated with rejected midstream contracts and renegotiation through the bankruptcy process. Additionally, total costs decreased as a result of our 2% decrease in production.

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Depreciation, Depletion and Amortization


	Successor		Predecessor
	Three Months Ended September 30, 2021		Three Months Ended September 30, 2020
Depreciation, depletion and amortization of oil and gas properties	$	61,922	$	49,120
Depreciation, depletion and amortization of other property and equipment	651		2,431
Total Depreciation, depletion and amortization	$	62,573	$	51,551
Depreciation, depletion and amortization per Mcfe	$	0.70	$	0.56

The increase in depreciation, depletion and amortization of our oil and gas properties for the Current Successor Quarter compared to the Prior Predecessor Quarter is primarily the result of an increase in our depletion rate as a result of the fresh start valuations on our oil and gas properties. See Note 3 for more information on our fresh start valuation adjustments.

Impairment of Oil and Gas Properties

We did not record an impairment charge of our oil and gas properties during the Current Successor Quarter. We recorded a $270.9 million impairment charge of our oil and gas properties during the Prior Predecessor Quarter primarily as a result of the decline in the twelve month trailing first of month average price for natural gas, oil and NGLs.

General and Administrative Expenses


	Successor		Predecessor
	Three Months Ended September 30, 2021		Three Months Ended September 30, 2020
General and administrative expenses, gross	$	24,951	$	29,171
Reimbursed from third parties	(3,182)		(2,656)
Capitalized general and administrative expenses	(5,078)		(6,184)
General and administrative expenses, net	$	16,691	$	20,331

General and administrative expenses, net per Mcfe	$	0.19	$	0.22

The decrease in general and administrative expenses for the Current Successor Quarter compared to the Prior Predecessor Quarter was primarily driven by retention payments made in 2020 and our continued focus on the workforce and leadership structure to align to our current operating environment.

Restructuring and Liability Management

During the Current Successor Quarter and Prior Predecessor Quarter, we incurred restructuring charges related to reductions in workforce as we continued to align our workforce and leadership structure to our current operating environment. Additionally, during the Prior Predecessor Quarter, we incurred liability management charges related to legal advisors engaged to assist with the evaluation of a range of liability management alternatives prior to our ultimate Chapter 11 filing.

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The following table summarizes the restructuring and liability management charges incurred:


	Successor		Predecessor
	Three months ended September 30, 2021		Three months ended September 30, 2020
Reduction in workforce	$	2,858	$	1,460
Liability management	—		7,524
Total restructuring and liability management	$	2,858	$	8,984

Interest Expense


	Successor		Predecessor
	Three Months Ended September 30, 2021		Three Months Ended September 30, 2020
Interest expense on Predecessor Senior Notes	$	—	$	28,134
Interest expense on Pre-Petition Revolving Credit Facility	—		4,280
Interest expense on building loan and other	(60)		459
Capitalized interest	(117)		(196)
Amortization of loan costs	594		1,644
Interest on DIP Credit Facility	—		—
Interest on Exit Facility	2,458		—
Interest on First-Out Term Loan	2,427		—
Interest on Successor Senior Notes	11,049		—
Total interest expense	$	16,351	$	34,321

Interest expense per Mcfe	$	0.18	$	0.38

The decrease in interest expense when comparing the Current Successor Quarter to the Prior Predecessor Quarter was due the changes in our debt structure upon emergence from Chapter 11. See Note 5 for more information on our Exit Facility.

Income Taxes

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

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

Natural Gas, Oil and NGL Production and Pricing

The following table summarizes our oil and condensate, natural gas and NGL production and related pricing for the Current Successor YTD Period, Current Predecessor YTD Period and the Current Combined YTD Period, as compared to such data for the Prior Predecessor YTD Period:


	Successor		Predecessor		Non-GAAP Combined		Predecessor
	Period from May 18, 2021 through September 30, 2021		Period from January 1, 2021 through May 17, 2021		Nine Months Ended September 30, 2021		Nine Months Ended September 30, 2020
Natural gas sales
Natural gas production volumes (MMcf)	118,720		124,279		242,999		254,092
Natural gas production volumes (MMcf/d)	873		907		890		927
Total sales	$	413,234	$	344,390	$	757,624	$	456,859
Average price without the impact of derivatives ($/Mcf)	$	3.48	$	2.77	$	3.12	$	1.80
Impact from settled derivatives ($/Mcf)	$	(0.75)	$	(0.03)	$	(0.38)	$	0.69
Average price, including settled derivatives ($/Mcf)	$	2.73	$	2.74	$	2.74	$	2.49

Oil and condensate sales
Oil and condensate production volumes (MBbl)	759		531		1,290		1,394
Oil and condensate production volumes (MBbl/d)	6		4		5		5
Total sales	$	50,866	$	29,106	$	79,972	$	47,553
Average price without the impact of derivatives ($/Bbl)	$	67.02	$	54.81	$	61.99	$	34.12
Impact from settled derivatives ($/Bbl)	$	(5.71)	$	—	$	(3.36)	$	34.76
Average price, including settled derivatives ($/Bbl)	$	61.31	$	54.81	$	58.63	$	68.88

NGL sales
NGL production volumes (MBbl)	1,664		1,211		2,875		3,028
NGL production volumes (MBbl/d)	12		9		11		11
Total sales	$	61,230	$	36,780	$	98,010	$	45,989
Average price without the impact of derivatives ($/Bbl)	$	36.80	$	30.37	$	34.09	$	15.19
Impact from settled derivatives ($/Bbl)	$	(3.60)	$	—	$	(2.08)	$	—
Average price, including settled derivatives ($/Bbl)	$	33.20	$	30.37	$	32.01	$	15.19

Natural gas, oil and condensate and NGL sales
Natural gas equivalents (MMcfe)	133,257		134,735		267,992		280,621
Natural gas equivalents (MMcfe/d)	980		983		982		1,024
Total sales	$	525,330	$	410,276	$	935,606	$	550,401
Average price without the impact of derivatives ($/Mcfe)	$	3.94	$	3.05	$	3.49	$	1.96
Impact from settled derivatives ($/Mcfe)	$	(0.75)	$	(0.02)	$	(0.38)	$	0.80
Average price, including settled derivatives ($/Mcfe)	$	3.19	$	3.03	$	3.11	$	2.76

Production Costs:
Average lease operating expenses ($/Mcfe)	$	0.13	$	0.14	$	0.14	$	0.15
Average taxes other than income ($/Mcfe)	$	0.13	$	0.09	$	0.11	$	0.07
Average transportation, gathering, processing and compression ($/Mcfe)	$	0.94	$	1.20	$	1.07	$	1.19
Total lease operating expenses, midstream costs and taxes other than income ($/Mcfe)	$	1.20	$	1.43	$	1.32	$	1.41

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Natural Gas, Oil and NGL Sales


	Successor		Predecessor		Non-GAAP Combined		Predecessor
	Period from May 18, 2021 through September 30, 2021		Period from January 1, 2021 through May 17, 2021		Nine Months Ended September 30, 2021		Nine Months Ended September 30, 2020
Natural gas	$	413,234	$	344,390	$	757,624	$	456,859
Oil and condensate	50,866		29,106		79,972		47,553
NGL	61,230		36,780		98,010		45,989
Natural gas, oil and NGL sales	$	525,330	$	410,276	$	935,606	$	550,401

The increase in natural gas sales without the impact of derivatives was due to a 73% increase in realized natural gas prices partially offset by a 4% decrease in sales volumes. The realized price change was driven by the significant increase in the average Henry Hub gas index from $1.88 per Mcf in the Prior Predecessor YTD Period to $3.18 per Mcf during the Current Combined YTD Period.

The increase in oil and condensate sales without the impact of derivatives was due to a 82% increase in realized prices and partially offset by a 7% decrease in sales volumes. The realized price change was driven by the significant increase in the average WTI crude index from $38.23 per barrel in the Prior Predecessor YTD Period to $64.82 per barrel during the Current Combined YTD Period.

The increase in NGL sales without the impact of derivatives was due to a 124% increase in realized prices partially offset by an 5% decrease in NGL sales volumes. The realized price change was driven by the significant increase in the average Mont Belvieu NGL index from $15.04 per barrel in the Prior Predecessor YTD Period to $35.76 per barrel during the Current Combined YTD Period.

Natural Gas, Oil and NGL Derivatives


	Successor		Predecessor		Non-GAAP Combined		Predecessor
	Period from May 18, 2021 through September 30, 2021		Period from January 1, 2021 through May 17, 2021		Nine Months Ended September 30, 2021		Nine Months Ended September 30, 2020
Natural gas derivatives - fair value losses	$	(638,063)	$	(123,080)	$	(761,143)	$	(147,661)
Natural gas derivatives - settlement (losses) gains	(89,255)		(3,362)		(92,617)		176,555
Total (losses) gains on natural gas derivatives	(727,318)		(126,442)		(853,760)		28,894

Oil and condensate derivatives - fair value losses	(6,947)		(6,126)		(13,073)		(4,289)
Oil and condensate derivatives - settlement (losses) gains	(4,336)		—		(4,336)		48,444
Total (losses) gains on oil and condensate derivatives	(11,283)		(6,126)		(17,409)		44,155

NGL derivatives - fair value losses	(17,549)		(4,671)		(22,220)		(620)
NGL derivatives - settlement (losses) gains	(5,984)		—		(5,984)		366
Total losses on NGL derivatives	(23,533)		(4,671)		(28,204)		(254)

Contingent consideration arrangement - fair value losses	—		—		—		(1,381)
Total (losses) gains on natural gas, oil and NGL derivatives	$	(762,134)	$	(137,239)	$	(899,373)	$	71,414

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, 2021. See Note 10 for hedged volumes and pricing.

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Lease Operating Expenses


	Successor		Predecessor		Non-GAAP Combined		Predecessor
	Period from May 18, 2021 through September 30, 2021		Period from January 1, 2021 through May 17, 2021		Nine Months Ended September 30, 2021		Nine Months Ended September 30, 2020
Lease operating expenses
Utica	$	12,162	$	13,991	$	26,153	$	30,572
SCOOP	5,757		5,449		11,206		10,539
Other	61		84		145		55
Total lease operating expenses	$	17,980	$	19,524	$	37,504	$	41,166

Lease operating expenses per Mcfe
Utica	$0.13		$0.13		$0.13		$0.14
SCOOP	0.15		0.22		0.18		0.17
Other	0.90		2.15		1.36		0.41
Total lease operating expenses per Mcfe	$0.13		$0.14		$0.14		$0.15

The decrease in total LOE during the Current Combined YTD Period compared to the Prior Predecessor YTD Period was primarily the result of a 4% decrease in production as well as ongoing cost reduction initiatives. The decrease in per unit LOE is primarily the result of ongoing cost reduction initiatives.

Taxes Other Than Income


	Successor		Predecessor		Non-GAAP Combined		Predecessor
	Period from May 18, 2021 through September 30, 2021		Period from January 1, 2021 through May 17, 2021		Nine Months Ended September 30, 2021		Nine Months Ended September 30, 2020
Production taxes	$	12,561	$	8,459	$	21,020	$	12,432
Property taxes	3,377		2,590		5,967		5,743
Other	962		1,300		2,262		864
Total taxes other than income	$	16,900	$	12,349	$	29,249	$	19,039
Total taxes other than income per Mcfe	$	0.13	$	0.09	$	0.11	$	0.07

The increase in total and per unit production taxes during the Current Combined YTD Period compared to the Prior Predecessor YTD Period was primarily related to an increase in revenues due to an increase in realized prices.

Transportation, Gathering, Processing and Compression


	Successor		Predecessor		Non-GAAP Combined		Predecessor
	Period from May 18, 2021 through September 30, 2021		Period from January 1, 2021 through May 17, 2021		Nine Months Ended September 30, 2021		Nine Months Ended September 30, 2020
Transportation, gathering, processing and compression	$	125,811	$	161,086	$	286,897	$	334,789
Transportation, gathering, processing and compression per Mcfe	$	0.94	$	1.20	$	1.07	$	1.19

The decrease in transportation, gathering, processing and compression was primarily related to savings associated with rejected midstream contracts and renegotiation through the bankruptcy process. Additionally, total costs decreased as a result of our 4% decrease in production.

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Depreciation, Depletion and Amortization


	Successor		Predecessor
	Period from May 18, 2021 through September 30, 2021		Period from January 1, 2021 through May 17, 2021		Nine Months Ended September 30, 2020
Depreciation, depletion and amortization of oil and gas properties	$	93,959	$	60,831	$	186,693
Depreciation, depletion and amortization of other property and equipment	$	976	$	1,933	$	7,676
Total Depreciation, depletion and amortization	$	94,935	$	62,764	$	194,369
Depreciation, depletion and amortization per Mcfe	$	0.71	$	0.47	$	0.69

The decrease in depreciation, depletion and amortization of our oil and gas properties for the Current Combined YTD Period compared to the Prior Predecessor YTD Period is primarily the result of impairments taken in 2020 which decreased the depletion rate, partially offset by 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. See Note 3 for more information on fresh start adjustments.

Impairment of Oil and Gas Properties

We incurred a $117.8 million impairment charge of oil and gas properties during the Current Combined YTD Period. We recorded $1.4 billion in impairment charges of oil and gas properties during the Prior Predecessor YTD 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 for the calculation performed at the end of the second quarter of 2021, which led to the Current Combined YTD 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 Current Predecessor YTD Period as a result in a change in expected future use.

General and Administrative Expenses


	Successor		Predecessor		Non-GAAP Combined		Predecessor
	Period from May 18, 2021 through September 30, 2021		Period from January 1, 2021 through May 17, 2021		Nine Months Ended September 30, 2021		Nine Months Ended September 30, 2020
General and administrative expenses, gross	$	34,818	$	32,152	$	66,970	$	74,226
Reimbursed from third parties	(4,355)		(4,957)		(9,312)		(8,731)
Capitalized general and administrative expenses	(7,254)		(8,020)		(15,274)		(19,776)
General and administrative expenses, net	$	23,209	$	19,175	$	42,384	$	45,719

General and administrative expenses, net per Mcfe	$	0.17	$	0.14	$	0.16	$	0.16

The decrease in total general and administrative expenses during the Current Combined YTD Period compared to the Prior Predecessor YTD Period was primarily driven by retention payments made in 2020 and our continued focus on workforce and leadership structure to align to our current operating environment.

Restructuring and Liability Management

During the Current Successor YTD Period and the Prior Predecessor YTD Period, we incurred restructuring charges related to reductions in workforce as we continued to align our workforce and leadership structure to our current operating environment. Additionally, during the Prior Predecessor YTD Period, we incurred liability management charges related to

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legal advisors engaged to assist with the evaluation of a range of liability management alternatives prior to our ultimate Chapter 11 filing. The following table summarizes the restructuring and liability management charges incurred:


	Successor		Predecessor
	Period from May 18, 2021 through September 30, 2021		Period from January 1, 2021 through May 17, 2021		Nine months ended September 30, 2020
Reduction in workforce	$	2,858	$	—	$	1,460
Liability management	—		—		8,141
Total restructuring and liability management	$	2,858	$	—	$	9,601

Interest Expense


	Successor		Predecessor
	Period from May 18, 2021 through September 30, 2021		Period from January 1, 2021 through May 17, 2021		Nine Months Ended September 30, 2020
Interest expense on Predecessor Senior Notes	$	—	$	—	$	85,433
Interest expense on Pre-Petition Revolving Credit Facility	—		2,044		9,305
Interest expense on building loan and other	556		(989)		1,110
Capitalized interest	(117)		—		(907)
Amortization of loan costs	1,014		—		4,736
Interest on DIP Credit Facility	—		3,104		—
Interest on Exit Facility	3,824		—		—
Interest on First-Out Term Loan	3,664		—		—
Interest on Successor Senior Notes	16,304		—		—
Total interest expense	$	25,245	$	4,159	$	99,677

Interest expense per Mcfe	$	0.19	$	0.03	$	0.36

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

Gain on Debt Extinguishment

During the Prior Predecessor YTD Period, we repurchased in the open market $73.3 million aggregate principal amount of our Predecessor Senior Notes for $22.8 million in cash and recognized a $49.6 million gain on debt extinguishment. We did not repurchase any of our senior notes in the Current Combined YTD Period.

Equity Investments


	Successor		Predecessor		Non-GAAP Combined		Predecessor
	Period from May 18, 2021 through September 30, 2021		Period from January 1, 2021 through May 17, 2021		Nine Months Ended September 30, 2021		Nine Months Ended September 30, 2020

Loss from equity method investments, net	$	—	$	342	$	342	$	10,987

During the Prior Predecessor YTD Period, our share of net loss from Mammoth was in excess of the carrying value of our investment, which reduced our investment to zero. Our carrying value remained at zero through the Current Predecessor YTD Period until the use of Mammoth Shares to settle Class 4A claims at the Emergence Date. See Note 13 to our consolidated financial statements for further discussion on our equity investments.

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Reorganization Items, Net.

The following table summarizes the components in reorganization items, net included in our consolidated statements of operations for the Current Successor YTD Period and Current Predecessor YTD Period ended September 30, 2021:


	Successor		Predecessor
	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

See Note 3 for further discussion of the components of reorganization items, net.

Income Taxes

We recorded an income tax benefit of $7.3 million during the Current 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. For the Prior Predecessor YTD Period, we had an effective tax rate of (0.5)% and tax expense of $7.3 million as a result of the sale of assets and a corresponding adjustment to the valuation allowance on remaining state net operating loss carryforwards.

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Liquidity and Capital Resources

Overview. We strive to maintain sufficient liquidity to ensure financial flexibility, withstand commodity price volatility and 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. Historically, we have generally funded our operations, planned capital expenditures and any debt or share repurchases with cash flow from our operating activities, cash on hand, and borrowings under our revolving credit facility. We also periodically access debt and equity markets and sell properties to enhance our liquidity.

For the Current Successor YTD Period, 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. Historically, our primary sources of capital funding and liquidity have been our operating cash flow, borrowings under our credit agreements and issuances of equity and debt securities. Our ability to issue additional indebtedness, dispose of assets or access the capital markets was substantially limited or nonexistent during the Chapter 11 Cases and required court approval in most instances. Accordingly, our liquidity in the Predecessor periods depended mainly on cash generated from operating activities and available funds under the DIP Credit Facility in the 2021 Predecessor Period and Pre-Petition Revolving Credit Facility in the 2020 Predecessor Period.

We believe our annual free cash flow generation, borrowing capacity under the New Credit Facility and cash on hand will provide sufficient liquidity to fund our operations, capital expenditures, interest expense, debt repayments and any return of capital to shareholders, if declared by the Board, 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 5 of the notes to our consolidated financial statements for further discussion of our debt obligations, including principal and carrying amounts of our notes.

As of September 30, 2021, we had $4.5 million of cash and cash equivalents, $35.6 million of borrowings under our Exit Facility, $165.0 million of borrowings under our First-Out Term Loan, $115.5 million of letters of credit outstanding, and $550 million of outstanding 2026 Notes. Our total principal amount of funded debt as of September 30, 2021 was $750.6 million.

As of October 28, 2021, after giving effect to the New Credit Facility, we had $6.2 million of cash and cash equivalents, $246.0 million of borrowings under our New Credit Facility, $97.1 million of letters of credit outstanding, and $550 million of outstanding 2026 Notes. The increase in borrowings since September 30, 2021 was primarily due to the $43.8 million payment made to TC pursuant to the settlement agreement as discussed in Note 9.

Post-Emergence Debt. On the Emergence Date, pursuant to the terms of the Plan, we entered into a reserve-based credit agreement providing for the Exit Credit Facility, which featured an initial borrowing base of $580.0 million. The Exit Credit Facility consisted of the Exit Facility and the First-Out Term Loan. Subsequent to the end of the third quarter of 2021, we amended and refinanced the Exit Credit Facility with the New Credit Facility.

As discussed in Note 17, 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 New 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.

The Exit Facility provided for a $150.0 million sublimit of the aggregate commitments that is available for the issuance of letters of credit. The Exit Facility also included a $40 million availability blocker that remains in place until Successful Midstream Resolution (as defined in the Exit Credit Agreement), as discussed in Note 9. The Exit Facility bore interest at a rate equal to, at our election, either (a) LIBOR plus an applicable margin that varies from 3.00% to 4.00% per annum or (b) a base rate plus an applicable margin that varies from 2.00% to 3.00% per annum. The First-Out Term Loan bore interest at a rate equal to, at Gulfport’s election, either (a) LIBOR (subject to a 1.00% floor) plus 4.50% or (b) a base rate (subject to a 2.00% floor) plus 3.50%. As of September 30, 2021, the Exit Facility and the First-Out Term Loan bore interest at weighted average rates of 4.50% and 5.50%, respectively.

Additionally, on the Emergence Date, pursuant to the terms of the Plan, we issued $550 million aggregate principal amount of our Successor Senior Notes.

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The Successor Senior Notes are guaranteed on a senior unsecured basis by each of the Company's subsidiaries that guarantee the Exit Credit Facility as well as the New Credit Facility effective October 14, 2021.

See Note 5 for additional discussion of our post-emergence debt.

Preferred Dividends. As discussed in Note 6 of the notes to our consolidated financial statements, holders of New 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 New Preferred Stock (“PIK Dividends”). Gulfport must pay PIK Dividends for so long as the quotient obtained by dividing (i) Total Net Funded Debt (as defined in the Exit Credit Facility) by (ii) the last twelve (12) months of EBITDAX (as defined in the Exit Credit Facility) calculated as at the applicable record date is equal to or greater than 1.50. If such ratio is less than 1.50 such dividend may be paid in either cash or as PIK Dividends, subject to certain conditions under the New Credit Facility.

On September 30, 2021, the company paid a PIK dividend on its New Preferred Stock, which included 2,065 shares of New Preferred Stock paid in kind and approximately $30 thousand of cash-in-lieu of fractional shares.

Supplemental Guarantor Financial Information. The Successor Senior Notes are guaranteed on a senior unsecured basis by all existing consolidated subsidiaries that guarantee our Exit Facility or certain other debt (the “Guarantors”). The 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 Successor 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 Successor 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 included in Item 1 of this report for further discussion on the impact of commodity price risk on our financial position. Additionally, see Note 10 of the notes to 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.

Our capital expenditures for 2021 are currently estimated to be in the range of $270 million to $290 million for drilling and completion expenditures. In addition, we currently expect to spend approximately $20 million in 2021 for non-drilling and completion expenditures, which includes acreage expenses, primarily lease extensions in the Utica Shale.

Proceeds from Issuance of New Preferred Stock. On the Emergence Date, pursuant to the Plan, we conducted a Rights Offering and issued 50,000 shares of New Preferred Stock at $1,000 per share to holders of claims against the Predecessor Subsidiaries, raising $50 million in proceeds.

Cash Flow from Operating Activities. Net cash flow provided by operating activities was $164.6 million for the Current Successor YTD Period and $172.2 million for the Current Predecessor YTD Period as compared to $200.0 million for the Prior

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Predecessor 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, partially offset by reorganization items related to our Chapter 11 Cases.

Uses of Funds. The following table presents the uses of our cash and cash equivalents for the Current Successor YTD Period, Current Predecessor YTD Period, and the Prior Predecessor YTD Period:


	Successor		Predecessor
	Period from May 18, 2021 through September 30, 2021		Period from January 1, 2021 through May 17, 2021		Nine Months Ended September 30, 2020
Oil and Natural Gas Property Cash Expenditures:
Drilling and completion costs	$	109,077	$	94,128	$	299,896
Leasehold acquisitions	3,474		2,752		18,449
Other	6,755		5,450		19,634
Total oil and natural gas property expenditures	$	119,306	$	102,330	$	337,979
Other Uses of Cash and Cash Equivalents
Principal payments on Pre-Petition Revolving Credit Facility, net	$	—	$	292,911	$	—
Principal payments on DIP credit facility	—		157,500		—
Principal payments on Exit Credit Facility, net	102,145		—		—
Cash paid to repurchase senior notes	—		—		22,827

Other	1,357		7,497		1,459
Total other uses of cash and cash equivalents	$	103,502	$	457,908	$	24,286
Total uses of cash and cash equivalents	$	222,808	$	560,238	$	362,265

Drilling and Completion Costs. During the Current Combined YTD Period, we spud 12 gross (11.6 net) and commenced sales from 11 gross and net operated wells in the Utica for a total cost of approximately $152.2 million. During the Current Combined YTD Period, we spud four gross (3.9 net) and commenced sales from 11 gross (9.3 net) operated wells in the SCOOP for a total cost of approximately $65.8 million.

During the Current Combined 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, 15 gross (1.6 net) wells were spud and 21 gross (0.05 net) wells were turned to sales by other operators on our SCOOP acreage during the Current Combined YTD Period.

Drilling and completion costs presented in this section reflect incurred costs while drilling and completion costs presented above in Uses of Funds section reflect cash payments for drilling and completions. Incurred capital expenditures and cash capital expenditures may vary from period to period due to the cash payment cycle.

Share Repurchase Program

Contractual and Commercial Obligations

We have various contractual obligations in the normal course of our operations and financing activities. See Note 3 for discussion of changes in contractual obligations as a result of emergence from bankruptcy. See Note 9 of the notes to our consolidated financial statements for discussion of changes to our firm transportation and gathering agreements subsequent to

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the Emergence Date. 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, 2020.

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, 2021, our material off-balance sheet arrangements and transactions include $115.5 million in letters of credit outstanding against our Exit Facility and $90.1 million in surety bonds issued. Both the letters of credit and surety bonds are being used as financial assurance, primarily on certain firm transportation agreements. There are no other transactions, arrangements or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect our liquidity or availability of our capital resources. See Note 9 to our consolidated financial statements for further discussion of the various financial guarantees we have issued.

Critical Accounting Policies and Estimates

As of September 30, 2021, there have been no significant changes in our critical accounting policies from those disclosed in our 2020 Annual Report on Form 10-K.

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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 COVID-19 pandemic 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, 2020 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.


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

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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. Future risk related to counterparties not being able to meet their obligations has been partially mitigated under our commodity hedging arrangements that require counterparties to post collateral if their obligations to us are in excess of defined thresholds. 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 10 of the notes to our consolidated financial statements for further discussion of the fair value measurements associated with our derivatives.

As of September 30, 2021, 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.

•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.

•Costless Collars: These instruments have 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, we will cash-settle the difference with the counterparty. Our fixed price swap contracts are tied to the commodity prices on NYMEX Henry Hub for natural gas, NYMEX WTI for oil, and Mont Belvieu for propane. We will receive the fixed priced amount stated in the contract and pay to its counterparty the current market price as listed on the applicable index.

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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, 2021, we had a net liability derivative position of $830.6 million as compared to a net liability derivative position of $80.6 million as of September 30, 2020. Utilizing actual derivative contractual volumes, a 10% increase in underlying commodity prices would have increased our liability by approximately $231.5 million, while a 10% decrease in underlying commodity prices would have decreased our liability by approximately $220.3 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, 2021, we had $35.6 million in borrowings outstanding under our Exit Facility which bore interest at a weighted average rate of 4.50%. At September 30, 2021, we had $165.0 million in borrowings outstanding under our First-Out Term Loan which bore interest at a weighted average rate of 5.50%. As of September 30, 2021, 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, 2021, 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, 2021, our disclosure controls and procedures are effective.

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

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

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PART II


ITEM 1.			LEGAL PROCEEDINGS

The information with respect to this Item 1. Legal Proceedings is set forth in Note 9 in the accompanying condensed 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, 2020 and our Quarterly Report on Form 10-Q for the quarter ended June 30, 2021.


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

Unregistered Sales of Equity Securities

None.

Issuer Repurchases of Equity Securities

None.


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

Third Amended and Restated Credit Agreement, dated as of October 14, 2021, by and among Gulfport Energy Corporation, as holdings, Gulfport Energy Operating Corporation, as the borrower, JPMorgan Chase Bank, N.A., the lenders party thereto, and the guarantors party thereto.

8-K

001-19514

10.1

10/14/2021

10.2*

CEO Agreement Amendment by and among Timothy Cutt and Gulfport, effective as of September 2, 2021.

8-K

001-19514

10.1

9/7/2021

31.1

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

31.2

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

32.1

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

32.2

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

101.INS

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

101.SCH

XBRL Taxonomy Extension Schema Document.

101.CAL

XBRL Taxonomy Extension Calculation Linkbase Document.

101.DEF

XBRL Taxonomy Extension Definition Linkbase Document.

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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.

Management contract or compensatory plan or arrangement

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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 3, 2021


GULFPORT ENERGY CORPORATION

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