UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)


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

For the quarterly period ended ~~June 30, 2020~~March 31, 2021


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

For the transition period from to

Commission File Number ~~000-19514~~001-19514

Gulfport Energy Corporation

(Exact Name of Registrant As Specified in Its Charter)


Delaware			73-1521290
(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, par value $0.01 per share~~

~~GPOR~~

~~Nasdaq Global Select Market~~

None(1)

(1) On November 27, 2020, our common stock was suspended from trading on the NASDAQ Stock Market LLC ("NASDAQ"). On November 30, 2020, our common stock began trading on the OTC Pink Marketplace maintained by the OTC Markets Group, Inc. under the symbol “GPORQ". On February 2, 2021, NASDAQ filed a Form 25 delisting our common stock from trading on NASDAQ, which delisting became effective 10 days after the filing of the Form 25. In accordance with Rule 12d2-2 of the Securities Exchange Act of 1934, as amended (the "Exchange Act"), the de-registration of our common stock under section 12(b) of the Exchange Act became effective on February 12, 2021.

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

Common Stock

(Title of Class)

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

As of ~~July 31, 2020, 160,115,829~~April 30, 2021, 160,892,447 shares of the registrant’s common stock were outstanding.

Table of Contents

GULFPORT ENERGY CORPORATION

TABLE OF CONTENTS

Page

PART I FINANCIAL INFORMATION

Item 1.

Consolidated Financial Statements (Unaudited):

Consolidated Balance Sheets at ~~June 30, 2020~~March 31, 2021 and December 31, ~~2019~~

~~Consolidated Statements of Operations for the Three~~ ~~and Six~~ ~~Months Ended~~ ~~June 30~~, 2020 ~~and 2019~~

Consolidated Statements of ~~Comprehensive Income~~Operations for the Three ~~and Six~~ Months Ended ~~June~~ 3 0 ,March 31, 2021 and 2020 ~~and 2019~~

Consolidated Statements of ~~Stockholders’ Equity~~Comprehensive Income (Loss) for the ~~Six~~ Three Months Ended ~~June 30~~,March 31, 2021 and 2020 ~~and 2019~~

Consolidated Statements of ~~Cash Flows~~Stockholders’ (Deficit) Equity for the ~~Six~~Three Months Ended ~~June 30~~,March 31, 2021 and 2020 ~~and 2019~~

Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2021 and 2020

Notes to Consolidated Financial Statements

Item 2.

Management’s Discussion and Analysis of Financial Conditions and Results of Operations

3731

Item 3.

Quantitative and Qualitative Disclosures About Market Risk

5947

Item 4.

Controls and Procedures

6149

PART II OTHER INFORMATION

Item 1.

Item 1A.

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds

6550

Item 3.

Defaults Upon Senior Securities

6650

Item 4.

Mine Safety Disclosures

Item 5.

Item 6.

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

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.


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.


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.
Net Acres or Net Wells. Refers to the sum of the fractional working interests owned in gross acres or gross wells.

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.

Table of Contents


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.






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.
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.

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


Undeveloped Acreage. Lease or mineral acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of crude oil and/or natural gas.

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.

Table of Contents

GULFPORT ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS

June 30, 2020 December 31, 2019
(Unaudited)
(In thousands, except share data)
Assets
Current assets:
Cash and cash equivalents $ 2,817 $ 6,060
Accounts receivable—oil and natural gas sales 65,645 121,210
Accounts receivable—joint interest and other 19,389 47,975
Prepaid expenses and other current assets 10,862 4,431
Short-term derivative instruments 53,188 126,201
Total current assets 151,901 305,877
Property and equipment:
Oil and natural gas properties, full-cost accounting, $1,564,189 and $1,686,666 excluded from amortization in 2020 and 2019, respectively 10,730,992 10,595,735
Other property and equipment 96,838 96,719
Accumulated depletion, depreciation, amortization and impairment (8,457,464) (7,228,660)
Property and equipment, net 2,370,366 3,463,794
Other assets:
Equity investments 13,052 32,044
Long-term derivative instruments 4,298 563
Deferred tax asset — 7,563
Operating lease assets 3,640 14,168
Operating lease assets—related parties — 43,270
Other assets 37,000 15,540
Total other assets 57,990 113,148
Total assets $ 2,580,257 $ 3,882,819
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable and accrued liabilities $ 315,575 $ 415,218
Short-term derivative instruments 8,540 303
Current portion of operating lease liabilities 3,356 13,826
Current portion of operating lease liabilities—related parties — 21,220
Current maturities of long-term debt 649 631
Total current liabilities 328,120 451,198
Long-term derivative instruments 45,615 53,135
Asset retirement obligation 61,371 60,355
Uncertain tax position liability 3,209 3,127
Non-current operating lease liabilities 284 342
Non-current operating lease liabilities—related parties — 22,050
Long-term debt, net of current maturities 1,910,318 1,978,020
Total liabilities 2,348,917 2,568,227
Commitments and contingencies (Note 9)
Preferred stock, $0.01 par value; 5.0 million shares authorized (30 thousand authorized as redeemable 12% cumulative preferred stock, Series A), and NaN issued and outstanding — —
Stockholders’ equity:
Common stock - $0.01 par value, 200.0 million shares authorized, 160.1 million issued and outstanding at June 30, 2020 and 159.7 million at December 31, 2019 1,601 1,597
Paid-in capital 4,211,062 4,207,554
Accumulated other comprehensive loss (54,991) (46,833)
Accumulated deficit (3,926,332) (2,847,726)
Total stockholders’ equity 231,340 1,314,592
Total liabilities and stockholders’ equity $ 2,580,257 $ 3,882,819
(DEBTOR-IN-POSSESSION)


	March 31, 2021		December 31, 2020
	(Unaudited)
	(In thousands, except share data)
Assets
Current assets:
Cash and cash equivalents	$	179,701	$	89,861


Accounts receivable—oil and natural gas sales	133,996		119,879
Accounts receivable—joint interest and other	12,904		12,200

Prepaid expenses and other current assets	134,509		160,664
Short-term derivative instruments	12,422		27,146
Total current assets	473,532		409,750
Property and equipment:
Oil and natural gas properties, full-cost accounting, $1,413,774 and $1,457,043 excluded from amortization in 2021 and 2020, respectively	10,895,625		10,816,909
Other property and equipment	88,835		88,538
Accumulated depletion, depreciation, amortization and impairment	(8,874,899)		(8,819,178)
Property and equipment, net	2,109,561		2,086,269
Other assets:
Equity investments	27,044		24,816
Long-term derivative instruments	652		322


Operating lease assets	314		342

Other assets	16,545		18,372
Total other assets	44,555		43,852
Total assets	$	2,627,648	$	2,539,871
Liabilities and Stockholders’ Deficit
Current liabilities:
Accounts payable and accrued liabilities	$	310,172	$	244,903

Short-term derivative instruments	20,687		11,641


Current maturities of long-term debt	279,807		253,743
Total current liabilities	610,666		510,287
Non-current liabilities:
Long-term derivative instruments	43,267		36,604






Total non-current liabilities	43,267		36,604
Liabilities subject to compromise	2,261,453		2,293,480
Total liabilities	$	2,915,386	$	2,840,371
Commitments and contingencies (Note 8)	0		0
Preferred stock - $0.01 par value; 5.0 million shares authorized (30 thousand authorized as redeemable 12% cumulative preferred stock, Series A), and NaN issued and outstanding	0		0
Stockholders’ deficit:
Common stock - $0.01 par value, 200.0 million shares authorized, 160.9 million issued and outstanding at March 31, 2021 and 160.8 million at December 31, 2020	1,609		1,607
Paid-in capital	4,215,162		4,213,752
Accumulated other comprehensive loss	(40,430)		(43,000)
Accumulated deficit	(4,464,079)		(4,472,859)
Total stockholders’ deficit	$	(287,738)	$	(300,500)
Total liabilities and stockholders’ deficit	$	2,627,648	$	2,539,871

See accompanying notes to consolidated financial statements.

Table of Contents

GULFPORT ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

(DEBTOR-IN-POSSESSION)

(Unaudited)

Three months ended June 30, Six months ended June 30,
2020 2019 2020 2019
(In thousands)
REVENUES:
Natural gas sales $ 86,797 $ 225,257 $ 195,344 $ 501,273
Oil and condensate sales 8,390 36,910 31,541 69,392
Natural gas liquid sales 10,252 25,687 27,165 57,812
Net gain on natural gas, oil and NGL derivatives 26,971 171,140 125,237 151,095
Total Revenues 132,410 458,994 379,287 779,572
OPERATING EXPENSES:
Lease operating expenses 15,686 22,388 31,672 42,195
Production taxes 3,605 8,098 8,404 16,019
Midstream gathering and processing expenses 59,974 72,015 117,870 142,297
Depreciation, depletion and amortization 64,790 124,951 142,818 243,384
Impairment of oil and natural gas properties 532,880 — 1,086,225 —
General and administrative expenses 10,470 11,727 26,639 21,784
Accretion expense 755 1,359 1,496 2,426
Total Operating Expenses 688,160 240,538 1,415,124 468,105
(LOSS) INCOME FROM OPERATIONS (555,750) 218,456 (1,035,837) 311,467
OTHER EXPENSE (INCOME):
Interest expense 32,366 36,418 65,356 72,039
Interest income (78) (159) (230) (311)
Gain on debt extinguishment (34,257) — (49,579) —
Loss from equity method investments, net 45 125,582 10,834 121,309
Other expense 7,242 990 9,098 563
Total Other Expense 5,318 162,831 35,479 193,600
(LOSS) INCOME BEFORE INCOME TAXES (561,068) 55,625 (1,071,316) 117,867
Income Tax Expense (Benefit) — (179,331) 7,290 (179,331)
NET (LOSS) INCOME $ (561,068) $ 234,956 $ (1,078,606) $ 297,198
NET (LOSS) INCOME PER COMMON SHARE:
Basic $ (3.51) $ 1.47 $ (6.75) $ 1.85
Diluted $ (3.51) $ 1.47 $ (6.75) $ 1.84
Weighted average common shares outstanding—Basic 159,934 159,325 159,847 161,065
Weighted average common shares outstanding—Diluted 159,934 159,507 159,847 161,590

~~See accompanying notes to consolidated financial statements.~~

~~Table of Contents~~

~~GULFPORT ENERGY CORPORATION~~

~~CONSOLIDATED STATEMENTS OF COMPREHENSIVE (LOSS) INCOME~~

~~(Unaudited)~~

Three months ended June 30, Six months ended June 30,
2020 2019 2020 2019
(In thousands)
Net (loss) income $ (561,068) $ 234,956 $ (1,078,606) $ 297,198
Foreign currency translation adjustment 6,872 3,610 (8,158) 7,411
Other comprehensive income (loss) 6,872 3,610 (8,158) 7,411
Comprehensive (loss) income $ (554,196) $ 238,566 $ (1,086,764) $ 304,609


	Three months ended March 31,
	2021		2020
	(In thousands)
REVENUES:
Natural gas sales	$	235,321	$	161,008
Oil and condensate sales	18,239		23,151
Natural gas liquid sales	23,776		16,913
Net (loss) gain on natural gas, oil and NGL derivatives	(29,978)		98,266
Total Revenues	247,358		299,338
OPERATING EXPENSES:
Lease operating expenses	12,653		14,695
Taxes other than income	8,704		6,637
Transportation, gathering, processing and compression	105,867		110,357
Depreciation, depletion and amortization	41,147		78,028
Impairment of oil and natural gas properties	0		553,345
Impairment of other property and equipment	14,568		0
General and administrative expenses	12,757		15,622

Accretion expense	805		741

Total Operating Expenses	196,501		779,425
INCOME (LOSS) FROM OPERATIONS	50,857		(480,087)
OTHER EXPENSE (INCOME):
Interest expense	3,261		32,990
Interest income	(143)		(152)
Gain on debt extinguishment	0		(15,322)

Loss from equity method investments, net	342		10,789
Reorganization items, net	38,721		0
Other expense	(104)		1,856
Total Other Expense	42,077		30,161
INCOME (LOSS) BEFORE INCOME TAXES	8,780		(510,248)
Income Tax Expense	0		7,290
NET INCOME (LOSS)	$	8,780	$	(517,538)
NET INCOME (LOSS) PER COMMON SHARE:
Basic	$	0.05	$	(3.24)
Diluted	$	0.05	$	(3.24)
Weighted average common shares outstanding—Basic	160,813		159,760
Weighted average common shares outstanding—Diluted	160,813		159,760

See accompanying notes to consolidated financial statements.

Table of Contents

GULFPORT ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF ~~STOCKHOLDERS’ EQUITY~~COMPREHENSIVE INCOME (LOSS)

(DEBTOR-IN-POSSESSION)

(Unaudited)

Paid-in
Capital Accumulated
Other
Comprehensive (Loss) Income Accumulated
Deficit Total
Stockholders’
Equity
Common Stock
Shares Amount
(In thousands)
Balance at January 1, 2020 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 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 160,116 $ 1,601 $ 4,211,062 $ (54,991) $ (3,926,332) $ 231,340

Paid-in
Capital Accumulated
Other
Comprehensive (Loss) Income Accumulated
Deficit Total
Stockholders’
Equity
Common Stock
Shares Amount
(In thousands)
Balance at January 1, 2019 162,986 $ 1,630 $ 4,227,532 $ (56,026) $ (845,368) $ 3,327,768
Net Income — — — — 62,242 62,242
Other Comprehensive Income — — — 3,801 — 3,801
Stock Compensation — — 2,785 — — 2,785
Shares Repurchased (3,619) (37) (28,293) — — (28,330)
Issuance of Restricted Stock 55 1 (1) — — —
Balance at March 31, 2019 159,422 $ 1,594 $ 4,202,023 $ (52,225) $ (783,126) $ 3,368,266
Net Income — — — — 234,956 234,956
Other Comprehensive Income — — — 3,610 — 3,610
Stock Compensation — — 2,846 — — 2,846
Shares Repurchased (297) (3) (2,267) — — (2,270)
Issuance of Restricted Stock 271 3 (3) — — —
Balance at June 30, 2019 159,396 $ 1,594 $ 4,202,599 $ (48,615) $ (548,170) $ 3,607,408


	Three months ended March 31,
	2021		2020
	(In thousands)
Net income (loss)	$	8,780	$	(517,538)
Foreign currency translation adjustment	2,570		(15,030)

Other comprehensive income (loss)	2,570		(15,030)
Comprehensive income (loss)	$	11,350	$	(532,568)

See accompanying notes to consolidated financial statements.

Table of Contents

GULFPORT ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ (DEFICIT) EQUITY

(DEBTOR-IN-POSSESSION)

(Unaudited)


				Paid-in Capital		Accumulated Other Comprehensive (Loss) Income		Accumulated Deficit		Total Stockholders’ Deficit
	Common Stock
	Shares	Amount
	(In thousands)












Balance at January 1, 2021	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	160,878	$	1,609	$	4,215,162	$	(40,430)	$	(4,464,079)	$	(287,738)


				Paid-in Capital		Accumulated Other Comprehensive Loss		Accumulated Deficit		Total Stockholders’ Equity
	Common Stock
	Shares	Amount
	(In thousands)
Balance at January 1, 2020	159,711	$	1,597	$	4,207,554	$	(46,833)	$	(2,847,726)	$	1,314,592
Net Loss	—	—		—		—		(517,538)		(517,538)
Other Comprehensive Income	—	—		—		(15,030)		—		(15,030)
Stock Compensation	—	—		2,104		—		—		2,104
Shares Repurchased	(80)	(1)		(78)		—		—		(79)
Issuance of Restricted Stock	211	2		(2)		—		—		0
Balance at March 31, 2020	159,842	$	1,598	$	4,209,578	$	(61,863)	$	(3,365,264)	$	784,049

See accompanying notes to consolidated financial statements.

Table of Contents

GULFPORT ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(DEBTOR-IN-POSSESSION)

(Unaudited)

Six months ended June 30,
2020 2019
(In thousands)
Cash flows from operating activities:
Net (loss) income $ (1,078,606) $ 297,198
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depletion, depreciation and amortization 142,818 243,384
Impairment of oil and natural gas properties 1,086,225 —
Loss (income) from equity investments 10,834 121,449
Gain on debt extinguishment (49,579) —
Net gain on derivative instruments (125,237) (151,095)
Net cash receipts (payments) on settled derivative instruments 195,232 (1,494)
Deferred income tax expense 7,290 (179,331)
Other, net 9,844 11,341
Changes in operating assets and liabilities:
Decrease in accounts receivable—oil and natural gas sales 55,565 78,525
Decrease (increase) in accounts receivable—joint interest and other 29,159 (24,148)
(Decrease) increase in accounts payable and accrued liabilities (30,620) 3,220
Other, net (5,703) 720
Net cash provided by operating activities 247,222 399,769
Cash flows from investing activities:
Additions to oil and natural gas properties (274,851) (508,315)
Proceeds from sale of oil and natural gas properties 45,185 745
Additions to other property and equipment (575) (4,298)
Proceeds from sale of other property and equipment 151 130
Contributions to equity method investments — (432)
Distributions from equity method investments — 1,945
Net cash used in investing activities (230,090) (510,225)
Cash flows from financing activities:
Principal payments on borrowings (323,322) (345,350)
Borrowings on line of credit 326,000 455,000
Repurchases of senior notes (22,827) —
Payments for repurchases of stock under approved stock repurchase program — (30,000)
Other, net (226) (714)
Net cash (used in) provided by financing activities (20,375) 78,936
Net decrease in cash, cash equivalents and restricted cash (3,243) (31,520)
Cash, cash equivalents and restricted cash at beginning of period 6,060 52,297
Cash, cash equivalents and restricted cash at end of period $ 2,817 $ 20,777
Supplemental disclosure of cash flow information:
Interest payments $ 60,523 $ 67,472
Income tax receipts $ — $ (1,794)
Supplemental disclosure of non-cash transactions:
Capitalized stock-based compensation $ 1,891 $ 2,252
Asset retirement obligation capitalized $ 1,553 $ 6,230
Asset retirement obligation removed due to divestiture $ (2,033) $ —
Interest capitalized $ 710 $ 1,771
Fair value of contingent consideration asset on date of divestiture $ 23,090 $ —
Foreign currency translation (loss) gain on equity method investments $ (8,158) $ 7,411


	Three months ended March 31,
	2021		2020
	(In thousands)
Cash flows from operating activities:
Net income (loss)	$	8,780	$	(517,538)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depletion, depreciation and amortization	41,147		78,028
Impairment of oil and natural gas properties	0		553,345
Impairment of other property and equipment	14,568		0
Loss from equity investments	342		10,789
Gain on debt extinguishment	0		(15,322)
Net loss (gain) on derivative instruments	29,978		(98,266)
Net cash receipts on settled derivative instruments	125		70,733

Deferred income tax expense	0		7,290
Other, net	1,574		3,223
Changes in operating assets and liabilities, net	26,661		38,556
Net cash provided by operating activities	123,175		130,838
Cash flows from investing activities:
Additions to oil and natural gas properties	(56,895)		(113,744)
Proceeds from sale of oil and natural gas properties	15		44,383
Other, net	(296)		(448)
Net cash used in investing activities	(57,176)		(69,809)
Cash flows from financing activities:
Principal payments on pre-petition revolving credit facility	(2,202)		(180,000)
Borrowings on pre-petition revolving credit facility	26,050		125,000


Repurchase of senior notes	0		(10,204)

Other, net	(7)		(252)
Net cash provided by (used in) financing activities	23,841		(65,456)
Net increase (decrease) in cash, cash equivalents and restricted cash	89,840		(4,427)
Cash, cash equivalents and restricted cash at beginning of period	89,861		6,060
Cash, cash equivalents and restricted cash at end of period	$	179,701	$	1,633

See accompanying notes to consolidated financial statements.

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GULFPORT ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(DEBTOR-IN-POSSESSION)

(Unaudited)

1.BASIS OF PRESENTATION ~~SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES~~ AND LIQUIDITY, MANAGEMENT'S PLANS AND GOING CONCERN

Basis of Presentation

The accompanying unaudited consolidated financial statements have been prepared by Gulfport Energy Corporation (the “Company” or “Gulfport”) pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”), and reflect all adjustments that, in the opinion of management, are necessary for a fair presentation of the results for the interim periods reported in all material respects, on a basis consistent with the annual audited consolidated financial statements. All such adjustments are of a normal, recurring nature. Certain information, accounting policies, and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles ("GAAP") have been omitted pursuant to such rules and regulations, although the Company believes that the disclosures are adequate to make the information presented not misleading.

The consolidated financial statements should be read in conjunction with the consolidated financial statements and the summary of significant accounting policies and notes included in the Company’s most recent annual report on Form 10-K. Results for the three ~~and six~~ months ended ~~June 30, 2020~~March 31, 2021 are not necessarily indicative of the results expected for the full year.

~~COVID-19~~Voluntary Reorganization Under Chapter 11 of the Bankruptcy Code

IOn November 13, 2020, 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 filed voluntary petitions of 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 are being administered jointly under the caption ~~n March 2020,~~In re Gulfport Energy Corporation, et al., Case No. 20-35562 (DRJ). The debtors continue to operate their businesses as "debtors-in-possession" under the ~~World Health Organization classified~~jurisdiction of the ~~outbreak~~Bankruptcy Court, in accordance with the applicable provisions of COVID-19 as a pandemic and recommended containment and mitigation measures worldwide. The measures have led to worldwide shutdowns and halting of commercial and interpersonal activity, as governments around the ~~world have imposed regulations in efforts to control the spread of COVID-19 such as shelter-in-place orders, quarantines, executive orders and similar restrictions.~~

~~Gulfport remains focused on~~ ~~protecting the health and well-being of its employees~~Bankruptcy Code and the ~~communities~~orders of the Bankruptcy Court.

The commencement of a voluntary proceeding in ~~which it operates while assuring~~bankruptcy constituted an event of default that accelerated the ~~continuity~~Company's obligations under the Company's Pre-Petition Revolving Credit Facility and the indentures governing the Company's senior notes, resulting in the principal and interest due thereunder becoming immediately due and payable. Subject to certain specific exceptions under the Bankruptcy Code, the filing of ~~its business operations. The Company~~ ~~implemented preventative measures and developed corporate and field response plans to minimize unnecessary risk of exposure and prevent infection. Additionally,~~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 are subject to settlement under the Bankruptcy Code.

The Company has ~~a crisis management team~~applied FASB ASC Topic 852 - Reorganizations ("ASC 852") in preparing the consolidated financial statements, which specifies the accounting and financial reporting requirements for ~~health, safety~~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 have been classified as liabilities subject to compromise on the consolidated balance sheets as of March 31, 2021 and ~~environmental matters~~December 31, 2020. Additionally, certain expenses, realized gains and ~~personnel issues,~~losses and ~~has established a COVID-19 Response Team~~provisions for losses that are realized or incurred during the Chapter 11 Cases are recorded as reorganization items, net in the consolidated statements of operations for the three months ended March 31, 2021. Refer to ~~address various~~Note 2 for more information on the events of the bankruptcy proceedings as well as the accounting and reporting impacts of the ~~situation,~~reorganization.

Ability to Continue as ~~they have been developing. Gulfport has modified certain business practices (including remote working for its corporate employees~~a Going Concern

The accompanying unaudited consolidated financial statements are prepared in accordance with generally accepted accounting principles applicable to a going concern, which contemplates the realization of assets and ~~restricted employee business travel) to conform to government restrictions and best practices encouraged by~~ the ~~Centers for Disease Control and Prevention,~~satisfaction of liabilities in the ~~World Health Organization and other governmental and regulatory authorities. In May 2020,~~normal course of business.

As discussed above, the Company began its phased transition back to the office for its corporate employees. As part of this transition, the Company put into place preventative measures to focus on social distancing and minimizing unnecessary risk of exposure. Asfiling of the ~~date~~Chapter 11 Cases constituted an event of ~~this filing, Gulfport has transitioned approximately 60% of its corporate employees back to~~default under the ~~corporate office. The Company will continue to monitor trends and governmental guidelines and may adjust its return to office plans accordingly to ensure the health and safety of its employees.~~ ~~As a result of its business continuity measures, the Company has not experienced significant disruptions in executing its business operations in 2020.~~

~~Gulfport is closely monitoring the impact of COVID-19 on all aspects of its business~~Company’s Pre-Petition Revolving Credit Facility and the ~~current commodity price environment and is unable to predict the impact it will have on its future financial position or operating results. I~~n response to the current commodity price environment, the Company voluntarily shut-in a portion of its production during the second quarter of 2020 and announced tiered salary reduction for most employees, senior management team and the Board of Directors beginning in June 2020 with such measures expected to last through December 2020. Additionally, select furloughs were implemented to reduce costs and preserve liquidity.

On March 27, 2020, the U.S. government enacted the Coronavirus Aid, Relief, and Economic Security Act (“CARES Act”). The CARES Act did not have a material impact on the Company’s consolidated financial statements.

~~Liquidity, Management's Plans and Going Concern~~

~~As noted above, decreased demand for oil and natural gas as a result of the COVID-19 pandemic and the accompanying decrease in commodity prices has significantly impaired~~indentures governing the Company's ~~ability to access capital markets and to refinance its~~senior notes (the "Default"), resulting in the principal

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~~existing indebtedness. Further,~~and interest due thereunder becoming immediately due and payable. The Company does not have sufficient cash on hand or available liquidity to repay these amounts due. These conditions ~~have made amendments or waivers to its revolving credit facility more difficult to obtain~~ and available on terms less favorable to the Company. If depressed commodity prices persist or decline further, the borrowing base under the Company's revolving credit facility could be further reduced at its next scheduled redetermination date in November 2020. Any such reduction would constrain the Company's liquidity and may impair its ability to fund its planned capital expenditures and meet its obligations under its existing indebtedness. Further, a reduction in the Company's capital expenditures would decrease its production, revenues, operating cash flow and EBITDA, which could limit its ability to comply with the restrictive covenants in its revolving credit facility and other existing indebtedness. Finally, the Company's existing revolving credit facility matures in December 2021 and therefore will become a current liability at year end 2020 unless the Company is able to refinance the credit facility with a new credit facility or other financing. Considering the current state of the first lien market and the Company's elevated leverage profile, there is substantial risk that a refinancing will not be available to the Company on reasonable terms. A current liability under the revolving credit facility at year end 2020 may result in a qualified audit opinion which could result in a default under the terms of the current revolving credit facility. As a result of these uncertainties and other factors, management has concluded that there isevents raise substantial doubt about the ~~Company's~~Company’s ability to continue as a going concern. Failure to meet the Company's obligations under its existing indebtedness or failure to comply with any of its covenants, if not waived, would result in an event of default under such indebtedness and result in the potential acceleration of outstanding indebtedness thereunder and, with respect to the revolving credit facility, the potential foreclosure on the collateral securing such debt, and could cause a cross-default under its other outstanding indebtedness.

InAs part of the ~~current depressed commodity price environment~~Chapter 11 Cases, the Company submitted the Plan to the Bankruptcy Court. The Company’s operations and ~~period~~its ability to develop and execute its business plan are subject to a high degree of ~~economic~~risk and uncertainty associated with the Chapter 11 Cases. As discussed in Note 14, an order was entered by the Bankruptcy Court confirming the Company's Plan on April 28, 2021 and it expects to emerge from bankruptcy in May 2021. However, there can be no assurance that the Company will consummate the confirmed Plan, and as a result, the Company has taken various steps over the last several months to improve its balance sheet and preserve liquidity including (1) exercising capital discipline by reducing 2020 capital spending by 50% as compared to 2019, (2) focusing on operational efficiencies to reduce operating costs as evidenced by the recent reductions in Development and Completion costs per lateral foot, (3) reducing corporate general and administrative costs significantly, (4) and repurchasing unsecured notes at a deep discount.

~~Although~~concluded that management’s actions listed above have helped to improve our liquidity and leverage profile, continued macro headwinds including the depressed state of energy capital markets and the extraordinarily low commodity price environments present significant risks to the Company's ability to fund its operations going forward. Accordingly, management has determined there isplans do not alleviate substantial doubt about ~~its~~the Company’s ability to continue as a going concern over the next twelve months from the issuance of these financial statements. The Company has engaged financial and legal advisors to assist with the evaluation of a range of liability management alternatives. Additionally, the Company maintains an active dialogue with its senior lenders and bondholders regarding liability management alternatives to improve its balance sheet. There can be no assurances that the Company will be able to successfully complete a liability management transaction that materially improves the Company’s leverage profile or liquidity position.concern.

~~The~~While operating as a debtor-in-possession, the Company may settle liabilities, subject to the approval of the Bankruptcy Court or as otherwise permitted in the ordinary course of business, for amounts other than those reflected in the accompanying consolidated financial statements. Further, the Plan or other bankruptcy proceedings could materially change the amounts and classifications of assets and liabilities reported in the consolidated financial statements, ~~(i) have been prepared on a going concern basis,~~including liabilities subject to compromise which ~~contemplates~~will be resolved in connection with the ~~realization of assets and satisfaction of liabilities and other commitments in the normal course of business and (ii)~~Chapter 11 Cases. The accompanying unaudited consolidated financial statements do not include any adjustments related to ~~reflect the possible future effects of the uncertainty on~~ the recoverability orand classification of ~~recorded asset amounts~~assets or the amounts and classification of liabilities or ~~classifications~~any other adjustments that might be necessary should the Company be unable to continue as a going concern or as a consequence of ~~liabilities.~~the Chapter 11 Cases.

Impact on Previously Reported Results

During the third quarter of ~~2019,~~2020, the Company identified that certain ~~activities~~firm transportation costs incurred in prior periods were misclassified ~~between cash flows from operating activities and cash flows from investing activities. These activities had been included in accounts payable, accrued liabilities and other and presented~~ as ~~cash flows from operating activities~~deducts to "natural gas sales" while they should have been ~~presented as additions to oil~~included in "transportation, gathering, processing and ~~natural gas properties in cash flows from investing activities.~~compression" on its consolidated statements of operations. The Company ~~corrected~~assessed the materiality of this presentation on prior periods’ consolidated financial statements in accordance with the SEC Staff Accounting Bulletin No. 99, “Materiality”, codified in ASC Topic 250, “Accounting Changes and Error Corrections”. Based on this assessment, the Company concluded that the correction is not material to any previously ~~presented~~issued financial statements. The correction had no impact on its consolidated balance sheets, consolidated statements of ~~cash flows for these additions and in doing so, for the six months ended June 30, 2019 contained herein, the~~comprehensive income, consolidated statements of stockholders' equity or consolidated statements of cash ~~flows and~~flows. Additionally, the ~~condensed consolidating~~error had no impact on net loss or net loss per share. The Company will conform presentation of previously reported consolidated statements of ~~cash flows were adjusted to increase net cash flows provided by operating activities by $90.8 million with a corresponding increase~~operations in ~~net cash flows used in investing activities.~~future filings. The ~~Company has evaluated~~following tables present the effect of the ~~previous presentation, both qualitatively and quantitatively, and concluded that it did not have a material impact~~correction on ~~any~~all affected line items of our previously ~~filed annual or quarterly~~issued consolidated financial ~~statements.~~statements of operations for the three months ended March 31, 2020.

~~Recently Adopted Accounting Standards~~

~~On January 1, 2020, the Company adopted ASU No. 2016-13,~~ ~~Financial Instruments-Credit Losses: Measurement of Credit Losses on Financial Instruments~~, which replaces the incurred loss impairment methodology with a methodology that reflects expected credit losses and requires consideration of a broader range of reasonable and supportable information to inform credit loss estimates. The measurement of expected credit losses is based on relevant information about past events, including historical experience, current conditions and reasonable and supportable forecasts that affect the collectibility of the


	Three months ended March 31, 2020
	As Reported		Adjustments		As Revised
	(In thousands)
Natural gas sales	$	108,547	$	52,461	$	161,008
Total Revenues	$	246,877	$	52,461	$	299,338
Transportation, gathering, processing and compression	$	57,896	$	52,461	$	110,357
Total Operating Expenses	$	726,964	$	52,461	$	779,425

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~~reported amount.~~Supplemental Cash Flow and Non-Cash Information


	Three months ended March 31,
	2021		2020
Supplemental disclosure of cash flow information:	(In thousands)
Cash paid for reorganization items, net	$	21,367	$	0
Interest payments	$	4,763	$	14,034
Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable - oil and natural gas sales	$	(14,117)	$	47,111
(Increase) decrease in accounts receivable - joint interest and other	(478)		6,001
Increase (decrease) in accounts payable and accrued liabilities	15,555		(7,637)
(Increase) decrease in prepaid expenses	26,356		(6,920)
(Increase) decrease in other assets	(655)		1
Total changes in operating assets and liabilities	$	26,661	$	38,556
Supplemental disclosure of non-cash transactions:
Capitalized stock-based compensation	$	630	$	934
Asset retirement obligation capitalized	$	483	$	381
Asset retirement obligation removed due to divestiture	$	0	$	(2,033)
Interest capitalized	$	0	$	187
Fair value of contingent consideration asset on date of divestiture	$	—	$	23,090
Foreign currency translation gain (loss) on equity method investments	$	2,570	$	(15,030)

2.CHAPTER 11 PROCEEDINGS

Restructuring Support Agreement

On November 13, 2020, the Debtors commenced the Chapter 11 Cases as described in Note 1 above. To ensure ordinary course operations, the Debtors have obtained approval from the Bankruptcy Court for certain first- and second-day motions, including motions to obtain customary relief intended to continue ordinary course operations after the Petition Date. In addition, the Debtors have received authority to use cash collateral of the lenders under the DIP Credit Facility.

On November 13, 2020, the Debtors entered into a restructuring support agreement with (i) over 95% of the lenders (the “Consenting RBL Lenders”) party to the Pre-Petition Revolving Credit Facility, dated as of December 27, 2013, by and among the Company, as borrower, each of the lenders party thereto, the Bank of Nova Scotia, as administrative agent and issuing bank, the joint lead arrangers and joint bookrunners, the co-syndication agents, and the co-documentation agents and (ii) certain holders (the “Consenting Noteholders,” and, together with the Consenting RBL Lenders, the “Consenting Stakeholders”) holding over two-thirds of the Company’s (a) 6.625% senior notes due 2023, issued under that certain Indenture, dated as of April 21, 2015, (b) 6.000% senior notes due 2024, issued under that certain Indenture, dated as of October 14, 2016, (c) 6.375% senior notes due 2025, issued under that certain Indenture, dated as of December 21, 2016, and (d) 6.375% senior notes due 2026, issued under that certain Indenture, dated as of October 11, 2017 (collectively, the “Unsecured Notes”), each by and among the Company, the subsidiary guarantors party thereto, and UMB Bank, N.A. as successor trustee.

The RSA outlines the key elements and actions the Company plans to take as part of Chapter 11 process, including equitizing a significant portion of its prepetition indebtedness and rejecting or renegotiating certain contracts which will result in a materially improved balance sheet and cost structure. The RSA contains certain covenants on the part of each of Gulfport and the Consenting Stakeholders, including commitments by the Consenting Stakeholders to vote in favor of the Plan and commitments of Gulfport and the Consenting Stakeholders to negotiate in good faith to finalize the documents and agreements governing the Restructuring. The RSA also places certain conditions on the obligations of the parties and provides that the RSA may be terminated upon the occurrence of certain events, including, without limitation, the failure to achieve certain milestones and certain breaches by the parties under the RSA. One such condition is the requirement of the Company to obtain certain levels of savings on certain midstream obligations (as set forth in the RSA) through rejection of such contracts and/or renegotiation of their terms.

Plan of Reorganization

On April 28, 2021, the Bankruptcy Court entered an order confirming the Amended Joint Chapter 11 Plan of Reorganization of Gulfport Energy Corporation and Its Debtor Subsidiaries (the "Plan"). The Company ~~adopted~~expects the effective

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date of the Plan will occur once all conditions precedent to the Plan have been satisfied (the "Effective Date"). Below is a summary of the material terms of the Plan as approved and confirmed by the Bankruptcy Court. This summary highlights only certain substantive provisions of the Plan and is not intended to be a complete description of the Plan. Capitalized terms used under this heading but not otherwise defined herein shall have the meaning given to such terms in the Plan, which has been included as an exhibit to this Form 10-Q:

•the RBL Lenders and DIP Lenders, each with The Bank of Nova Scotia as administrative agent, have agreed that the RBL Credit Facility and DIP Facility, respectively, will convert into the $580 million Exit Facility upon the Effective Date, subject to the terms and conditions set forth in the Exit Facility Documentation;

•certain members of the Ad Hoc Noteholder Group have agreed to backstop the Rights Offering of at least $50 million in exchange for New Preferred Stock;

•Holders of Allowed General Unsecured Claims against Gulfport Parent will receive their Pro Rata share of: (a) $10 million in Cash, subject to adjustment by the Unsecured Claims Distribution Trustee; (b) 100% of the Mammoth Shares; and (c) 4% of the New Common Stock of the Reorganized Debtors, subject to dilution and certain adjustments;

•Holders of Allowed Notes Claims against Gulfport Parent will waive their entitlement to a Cash recovery or any of the Mammoth Shares, and will cap their recovery at 96% of the New Common Stock of the Reorganized Debtors, which will be drawn first from the Gulfport Subsidiaries Equity Pool and then from the Gulfport Parent Equity Pool to the extent required due to dilution as a result of distributions made to General Unsecured Claims against Gulfport Subsidiaries (excluding distributions to Unsecured Surety Claims);

•Holders of Allowed Notes Claims against Gulfport Subsidiaries and Allowed General Unsecured Claims against Gulfport Subsidiaries will receive their Pro Rata share of: (a) the Gulfport Subsidiaries Equity Pool; (b) the New Unsecured Notes; and (c) the Rights Offering Subscription Rights;

•a Class of Convenience Claims consisting of (a) Allowed General Unsecured Claims of $300,000 or less or (b) Allowed General Unsecured Claims over $300,000 that the applicable Holder has irrevocably elected to have reduced to $300,000 and treated as Convenience Claims, will share in a $3,000,000 Cash distribution pool, which the Unsecured Claims Distribution Trustee may increase by an additional $2,000,000 by reducing the Gulfport Parent Cash Pool;

•an Unsecured Claims Distribution Trustee will administer a trust to make distributions to Allowed General Unsecured Claims and Allowed Convenience Claims and to exercise certain consent rights with respect to the settlement and Allowance of disputed General Unsecured Claims and Convenience Claims;

•each Intercompany Claim shall be cancelled in exchange for the distributions contemplated by the Plan to Holders of Claims against and Interests in the respective Debtor entities and shall be considered settled pursuant to Bankruptcy Rule 9019;

•each Holder of an Intercompany Interest shall receive no recovery or distribution and shall be Reinstated solely to the extent necessary to maintain the Debtors’ prepetition corporate structure for the ultimate benefit of the Holders of New Common Stock and New Preferred Stock; and

•the Existing Interests in Gulfport Parent will be cancelled, released, and extinguished, and will be of no further force or effect, without any distribution.

DIP Credit Facility

Pursuant to the RSA, the Consenting RBL Lenders have 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 ~~standard~~money and (b) $157.5 million to roll up a portion of the existing outstanding obligations under the Pre-Petition Revolving Credit Facility. The proceeds of the DIP Credit Facility may be 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. The DIP Credit Facility was approved by the Bankruptcy Court on a final basis on December 18, 2020. See Note 5 for additional information.

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Executory Contracts

Subject to certain exceptions, under the Bankruptcy Code, the Company may assume, assign, or reject certain executory contracts and unexpired leases subject to the approval of the Bankruptcy Court and certain other conditions. Generally, the rejection of an executory contract or unexpired lease is treated as a pre-petition breach of such executory contract or unexpired lease and, subject to certain exceptions, relieves the Company from performing its future obligations under such executory contract or unexpired lease but entitles the contract counterparty or lessor to a pre-petition general unsecured claim for damages caused by such deemed breach. Counterparties to rejected contracts or leases may assert unsecured claims in the Bankruptcy Court against the Company's estate for such damages. Generally, the assumption of an executory contract or unexpired lease requires the Company to cure existing monetary defaults under such executory contract or unexpired lease and provide adequate assurance of future performance. Accordingly, any description of an executory contract or unexpired lease with the Company, including where applicable a quantification of the Company's obligations under any such executory contract or unexpired lease of the Company, is qualified by any overriding rejection rights it has under the Bankruptcy Code.

Potential Claims

The Company has filed with the Bankruptcy Court schedules and statements setting forth, among other things, the assets and liabilities of the Company and each of its subsidiaries, subject to the assumptions filed in connection therewith. These schedules and statements may be subject to further amendment or modification after filing. Certain holders of pre-petition claims that are not governmental units were required to file proofs of claim by the deadline for general claims, which was set by the Bankruptcy Court as January 26, 2021. Governmental units are required to file proof of claims by May 12, 2021, the deadline that was set by the Bankruptcy Court.

As of April 30, 2021, the Debtors have received approximately 2,700 proofs of claim for an aggregate amount of approximately $13 billion. The Company will continue to evaluate these claims throughout the Chapter 11 process and recognize or adjust amounts in future financial statements as necessary using the ~~prospective transition method,~~best information available at such time. Differences between amounts scheduled by the Company and ~~it did~~claims by creditors will ultimately be reconciled and resolved in connection with the claims resolution process. In light of the expected number of creditors, the claims resolution process may take considerable time to complete and likely will continue after the Company emerges from bankruptcy.

Financial Statement Classification of Liabilities Subject to Compromise

The accompanying consolidated balance sheets as of March 31, 2021 and December 31, 2020 include amounts classified as liabilities subject to compromise, which represent liabilities the Company anticipates will be allowed as claims in the Chapter 11 Cases. These amounts represent the Company's current estimate of known or potential obligations to be resolved in connection with the Chapter 11 Cases, and may differ from actual future settlement amounts paid. Differences between liabilities estimated and claims filed, or to be filed, will be investigated and resolved in connection with the claims resolution process. The Company will continue to evaluate these liabilities throughout the Chapter 11 process and adjust amounts as necessary. Such adjustments may be material.

Liabilities subject to compromise includes amounts related to the rejection of various executory contracts. Additional amounts may be included in liabilities subject to compromise in future periods if additional executory contracts and/or unexpired leases are rejected. The nature of many of the potential claims arising under the Company's executory contracts and unexpired leases has not been determined at this time, and therefore, such claims are not reasonably estimable at this time and may be material. Damages related to rejected contracts are accounted for after they have ~~a material impact~~been approved for rejection by the Bankruptcy Court.

The following table summarizes the components of liabilities subject to compromise included on the Company's consolidated ~~financial statements~~balance sheets as of March 31, 2021 and ~~related disclosures.~~December 31, 2020:

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	March 31, 2021		December 31, 2020
	(in thousands)
Debt subject to compromise	$	2,003,004	$	2,005,219
Accounts payable and accrued liabilities	134,344		164,939
Asset retirement obligations	64,854		63,566
Accrued interest on debt subject to compromise	55,159		55,634
Other liabilities	4,092		4,122
Liabilities subject to compromise	$	2,261,453	$	2,293,480

Interest Expense

The Company has discontinued recording interest on debt instruments classified as liabilities subject to compromise as of the Petition Date. The contractual interest expense on liabilities subject to compromise not accrued in the consolidated statements of operations was approximately $28.5 million for the three months ended March 31, 2021.

Reorganization Items, Net

The Company has incurred and will continue to incur significant expenses, gains and losses associated with the reorganization, primarily the write-off of unamortized debt issuance costs, debt and equity financing fees, adjustments to allowed claims and legal and professional fees incurred subsequent to the Chapter 11 filings related to the restructuring process. The amount of these items, which are being incurred in reorganization items, net within the Company's accompanying audited consolidated statements of operations, are expected to significantly affect the Company's statements of operations. The Company has incurred adjustments for allowable claims related to its legal proceedings and executory contracts approved for rejections by the Bankruptcy Court, with additional adjustments possible in future periods.

The following table summarizes the components in reorganization items, net included in the Company's consolidated statements of operations for the three months ended March 31, 2021:


	Three months ended March 31, 2021
	(in thousands)
Legal and professional fees	$	40,783
Adjustment to allowed claims	2,088


Gain on settlement of pre-petition accounts payable	(4,150)
Reorganization items, net	$	38,721

3.PROPERTY AND EQUIPMENT

The major categories of property and equipment and related accumulated ~~depletion, depreciation, amortization ("~~DD~~&A")~~&A and impairment as of ~~June 30, 2020~~March 31, 2021 and December 31, ~~2019~~2020 are as follows:


		June 30, 2020		December 31, 2019			March 31, 2021		December 31, 2020
		(In thousands)							(In thousands)
Oil and natural gas properties	Oil and natural gas properties	$	10,730,992	$	10,595,735	Oil and natural gas properties	$	10,895,625	$	10,816,909
Accumulated DD&A and impairment		(8,415,756)		(7,191,957)
Oil and natural gas properties, net		2,315,236		3,403,778
Other depreciable property and equipment	Other depreciable property and equipment	91,317		91,198		Other depreciable property and equipment	85,827		85,530
Land	Land	5,521		5,521		Land	3,008		3,008
Accumulated DD&A		(41,708)		(36,703)
Other property and equipment, net		55,130		60,016
Total property and equipment						Total property and equipment	10,984,460		10,905,447
Accumulated DD&A and impairment						Accumulated DD&A and impairment	(8,874,899)		(8,819,178)
Property and equipment, net	Property and equipment, net	$	2,370,366	$	3,463,794	Property and equipment, net	$	2,109,561	$	2,086,269

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Under the full cost method of accounting, the Company is required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the Company's oil and natural gas properties. At ~~June 30, 2020,~~March 31, 2021, the net book value of the Company's oil and gas properties ~~less related deferred income taxes,~~ was ~~above~~below the calculated ceiling ~~primarily as a result of reduced commodity prices~~ for the period leading up to ~~June 30, 2020.~~March 31, 2021. As a result, the Company ~~was required to record impairments~~recorded 0 impairment of its oil and natural gas properties for the three months ended March 31, 2021. The Company recorded an impairment of its oil and natural gas properties of ~~$532.9~~$553.3 million ~~and $1.1 billion~~ for the three ~~and six~~ months ended ~~June 30, 2020, respectively. NaN impairments were required for oil and natural gas properties for the three and six months ended June 30, 2019.~~

~~Based on prices for the last nine months and the short-term pricing outlook for the third quarter of 2020, the Company expects to recognize additional full cost impairments in the third quarter of~~March 31, 2020. The amount of any future impairments is difficult to predict as it depends on future commodity prices, production rates, proved reserves, evaluation of costs excluded from amortization, future development costs and production costs. Any future full cost impairments are not expected to have an impact to the Company's future cash flows or liquidity.

~~General~~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 such as geological and other costs associated with overseeing exploration and development~~ activities. All general and administrative costs not ~~directly associated with exploration and development activities~~capitalized are charged to expense as they are incurred. Capitalized general and administrative costs were approximately ~~$8.2~~$5.5 million and ~~$13.6~~$5.4 million for the three ~~and six~~ months ended ~~June 30,~~March 31, 2021 and 2020, ~~respectively, and $8.8 million and $16.5 million for the three and six months ended June 30, 2019,~~ respectively.

The average depletion rate per Mcfe, which is a function of capitalized costs, future development costs and the related underlying reserves in the periods presented, was $0.73 and $1.00 per Mcfe for the six months ended June 30, 2020 and 2019, respectively.

The following table summarizes the Company’s unevaluated properties excluded from amortization by area at ~~June 30, 2020:~~March 31, 2021:


	~~June 30, 2020~~March 31, 2021
	(In thousands)
Utica	$	~~874,886~~761,397
~~MidContinent~~SCOOP	~~687,169~~651,451
Other	~~2,134~~926
	$	~~1,564,189~~1,413,774

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At December 31, ~~2019,~~2020, approximately ~~$1.7~~$1.5 billion of unevaluated properties were not subject to amortization.

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.

Impairment of Other Property and Equipment

During the three months ended March 31, 2021, the Company recorded an impairment of $14.6 million related to its corporate headquarters as a result of changes in the expected future use.

Asset Retirement Obligation

A reconciliation of the Company’s asset retirement obligation for the ~~six~~three months ended ~~June 30,~~March 31, 2021 and 2020 ~~and 2019~~ is as follows:


		June 30, 2020		June 30, 2019			March 31, 2021		March 31, 2020
		(In thousands)							(In thousands)
Asset retirement obligation, beginning of period	Asset retirement obligation, beginning of period	$	60,355	$	79,952	Asset retirement obligation, beginning of period	$	63,566	$	60,355
Liabilities incurred	Liabilities incurred	1,553		5,153		Liabilities incurred	483		381
Liabilities settled		—		(117)

Liabilities removed due to divestitures	Liabilities removed due to divestitures	(2,033)		—		Liabilities removed due to divestitures	0		(2,033)
Accretion expense	Accretion expense	1,496		2,426		Accretion expense	805		741
Revisions in estimated cash flows		—		1,077
Asset retirement obligation as of end of period		61,371		88,491

Total asset retirement obligation as of end of period						Total asset retirement obligation as of end of period	$	64,854	$	59,444
Less: amounts reclassified to liabilities subject to compromise						Less: amounts reclassified to liabilities subject to compromise	$	(64,854)	$	0
Total asset retirement obligation reflected as non-current liabilities						Total asset retirement obligation reflected as non-current liabilities	$	0	$	59,444

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3.~~DIVESTITURES~~

~~Sale of Water Infrastructure Assets~~

On January 2, 2020, the Company closed on the sale of its SCOOP water infrastructure assets to a third-party water service provider. The Company received $50.0 million in cash proceeds upon closing and has an opportunity to earn potential additional incentive payments over the next 15 years, subject to the Company's ability to meet certain thresholds which will be driven by, among other things, the Company's future development program and water production levels. The agreement contained no minimum volume commitments. The fair value of the contingent consideration as of the closing date was $23.1 million. The divested assets were included in the amortization base of the full cost pool and 0 gain or loss was recognized in the accompanying consolidated statements of operations as a result of the sale.

4.EQUITY INVESTMENTS

Investments accounted for by the equity method consist of the following as of ~~June 30, 2020~~March 31, 2021 and December 31, ~~2019:~~2020:


				Carrying value						(Loss) income from equity method investments																								Carrying value			Loss from equity method investments
		Approximate ownership %		June 30, 2020		December 31, 2019		Three months ended June 30,								Six months ended June 30,									Approximate ownership %			March 31, 2021			December 31, 2020			Three months ended March 31,
												2020			2019			2020			2019			Approximate ownership %			March 31, 2021			December 31, 2020			2021			2020
				(In thousands)																														(In thousands)
Investment in Grizzly Oil Sands ULC	Investment in Grizzly Oil Sands ULC	24.6	%	$	13,013	$	21,000	$	(45)	$	54		(188)			$	(339)	Investment in Grizzly Oil Sands ULC	24.5	%		$	27,044					$	24,816		$	(342)		$	(143)
Investment in Mammoth Energy Services, Inc.	Investment in Mammoth Energy Services, Inc.	21.5	%	—		11,005		—		(127,581)			(10,646)			(123,055)		Investment in Mammoth Energy Services, Inc.	21.5	%		0			0			0			(10,646)
Investment in Windsor Midstream LLC		22.5	%	39		39		—		—			—			—
Investment in Tatex Thailand II, LLC		23.5	%	—		—		—		1,945			—			2,085
				$	13,052	$	32,044	$	(45)	$	(125,582)		$	(10,834)		$	(121,309)
																						$	27,044		$	24,816		$	(342)		$	(10,789)

The tables below summarize financial information for the Company’s equity investments as of ~~June 30, 2020~~March 31, 2021 and December 31, ~~2019.~~2020.

Summarized balance sheet information:

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		June 30, 2020		December 31, 2019			March 31, 2021		December 31, 2020
											December 31, 2020
		(In thousands)										(In thousands)
Current assets	Current assets	$	434,966	$	421,326	Current assets	$	462,478	$	483,303
Noncurrent assets	Noncurrent assets	$	1,107,221	$	1,260,075	Noncurrent assets	$	1,079,557	$	1,092,495
Current liabilities	Current liabilities	$	115,281	$	132,569	Current liabilities	$	125,359	$	132,978
Noncurrent liabilities	Noncurrent liabilities	$	172,478	$	163,241	Noncurrent liabilities	$	124,628	$	148,240

Summarized results of operations:


		Three months ended June 30,						Six months ended June 30,							Three months ended March 31,
		2020		2019		2020		2019			2021		2020
		(In thousands)														(In thousands)
Gross revenue	Gross revenue	$	60,109	$	179,114	$	157,492	$	443,958	Gross revenue	$	66,805	$	97,383
Net (loss) income		$	(14,922)	$	(4,072)	$	(99,953)	$	20,684
Net loss										Net loss	$	(13,606)	$	(85,031)

Grizzly Oil Sands ULC

The Company, through its wholly owned subsidiary Grizzly Holdings, ~~Inc. (“Grizzly Holdings”),~~ owns an approximate ~~24.6%~~24.5% interest in Grizzly, ~~Oil Sands ULC (“Grizzly”),~~ a Canadian unlimited liability company. ~~The remaining interest in Grizzly is owned by Grizzly Oil Sands Inc.~~ As of ~~June 30, 2020,~~March 31, 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 reviewed its investment in Grizzly for impairment at ~~June 30,~~March 31, 2021 and 2020 ~~and 2019~~ and determined 0 impairment was required. The Company has 0t paid ~~$0.4 million in~~any cash calls ~~during the six months ended June 30, 2019 prior to~~since its election to cease funding further capital ~~calls.~~calls in 2019. Grizzly’s functional currency is the Canadian dollar. The Company’s investment in Grizzly increased by ~~$6.9~~$2.6 million as a result of a foreign currency translation gain and decreased by ~~$7.8~~$14.7 million as a result of a foreign currency translation loss for the three ~~and six~~ months ended ~~June 30,~~March 31, 2021 and 2020, respectively. ~~The Company's investment in Grizzly was increased by $3.5 million and $7.3 million for the three and six months ended June 30, 2019, respectively, as a result of a foreign currency translation gain.~~

Mammoth Energy Services, Inc.

At ~~June 30, 2020,~~March 31, 2021, the Company owned 9,829,548 shares, or approximately 21.5%, of the outstanding common stock of Mammoth Energy Services, Inc. ("Mammoth Energy"). The approximate fair value of the Company's investment in Mammoth Energy at ~~June 30, 2020~~March 31, 2021 was ~~$11.6~~$52.3 million based on the quoted market price of Mammoth Energy's common ~~stock~~stock.

At March 31, 2020, the Company's share of net loss of Mammoth was in excess of the carrying value of its investment. As such, the Company's investment value was reduced to ~~zero~~0 at March 31, 2020. During the ~~second~~first quarter of ~~2020,~~2021, the Company's

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share of net loss of Mammoth continued to be in excess of the carrying value of its investment and, therefore, the Company's investment value remained at 0 at ~~June 30, 2020.~~March 31, 2021.

The Company received 0 distributions from Mammoth Energy during the ~~six~~three months ended ~~June 30,~~March 31, 2021 and 2020, ~~and distributions of $2.5 million during the six months ended June 30, 2019 as a result of $0.125 per share dividends in February 2019 and May 2019.~~respectively. The loss ~~(income)~~ from equity method investments presented in the table above reflects any intercompany profit eliminations.

~~Windsor Midstream LLC~~

At June 30, 2020, the Company held a 22.5% interest in Windsor Midstream LLC (“Midstream”), an entity controlled and managed by an unrelated third party. The Company received 0 distributions from Midstream during the six months ended June 30, 2020.

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~~Tatex Thailand II, LLC~~

The Company has an indirect ownership interest in Tatex Thailand II, LLC ("Tatex") and received 0 distributions and $2.1 million in distributions from Tatex during the six months ended June 30, 2020 and 2019, respectively. Tatex previously held an 8.5% interest in APICO, LLC (“APICO”), an international oil and gas exploration company, before selling its interest in June 2019. APICO has a reserve base located in Southeast Asia through its ownership of concessions covering approximately 108,000 acres which includes the Phu Horm Field.

5.LONG-TERM DEBT

Long-term debt consisted of the following items as of ~~June 30, 2020~~March 31, 2021 and December 31, ~~2019:~~2020:

June 30, 2020 December 31, 2019
(In thousands)
Revolving credit agreement⁽¹⁾
$ 123,000 $ 120,000
6.625% senior unsecured notes due 2023 324,583 329,467
6.000% senior unsecured notes due 2024 579,568 603,428
6.375% senior unsecured notes due 2025 507,870 529,525
6.375% senior unsecured notes due 2026 374,617 397,529
Net unamortized debt issuance costs⁽²⁾
(20,802) (23,751)
Construction loan 22,131 22,453
Less: current maturities of long term debt (649) (631)
Debt reflected as long term $ 1,910,318 $ 1,978,020


	March 31, 2021		December 31, 2020
	(In thousands)
DIP credit facility	$	157,500	$	157,500
Pre-petition revolving credit facility	316,759		292,910
6.625% senior unsecured notes due 2023	324,583		324,583
6.000% senior unsecured notes due 2024	579,568		579,568
6.375% senior unsecured notes due 2025	507,870		507,870
6.375% senior unsecured notes due 2026	374,617		374,617
Building loan	21,914		21,914
Total Debt	2,282,811		2,258,962
Less: current maturities of long-term debt	(279,807)		(253,743)
Less: amounts reclassified to liabilities subject to compromise	(2,003,004)		(2,005,219)
Total Debt reflected as long term	$	0	$	0

~~(1)~~ Chapter 11 Proceedings

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 stays the creditors from taking any action as a result of the default.

The principal amounts from the 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 sheets as of March 31, 2021 and December 31, 2020.

Debtor-in-Possession Credit Agreement

Pursuant to the RSA, the Consenting RBL Lenders have agreed to provide the Company ~~has entered into~~with a senior secured superpriority debtor-in-possession revolving credit facility ~~as amended (the "revolving credit facility"), with~~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 ~~Bank~~terms and conditions of ~~Nova Scotia, as~~ the ~~lead arranger and administrative agent and other lenders. The~~DIP Credit Facility are set forth in that certain form of credit agreement ~~provides~~governing the DIP Credit Facility. The proceeds of the DIP Credit Facility may be 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. The DIP Credit Facility was approved by the Bankruptcy Court on a ~~maximum facility of $1.5 billion and matures~~final basis on December 13, 2021. On May 1, 2020, the Company entered into the fifteenth amendment to the Amended and Restated Credit Agreement. As part of the amendment, the Company's borrowing base and elected commitment were reduced from $1.2 billion and $1.0 billion, respectively, to $700.0 million. Additionally, the amendment added a requirement to maintain a ratio of Net Secured Debt to EBITDAX (as defined under the revolving credit agreement) not exceeding 2.00 to 1.00, deferred the requirement to maintain a ratio of Net Funded Debt to EBITDAX of 4.00 to 1.00 until September 30, 2021 and added a limitation on the repurchase of unsecured notes, among other amendments.

On July 27, 2020, the Company entered into the sixteenth amendment to the Amended and Restated Credit Agreement. The sixteenth amendment allows for the Company to issue up to $750 million in second lien debt subject to certain conditions. See ~~Note~~ 16 ~~for further information on this amendment.~~

18, 2020. As of ~~June 30, 2020, $123.0~~March 31, 2021, $157.5 million was outstanding under the ~~revolving credit facility~~DIP Credit Facility and the total availability for future borrowings under this facility, after giving effect to an aggregate of ~~$324.1~~$28.5 million letters of credit, was ~~$252.9~~$76.5 million. ~~The Company’s wholly owned subsidiaries~~

Borrowings under the DIP Credit Facility will mature, and the lending commitments thereunder will terminate, upon the earliest to occur of: (a) August 30, 2021; (b) three (3) business days after the Petition Date, if the Interim Order and Hedging Order have ~~guaranteed~~not been entered prior to the ~~obligations~~expiration of such period; (c) thirty five (35) days (or a later date consented to by the Administrative Agent and the Majority Lenders in their sole discretion) after the entry of the ~~Company~~Interim Order, if the Bankruptcy Court has not entered the Final Order on or prior to such date; (d) the effective date of an Approved Plan of Reorganization, (e)

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the consummation of a sale of all or substantially all of the equity and/or assets of the Debtors and budgeted and necessary expenses of the estates; (f) the date of the payment in full, in cash, of all Obligations (and the termination of all Commitments in accordance with the terms hereof); and (g) the date of termination of all Commitments and/or the acceleration of all of the Obligations under the Agreement and the other Loan Documents following the occurrence and during the continuance of an Event of Default.

Borrowings under the DIP Credit Facility bear interest at a eurodollar rate or base rate, at our election, plus an applicable margin of 4.50% per annum for eurodollar loans and 3.50% per annum for base rate loans. At March 31, 2021, amounts borrowed under the DIP credit facility bore interest at a weighted average rate of 5.50%. In addition to paying interest on outstanding principal and letters of credit posted under the DIP Credit Facility, we are required to pay a commitment fee of 0.50% per annum to the lenders of the DIP Credit Facility in respect of the unutilized DIP commitments thereunder and a letter of credit fee equal to 0.20% per annum.

The DIP Credit Facility includes negative covenants that, subject to significant exceptions, limit the Company's ability and the ability of its restricted subsidiaries to, among other things, (i) create liens on assets, property revenues, (ii) make investments, (iii) incur additional indebtedness, (iv) engage in mergers, consolidations, liquidations and dissolutions, (v) sell assets, (vi) pay dividends and distributions or repurchase capital stock, (vii) cease for any reason to be the operator of its properties, (viii) enter into letters of credit without prior written consent, (ix) enter into certain commodity hedging contracts except commodity hedging contracts with terms approved by the Bankruptcy Court in the hedging order or certain interest rate contracts, (x) change lines of business, (xi) engage in certain transactions with affiliates and (xii) incur more than a certain amount in capital expenditures in any calendar month. The DIP Credit Facility includes certain customary representations and warranties, affirmative covenants and events of default, including but not limited to defaults on account of nonpayment, breaches of representations and warranties and covenants, certain bankruptcy-related events, certain events under ERISA, material judgments and a change in control. If an event of default occurs, the lenders under the DIP Credit Facility will be entitled to take various actions, including the acceleration of all amounts due under the DIP Credit Facility and all actions permitted to be taken under the loan documents or application of law. In addition, the DIP Credit Facility is subject to various other financial performance covenants, including compliance with certain financial metrics and adherence to a budget approved by the Company's DIP Credit Facility lenders.

Pre-Petition Revolving Credit Facility

The Company has 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. On October 8, 2020, the Company's borrowing base under its Pre-Petition Revolving Credit Facility was reduced from $700 million to $580 million, thereby significantly reducing the Company's available liquidity. On October 15, 2020, the Company elected to not pay interest on certain Senior Notes outstanding triggering a default under the credit agreement. There was $316.8 million of outstanding borrowings under the Pre-Petition Revolving Credit Facility as of March 31, 2021 that were not rolled up into the DIP Credit Facility. This amount of indebtedness will remain outstanding throughout the Chapter 11 Cases and will continue to accrue interest at the default interest rate on amounts drawn after the Petition Date. The Company made certain adequate protection payments of $2.2 million on its Pre-Petition Revolving Credit Facility during the three months ended March 31, 2021 which reduced the amount of outstanding borrowings under the Pre-Petition Revolving Credit Facility classified as liabilities subject to compromise as of March 31, 2021 in the accompanying consolidated balance sheets.

During the first quarter of 2021, $26.1 million was drawn on letters of credit secured by the Company's Pre-Petition Revolving Credit Facility by certain of its firm transportation contract counterparties. As these were post-petition activities, these letters of credit drawn are included in current portion of long-term debt in the accompanying consolidated balance sheets. At March 31, 2021 the Company included $99.1 million in prepaid and other current assets in the accompanying consolidated balance sheets as an offset for the drawn letters of credit. A portion of the drawn letters of credit were netted against accounts payable to the Company's firm transportation contract counterparties.

Additionally, as of March 31, 2021, the Company had an aggregate of $121.2 million of letters of credit outstanding and 0 availability for future borrowings under its Pre-Petition Revolving Credit Facility. This facility is secured by substantially all of the Company's assets. All of the Company's wholly-owned subsidiaries, excluding Grizzly Holdings and Mule Sky, guarantee our obligations under our revolving credit facility.

At ~~June 30, 2020,~~March 31, 2021, amounts borrowed under the revolving credit facility bore interest at a weighted average rate of ~~2.44%~~3.12%.

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Capitalization of Interest

The Company ~~was in compliance with its financial covenants under the revolving credit facility at June 30, 2020.~~

(2) Loan issuance costs related to the 6.625% Senior Notes due 2023 (the "2023 Notes"), the 6.000% Senior Notes due 2024 (the "2024 Notes"), the 6.375% Senior Notes due 2025 (the "2025 Notes") and the 6.375% Senior Notes due 2026 (the "2026 Notes") (collectively the “Notes”) have been presented as a reduction to the principal amount of the Notes. At June 30, 2020, total unamortized debt issuance costs were $2.8 milliondid 0t capitalize interest expense for the ~~2023 Notes, $6.1 million for the 2024 Notes, $8.5 million for the 2025 Notes~~three months ended March 31, 2021 and ~~$3.4 million for the 2026 Notes. In addition, loan commitment fee costs for the Company's construction loan agreement were $0.1 million at June 30, 2020.~~

~~The Company~~ capitalized approximately ~~$0.5~~$0.2 million ~~and $0.7 million~~ in interest expense related to its unevaluated oil and natural gas properties during the three ~~and six~~ months ended ~~June 30, 2020, respectively. The Company capitalized approximately $1.0~~

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~~million and $1.8 million in interest expense to its unevaluated oil and natural gas properties during the three and six months ended June 30, 2019, respectively.~~

~~Debt Repurchases~~

In 2019, the Company's Board of Directors authorized $200 million of cash to be used to repurchase its senior notes in the open market at discounted values to par. The Company used borrowings under its revolving credit facility to repurchase in the open market $47.5 million and $73.3 million aggregate principal amount of its outstanding Notes for $12.6 million and $22.8 million during the three and six months ended June 30, 2020, respectively. For the three months ended June 30, 2020, this included $4.9 million principal amount of the 2023 Notes, $16.3 million principal amount of the 2024 Notes, $13.5 million principal amount of the 2025 Notes, and $12.8 million principal amount of the 2026 Notes. The Company recognized a $34.3 million and $49.6 million gain on debt extinguishment, which included retirement of unamortized issuance costs and fees associated with the repurchased debt, during the three and six months ended June 30, 2020, respectively. This gain is included in gain on debt extinguishment in the accompanying consolidated statements of operations. As of May 1, 2020, further repurchases under this program are limited due to the agreements entered into under the fifteenth amendment to the Amended and Restated Credit Agreement of the Company's credit facility.March 31, 2020.

Fair Value of Debt

At ~~June 30, 2020,~~March 31, 2021, the carrying value of the outstanding debt represented by the Notes was approximately $1.8 billion. Based on the quoted market prices (Level 1), the fair value of the Notes was determined to be approximately ~~$930.2 million~~$1.6 billion at ~~June 30, 2020.~~

March 31, 2021.

6.~~CHANGES IN CAPITALIZATION~~

~~Stock Repurchases~~

In January 2019, the Company's Board of Directors approved a stock repurchase program to acquire a portion of the Company's outstanding common stock within a 24-month period. The program was suspended in the fourth quarter of 2019, and the May 1, 2020 amendment to the Company's revolving credit facility prohibits further stock repurchases.

For the three and six months ended June 30, 2019, the Company repurchased 0.2 million and 3.8 million shares for a cost of approximately $1.8 million and $30.0 million, respectively, under this repurchase program.

Additionally, during the three and six months ended June 30, 2020, the Company repurchased approximately 27,000 and 107,000 shares, respectively, for a cost of $28 thousand and $0.1 million, respectively, to satisfy tax withholding requirements incurred upon the vesting of restricted stock. During the three and six months ended June 30, 2019, the Company repurchased approximately 72,000 and 87,000 shares, respectively, for a cost of $0.5 million and $0.6 million, respectively, to satisfy tax withholding requirements incurred upon the vesting of restricted stock. All repurchased shares have been canceled and returned to the status of authorized but unissued shares.

7.STOCK-BASED COMPENSATION

The Company has granted restricted stock units to employees and directors pursuant to the 2019 Amended and Restated Incentive Stock Plan ("2019 Plan"), as discussed below. During the three ~~and six~~ months ended ~~June 30, 2020,~~March 31, 2021, the Company’s stock-based compensation cost was ~~$2.2~~$3.0 million, ~~and $4.3 million, respectively,~~ of which the Company capitalized ~~$1.0~~$0.6 million ~~and $1.9 million, respectively,~~ relating to its exploration and development efforts. During the three ~~and six~~ months ended ~~June 30, 2019,~~March 31, 2020, the Company’s stock-based compensation cost was ~~$2.8~~$2.1 million ~~and $5.6 million, respectively,~~ of which the Company capitalized ~~$1.1~~$0.9 million ~~and $2.3 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.

The following table summarizes restricted stock unit activity for the ~~six~~three months ended ~~June 30, 2020:~~March 31, 2021:

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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, 2020 4,098,318 $ 4.73 1,783,660 $ 2.96
Granted 1,985,452 0.67 — —
Vested (512,283) 7.19 — —
Forfeited (979,929) 3.82 (830,323) 1.98
Unvested shares as of June 30, 2020 4,591,558 $ 3.00 953,337 $ 3.82


	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	0	0		0	0
Vested	(202,583)	8.32		0	0
Forfeited/canceled	(19,707)	3.61		0	0
Unvested shares as of March 31, 2021	1,480,223	$	4.26	840,595	$	4.07

Restricted Stock Units

Restricted stock units awarded under the 2019 Plan generally vest over a period of one year in the case of directors and three years in the case of employees and vesting is 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. Unrecognized compensation expense as of ~~June 30, 2020~~March 31, 2021 related to restricted stock units was ~~$9.4 million~~.$4.0 million. The expense is expected to be recognized over a weighted average period of ~~1.75~~1.12 years.

Performance Vesting Restricted Stock Units

The Company has awarded performance vesting units to certain of its executive officers under the 2019 Plan. The number of shares of common stock issued pursuant to the award will be based on relative total shareholder return ("RTSR"). RTSR is an incentive measure whereby participants will earn from 0% to 200% of the target award based on the Company’s RTSR ranking compared to the RTSR 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 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. Unrecognized compensation expense as of ~~June 30, 2020~~March 31, 2021 related to performance vesting restricted shares was ~~$2.2 million. The expense is expected to be recognized over a weighted average period of~~ ~~1.78~~ ~~years.~~

~~Cash Incentive Awards~~

On March 16, 2020, the Board of Directors of the Company approved the Company's 2020 Incentive Plan (the "2020 Incentive Plan"). The 2020 Incentive Plan provides for incentive compensation opportunities ("Incentive Awards") for select employees of the Company that are tied to the achievement of one or more performance goals relating to certain financial and operational metrics over a period of time. The earning of an Incentive Award and payout opportunity is contingent upon meeting the Incentive Award's applicable threshold performance levels. If such threshold performance levels are satisfied, the payout amount varies for performance above or below the pre-established target performance levels.

During the six months ended June 30, 2020, the Company awarded Incentive Awards to certain of its executive officers under the 2020 Incentive Plan. The cash amount of each award ultimately received is based on the attainment of certain financial, operational and total shareholder return performance targets and is subject to the recipient's continuous employment. Each Incentive Award is subject to a Performance Period of January 1, 2020 to December 31, 2020, and different vesting periods apply to separate one-third portions of each Incentive Award, with a different tranche vesting each on December 31, 2020, 2021, and 2022. The Incentive Awards are considered liability awards as the ultimate amount of the award is based, at least in part, on the price of the Company's shares, and as such, are remeasured to fair value at the end of each reporting period. The fair value of the Incentive Awards at June 30, 2020 was $3.0 million. Unrecognized compensation expense as of June 30, 2020 related to Incentive Awards was $2.4$1.1 million. The expense is expected to be recognized over a weighted average period of ~~1.62~~1.04 years.

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2020 Cash Retention Incentives

On August 4, 2020, the Company's Board of Directors authorized a redesign of the incentive compensation program for the Company's workforce, including for its current named executive officers. In connection with a comprehensive review of the Company’s compensation programs and in consultation with its independent compensation consultant and legal advisors, the Board of Directors determined that significant changes were appropriate to retain and motivate the Company’s employees as a result of the ongoing uncertainty and unprecedented disruption in the oil and gas industry.

All unpaid amounts previously awarded pursuant to the 2020 Incentive Plan and all restricted stock units granted in 2020 issued to the Company's named executive officers were cancelled and replaced with cash retention incentives. These cash retention incentives are equally weighted between achievement of certain specified performance metrics and a service period. Of the cash retention incentives, 50% may be clawed back on an after-tax basis if an executive officer terminates employment for any reason other than a qualifying termination prior to the earlier of July 31, 2021, a change in control or completion of a restructuring, and the remaining 50% will be subject to repayment on an after-tax basis if established performance metrics are not met over performance periods from August 1, 2020 through July 31, 2021. In total, $13.5 million in cash retention incentives were paid to the Company's executives in August 2020.

The transactions were considered a modification to the previously issued equity- and liability-classified awards, and the previously issued equity-classified awards were reclassified as liability awards. The after-tax value of the cash incentives paid to the Company's executives of was capitalized to prepaid expenses and other current assets in the accompanying consolidated balance sheets and will be amortized over the remaining service period. Unrecognized compensation expense as of March 31, 2021 related to these payments was $2.1 million.

8.7.EARNINGS (LOSS) PER SHARE

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

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Three months ended June 30,
2020 2019
Loss Shares Per
Share Income Shares Per
Share
(In thousands, except share data)
Basic:
Net (loss) income $ (561,068) 159,933,739 $ (3.51) $ 234,956 159,324,909 $ 1.47
Effect of dilutive securities:
Stock awards — — — 181,917
Diluted:
Net (loss) income $ (561,068) 159,933,739 $ (3.51) $ 234,956 159,506,826 $ 1.47

Six months ended June 30,
2020 2019
Loss Shares Per
Share Income Shares Per
Share
(In thousands, except share data)
Basic:
Net (loss) income $ (1,078,606) 159,846,981 $ (6.75) $ 297,198 161,064,787 $ 1.85
Effect of dilutive securities:
Stock options and awards — — — 525,300
Diluted:
Net (loss) income $ (1,078,606) 159,846,981 $ (6.75) $ 297,198 161,590,087 $ 1.84


	Three months ended March 31,
	2021		2020
	(In thousands, except share data)
Net income (loss)	$	8,780	$	(517,538)
Basic Shares	160,812,935		159,760,222
Basic EPS	$	0.05	$	(3.24)
Effect of dilutive securities:
Stock options and awards	0		0
Dilutive Shares	160,812,935		159,760,222
Dilutive EPS	$	0.05	$	(3.24)

There were ~~1,281,773 and 1,610,572~~0 potential shares of common stock that were considered ~~anti-dilutive~~dilutive for the three ~~and six~~ months ended ~~June 30, 2020, respectively.~~March 31, 2021. There were 01,552,423 potential shares of common stock that were considered anti-dilutive for the three ~~and six~~ months ended ~~June 30, 2019.~~

March 31, 2020.

9.8.COMMITMENTS AND CONTINGENCIES

Future Firm Transportation and Gathering Agreements

The Company has contractual commitments with 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. Commitments related to future firm transportation and gathering agreements are not recorded as obligations in the accompanying consolidated balance sheets; however, they are reflected in the Company's estimates of proved reserves.

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Additionally, one of the requirements provided for in the RSA is that the Company must permanently reduce its future demand reservation fees owed over the life of all of its firm transportation agreements, taken as a whole, by at least 50% of the amount of all such fees owed on October 31, 2020, as calculated on a PV-10 basis. Additionally, the Company must reduce the future firm transportation demand reservation volumes over the life of all of its firm transportation agreements, taken as a whole, by at least 35%. Since the filing of the Chapter 11 Cases in November 2020, the Company has successfully renegotiated or terminated certain of its midstream contracts and commitments, significantly reducing its transportation expenses. As of March 31, 2021, the Company was still negotiating certain of its midstream contracts pending emergence from Chapter 11. However, there can be no assurances the Company will successfully renegotiate or terminate any additional midstream contracts. The below table reflects the Company's obligations as of March 31, 2021 excluding contemplation of any contracts yet to be terminated or renegotiated throughout the Chapter 11 Cases.

A summary of these commitments at March 31, 2021 are set forth in the table below:


	(In thousands)
Remaining 2021	$	242,253
2022	324,048
2023	322,241
2024	302,116
2025	215,119
Thereafter	1,575,874
Total	$	2,981,651

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 ~~proved reserves have~~operated production has generally been sufficient to satisfy its delivery commitments during the ~~three most recent years,~~periods presented, and it expects ~~such reserves~~its operated production will continue to be the primary means of fulfilling its future commitments. However, where the Company's ~~proved reserves are~~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 ~~June 30, 2020~~March 31, 2021 are set forth in the table below:

(MMBtu per day)
Remaining 2020 311,000
2021 192,000
2022 70,000
2023 17,000
Total 590,000

~~Future Firm Transportation Commitments~~

The Company has contractual commitments with pipeline carriers for future transportation of natural gas from the Company's production areas to downstream markets. Commitments related to future firm transportation agreements are not

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recorded as obligations in the accompanying consolidated balance sheets; however, the costs associated with these commitments are reflected in the Company's estimates of proved reserves and future net revenues.

~~A summary of these commitments at June 30, 2020 are set forth in the table below:~~

Total MMBtu (In thousands)
Remaining 2020 267,720,000 $ 138,495
2021 531,075,000 285,779
2022 531,075,000 286,616
2023 515,775,000 282,936
2024 489,490,000 265,558
Thereafter 3,767,959,000 2,160,634
Total 6,103,094,000 $ 3,420,018

As of June 30, 2020, the Company had entered into firm transportation contracts to deliver approximately 1,455,000 MMBtu per day for the remainder of 2020 and 2021, respectively. Under these firm transportation contracts, the Company is obligated to deliver minimum daily volumes or pay fees for any deficiencies in deliveries. As a result of the reduced production from the Company's Utica Shale or SCOOP acreage due to decreased developmental activities, taking into consideration the current low commodity price environment, the Company expects that it will be unable to meet its obligations under the existing firm transportation contracts, resulting in fees, which may be significant and may have a material adverse effect on its operations.

~~Other Commitments~~

Effective October 1, 2014, the Company entered into a Sand Supply Agreement with Muskie Proppant LLC (“Muskie”), a subsidiary of Mammoth Energy and a related party. Pursuant to this agreement, as amended effective August 3, 2018, the Company agreed to purchase annual and monthly amounts of proppant sand subject to exceptions specified in the agreement at agreed pricing plus agreed costs and expenses through 2021. Failure by either Muskie or the Company to deliver or accept the minimum monthly amount results in damages calculated per ton based on the difference between the monthly obligation amount and the amount actually delivered or accepted, as applicable. The Company incurred $1.9 million and $3.8 million in non-utilization fees under this agreement during the three and six months ended June 30, 2020, respectively. The Company did not incur any non-utilization fees under this agreement during the three months ended June 30, 2019 and incurred $0.3 million of such fees during the six months ended June 30, 2019.

~~Future minimum commitments under this agreement at June 30, 2020 are:~~

(In thousands)
Remaining 2020 $ 3,750
2021 7,500
Total $ 11,250


						(MMBtu per day)
Remaining 2021						61,000
2022						49,000
2023						17,000



Total						127,000

Litigation and Regulatory Proceedings

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.

The Company, along with a number of other oil and gas companies, has been named as a defendant in 2 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

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District of the State of Louisiana in the 15th Judicial District Court for the Parish of Vermilion on July 29, 2016 (together, the ~~"Complaints"~~

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"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.

In July 2019, Pigeon Land Company, Inc., a successor in interest to certain of the Company’s legacy Louisiana properties, filed an action against the Company and many other oil and gas companies in the 16th Judicial District Court for the Parish of Iberia in Louisiana. The suit alleges negligence, strict liability and various violations of Louisiana statutes relating to property damage in connection with the historic development of the Company’s Louisiana properties and seeks unspecified damages (including punitive damages), an injunction to return the affected property to its original condition, and the payment of reasonable attorney fees and legal expenses and interest.

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.

In October 2019, Kelsie Wagner, in her capacity as trustee of various trusts and on behalf of the trusts and other similarly situated royalty owners, filed an action against the Company in the District Court of Grady County, Oklahoma. The suit alleges that the Company underpaid royalty owners and seeks unspecified damages for violations of the Oklahoma Production Revenue Standards Act and fraud. This matter was administratively terminated on December 2, 2020.

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.

In June 2020, Sam L. Carter, derivatively on behalf of the Company, filed an action against certain of our current and former executive officers and directors in the United States District Court for the District of Delaware. The complaint alleges that the defendants breached their fiduciary duties to the Company in connection with certain alleged materially false and misleading statements regarding our business and operations in violation of the federal securities laws. The complaint seeks to recover unspecified damages from the defendants, the implementation of specified corporate governance reforms, reasonable attorneys’ and experts’ fees, costs and expenses, and such other relief as may be deemed just and proper.

~~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, ~~which~~and Stingray filed claims in the ~~complaint calculates~~Chapter 11 proceedings exceeding $80 million related to ~~be approximately $28.0 million as~~breach of ~~June 2020 (such amount to increase each month), the payment of reasonable attorney~~contract damages, attorneys' fees and ~~legal expenses and pre- and post-judgment interest as allowed, and such other and further relief which it may be justly entitled.~~interest.

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

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to 6 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.~~workers, and claims were filed in the Chapter 11 proceedings totaling $5.8 million.

~~These cases are still in their early stages. As a result,~~In August 2020, Muskie filed an action against the Company ~~has not had the opportunity to evaluate the allegations made~~ in the ~~plaintiffs' complaints and intends~~Superior Court of the State of Delaware for breach of contract. The complaint alleges that the Company breached its obligation to ~~vigorously defend~~purchase a certain amount of proppant sand each month or make designated shortfall payments under the ~~suits.~~

~~SEC Investigation~~

The SEC has commenced an investigation with respect to certain actions by former Company management, including alleged improper personal use of Company assets, and potential violations by former managementSand 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 filed a claim in the ~~Sarbanes-Oxley Act~~Chapter 11 proceedings for $3.4 million.

As part of ~~2002~~its Chapter 11 Cases and restructuring efforts as discussed in ~~connection with such actions.~~Note 2, the Company filed motions to reject certain firm transportation agreements between the Company and affiliates of TC Energy Corporation and Rover Pipeline LLC (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 ~~has fully cooperated and intends~~isn’t required to ~~continue to cooperate fully with the SEC’s investigation. Although it is not possible to predict the ultimate resolution or financial liability with respect to this matter, the~~perform under these firm transportation agreements. The Company believes that the ~~outcome of this matter~~Pending Motions to Reject will be ultimately granted, and that the Company does not have ~~a material effect on~~any ongoing obligations pursuant to the ~~Company’s business, financial condition or results~~contracts; however, in the event that the Company is not permitted to reject these firm transportation contracts, the monetary damages awarded could be greater than $57 million.

Table of ~~operations.~~Contents

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. ~~They~~Gulfport and its subsidiaries have implemented various policies, programs, procedures, training and audits to reduce and mitigate environmental risks. They conduct 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.

The Company received several Finding of Violation (“FOVs”) from the United States Environmental Protection Agency ("USEPA") alleging violations of the Clean Air Act at approximately 17 locations in Ohio. The first FOV for 1 site was dated December 11, 2013. Two subsequent FOVs incorporated and expanded the scope on January 4, 2017 and April 15, 2019. The Company has exchanged information with the USEPA and is engaged in discussions aimed at resolving the allegations. Resolution of the matter resulted in monetary sanctions of approximately $1.7 million.

In October 2018, the company submitted a Voluntary Disclosure document to the Oklahoma Department of Environmental Quality (ODEQ) stemming from improper air permitting at several sites in Midcon between 2014 and 2017. The sites were permitted by Vitruvian prior to the Company's purchase of those assets. The sites were permitted utilizing the “permit by rule” regulation but actually required Title V air permits. The Company has agreed in a draft Consent Order to obtain the proper permits and to pay the costs from not having the proper permits in place in the amount of $180,000 to the ODEQ. The Order received final approval at the ODEQ and is expected to be finalized in the third quarter of 2020.

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.

1822

~~10.~~9.DERIVATIVE INSTRUMENTS

Natural Gas, Oil and Natural Gas Liquids Derivative Instruments

The Company seeks to ~~reduce its exposure~~mitigate risks related to unfavorable changes in natural gas, oil and ~~natural gas liquids ("NGL")~~NGL prices, which are subject to significant and often volatile fluctuation, by entering into over-the-counter fixed price swaps, basis swaps, ~~costless~~ collars and various types of option contracts. These contracts allow the Company to ~~predict with greater certainty~~mitigate the ~~effective~~impact of declines in future natural gas, oil and NGL prices by effectively locking in floor price for a certain level of the Company’s production. However, these hedge contracts also limit the benefit to ~~be received for hedged production and benefit operating cash flows and earnings~~the Company in periods when the future market prices ~~are less than the fixed prices provided in the contracts. However, the Company will not benefit from market prices~~of natural gas, oil and NGL that are higher than the ~~fixed prices in the contracts for~~ hedged ~~production.~~prices.

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 West Texas Intermediate for oil and Mont Belvieu for propane, pentane and ethane. Below is a summary of the Company’s open fixed price swap positions as of ~~June 30, 2020.~~March 31, 2021.

Location Daily Volume
(MMBtu/day) Weighted
Average Price
Remaining 2020 NYMEX Henry Hub 357,000 $ 2.86

Location

Daily Volume
(MMBtu/day)

Weighted
Average Price

Remaining 2021

NYMEX Henry Hub

351,316

2.73

Location Daily Volume
(Bbls/day) Weighted
Average Price
Remaining 2020 NYMEX WTI 3,000 $ 35.49

Location

Daily Volume
(Bbl/day)

Weighted
Average Price

Remaining 2021

NYMEX WTI

1,505

53.07

Location Daily Volume
(Bbls/day) Weighted
Average Price
Remaining 2020 Mont Belvieu C3 1,500 $ 20.27


	Location	Daily Volume (Bbl/day)	Weighted Average Price
Remaining 2021	Mont Belvieu C3	2,074	$	27.80
2022	Mont Belvieu C3	496	$	27.30

~~The~~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 ~~for a portion of the fixed price~~on certain natural gas swaps ~~primarily for 2020 listed above.~~that settled in 2020. Each call option has an established ceiling ~~price. When the referenced settlement~~ price isof $2.90/MMBtu. If monthly NYMEX natural gas prices settle above the ~~price~~$2.90 ceiling ~~established by these call options,~~price, the Company ~~pays its~~is required to pay the option counterparty an amount equal to the difference between the referenced NYMEX natural gas settlement price and ~~the price ceiling~~$2.90 multiplied by the hedged contract volumes. Below is a summary of the Company's sold call option positions as of March 31, 2021.


		Location	Daily Volume (MMBtu/day)	Weighted Average Price			Location	Daily Volume (MMBtu/day)	Weighted Average Price

2022	2022	NYMEX Henry Hub	628,000	$	2.90	2022	NYMEX Henry Hub	152,675	$	2.90
2023	2023	NYMEX Henry Hub	628,000	$	2.90	2023	NYMEX Henry Hub	627,675	$	2.90

The Company entered into costless collars based off the NYMEX Henry Hub natural gas index. 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 March 31, 2021.

Location Daily Volume (MMBtu/day) Weighted Average Floor Price Weighted Average Ceiling Price
2021 NYMEX Henry Hub 250,000 $ 2.46 $ 2.81


	Location	Daily Volume (MMBtu/day)	Weighted Average Floor Price		Weighted Average Ceiling Price
Remaining 2021	NYMEX Henry Hub	390,509	$	2.54	$	2.93
2022	NYMEX Henry Hub	186,438	$	2.63	$	3.04

In addition, the Company entered into natural gas basis swap ~~positions. As~~hedge contracts. If the applicable monthly price indices are outside of ~~June 30, 2020,~~ the ~~Company had~~ranges set forth in the ~~following~~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 basis swap positions ~~open:~~

Gulfport Pays Gulfport Receives Daily Volume
(MMBtu/day) Weighted Average Fixed Spread
Remaining 2020 Transco Zone 4 NYMEX Plus Fixed Spread 60,000 $ (0.05)
Remaining 2020 Fixed Spread ONEOK Minus NYMEX 10,000 $ (0.54)
as of March 31, 2021.

1923

During the three months ended June 30, 2020, we early terminated oil fixed price swaps which represented approximately 6,000 BBls of oil per day for the remainder of 2020. The early termination resulted in a cash settlement of $40.5 million.

~~Contingent Consideration Arrangement~~

The Company sold its non-core assets located in the West Cote Blanche Bay and Hackberry fields of Louisiana in July 2019. The sale price included the potential for the Company to receive contingent payments based on commodity prices exceeding specified thresholds over the two years following the closing date. This contingent consideration arrangement was determined to be an embedded derivative. See below for threshold and potential payment amounts.


~~Period~~	~~Threshold~~⁽¹⁾	~~Payment to be received~~⁽²⁾
~~July 2020 - June 2021~~	~~Greater than or equal to $60.65~~	$	~~150,000~~
	~~Between $52.62 - $60.65~~	~~Calculated Value~~⁽³⁾
	~~Less than or equal to $52.62~~	$	—

~~(1)~~

~~Based on the "WTI NYMEX + Argus LLS Differential," as published by Argus Media.~~

~~(2)~~

~~Payment will be assessed monthly from July 2020 through June 2021. If threshold is met, payment shall be received within five business days after the end of each calendar month.~~

~~(3)~~

If average daily price, as defined in (1), is greater than $52.62 but less than $60.65, payment received will be $150,000 multiplied by a fraction, the numerator of which is the amount determined by subtracting $52.62 from such average daily price, and the denominator of which is $8.03.


	Gulfport Pays	Gulfport Receives	Daily Volume (MMBtu/day)	Weighted Average Fixed Spread
Remaining 2021	Rex Zone 3	NYMEX Plus Fixed Spread	85,309	$	(0.22)
Remaining 2021	Tetco M2	NYMEX Plus Fixed Spread	32,384	$	(0.63)
2022	Rex Zone 3	NYMEX Plus Fixed Spread	14,795	$	(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 ~~June 30, 2020~~March 31, 2021 and December 31, ~~2019:~~2020:


		June 30, 2020		December 31, 2019			March 31, 2021		December 31, 2020
		(In thousands)							(In thousands)
Commodity Contracts:

Short-term derivative asset	Short-term derivative asset	$	53,188	$	125,383	Short-term derivative asset	$	12,422	$	27,146
Long-term derivative asset	Long-term derivative asset	4,298		—		Long-term derivative asset	652		322
Short-term derivative liability	Short-term derivative liability	(8,540)		(303)		Short-term derivative liability	(20,687)		(11,641)
Long-term derivative liability	Long-term derivative liability	(45,615)		(53,135)		Long-term derivative liability	(43,267)		(36,604)
Total commodity derivative position	Total commodity derivative position	$	3,331	$	71,945	Total commodity derivative position	$	(50,880)	$	(20,777)

Contingent consideration arrangement:
Short-term derivative asset		$	—	$	818
Long-term derivative asset		—		563
Total contingent consideration derivative position		$	—	$	1,381

Total net asset derivative position		$	3,331	$	73,326

Gains and Losses

The following table presents the gain and loss recognized in net (loss) gain on natural gas, oil and NGL derivatives in the accompanying consolidated statements of operations for the three ~~and six~~ months ended ~~June 30, 2020~~March 31, 2021 and ~~2019.~~2020.


		Net gain (loss) on derivative instruments														Net (loss) gain on derivative instruments
		Three months ended June 30,						Six months ended June 30,							Three months ended March 31,
		2020		2019		2020		2019			2021		2020
		(In thousands)														(In thousands)
Natural gas derivatives	Natural gas derivatives	$	35,689	$	152,475	$	81,542	$	136,044	Natural gas derivatives	$	(25,413)	$	45,853
Oil derivatives	Oil derivatives	(7,937)		11,871		44,937		11,417		Oil derivatives	(1,731)		52,874
NGL derivatives	NGL derivatives	(781)		6,794		139		3,634		NGL derivatives	(2,834)		920
Contingent consideration arrangement	Contingent consideration arrangement	—		—		(1,381)		—		Contingent consideration arrangement	0		(1,381)
Total	Total	$	26,971	$	171,140	$	125,237	$	151,095	Total	$	(29,978)	$	98,266

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.


		As of June 30, 2020											As of March 31, 2021
		Gross Assets (Liabilities)		Gross Amounts					Gross Assets (Liabilities)		Gross Amounts
		Presented in the		Subject to Master		Net			Presented in the		Subject to Master		Net
		Consolidated Balance Sheets		Netting Agreements		Amount			Consolidated Balance Sheets		Netting Agreements		Amount
		(In thousands)											(In thousands)
Derivative assets	Derivative assets	$	57,486	$	(48,761)	$	8,725	Derivative assets	$	13,074	$	(13,074)	$	0
Derivative liabilities	Derivative liabilities	$	(54,155)	$	48,761	$	(5,394)	Derivative liabilities	$	(63,954)	$	13,074	$	(50,880)

As of December 31, 2019
Gross Assets (Liabilities) Gross Amounts
Presented in the Subject to Master Net
Consolidated Balance Sheets Netting Agreements Amount
(In thousands)
Derivative assets $ 126,764 $ (53,438) $ 73,326
Derivative liabilities $ (53,438) $ 53,438 $ —


	As of December 31, 2020
	Gross Assets (Liabilities)		Gross Amounts
	Presented in the		Subject to Master		Net
	Consolidated Balance Sheets		Netting Agreements		Amount
	(In thousands)
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 with multiple counterparties to lessen its exposure to any individual counterparty. Additionally, the Company uses master netting agreements to minimize credit risk exposure. The creditworthiness of the Company’s counterparties is subject to periodic review. None of the Company’s derivative instrument contracts contain credit-risk related contingent features. Other than as provided by the Company’s revolving credit facility, the Company is not required to provide credit support or collateral to any of its counterparties under its derivative instruments, nor are the counterparties required to provide credit support to the Company.

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~~11.~~10.FAIR VALUE MEASUREMENTS

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

Level 1 – Quoted prices 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.

Financial assets and liabilities

The following tables summarize the Company’s financial and non-financial assets and liabilities by valuation level as of ~~June 30, 2020~~March 31, 2021 and December 31, ~~2019:~~2020:

~~June 30, 2020~~

~~Level 1~~

~~Level 2~~

~~Level 3~~

~~(In thousands)~~

~~Assets:~~

~~Derivative Instruments~~

—

~~57,486~~

—

~~Liabilities:~~

~~Derivative Instruments~~

—

~~54,155~~

—


	March 31, 2021
	Level 1		Level 2		Level 3
	(In thousands)
Assets:
Derivative Instruments	$	0	$	13,074	$	0
Contingent consideration arrangement	$	0	$	0	$	6,000
Total assets	$	0	$	13,074	$	6,000
Liabilities:
Derivative Instruments	$	0	$	63,954	$	0

~~December 31, 2019~~

~~Level 1~~

~~Level 2~~

~~Level 3~~

~~(In thousands)~~

~~Assets:~~

~~Derivative Instruments~~

—

~~126,764~~

—

~~Liabilities:~~

~~Derivative Instruments~~

—

~~53,438~~

—


	December 31, 2020
	Level 1		Level 2		Level 3
	(In thousands)
Assets:
Derivative Instruments	$	0	$	27,468	$	0
Contingent consideration arrangement	$	0	$	0	$	6,200
Total assets	$	0	$	27,468	$	6,200
Liabilities:
Derivative Instruments	$	0	$	48,245	$	0

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~~The Company's SCOOP water infrastructure sale, which closed in the first quarter of 2020, included a contingent consideration arrangement. As of ~~June 30, 2020,~~March 31, 2021, the fair value of the contingent consideration was ~~$19.8~~$6.0 million, of which ~~$0.8~~

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$1.3 million is included in prepaid expenses and other assets and ~~$19.0~~$4.7 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 an immaterial gain and a ~~loss~~gain of ~~$3.2 million and $3.0~~$0.2 million on changes in fair value of the contingent consideration during the three ~~and six~~ months ended ~~June 30,~~March 31, 2021 and 2020, respectively, which is included in other expense (income) in

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the accompanying consolidated statements of operations. ~~Settlements under the contingent consideration arrangement totaled $0.3 million during the six months ended June 30, 2020.~~

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 23 for further discussion of the Company’s asset retirement obligations. Asset retirement obligations incurred during the ~~six~~three months ended ~~June 30, 2020~~March 31, 2021 were approximately $0.5 million.

As discussed in ~~$1.6 million~~Note 3., the Company recorded an impairment during the three months ended March 31, 2021 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 ~~construction~~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.

~~12.~~11.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 midstream, gathering and processing 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

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product generally represents a separate performance obligation; therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. Currently, the Company's product sales that have a contractual term greater than one year have no long-term fixed consideration.

Contract Balances

Receivables from contracts with customers are recorded when the right to consideration becomes unconditional, generally when control of the product has been transferred to the customer. Receivables from contracts with customers were ~~$65.6~~$134.0 million and ~~$121.2~~$119.9 million as of ~~June 30, 2020~~March 31, 2021 and December 31, ~~2019,~~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

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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 ~~six~~three months ended ~~June 30, 2020,~~March 31, 2021, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.

~~13.~~12.LEASES

Nature of Leases

The Company has operating leases ~~associated with drilling rig commitments,~~on certain equipment and field offices ~~and other equipment~~ with remaining lease ~~terms with contractual~~ 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 ~~a contract~~contracts for a drilling ~~rig~~rigs with avarying terms with third ~~party~~parties to ensure operational continuity, cost control and rig ~~availability.~~availability in its operations. The Company has concluded its drilling rig contracts are operating leases as the assets are identifiable and ~~the evaluation that~~ the Company has the right to control the identified assets. The Company's drilling rig commitments are typically structured with an initial term of less than one year to two years, ~~and typically include renewal options~~although at ~~the end of the initial term. Due to the nature of the Company's drilling schedules and potential volatility in commodity prices,~~March 31, 2021, the Company ~~is unable to determine at commencement with reasonable certainty if the renewal options will be exercised; therefore, renewal options are~~did not considered in the lease term for drilling contracts. The operating lease liability associated with its rig commitment is based on the minimum contractual obligation, primarily standby rate, and does not include variable amounts based on actual activity in a given period. The Company has also entered into severalhave any active long-term drilling rig ~~commitments with an initial term less than one year. The costs for these short-term rig commitments are included~~contracts in the short-term lease cost for the period as shown below. Pursuant to the full cost method of accounting, these costs are capitalized as part of oil and natural gas properties on the accompanying consolidated balance sheets. A portion of these costs are borne by other interest owners.

Effective October 1, 2014, the Company entered into an Amended and Restated Master Services Agreement for pressure pumping services with Stingray Pressure Pumping LLC (“Stingray Pressure”), a subsidiary of Mammoth Energy and a related party. Pursuant to this agreement, as amended effective July 1, 2018, Stingray Pressure has agreed to provide hydraulic fracturing, stimulation and related completion and rework services to the Company through 2021 and the Company has agreed to pay Stingray Pressure a monthly service fee plus the associated costs of the services provided. As discussed further in ~~Note 9~~, the Company has terminated the Master Services Agreement for pressure pumping with Stingray Pressure. As a result, in the first quarter of 2020, Gulfport has removed the related right of use assets and lease liabilities associated with the terminated contract.place.

The Company rents office space for its field locations and certain other equipment from third parties, which expire at various dates through 2024. 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.

Discount Rate

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

2428

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Maturities of operating lease liabilities as of ~~June 30, 2020~~March 31, 2021 were as follows:


		(In thousands)			(In thousands)
Remaining 2020		$	3,321
2021		129
Remaining 2021				Remaining 2021	$	97
2022	2022	115		2022	115
2023	2023	90		2023	90
2024	2024	30		2024	30

Total lease payments	Total lease payments	$	3,685	Total lease payments	$	332
Less: Imputed interest	Less: Imputed interest	(45)		Less: Imputed interest	(18)
Total	Total	$	3,640	Total	$	314

Lease cost for the three ~~and six~~ months ended ~~June 30,~~March 31, 2021 and 2020 ~~and 2019~~ consisted of the following:


		Three months ended June 30,						Six months ended June 30,							Three months ended March 31,
		2020		2019		2020		2019			2021		2020
		(In thousands)														(In thousands)
Operating lease cost	Operating lease cost	$	2,196	$	7,748	$	6,278	$	16,284	Operating lease cost	$	32	$	4,082
Operating lease cost—related party		—		5,610		—		11,220

Variable lease cost	Variable lease cost	235		531		460		960		Variable lease cost	0		224
Variable lease cost—related party		—		28,158		—		59,611

Short-term lease cost	Short-term lease cost	2,629		183		5,439		183		Short-term lease cost	2,189		2,810
Total lease cost⁽¹⁾	Total lease cost⁽¹⁾	$	5,060	$	42,230	$	12,177	$	88,258	Total lease cost(1)	$	2,221	$	7,116

(1)

The majority of the Company's total lease cost was capitalized to the full cost pool, and the remainder was included in general and administrative expenses in the accompanying consolidated statements of operations.

Supplemental cash flow information for the ~~six~~three months ended ~~June 30,~~March 31, 2021 and 2020 ~~and 2019~~ related to leases was as follows:


		Six months ended June 30,								Three months ended March 31,
		2020		2019			2021			2020
Cash paid for amounts included in the measurement of lease liabilities	Cash paid for amounts included in the measurement of lease liabilities	(In thousands)							Cash paid for amounts included in the measurement of lease liabilities	(In thousands)
Operating cash flows from operating leases	Operating cash flows from operating leases	$	72	$	120	Operating cash flows from operating leases	$	31		$	36
Investing cash flow from operating leases	Investing cash flow from operating leases	$	7,727	$	12,288	Investing cash flow from operating leases	$	0		$	3,997
Investing cash flow from operating leases—related party	Investing cash flow from operating leases—related party	$	6,800	$	43,925	Investing cash flow from operating leases—related party	$	0		$	6,800

The weighted-average remaining lease term as of ~~June 30, 2020~~March 31, 2021 was ~~0.83~~2.8 years. The weighted-average discount rate used to determine the operating lease liability as of ~~June 30, 2020~~March 31, 2021 was ~~2.47%~~4.22%.

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~~14.~~13.INCOME TAXES

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

For the three ~~and six~~ months ended ~~June 30, 2020,~~March 31, 2021, the Company's estimated annual effective tax rate before discrete items ~~remained near zero~~was approximately 0% as a result of the valuation allowance on its deferred tax assets. ~~During the first quarter of 2020,~~

At each reporting period, the Company ~~recognized $7.3 million of income tax expense discretely in the quarter as a result of the sale of assets~~weighs all available positive and ~~a corresponding adjustment~~negative evidence to ~~the valuation allowance on remaining state net operating loss carryforwards.~~

~~The Company anticipates remaining in a net deferred tax position based on the analysis performed for three and six months ended June 30, 2020. The Company expects a full valuation allowance against~~determine whether its deferred tax assets ~~based on its conclusion, considering all available evidence (both positive and negative), that it was~~are more likely than not ~~that the deferred tax assets would 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

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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.

~~On March 27, 2020,~~ The cumulative loss in recent years is a significant piece of negative evidence that is hard to overcome and therefore the ~~CARES Act~~Company placed more reliance on historical results than forecasts. As a result of this analysis, the Company determined a full valuation allowance of $911.4 million was enacted in response to the COVID-19 pandemic. The Act includes several significant provisions for corporations including allowing companies to carryback certain NOLs, increasing the amount of NOLs that corporations can use to offset income, and increasing the amount of deductible interest under section 163(j). The Company does not expect to be materially impacted by the CARES Act provision and does not anticipate the CARES Act to have a material effect onnecessary against its ~~ability to realized~~net deferred tax ~~assets.~~

The Company’s ability to utilize NOL carryforwards and other tax attributes to reduce future federal taxable income is subject to potential limitations under Internal Revenue Code Section 382 (“Section 382”) and its related tax regulations. The utilizationasset as of these attributes may be limited if certain ownership changes by 5% stockholders (as defined in Treasury regulations pursuant to Section 382) and the effects of stock issuances by the Company during any three-year period result in a cumulative change of more than 50% in the beneficial ownership of Gulfport. The Company updates its Section 382 analysis to determine if an ownership change has occurred at each reporting period. If it is determined that an ownership change has occurred under these rules, the Company would generally be subject to an annual limitation on the use of pre-ownership change NOL carryforwards and certain other losses and/or credits. In addition, certain future transactions regarding the Company's equity, including the cumulative effects of small transactions as well as transactions beyond the Company’s control, could cause an ownership change and therefore a potential limitation on the annual utilization of its deferred tax assets. On April 30, 2020, the board of directors of the Company adopted a tax benefits preservation plan in order to protect against a possible limitation on the Company’s ability to use its tax net operating losses and certain other tax benefits to reduce potential future U.S. federal income tax obligations. The Tax Benefits Preservation Plan is intended to prevent against such an ownership change by deterring any person or group from acquiring beneficial ownership of 4.9% or more of the Company’s securities.

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~~15.CONDENSED CONSOLIDATING FINANCIAL INFORMATION~~

The 2023 Notes, the 2024 Notes, the 2025 Notes and the 2026 Notes are guaranteed on a senior unsecured basis by all existing consolidated subsidiaries that guarantee the Company’s secured revolving credit facility or certain other debt (the “Guarantors”). The Notes are not guaranteed by Grizzly Holdings or Mule Sky LLC ("Mule Sky") (the “Non-Guarantors”). The Guarantors are 100% owned by Gulfport (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. Effective June 1, 2019, the Parent contributed interests in certain oil and gas assets and related liabilities to certain of the Guarantors.

The following condensed consolidating balance sheets, statements of operations, statements of comprehensive income and statements of cash flows are provided for the Parent, the Guarantors and the Non-Guarantors and include the consolidating adjustments and eliminations necessary to arrive at the information for the Company on a condensed consolidated basis. The information has been presented using the equity method of accounting for the Parent’s ownership of the Guarantors and the Non-Guarantors.

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~~CONDENSED CONSOLIDATING BALANCE SHEETS~~

~~(Amounts in thousands)~~

June 30, 2020
Parent Guarantors Non-Guarantors Eliminations Consolidated
Assets
Current assets:
Cash and cash equivalents $ 823 $ 1,748 $ 246 $ — $ 2,817
Accounts receivable - oil and natural gas sales 860 64,785 — — 65,645
Accounts receivable - joint interest and other 2,949 16,440 — — 19,389
Accounts receivable - intercompany 1,482,102 1,150,631 — (2,632,733) —
Prepaid expenses and other current assets 10,781 5 76 — 10,862
Short-term derivative instruments 53,188 — — — 53,188
Total current assets 1,550,703 1,233,609 322 (2,632,733) 151,901
Property and equipment:
Oil and natural gas properties, full-cost accounting 1,247,631 9,478,228 5,862 (729) 10,730,992
Other property and equipment 92,768 51 4,019 — 96,838
Accumulated depletion, depreciation, amortization and impairment (1,423,539) (7,032,075) (1,850) — (8,457,464)
Property and equipment, net (83,140) 2,446,204 8,031 (729) 2,370,366
Other assets:
Equity investments and investments in subsidiaries 1,930,479 6,332 13,013 (1,936,772) 13,052
Long-term derivative instruments 4,298 — — — 4,298
Operating lease assets 3,640 — — — 3,640
Other assets 29,216 7,784 — — 37,000
Total other assets 1,967,633 14,116 13,013 (1,936,772) 57,990
Total assets $ 3,435,196 $ 3,693,929 $ 21,366 $ (4,570,234) $ 2,580,257
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable and accrued liabilities $ 46,085 $ 269,490 $ — $ — $ 315,575
Accounts payable - intercompany 1,185,800 1,442,144 4,789 (2,632,733) —
Short-term derivative instruments 8,540 — — — 8,540
Current portion of operating lease liabilities 3,356 — — — 3,356
Current maturities of long-term debt 649 — — — 649
Total current liabilities 1,244,430 1,711,634 4,789 (2,632,733) 328,120
Long-term derivative instruments 45,615 — — — 45,615
Asset retirement obligation - long-term — 61,371 — — 61,371
Uncertain tax position liability 3,209 — — — 3,209
Non-current operating lease liabilities 284 — — — 284
Long-term debt, net of current maturities 1,910,318 — — — 1,910,318
Total liabilities 3,203,856 1,773,005 4,789 (2,632,733) 2,348,917
Stockholders’ equity:
Common stock 1,601 — — — 1,601
Paid-in capital 4,211,062 4,171,409 267,559 (4,438,968) 4,211,062
Accumulated other comprehensive loss (54,991) — (52,562) 52,562 (54,991)
Accumulated deficit (3,926,332) (2,250,485) (198,420) 2,448,905 (3,926,332)
Total stockholders’ equity 231,340 1,920,924 16,577 (1,937,501) 231,340
Total liabilities and stockholders’ equity
$ 3,435,196 $ 3,693,929 $ 21,366 $ (4,570,234) $ 2,580,257

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~~CONDENSED CONSOLIDATING BALANCE SHEETS~~

~~(Amounts in thousands)~~

December 31, 2019
Parent Guarantors Non-Guarantor Eliminations Consolidated
Assets
Current assets:
Cash and cash equivalents $ 2,768 $ 3,097 $ 195 $ — $ 6,060
Accounts receivable - oil and natural gas sales 859 120,351 — — 121,210
Accounts receivable - joint interest and other 5,279 42,696 — — 47,975
Accounts receivable - intercompany 1,065,593 843,223 — (1,908,816) —
Prepaid expenses and other current assets 4,047 308 76 — 4,431
Short-term derivative instruments 126,201 — — — 126,201
Total current assets 1,204,747 1,009,675 271 (1,908,816) 305,877
Property and equipment:
Oil and natural gas properties, full-cost accounting, 1,314,933 9,273,681 7,850 (729) 10,595,735
Other property and equipment 92,650 50 4,019 — 96,719
Accumulated depletion, depreciation, amortization and impairment (1,418,888) (5,808,254) (1,518) — (7,228,660)
Property and equipment, net (11,305) 3,465,477 10,351 (729) 3,463,794
Other assets:
Equity investments and investments in subsidiaries 3,064,503 6,332 21,000 (3,059,791) 32,044
Long-term derivative instruments 563 — — — 563
Deferred tax asset 7,563 — — — 7,563
Operating lease assets 14,168 — — — 14,168
Operating lease assets - related parties 43,270 — — — 43,270
Other assets 10,026 5,514 — — 15,540
Total other assets 3,140,093 11,846 21,000 (3,059,791) 113,148
Total assets $ 4,333,535 $ 4,486,998 $ 31,622 $ (4,969,336) $ 3,882,819
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable and accrued liabilities $ 48,006 $ 367,088 $ 124 $ — $ 415,218
Accounts payable - intercompany 878,283 1,026,249 4,285 (1,908,817) —
Short-term derivative instruments 303 — — — 303
Current portion of operating lease liabilities 13,826 — — — 13,826
Current portion of operating lease liabilities - related parties 21,220 — — — 21,220
Current maturities of long-term debt 631 — — — 631
Total current liabilities 962,269 1,393,337 4,409 (1,908,817) 451,198
Long-term derivative instruments 53,135 — — — 53,135
Asset retirement obligation - long-term — 58,322 2,033 — 60,355
Uncertain tax position liability 3,127 — — — 3,127
Non-current operating lease liabilities 342 — — — 342
Non-current operating lease liabilities - related parties 22,050 — — — 22,050
Long-term debt, net of current maturities 1,978,020 — — — 1,978,020
Total liabilities 3,018,943 1,451,659 6,442 (1,908,817) 2,568,227
Stockholders’ equity:
Common stock 1,597 — — — 1,597
Paid-in capital 4,207,554 4,171,408 267,557 (4,438,965) 4,207,554
Accumulated other comprehensive loss (46,833) — (44,763) 44,763 (46,833)
Accumulated deficit (2,847,726) (1,136,069) (197,614) 1,333,683 (2,847,726)
Total stockholders’ equity 1,314,592 3,035,339 25,180 (3,060,519) 1,314,592
Total liabilities and stockholders’ equity
$ 4,333,535 $ 4,486,998 $ 31,622 $ (4,969,336) $ 3,882,819

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~~CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS~~

~~(Amounts in thousands)~~

Three months ended June 30, 2020
Parent Guarantors Non-Guarantors Eliminations Consolidated
Total revenues $ 26,970 $ 105,440 $ — $ — $ 132,410
Costs and expenses:
Lease operating expenses — 15,686 — — 15,686
Production taxes — 3,605 — — 3,605
Midstream gathering and processing expenses — 59,974 — — 59,974
Depreciation, depletion and amortization 2,388 62,236 166 — 64,790
Impairment of oil and natural gas properties — 532,880 — — 532,880
General and administrative expenses 21,731 (11,374) 113 — 10,470
Accretion expense — 755 — — 755
Total Operating Expenses 24,119 663,762 279 — 688,160
INCOME (LOSS) FROM OPERATIONS 2,851 (558,322) (279) — (555,750)
OTHER EXPENSE (INCOME):
Interest expense 32,825 (459) — — 32,366
Interest income (28) (50) — — (78)
Gain on debt extinguishment (34,257) — — — (34,257)
Loss from equity method investments and investments in subsidiaries 562,502 — 45 (562,502) 45
Other expense 2,877 4,365 — — 7,242
Total Other Expense 563,919 3,856 45 (562,502) 5,318
LOSS BEFORE INCOME TAXES (561,068) (562,178) (324) 562,502 (561,068)
INCOME TAX EXPENSE — — — — —
NET LOSS $ (561,068) $ (562,178) $ (324) $ 562,502 $ (561,068)

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~~CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS~~

~~(Amounts in thousands)~~

Three months ended June 30, 2019
Parent Guarantors Non-Guarantor Eliminations Consolidated
Total revenues $ 280,291 $ 178,703 $ — $ — $ 458,994
Costs and expenses:
Lease operating expenses 12,256 10,132 — — 22,388
Production taxes 2,820 5,278 — — 8,098
Midstream gathering and processing expenses 28,121 43,894 — — 72,015
Depreciation, depletion and amortization 80,132 44,764 55 — 124,951
General and administrative expenses 15,207 (3,583) 103 — 11,727
Accretion expense 438 921 — — 1,359
Total Operating Expenses 138,974 101,406 158 — 240,538
INCOME (LOSS) FROM OPERATIONS 141,317 77,297 (158) — 218,456
OTHER EXPENSE (INCOME):
Interest expense 37,373 (955) — — 36,418
Interest income (120) (39) — — (159)
Loss (income) from equity method investments and investments in subsidiaries 47,449 — (54) 78,187 125,582
Other expense 990 — — — 990
Total Other Expense (Income) 85,692 (994) (54) 78,187 162,831
INCOME (LOSS) BEFORE INCOME TAXES 55,625 78,291 (104) (78,187) 55,625
INCOME TAX BENEFIT (179,331) — — — (179,331)
NET INCOME (LOSS) $ 234,956 $ 78,291 $ (104) $ (78,187) $ 234,956

March 31,

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~~CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS~~

~~(Amounts in thousands)~~

Six months ended June 30, 2020
Parent Guarantors Non-Guarantors Eliminations Consolidated
Total revenues $ 125,238 $ 254,049 $ — $ — $ 379,287
Costs and expenses:
Lease operating expenses — 31,672 — — 31,672
Production taxes — 8,404 — — 8,404
Midstream gathering and processing expenses — 117,870 — — 117,870
Depreciation, depletion, and amortization 4,890 137,596 332 — 142,818
Impairment of oil and gas properties — 1,086,225 — — 1,086,225
General and administrative expenses 46,377 (20,024) 286 — 26,639
Accretion expense — 1,496 — — 1,496
Total Operating Expenses 51,267 1,363,239 618 — 1,415,124
INCOME (LOSS) FROM OPERATIONS 73,971 (1,109,190) (618) — (1,035,837)
OTHER EXPENSE (INCOME):
Interest expense 66,002 (646) — — 65,356
Interest income (87) (143) — — (230)
Gain on debt extinguishment (49,579) — — — (49,579)
Loss from equity method investments and investments in subsidiaries 1,125,868 — 188 (1,115,222) 10,834
Other expense 3,083 6,015 — — 9,098
Total Other Expense 1,145,287 5,226 188 (1,115,222) 35,479
LOSS BEFORE INCOME TAXES (1,071,316) (1,114,416) (806) 1,115,222 (1,071,316)
INCOME TAX EXPENSE 7,290 — — — 7,290
NET LOSS $ (1,078,606) $ (1,114,416) $ (806) $ 1,115,222 $ (1,078,606)

~~Table of Contents~~

~~CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS~~

~~(Amounts in thousands)~~

Six months ended June 30, 2019
Parent Guarantors Non-Guarantor Eliminations Consolidated
Total revenues $ 466,537 $ 313,035 $ — $ — $ 779,572
Costs and expenses:
Lease operating expenses 27,149 15,046 — — 42,195
Production taxes 6,081 9,938 — — 16,019
Midstream gathering and processing expenses 71,420 70,877 — — 142,297
Depreciation, depletion, and amortization 198,564 44,765 55 — 243,384
General and administrative expenses 25,938 (4,258) 104 — 21,784
Accretion expense 1,389 1,037 — — 2,426
Total Operating Expenses 330,541 137,405 159 — 468,105
INCOME (LOSS) FROM OPERATIONS 135,996 175,630 (159) — 311,467
OTHER EXPENSE (INCOME):
Interest expense 73,298 (1,259) — — 72,039
Interest income (267) (44) — — (311)
(Income) loss from equity method investments and investments in subsidiaries (55,465) — 339 176,435 121,309
Other expense 563 — — — 563
Total Other Expense (Income) 18,129 (1,303) 339 176,435 193,600
INCOME (LOSS) BEFORE INCOME TAXES 117,867 176,933 (498) (176,435) 117,867
INCOME TAX BENEFIT (179,331) — — — (179,331)
NET INCOME (LOSS) $ 297,198 $ 176,933 $ (498) $ (176,435) $ 297,198

~~Table of Contents~~

~~CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME (LOSS)~~

~~(Amounts in thousands)~~

Three months ended June 30, 2020
Parent Guarantors Non-Guarantors Eliminations Consolidated
Net loss $ (561,068) $ (562,178) $ (324) $ 562,502 $ (561,068)
Foreign currency translation adjustment 6,872 — 6,872 (6,872) 6,872
Other comprehensive loss 6,872 — 6,872 (6,872) 6,872
Comprehensive loss $ (554,196) $ (562,178) $ 6,548 $ 555,630 $ (554,196)

2021.

Three months ended June 30, 2019
Parent Guarantors Non-Guarantor Eliminations Consolidated
Net income (loss) $ 234,956 $ 78,291 $ (104) $ (78,187) $ 234,956
Foreign currency translation adjustment 3,610 61 3,549 (3,610) 3,610
Other comprehensive income 3,610 61 3,549 (3,610) 3,610
Comprehensive income $ 238,566 $ 78,352 $ 3,445 $ (81,797) $ 238,566

Six months ended June 30, 2020
Parent Guarantors Non-Guarantors Eliminations Consolidated
Net loss $ (1,078,606) $ (1,114,416) $ (806) $ 1,115,222 $ (1,078,606)
Foreign currency translation adjustment (8,158) (360) (7,798) 8,158 (8,158)
Other comprehensive loss (8,158) (360) (7,798) 8,158 (8,158)
Comprehensive loss $ (1,086,764) $ (1,114,776) $ (8,604) $ 1,123,380 $ (1,086,764)

Six months ended June 30, 2019
Parent Guarantors Non-Guarantor Eliminations Consolidated
Net income (loss) $ 297,198 $ 176,933 $ (498) $ (176,435) $ 297,198
Foreign currency translation adjustment 7,411 155 7,256 (7,411) 7,411
Other comprehensive income 7,411 155 7,256 (7,411) 7,411
Comprehensive income $ 304,609 $ 177,088 $ 6,758 $ (183,846) $ 304,609

~~Table of Contents~~

~~CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS~~

~~(Amounts in thousands)~~

Six months ended June 30, 2020
Parent Guarantors Non-Guarantors Eliminations Consolidated
Net cash provided by (used in) operating activities $ 18,854 $ 228,317 $ (384) $ 435 $ 247,222
Net cash used in investing activities (424) (229,666) — — (230,090)
Net cash (used in) provided by financing activities (20,375) — 435 (435) (20,375)
Net (decrease) increase in cash, cash equivalents and restricted cash (1,945) (1,349) 51 — (3,243)
Cash, cash equivalents and restricted cash at beginning of period 2,768 3,097 195 — 6,060
Cash, cash equivalents and restricted cash at end of period $ 823 $ 1,748 $ 246 $ — $ 2,817

Six months ended June 30, 2019
Parent Guarantors Non-Guarantor Eliminations Consolidated
Net cash provided by (used in) operating activities $ 312,267 $ 84,146 $ 3,355 $ 1 $ 399,769
Net cash used in investing activities (405,848) (101,058) (3,751) 432 (510,225)
Net cash (used in) provided by financing activities 78,936 — 433 (433) 78,936
Net decrease in cash, cash equivalents and restricted cash (14,645) (16,912) 37 — (31,520)
Cash, cash equivalents and restricted cash at beginning of period 25,585 26,711 1 — 52,297
Cash, cash equivalents and restricted cash at end of period $ 10,940 $ 9,799 $ 38 $ — $ 20,777

~~Table of Contents~~

~~16.~~14.SUBSEQUENT EVENTS

~~Amendment~~Chapter 11 Proceedings Update

The Bankruptcy Court entered an order confirming the Plan on April 28, 2021. In support of the Plan, the enterprise value of the Successor was estimated and approved by the Bankruptcy Court to ~~Credit Facility~~

be in the range of
$1.3 billion to $1.9 billion.

~~On July 27, 2020,~~Upon emergence from bankruptcy, which is expected to occur in May 2021, Gulfport ~~entered into~~expects to qualify for fresh-start reporting. In order to qualify for fresh start-reporting (i) the holders of existing voting shares of the Company prior to its emergence must receive less than 50% of the voting shares of the Company outstanding following its emergence from bankruptcy and (ii) the reorganization value of our assets immediately prior to confirmation of the plan of reorganization must be less than the post-petition liabilities and allowed claims. Under the principles of fresh-start reporting, a Sixteenth Amendment to the Amended and Restated Credit Agreement. Among other changes, the Sixteenth Amendment amends the Credit Agreement to: (i) require that, in the event of any issuances of Senior Notes, including Second Lien Notes, after the effective date, the then effective borrowing basenew reporting entity will be ~~reduced by~~considered to have been created, and, as a ~~variable amount prescribed in~~result, the ~~Credit Agreement to~~Company will allocate the ~~extent the proceeds are not used to satisfy previously issued senior notes within 90 days of such issuance; (ii) require that each Loan Notice specify the amount~~reorganization value of the ~~then effective Borrowing Base~~Company to its individual assets, including property, plant and ~~Pro Forma Borrowing Base,~~equipment, based on their estimated fair values. Gulfport cannot currently estimate the ~~Aggregate Elected Commitment Amount,~~financial effect of emergence from bankruptcy on its financial statements, although it expects to record material adjustments related to its Plan and the ~~current Total Outstandings, both with~~application of fresh-start reporting guidance upon the Effective Date.

Natural Gas, Oil and ~~without regard~~Natural Gas Liquids Derivative Instruments

Subsequent to the requested Borrowing; (iii) permit the Borrower or any Restricted Subsidiary to enter into obligations in connection with a Permitted Bond Hedge Transaction or Permitted Warrant Transaction; (iv) permit the Borrower to make any paymentsMarch 31, 2021 and as of Senior Notes and Subordinated Obligation prior to their scheduled maturity, in any event not to exceed $750,000,000 or, if lesser, the net cash proceeds of any Senior Notes issued within 90 days before such payment; (v) require that the Senior Notes have a stated maturity date of no earlier than March 13, 2024, as well as not require payment of principal prior to such date, in order for the Borrower to be permitted to secure indebtedness under the Senior Notes; (vi) permit certain additional liens securing obligations in respect of the incurrence or issuance of any Permitted Refinancing Notes (as such term is defined in the Credit Agreement) not to exceed $750,000,000, subject to the terms of an intercreditor agreement; and (vii) amend and restate the Applicable Rate Grid~~to provide as follows:~~

Applicable Rate
Applicable Usage Level Commitment fee Eurodollar Rate Loans and Letters of Credit Base Rate Loans
Level 1 0.375% 2.00% 1.00%
Level 2 0.375% 2.25% 1.25%
Level 3 0.50% 2.50% 1.50%
Level 4 0.50% 2.75% 1.75%
Level 5 0.50% 3.00% 2.00%

~~Derivatives~~

~~In August 2020,~~April 30, 2021, the Company entered into the following natural gas ~~fixed price swap~~and oil derivative contracts as it completed minimum hedging requirements as provided for in the ~~fourth quarter of 2020 covering approximately 100,000 MMBtu of natural~~RSA:

Period

Type of Derivative Instrument

Index

Daily Volume(1)

Weighted
Average Price

November 2021 - March 2022

Basis Swaps

Rex Zone 3

40,000

(0.10)

April 2022 - December 2022

Costless Collars

NYMEX Henry Hub

139,773

$2.40/$2.60

January 2022 - December 2022

Costless Collars

NYMEX WTI

1,500

$55.00/$60.00

(1) Volume units for gas ~~per~~ instruments are presented as MMBtu/day ~~at an average swap price of $2.38 per MMBtu.~~and oil is presented in Bbls/day.

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

The following discussion and analysis should be read in conjunction with the “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section and audited consolidated financial statements and related notes included in our Annual Report on Form 10-K and with the unaudited consolidated financial statements and related notes thereto presented in this Quarterly Report on Form 10-Q.

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 such things as the potential effects of the Chapter 11 Cases on our operations, management, and employees, our ability to consummate the restructuring, our ability to continue as a going concern, 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), ~~the effect of our remediation plan for a material weakness,~~ 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, ~~2019~~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.

Investors should note that we announce financial information in SEC ~~filings, press releases and public conference calls.~~filings. 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.

Overview

We are an independent natural gas-weighted exploration and production company focused on the exploration, acquisition and production of natural gas, crude oil and ~~natural gas liquids ("NGL")~~NGL in the United States with primary focus in the Appalachia and Anadarko

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~~Appalachia and Mid-Continent~~ 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.

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 are being administered jointly under the caption In re Gulfport Energy Corporation, et al., Case No. 20-35562 (DRJ). We continue to operate our businesses as "debtors-in-possession" under the jurisdiction of the Bankruptcy Court, in accordance with the applicable provisions of the Bankruptcy Code and the orders of the Bankruptcy Court.

The Bankruptcy Court has granted first- and second-day motions filed by us that were designed primarily to mitigate the impact of the Chapter 11 Cases on our operations, customers and employees. As a result, we are able to conduct normal business activities and pay all associated obligations for the period following the Bankruptcy Filing and are authorized to pay owner royalties, employee wages and benefits and certain vendors and suppliers in the ordinary course for goods and services provided. During the pendency of the Chapter 11 Cases, all transactions outside the ordinary course of business require the prior approval of the Bankruptcy Court.

~~COVID-19~~

~~In March 2020,~~For the ~~World Health Organization classified~~duration of the ~~outbreak of COVID-19~~Chapter 11 Cases, our operations and ability to develop and execute our business plan are subject to the risks and uncertainties associated with the Chapter 11 process as a pandemic and recommended containment and mitigation measures worldwide. The measures have led to worldwide shutdowns and halting of commercial and interpersonal activity, as governments around the world imposed regulationsdescribed in ~~efforts to control the spread of COVID-19 such as shelter-in-place orders, quarantines, executive orders and similar restrictions.~~

~~We remain focused on protecting the health and well-being~~"Risk Factors" in Item 1A. of our ~~employees~~Annual Report on Form 10-K for the year ended December 31, 2020. As a result of these risks and the communities in which we operate while assuring the continuity of our business operations. We have implemented preventative measures and developed corporate and field response plans to minimize unnecessary risk of exposure and prevent infection. We have a crisis management team for health, safety and environmental matters and personnel issues, and we have established a COVID-19 Response Team to address various impacts of the situation, as they have been developing. We also have modified certain business practices (including remote working for our corporate employees and restricted employee business travel) to conform to government restrictions and best practices encouraged by the Centers for Disease Control and Prevention, the World Health Organization and other governmental and regulatory authorities.

On May 18, 2020, we began our phased transition back to the office for our corporate employees. As part of this transition, we have put into place preventative measures to focus on social distancing and minimizing unnecessary risk of exposure. Such measures include, but are not limited to, daily health surveys, protective masks in public areas of the building, no outside visitors, limitinguncertainties, the number of ~~employees on elevators, additional sanitizing~~our shares of common stock and ~~100%~~stockholders, assets, liabilities, officers and/or directors could be significantly different following the outcome of the ~~corporate employees working remotely on Fridays~~Chapter 11 Cases, and the description of our operations, properties and capital plans included in this Form 10-Q may not accurately reflect our operations, properties and capital plans following the Chapter 11 Cases.

During the Chapter 11 Cases, we expect our financial results to ~~provide additional time for deep cleaning.~~continue to be volatile as restructuring activities and expenses, contract terminations and rejections and claims assessments significantly impact our consolidated financial statements. As a result, our historical financial performance is likely not indicative of our financial performance after the date of ~~this filing,~~the Bankruptcy Filing. In addition, we have ~~transitioned approximately 60% of our corporate employees back to~~incurred significant professional fees and other costs in connection with the ~~corporate office. We~~Chapter 11 Cases and expect that we will continue to ~~monitor trends~~incur significant professional fees and ~~governmental guidelines and may adjust~~costs throughout our ~~return~~Chapter 11 Cases until emergence.

See Note 2 of the notes to ~~office plans accordingly to ensure~~our consolidated financial statements included in Item 8 of Part II of this report for a complete discussion of the ~~health and safety~~Chapter 11 Cases.

Delisting of our ~~employees.~~Common Stock from Nasdaq

On November 27, 2020, our common stock was suspended from trading on NASDAQ. On November 30, 2020, our common stock began trading on the OTC Pink Marketplace maintained by the OTC Markets Group, Inc. under the symbol “GPORQ". On February 2, 2021, NASDAQ filed a Form 25 delisting our common stock from trading on NASDAQ, which delisting became effective 10 days after the filing of the Form 25. In accordance with Rule 12d2-2 of the Securities Exchange Act of 1934, as amended (the "Exchange Act"), the de-registration of our common stock under section 12(b) of the Exchange Act became effective on February 12, 2021.

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 ~~in the first and second quarters of 2020.~~due to COVID-19. While we ~~have~~did not ~~experienced~~experience significant disruptions to our operations in ~~2020,~~the first quarter 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. There is considerable uncertainty regarding the extent to which COVID-19 will continue to spread and the extent and duration of governmental and other measures implemented to slow the spread of the virus, such as large-scale travel bans and restrictions, quarantines, shelter-in-place orders and business and government shutdowns. Restrictions ~~of this nature~~ 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. ~~The~~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.

One of the impacts of the pandemic has been a significant reduction in global demand for oil and natural gas. The significant decline in demand has been met with a sharp decline in oil prices following the announcement of price reductions and production increases in March 2020 by members of the Organization of Petroleum Exporting Countries, and other foreign, oil-exporting countries. The resulting supply/demand imbalance is having disruptive impacts on the oil and natural gas exploration and production industry and on other industries that serve exploration and production companies. These industry conditions, coupled with those resulting from the COVID-19 pandemic, could lead to significant global economic contraction generally and in our industry in particular. We expect to see continued volatility in oil and natural gas prices for the foreseeable future, which may, over the long term, adversely impact our business. A significant decline in demand or prices for oil and natural gas would have a material adverse effect on our business, cash flows, liquidity, financial condition and results of operations.

Because of the sharp decline in oil prices since early March 2020, we chose to shut in a portion of our operated low margin, liquids-weighted production during the second quarter of 2020, largely consisting of legacy vertical production in the SCOOP. We also experienced shut ins across both the SCOOP and Utica from our non-operated partners. Nearly all liquids-weighted volumes on both our operated assets and those of our non-operated partners have returned to production. A sharp decline in prices or a pro-longed depressed environment may result in additional future shut ins. In addition, the COVID-19 pandemic

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~~creates risks of delays in new drilling and completion activities that could negatively impact us, our non-operated partners or our service providers.~~

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 including, among others, the ultimate geographic spread of the virus, the consequences of governmental and other measures designed to prevent the spread of the virus, the development of effective treatments, the duration of the outbreak, actions taken by members of OPEC and other foreign, oil-exporting countries, governmental authorities, customers, suppliers and other thirds parties, workforce availability, and the timing and extent to which normal economic and operating conditions resume. ~~For additional discussion~~While we have seen meaningful recovery in demand during the second half 2020 and into 2021, significant uncertainty remains regarding ~~risks associated with~~ the ~~COVID-19 pandemic, see Item 1A “Risk Factors” in this report.~~

~~Also, in response to the current commodity price environment, we announced tiered salary reduction for most employees, senior management team~~duration and our Board of Directors with such measures expected to last through December 2020. In addition, select furloughs were implemented to reduce costs and preserve liquidity. We continue to evaluate ways to reduce our cost structure in an effort to improve profitability during this economic and commodity price downturn.

~~As noted above, decreased demand for oil and natural gas as a result~~extent of the COVID-19 pandemic and the accompanying decrease in commodity prices has significantly reduced our ability to access capital markets and to refinance our existing indebtedness. Further, these conditions have made amendments or waivers to our revolving credit facility more difficult to obtain and available on terms less favorable to us. If depressed commodity prices persist or decline further, the borrowing base under our revolving credit facility could be further reduced at our next scheduled redetermination date in November 2020. Any such reduction would constrain our liquidity and may impair our ability to fund our planned capital expenditures and meet our obligations under our existing indebtedness. Further, a reduction in our capital expenditures would decrease our production, revenues, operating cash flow and EBITDA, which could limit our ability to comply with the restrictive covenants in our revolving credit facility and other existing indebtedness. Finally, our existing revolving credit facility matures in December 2021 and therefore will become a current liability at year end 2020 unless we are able to refinance the credit facility with a new credit facility or other financing. Considering the current stateimpact of the first lien market and our elevated leverage profile, there is substantial risk that a refinancing will not be available to us on reasonable terms. A current liability under the revolving credit facility at year end 2020 may result in a qualified audit opinion which could result in a default under the terms of the current revolving credit facility. As a result of these uncertainties and other factors, management has concluded that there is substantial doubt about our ability to continue as a going concern. Failure to meet our obligations under our existing indebtedness or failure to comply with any of our covenants, if not waived, would result in an event of default under such indebtedness and result in the potential acceleration of outstanding indebtedness thereunder and, with respect to the revolving credit facility, the potential foreclosurepandemic on the ~~collateral securing such debt,~~energy industry, including demand and ~~could cause a cross-default under our other outstanding indebtedness.~~

As of June 30, 2020, we had entered into firm transportation contracts to deliver approximately 1,455,000 MMBtu per day for the remainder of 2020 and 2021, respectively. Under these firm transportation contracts, we are obligated to deliver minimum daily volumes or pay fees for any deficiencies in deliveries. As a result of the reduced production from our Utica Shale or SCOOP acreage due to decreased developmental activities, taking into consideration the current low commodity price environment,commodities pricing, although we expect ~~that we will be unable~~ to ~~meet our obligations under the existing firm transportation contracts, resulting in fees, which may be significant~~see further recovery as vaccines are distributed and ~~may have a material adverse effect on our operations.~~more normal societal activity resumes.

~~2020~~

2021 Operational and Financial Highlights

Despite the challenges our company and the entire upstream energy industry faces from low commodity prices, we have remained committed to the execution of our strategy and to position Gulfport for long-term success. During the three ~~and six~~ months ended ~~June 30, 2020,~~March 31, 2021, we had the following notable achievements:

•~~Continued~~An order was entered to confirm our ~~efforts~~Plan by the Bankruptcy Court on April 28, 2021. We expect to ~~improve~~emerge from Chapter 11 proceedings and complete our ~~balance sheet by reducing long-term debt by approximately $70 million as compared to December 31, 2019 primarily through discounted bond repurchases.~~financial restructuring in May 2021.

•~~Continued~~We continued to improve operational efficiencies and reduce drilling and completion costs in ~~both~~ our ~~SCOOP and Utica~~ operating areas. In the Utica, our average spud to rig release time was ~~18.5~~17.0 days in the first ~~half~~quarter of ~~2020,~~2021, which was a 6%9% improvement from full year ~~2019 levels. In the SCOOP, our average spud to rig release time was 37 days, representing a 32% improvement compared to full year 2019~~2020 levels.

•~~Closed on the sale~~We have continued to decrease costs as a result of our ~~SCOOP water infrastructure assets on January 2,~~ongoing cost reduction initiatives highlighted by a 7% decrease in lease operating expenses per Mcfe and a 13% decrease in general and administrative expenses per Mcfe for the first quarter of 2021 as compared to the first quarter of 2020. ~~We received $50.0 million in cash upon closing and have an opportunity to earn additional incentive payments over the next 15 years, subject to our~~

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ability to meet certain thresholds which will be driven by, among other things, our future development program and future water production levels. Proceeds from the divestiture were used to reduce our outstanding revolver balance.

~~Table of Contents~~

~~2020~~2021 Production and Drilling Activity

Production Volumes


		Three months ended June 30,
		2020	% of Total		2019	% of Total		Change	% Change			Three months ended March 31,
		($ In thousands)																	2021		% of Total	2020	% of Total	Change	% Change
Natural gas (Mcf/day)	Natural gas (Mcf/day)										Natural gas (Mcf/day)
Utica Shale		775,070	83	%	1,014,302	83	%	(239,232)	(24)	%
Utica											Utica	797,452	88	%	785,781	83	%	11,671	1	%
SCOOP	SCOOP	158,813	17	%	211,898	17	%	(53,085)	(25)	%	SCOOP	111,708	12	%	159,886	17	%	(48,178)	(30)	%
Other	Other	53	—	%	205	—	%	(152)	(74)	%	Other	80	—	%	39	—	%	41	105	%
Total	Total	933,936			1,226,405			(292,469)	(24)	%	Total	909,240			945,706			(36,466)	(5)	%
Oil and condensate (Bbls/day)
Utica Shale		308	7	%	621	9	%	(313)	(50)	%
Oil and condensate (Bbl/day)											Oil and condensate (Bbl/day)
Utica											Utica	1,403	37	%	592	10	%	811	137	%
SCOOP	SCOOP	4,186	91	%	4,899	69	%	(713)	(15)	%	SCOOP	2,379	62	%	5,174	89	%	(2,795)	(54)	%
Other	Other	83	2	%	1,614	22	%	(1,531)	(95)	%	Other	40	1	%	78	1	%	(38)	(49)	%
Total	Total	4,577			7,134			(2,557)	(36)	%	Total	3,822			5,844			(2,022)	(35)	%
NGL (Gal/day)
Utica Shale		106,333	23	%	228,871	36	%	(122,538)	(54)	%
NGL (Bbl/day)											NGL (Bbl/day)
Utica											Utica	2,665	32	%	3,197	26	%	(532)	(17)	%
SCOOP	SCOOP	353,252	77	%	399,368	64	%	(46,116)	(12)	%	SCOOP	5,758	68	%	8,974	74	%	(3,216)	(36)	%
Other	Other	72	—	%	208	—	%	(136)	(65)	%	Other	4	—	%	—	—	%	4	100	%
Total	Total	459,657			628,447			(168,790)	(27)	%	Total	8,427			12,171			(3,744)	(31)	%
Combined (Mcfe/day)	Combined (Mcfe/day)										Combined (Mcfe/day)
Utica Shale		792,106	77	%	1,050,724	77	%	(258,618)	(25)	%
Utica											Utica	821,858	84	%	808,520	77	%	13,338	2	%
SCOOP	SCOOP	234,396	23	%	298,343	22	%	(63,947)	(21)	%	SCOOP	160,528	16	%	244,771	23	%	(84,243)	(34)	%
Other	Other	563	—	%	9,922	1	%	(9,359)	(94)	%	Other	343	—	%	508	—	%	(165)	(32)	%
Total	Total	1,027,065			1,358,989			(331,924)	(24)	%	Total	982,729			1,053,799			(71,070)	(7)	%

Our total net production averaged ~~approx~~approximately 982.7 M~~imately~~ ~~1,027.1~~ ~~MMcfe~~Mcfe per day during the three months ended ~~June 30, 2020,~~March 31, 2021, as compared to ~~1,359.0~~1,053.8 MMcfe per day during the same period in ~~2019.~~2020. The ~~24%~~7% decrease in production is largely the result of a decrease in development activities ~~of our Utica Shale and SCOOP operating areas beginning~~ in the third and fourth quarters of 2019. Additionally, in response to sharp declines in commodity prices resulting from COVID-19 uncertainties, beginning in March 2020, we chose to shut in a portion of our operated low margin, liquids-weighted production during the second quarter of 2020, largely consisting of legacy vertical production in the SCOOP. We also experienced shut ins across both the SCOOP ~~and Utica from our non-operated partners. Nearly all liquids-weighted volumes on both our operated assets and those of our non-operated partners have returned to production.~~

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Six months ended June 30,
2020 % of Total 2019 % of Total Change % Change
($ In thousands)
Natural gas (Mcf/day)
Utica Shale 780,426 83 % 983,436 83 % (203,010) (21) %
SCOOP 159,349 17 % 196,955 17 % (37,606) (19) %
Other 46 — % 173 — % (127) (73) %
Total 939,821 1,180,564 (240,743) (20) %
Oil and condensate (Bbls/day)
Utica Shale 450 9 % 675 10 % (225) (33) %
SCOOP 4,680 90 % 4,661 67 % 19 — %
Other 81 1 % 1,630 23 % (1,549) (95) %
Total 5,211 6,966 (1,755) (25) %
NGL (Gal/day)
Utica Shale 120,313 25 % 243,995 39 % (123,682) (51) %
SCOOP 365,073 75 % 380,234 61 % (15,161) (4) %
Other 34 — % 186 — % (152) (82) %
Total 485,420 624,415 (138,995) (22) %
Combined (Mcfe/day)
Utica Shale 800,313 77 % 1,022,341 78 % (222,028) (22) %
SCOOP 239,583 23 % 279,243 21 % (39,660) (14) %
Other 536 — % 9,983 1 % (9,447) (95) %
Total 1,040,432 1,311,567 (271,135) (21) %

~~Our total net production averaged approximately~~ ~~1,040.4~~ ~~MMcfe per day during the~~ ~~six months ended June 30, 2020, as compared t~~o 1,311.6 MMcfe per day during the same period in 2019. The 21% decrease in production is largely the result of a decrease in development activities of our Utica Shale and SCOOP operating areas beginning in the third and fourth quarters of 2019. Additionally, in response to sharp declines in commodity prices resulting from COVID-19 uncertainties, beginning in March 2020, we chose to shut in a portion of our operated low margin, liquids-weighted production during the second quarter of 2020, largely consisting of legacy vertical production in the SCOOP. We also experienced shut ins across both the SCOOP and Utica from our non-operated partners. Nearly all liquids-weighted volumes on both our operated assets and those of our non-operated partners have returned to production.throughout 2020.

Utica ~~Shale~~. From January 1, ~~2020~~2021 through ~~June 30, 2020,~~March 31, 2021, we spud 12nine gross ~~(11.1~~(nine net) wells in the Utica, ~~Shale,~~ of which ~~one was~~five were being drilled and 11four were in various stages of operations at ~~June 30, 2020.~~March 31, 2021. In addition, we completed 22seven gross and net operated wells. We did not participate in any additional wells that were drilled by other operators on our Utica ~~Shale~~ acreage.

As of ~~July 31, 2020,~~April 30, 2021, we had two operated drilling rigs running in the Utica, both of which we expect to release in May 2021. We expect to add back one operated drilling rig ~~running~~ in the ~~play and expect to continue with this level of activity through~~Utica in the third quarter of ~~2020.~~

Aggregate net production from our Utica Shale acreage during the three months ended June 30, 2020 was approximately 72,082 MMcfe, or an average of 792.1 MMcfe per day, of which 98% was natural gas and 2% was oil and NGL.2021.

SCOOP. From January 1, ~~2020~~2021 through ~~June 30, 2020,~~March 31, 2021, we did not spud ~~six gross (5.2 net)~~any wells in the ~~SCOOP, of which~~ ~~one~~ ~~was being drilled and~~ ~~five~~ ~~were in various stages of operations at June 30, 2020. In addition. we~~SCOOP. We completed 4three gross ~~(3.8~~(2.69 net) operated wells. We also participated in an additional ~~five~~three gross wells that were drilled by other operators on our SCOOP acreage.

As of ~~July 31, 2020,~~April 30, 2021, we had one operated drilling rig running in the ~~play and~~SCOOP, which we expect towill continue ~~with this level of activity for~~through the remainder of ~~2020.~~

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~~Aggregate net production from our SCOOP acreage during the three months ended June 30, 2020 was approximately~~ ~~21,330~~ ~~MMcfe, or an average of~~ ~~234.4~~ ~~MMcfe per day, of which~~ ~~68%~~ ~~was from natural gas and~~ ~~32%~~ ~~was from oil and NGL.~~2021.

RESULTS OF OPERATIONS

Comparison of the Three Month Periods Ended ~~June 30,~~March 31, 2021 and 2020 ~~and 2019~~

We reported a net ~~loss~~income of ~~$561.1~~$8.8 million for the three months ended ~~June 30, 2020~~March 31, 2021 as compared to net ~~income~~loss of ~~$235.0~~$517.5 million for the three months ended June 30, 2019. Included in the loss for the three months ended June 30, 2020 was a $532.9 million non-cash impairment of our oil and natural gas properties, which primarily resulted from a significant decrease in the trailing twelve month first of month prices of natural gas, oil and NGL, and was the main driver ofMarch 31, 2020. The graph below shows the change in ~~our~~the net income (loss) ~~income during the period. Additionally, pricing for all of our commodities decreased significantly during the second quarter of 2020, resulting in a~~ ~~$182.4 million decrease in~~ ~~natural gas, oil and NGL sales and a~~ ~~$144.2 million~~ ~~decrease in gain on natural gas, oil and NGL derivatives. This increase in loss is partially offset by~~ ~~a $125.5 million decrease in loss~~ from equity method investments, a $60.2 million decrease in DD&A, a $34.3 million gain on debt extinguishment, a $12.0 million decrease in midstream gathering and processing expenses, a $6.7 million decrease in lease operating expenses and a $4.5 million decrease in production taxes for the three

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months ended ~~June 30,~~March 31, 2020 ~~as compared~~ to the three months ended ~~June 30, 2019.~~March 31, 2021. The material changes are further discussed by category on the following pages. Some totals and changes throughout below section may not sum or recalculate due to rounding.

(1) Includes lease operating expenses, taxes other than income and transportation, gathering, processing and compression.

Natural Gas, Oil and NGL Sales


		Three months ended June 30,											Three months ended March 31,
		2020		2019		change			2021		2020		change
		($ In thousands)											($ In thousands)
Natural gas	Natural gas	86,797		225,257		(61)	%	Natural gas	$	235,321	$	161,008	46	%
Oil and condensate	Oil and condensate	8,390		36,910		(77)	%	Oil and condensate	18,239		23,151		(21)	%
NGL	NGL	10,252		25,687		(60)	%	NGL	23,776		16,913		41	%
Natural gas, oil and NGL sales	Natural gas, oil and NGL sales	$	105,439	$	287,854	(63)	%	Natural gas, oil and NGL sales	$	277,336	$	201,072	38	%

The ~~decrease~~increase in natural gas sales without the impact of derivatives was duedue to a 49~~% decrease~~54% increase in realized natural gas prices ~~and~~ partially offset by a ~~24%~~5% decrease in ~~natural gas~~ sales volumes.

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The decrease in oil and condensate sales without the impact of derivatives was due to a ~~65% decrease in realized oil and condensate prices and a 36%~~35% decrease in oil and condensate sales ~~volumes.~~volumes partially offset by a 22% increase in realized oil and condensate prices.

The ~~decrease~~increase in NGL sales without the impact of derivatives was due to a 45~~% decrease~~105% increase in realized ~~NGL~~ prices ~~and~~partially offset by a ~~27%~~31% decrease in NGL sales volumes.

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Natural Gas, Oil and NGL Derivatives


		Three months ended June 30,							Three months ended March 31,
		2020		2019			2021		2020
		($ In thousands)							($ In thousands)
Natural gas derivatives - fair value (losses) gains		$	(48,146)	$	132,760
Natural gas derivatives - fair value losses						Natural gas derivatives - fair value losses	$	(25,538)	$	(15,125)
Natural gas derivatives - settlement gains	Natural gas derivatives - settlement gains	83,835		19,715		Natural gas derivatives - settlement gains	125		60,978
Total gains on natural gas derivatives		35,689		152,475
Total (losses) gains on natural gas derivatives						Total (losses) gains on natural gas derivatives	(25,413)		45,853

Oil and condensate derivatives - fair value (losses) gains	Oil and condensate derivatives - fair value (losses) gains	(48,386)		11,501		Oil and condensate derivatives - fair value (losses) gains	(1,731)		43,374
Oil and condensate derivatives - settlement gains	Oil and condensate derivatives - settlement gains	40,449		370		Oil and condensate derivatives - settlement gains	—		9,500
Total (losses) gains on oil and condensate derivatives	Total (losses) gains on oil and condensate derivatives	(7,937)		11,871		Total (losses) gains on oil and condensate derivatives	(1,731)		52,874

NGL derivatives - fair value (losses) gains	NGL derivatives - fair value (losses) gains	(997)		3,537		NGL derivatives - fair value (losses) gains	(2,834)		665
NGL derivatives - settlement gains	NGL derivatives - settlement gains	216		3,257		NGL derivatives - settlement gains	—		255
Total (losses) gains on NGL derivatives	Total (losses) gains on NGL derivatives	(781)		6,794		Total (losses) gains on NGL derivatives	(2,834)		920

Contingent consideration arrangement - fair value losses	Contingent consideration arrangement - fair value losses	—		—		Contingent consideration arrangement - fair value losses	—		(1,381)
Total gains on natural gas, oil and NGL derivatives		$	26,971	$	171,140
Total (losses) gains on natural gas, oil and NGL derivatives						Total (losses) gains on natural gas, oil and NGL derivatives	$	(29,978)	$	98,266

See Note 109 to our consolidated financial statements for further discussion of our derivative activity.

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 three months ended ~~June 30, 2020,~~March 31, 2021, as compared to such data for the three months ended ~~June 30, 2019:~~March 31, 2020:

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Three months ended June 30,
2020 2019
($ In thousands)
Natural gas sales
Natural gas production volumes (MMcf) 84,988 111,603
Total natural gas sales $ 86,797 $ 225,257
Natural gas sales without the impact of derivatives ($/Mcf) $ 1.02 $ 2.02
Impact from settled derivatives ($/Mcf) $ 0.99 $ 0.18
Average natural gas sales price, including settled derivatives ($/Mcf) $ 2.01 $ 2.20
Oil and condensate sales
Oil and condensate production volumes (MBbls) 417 649
Total oil and condensate sales $ 8,390 $ 36,910
Oil and condensate sales without the impact of derivatives ($/Bbl) $ 20.14 $ 56.85
Impact from settled derivatives ($/Bbl) $ 97.12 $ 0.57
Average oil and condensate sales price, including settled derivatives ($/Bbl) $ 117.26 $ 57.42
NGL sales
NGL production volumes (MGal) 41,829 57,189
Total NGL sales $ 10,252 $ 25,687
NGL sales without the impact of derivatives ($/Gal) $ 0.25 $ 0.45
Impact from settled derivatives ($/Gal) $ — $ 0.06
Average NGL sales price, including settled derivatives ($/Gal) $ 0.25 $ 0.51
Natural gas, oil and condensate and NGL sales
Natural gas equivalents (MMcfe) 93,463 123,668
Total natural gas, oil and condensate and NGL sales $ 105,439 $ 287,854
Natural gas, oil and condensate and NGL sales without the impact of derivatives ($/Mcfe) $ 1.13 $ 2.33
Impact from settled derivatives ($/Mcfe) $ 1.33 $ 0.19
Average natural gas, oil and condensate and NGL sales price, including settled derivatives ($/Mcfe) $ 2.46 $ 2.52
Production Costs:
Average lease operating expenses ($/Mcfe) $ 0.17 $ 0.18
Average production taxes ($/Mcfe) $ 0.04 $ 0.07
Average midstream gathering and processing ($/Mcfe) $ 0.64 $ 0.58
Total lease operating expenses, midstream costs and production taxes ($/Mcfe) $ 0.85 $ 0.83


	Three months ended March 31,
	2021		2020
	($ In thousands)
Natural gas sales
Natural gas production volumes (MMcf)	81,832		86,059
Natural gas production volumes (MMcf) per day	909		946
Total sales	235,321		161,008
Average price without the impact of derivatives ($/Mcf)	2.88		1.87
Impact from settled derivatives ($/Mcf)	—		0.71
Average price, including settled derivatives ($/Mcf)	2.88		2.58

Oil and condensate sales
Oil and condensate production volumes (MBbl)	344		532
Oil and condensate production volumes (MBbl) per day	4		6
Total sales	18,239		23,151
Average price without the impact of derivatives ($/Bbl)	53.03		43.53
Impact from settled derivatives ($/Bbl)	—		17.86
Average price, including settled derivatives ($/Bbl)	53.03		61.39

NGL sales
NGL production volumes (MBbl)	758		1,108
NGL production volumes (MBbl) per day	8		12
Total sales	23,776		16,913
Average price without the impact of derivatives ($/Bbl)	31.35		15.27
Impact from settled derivatives ($/Bbl)	—		—
Average price, including settled derivatives ($/Bbl)	31.35		15.27

Natural gas, oil and condensate and NGL sales
Natural gas equivalents (MMcfe)	88,446		95,896
Natural gas equivalents (MMcfe) per day	983		1,054
Total sales	277,336		201,072
Average price without the impact of derivatives ($/Mcfe)	3.14		2.10
Impact from settled derivatives ($/Mcfe)	—		0.74
Average price, including settled derivatives ($/Mcfe)	3.14		2.84

Production Costs:
Average lease operating expenses ($/Mcfe)	$	0.14	$	0.15
Average production taxes ($/Mcfe)	$	0.07	$	0.05
Average transportation, gathering, processing and compression ($/Mcfe)	$	1.20	$	1.15
Total lease operating expenses, midstream costs and production taxes ($/Mcfe)	$	1.41	$	1.35

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Lease Operating Expenses


		Three months ended June 30,											Three months ended March 31,
		2020		2019		change			2021		2020		change
		($ In thousands, except per unit)											($ In thousands, except per unit)
Lease operating expenses	Lease operating expenses							Lease operating expenses
Utica	Utica	$	12,996	$	13,646	(5)	%	Utica	$	9,222	$	9,898	(7)	%
SCOOP	SCOOP	2,551		4,143		(38)	%	SCOOP	3,357		4,765		(30)	%
Other⁽¹⁾	Other⁽¹⁾	139		4,599		(97)	%	Other(1)	74		32		131	%
Total lease operating expenses	Total lease operating expenses	$	15,686	$	22,388	(30)	%	Total lease operating expenses	$	12,653	$	14,695	(14)	%

Lease operating expenses per Mcfe	Lease operating expenses per Mcfe							Lease operating expenses per Mcfe
Utica	Utica	$	0.18	$	0.14	26	%	Utica	$	0.12	$	0.13	(7)	%
SCOOP	SCOOP	0.12		0.15		(22)	%	SCOOP	0.23		0.21		9	%
Other⁽¹⁾	Other⁽¹⁾	2.72		5.09		(47)	%	Other(1)	2.41		0.69		251	%
Total lease operating expenses per Mcfe	Total lease operating expenses per Mcfe	$	0.17	$	0.18	(7)	%	Total lease operating expenses per Mcfe	$	0.14	$	0.15	(7)	%

_____________________

(1) Includes ~~WCBB, Hackberry,~~ Niobrara and Bakken.

The decrease in total ~~lease operating expenses ("LOE") for the three months ended June 30, 2020 as compared to the three months ended June 30, 2019~~LOE was primarily the result of ~~our 24%~~a 7% decrease in production ~~and~~as well as ongoing ~~well optimization and~~ cost reduction initiatives. ~~Per~~The decrease in per unit LOE ~~was relatively flat for~~is primarily the ~~three months ended June 30, 2020 as compared to the three months ended June 30, 2019.~~result of ongoing cost reduction initiatives.

~~Production~~ Taxes Other Than Income


		Three months ended June 30,											Three months ended March 31,
		2020		2019		change			2021		2020		change
		($ In thousands, except per unit)											($ In thousands, except per unit)
Production taxes	Production taxes	$	3,605	$	8,098	(55)	%	Production taxes	$	5,803	$	4,799	21	%
Property taxes								Property taxes	1,912		1,282		49	%
Other								Other	989		556		78	%
Total taxes other than income								Total taxes other than income	$	8,704	$	6,637	31	%
Production taxes per Mcfe	Production taxes per Mcfe	$	0.04	$	0.07	(41)	%	Production taxes per Mcfe	$	0.07	$	0.05	40	%

The ~~decrease~~increase in total and per unit production taxes was primarily related to ~~a decrease~~an increase in revenues due to an increase in realized ~~prices~~prices.

Transportation, Gathering, Processing and ~~production for the three months ended June 30, 2020 as compared to the three months ended June 30, 2019.~~Compression

~~Midstream Gathering and Processing Expenses~~

Three months ended June 30,
2020 2019 change
($ In thousands, except per unit)
Midstream gathering and processing expenses $ 59,974 $ 72,015 (17) %
Midstream gathering and processing expenses per Mcfe $ 0.64 $ 0.58 10 %


	Three months ended March 31,
	2021		2020		change
	($ In thousands, except per unit)
Transportation, gathering, processing and compression	$	105,867	$	110,357	(4)	%
Transportation, gathering, processing and compression per Mcfe	$	1.20	$	1.15	4	%

The decrease in ~~midstream~~transportation, gathering, processing and ~~processing expenses~~compression was primarily related to ~~our 24%~~a 7% decrease in our ~~production for the three months ended June 30, 2020 as compared to the three months ended June 30, 2019.~~production. The increase in per unit ~~midstream~~transportation, gathering, processing and ~~processing expenses for the three months ended June 30, 2020 as compared to the three months ended June 30, 2019~~compression is primarily related to Utica ~~Shale production volumes falling below a minimum volume commitment and the resulting deficiency payments during the three months ended June 30, 2020.~~

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production volumes falling below our minimum volume commitments on certain firm transportation and gathering contracts during the three months ended March 31, 2021.

Depreciation, Depletion and Amortization


		Three months ended June 30,											Three months ended March 31,
		2020		2019		change			2021		2020		change
		($ In thousands, except per unit)											($ In thousands, except per unit)
Depreciation, depletion and amortization		$	64,790	$	124,951	(48)	%
Depreciation, depletion and amortization of oil and gas properties								Depreciation, depletion and amortization of oil and gas properties	$	39,767	$	75,359	(47)	%
Depreciation, depletion and amortization of other property and equipment								Depreciation, depletion and amortization of other property and equipment	$	1,380	$	2,669	(48)	%
Total Depreciation, depletion and amortization								Total Depreciation, depletion and amortization	$	41,147	$	78,028	(47)	%
Depreciation, depletion and amortization per Mcfe	Depreciation, depletion and amortization per Mcfe	$	0.69	$	1.01	(32)	%	Depreciation, depletion and amortization per Mcfe	$	0.47	$	0.81	(42)	%

~~Depreciation, depletion and amortization ("DD&A") expense consisted of~~ ~~$62.2 million~~The decrease in ~~depletion~~DD&A of oil and ~~natural~~ gas properties ~~and~~ ~~$2.6 million~~ in depreciation of other property and equipment, compared to $122.5 million in depletion of oil and natural gas properties and $2.5 million in depreciation of other property and equipment for the three months ended June 30, 2019. The ~~decrease~~ ~~in DD&A~~ was due to both a decrease in our depletion rate as a result of a decrease in our amortization base from full cost ceiling test impairments recorded ~~during 2019 and the first quarter of~~throughout 2020, as well as a decrease in our production.

Impairment of Oil and Gas ~~Properties.~~ ~~During the three months ended June 30, 2020, we incurred a$532.9 million~~Properties

We did not incur an oil and natural gas properties impairment charge ~~related primarily to~~during the ~~decline in the twelve month trailing first of month average price for natural gas, oil and NGL, compared to no~~three months ended March 31, 2021 while we recorded a $553.3 million impairment charge of oil and gas properties during the three months ended ~~June 30, 2019.~~March 31, 2020. No impairment was required during the Current Quarter primarily due to the combination of improved commodity prices and a decrease in the net book value of our oil and gas properties stemming from impairment charges in 2020.

Impairment of Other Property and Equipment

We recognized a $14.6 million impairment charge on the Company's corporate headquarters during the three months ended March 31, 2021 as a result in a change in expected future use.

General and Administrative Expenses


	Three months ended March 31,
	2021		2020		change
	($ In thousands, except per unit)
General and administrative expenses, gross	$	21,317	$	24,105	(12)	%
Reimbursed from third parties	$	(3,039)	$	(3,052)	—	%
Capitalized general and administrative expenses	$	(5,521)	$	(5,431)	2	%
General and administrative expenses, net	$	12,757	$	15,622	(18)	%

General and administrative expenses, net per Mcfe	$	0.14	$	0.16	(13)	%

The decrease in general and administrative expenses on a total and per unit basis was primarily driven by our continued focus on reducing costs across our organization and lower non-recurring legal and consulting expenses.

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~~Based~~

Interest Expense


	Three months ended March 31,
	2021		2020
	($ In thousands, except per unit)
Interest expense on senior notes	$	—	$	29,119
Interest expense on pre-petition revolving credit facility	1,020		2,165
Interest expense on building loan and other	75		340
Capitalized interest	—		(187)
Amortization of loan costs	—		1,553
Interest on DIP credit facility	2,166		—
Total interest expense	$	3,261	$	32,990

Interest expense per Mcfe	$	0.04	$	0.34

Weighted average debt outstanding under revolving credit facility	$	307,208	$	81,978

The decrease of total and per unit interest expense was due to the cessation of interest accrual on ~~prices for~~borrowings classified as subject to compromise as of the ~~last nine~~petition date.

Gain on Debt Extinguishment.

In July of 2019, our Board of Directors authorized $100 million of cash to be used to repurchase its senior notes in the open market at discounted values to par. In December 2019, our Board of Directors increased the authorized size of the senior note repurchase program to $200 million in total. During the three months ~~and the short-term pricing outlook for the third quarter of~~ended March 31, 2020, we ~~expect to recognize an additional full cost impairment~~repurchased in the ~~third quarter of 2020. The~~open market $25.9 million aggregate principal amount of our outstanding Senior Notes for $10.2 million in cash and recognized a $15.3 million gain on debt extinguishment. We did not repurchase any ~~future impairments is difficult to predict as it depends on changes~~of our Senior Notes in ~~commodity prices, production rates, proved reserves, evaluation of costs excluded from amortization, future development costs and production costs.~~the three months ended March 31, 2021.

Equity Investments

Three months ended June 30,
2020 2019 change
($ In thousands, except per unit)
Loss from equity method investments, net $ 45 $ 125,582 (100) %


	Three months ended March 31,
	2021		2020		change
	($ In thousands, except per unit)

Loss from equity method investments, net	$	342	$	10,789	(97)	%

~~The decrease in loss from equity method investments is primarily related to a $125.4 million impairment charge recorded during~~During the three months ended ~~June 30, 2019. As~~March 31, 2020, our share of net loss from Mammoth was in excess of the carrying value of our investment, ~~in Mammoth~~which reduced our investment to zero. Our carrying value has remained at zero as of March 31, 2021 and thus no additional net loss or income was ~~reduced to zero during the first quarter of 2020, we did not record any similar impairment charges during the three months ended June 30, 2020.~~recorded . See Note 4 to our consolidated financial statements for further discussion on our equity investments.

~~General and Administrative Expenses~~

Three months ended June 30,
2020 2019 change
($ In thousands, except per unit)
General and administrative expenses, gross $ 21,655 $ 23,539 (8) %
Reimbursed from third parties $ (3,023) $ (2,978) 2 %
Capitalized general and administrative expenses $ (8,162) $ (8,834) (8) %
General and administrative expenses, net $ 10,470 $ 11,727 (11) %
General and administrative expenses, net per Mcfe $ 0.11 $ 0.09 22 %

The decrease in general and administrative expenses, gross was due primarily due to lower employee costs resulting from the reduction in workforce that was completed in the fourth quarter of 2019. Additionally, in June 2020, in response to the

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continued depressed commodity price environment, we announced several G&A initiatives to reduce our corporate cost structure. This decrease was partially offset by an increase in non-recurring legal and consulting expenses.

Reorganization Items, Ne

~~Interest Expense~~

Three months ended June 30,
2020 2019
($ In thousands, except per unit)
Interest expense on senior notes 28,179 32,281
Interest expense on revolving credit agreement 2,860 3,224
Interest expense on construction loan and other 310 312
Capitalized interest (523) (1,005)
Amortization of loan costs 1,540 1,606
Total interest expense $ 32,366 $ 36,418
Interest expense per Mcfe $ 0.35 $ 0.29
Weighted average debt outstanding under revolving credit facility $ 132,077 $ 168,791
t.

The ~~decrease~~following table summarizes the components in ~~interest expense~~reorganization items, net included in our consolidated statements of operations for ~~three months ended June 30, 2020 as compared to~~ the three months ended ~~June 30, 2019 was~~March 31, 2021:


	Three months ended March 31, 2021
	(in thousands)
Adjustment to allowed claims	$	2,088
Legal and professional fees	40,783


Gain on settlement of pre-petition accounts payable	(4,150)
Reorganization items, net	$	38,721

We have incurred and will continue to incur additional gains and losses associated with our reorganization, primarily ~~due~~related to ~~repurchases of~~legal and professional fees related to our ~~senior notes in the second half of 2019 and the first half of 2020.~~ongoing Chapter 11 cases.

Income Taxes.

We recorded no income tax expense for the three months ended ~~June 30, 2020 compared to~~March 31, 2021 as a result of maintaining a full valuation allowance of $911.4 million against our net deferred tax asset. We recorded income tax ~~benefit~~expense of ~~$179.3~~$7.3 million for the three months ended ~~June 30, 2019. As~~March 31, 2020 as a result of ~~June 30, 2020, we had~~the recognition of a ~~federal net operating loss carryforward of approximately $1.5 billion, in addition to numerous temporary differences, which gave rise to~~valuation allowance against a ~~net~~state deferred tax asset. Quarterly, management performs a forecast of our taxable income and analyzes other relevant factors to determine whether it is more likely than not that a valuation allowance is needed, looking at both positive and negative factors. A valuation allowance for our deferred tax assets is established if, in management’s opinion, it is more likely than not that some portion will not be realized. At June 30, 2020, a valuation allowance of $879.3 million has been maintained against the full net deferred tax asset. The tax benefit recorded during the three months ended June 30, 2019 was a result of management's determination there was sufficient positive evidence that it was more likely than not that the federal and some state net operating loss carryforwards would be realized.

On April 30, 2020, our Board of Directors approved the adoption of a tax benefits preservation plan that is intended to protect value by preserving our ability to use our tax attributes, such as NOLs, to offset potential future income taxes for federal income tax purposes. See ~~Note~~ 14 ~~of the notes to our consolidated financial statements for more information.~~

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~~Comparison of the Six Month Periods Ended June 30, 2020 and 2019~~

~~We reported net~~ ~~loss~~ of ~~$1.1 billion~~ for the six months ended June 30, 2020 as compared to net income of $297.2 million for the six months ended June 30, 2019. Included in the loss for the six months ended June 30, 2020 was a $1.1 billion non-cash impairment of our oil and natural gas properties which primarily resulted from a significant decrease in the trailing twelve month first of month prices of natural gas, oil and NGL, and was the main driver of the change in our net (loss) income during the period. Additionally, pricing for all of our commodities decreased significantly, resulting in a $374.4 million decrease in natural gas, oil and NGL sales and a $25.9 million decrease in gain on natural gas, oil and NGL derivatives. The remaining variance related to a $4.9 million increase in general and administrative expenses, partially offset by a $110.5 million decrease in loss from equity method investments, including a $125.4 million impairment related to our investment in Mammoth Energy, a $100.6 million decrease in DD&A, a $49.6 million gain on debt extinguishment, a $24.4 million decrease in midstream gathering and processing expenses, a $10.5 million decrease in lease operating expenses and a $7.6 million decrease in production taxes for the six months ended June 30, 2020 as compared to the six months ended June 30, 2019.

~~Natural Gas, Oil and NGL Sales~~

Six months ended June 30,
2020 2019 change
($ In thousands)
Natural gas 195,344 501,273 (61) %
Oil and condensate 31,541 69,392 (55) %
NGL 27,165 57,812 (53) %
Natural gas, oil and NGL sales $ 254,050 $ 628,477 (60) %

~~The decrease in natural gas sales without the impact of derivatives was due to~~ ~~a 51% decrease~~ ~~in realized natural gas prices and a~~ ~~20%~~ ~~decreasein natural gas sales volumes.~~

~~The decrease in oil and condensate sales without the impact of derivatives was due to an 40% decrease in realized oil and condensate prices and a 25% decrease in oil and condensate sales volumes.~~

~~The decrease in NGL sales without the impact of derivatives was due to~~ ~~a 40% decrease in realized NGL prices and a 22%~~ ~~decrease~~ ~~in NGL sales volumes.~~

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~~Natural Gas, Oil and NGL Derivatives~~

Six months ended June 30,
2020 2019
($ In thousands)
Natural gas derivatives - fair value (losses) gains $ (63,271) $ 142,098
Natural gas derivatives - settlement gains (losses) 144,813 (6,054)
Total gains on natural gas derivatives 81,542 136,044
Oil and condensate derivatives - fair value (losses) gains (5,012) 11,027
Oil and condensate derivatives - settlement gains 49,949 390
Total gains on oil and condensate derivatives 44,937 11,417
NGL derivatives - fair value losses (332) (536)
NGL derivatives - settlement gains 471 4,170
Total gains on NGL derivatives 139 3,634
Contingent consideration arrangement - fair value losses (1,381) —
Total gains on natural gas, oil and NGL derivatives $ 125,237 $ 151,095

~~See~~ ~~Note 10~~ ~~to our consolidated financial statements for further discussion of our derivative activity.~~

~~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 six months ended June 30, 2020, as compared to such data for the six months ended June 30, 2019:

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Six months ended June 30,
2020 2019
($ In thousands)
Natural gas sales
Natural gas production volumes (MMcf) 171,047 213,682
Total natural gas sales $ 195,344 $ 501,273
Natural gas sales without the impact of derivatives ($/Mcf) $ 1.14 $ 2.35
Impact from settled derivatives ($/Mcf) $ 0.85 $ (0.03)
Average natural gas sales price, including settled derivatives ($/Mcf) $ 1.99 $ 2.32
Oil and condensate sales
Oil and condensate production volumes (MBbls) 948 1,261
Total oil and condensate sales $ 31,541 $ 69,392
Oil and condensate sales without the impact of derivatives ($/Bbl) $ 33.26 $ 55.03
Impact from settled derivatives ($/Bbl) $ 52.67 $ 0.31
Average oil and condensate sales price, including settled derivatives ($/Bbl) $ 85.93 $ 55.34
NGL sales
NGL production volumes (MGal) 88,346 113,019
Total NGL sales $ 27,165 $ 57,812
NGL sales without the impact of derivatives ($/Gal) $ 0.31 $ 0.51
Impact from settled derivatives ($/Gal) $ — $ 0.04
Average NGL sales price, including settled derivatives ($/Gal) $ 0.31 $ 0.55
Natural gas, oil and condensate and NGL sales
Natural gas equivalents (MMcfe) 189,359 237,394
Total natural gas, oil and condensate and NGL sales $ 254,050 $ 628,477
Natural gas, oil and condensate and NGL sales without the impact of derivatives ($/Mcfe) $ 1.34 $ 2.65
Impact from settled derivatives ($/Mcfe) $ 1.03 $ (0.01)
Average natural gas, oil and condensate and NGL sales price, including settled derivatives ($/Mcfe) $ 2.37 $ 2.64
Production Costs:
Average lease operating expenses ($/Mcfe) $ 0.17 $ 0.18
Average production taxes ($/Mcfe) $ 0.04 $ 0.07
Average midstream gathering and processing ($/Mcfe) $ 0.62 $ 0.60
Total lease operating expenses, midstream costs and production taxes ($/Mcfe) $ 0.83 $ 0.85

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~~Lease Operating Expenses~~

Six months ended June 30,
2020 2019 change
($ In thousands, except per unit)
Lease operating expenses
Utica $ 24,180 $ 25,473 (5) %
SCOOP 7,320 7,757 (6) %
Other(1) 172 8,965 (98) %
Total lease operating expenses $ 31,672 $ 42,195 (25) %
Lease operating expenses per Mcfe
Utica $ 0.17 $ 0.14 21 %
SCOOP 0.17 0.15 9 %
Other(1) 1.77 4.96 (64) %
Total lease operating expenses per Mcfe $ 0.17 $ 0.18 (6) %

~~_____________________~~

~~(1) Includes WCBB, Hackberry, Niobrara and Bakken.~~

The decrease in total LOE for the six months ended June 30, 2020 as compared to the six months ended June 30, 2019 was primarily the result of our 21% decrease in production. Per unit LOE was relatively flat for the six months ended June 30, 2020 as compared to the six months ended June 30, 2019.

~~Production Taxes~~

Six months ended June 30,
2020 2019 change
($ In thousands, except per unit)
Production taxes $ 8,404 $ 16,019 (48) %
Production taxes per Mcfe $ 0.04 $ 0.07 (34) %

~~The decrease in production taxes was primarily related to a decrease in realized prices and production for the six months ended June 30, 2020.~~

Six months ended June 30,
2020 2019 change
($ In thousands, except per unit)
Midstream gathering and processing expenses $ 117,870 $ 142,297 (17) %
Midstream gathering and processing expenses per Mcfe $ 0.62 $ 0.60 4 %

The decrease in midstream gathering and processing expenses was primarily related to our 21% decrease in our production for the six months ended June 30, 2020 as compared to the six months ended June 30, 2019. Per unit midstream gathering and processing expenses was relatively flat for the six months ended June 30, 2020 as compared to the six months ended June 30, 2019.

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~~Depreciation, Depletion and Amortization~~

Six months ended June 30,
2020 2019 change
($ In thousands, except per unit)
Depreciation, depletion and amortization $ 142,818 $ 243,384 (41) %
Depreciation, depletion and amortization per Mcfe $ 0.75 $ 1.03 (26) %

Depreciation, depletion and amortization ("DD&A") expense consisted of $137.6 million in depletion of oil and natural gas properties and $5.2 million in depreciation of other property and equipment, compared to $237.7 million in depletion of oil and natural gas properties and $5.7 million in depreciation of other property and equipment for the six months ended June 30, 2019. The decrease in DD&A was due to both a decrease in our depletion rate as a result of a decrease in our amortization base from full cost ceiling test impairments recorded during 2019 and the first quarter of 2019 as well as a decrease in our production.

~~Impairment of Oil and Gas Properties.~~ During the six months ended June 30, 2020, we incurred $1.1 billion of oil and natural gas properties impairment charges related primarily to the decline in the twelve month trailing first of month average price for natural gas, oil and NGL compared to no impairment charge of oil and gas properties during the six months ended June 30, 2019.

~~Equity Investments~~

Six months ended June 30,
2020 2019 change
($ In thousands, except per unit)
Loss from equity method investments, net $ 10,834 $ 121,309 (91) %

The decrease in loss from equity method investments is primarily related to a $125.4 million impairment charge recorded during the six months ended June 30, 2019. The value of our investment in Mammoth was reduced to zero during the first quarter of 2020, and we did not record any similar impairment charges during the six months ended June 30, 2020. See ~~Note 4~~ ~~to our consolidated financial statements for further discussion on our equity investments.~~

~~General and Administrative Expenses~~

Six months ended June 30,
2020 2019 change
($ In thousands, except per unit)
General and administrative expenses, gross $ 46,306 $ 43,980 5 %
Reimbursed from third parties $ (6,075) $ (5,667) 7 %
Capitalized general and administrative expenses $ (13,592) $ (16,529) (18) %
General and administrative expenses, net $ 26,639 $ 21,784 22 %
General and administrative expenses, net per Mcfe $ 0.14 $ 0.09 53 %

The increase in general and administrative expenses, gross was due primarily due to an increase in non-recurring legal and consulting charges for the six months ended June 30, 2020 as compared to the six months ended June 30, 2019. This increase was partially offset by lower employee costs resulting from the reduction in workforce that was completed in the fourth quarter of 2019. Additionally, in June 2020, in response to the continued depressed commodity price environment, we announced several G&A initiatives to reduce our corporate cost structure. The decrease in capitalized general and administrative expenses was due to lower development activities for the six months ended June 30, 2020 as compared to the six months ended June 30, 2019.

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~~Interest Expense~~

Six months ended June 30,
2020 2019
($ In thousands, except per unit)
Interest expense on senior notes 57,299 64,562
Interest expense on revolving credit agreement 5,025 5,479
Interest expense on construction loan and other 650 578
Capitalized interest (710) (1,771)
Amortization of loan costs 3,092 3,191
Total interest expense $ 65,356 $ 72,039
Interest expense per Mcfe $ 0.35 $ 0.30
Weighted average debt outstanding under revolving credit facility $ 107,027 $ 123,287

~~The decrease in interest expense for the six months ended June 30, 2020 as compared to the six months ended June 30, 2019 was primarily due to continued repurchases of our senior notes.~~

~~Income Taxes~~. We recorded income tax expense of 7.3 million for the six months ended June 30, 2020 compared to income tax benefit of 179.3 million for the six months ended June 30, 2019. As of June 30, 2020, we had a federal net operating loss carryforward of approximately $1.5 billion from prior years, in addition to numerous temporary differences, which gave rise to a net deferred tax asset. Quarterly, management performs a forecast of our taxable income and analyzes other relevant factors to determine whether it is more likely than not that a valuation allowance is needed, looking at both positive and negative factors. A valuation allowance for our deferred tax assets is established if, in management’s opinion, it is more likely than not that some portion will not be realized. At June 30, 2020, a valuation allowance of $879.3 million has been maintained against the full net deferred tax asset. Income tax expense recorded during the six months ended June 30, 2020 is related to the recognition of a valuation allowance against a state deferred tax asset during the first quarter of 2020. The tax benefit recorded during the six months ended June 30, 2019 was a result of management's determination there was sufficient positive evidence that it was more likely than not that the federal and some state net operating loss carryforwards would be realized.

Liquidity and Capital Resources

Overview. Historically, our primary sources of capital funding and liquidity have been our operating cash flow, borrowings under our ~~revolving credit facility~~Pre-Petition Revolving Credit Facility and issuances of equity and debt securities. Our ability to issue additional indebtedness, dispose of assets or access ~~these sources of funds can be significantly impacted by changes in~~the capital markets ~~decreases~~may be substantially limited or nonexistent during the Chapter 11 Cases and will require court approval in ~~commodity prices~~most instances. Accordingly, our liquidity will depend mainly on cash generated from operating activities and ~~decreases in~~available funds under the DIP Credit Facility as discussed below.

Filing of the Chapter 11 Cases constituted an event of default with respect to certain of our ~~production levels.~~

~~In 2020, decreased demand for oil~~secured and ~~natural gas~~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, the creditors are stayed from taking any action as a result of the COVID-19 pandemic and the accompanying decrease in commodity prices has significantly reduced our ability to access capital markets and to refinance our existing indebtedness. Further, these conditions have made amendments or waivers to our revolving credit facility more difficult to obtain and available on terms less favorable to us. If depressed commodity prices persist or decline further, the borrowing basedefault under our revolving credit facility could be further reduced at our next scheduled redetermination date in November 2020. Any such reduction would constrain our liquidity and may impair our ability to fund our planned capital expenditures and meet our obligations under our existing indebtedness. Further, a reduction in our capital expenditures would decrease our production, revenues, operating cash flow and EBITDA, which could limit our ability to comply with the restrictive covenants in our revolving credit facility and other existing indebtedness. Finally, our existing revolving credit facility matures in December 2021 and therefore will become a current liability at year end 2020 unless we are able to refinance the credit facility with a new credit facility or other financing. Considering the current stateSection 362 of the first lien market and our elevated leverage profile, there is substantial risk that a refinancing will not be available to us on reasonable terms. A current liability under the revolving credit facility at year end 2020 may result in a qualified audit opinion which could result in a default under the terms of the current revolving credit facility. As a result of these uncertainties and other factors, management has concluded that there is substantial doubt about our ability to continue as a going concern. Failure to meet our obligations under our existing indebtedness or failure to comply with any of our covenants, if not waived, would result in an event of default under such indebtedness and result in the potential acceleration of outstanding indebtedness thereunder and, with respect to the revolving credit facility, the

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~~potential foreclosure on the collateral securing such debt, and could cause a cross-default under our other outstanding indebtedness.~~

Bankruptcy Code.

As of ~~June 30, 2020,~~March 31, 2021, we had a cash balance of ~~$2.8~~$179.7 million compared to ~~$6.1~~$89.9 million as of December 31, ~~2019,~~2020, and a net working capital deficit of ~~$176.2~~$137.1 million as of ~~June 30, 2020,~~March 31, 2021, compared to a net working capital deficit of ~~$145.3~~$100.5 million as of December 31, ~~2019.~~2020. As of ~~June 30, 2020,~~March 31, 2021, our working capital deficit includes ~~$0.6~~$279.8 million of debt due in the next 12 months. Our total principal debt as of ~~June 30,~~both March 31, 2021 and December 31, 2020 was ~~$1.9 billion compared to $2.0 billion as of December 31, 2019.~~$2.3 billion. As of ~~June 30, 2020,~~March 31, 2021, we had ~~$252.9~~no borrowing capacity available under the Pre-Petition Revolving Credit Facility, with outstanding borrowings of $316.8 million and $121.2 million utilized for various letters of credit and $76.5 million of borrowing capacity available under the ~~revolving credit facility,~~DIP Credit Facility, with outstanding borrowings of ~~$123.0~~$157.5 million and ~~$324.1~~$28.5 million utilized for various letters of credit. 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.

We believe our cash flow from operations, borrowing capacity under the DIP Credit Facility and cash on hand will provide sufficient liquidity during the Chapter 11 process. We expect to continue to incur significant costs related to our ongoing Chapter 11 Cases until our expected emergence in May 2021, including fees for legal, financial and restructuring advisors to the Company, certain of our creditors and royalty interest owners.

Our ability to continue as a going concern is contingent on our ability to comply with the financial and other covenants contained in our DIP Credit Facility, our ability to successfully implement the Plan and obtain exit financing, among other factors. As a result of the Bankruptcy Filing, the realization of assets and the satisfaction of liabilities are subject to uncertainty. While operating as debtors-in-possession under Chapter 11, we may settle liabilities, subject to the approval of the Bankruptcy Court or as otherwise permitted in the ordinary course of business (and subject to restrictions contained in the DIP Credit Facility), for amounts other than those reflected in the accompanying consolidated financial statements.

The Bankruptcy Court entered an order confirming the Plan on April 28, 2021. See Note 2 for discussion of the exit facility to become effective upon emergence.

Debtor-In-Possession Credit Facility. Pursuant to the RSA, the Consenting RBL Lenders have 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 $105 million of new money and $157.5 million to roll up a portion of the existing outstanding obligations under the Pre-Petition Revolving Credit Facility. The proceeds of the DIP Credit Facility may be 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.

Advances under our DIP Credit Facility may be in the form of either base rate loans or eurodollar loans. The interest rate for base rate loans is equal to (1) the applicable rate of 3.50%, plus (2) the base rate. The interest rate for eurodollar loans is equal to (1) the applicable rate of 4.50%, plus (2) the highest of: (a) 1% or (b) the eurodollar rate. As of March 31, 2021 amounts borrowed under our DIP Credit Facility bore interest at the weighted average rate of 5.50%. In addition to paying interest on outstanding principal and letters of credit posted under the DIP Credit Facility, we are required to pay a commitment fee of 0.50% per annum to the lenders of the DIP Credit Facility in respect of the unutilized DIP commitments thereunder and a letter of credit fee equal to 0.20% per annum.

The DIP Credit Facility includes negative covenants that, subject to significant exceptions, limit our ability and the ability of our restricted subsidiaries to, among other things, (i) create liens on assets, property revenues, (ii) make investments, (iii) incur additional indebtedness, (iv) engage in mergers, consolidations, liquidations and dissolutions, (v) sell assets, (vi) pay dividends and distributions or repurchase capital stock, (vii) cease for any reason to be the operator of its properties, (viii) enter into letters of credit without prior written consent, (ix) enter into certain commodity hedging contracts except commodity

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hedging contracts with terms approved by the Bankruptcy Court in the hedging order or certain interest rate contracts, (x) change lines of business, (xi) engage in certain transactions with affiliates and (xii) incur more than a certain amount in capital expenditures in any calendar month. The DIP Credit Facility includes certain customary representations and warranties, affirmative covenants and events of default, including but not limited to defaults on account of nonpayment, breaches of representations and warranties and covenants, certain bankruptcy-related events, certain events under ERISA, material judgments and a change in control. If an event of default occurs, the lenders under the DIP Credit Facility will be entitled to take various actions, including the acceleration of all amounts due under the DIP Credit Facility and all actions permitted to be taken under the loan documents or application of law. In addition, the DIP Credit Facility is subject to various other financial performance covenants, including compliance with certain financial metrics and adherence to a budget approved by our DIP Credit Facility lenders.

Pre-Petition Revolving Credit Facility. We have 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 credit agreement provides for a maximum borrowing base amount of $580 million and matures on December 31, 2021. The $316.8 million of outstanding borrowings under the Pre-Petition Revolving Credit Facility as of March 31, 2021 that were not rolled up into the DIP Credit Facility will remain outstanding throughout the Chapter 11 Cases and will continue to accrue interest on amounts drawn after the Petition Date. Additionally, as of March 31, 2021, we had an aggregate of $121.2 million of letters of credit outstanding under our Pre-Petition Revolving Credit Facility. This facility is secured by substantially all of our assets. Our wholly-owned subsidiaries, excluding Grizzly Holdings and Mule Sky, guarantee our obligations under our revolving credit facility.

Advances under our Pre-Petition Revolving Credit Facility may be in the form of either base rate loans or eurodollar loans. The interest rate for base rate loans is equal to (1) the applicable rate, which ranges from 0.25% to 1.25%, plus (2) the highest of: (a) the federal funds rate plus 0.50%, (b) the rate of interest in effect for such day as publicly announced from time to time by the administrative agent as its “prime rate,” and (c) the eurodollar rate for an interest period of one month plus 1.00%. The interest rate for eurodollar loans is equal to (1) the applicable rate, which ranges from 1.25% to 2.25%, plus (2) the London interbank offered rate that appears on pages LIBOR01 or LIBOR02 of the Reuters screen that displays such rate for deposits in U.S. dollars, or, if such rate is not available, the rate as administered by ICE Benchmark Administration (or any other person that takes over administration of such rate) per annum equal to the offered rate on such other page or other service that displays an average London interbank offered rate as administered by ICE Benchmark Administration (or any other person that takes over the administration of such rate) for deposits in U.S. dollars, or, if such rate is not available, the average quotations for three major New York money center banks of whom the administrative agent shall inquire as the “London Interbank Offered Rate” for deposits in U.S. dollars. As of March 31, 2021, amounts borrowed under our revolving credit facility bore interest at the weighted average rate of 3.12%.

Senior Notes. In April 2015, we issued an aggregate of $350.0 million in principal amount of our 2023 Notes. Interest on these senior notes accrues at a rate of 6.625% per annum on the outstanding principal amount thereof, payable semi-annually on May 1 and November 1 of each year. As of March 31, 2021, $324.6 million principal amount remained outstanding. The 2023 Notes mature on May 1, 2023.

In October 2016, we issued an aggregate of $650.0 million in principal amount of our 2024 Notes. Interest on the 2024 Notes accrues at a rate of 6.000% per annum on the outstanding principal amount thereof, payable semi-annually on April 15 and October 15 of each year. As of March 31, 2021, $579.6 million principal amount remained outstanding. The 2024 Notes mature on October 15, 2024.

In December 2016, we issued an aggregate of $600.0 million in principal amount of our 2025 Notes. Interest on the 2025 Notes accrues at a rate of 6.375% per annum on the outstanding principal amount thereof, payable semi-annually on May 15 and November 15 of each year. As of March 31, 2021, $507.9 million principal amount remained outstanding. The 2025 Notes mature on May 15, 2025.

In October 2017, we issued $450.0 million in aggregate principal amount of our 2026 Notes. Interest on the 2026 Notes accrues at a rate of 6.375% per annum on the outstanding principal amount thereof, payable semi-annually on January 15 and July 15 of each year. As of March 31, 2021, $374.6 million principal amount remained outstanding. The 2026 Notes mature on January 15, 2026.

All amounts outstanding on our Senior Notes have been classified as liabilities subject to compromise on the accompanying consolidated balance sheets as of March 31, 2021 and December 31, 2020.

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Building Loan. On June 4, 2015, we entered into a loan for the construction of our corporate headquarters in Oklahoma City, which was substantially completed in December 2016. Interest accrues daily on the outstanding principal balance at a fixed rate of 4.50% per annum. The building loan matures on June 4, 2025. As of March 31, 2021, the total borrowings under the building loan were approximately $21.9 million, which has been classified as liabilities subject to compromise on the accompanying consolidated balance sheets as of March 31, 2021.

Supplemental Guarantor Financial Information. The 2023 Notes, 2024 Notes, 2025 Notes and 2026 Notes are guaranteed on a senior unsecured basis by all existing consolidated subsidiaries that guarantee our secured revolving credit 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 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 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.

As of ~~June 30, 2020,~~March 31, 2021, we had the following open natural gas, oil and NGL derivative instruments:


Natural Gas Derivatives	Natural Gas Derivatives										Natural Gas Derivatives
Year	Year	Type of Derivative Instrument	Index	Daily Volume (MMBtu/day)	Weighted Average Price ($)	Year	Type of Derivative Instrument	Index	Daily Volume (MMBtu/day)	Weighted Average Price ($)
2020		Swaps	NYMEX Henry Hub	357,000	2.86
2020		Basis Swaps	Various	70,000	(0.12)
2021	2021	Costless Collars	NYMEX Henry Hub	250,000	2.46/2.81	2021	Swaps	NYMEX Henry Hub	351,316	$	2.73
2021						2021	Basis Swaps	Tetco M2	32,384	$	(0.63)
2021						2021	Basis Swaps	Rex Zone 3	85,309	$	(0.22)
2022						2022	Basis Swaps	Rex Zone 3	14,795	$	(0.10)
2021						2021	Costless Collars	NYMEX Henry Hub	390,509	$2.54/$2.93
2022						2022	Costless Collars	NYMEX Henry Hub	186,438	$2.63/$3.04
2022	2022	Sold Call Options	NYMEX Henry Hub	628,000	2.90	2022	Sold Call Options	NYMEX Henry Hub	152,675	$	2.90
2023	2023	Sold Call Options	NYMEX Henry Hub	628,000	2.90	2023	Sold Call Options	NYMEX Henry Hub	627,675	$	2.90
Oil Derivatives	Oil Derivatives										Oil Derivatives
Year	Year	Type of Derivative Instrument	Index	Daily Volume (Bbls/day)	Weighted Average Price ($)	Year	Type of Derivative Instrument	Index	Daily Volume (Bbl/day)	Weighted Average Price ($)
2020		Swaps	NYMEX WTI	3,000	35.49
2021						2021	Swaps	NYMEX WTI	1,505	$	53.07
NGL Derivatives	NGL Derivatives										NGL Derivatives
Year	Year	Type of Derivative Instrument	Index	Daily Volume (Bbls/day)	Weighted Average Price ($)	Year	Type of Derivative Instrument	Index	Daily Volume (Bbl/day)	Weighted Average Price ($)
2020		Swaps	Mont Belvieu C3	1,500	20.27
2021						2021	Swaps	Mont Belvieu C3	2,074	$	27.80
2022						2022	Swaps	Mont Belvieu C3	496	$	27.30

See Note 109 of the notes to our consolidated financial statements for further discussion of derivatives and hedging activities. ~~Additionally, as discussed in~~ ~~Note 16~~, we brought forward the value of our oil swaps by monetizing our remaining position in April 2020 and entered into additional contracts to hedge our remaining 2020 and 2021 production in April and May 2020.

~~Credit Facility.~~ We have entered into a senior secured revolving credit facility, as amended, with The Bank of Nova Scotia, as the lead arranger and administrative agent and other lenders. The credit agreement provides for a maximum facility amount of $1.5 billion and matures on December 13, 2021. As of June 30, 2020, we had a borrowing base and elected commitment of $700.0 million and $123.0 million in borrowings outstanding. Total funds available for borrowing under our revolving credit facility, after giving effect to an aggregate of ~~$324.1 million~~ ~~of outstanding letters of credit, were~~ ~~$252.9 million~~ as of June 30, 2020. This facility is secured by substantially all of our assets. Our wholly owned subsidiaries, excluding Grizzly Holdings Inc. ("Grizzly Holdings") and Mule Sky LLC ("Mule Sky"), guarantee our obligations under our revolving credit facility.

Our revolving credit facility contains customary negative covenants including, but not limited to, restrictions on our and our subsidiaries’ ability to: incur indebtedness; grant liens; pay dividends and make other restricted payments; agree to payment restrictions affecting our restricted subsidiaries; make investments; undertake fundamental changes including selling all or substantially all of our assets; enter into swap contracts and forward sales contracts; dispose of assets; change the nature of their business; enter into transactions with their affiliates; and engage in certain transactions with restricted subsidiaries. The negative covenants are subject to certain exceptions as specified in our revolving credit facility. Our revolving credit facility also contains certain affirmative covenants, including, but not limited to the following financial covenants: (1) the ratio of Net Secured Debt to EBITDAX (as defined under the revolving credit agreement) may not be greater than 2.00 to 1.00 for the

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twelve-month period of the end of each fiscal quarter; and (2) the ratio of EBITDAX to interest expense for the twelve-month period at the end of each fiscal quarter may not be less than 3.00 to 1.00. On May 1, 2020, we entered into a fifteenth amendment to our Amended and Restated Credit Agreement. As part of the amendment, our borrowing base and elected commitment were reduced from $1.2 billion and $1.0 billion, respectively, to $700.0 million. Additionally, the amendment added the requirement to maintain a ratio of Net Secured Debt to EBITDAX as described above, deferred the requirement to maintain a ratio of Net Funded Debt to EBITDAX of 4.00 to 1.00 until September 30, 2021, and added a limitation on the repurchase of unsecured notes, among other amendments. ~~We were in compliance with these financial covenants at June 30, 2020.~~

On July 27, 2020, we entered into the sixteenth amendment to the Amended and Restated Credit Agreement. The sixteenth amendment allows us to issue up to $750 million in second lien debt subject to certain conditions.

~~Senior Notes~~.~~We used borrowings under our revolving credit facility to repurchase in the open market approximately~~ ~~$47.5 million~~ ~~and $73.3 million aggregate principal amount of our outstanding Notes for~~ ~~$12.6 million and~~ $22.8 million during the three and six months ended June 30, 2020, respectively. For the three months ended June 30, 2020, this included approximately $4.9 million principal amount of the 2023 Notes, $16.3 million principal amount of the 2024 Notes, $13.5 million principal amount of the 2025 Notes, and $12.8 million principal amount of the 2026 Notes. We recognized a $34.3 million and $49.6 million gain on debt extinguishment, which included retirement of unamortized issuance costs and fees associated with the repurchased debt, during the three and six months ended June 30, 2020, respectively.

~~Subject to restrictions in our own revolving credit facility, we may use a combination of cash and borrowing under our~~

~~revolving credit facility to retire our outstanding debt, through privately negotiated transactions, open market repurchases,~~

~~redemptions, tender offers or otherwise, but we are under no obligation to do so.~~

Capital Expenditures. Our capital ~~commitments~~expenditures have historically been primarily ~~for~~related to the execution of our drilling ~~programs~~ and ~~discounted repurchases of our senior notes.~~completion activities in addition to certain lease and other 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 while also selectively pursuing mergers or acquisitions in our current operating regions in an effort to gain scale and deepen our drilling inventory.~~prices.

Our capital expenditures for 2020 are currently estimated to be in the range of $265.0 million to $285.0 million for drilling and completion expenditures. In addition, we currently expect to spend $20.0 million to $25.0 million in 2020 for non-drilling and completion expenditures, which includes acreage expenses, primarily lease extensions in the Utica Shale. The midpoint of the 2020 range of capital expenditures is more than 50% lower than the $602.5 million spent in 2019, primarily due to our decision to reduce capital activity in response to lower commodity prices, specifically natural gas prices, and our desire to fund our capital development program primarily with cash flow from operations. As a result of our decreased capital spending program for 2020 and the impact of our 2019 property divestitures, we expect our production volumes in 2020 to be approximately 22% to 27% lower than 2019. Coupled with forecasted lower commodity prices, we expect 2020 revenues, operating cash flows and EBITDA to be significantly lower in 2020 as compared to 2019.

We continually monitor market conditions and are prepared to adjust our drilling program if commodity prices dictate. ~~Currently, we~~We believe ~~that~~ our cash flow from operations, borrowing capacity under the DIP Credit Facility and cash on hand will provide sufficient liquidity during the Chapter 11 process. We expect to incur significant costs associated with our ongoing Chapter 11 Cases in 2021, including fees for legal, financial and ~~borrowing base availability under~~restructuring advisors to the Company, certain of our ~~revolving credit agreement will be sufficient to meet~~creditors and royalty interest owners. Therefore, our ~~normal recurring operating needs and capital requirements for the next twelve months. We have the~~ ability to ~~react quickly~~obtain confirmation of the Plan in a timely manner is critical to ~~changing commodity prices and accelerate or decelerate~~ensuring our ~~activity within our operating areas as market conditions warrant. Notwithstanding~~liquidity is sufficient during the foregoing, in the event commodity prices decline from current levels or our capital or other costs increase we may be required to obtain additional funds which we would seek to do through borrowings, offerings of debt or equity securities or other means, including the sale of assets. To the extent that access to capital and other financial markets is adversely affected by the effects of COVID-19, the Company may need to consider alternative sources of funding for some of its operations and for working capital, which may increase the cost of, as well as adversely impact access to, capital. We regularly evaluate merger, acquisition and divestiture opportunities. Capital may not be available to us on acceptable terms or at all in the future. Further, if we are unable to obtain funds when needed or on acceptable terms, we may be required to delay or curtail implementation of our business plan or not be able to complete acquisitions that may be favorable to us. If the current low commodity price environment worsens, our revenues, cash flows, results of operations, liquidity and reserves may be materially and adversely affected.bankruptcy process.

Cash Flow from Operating Activities. Net cash flow provided by operating activities was ~~$247.2~~$123.2 million for the ~~six~~three months ended ~~June 30, 2020~~March 31, 2021 as compared to ~~$399.8~~$130.8 million for the same period in ~~2019.~~2020. This decrease was primarily the result of ~~a significant decrease in our realized gas prices as well as decreases in our production volumes.~~

~~Table of Contents~~working capital changes.

~~Divestitures.~~ During the six months ended June 30, 2020, we divested our SCOOP water infrastructure assets and received $50.0 million in cash upon closing and have an opportunity to earn additional incentive payments over the next 15 years, subject to our ability to meet certain thresholds which will be driven by, among other things, our future development program and future water production levels. Proceeds from the divestiture were used to reduce our outstanding revolver balance. See ~~Note 3~~ ~~of the notes to our consolidated financial statements for further discussion.~~

~~Use~~Uses of Funds. The following table presents the uses of our cash and cash equivalents for the ~~six~~three months ended ~~June 30, 2020~~March 31, 2021 and ~~2019:~~2020:


		Six months ended June 30,							Three months ended March 31,
		2020		2019			2021		2020
		(In thousands)							(In thousands)
Oil and Natural Gas Property Cash Expenditures:	Oil and Natural Gas Property Cash Expenditures:					Oil and Natural Gas Property Cash Expenditures:
Drilling and completion costs	Drilling and completion costs	255,904		435,583		Drilling and completion costs	$	51,702	$	97,538
Leasehold acquisitions	Leasehold acquisitions	10,098		25,778		Leasehold acquisitions	2,354		7,346
Other	Other	8,849		46,954		Other	2,839		8,860
Total oil and natural gas property expenditures	Total oil and natural gas property expenditures	$	274,851	$	508,315	Total oil and natural gas property expenditures	$	56,895	$	113,744
Other Uses of Cash and Cash Equivalents	Other Uses of Cash and Cash Equivalents					Other Uses of Cash and Cash Equivalents
Cash paid to repurchase senior notes	Cash paid to repurchase senior notes	22,827		—		Cash paid to repurchase senior notes	$	—	$	10,204
Cash paid to repurchase common stock under approved stock repurchase program		—		30,000
Principal payments on borrowings, net						Principal payments on borrowings, net	—		55,106

Other	Other	801		5,444		Other	303		685
Total other uses of cash and cash equivalents	Total other uses of cash and cash equivalents	$	23,628	$	35,444	Total other uses of cash and cash equivalents	$	303	$	65,995
Total uses of cash and cash equivalents	Total uses of cash and cash equivalents	$	298,479	$	543,759	Total uses of cash and cash equivalents	$	57,198	$	179,739

Drilling and Completion Costs. During ~~six~~three months ended ~~June 30, 2020,~~March 31, 2021, we spud 12nine gross ~~(11.1~~(9.0 net) and commenced sales from 13seven gross and net operated wells in the Utica ~~Shale~~ for a total cost of approximately $~~141.5~~ ~~million~~.$46.4 million. During the ~~six~~three months ended ~~June 30, 2020,~~March 31, 2021, we did not spud ~~six gross (5.2 net)~~any wells and commenced sales from ~~four~~three gross ~~(3.8~~(2.7 net) operated wells in the SCOOP for a total cost of approximately $~~42.2~~ ~~million~~.$23.9 million.

During the ~~six~~three months ended ~~June 30, 2020,~~March 31, 2021, we did not participate in any wells that were spud or turned to sales by other operators on our Utica ~~Shale~~ acreage. In addition, ~~5.00~~three gross ~~(0.03~~(0.001 net) wells were spud and ~~5.00~~10 gross ~~(3.5~~(1.86 net) wells were turned to sales by other operators on our SCOOP acreage during the ~~six~~three months ended ~~June 30, 2020.~~March 31, 2021.

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.

Contractual and Commercial Obligations

We have various contractual obligations in the normal course of our operations and financing activities. See Note 9 ~~and~~ ~~Note 13~~8 of the notes to our consolidated financial statements for further discussion of the ~~termination of~~amendments to our ~~Master Services Agreement with Stingray Pressure Pumping LLC, a subsidiary of Mammoth Energy Services, Inc.~~firm gathering and ~~a related party.~~transportation agreements. 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, ~~2019.~~2020.

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Off-balance Sheet Arrangements

We may enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. As of ~~June 30, 2020,~~March 31, 2021, our material off-balance sheet arrangements and transactions include ~~$324.1~~$121.2 million in letters of credit outstanding against our ~~revolving~~Pre-Petition Revolving Credit Facility, $28.5 million in letters of credit ~~facility~~outstanding against our DIP Credit Facility and ~~$119.5~~$110.9 million in surety bonds issued. Both the letters of credit and surety bonds are being used as financial assurance, primarily on certain firm transportation agreements. ~~Management believes these items will expire without being funded.~~ 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

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resources. See Note 98 to our consolidated financial statements for further discussion of the various financial guarantees we have issued.

Critical Accounting Policies and Estimates

As of ~~June 30, 2020,~~March 31, 2021, there have been no significant changes in our critical accounting policies from those disclosed in our ~~2019~~2020 Annual Report on Form 10-K.

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ITEM 3.			QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

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

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

We determine the notional volume potentially subject to derivative contracts by reviewing our overall estimated future production levels, which are derived from extensive examination of existing producing reserve estimates and estimates of ~~likely~~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 ~~would be~~are typically reversed. The actual fixed ~~price~~prices on our derivative instruments is derived from the reference ~~NYMEX price,~~prices from 3rd party indices such as ~~reflected in current NYMEX trading. The pricing dates of our derivative contracts follow NYMEX futures.~~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. ~~Gains or losses related to closed positions will be recognized in the month specified in the original contract.~~

We have determined the fair value of our derivative instruments utilizing established index prices, volatility curves, discount factors and ~~discount factors.~~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 109 of the notes to our consolidated financial statements for further discussion of the fair value measurements associated with our derivatives.

As of ~~June 30, 2020,~~March 31, 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.

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

•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.

To mitigate the effects of commodity price fluctuations on our oil and natural gas production, we had the following open fixed price swap positions at ~~June 30, 2020:~~March 31, 2021:

Location Daily Volume (MMBtu/day) Weighted
Average Price
Remaining 2020 NYMEX Henry Hub 357,000 $ 2.86

Location

Daily Volume (MMBtu/day)

Weighted
Average Price

Remaining 2021

NYMEX Henry Hub

351,316

2.73

Location Daily Volume
(Bbls/day) Weighted
Average Price
Remaining 2020 NYMEX WTI 3,000 $ 35.49

Location

Daily Volume
(Bbl/day)

Weighted
Average Price

Remaining 2021

NYMEX WTI

1,505

53.07

Location Daily Volume
(Bbls/day) Weighted
Average Price
Remaining 2020 Mont Belvieu C3 1,500 $ 20.27


	Location	Daily Volume (Bbl/day)	Weighted Average Price
Remaining 2021	Mont Belvieu C2	2,074	$	27.80
2022	Mont Belvieu C3	496	$	27.30

WeIn the second half of 2019, we sold 2022 and 2023 natural gas call options in exchange for a premium, and used the associated premiums to enhance the fixed price ~~for a portion of the fixed price~~on certain natural gas swaps ~~primarily for 2020 listed above. We had~~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 ~~following open~~$2.90 ceiling price, we are required to pay the option counterparty an amount equal to the difference between the referenced NYMEX natural gas settlement price and $2.90 multiplied by the hedged contract volumes. Below is a summary of our sold call option positions ~~at June 30, 2020:~~as of March 31, 2021.


		Location	Daily Volume (MMBtu/day)	Weighted Average Price			Location	Daily Volume (MMBtu/day)	Weighted Average Price

2022	2022	NYMEX Henry Hub	628,000	$	2.90	2022	NYMEX Henry Hub	152,675	$	2.90
2023	2023	NYMEX Henry Hub	628,000	$	2.90	2023	NYMEX Henry Hub	627,675	$	2.90

~~We had the following open~~Below is a summary of our costless collar positions ~~at June 30, 2020:~~as of March 31, 2021.

Location Daily Volume (MMBtu/day) Weighted Average Floor Price Weighted Average Ceiling Price
2021 NYMEX Henry Hub 250,000 $ 2.46 $ 2.81


	Location	Daily Volume (MMBtu/day)	Weighted Average Floor Price		Weighted Average Ceiling Price
2021	NYMEX Henry Hub	390,509	$	2.54	$	2.93
2022	NYMEX Henry Hub	186,438	$	2.63	$	3.04

AsBelow is a summary of ~~June 30, 2020, the Company had the following natural gas~~our basis swap positions ~~open:~~as of March 31, 2021.

Gulfport Pays Gulfport Receives Daily Volume (MMBtu/day) Weighted Average Fixed Spread
Remaining 2020 Transco Zone 4 NYMEX Plus Fixed Spread 60,000 $ (0.05)
Remaining 2020 Fixed Spread ONEOK Minus NYMEX 10,000 $ (0.54)


	Gulfport Pays	Gulfport Receives	Daily Volume (MMBtu/day)	Weighted Average Fixed Spread
Remaining 2021	Rex Zone 3	NYMEX Plus Fixed Spread	85,309	$	(0.22)
Remaining 2021	Tetco M2	NYMEX Plus Fixed Spread	32,384	$	(0.63)
2022	Rex Zone 3	NYMEX Plus Fixed Spread	14,795	$	(0.10)

~~During the three months ended June 30, 2020, we early terminated oil fixed price swaps which represented approximately 6,000 BBls~~

Table of ~~oil per day for the remainder of 2020. The early termination resulted in a cash settlement of approximately $40.5 million.~~Contents

In August 2020, we entered into natural gas fixed price swap contracts for the fourth quarter of 2020 covering approximately 100,000 MMBtu of natural gas per day at an average swap price of $2.38 per MMBtu.

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, pentane and ethane. We will receive the fixed priced amount stated in the contract and pay to its counterparty the current market price as listed on ~~NYMEX Henry Hub for natural gas or Mont Belvieu for propane, pentane and ethane.~~the applicable index.

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~~Under our 2020 contracts, we have hedged approximately 59% to 63% of our estimated 2020 production. Such~~Our hedge arrangements may expose us to risk of financial loss in certain circumstances, including instances where production is less than expected or commodity prices increase. At ~~June 30, 2020,~~March 31, 2021, we had a net ~~asset~~liability derivative position of ~~$3.3~~$50.9 million as compared to a net asset derivative position of ~~$139.5~~$100.9 million as of ~~June 30, 2019, related to our hedging portfolio.~~March 31, 2020. Utilizing actual derivative contractual volumes, a 10% increase in underlying commodity prices would have reduced the fair value of these instruments by approximately ~~$48.8~~$87.4 million, while a 10% decrease in underlying commodity prices would have increased the fair value of these instruments by approximately ~~$43.1~~$80.0 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 ~~June 30, 2020,~~March 31, 2021, we had ~~$123.0~~$316.8 million in borrowings outstanding under our ~~revolving credit facility~~Pre-Petition Revolving Credit Facility which bore interest at a weighted average rate of ~~2.44%~~3.12%. At March 31, 2021, we had $157.5 million in borrowings outstanding under our DIP Credit Facility which bore interest at a weighted average rate of 5.50%. As of ~~June 30, 2020,~~March 31, 2021, we did not have any interest rate swaps to hedge ~~our~~ interest rate risks.


ITEM 4.			CONTROLS AND PROCEDURES

Evaluation of Disclosure Control and Procedures. Under the direction of our Chief Executive Officer and President and our Chief Financial Officer, 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 President and our Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosures.

As of ~~June 30, 2020,~~March 31, 2021, an evaluation was performed under the supervision and with the participation of management, including our Chief Executive Officer and President and our 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 President and our Chief Financial Officer have concluded that, as of ~~June 30, 2020,~~March 31, 2021, our disclosure controls and procedures were not effective because of the material weakness in our internal control over financial reporting described in Management’s Report on Internal Control Over Financial Reporting appearing under Item 9A of Part II of our Annual Report on Form 10-K for the year ended December 31, 2019.

~~Remediation Plan for the Material Weakness.~~ Our management is actively engaged in the implementation of remediation efforts to address the material weakness identified in the fourth quarter of 2019. Specifically, our management is in the process of implementing new controls and processes over the evaluation and transfer of unevaluated costs to the amortizable base. Our management believes that these actions will remediate the material weakness in internal control over financial reporting.

are effective.

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

~~Litigation and Regulatory Proceedings~~

We are 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. Our 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.

We, along with a number of other oil and gas companies, have 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.

In July 2019, Pigeon Land Company, Inc., a successor in interest to certain of our legacy Louisiana properties, filed an action against us and many other oil and gas companies in the 16th Judicial District Court for the Parish of Iberia in Louisiana. The suit alleges negligence, strict liability and various violations of Louisiana statutes relating to property damage in connection with the historic development of our Louisiana properties and seeks unspecified damages (including punitive damages), an injunction to return the affected property to its original condition, and the payment of reasonable attorney fees and legal expenses and interest.

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 us, and its significant stockholders, including us, 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.

In October 2019, Kelsie Wagner, in her capacity as trustee of various trusts and on behalf of the trusts and other similarly situated royalty owners, filed an action against us in the District Court of Grady County, Oklahoma. The suit alleges that we underpaid royalty owners and seeks unspecified damages for violations of the Oklahoma Production Revenue Standards Act and fraud.

In March 2020, Robert F. Woodley, individually and on behalf of all others similarly situated, filed a federal securities class action against us, 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 we made materially false and misleading statements regarding our 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.

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recover unspecified damages from the defendants, the implementation of specified corporate governance reforms, reasonable attorneys’ and experts’ fees, costs and expenses, and such other relief as may be deemed just and proper.

In December 2019, we 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 us. In March 2020, Stingray filed a counterclaim against us in the Superior Court of the State of Delaware. The counterclaim alleges that we have breached the Master Services Agreement. The counterclaim seeks actual damages, which the complaint calculates to be approximately 28 million as of June 2020 (such amount to increase each month), the payment of reasonable attorney fees and legal expenses and pre- and post-judgment interest as allowed, and such other and further relief which it may be justly entitled.

In April 2020, Bryon Lefort, individually and on behalf of similarly situated individuals, filed an action against us in the United States District Court for the Southern District of Ohio Eastern Division. The complaint alleges that we 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.

~~These cases are still in their early stages. As a result, we have not had the opportunity to evaluate the allegations made in the plaintiffs' complaints and intend to vigorously defend the suits.~~

~~SEC Investigation~~

The SEC has commenced an investigation with respect to certain actions by our former management, including alleged improper personal use of company assets, and potential violations by our former management and the company of the Sarbanes-Oxley Act of 2002 in connection with such actions. We have fully cooperated and intend to continue to cooperate fully with the SEC’s investigation. Although it is not possible to predict the ultimate resolution or financial liabilityinformation with respect to this ~~matter, we believe that~~Item 1. Legal Proceedings is set forth in Note 8 in the ~~outcome~~accompanying condensed consolidated financial statements. Additionally, see Note 1 in the accompanying condensed consolidated financial statements for additional discussion of ~~this matter will not have a material effect on our business, financial condition or results of operations.~~

~~Business Operations~~

~~We are involved in various lawsuits~~on-going claims and disputes ~~incidental to~~in our ~~business operations, including commercial disputes, personal injury claims, royalty claims, property damage claims and contract actions.~~

~~Environmental Contingencies~~

~~The nature~~Chapter 11 proceedings, certain of the oil and gas business carries with it certain environmental risks for Gulfport and its subsidiaries. They have implemented various policies, programs, procedures, training and audits to reduce and mitigate environmental risks. They conduct 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. We manage our 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.

We received several Finding of Violation (“FOVs”) from the United States Environmental Protection Agency ("USEPA") alleging violations of the Clean Air Act at approximately 17 locations in Ohio. The first FOV for one site was dated December 11, 2013. Two subsequent FOVs incorporated and expanded the scope on January 4, 2017 and April 15, 2019. We have exchanged information with the USEPA and are engaged in discussions aimed at resolving the allegations. Resolution of the matter resulted in monetary sanctions of approximately $1.7 million.

In October 2018, we submitted a Voluntary Disclosure document to the Oklahoma Department of Environmental Quality (ODEQ) stemming from improper air permitting at several sites in Midcon between 2014 and 2017. The sites were permitted by Vitruvian prior to our purchase of those assets. The sites were permitted utilizing the “permit by rule” regulation but actually required Title V air permits. We have agreed in a draft Consent Order to obtain the proper permits and to pay the

~~Table of Contents~~

~~costs from not having the proper permits in place in the amount of $180,000 to the ODEQ. The Order received final approval at the ODEQ and expects to~~ be ~~finalized in the third quarter of 2020.~~

~~Other Matters~~

material.


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 under "Risk Factors" in Item 1A of our Annual Report on Form 10-K for the year ended December 31, ~~2019. The risk factors below updates our risk factors previously discussed in our Annual Report on Form 10-K for the fiscal year ended December 31, 2019.~~

Any significant reduction in our borrowing base under our revolving credit facility as a result of periodic borrowing base redeterminations or otherwise or an inability to refinance our revolving credit facility prior to its maturity may negatively impact our ability to fund our operations, and we may not have sufficient funds to repay borrowings under our revolving credit facility if required as a result of a borrowing base redetermination.

In 2020, decreased demand for oil and natural gas as a result of the COVID-19 pandemic and the accompanying decrease in commodity prices has significantly reduced our ability to access capital markets and to refinance our existing indebtedness. Further, these conditions have made amendments or waivers to our revolving credit facility more difficult to obtain and available on terms less favorable to us. If depressed commodity prices persist or decline further, the borrowing base under our revolving credit facility could be further reduced at our next scheduled redetermination date in November 2020. Any such reduction would constrain our liquidity and may impair our ability to fund our planned capital expenditures and meet our obligations under our existing indebtedness. Further, a reduction in our capital expenditures would decrease our production, revenues, operating cash flow and EBITDA, which could limit our ability to comply with the restrictive covenants in our revolving credit facility and other existing indebtedness. Finally, our existing revolving credit facility matures in December 2021 and therefore will become a current liability at year end 2020 unless we are able to refinance the credit facility with a new credit facility or other financing. Considering the current state of the first lien market and our elevated leverage profile, there is substantial risk that a refinancing will not be available to us on reasonable terms. A current liability under the revolving credit facility at year end 2020 may result in a qualified audit opinion which could result in a default under the terms of the current revolving credit facility. As a result of these uncertainties, management has concluded that there is substantial doubt about our ability to continue as a going concern. Failure to meet our obligations under our existing indebtedness or failure to comply with any of our covenants, if not waived, would result in an event of default under such indebtedness and result in the potential acceleration of outstanding indebtedness thereunder and, with respect to the revolving credit facility, the potential foreclosure on the collateral securing such debt, and could cause a cross-default under our other outstanding indebtedness. Further, if the outstanding borrowings under our revolving credit facility were to exceed the borrowing base as a result of any such redetermination, we would be required to repay the excess. We may not have sufficient funds to make such repayments. If we do not have sufficient funds and we are otherwise unable to negotiate renewals of our borrowings or arrange new financing, we may have to sell significant assets. Any such sale could have a material adverse effect on our business and financial results.

The outbreak of the novel coronavirus, or COVID-19, has affected and may materially adversely affect, and any future outbreak of any other highly infectious or contagious diseases may materially adversely affect, our operations, financial performance and condition, operating results and cash flows.

The recent outbreak of COVID-19 has affected, and may materially adversely affect, our business and financial and operating results. The severity, magnitude and duration of the current COVID-19 outbreak is uncertain, rapidly changing and hard to predict. Thus far in 2020, the outbreak has significantly impacted economic activity and markets around the world, and COVID-19 or another similar outbreak could negatively impact our business in numerous ways, including, but not limited to, the following:

•our revenue may be reduced if the outbreak results in an economic downturn or recession, as many experts predict, to the extent it leads to a prolonged decrease in the demand for natural gas and, to a lesser extent, NGL and oil;

~~Table of Contents~~

•our operations may be disrupted or impaired, thus lowering our production level, if a significant portion of our employees or contractors are unable to work due to illness or if our field operations are suspended or temporarily shut-down or restricted due to control measures designed to contain the outbreak;

•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, oil and NGL, may be disrupted or suspended in response to containing the outbreak, and/or the difficult economic environment may lead to the bankruptcy or closing of the facilities and infrastructure of our midstream service providers, which may result in substantial discounts in the prices we receive for our produced natural gas, oil and NGL or result in the shut-in of producing wells or the delay or discontinuance of development plans for our properties; and

•the disruption and instability in the financial markets and the uncertainty in the general business environment may affect our ability to execute on our business strategy, including our focus on reducing our leverage profile. If we are not able to successfully execute our plan to reduce our leverage profile, our high level of indebtedness could make it more difficult for us to satisfy our obligations with respect to our indebtedness, and any failure to comply with the obligations under any of our debt instruments, including their restrictive covenants, could result in a default under our revolving credit facility or the indentures governing our senior notes. Additionally, our credit ratings may be lowered, we may reduce or delay our planned capital expenditures or investments, and we may revise or delay our strategic plans.

We expect that the principal areas of operational risk for us are availability of service providers and supply chain disruption. Active development operations, including drilling and fracking operations, represent the greatest risk for transmission given the number of personnel and contractors on site. While we believe that we are following best practices under COVID-19 guidance, the potential for transmission still exists. In certain instances, it may be necessary or determined advisable for us to delay development operations.

In addition, the COVID-19 pandemic has increased volatility and caused negative pressure in the capital and credit markets. As a result, we may experience difficulty accessing the capital or financing needed to fund our exploration and production operations, which have substantial capital requirements, or refinance our upcoming maturities on satisfactory terms or at all. We typically fund our capital expenditures with existing cash and cash generated by operations (which is subject to a number of variables, including many beyond our control) and, to the extent our capital expenditures exceed our cash resources, from borrowings under our revolving credit facility and other external sources of capital. If our cash flows from operations or the borrowing capacity under our revolving credit facility are insufficient to fund our capital expenditures and we are unable to obtain the capital necessary for our planned capital budget or our operations, we could be required to curtail our operations and the development of our properties, which in turn could lead to a decline in our reserves and production, and could adversely affect our business, results of operations and financial position.

To the extent the COVID-19 pandemic adversely affects our business and financial results, it may also have the effect of heightening many of the other risks set forth in Item 1A., “Risk Factors” in our Annual Report on Form 10-K, such as those relating to our financial performance and debt obligations. The rapid development and fluidity of this situation precludes any prediction as to the ultimate adverse impact of COVID-19 on our business, which will depend on numerous evolving factors and future developments that we are not able to predict, including the length of time that the pandemic continues, its effect on the demand for natural gas, NGL and oil, the response of the overall economy and the financial markets as well as the effect of governmental actions taken in response to the pandemic.

We expect that we will be unable to meet our firm commitment delivery obligations under our firm transportation contracts relating to our Utica Shale or SCOOP acreage due to decreased developmental activities, which will result in fees and may have a material adverse effect on our operations.

As of June 30, 2020, we had entered into firm transportation contracts to deliver approximately 1,455,000 MMBtu per day for the remainder of 2020 and 2021, respectively. Under these firm transportation contracts, we are obligated to deliver minimum daily volumes or pay fees for any deficiencies in deliveries. As a result of the reduced production from our Utica Shale or SCOOP acreage due to decreased developmental activities, taking into consideration the current low commodity price environment, we expect that we will be unable to meet our obligations under the existing firm transportation contracts, resulting in fees, which may be significant and may have a material adverse effect on our operations.


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

~~Table of Contents~~

Unregistered Sales of Equity Securities

None.

Issuer Repurchases of Equity Securities

Our common stock repurchase activity for the three months ended ~~June 30, 2020~~March 31, 2021 was as follows:

Period Total number of shares purchased (1) Average price paid per share Total number of shares purchased as part of publicly announced plans or programs Approximate maximum dollar value of shares that may yet be purchased under the plans or programs (2)
April 2020 18,338 $ 0.72 — $ 370,000,000
May 2020 — $ — — $ 370,000,000
June 2020 8,956 $ 1.69 — $ 370,000,000
Total 27,294 $ 1.04 —


Period	Total number of shares purchased (1)	Average price paid per share		Total number of shares purchased as part of publicly announced plans or programs
January	—	$	—	—
February	86,401	$	0.09	—
March	—	$	—	—
Total	86,401	$	0.09	—

(1)

During the three months ended ~~June 30, 2020,~~March 31, 2021, we repurchased and canceled ~~27,294~~86,401 shares of our common stock at a weighted average price of ~~$1.04~~$0.09 to satisfy tax withholding requirements incurred upon the vesting of restricted stock unit awards.

~~(2)~~

In January 2019, our board of directors approved a new stock repurchase program to acquire up to $400.0 million of our outstanding common stock within a 24 month period. The program was suspended in the fourth quarter of 2019, and the May 1, 2020 amendment to our revolving credit facility prohibits further repurchases.


ITEM 3.			DEFAULTS UPON SENIOR SECURITIES

~~Not applicable.~~Our Bankruptcy Filing described above constitutes an event of default that accelerated our obligations under our senior Pre-Petition Revolving Credit Facility and our Senior Notes. Under the Bankruptcy Code, the creditors under these debt agreements are stayed from taking any action against us as a result of an event of default. See Note 1 and Note 5 to the unaudited consolidated financial statements included in Part I, Item 1 of this Form 10-Q for additional details about the principal and interest amounts of debt included in liabilities subject to compromise on the accompanying unaudited consolidated balance sheet as of March 31, 2021 and our Bankruptcy Filing and the Chapter 11 Cases.


ITEM 4.			MINE SAFETY DISCLOSURES

Not applicable.

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ITEM 5.			OTHER INFORMATION

~~Incentive compensation program~~

In connection with a comprehensive review of the Company’s compensation programs and in consultation with its independent compensation consultant and legal advisors, the Board of Directors has determined that significant changes are appropriate to retain and motivate the Company’s employees as a result of the ongoing uncertainty and unprecedented disruption in the oil and gas industry. Accordingly, as of August 4, 2020, the Board has authorized a redesign of the incentive compensation program for the Company’s workforce, including for its current named executive officers: David M. Wood, Donnie Moore, Quentin R. Hicks, Patrick K. Craine and Michael Sluiter (the “executives”). Participation by the executives in the new compensation program is contingent upon forfeiture of (i) all unpaid amounts previously awarded pursuant to the 2020 Incentive Plan, (ii) all restricted stock units granted in 2020 and (iii) any award pursuant to the 2019 Executive Annual Incentive Compensation Program for 2020, other than payment of pro-rata bonuses earned for the period from January 1, 2020 through July 31, 2020 at the target level. Under the new compensation program, each executive’s target total variable compensation amount for 2020 (target annual bonus and long-term incentive, after adjusting the long-term incentive targets for each of Messrs. Hicks and Craine to 350% in recognition of increased workload), less any amounts previously paid pursuant to the 2020 Incentive Plan, will be paid as soon as practicable. Of this variable compensation amount, 50% will be subject to repayment on an after-tax basis in the event of the executive’s resignation without good reason or termination by the Company for cause prior to the earlier of July 31, 2021, a change in control or completion of a restructuring, and the remaining 50% will be subject to repayment on an after-tax basis if performance metrics established by the Board are not met over performance periods from August 1, 2020 through July 31, 2021.

~~Restricted stock dispositions to satisfy tax withholding obligations for Named Executive Officers~~

All shares noted below represent vested restricted stock units previously granted under Gulfport's equity incentive plan and were withheld by Gulfport to satisfy tax withholding obligations due upon settlement of the restricted stock units.

~~On February 26, 2020, the following named executive officers disposed of shares to satisfy tax withholding obligations:~~


~~Named Executive Officer~~			~~Restricted Stock Units~~
~~David M. Wood~~			~~43,557~~
~~Michael Sluiter~~			~~17,060~~

~~Additionally, on February 27, 2020, the following named executive officer disposed of shares to satisfy tax withholding obligations:~~


~~Named Executive Officer~~			~~Restricted Stock Units~~
~~Donnie Moore~~			~~19,498~~

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
3.1
Restated Certificate of Incorporation.
8-K 000-19514 3.1 4/26/2006
3.2
Certificate of Amendment No. 1 to Restated Certificate of Incorporation.
10-Q 000-19514 3.2 11/6/2009
3.3
Certificate of Amendment No. 2 to Restated Certificate of Incorporation.
8-K 000-19514 3.1 7/23/2013
3.4
Second Amended and Restated Bylaws of Gulfport Energy Corporation
8-K 000-19514 3.1 2/27/2020
3.5
First Amendment to the Second Amended and Restated Bylaws of Gulfport Energy Corporation
8-K 001-19514 3.1 5/29/2020
3.6
Certificate of Designation of Series B Junior Participating Preferred Stock of Gulfport Energy Corporation
8-A 001-19514 3.1 4/30/2020
4.1
Form of Common Stock certificate.
SB-2 333-115396 4.1 7/22/2004
4.2
Indenture, dated as of April 21, 2015, among the Company, the subsidiary guarantors party thereto and Wells Fargo Bank, N.A., as trustee (including the form of the Company’s 6.625% Senior Notes due 2023).
8-K 000-19514 4.1 4/21/2015
4.3
Indenture, dated as of October 14, 2016, among Gulfport Energy Corporation, the subsidiary guarantors party thereto and Wells Fargo Bank, N.A., as trustee (including the form of Gulfport Energy Corporation’s 6.000% Senior Notes due 2024).
8-K 000-19514 4.1 10/19/2016
4.4
Indenture, dated as of December 21, 2016, among Gulfport Energy Corporation, the subsidiary guarantors party thereto and Wells Fargo Bank, N.A., as trustee (including the form of Gulfport Energy Corporation’s 6.375% Senior Notes due 2025).
8-K 000-19514 4.1 12/21/2016
4.5
Indenture, dated as of October 11, 2017, among Gulfport Energy Corporation, the subsidiary guarantors party thereto and Wells Fargo Bank, N.A., as trustee (including the form of Gulfport Energy Corporation’s 6.375% Senior Notes due 2026).
8-K 000-19514 4.1 10/11/2017
4.6
Tax Benefits Preservation Plan, dated as of April 30, 2020, between Gulfport Energy Corporation and Computershare Trust Company, N.A., as rights agent (which includes the Form of Rights Certificate as Exhibit B thereto)
8-A 001-19514 4.1 4/30/2020
10.1+
Gulfport Energy Corporation 2020 Incentive Plan.
8-K 000-19514 10.1 3/17/2020


INDEX OF EXHIBITS
		Incorporated by Reference
Exhibit Number	Description	Form	SEC File Number	Exhibit	Filing Date	Filed or Furnished Herewith
2.1	Order (I) Confirming the Amended Joint Chapter 11 Plan of Reorganization of Gulfport Energy Corporation and its Debtor Subsidiaries and (II) Granting Related Relief.	8-K	001-19514	2.1	4/29/2021

2.2	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	Restated Certificate of Incorporation.	8-K	000-19514	3.1	4/26/2006

3.2	Certificate of Amendment No. 1 to Restated Certificate of Incorporation.	10-Q	000-19514	3.2	11/6/2009

3.3	Certificate of Amendment No. 2 to Restated Certificate of Incorporation.	8-K	000-19514	3.1	7/23/2013

3.4	Second Amended and Restated Bylaws of Gulfport Energy Corporation	8-K	000-19514	3.1	2/27/2020

3.5	First Amendment to the Second Amended and Restated Bylaws of Gulfport Energy Corporation	8-K	001-19514	3.1	5/29/2020

3.6	Certificate of Designation of Series B Junior Participating Preferred Stock of Gulfport Energy Corporation	8-A	001-19514	3.1	4/30/2020

4.1	Form of Common Stock certificate.	SB-2	333-115396	4.1	7/22/2004

4.2	Indenture, dated as of April 21, 2015, among the Company, the subsidiary guarantors party thereto and Wells Fargo Bank, N.A., as trustee (including the form of the Company’s 6.625% Senior Notes due 2023).	8-K	000-19514	4.1	4/21/2015

4.3	Indenture, dated as of October 14, 2016, among Gulfport Energy Corporation, the subsidiary guarantors party thereto and Wells Fargo Bank, N.A., as trustee (including the form of Gulfport Energy Corporation’s 6.000% Senior Notes due 2024).	8-K	000-19514	4.1	10/19/2016

4.4	Indenture, dated as of December 21, 2016, among Gulfport Energy Corporation, the subsidiary guarantors party thereto and Wells Fargo Bank, N.A., as trustee (including the form of Gulfport Energy Corporation’s 6.375% Senior Notes due 2025).	8-K	000-19514	4.1	12/21/2016

4.5	Indenture, dated as of October 11, 2017, among Gulfport Energy Corporation, the subsidiary guarantors party thereto and Wells Fargo Bank, N.A., as trustee (including the form of Gulfport Energy Corporation’s 6.375% Senior Notes due 2026).	8-K	000-19514	4.1	10/11/2017

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10.2+
Form of 2020 Cash Award under Gulfport Energy Corporation 2020 Incentive Plan.
8-K 000-19514 10.2 3/17/2020
10.3
Fifteenth Amendment to the Amended and Restated Credit Agreement, dated as of May 1, 2020, between Gulfport Energy Corporation, as Borrower, the Bank of Nova Scotia, as Administrative Agent and the lenders party thereto
X
10.4
Sixteenth Amendment to the Amended and Restated Credit Agreement, dated as of July 27, 2020, between Gulfport Energy Corporation, as Borrower, the Bank of Nova Scotia, as Administrative Agent and the lenders party thereto
8-K 001-19514 10.1 7/30/2020
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.
X
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.
X
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.
X
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.
X
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+			~~Management contract, compensation plan or arrangement.~~

4.6

Tax Benefits Preservation Plan, dated as of April 30, 2020, between Gulfport Energy Corporation and Computershare Trust Company, N.A., as rights agent (which includes the Form of Rights Certificate as Exhibit B thereto)

8-A

001-19514

4.1

4/30/2020

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.

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SIGNATURES

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

Date: ~~August~~May 6, ~~2020~~2021

GULFPORT ENERGY CORPORATION

By:

/s/ Quentin Hicks

Quentin Hicks
Executive Vice President & Chief Financial Officer

7054


				Paid-in Capital		Accumulated Other Comprehensive (Loss) Income		Accumulated Deficit		Total Stockholders’ Equity
	Common Stock
	Shares	Amount
	(In thousands)
Balance at January 1, 2020	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	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	160,116	$	1,601	$	4,211,062	$	(54,991)	$	(3,926,332)	$	231,340


						(MMBtu per day)
Remaining 2020						311,000
2021						192,000
2022						70,000
2023						17,000


Total						590,000


	Total MMBtu	(In thousands)
Remaining 2020	267,720,000	$	138,495
2021	531,075,000	285,779
2022	531,075,000	286,616
2023	515,775,000	282,936
2024	489,490,000	265,558
Thereafter	3,767,959,000	2,160,634
Total	6,103,094,000	$	3,420,018


	As of December 31, 2019
	Gross Assets (Liabilities)		Gross Amounts
	Presented in the		Subject to Master		Net
	Consolidated Balance Sheets		Netting Agreements		Amount
	(In thousands)
Derivative assets	$	126,764	$	(53,438)	$	73,326
Derivative liabilities	$	(53,438)	$	53,438	$	—


	June 30, 2020
	Parent		Guarantors		Non-Guarantors		Eliminations		Consolidated
Assets
Current assets:
Cash and cash equivalents	$	823	$	1,748	$	246	$	—	$	2,817
Accounts receivable - oil and natural gas sales	860		64,785		—		—		65,645
Accounts receivable - joint interest and other	2,949		16,440		—		—		19,389

Accounts receivable - intercompany	1,482,102		1,150,631		—		(2,632,733)		—
Prepaid expenses and other current assets	10,781		5		76		—		10,862
Short-term derivative instruments	53,188		—		—		—		53,188
Total current assets	1,550,703		1,233,609		322		(2,632,733)		151,901

Property and equipment:
Oil and natural gas properties, full-cost accounting	1,247,631		9,478,228		5,862		(729)		10,730,992
Other property and equipment	92,768		51		4,019		—		96,838
Accumulated depletion, depreciation, amortization and impairment	(1,423,539)		(7,032,075)		(1,850)		—		(8,457,464)
Property and equipment, net	(83,140)		2,446,204		8,031		(729)		2,370,366
Other assets:
Equity investments and investments in subsidiaries	1,930,479		6,332		13,013		(1,936,772)		13,052
Long-term derivative instruments	4,298		—		—		—		4,298


Operating lease assets	3,640		—		—		—		3,640

Other assets	29,216		7,784		—		—		37,000
Total other assets	1,967,633		14,116		13,013		(1,936,772)		57,990
Total assets	$	3,435,196	$	3,693,929	$	21,366	$	(4,570,234)	$	2,580,257

Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable and accrued liabilities	$	46,085	$	269,490	$	—	$	—	$	315,575
Accounts payable - intercompany	1,185,800		1,442,144		4,789		(2,632,733)		—

Short-term derivative instruments	8,540		—		—		—		8,540
Current portion of operating lease liabilities	3,356		—		—		—		3,356

Current maturities of long-term debt	649		—		—		—		649
Total current liabilities	1,244,430		1,711,634		4,789		(2,632,733)		328,120
Long-term derivative instruments	45,615		—		—		—		45,615
Asset retirement obligation - long-term	—		61,371		—		—		61,371
Uncertain tax position liability	3,209		—		—		—		3,209

Non-current operating lease liabilities	284		—		—		—		284

Long-term debt, net of current maturities	1,910,318		—		—		—		1,910,318
Total liabilities	3,203,856		1,773,005		4,789		(2,632,733)		2,348,917

Stockholders’ equity:
Common stock	1,601		—		—		—		1,601
Paid-in capital	4,211,062		4,171,409		267,559		(4,438,968)		4,211,062
Accumulated other comprehensive loss	(54,991)		—		(52,562)		52,562		(54,991)
Accumulated deficit	(3,926,332)		(2,250,485)		(198,420)		2,448,905		(3,926,332)
Total stockholders’ equity	231,340		1,920,924		16,577		(1,937,501)		231,340
Total liabilities and stockholders’ equity	$	3,435,196	$	3,693,929	$	21,366	$	(4,570,234)	$	2,580,257


	Three months ended June 30, 2020
	Parent		Guarantors		Non-Guarantors		Eliminations		Consolidated

Total revenues	$	26,970	$	105,440	$	—	$	—	$	132,410

Costs and expenses:
Lease operating expenses	—		15,686		—		—		15,686
Production taxes	—		3,605		—		—		3,605
Midstream gathering and processing expenses	—		59,974		—		—		59,974
Depreciation, depletion and amortization	2,388		62,236		166		—		64,790
Impairment of oil and natural gas properties	—		532,880		—		—		532,880
General and administrative expenses	21,731		(11,374)		113		—		10,470
Accretion expense	—		755		—		—		755
Total Operating Expenses	24,119		663,762		279		—		688,160

INCOME (LOSS) FROM OPERATIONS	2,851		(558,322)		(279)		—		(555,750)

OTHER EXPENSE (INCOME):
Interest expense	32,825		(459)		—		—		32,366
Interest income	(28)		(50)		—		—		(78)



Gain on debt extinguishment	(34,257)		—		—		—		(34,257)
Loss from equity method investments and investments in subsidiaries	562,502		—		45		(562,502)		45
Other expense	2,877		4,365		—		—		7,242
Total Other Expense	563,919		3,856		45		(562,502)		5,318

LOSS BEFORE INCOME TAXES	(561,068)		(562,178)		(324)		562,502		(561,068)
INCOME TAX EXPENSE	—		—		—		—		—

NET LOSS	$	(561,068)	$	(562,178)	$	(324)	$	562,502	$	(561,068)


	Three months ended June 30, 2019
	Parent		Guarantors		Non-Guarantor		Eliminations		Consolidated

Total revenues	$	280,291	$	178,703	$	—	$	—	$	458,994

Costs and expenses:
Lease operating expenses	12,256		10,132		—		—		22,388
Production taxes	2,820		5,278		—		—		8,098
Midstream gathering and processing expenses	28,121		43,894		—		—		72,015
Depreciation, depletion and amortization	80,132		44,764		55		—		124,951

General and administrative expenses	15,207		(3,583)		103		—		11,727
Accretion expense	438		921		—		—		1,359


Total Operating Expenses	138,974		101,406		158		—		240,538

INCOME (LOSS) FROM OPERATIONS	141,317		77,297		(158)		—		218,456

OTHER EXPENSE (INCOME):
Interest expense	37,373		(955)		—		—		36,418
Interest income	(120)		(39)		—		—		(159)



Loss (income) from equity method investments and investments in subsidiaries	47,449		—		(54)		78,187		125,582
Other expense	990		—		—		—		990
Total Other Expense (Income)	85,692		(994)		(54)		78,187		162,831

INCOME (LOSS) BEFORE INCOME TAXES	55,625		78,291		(104)		(78,187)		55,625
INCOME TAX BENEFIT	(179,331)		—		—		—		(179,331)

NET INCOME (LOSS)	$	234,956	$	78,291	$	(104)	$	(78,187)	$	234,956


	Six months ended June 30, 2020
	Parent		Guarantors		Non-Guarantors		Eliminations		Consolidated

Total revenues	$	125,238	$	254,049	$	—	$	—	$	379,287

Costs and expenses:
Lease operating expenses	—		31,672		—		—		31,672
Production taxes	—		8,404		—		—		8,404
Midstream gathering and processing expenses	—		117,870		—		—		117,870
Depreciation, depletion, and amortization	4,890		137,596		332		—		142,818
Impairment of oil and gas properties	—		1,086,225		—		—		1,086,225
General and administrative expenses	46,377		(20,024)		286		—		26,639
Accretion expense	—		1,496		—		—		1,496
Total Operating Expenses	51,267		1,363,239		618		—		1,415,124

INCOME (LOSS) FROM OPERATIONS	73,971		(1,109,190)		(618)		—		(1,035,837)

OTHER EXPENSE (INCOME):
Interest expense	66,002		(646)		—		—		65,356
Interest income	(87)		(143)		—		—		(230)



Gain on debt extinguishment	(49,579)		—		—		—		(49,579)
Loss from equity method investments and investments in subsidiaries	1,125,868		—		188		(1,115,222)		10,834
Other expense	3,083		6,015		—		—		9,098
Total Other Expense	1,145,287		5,226		188		(1,115,222)		35,479

LOSS BEFORE INCOME TAXES	(1,071,316)		(1,114,416)		(806)		1,115,222		(1,071,316)
INCOME TAX EXPENSE	7,290		—		—		—		7,290

NET LOSS	$	(1,078,606)	$	(1,114,416)	$	(806)	$	1,115,222	$	(1,078,606)


	Six months ended June 30, 2019
	Parent		Guarantors		Non-Guarantor		Eliminations		Consolidated

Total revenues	$	466,537	$	313,035	$	—	$	—	$	779,572

Costs and expenses:
Lease operating expenses	27,149		15,046		—		—		42,195
Production taxes	6,081		9,938		—		—		16,019
Midstream gathering and processing expenses	71,420		70,877		—		—		142,297
Depreciation, depletion, and amortization	198,564		44,765		55		—		243,384

General and administrative expenses	25,938		(4,258)		104		—		21,784
Accretion expense	1,389		1,037		—		—		2,426

Total Operating Expenses	330,541		137,405		159		—		468,105

INCOME (LOSS) FROM OPERATIONS	135,996		175,630		(159)		—		311,467

OTHER EXPENSE (INCOME):
Interest expense	73,298		(1,259)		—		—		72,039
Interest income	(267)		(44)		—		—		(311)



(Income) loss from equity method investments and investments in subsidiaries	(55,465)		—		339		176,435		121,309
Other expense	563		—		—		—		563
Total Other Expense (Income)	18,129		(1,303)		339		176,435		193,600

INCOME (LOSS) BEFORE INCOME TAXES	117,867		176,933		(498)		(176,435)		117,867
INCOME TAX BENEFIT	(179,331)		—		—		—		(179,331)

NET INCOME (LOSS)	$	297,198	$	176,933	$	(498)	$	(176,435)	$	297,198


Applicable Rate
Applicable Usage Level	Commitment fee	Eurodollar Rate Loans and Letters of Credit	Base Rate Loans
Level 1	0.375%	2.00%	1.00%
Level 2	0.375%	2.25%	1.25%
Level 3	0.50%	2.50%	1.50%
Level 4	0.50%	2.75%	1.75%
Level 5	0.50%	3.00%	2.00%