UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM ~~10-Q/A~~10-Q

~~(Amendment No. 1)~~

(Mark One)



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

For the quarterly period ended ~~September 30, 2019~~March 31, 2020



☐	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

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No ¨

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. (Check one):

Large Accelerated filer ý Accelerated filer ¨

Non-accelerated filer ¨ Smaller reporting company ☐

Emerging growth company ☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ý

As of ~~October 25, 2019~~May 1, 2020, ~~159,709,221~~159,872,688 shares of the registrant’s common stock were outstanding.

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~~EXPLANATORY NOTE~~

This Amendment No. 1 to the Quarterly Report on Form 10-Q/A (the “Amendment”) is being filed by Gulfport Energy Corporation (the "Company") to amend the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2019, which was originally filed with the Securities and Exchange Commission (the "SEC") on November 1, 2019 (the “Original Filing”). The Amendment sets forth the information in Original Filing in its entirety, as adjusted for the effects of the restatement described below.

On February 25, 2020, the Audit Committee of the Company's Board of Directors, in conjunction with senior management, concluded that the Company's unaudited consolidated financial statements as of and for the periods ended September 30, 2019 included in the Company's quarterly report on Form 10-Q for the quarterly period ended September 30, 2019 should be restated to correct the error discussed below and should no longer be relied upon.

In the course of preparing the consolidated financial statements for the year ended December 31, 2019, the Company identified a misstatement of its depreciation, depletion and amortization and impairment of oil and gas properties as of September 30, 2019 of approximately $554 million ($436 million net of the tax benefit) related to unrecorded transfers of its unevaluated oil and natural gas properties into the amortization base. This error impacted the related calculations of the Company's depreciation, depletion and amortization and impairment of oil and natural gas properties for the three and nine month periods ended September 2019. Net (loss) income and income tax benefit have also been impacted.

This Amendment is being filed solely to (i) restate the consolidated financial statements for the misstatement described above to the consolidated financial statements (and to make corresponding changes to the Risk Factors and Management's Discussion and Analysis of Financial Condition and Results of Operations sections in this Amendment) and (ii) amend Item 4 (Controls and Procedures).

~~The following sections in the Original Filing are revised in this Amendment to reflect the restatement:~~

•~~Part I - Item 1.~~ ~~Consolidated Financial Statements~~

•~~Part I - Item 2.~~ ~~Management's Discussion and Analysis of Financial Conditions and Results of Operations~~

•~~Part I - Item 4.~~ ~~Controls and Procedures~~

•~~Part II - Item 1A. Risk Factors~~

•~~Part II - Item 6. Exhibits~~

Our consolidated financial statements as of September 30, 2019 and for the three and nine month periods then ended have been restated to correctly reflect the unproved oil and natural gas properties excluded from amortization and accumulated depletion, depreciation, amortization and impairment in the consolidated balance sheet and the depreciation, depletion and amortization, impairment of oil and natural gas properties, income tax benefit and net loss in the consolidated statements of operations and consolidated statements of cash flows and other related effects on the consolidated financial statements and related footnotes. See restated Note 1 for the adjustments to the consolidated financial statements related to this misstatement. The Company has also made corresponding amendments to Management's Discussion and Analysis of Financial Conditions and Results of Operations.

This Amendment resulted from a material weakness in internal control over financial reporting. As such, Item 4 of Part I has been amended for our assessment of the effectiveness of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Exchange Act. This Amendment includes new certifications from the Company’s Chief Executive Officer and President and Chief Financial Officer dated as of the date of filing of this Amendment, as required by Sections 302 and 906 of the Sarbanes-Oxley act of 2002. The certifications are included in this Amendment as Exhibits 31.1, 31.2, 32.1 and 32.2.

This Amendment does not reflect events occurring after the filing of the Original Filing, or modify or update those disclosures affected by subsequent events, except for the effects of the restatement. Disclosures not affected by the restatement are unchanged and reflect the disclosures made at the time of the Original Filing. Accordingly, this Amended Form 10-Q should be read in conjunction with our filings with the SEC subsequent to the date on which we filed the Original Filing with the SEC.

GULFPORT ENERGY CORPORATION

TABLE OF CONTENTS

~~Table of Contents~~



		Page
PART I FINANCIAL INFORMATION

Item 1.	Consolidated Financial Statements (Unaudited):	2

	Consolidated Balance Sheets at ~~September 30, 2019~~March 31, 2020 and December 31, ~~2018~~2019	2

	Consolidated Statements of Operations for the Three ~~and Nine~~ Months Ended ~~September 30,~~March 31, 2020 and 2019 ~~and 2018~~	3

	Consolidated Statements of Comprehensive Income for the Three ~~and Nine~~ Months Ended ~~September 30,~~March 31, 2020 and 2019 ~~and 2018~~	4

	Consolidated Statements of Stockholders’ Equity for the ~~Nine~~Three Months Ended ~~September 30,~~March 31, 2020 and 2019 ~~and 2018~~	54

	Consolidated Statements of Cash Flows for the ~~Nine~~Three Months Ended ~~September 30,~~March 31, 2020 and 2019 ~~and 2018~~	75

	Notes to Consolidated Financial Statements	86

Item 2.	Management’s Discussion and Analysis of Financial Conditions and Results of Operations	3831

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	5143

Item 4.	Controls and Procedures	5345

PART II OTHER INFORMATION

Item 1.	Legal Proceedings	5546

Item 1A.	Risk Factors	5647

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	5749

Item 3.	Defaults Upon Senior Securities	5749

Item 4.	Mine Safety Disclosures	5749

Item 5.	Other Information	5749

Item 6.	Exhibits	5751

Signatures		6053

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GULFPORT ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS

~~(Unaudited)~~


	September 30, 2019			December 31, 2018			March 31, 2020			December 31, 2019
	(In thousands, except share data)						(Unaudited)
	As Restated						(In thousands, except share data)
Assets
Current assets:
Cash and cash equivalents	$	10,124		$	52,297		$	1,633		$	6,060
Accounts receivable—oil and natural gas sales	112,657			210,200			74,099			121,210
Accounts receivable—joint interest and other	41,327			22,497			42,547			47,975
Prepaid expenses and other current assets	5,658			10,017			11,848			4,431
Short-term derivative instruments	134,571			21,352			171,755			126,201
Total current assets	304,337			316,363			301,882			305,877
Property and equipment:
Oil and natural gas properties, full-cost accounting, $2,260,759 and $2,873,037 excluded from amortization in 2019 and 2018, respectively	10,551,713			10,026,836
Oil and natural gas properties, full-cost accounting, $1,608,640 and $1,686,666 excluded from amortization in 2020 and 2019, respectively							10,667,532			10,595,735
Other property and equipment	96,233			92,667			96,882			96,719
Accumulated depletion, depreciation, amortization and impairment	(5,616,988		)	(4,640,098		)	(7,859,873		)	(7,228,660		)
Property and equipment, net	5,030,958			5,479,405			2,904,541			3,463,794
Other assets:
Equity investments	73,962			236,121			6,225			32,044
Long-term derivative instruments	23,419			—			—			563
Deferred tax asset	323,378			—			—			7,563
Inventories	7,022			5,344
Operating lease assets	13,920			—			10,186			14,168
Operating lease assets - related parties	48,449			—
Operating lease assets—related parties							—			43,270
Other assets	11,653			13,803			41,453			15,540
Total other assets	501,803			255,268			57,864			113,148
Total assets	$	5,837,098		$	6,051,036		$	3,264,287		$	3,882,819
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable and accrued liabilities	$	439,019		$	518,380		$	437,453		$	415,218
Short-term derivative instruments	429			20,401			67			303
Current portion of operating lease liabilities	12,848			—			9,873			13,826
Current portion of operating lease liabilities - related parties	21,017			—
Current portion of operating lease liabilities—related parties							—			21,220
Current maturities of long-term debt	622			651			688			631
Total current liabilities	473,935			539,432			448,081			451,198
Long-term derivative instruments	72,040			13,992			70,829			53,135
Asset retirement obligation—long-term	59,819			79,952
Asset retirement obligation							59,444			60,355
Uncertain tax position liability	3,127			3,127			3,209			3,127
Non-current operating lease liabilities	1,072			—			313			342
Non-current operating lease liabilities - related parties	27,432			—
Non-current operating lease liabilities—related parties							—			22,050
Long-term debt, net of current maturities	2,076,569			2,086,765			1,898,362			1,978,020
Total liabilities	2,713,994			2,723,268			2,480,238			2,568,227
Commitments and contingencies (Note 8)
Commitments and contingencies (Note 9)
Preferred stock, $0.01 par value; 5,000,000 shares authorized (30,000 authorized as redeemable 12% cumulative preferred stock, Series A), and none issued and outstanding	—			—			—			—
Stockholders’ equity:
Common stock - $0.01 par value, 200,000,000 shares authorized, 159,709,221 issued and outstanding at September 30, 2019 and 162,986,045 at December 31, 2018	1,597			1,630
Common stock - $.01 par value, 200,000,000 shares authorized, 159,841,930 issued and outstanding at March 31, 2020 and 159,710,955 at December 31, 2019							1,598			1,597
Paid-in capital	4,205,158			4,227,532			4,209,578			4,207,554
Accumulated other comprehensive loss	(50,679		)	(56,026		)	(61,863		)	(46,833		)
Accumulated deficit	(1,032,972		)	(845,368		)	(3,365,264		)	(2,847,726		)
Total stockholders’ equity	3,123,104			3,327,768			784,049			1,314,592
Total liabilities and stockholders’ equity	$	5,837,098		$	6,051,036		$	3,264,287		$	3,882,819

See accompanying notes to consolidated financial statements.

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GULFPORT ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)


	Three months ended September 30,						Nine months ended September 30,
	2019			2018			2019			2018			Three months ended March 31,
	(In thousands, except share data)												2020			2019
	As Restated						As Restated						(In thousands, except share data)
Revenues:
Natural gas sales	$	213,227		$	271,167		$	714,500		$	753,261		$	108,547		$	276,016
Oil and condensate sales	24,550			45,682			93,942			140,687			23,151			32,482
Natural gas liquid sales	20,324			53,776			78,136			141,883			16,913			32,125
Net gain (loss) on natural gas, oil and NGLs derivatives	27,074			(9,663		)	178,169			(96,737		)
Net gain (loss) on natural gas, oil and NGL derivatives													98,266			(20,045		)
	285,175			360,962			1,064,747			939,094			246,877			320,578
Costs and expenses:
Lease operating expenses	22,473			22,325			64,668			64,143			15,986			19,807
Production taxes	6,565			9,348			22,584			23,861			4,799			7,921
Midstream gathering and processing expenses	78,435			78,913			220,732			214,546			57,896			70,282
Depreciation, depletion and amortization	163,270			119,915			406,654			352,848			78,028			118,433
Impairment of oil and natural gas properties	571,442			—			571,442			—			553,345			—
General and administrative expenses	14,659			15,848			39,482			42,955			16,169			10,057
Accretion expense	747			1,037			3,173			3,056			741			1,067
	857,591			247,386			1,328,735			701,409			726,964			227,567
(LOSS) INCOME FROM OPERATIONS	(572,416		)	113,576			(263,988		)	237,685			(480,087		)	93,011
OTHER EXPENSE (INCOME):
Interest expense	34,095			33,253			103,095			100,922			32,990			35,621
Interest income	(338		)	(92		)	(649		)	(162		)	(152		)	(152		)
Gain on debt extinguishment	(23,600		)	—			(23,600		)	—			(15,322		)	—
Gain on sale of equity method investments	—			(2,733		)	—			(124,768		)
Loss (income) from equity method investments, net	43,082			(12,858		)	164,391			(35,282		)	10,789			(4,273		)
Other expense	3,194			856			3,757			485
Other expense (income)													1,856			(427		)
	56,433			18,426			246,994			(58,805		)	30,161			30,769
(LOSS) INCOME BEFORE INCOME TAXES	(628,849		)	95,150			(510,982		)	296,490			(510,248		)	62,242
INCOME TAX BENEFIT	(144,047		)	—			(323,378		)	(69		)
INCOME TAX EXPENSE													7,290			—
NET (LOSS) INCOME	$	(484,802	)	$	95,150		$	(187,604	)	$	296,559		$	(517,538	)	$	62,242
NET (LOSS) INCOME PER COMMON SHARE:
Basic	$	(3.04	)	$	0.55		$	(1.17	)	$	1.69		$	(3.24	)	$	0.38
Diluted	$	(3.04	)	$	0.55		$	(1.17	)	$	1.68		$	(3.24	)	$	0.38
Weighted average common shares outstanding—Basic	159,548,477			173,057,538			160,553,796			175,776,312			159,760,222			162,823,997
Weighted average common shares outstanding—Diluted	159,548,477			173,304,914			160,553,796			176,440,461			159,760,222			163,099,409

See accompanying notes to consolidated financial statements.

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GULFPORT ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE (LOSS) INCOME

(Unaudited)


	Three months ended September 30,					Nine months ended September 30,
	2019			2018		2019			2018			Three months ended March 31,
	(In thousands)											2020			2019
	As Restated					As Restated						(In thousands)
Net (loss) income	$	(484,802	)	$	95,150	$	(187,604	)	$	296,559		$	(517,538	)	$	62,242
Foreign currency translation adjustment	(2,064		)	3,052		5,347			(5,815		)	(15,030		)	3,801
Other comprehensive (loss) income	(2,064		)	3,052		5,347			(5,815		)	(15,030		)	3,801
Comprehensive (loss) income	$	(486,866	)	$	98,202	$	(182,257	)	$	290,744		$	(532,568	)	$	66,043

See accompanying notes to consolidated financial statements.

~~Table of Contents~~

GULFPORT ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(Unaudited)

Paid-in
Capital

Accumulated
Other
Comprehensive (Loss) Income

Accumulated
Deficit

Total
Stockholders’
Equity
Common Stock
Shares Amount
(In thousands, except share data)
Balance at January 1, 2019 162,986,045
$ 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 (3,618,634 ) (37 ) (28,293 ) —
—
(28,330 )
Issuance of Restricted Stock 54,554
1
(1 ) —
—
—
Balance at March 31, 2019 159,421,965
$ 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 (296,587 ) (3 ) (2,267 ) —
—
(2,270 )
Issuance of Restricted Stock 270,639
3
(3 ) —
—
—
Balance at June 30, 2019 159,396,017
$ 1,594
$ 4,202,599
$ (48,615 ) $ (548,170 ) $ 3,607,408
Net Loss (As Restated) —
—
—
—
(484,802 ) (484,802 )
Other Comprehensive Loss —
—
—
(2,064 ) —
(2,064 )
Stock Compensation —
—
2,651
—
—
2,651
Shares Repurchased (35,977 ) —
(89 ) —
—
(89 )
Issuance of Restricted Stock 349,181
3
(3 ) —
—
—
Balance at September 30, 2019 (As Restated) 159,709,221
$ 1,597
$ 4,205,158
$ (50,679 ) $ (1,032,972 ) $ 3,123,104

~~(Continued on next page)~~

~~Table of Contents~~

~~GULFPORT ENERGY CORPORATION~~

~~CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (continued)~~

~~(Unaudited)~~



						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 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


						Paid-in Capital				Accumulated Other Comprehensive (Loss) Income				Accumulated Deficit				Total Stockholders’ Equity								Paid-in Capital			Accumulated Other Comprehensive (Loss) Income			Accumulated Deficit			Total Stockholders’ Equity
	Common Stock								Common Stock
	Shares		Amount						Shares								Amount
	(In thousands, except share data)																				(In thousands)
Balance at January 1, 2018	183,105,910		$	1,831					$				4,416,250				$				(40,539	)	$	(1,275,928	)	$	3,101,614
Net Income	—		—						—				—				90,090					90,090
Other Comprehensive Loss	—		—			—					(5,503		)		—					(5,503		)
Stock Compensation	—		—			2,685				—				—				2,685
Shares Repurchased	(9,692,356	)	(97		)	(99,900		)		—				—				(99,997		)
Issuance of Restricted Stock	109,933		1			(1		)		—				—				—
Balance at March 31, 2018	173,523,487		$	1,735		$	4,319,034			$	(46,042	)		$	(1,185,838	)		$	3,088,889
Net Income	—		—			—				—				111,319				111,319
Other Comprehensive Loss	—		—			—				(3,364		)		—				(3,364		)
Stock Compensation	—		—			3,355				—				—				3,355
Shares Repurchased	(412,516	)	(4		)	(4,996		)		—				—				(5,000		)
Issuance of Restricted Stock	191,084		2			(2		)		—				—				—
Balance at June 30, 2018	173,302,055		$	1,733		$	4,317,391			$	(49,406	)		$	(1,074,519	)		$	3,195,199
Balance at January 1, 2019																					162,986		$	1,630		$	4,227,532		$	(56,026	)	$	(845,368	)	$	3,327,768
Net Income	—		—			—				—				95,150				95,150			—		—			—			—			62,242			62,242
Other Comprehensive Income	—		—			—				3,052				—				3,052			—		—			—			3,801			—			3,801
Stock Compensation	—		—			3,614				—				—				3,614			—		—			2,785			—			—			2,785
Shares Repurchased	(400,597	)	(4		)	(4,996		)		—				—				(5,000		)	(3,619	)	(37		)	(28,293		)	—			—			(28,330		)
Issuance of Restricted Stock	317,185		3			(3		)		—				—				—			55		1			(1		)	—			—			—
Balance at September 30, 2018	173,218,643		$	1,732		$	4,316,006			$	(46,354	)		$	(979,369	)		$	3,292,015
Balance at March 31, 2019																					159,422		$	1,594		$	4,202,023		$	(52,225	)	$	(783,126	)	$	3,368,266

See accompanying notes to consolidated financial statements.

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GULFPORT ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Nine months ended September 30,
	2019			2018			Three months ended March 31,
	(In thousands)						2020			2019
	As Restated						(In thousands)
Cash flows from operating activities:
Net (loss) income	$	(187,604	)	$	296,559		$	(517,538	)	$	62,242
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Accretion expense	3,173			3,056
Depletion, depreciation and amortization	406,654			352,848			78,028			118,433
Impairment of oil and natural gas properties	571,442			—			553,345			—
Stock-based compensation expense	4,969			5,792
Loss (income) from equity investments	164,532			(35,040		)	10,789			(4,132		)
Gain on debt extinguishment	(23,600		)	—			(15,322		)	—
Change in fair value of derivative instruments	(97,425		)	106,373
Deferred income tax benefit	(323,378		)	(69		)
Amortization of loan costs	4,821			4,554
Gain on sale of equity investments and other assets	(178		)	(124,768		)
Distributions from equity method investments	2,457			1,978
Net (gain) loss on derivative instruments							(98,266		)	20,045
Cash receipts (payments) on settled derivative instruments							70,733			(24,836		)
Deferred income tax expense							7,290			—
Other, net							3,223			5,508
Changes in operating assets and liabilities:
Decrease (increase) in accounts receivable—oil and natural gas sales	97,543			(10,618		)
Increase in accounts receivable—joint interest and other	(18,830		)	(2,277		)
Increase in accounts receivable—related parties	—			(79		)
Decrease (increase) in prepaid expenses and other current assets	4,359			(4,830		)
(Increase) decrease in other assets	(30		)	1,228
Increase in accounts payable, accrued liabilities and other	8,567			36,809
Settlement of asset retirement obligation	(117		)	(719		)
Decrease in accounts receivable—oil and natural gas sales							47,111			65,204
Decrease (increase) in accounts receivable—joint interest and other							6,001			(2,083		)
(Decrease) increase in accounts payable and accrued liabilities							(7,637		)	1,366
Other, net							(6,919		)	(1,982		)
Net cash provided by operating activities	617,355			630,797			130,838			239,765
Cash flows from investing activities:
Additions to other property and equipment	(4,694		)	(7,134		)
Additions to oil and natural gas properties	(646,535		)	(777,104		)	(113,744		)	(241,391		)
Proceeds from sale of oil and natural gas properties	10,864			4,820			44,383			52
Additions to other property and equipment							(539		)	(3,848		)
Proceeds from sale of other property and equipment	204			217			91			56
Proceeds from sale of equity method investments	—			226,487
Contributions to equity method investments	(432		)	(2,318		)	—			(432		)
Distributions from equity method investments	1,945			446
Net cash used in investing activities	(638,648		)	(554,586		)	(69,809		)	(245,563		)
Cash flows from financing activities:
Principal payments on borrowings	(550,500		)	(165,428		)	(180,106		)	(150,151		)
Borrowings on line of credit	640,000			225,000			125,000			150,000
Repurchase of senior notes	(79,480		)	—
Debt issuance costs and loan commitment fees	(211		)	(772		)
Payments for repurchase of stock	(30,689		)	(109,997		)
Repurchases of senior notes							(10,204		)	—
Payments for repurchases of stock under approved stock repurchase program							—			(28,212		)
Other, net							(146		)	(140		)
Net cash used in financing activities	(20,880		)	(51,197		)	(65,456		)	(28,503		)
Net (decrease) increase in cash, cash equivalents and restricted cash	(42,173		)	25,014
Net decrease in cash, cash equivalents and restricted cash							(4,427		)	(34,301		)
Cash, cash equivalents and restricted cash at beginning of period	52,297			99,557			6,060			52,297
Cash, cash equivalents and restricted cash at end of period	$	10,124		$	124,571		$	1,633		$	17,996
Supplemental disclosure of cash flow information:
Interest payments	$	85,272		$	75,045		$	14,034		$	15,266
Income tax receipts	$	(1,794	)	$	—		$	—		$	(1,794	)
Supplemental disclosure of non-cash transactions:
Capitalized stock-based compensation	$	3,313		$	3,862		$	934		$	1,114
Asset retirement obligation capitalized	$	6,846		$	1,094		$	381		$	1,952
Asset retirement obligation removed due to divestiture	$	(30,035	)	$	—		$	(2,033	)	$	—
Interest capitalized	$	2,782		$	3,956		$	187		$	766
Fair value of contingent consideration asset on date of divestiture	$	(1,137	)	$	—		$	23,090		$	—
Foreign currency translation gain (loss) on equity method investments	$	5,347		$	(5,815	)
Foreign currency translation (loss) gain on equity method investments							$	(15,030	)	$	3,801

See accompanying notes to consolidated financial statements.

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GULFPORT ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)


1.	BASIS OF PRESENTATION ~~RESTATEMENT~~ AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

~~These~~The accompanying unaudited consolidated financial statements have been prepared by Gulfport Energy Corporation (the “Company” or “Gulfport”) ~~without audit,~~ 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. ~~These~~

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 nine~~ months ended ~~September 30, 2019~~March 31, 2020 are not necessarily indicative of the results expected for the full year.

~~Restatement~~COVID-19

In March 2020, the World Health Organization classified the outbreak of ~~Previously Issued Unaudited Consolidated Financial Statements~~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 imposed regulations in efforts to control the spread of COVID-19 such as shelter-in-place orders, quarantines, executive orders and similar restrictions.

~~The~~While the Company continues to deliver energy resources to the United States, it remains focused on protecting the health and wellbeing of its employees and the communities in which it operates while assuring the continuity of its business operations. As a result of its business continuity measures, the Company has ~~restated~~not experienced significant disruptions in executing its ~~unaudited~~business operations in the first quarter of 2020. However, Gulfport is closely monitoring the impact of COVID-19 on all aspects of its business and the current commodity price environment and is unable to predict the impact it will have on its future financial position or operating results.

On March 27, 2020, the U.S. government enacted the Coronavirus Aid, Relief, and Economic Security Act (“CARES Act”). The CARES Act as currently structured is not expected to have a material impact on the Company’s consolidated financial statements to correct an error in the balance of unproved oil and natural gas properties, which impacted related depletion, depreciation and amortization and impairment of oil and natural gas properties. This error as of September 30, 2019 was identified in the course of preparing the Company's consolidated financial statements for the year ended December 31, 2019.statements.

~~The following tables present the effect of the error correction discussed above~~Impact on all affected line items of our previously issued consolidated balance sheets as of September 30, 2019, consolidated statements of operations for the three and nine months ended September 30, 2019, consolidated statements of comprehensive income for the three and nine months ended September 30, 2019, consolidated statements of stockholders' equity for the three months ended September 30, 2019 and the consolidated statements of cash flows for the nine months ended September 30, 2019.

~~Consolidated Balance Sheets~~

September 30, 2019
As Reported Adjustments As Restated
(In thousands)
Accumulated depletion, depreciation, amortization and impairment (5,063,413 ) (553,575 ) (5,616,988 )
Property and equipment, net⁽¹⁾
5,584,533
(553,575 ) 5,030,958

Deferred tax asset 205,853
117,525
323,378
Total other assets 384,278
117,525
501,803
Total assets $ 6,273,148
(436,050 ) $ 5,837,098

Accumulated deficit (596,922 ) (436,050 ) (1,032,972 )
Total stockholders’ equity 3,559,154
(436,050 ) 3,123,104
Total liabilities and stockholders’ equity $ 6,273,148
(436,050 ) $ 5,837,098

⁽¹⁾ Amount excluded from amortization in 2019
$ 2,814,334
(553,575 ) $ 2,260,759

~~Consolidated Statements of Operations~~

~~Table of Contents~~

Three Months Ended September 30, 2019
As Reported Adjustments As Restated
(In thousands)
Depreciation, depletion and amortization $ 145,490
17,780
$ 163,270
Impairment of oil and natural gas properties 35,647
535,795
571,442
Total Costs and Expenses 304,016
553,575
857,591
(LOSS) INCOME FROM OPERATIONS (18,841 ) (553,575 ) (572,416 )
(LOSS) INCOME BEFORE INCOME TAXES (75,274 ) (553,575 ) (628,849 )
INCOME TAX BENEFIT (26,522 ) (117,525 ) (144,047 )
NET (LOSS) INCOME $ (48,752 ) (436,050 ) $ (484,802 )
NET (LOSS) INCOME PER COMMON SHARE:
Basic $ (0.31 ) $ (2.73 ) $ (3.04 )
Diluted $ (0.31 ) $ (2.73 ) $ (3.04 )

Nine Months Ended September 30, 2019
As Reported Adjustments As Restated
(In thousands, except share data)
Depreciation, depletion and amortization $ 388,874
17,780
$ 406,654
Impairment of oil and natural gas properties 35,647
535,795
571,442
Total Costs and Expenses 775,160
553,575
1,328,735
(LOSS) INCOME FROM OPERATIONS 289,587
(553,575 ) (263,988 )
(LOSS) INCOME BEFORE INCOME TAXES 42,593
(553,575 ) (510,982 )
INCOME TAX BENEFIT (205,853 ) (117,525 ) (323,378 )
NET (LOSS) INCOME $ 248,446
(436,050 ) $ (187,604 )
NET (LOSS) INCOME PER COMMON SHARE:
Basic $ 1.55
$ (2.72 ) $ (1.17 )
Diluted $ 1.51
$ (2.68 ) $ (1.17 )
Weighted average common shares outstanding—Diluted 164,820,002
(4,266,206 ) 160,553,796

~~Consolidated Statements of Comprehensive Income~~

Three Months Ended September 30, 2019
As Reported Adjustments As Restated
(In thousands)
Net (loss) income $ (48,752 ) (436,050 ) $ (484,802 )
Comprehensive (loss) income $ (50,816 ) (436,050 ) $ (486,866 )

Nine Months Ended September 30, 2019
As Reported Adjustments As Restated
(In thousands)
Net (loss) income $ 248,446
(436,050 ) $ (187,604 )
Comprehensive (loss) income $ 253,793
(436,050 ) $ (182,257 )

~~Consolidated Statements of Stockholders' Equity~~

~~Table of Contents~~

Accumulated Deficit
As Reported Adjustments As Restated
(In thousands)
Net loss $ (48,752 ) (436,050 ) $ (484,802 )
Balance at September 30, 2019 $ (596,922 ) (436,050 ) $ (1,032,972 )

Total Stockholders' Equity
As Reported Adjustments As Restated
(In thousands)
Net loss $ (48,752 ) (436,050 ) $ (484,802 )
Balance at September 30, 2019 $ 3,559,154
(436,050 ) $ 3,123,104

~~Consolidated Statements of Cash Flows~~

Nine Months Ended September 30, 2019
As Reported Adjustments As Restated
(In thousands)
Cash flows from operating activities:
Net (loss) income $ 248,446
(436,050 ) $ (187,604 )
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depletion, depreciation and amortization 388,874
17,780
406,654
Impairment of oil and natural gas properties 35,647
535,795
571,442
Deferred income tax benefit (205,853 ) (117,525 ) (323,378 )

~~Statements of Cash Flows~~Previously Reported Results

During the third quarter of 2019, the Company identified that certain activities 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 while they should have been presented as additions to oil and natural gas properties in cash flows from investing activities. The Company corrected the previously presented statements of cash flows for these additions and in doing so, for the ~~nine~~three months ended ~~September 30, 2018,~~March 31, 2019 contained herein, the consolidated statements of cash flows and the condensed consolidating statements of cash flows were adjusted to increase net cash flows provided by operating activities by ~~$21.8~~$54.7 million with a corresponding increase in net cash flows used in investing activities. The Company has evaluated the effect of the incorrect presentation, both qualitatively and quantitatively, and concluded that it did not have a material impact on any previously filed annual or quarterly consolidated financial statements.

Recently ~~Issued~~Adopted Accounting ~~Pronouncements~~Standards

~~In February 2016, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2016-02,~~ ~~Leases (Topic 842).~~ The standard supersedes the previous lease guidance by requiring lessees to recognize a right-to-use asset and lease liability on the balance sheet for all leases with lease terms of greater than one year while maintaining substantially similar classifications for financing and operating leases. Subsequent to ASU 2016-02, the FASB issued several related ASU’s to clarify the application of the lease standard. The Company adopted the new standard as ofOn January 1, ~~2019 on a prospective basis using~~2020, the ~~simplified transition method permitted by ASU 2018-11,~~ ~~Leases (Topic 842): Targeted Improvements.~~ The comparative information has not been restated and continues to be reported under the historic accounting standards in effect for those periods. See Note 13 for further discussion of the lease standard.

~~Table of Contents~~

~~In June 2016, the FASB issued~~Company adopted ASU No. 2016-13, Financial Instruments-Credit Losses: Measurement of Credit Losses on Financial Instruments~~. This ASU amends guidance on reporting~~, which replaces the incurred loss impairment methodology with a methodology that reflects expected credit losses ~~for assets held at amortized cost basis~~ and ~~available for sale debt securities. For assets held at amortized cost basis, this ASU eliminates the probable initial recognition threshold in current GAAP~~requires consideration of a broader range of reasonable and ~~instead, requires an entity~~supportable information to ~~reflect its current estimate~~inform credit loss estimates. The measurement of ~~all~~ expected credit ~~losses. The amendments~~losses is based on relevant information about past events,

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including historical experience, current conditions and reasonable and supportable forecasts that affect ~~loans, debt securities, trade receivables, net investments in leases, off balance sheet credit exposure, reinsurance receivables and any other financial assets not excluded from~~ the ~~scope that have~~collectibility of the ~~contractual right to receive cash. Additionally, in May 2019, the FASB issued ASU No. 2019-05,~~ ~~Financial Instruments—Credit Losses (Topic 326): Targeted Transition Relief~~. The amendments in this update allow preparers to irrevocably elect the fair value option, on an instrument-by-instrument basis, for eligible financial assets measured at amortized cost basis upon adoption of 2016-13. The guidance is effective for periods after December 15, 2019, with early adoption permitted.reported amount. The Company ~~is in the process of designing processes and controls needed to comply with the requirements of~~adopted the new ~~standard. Although~~standard using the ~~standard will have an impact, the Company does~~prospective transition method, and it did not ~~currently anticipate the ASU to~~ have a material ~~effect~~impact on ~~its~~the Company's consolidated financial statements and related disclosures.

~~In August 2018, the FASB issued ASU No. 2018-13,~~ ~~Fair Value Measurement (Topic 820): Disclosure Framework—Changes to the Disclosure Requirements for Fair Value Measurement,~~ which removes, modifies, and adds certain disclosure requirements on fair value measurements. The amendment will be effective for reporting periods beginning after December 15, 2019, and early adoption is permitted. The Company does not anticipate the new standard to have a material effect on its consolidated financial statements and related disclosures.

~~In August 2018, the FASB also issued ASU No. 2018-15,~~ ~~Intangibles—Goodwill and Other—Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract~~, which aligns the accounting for costs associated with implementing a cloud computing arrangement in a hosting arrangement that is a service contract with the accounting for implementation costs incurred to develop or obtain internal-use software. The amendment will be effective for reporting periods beginning after December 15, 2019, and early adoption is permitted. The Company does not anticipate the new standard to have a material effect on its consolidated financial statements and related disclosures.

~~In November 2018, the FASB issued ASU No. 2018-18,~~ ~~Collaborative Arrangements (Topic 808): Clarifying the Interaction Between Topic 808 and Topic 606~~, which provides guidance on how to assess whether certain transactions between participants in a collaborative arrangement should be accounted for within the ASU No. 2014-09 revenue recognition standard discussed above. The amendment will be effective for reporting periods beginning after December 15, 2019, and early adoption is permitted. The Company does not anticipate the new standard to have a material effect on its consolidated financial statements and related disclosures.

~~In July 2019, the FASB issued ASU No. 2019-07,~~ Codification Updates to SEC Sections, Amendments to SEC Paragraphs Pursuant to SEC Final Rule Releases No. 33-10532, Disclosure Update and Simplification, and Nos. 33-10231 and 33-10442, Investment Company Reporting Modernization, and Miscellaneous Updates. This ASU amends various SEC sections within the FASB Codification to align with the updated requirements of certain SEC final rules and includes miscellaneous updates to agree the language in the Codification to the electronic Code of Federal Regulations. ASU No. 2019-07 is effective upon issuance, and the Company has adopted the changes with no material impacts.


2.	PROPERTY AND EQUIPMENT

The major categories of property and equipment and related accumulated depletion, depreciation, amortization ("DD&A") and impairment as of ~~September 30, 2019~~March 31, 2020 and December 31, ~~2018~~2019 are as follows:

~~Table of Contents~~


	September 30, 2019			December 31, 2018
	(In thousands)						March 31, 2020			December 31, 2019
	As Restated						(In thousands)
Oil and natural gas properties	$	10,551,713		$	10,026,836		$	10,667,532		$	10,595,735
Accumulated DD&A and impairment							(7,820,662		)	(7,191,957		)
Oil and natural gas properties, net							2,846,870			3,403,778
Other depreciable property and equipment	90,712			87,146			91,361			91,198
Land	5,521			5,521			5,521			5,521
Total property and equipment	10,647,946			10,119,503
Accumulated depletion, depreciation, amortization and impairment	(5,616,988		)	(4,640,098		)
Accumulated DD&A							(39,211		)	(36,703		)
Other property and equipment, net							57,671			60,016
Property and equipment, net	$	5,030,958		$	5,479,405		$	2,904,541		$	3,463,794

Under the full cost method of accounting, the Company is required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the Company's oil and natural gas properties. At ~~September 30, 2019,~~March 31, 2020, the net book value of the Company's oil and gas properties, less related deferred income taxes, was above the calculated ceiling as a result of reduced commodity prices for the period leading up to ~~September 30, 2019.~~March 31, 2020. As a result, the Company was required to record an impairment of its oil and natural gas properties ~~under the full cost method of accounting~~ in the amount of ~~$571.4~~$553.3 million ~~(as restated)~~ for the three ~~and nine~~ months ended ~~September 30, 2019.~~March 31, 2020. NaN impairment was required for oil and natural gas properties for the three ~~and~~months ended March 31, 2019.

Based on prices for the last nine months ~~ended September 30, 2018. Additional~~and the short-term pricing outlook for the second quarter of 2020, the Company expects to recognize additional full cost impairments in the second quarter of ~~oil and natural gas properties are expected to occur in upcoming quarters should commodity prices continue below the average of the previous 12 months. However, the~~2020. The amount of any future impairments is difficult to predict as it depends on changes in commodity prices, production rates, proved reserves, evaluation of costs excluded from amortization, future development costs and production costs.

~~Included in oil and natural gas properties at September 30, 2019 is the cumulative capitalization of $229.6 million in general and administrative costs incurred and capitalized~~ Any future full cost impairments are not expected to have any impact to the ~~full cost pool.~~ Company's future cash flows or liquidity.

General and administrative costs capitalized to the full cost pool represent management’s estimate of costs incurred directly related to exploration and development activities such as geological and other ~~administrative~~ costs associated with overseeing the exploration and development activities. All general and administrative costs not directly associated with exploration and development activities were charged to expense as they were incurred. Capitalized general and administrative costs were approximately ~~$9.8~~$5.4 million and ~~$26.3 million~~ ~~for the three and nine months ended September 30, 2019, respectively, and $10.6 million and $28.8~~$7.7 million for the three ~~and nine~~ months ended ~~September 30, 2018,~~March 31, 2020 and 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 ~~$1.05 (as restated)~~$0.79 and ~~$0.94~~$1.02 per Mcfe for the ~~nine~~three months ended ~~September 30,~~March 31, 2020 and 2019, ~~and 2018,~~ respectively.

The following table summarizes the Company’s ~~unproved~~unevaluated properties excluded from amortization by area at ~~September 30, 2019:~~March 31, 2020:


	September 30, 2019
	(In thousands)		March 31, 2020
	As Restated		(In thousands)
Utica	$	1,112,148	$	908,481
MidContinent	1,148,271		697,909
Other	340		2,250
	$	2,260,759	$	1,608,640

At December 31, ~~2018,~~2019, approximately ~~$2.9~~$1.7 billion of ~~non-producing leasehold costs was~~unevaluated properties were not subject to amortization.

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The Company evaluates the costs excluded from its amortization calculation at least annually. ~~Subject~~Individually insignificant unevaluated properties are grouped for evaluation and periodically transferred to industry conditions and the level of the Company’s activities, the inclusion of most of the above referenced costs into the Company’s amortization calculation typically occurs within three to five years. However, the majority of the Company’s non-producing leases in the Utica Shale have five-year extension terms which could extend this time frame beyond five years.

~~Table of Contents~~

~~Divestitures~~

~~In December of 2018, the Company entered into an agreement to sell its non-core assets located in the West Cote Blanche Bay ("WCBB") and Hackberry fields of Louisiana to an undisclosed third party for~~evaluated properties over a ~~purchase price of approximately $19.7 million. The sale closed on July 3, 2019, subject to customary post-closing terms and conditions,~~timeframe consistent with an effective date of August 15, 2018. The Company received approximately $9.2 million in cash and retained contingent overriding royalty interests. In addition, the Company could also receive contingent payments based on commodity prices exceeding specified thresholds over the two years following the closing date. See Note 9 for further discussion of the contingent consideration arrangement, which was determined to be an embedded derivative. The buyer assumed all plugging and abandonment liabilities associated with these assets which totaled approximately $30.0 million at the divestiture date.their expected development schedule.

Asset Retirement Obligation

A reconciliation of the Company’s asset retirement obligation for the ~~nine~~three months ended ~~September 30,~~March 31, 2020 and 2019 ~~and 2018~~ is as follows:


	September 30, 2019			September 30, 2018			March 31, 2020			March 31, 2019
	(In thousands)						(In thousands)
Asset retirement obligation, beginning of period	$	79,952		$	75,100		$	60,355		$	79,952
Liabilities incurred	5,769			1,468			381			969
Liabilities settled	(117		)	(719		)	—			(71		)
Liabilities removed due to divestitures	(30,035		)	—			(2,033		)	—
Accretion expense	3,173			3,056			741			1,067
Revisions in estimated cash flows	1,077			(374		)	—			983
Asset retirement obligation as of end of period	59,819			78,531			59,444			82,900
Less current portion	—			120
Asset retirement obligation, long-term	$	59,819		$	78,411


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 ~~September 30, 2019~~March 31, 2020 and December 31, ~~2018:~~2019:

Carrying value Loss (income) from equity method investments
Approximate ownership % September 30, 2019 December 31, 2018 Three months ended September 30, Nine months ended September 30,
2019 2018 2019 2018
(In thousands)
Investment in Tatex Thailand II, LLC 23.5 % $ —
$ —
$ —
$ (137 ) $ (2,085 ) $ (241 )
Investment in Grizzly Oil Sands ULC 24.9999 % 49,546
44,259
41
275
380
833
Investment in Timber Wolf Terminals LLC⁽¹⁾
— % —
—
—
—
—
536
Investment in Windsor Midstream LLC 22.5 % 39
39
—
—
—
(9 )
Investment in Mammoth Energy Services, Inc. 21.8 % 24,377
191,823
43,041
(12,996 ) 166,096
(35,708 )
Investment in Strike Force Midstream LLC⁽²⁾
— % —
—
—
—
—
(693 )
$ 73,962

$ 236,121

$ 43,082
$ (12,858 ) $ 164,391
$ (35,282 )



~~(1)~~	~~On June 5, 2018, the Company received its final distribution from Timber Wolf Terminals LLC ("Timber Wolf"). See below under~~ ~~Timber Wolf Terminals LLC~~ ~~for information regarding the subsequent dissolution of Timber Wolf.~~
~~(2)~~	~~On May 1, 2018, the Company sold its 25% interest in Strike Force Midstream LLC ("Strike Force") to EQT Midstream Partners, LP. See below under~~ ~~Strike Force Midstream LLC~~ ~~for information regarding this transaction.~~



			Carrying value				(Loss) income from equity method investments
	Approximate ownership %		March 31, 2020		December 31, 2019		Three months ended March 31,
	Approximate ownership %		March 31, 2020		December 31, 2019		2020			2019
			(In thousands)
Investment in Grizzly Oil Sands ULC	24.9	%	$	6,186	$	21,000	$	(143	)	$	(393	)
Investment in Mammoth Energy Services, Inc.	21.5	%	—		11,005		(10,646		)	4,526
Investment in Windsor Midstream LLC	22.5	%	39		39		—			—
Investment in Tatex Thailand II, LLC	23.5	%	—		—		—			140
			$	6,225	$	32,044	$	(10,789	)	$	4,273

The tables below summarize financial information for the Company’s equity investments as of ~~September 30, 2019~~March 31, 2020 and December 31, ~~2018.~~2019.

138

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Summarized balance sheet information:


	September 30, 2019		December 31, 2018		March 31, 2020		December 31, 2019
	September 30, 2019		December 31, 2018		March 31, 2020		December 31, 2019
	(In thousands)				(In thousands)
Current assets	$	427,643	$	471,733	$	440,801	$	421,326
Noncurrent assets	$	1,309,729	$	1,302,488	$	1,104,297	$	1,260,075
Current liabilities	$	130,465	$	239,975	$	131,175	$	132,569
Noncurrent liabilities	$	176,145	$	94,575	$	171,132	$	163,241

Summarized results of operations:


	Three months ended September 30,					Nine months ended September 30,					Three months ended March 31,
	2019			2018		2019			2018		2020			2019
	(In thousands)										(In thousands)
Gross revenue	$	113,417		$	384,043	$	557,375		$	1,451,580	$	97,383		$	264,844
Net (loss) income	$	(35,730	)	$	68,414	$	(15,046	)	$	181,884	$	(85,031	)	$	24,756

Grizzly Oil Sands ULC

The Company, through its wholly owned subsidiary Grizzly Holdings Inc. (“Grizzly Holdings”), owns an approximate 24.9% 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 March 31, 2020, 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 March 31, 2020 and 2019 and determined 0 impairment was required. The Company paid $0.4 million in cash calls during the three months ended March 31, 2019 prior to its election to cease funding further capital calls. Grizzly’s functional currency is the Canadian dollar. The Company’s investment in Grizzly was decreased by a $14.7 million foreign currency translation loss and increased by a $3.7 million foreign currency translation gain for the three months ended March 31, 2020 and 2019, respectively.

Mammoth Energy Services, Inc.

At March 31, 2020, the Company owned 9,829,548 shares, or approximately 21.5%, of the outstanding common stock of Mammoth Energy Services, Inc. ("Mammoth Energy"). The Company’s investment in Mammoth Energy was decreased by a $0.4 million foreign currency loss and increased by a $0.1 million foreign currency gain resulting from Mammoth Energy's foreign subsidiary for the three months ended March 31, 2020 and 2019, respectively. The Company received 0 distributions from Mammoth Energy during the three months ended March 31, 2020 and distributions of $1.2 million during the three months ended March 31, 2019 as a result of $0.125 per share dividends in February 2019. The approximate fair value of the Company's investment in Mammoth Energy at March 31, 2020 was $7.4 million based on the quoted market price of Mammoth Energy's common stock. The Company's share of net loss of Mammoth for three months ended March 31, 2020 was in excess of the carrying value of its investment. As such, the Company's investment value was reduced to 0 at March 31, 2020. The loss (income) from equity method investments presented in the table above reflects any intercompany profit eliminations.

Windsor Midstream LLC

At March 31, 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 three months ended March 31, 2020.

Tatex Thailand II, LLC

The Company has an indirect ownership interest in Tatex Thailand II, LLC ("Tatex") and received 0 distributions and $0.1 million in distributions from Tatex ~~II").~~during the three months ended March 31, 2020 and 2019, respectively. Tatex IIpreviously 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. ~~The Company received $2.1 million in distributions from Tatex II during the nine months ended September 30, 2019, of which $1.9 million related to proceeds from the sale of its interest in APICO.~~

~~Grizzly Oil Sands ULC~~

The Company, through its wholly owned subsidiary Grizzly Holdings Inc. (“Grizzly Holdings”), owns an approximate 24.9999% interest in Grizzly Oil Sands ULC (“Grizzly”), a Canadian unlimited liability company. The remaining interest in Grizzly is owned by Grizzly Oil Sands Inc. (“Oil Sands”). As of September 30, 2019, 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 September 30, 2019 and 2018 and determined 0 impairment was required. If commodity prices decline in the future however, impairment of the Company's investment in Grizzly may be necessary. During the nine months ended September 30, 2019, Gulfport paid $0.4 million in cash calls. Grizzly’s functional currency is the Canadian dollar. The Company’s investment in Grizzly was decreased by a $2.0 million foreign currency translation loss and increased by a $5.2 million foreign currency translation gain for the three and nine months ended September 30, 2019, respectively. The Company's investment in Grizzly was increased by a $2.9 million foreign currency translation gain and decreased by a $5.7 million foreign currency translation loss for the three and nine months ended September 30, 2018, respectively.

~~Timber Wolf Terminals LLC~~

~~During 2012, the Company invested in Timber Wolf. Timber Wolf was formed to operate a crude/condensate terminal and a sand transloading facility in Ohio. Timber Wolf was dissolved in 2018.~~

~~Windsor Midstream LLC~~

At September 30, 2019, 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 nine months ended September 30, 2019.

The Company has determined that Midstream is a variable interest entity ("VIE") but that the Company is not the primary beneficiary because it does not have a controlling financial interest in Midstream. This entity is considered a VIE because the limited partners lack substantive kick-out or participating rights over the general partner. The general partner has power to direct the activities that most significantly impact Midstream's economic performance. The Company accounts for its investment in

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VIEs following the equity method of accounting. The carrying amounts of the Company’s equity investments are classified as other non-current assets on the accompanying consolidated balance sheets. The Company’s maximum exposure to loss as a result of its involvement with VIEs is based on the Company’s capital contributions and the economic performance of the VIEs, and is equal to the carrying value of the Company’s investments which is the maximum loss the Company could be required to record in the consolidated statements of operations.

~~Mammoth Energy Services, Inc.~~

At September 30, 2019, the Company owned 9,829,548 shares, or approximately 21.8%, of the outstanding common stock of Mammoth Energy Services, Inc. ("Mammoth Energy"). The Company reviewed its investment in Mammoth Energy as of September 30, 2019 for impairment based on certain qualitative and quantitative factors. As a result of the calculated fair values and other qualitative factors, the Company concluded that an other than temporary impairment was indicated. This resulted in recording an impairment loss of $35.5 million and $160.8 million for the three and nine months ended September 30, 2019, which is included in loss (income) from equity method investments, net in the accompanying consolidated statements of operations. If Mammoth Energy's common stock continues to trade below the Company's carrying value for a prolonged period of time, further impairment of the Company's investment in Mammoth Energy may be necessary. The Company’s investment in Mammoth Energy was decreased by a $0.1 million foreign currency loss and increased by a $0.1 million foreign currency gain resulting from Mammoth Energy's foreign subsidiary for the three and nine months ended September 30, 2019, respectively. The Company’s investment in Mammoth Energy was increased by a $0.1 million foreign currency gain and decreased by a $0.2 million foreign currency loss resulting from Mammoth Energy’s foreign subsidiary for the three and nine months ended September 30, 2018, respectively. During the nine months ended September 30, 2019, Gulfport received distributions of $2.5 million from Mammoth Energy as a result of $0.125 per share dividends in February 2019 and May 2019. The approximate fair value of the Company's investment in Mammoth Energy's common stock at September 30, 2019 was $24.4 million based on the quoted market price of Mammoth Energy's common stock. The loss (income) from equity method investments presented in the table above reflects any intercompany profit eliminations.

~~Strike Force Midstream LLC~~

In February 2016, the Company, through its wholly owned subsidiary Gulfport Midstream Holdings, LLC (“Midstream Holdings”), entered into an agreement with Rice Midstream Holdings LLC (“Rice”), then a subsidiary of Rice Energy Inc., to develop natural gas gathering assets in eastern Belmont County and Monroe County, Ohio through Strike Force. In 2017, Rice was acquired by EQT Corporation ("EQT"). The Company owned a 25% interest in Strike Force, which was sold to EQT Midstream Partners, LP in May 2018. The loss (income) from equity method investments presented in the table above reflects any intercompany profit eliminations.


4.5.	LONG-TERM DEBT

Long-term debt consisted of the following items as of ~~September 30, 2019~~March 31, 2020 and December 31, ~~2018:~~2019:


	September 30, 2019			December 31, 2018			March 31, 2020			December 31, 2019
	(In thousands)						(In thousands)
Revolving credit agreement⁽¹⁾	$	135,000		$	45,000		$	65,000		$	120,000
6.625% senior unsecured notes due 2023	340,000			350,000			329,467			329,467
6.000% senior unsecured notes due 2024	630,796			650,000			595,903			603,428
6.375% senior unsecured notes due 2025	577,268			600,000			521,360			529,525
6.375% senior unsecured notes due 2026	397,529			450,000			387,367			397,529
Net unamortized debt issuance costs⁽²⁾	(26,052		)	(30,733		)	(22,395		)	(23,751		)
Construction loan	22,650			23,149			22,348			22,453
Less: current maturities of long term debt	(622		)	(651		)	(688		)	(631		)
Debt reflected as long term	$	2,076,569		$	2,086,765		$	1,898,362		$	1,978,020

(1) The Company has entered into a senior secured revolving credit facility, as amended (the "revolving credit facility"), with The Bank of Nova Scotia, as the lead arranger and administrative agent and other lenders. The credit agreement provides for a maximum facility of $1.5 billion and matures on December 13, 2021. On ~~June 3,~~November 25, 2019, the ~~Company further amended its~~borrowing base under the Company's revolving credit facility was reduced to ~~among other things, allow the Company to designate certain of its subsidiaries~~

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~~as unrestricted subsidiaries and to include LIBOR replacement provisions. Additionally, the borrowing base was reaffirmed at $1.4~~$1.2 billion, and the ~~Company’s~~Company's elected commitment ~~amount~~ remained at $1.0 billion.

As of ~~September 30, 2019, $135.0~~March 31, 2020, $65.0 million was outstanding under the revolving credit facility and the total availability for future borrowings under this facility, after giving effect to an aggregate of ~~$248.6~~$236.8 million letters of credit, was ~~$616.4~~$698.2 million. The Company’s wholly owned subsidiaries have guaranteed the obligations of the Company under the revolving credit facility.

At ~~September 30, 2019,~~March 31, 2020, amounts borrowed under the revolving credit facility bore interest at a weighted average rate of ~~3.52%~~2.45%.

The Company was in compliance with its financial covenants under the revolving credit facility at ~~September 30, 2019.~~March 31, 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 ~~September 30, 2019,~~March 31, 2020, total unamortized debt issuance costs were ~~$3.6~~$3.1 million for the 2023 Notes, ~~$7.5~~$6.5 million for the 2024 Notes, ~~$10.8~~$9.1 million for the 2025 Notes and ~~$4.0~~$3.6 million for the 2026 Notes. In addition, loan commitment fee costs for the Company's construction loan agreement were $0.1 million at ~~September 30, 2019.~~March 31, 2020.

The Company capitalized approximately ~~$1.0~~$0.2 million and ~~$2.8~~$0.8 million in interest expense to ~~undeveloped~~its unevaluated oil and natural gas properties during the three ~~and nine~~ months ended ~~September 30,~~March 31, 2020 and 2019, respectively. The Company capitalized approximately $1.6 million and $4.0 million in interest expense to undeveloped oil and natural gas properties during the three and nine months ended September 30, 2018, respectively.

Debt Repurchases

The Company's Board of Directors has authorized $200 million of cash to be used to repurchase its senior notes in the open market at discounted values to par. During the three months ended ~~September 30, 2019,~~March 31, 2020, the Company used borrowings under its revolving credit facility to repurchase in the open market approximately ~~$104.4~~$25.9 million aggregate principal amount of its outstanding Notes for ~~$80.3~~$10.2 million. This included approximately ~~$10.0 million principal amount of the 2023 Notes, $19.2~~$7.5 million principal amount of the 2024 Notes, ~~$22.7~~$8.2 million principal amount of the 2025 Notes, and ~~$52.5~~$10.2 million principal amount of the 2026 Notes. The Company recognized a ~~$23.6~~$15.3 million gain on debt extinguishment, which included retirement of unamortized issuance costs and fees associated with the repurchased debt. This gain is included in gain on debt extinguishment in the accompanying consolidated statements of operations.

Fair Value of Debt

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At March 31, 2020, 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 $447.4 million at March 31, 2020.


5.6.	~~COMMON STOCK AND~~ CHANGES IN CAPITALIZATION

Stock ~~Repurchase Program~~

In January 2018, the board of directors of the Company approved a stock repurchase program to acquire up to $100 million of the Company's outstanding stock during 2018. In May 2018, the Company's board of directors authorized the expansion of its stock repurchase program, authorizing the Company to acquire up to an additional $100 million of its outstanding common stock during 2018 for a total of up to $200 million. The repurchase program did not require the Company to acquire any specific number of shares. This repurchase program was authorized to extend through December 31, 2018 and the Company repurchased 20.7 million shares of common stock in 2018 for $200.0 million in aggregate consideration.Repurchases

In January 2019, the ~~board~~Company's Board of ~~directors of the Company~~Directors approved a ~~new~~ stock repurchase program to acquire a portion of the Company's outstanding common stock within a ~~24 month~~24-month period. ~~Purchases under~~The program was suspended in the ~~repurchase program may be made from time~~fourth quarter of 2019, and the May 1, 2020 amendment to time in open market or privately negotiated transactions, and are subject to market conditions, applicable legal requirements, contractual obligations and other factors. The repurchase program does not require the Company to acquire any specific number of shares. This repurchase program is authorized to extend through December 31, 2020 and may be suspended, modified, extended or discontinued by the board of directors at any time. The Company did not repurchase any shares under the program duringCompany's revolving credit facility prohibits further repurchases.

For the three months ended ~~September 30,~~March 31, 2019, ~~and~~the Company repurchased ~~approximately 3.8~~3.6 million shares for a cost of approximately ~~$30.0~~$28.2 million under this repurchase program. Additionally, during the ~~nine~~three months ended ~~September 30, 2019. Additionally, during each of the three~~March 31, 2020 and ~~nine months ended September 30,~~ 2019, the Company repurchased ~~approximately 0.1 million~~80,000 and 15,000 shares, respectively, for a cost of approximately $0.1 million ~~and $0.7 million, respectively,~~in each period 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.


6.7.	STOCK-BASED COMPENSATION

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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 nine~~ months ended ~~September 30,~~March 31, 2020 and 2019, the Company’s stock-based compensation cost was ~~$2.7~~$2.1 million and ~~$8.3~~$2.8 million, respectively, of which the Company capitalized ~~$1.1~~$0.9 million and $3.3 million, respectively, relating to its exploration and development efforts. During the three and nine months ended September 30, 2018, the Company's stock-based compensation cost was $3.6 million and $9.7 million, respectively, of which the Company capitalized $1.4 million and $3.9$1.1 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 ~~nine~~three months ended ~~September 30, 2019:~~March 31, 2020:


	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		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, 2019	1,535,811		$	11.57	$	—		$	—
Unvested shares as of January 1, 2020										4,098,318		$	4.73	1,783,660		$	2.96
Granted	4,011,073		3.74		2,009,144			2.85		1,985,452		0.67		—		—
Vested	(674,374	)	12.86		—			—		(211,090	)	8.65		—		—
Forfeited	(289,610	)	7.83		(112,742		)	1.98		(344,112	)	5.00		(225,484	)	1.98
Unvested shares as of September 30, 2019	4,582,900		$	4.76	1,896,402			$	2.91
Unvested shares as of March 31, 2020										5,528,568		$	3.17	1,558,176		$	3.11

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 ~~September 30, 2019~~March 31, 2020 related to restricted stock units was ~~$19.0 million.~~$12.9 million. The expense is expected to be recognized over a weighted average period of ~~2.28~~1.96 years.

Performance Vesting Restricted Stock Units

~~During the nine months ended September 30, 2019, the~~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. The grant date fair value was determined using the Monte Carlo simulation method and is being recorded ratably over the performance period. Expected volatilities utilized in the Monte Carlo model were estimated using a historical period consistent with the remaining performance period of approximately two years. The risk-free interest rates were based on the U.S. Treasury rate for a term commensurate with the expected life of the grant. The Company assumed a range of risk-free interest rates of 1.56% to 2.42% and a range of expected volatilities of 29.1% to 85.1% to estimate the fair value of performance vesting units granted during the nine months ended September 30, 2019. Unrecognized compensation expense as of ~~September 30, 2019~~March 31, 2020 related to performance vesting restricted shares was ~~$4.9~~$3.4 million. The expense is expected to be recognized over a weighted average period of 2.11 years.

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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 three months ended March 31, 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 March 31, 2020 was $3.2 million, which also approximated the grant date fair value. Unrecognized compensation expense as of March 31, 2020 related to Incentive Awards was $3.1 million. The expense is expected to be recognized over a weighted average period of ~~2.64~~1.77 years.

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7.8.	EARNINGS PER SHARE

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


	Three months ended September 30,												Three months ended March 31,
	2019							2018					2020							2019
	Loss			Shares	Per Share			Income		Shares	Per Share		Loss			Shares	Per Share			Income		Shares	Per Share
	(In thousands, except share data)												(In thousands, except share data)
Basic:
Net (loss) income (as restated)	$	(484,802	)	159,548,477	$	(3.04	)	$	95,150	173,057,538	$	0.55
Net (loss) income													$	(517,538	)	159,760,222	$	(3.24	)	$	62,242	162,823,997	$	0.38
Effect of dilutive securities:
Stock options and awards	—			—				—		247,376
Stock awards													—			—				—		275,412
Diluted:
Net (loss) income (as restated)	$	(484,802	)	159,548,477	$	(3.04	)	$	95,150	173,304,914	$	0.55
Net (loss) income													$	(517,538	)	159,760,222	$	(3.24	)	$	62,242	163,099,409	$	0.38

Nine months ended September 30,
2019 2018
Income Shares Per
Share Income Shares Per
Share
(In thousands, except share data)
Basic:
Net (loss)income (as restated) $ (187,604 ) 160,553,796
$ (1.17 ) $ 296,559
175,776,312
$ 1.69
Effect of dilutive securities:

Stock options and awards (as restated) —
—

—
664,149

Diluted:

Net (loss) income (as restated) $ (187,604 ) 160,553,796
$ (1.17 ) $ 296,559
176,440,461
$ 1.68

There were ~~2,073,638 and 4,266,206 (as restated)~~1,552,423 shares of common stock that were considered anti-dilutive for the three ~~and nine~~ months ended ~~September 30, 2019, respectively.~~March 31, 2020. There were 0 potential shares of common stock that were considered anti-dilutive for the three ~~and nine~~ months ended ~~September 30, 2018.~~March 31, 2019.

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8.9.	COMMITMENTS AND CONTINGENCIES

Future Firm ~~Transportation and~~ Sales Commitments

The ~~table below presents the~~Company has entered into various firm sales contracts to deliver and sell natural gas. The Company expects to fulfill its delivery commitments ~~by year:~~primarily with production from proved developed reserves. The Company's proved reserves have generally been sufficient to satisfy its delivery commitments during the three most recent years, and it expects such reserves will continue to be the primary means of fulfilling its future commitments. However, where the Company's proved reserves are not sufficient to satisfy its delivery commitments, it can and may use spot market purchases to satisfy the commitments.

A summary of these commitments at March 31, 2020 are set forth in the table below:


	(MMBtu per day)	(MMBtu per day)
Remaining 2019	424,000
2020	314,000
Remaining 2020		316,000
2021	192,000	192,000
2022	70,000	70,000
2023	17,000	17,000
Thereafter	—
Total	1,017,000	595,000

Future Firm Transportation Commitments

The ~~table below presents~~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 recorded as obligations in the accompanying consolidated balance sheets; however, the costs associated with these commitments ~~by year:~~are reflected in the Company's estimates of proved reserves and future net revenues.

A summary of these commitments at March 31, 2020 are set forth in the table below:


	(In thousands)		Total MMBtu	(In thousands)
Remaining 2019	$	65,763
2020	287,627
Remaining 2020			395,625,000	$	206,292
2021	286,665		531,075,000	285,789
2022	286,665		531,075,000	286,626
2023	282,981		515,867,000	282,945
2024			489,525,000	265,568
Thereafter	2,410,866		3,769,092,000	2,160,732
Total	$	3,620,567	6,232,259,000	$	3,487,952

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 has 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 ~~$0.02~~$1.9 million and ~~$0.4~~$0.3 million in non-utilization fees under this agreement during the three ~~and nine~~ months ended ~~September 30,~~March 31, 2020 and 2019, respectively. ~~The Company incurred $1.3 million and $1.5 million in non-utilization fees under this agreement during the three and nine months ended September 30, 2018.~~

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Future minimum commitments under this agreement at ~~September 30, 2019~~March 31, 2020 are:


	(In thousands)		(In thousands)
Remaining 2019	$	6,000
2020	24,000
Remaining 2020			$	5,625
2021	24,000		7,500
Total	$	54,000	$	13,125

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

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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 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 the Company’s legacy Louisiana properties, filed an action against the Company and ~~a number of~~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, Saydee Resources, LLC, on behalf of itself and a class of similarly situated royalty holders, filed an action against the Company in the District Court of Grady County Oklahoma. The suit alleges that the Company underpaid royalty holders and seeks unspecified damages for breach of contract, tortious breach of contract, fraud and unjust enrichment.

~~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.

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.

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As previously disclosed, 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 the complaint calculates to be approximately $6.7 million as of February 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 the Company in the United States District Court for the Southern District of Ohio Eastern Division. The complaint alleges that the Company violated the Fair Labor Standards Act (“FLSA”), the Ohio Wage Act and the Ohio Prompt Pay Act by classifying the plaintiffs as independent contractors and paying them a daily rate with no overtime compensation for hours worked in excess of 40 hours per week. The complaint seeks to recover unpaid regular and overtime wages, liquidated damages in an amount equal to 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.

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

The Company filed an action against TH Exploration, LLC ("TH") in Tarrant County, Texas. The suit alleges breach of purchase and sale agreement providing for the Company's disposition of certain oil and gas properties in Ohio to TH. The Company is seeking specific performance, related to TH's obligations to close the transaction and tender the purchase price, along with any additional relief available to the Company.

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 management and the Company of the Sarbanes-Oxley Act of 2002 in connection with such actions. The Company has fully cooperated and intends to continue to cooperate fully with the SEC’s investigation. Although it is not possible to predict the ultimate resolution or financial liability

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with respect to this matter, the Company believes that the outcome of this matter will not have a material effect on the Company’s business, financial condition or results of operations.

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 have implemented various policies, programs, procedures, training and audits to reduce and mitigate ~~such~~ 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 1217 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 ~~may result~~resulted in monetary sanctions of ~~more than $100,000.~~ approximately $1.7 million.

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.


9.10.	DERIVATIVE INSTRUMENTS

Natural Gas, Oil and Natural Gas Liquids Derivative Instruments

The Company seeks to reduce its exposure to unfavorable changes in natural gas, oil and natural gas liquids ("~~NGLs"~~NGL") prices, which are subject to significant and often volatile fluctuation, by entering into over-the-counter fixed price swaps, basis swaps and various types of option contracts. These contracts allow the Company to predict with greater certainty the effective natural gas, oil and ~~NGLs~~NGL prices to be received for hedged production and benefit operating cash flows and earnings when market prices are less than the fixed prices provided in the contracts. However, the Company will not benefit from market prices that are higher than the fixed prices in the contracts for hedged production.

Fixed price swaps are settled monthly based on differences between the fixed price specified in the contract and the referenced settlement price. When the referenced settlement price is less than the price specified in the contract, the Company receives an amount from the counterparty based on the price difference multiplied by the volume. Similarly, when the referenced settlement price exceeds the price specified in the contract, the Company pays the counterparty an amount based on the price difference multiplied by the volume. The prices contained in these fixed price swaps are based on the NYMEX Henry Hub for natural gas, the NYMEX 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 ~~September 30, 2019.~~March 31, 2020.

Location Daily Volume (MMBtu/day) Weighted
Average Price
Remaining 2019 NYMEX Henry Hub 1,380,000
$ 2.81
2020 NYMEX Henry Hub 519,000
$ 2.88



	Location	Daily Volume (MMBtu/day)	Weighted Average Price
Remaining 2020	NYMEX Henry Hub	432,000	$	2.92

Location Daily Volume
(Bbls/day) Weighted
Average Price
Remaining 2019 NYMEX WTI 6,000
$ 60.81
2020 NYMEX WTI 6,000
$ 59.82



	Location	Daily Volume (Bbls/day)	Weighted Average Price
Remaining 2020	NYMEX WTI	6,000	$	59.83

Location Daily Volume
(Bbls/day) Weighted
Average Price
Remaining 2019 Mont Belvieu C2 1,000
$ 18.48
Remaining 2019 Mont Belvieu C3 4,000
$ 29.02
Remaining 2019 Mont Belvieu C5 1,000
$ 53.71



	Location	Daily Volume (Bbls/day)	Weighted Average Price
Remaining 2020	Mont Belvieu C3	500	$	21.63

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


	Location	Daily Volume (MMBtu/day)	Weighted Average Price		Location	Daily Volume (MMBtu/day)	Weighted Average Price
Remaining 2019	NYMEX Henry Hub	30,000	$	3.10
2022	NYMEX Henry Hub	628,000	$	2.90	NYMEX Henry Hub	628,000	$	2.90
2023	NYMEX Henry Hub	628,000	$	2.90	NYMEX Henry Hub	628,000	$	2.90

For a portion of the natural gas fixed price swaps listed above, the counterparty had the option to extend the original terms for an additional twelve months for the period of January 2019 through December 2019. In December 2018, the counterparties chose to exercise all natural gas fixed price swaps, resulting in an additional 100,000 MMBtu per day at a weighted average price of $3.05 per MMBtu, which is included in the natural gas fixed price swaps listed above.

In addition, the Company entered into natural gas basis swap positions. As of ~~September 30, 2019,~~March 31, 2020, the Company had the following natural gas basis swap positions open:

Gulfport Pays Gulfport Receives Daily Volume (MMBtu/day) Weighted Average Fixed Spread
Remaining 2019 Transco Zone 4 NYMEX Plus Fixed Spread 60,000
$ (0.05 )
2020 Transco Zone 4 NYMEX Plus Fixed Spread 60,000
$ (0.05 )
2020 Fixed Spread ONEOK Minus NYMEX 10,000
$ (0.54 )



	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	)

Contingent Consideration Arrangement

The ~~purchase and sale agreement for the sale of the Company's~~Company sold its non-core assets located in the ~~WCBB~~West Cote Blanche Bay and Hackberry fields of Louisiana in July 2019. The sale price included ~~a contingent consideration arrangement that entitles~~the potential for the Company to receive ~~bonus~~contingent payments ifbased on commodity prices ~~exceed~~exceeding specified ~~thresholds. The calculated fair value of this~~thresholds over the two years following the closing date. This contingent ~~payment~~consideration arrangement was ~~approximately $1.1 million as of the closing date of the divestiture.~~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.

Balance Sheet Presentation

The Company reports the fair value of derivative instruments on the consolidated balance sheets as derivative instruments under current assets, noncurrent assets, current liabilities and noncurrent liabilities on a gross basis. The Company determines the current and noncurrent classification based on the timing of expected future cash flows of individual trades. The following table presents the fair value of the Company’s derivative instruments on a gross basis at ~~September 30, 2019~~March 31, 2020 and December 31, ~~2018:~~2019:


	September 30, 2019		December 31, 2018		March 31, 2020		December 31, 2019
	(In thousands)				(In thousands)
Commodity derivative instruments	$	134,511	$	21,352	$	171,755	$	125,383
Contingent consideration arrangement	60		—		—		818
Total short-term derivative instruments - asset	$	134,571	$	21,352	$	171,755	$	126,201

Commodity derivative instruments	$	23,375	$	—
Contingent consideration arrangement	44		—		—		563
Total long-term derivative instruments - asset	$	23,419	$	—	$	—	$	563

Total short-term derivative instruments - liability	$	429	$	20,401	$	67	$	303

Total long-term derivative instruments - liability	$	72,040	$	13,992	$	70,829	$	53,135
Total net asset derivative position					$	100,859	$	73,326

Gains and Losses

The following table presents the gain and loss recognized in net gain (loss) on natural gas, oil and ~~NGLs~~NGL derivatives in the accompanying consolidated statements of operations for the three ~~and nine~~ months ended ~~September 30, 2019~~March 31, 2020 and ~~2018.~~2019.


	Net gain (loss) on derivative instruments												Net gain (loss) on derivative instruments
	Three months ended September 30,						Nine months ended September 30,
��													Three months ended March 31,
	2019			2018			2019			2018			2020			2019
	(In thousands)												(In thousands)
Natural gas derivatives	$	11,731		$	14,101		$	147,774		$	(26,789	)	$	45,853		$	(16,431	)
Oil derivatives	12,736			(11,610		)	24,153			(45,176		)	52,874			(454		)
NGLs derivatives	3,641			(12,154		)	7,276			(24,772		)
NGL derivatives													920			(3,160		)
Contingent consideration arrangement	(1,034		)	—			(1,034		)	—			(1,381		)	—
Total	$	27,074		$	(9,663	)	$	178,169		$	(96,737	)	$	98,266		$	(20,045	)

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 September 30, 2019
Gross Assets (Liabilities) Gross Amounts
Presented in the Subject to Master Net
Consolidated Balance Sheets Netting Agreements Amount
(In thousands)
Derivative assets $ 157,990
$ (72,469 ) $ 85,521
Derivative liabilities $ (72,469 ) $ 72,469
$ —



	As of March 31, 2020
	Gross Assets (Liabilities)			Gross Amounts
	Presented in the			Subject to Master			Net
	Consolidated Balance Sheets			Netting Agreements			Amount
	(In thousands)
Derivative assets	$	171,755		$	(70,896	)	$	100,859
Derivative liabilities	$	(70,896	)	$	70,896		$	—


	As of December 31, 2018									As of December 31, 2019
	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	$	21,352		$	(19,289	)	$	2,063		$	126,764		$	(53,438	)	$	73,326
Derivative liabilities	$	(34,393	)	$	19,289		$	(15,104	)	$	(53,438	)	$	53,438		$	—

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.


~~10.~~11.	FAIR VALUE MEASUREMENTS

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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.

The following tables summarize the Company’s financial and non-financial assets and liabilities by valuation level as of ~~September 30, 2019~~March 31, 2020 and December 31, ~~2018:~~2019:

September 30, 2019
Level 1 Level 2 Level 3
(In thousands)
Assets:
Derivative Instruments $ —
$ 157,990
$ —
Liabilities:
Derivative Instruments $ —
$ 72,469
$ —

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	March 31, 2020
	Level 1		Level 2		Level 3
	(In thousands)
Assets:
Derivative Instruments	$	—	$	171,755	$	—
Liabilities:
Derivative Instruments	$	—	$	70,896	$	—


	December 31, 2018						December 31, 2019
	Level 1		Level 2		Level 3		Level 1		Level 2		Level 3
	(In thousands)						(In thousands)
Assets:
Derivative Instruments	$	—	$	21,352	$	—	$	—	$	126,764	$	—
Liabilities:
Derivative Instruments	$	—	$	34,393	$	—	$	—	$	53,438	$	—

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 water infrastructure sale included a contingent consideration arrangement. As of March 31, 2020, the fair value of the contingent consideration was $23.0 million, of which $0.6 million is included in prepaid expenses and other assets and $22.4 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 based on internal estimates of the Company's ~~investment~~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, will record changes in ~~Mammoth Energy as~~fair value in earnings in that period. The Company recognized a gain of ~~September 30, 2019 was estimated using Level 1 inputs, as~~$0.2 million on changes in fair value of the ~~price per share was a quoted price~~contingent consideration during the three months ended March 31, 2020, which is included in ~~an active market for identical Mammoth Energy common shares.~~other expense (income) in the accompanying consolidated

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statements of operations. Settlements under the contingent consideration arrangement totaled $0.3 million during the three months ended March 31, 2020.

The initial measurement of asset retirement obligations at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with oil and gas properties. Given the unobservable nature of the inputs, including plugging costs and reserve lives, the initial measurement of the asset retirement obligation liability is deemed to use Level 3 inputs. See Note 2 for further discussion of the Company’s asset retirement obligations. Asset retirement obligations incurred during the ~~nine~~three months ended ~~September 30, 2019~~March 31, 2020 were approximately ~~$5.8 million.~~$0.4 million.

Fair value of financial instruments


~~11.~~	~~FAIR VALUE OF 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 loan is carried at cost, which approximates market value based on the borrowing rates currently available to the Company with similar terms and maturities.

At September 30, 2019, the carrying value of the outstanding debt represented by the Notes was approximately $1.9 billion, including the unamortized debt issuance cost of approximately $3.6 million related to the 2023 Notes, approximately $7.5 million related to the 2024 Notes, approximately $10.8 million related to the 2025 Notes and approximately $4.0 million related to the 2026 Notes. Based on the quoted market price, the fair value of the Notes was determined to be approximately $1.4 billion at September 30, 2019.


12.	REVENUE FROM CONTRACTS WITH CUSTOMERS

Revenue Recognition

The Company’s revenues are primarily derived from the sale of natural gas, oil and condensate and ~~NGLs.~~NGL. Sales of natural gas, oil and condensate and ~~NGLs~~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.

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

For product sales that have a contract term greater than one year, the Company has utilized the practical expedient that exempts the Company from disclosure of the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product generally represents a separate performance obligation; therefore, future volumes are wholly unsatisfied and disclosure 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 ~~$112.7~~$74.1

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million and ~~$210.2~~$121.2 million as of ~~September 30, 2019~~March 31, 2020 and December 31, ~~2018,~~2019, respectively, and are reported in accounts receivable - oil and natural gas sales on the consolidated balance sheets. The Company currently has no assets or liabilities related to its revenue contracts, including no upfront or rights to deficiency payments.

Prior-Period Performance Obligations

The Company records revenue in the month production is delivered to the purchaser. However, settlement statements for certain sales may be received for 30 to 90 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production that was delivered to the purchaser and the price that will be received for the sale of the product. The differences between the estimates and the actual amounts for product sales is recorded in the month that payment is received from the purchaser. For the ~~nine~~three months ended ~~September 30, 2019,~~March 31, 2020, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.


13.	LEASES

~~Effective January 1, 2019, the Company adopted ASU No. 2016-02,~~ ~~Leases (Topic 842)~~. The new standard supersedes the previous lease guidance by requiring lessees to recognize a right-of-use asset and lease liability on the balance sheet for all leases with lease terms of greater than one year while maintaining substantially similar classifications for financing and operating leases. The Company adopted the new standard on a prospective basis using the simplified transition method permitted by ASU No. 2018-11, ~~Leases (Topic 842): Targeted Improvements~~. Offsetting right-of-use assets and corresponding lease liabilities recognized by the Company on the adoption date totaled approximately $110 million, representing minimum payment obligations associated with identified leases with contractual durations exceeding one year. NaN cumulative-effect adjustment to retained earnings was required upon adoption of the new standard. The Company elected the package of practical expedients permitted under the new standard, which among other things, allows for lease and non-lease components in a contract to be accounted for as a single lease component for all asset classes and the carry forward of historical lease classifications.

Nature of Leases

The Company has operating leases associated with drilling rig commitments, ~~pressure pumping services,~~ field offices and other equipment with remaining lease terms with contractual durations in excess of one year. Short-term leases that have an initial term of one year or less are not capitalized.

The Company has entered into contracts for drilling rigs with third parties to ensure rig availability in its key operating areas. 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 one to two years and expire at various dates through ~~2021.~~2020. These agreements typically include renewal options at the end of the initial term. Due to the nature of the Company's drilling schedules and potential volatility in commodity prices, the Company is unable to determine at commencement with reasonable certainty if the renewal options will

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be exercised; therefore, renewal options are not considered in the lease term for drilling contracts. The operating lease liabilities associated with these rig commitments are based on the minimum contractual obligations, primarily standby rates, and do not include variable amounts based on actual activity in a given period. The Company has also entered into several drilling rig commitments with an initial term less than one year. The costs for these short-term rig commitments are included 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. ~~The~~As discussed further in Note 9, the Company has terminated its Master Services Agreement for pressure pumping with Stingray Pressure. As a result, in the first quarter of 2020, Gulfport has removed the related right ~~to suspend services~~ of ~~one crew~~use assets and ~~only one crew at any point in time without payment, fee or other obligation~~lease liabilities associated with the suspended crew, given appropriate notification of suspension. The Company has determined that the agreement with Stingray Pressure is an operating lease due to the implicit identification of assets and the evaluation that the Company has the right to control the identified assets. The operating lease liability associated with this agreement is based on the minimum contractual obligations, which is the monthly service fee for one crew, and does not include variable amounts based on actual activity in a given period. 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.

~~Table of Contents~~terminated contract.

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.

Maturities of operating lease liabilities as of ~~September 30, 2019~~March 31, 2020 were as follows:


	(In thousands)			(In thousands)
Remaining 2019	$	10,190
2020	31,460
Remaining 2020				$	9,920
2021	22,731			129
2022	115			115
2023	90			90
Thereafter	30
2024				30
Total lease payments	$	64,616		$	10,284
Less: Imputed interest	(2,247		)	(98		)
Total	$	62,369		$	10,186

Lease cost for the three ~~and nine~~ months ended ~~September 30,~~March 31, 2020 and 2019 consisted of the following:

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	Three months ended September 30,		Nine months ended September 30,		Three months ended March 31,
	2019		2019		2020		2019
	(In thousands)				(In thousands)
Operating lease cost	$	4,551	$	20,835	$	4,082	$	8,536
Operating lease cost - related party	5,610		16,830
Operating lease cost—related party					—		5,610
Variable lease cost	105		1,065		224		429
Variable lease cost - related party	5,357		64,968
Variable lease cost—related party					—		31,453
Short-term lease cost	224		407		2,810		—
Total lease cost⁽¹⁾	$	15,847	$	104,105	$	7,116	$	46,028



(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 ~~nine~~three months ended ~~September 30,~~March 31, 2020 and 2019 related to leases was as follows:


			Three months ended March 31,
			2020		2019
Cash paid for amounts included in the measurement of lease liabilities	(In thousands)		(In thousands)
Operating cash flows from operating leases	$	146	$	36	$	52
Investing cash flow from operating leases	$	18,998	$	3,997	$	4,858
Investing cash flow from operating leases - related party	$	78,518
Investing cash flow from operating leases—related party			$	6,800	$	6,545

~~Table of Contents~~

The weighted-average remaining lease term as of ~~September 30, 2019~~March 31, 2020 was ~~1.82~~0.76 years. The weighted-average discount rate used to determine the operating lease liability as of ~~September 30, 2019~~March 31, 2020 was ~~3.66%~~2.53%.


14.	INCOME TAXES

~~The dollar amounts and the effective tax rates in this note have been restated as a result of the matter described in Note 1.~~

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 months ended March 31, 2020, the Company's estimated annual effective tax rate before discrete items remained nominal as a result of the valuation allowance on its deferred tax assets. The effective tax rate for the period was (1.4)%, which differs from the statutory rate of 21% primarily as a result of the valuation allowance on the Company's deferred tax assets. In addition, the Company recognized $7.3 million of income tax expense discretely in the quarter as a result of the sale of assets and a corresponding adjustment 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 months ended March 31, 2020. The Company expects a full valuation allowance against its deferred tax assets based on its conclusion, considering all available evidence (both positive and negative), that it was more likely than not that the deferred tax assets would not be realized. A valuation allowance for deferred tax assets, including net operating losses, is recognized when it is more likely than not that some or all of the benefit from the deferred tax assets will not be realized. To assess that likelihood, the Company uses estimates and judgment regarding future taxable income, and considers the tax laws in the jurisdiction where such taxable income is generated, to determine whether a valuation allowance is required. Such evidence can include current financial position, results of operations, both actual and forecasted, the reversal of deferred tax liabilities and tax planning strategies as well as the current and forecasted business economics of the oil and gas industry.

On March 27, 2020, the CARES Act 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 NOL that corporations can use to offset income, and increasing the amount of deductible interest under section 163(j). The Company

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does not expect to be materially impacted by the CARES Act provision and does not anticipate the CARES Act to have a material effect on the ability to realized 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 utilization 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.

~~For~~ On April 30, 2020, the ~~three month period ended March 31, 2019,~~Company's Board of Directors approved the ~~Company maintained~~adoption of a ~~full valuation allowance against its deferred~~ tax ~~assets based on its conclusion, considering all available evidence (both positive and negative),~~benefits preservation plan that ~~it was more likely than not that~~is intended to protect value by preserving the deferred tax assets would not be realized. A valuation allowance for deferred tax assets, including net operating losses, is recognized when it is more likely than not that some or all of the benefit from the deferred tax assets will not be realized. To assess that likelihood, the Company uses estimates and judgment regarding future taxable income, and considers the tax laws in the jurisdiction where such taxable income is generated, to determine whether a valuation allowance is required. Such evidence can include current financial position, results of operations, both actual and forecasted, the reversal of deferred tax liabilities and tax planning strategies as well as the current and forecasted business economics of the oil and gas industry.

As of June 30, 2019, in part because in the current year the Company achieved more than three years of cumulative pretax income in the U.S. federal tax jurisdiction and the Company determined that an ownership change under Internal Revenue Code Section 382 did not occur that would further limit itsCompany's ability to ~~utilize net operating loss carryforwards, management determined that there was sufficient positive evidence~~use its tax attributes, such as NOLs, to ~~conclude that it is~~offset potential future income taxes for federal income tax purposes. See Note 16 for more ~~likely than not that additional deferred taxes of $207.0 million are realizable.~~

For the three and nine months ended September 30, 2019, the Company recognized $27.7 million and $207.0 million, respectively, as a discrete tax benefit. It therefore reduced the valuation allowance accordingly and maintains a valuation allowance of $5.0 million related to foreign tax credits, general business credits and net operating losses in jurisdictions for which it has determined that it is more likely than not that deferred tax assets would not be realized before expiration.

As of each reporting date, management considers new evidence, both positive and negative, that could affect its view of the future realization of deferred tax assets. This assessment relies upon a number of areas of management’s judgment regarding forecast of results in subsequent years. Changes in those judgments could require the Company to establish a valuation allowance for currently recognized deferred tax assets in a subsequent reporting period. In addition, if the Company incurred an Internal Revenue Code Section 382 ownership change it would significantly limit the Company’s ability to utilize net operating loss carryforwards and other tax attributes.

For the three and nine months ended September 30, 2019, the Company's estimated annual effective tax rates were approximately 50.4% and 28.2%, respectively. The effective tax rate varies from the expected statutory tax rate of 21% primarily because of the release of the valuation allowance of $207.0 million for the nine months ended September 30, 2019. The Company also recognized tax expense of $1.6 million and $1.7 million for the three and nine months ended September 30, 2019, respectively, related to equity compensation book amounts that exceed the tax deduction.information.


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)


	September 30, 2019
	Parent			Guarantors			Non-Guarantors			Eliminations			Consolidated			March 31, 2020
	As Restated															Parent			Guarantors			Non-Guarantors			Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	6,279		$	3,715		$	130		$	—		$	10,124		$	897		$	541		$	195		$	—		$	1,633
Accounts receivable - oil and natural gas sales	857			111,800			—			—			112,657			860			73,239			—			—			74,099
Accounts receivable - joint interest and other	6,909			34,418			—			—			41,327			8,521			34,026			—			—			42,547
Accounts receivable - intercompany	953,446			625,306			—			(1,578,752		)	—			1,277,124			1,052,317			—			(2,329,441		)	—
Prepaid expenses and other current assets	3,886			1,697			75			—			5,658			11,452			320			76			—			11,848
Short-term derivative instruments	134,571			—			—			—			134,571			171,755			—			—			—			171,755
Total current assets	1,105,948			776,936			205			(1,578,752		)	304,337			1,470,609			1,160,443			271			(2,329,441		)	301,882

Property and equipment:
Oil and natural gas properties, full-cost accounting	1,312,715			9,239,581			146			(729		)	10,551,713			1,247,661			9,414,738			5,862			(729		)	10,667,532
Other property and equipment	92,163			751			3,319			—			96,233			92,812			51			4,019			—			96,882
Accumulated depletion, depreciation, amortization and impairment	(1,416,248		)	(4,200,519		)	(221		)	—			(5,616,988		)	(1,421,230		)	(6,436,959		)	(1,684		)	—			(7,859,873		)
Property and equipment, net	(11,370		)	5,039,813			3,244			(729		)	5,030,958			(80,757		)	2,977,830			8,197			(729		)	2,904,541
Other assets:
Equity investments and investments in subsidiaries	4,553,316			—			49,545			(4,528,899		)	73,962			2,486,108			6,332			6,186			(2,492,401		)	6,225
Long-term derivative instruments	23,419			—			—			—			23,419
Deferred tax asset	323,378			—			—			—			323,378
Inventories	94			6,928			—			—			7,022
Operating lease assets	13,920			—			—			—			13,920			10,186			—			—			—			10,186
Operating lease assets - related parties	48,449			—			—			—			48,449
Other assets	11,333			320			—			—			11,653			32,591			8,863			(1		)	—			41,453
Total other assets	4,973,909			7,248			49,545			(4,528,899		)	501,803			2,528,885			15,195			6,185			(2,492,401		)	57,864
Total assets	$	6,068,487		$	5,823,997		$	52,994		$	(6,108,380	)	$	5,837,098		$	3,918,737		$	4,153,468		$	14,653		$	(4,822,571	)	$	3,264,287

Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable and accrued liabilities	$	69,863		$	369,129		$	27		$	—		$	439,019		$	63,863		$	373,554		$	36		$	—		$	437,453
Accounts payable - intercompany	660,364			914,401			3,987			(1,578,752		)	—			1,087,484			1,237,368			4,589			(2,329,441		)	—
Short-term derivative instruments	429			—			—			—			429			67			—			—			—			67
Current portion of operating lease liabilities	12,848			—			—			—			12,848			9,873			—			—			—			9,873
Current portion of operating lease liabilities - related parties	21,017			—			—			—			21,017
Current maturities of long-term debt	622			—			—			—			622			688			—			—			—			688
Total current liabilities	765,143			1,283,530			4,014			(1,578,752		)	473,935			1,161,975			1,610,922			4,625			(2,329,441		)	448,081
Long-term derivative instruments	72,040			—			—			—			72,040			70,829			—			—			—			70,829
Asset retirement obligation - long-term	—			59,819			—			—			59,819			—			59,444			—			—			59,444
Uncertain tax position liability	3,127			—			—			—			3,127			3,209			—			—			—			3,209
Non-current operating lease liabilities	1,072			—			—			—			1,072			313			—			—			—			313
Non-current operating lease liabilities - related parties	27,432			—			—			—			27,432
Long-term debt, net of current maturities	2,076,569			—			—			—			2,076,569			1,898,362			—			—			—			1,898,362
Total liabilities	2,945,383			1,343,349			4,014			(1,578,752		)	2,713,994			3,134,688			1,670,366			4,625			(2,329,441		)	2,480,238

Stockholders’ equity:
Common stock	1,597			—			—			—			1,597			1,598			—			—			—			1,598
Paid-in capital	4,205,158			4,170,573			262,061			(4,432,634		)	4,205,158			4,209,578			4,171,409			267,558			(4,438,967		)	4,209,578
Accumulated other comprehensive loss	(50,679		)	—			(48,548		)	48,548			(50,679		)	(61,863		)	—			(59,434		)	59,434			(61,863		)
(Accumulated deficit) retained earnings	(1,032,972		)	310,075			(164,533		)	(145,542		)	(1,032,972		)
Accumulated deficit																(3,365,264		)	(1,688,307		)	(198,096		)	1,886,403			(3,365,264		)
Total stockholders’ equity	3,123,104			4,480,648			48,980			(4,529,628		)	3,123,104			784,049			2,483,102			10,028			(2,493,130		)	784,049
Total liabilities and stockholders’ equity	$	6,068,487		$	5,823,997		$	52,994		$	(6,108,380	)	$	5,837,098		$	3,918,737		$	4,153,468		$	14,653		$	(4,822,571	)	$	3,264,287

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CONDENSED CONSOLIDATING BALANCE SHEETS

(Amounts in thousands)


	December 31, 2018															December 31, 2019
	Parent			Guarantors			Non-Guarantor			Eliminations			Consolidated			Parent			Guarantors			Non-Guarantor			Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	25,585		$	26,711		$	1		$	—		$	52,297		$	2,768		$	3,097		$	195		$	—		$	6,060
Accounts receivable - oil and natural gas sales	146,075			64,125			—			—			210,200			859			120,351			—			—			121,210
Accounts receivable - joint interest and other	16,212			6,285			—			—			22,497			5,279			42,696			—			—			47,975
Accounts receivable - intercompany	671,633			319,464			—			(991,097		)	—			1,065,593			843,223			—			(1,908,816		)	—
Prepaid expenses and other current assets	7,843			2,174			—			—			10,017			4,047			308			76			—			4,431
Short-term derivative instruments	21,352			—			—			—			21,352			126,201			—			—			—			126,201
Total current assets	888,700			418,759			1			(991,097		)	316,363			1,204,747			1,009,675			271			(1,908,816		)	305,877

Property and equipment:
Oil and natural gas properties, full-cost accounting,	7,044,550			2,983,015			—			(729		)	10,026,836			1,314,933			9,273,681			7,850			(729		)	10,595,735
Other property and equipment	91,916			751			—			—			92,667			92,650			50			4,019			—			96,719
Accumulated depletion, depreciation, amortization and impairment	(4,640,059		)	(39		)	—			—			(4,640,098		)	(1,418,888		)	(5,808,254		)	(1,518		)	—			(7,228,660		)
Property and equipment, net	2,496,407			2,983,727			—			(729		)	5,479,405			(11,305		)	3,465,477			10,351			(729		)	3,463,794
Other assets:
Equity investments and investments in subsidiaries	2,856,988			—			44,259			(2,665,126		)	236,121			3,064,503			6,332			21,000			(3,059,791		)	32,044
Inventories	4,210			1,134			—			—			5,344
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	12,624			1,178			—			1			13,803			10,026			5,514			—			—			15,540
Total other assets	2,873,822			2,312			44,259			(2,665,125		)	255,268			3,140,093			11,846			21,000			(3,059,791		)	113,148
Total assets	$	6,258,929		$	3,404,798		$	44,260		$	(3,656,951	)	$	6,051,036		$	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	$	419,107		$	99,273		$	—		$	—		$	518,380		$	48,006		$	367,088		$	124		$	—		$	415,218
Accounts payable - intercompany	320,259			670,708			130			(991,097		)	—			878,283			1,026,249			4,285			(1,908,817		)	—
Short-term derivative instruments	20,401			—			—			—			20,401			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	651			—			—			—			651			631			—			—			—			631
Total current liabilities	760,418			769,981			130			(991,097		)	539,432			962,269			1,393,337			4,409			(1,908,817		)	451,198
Long-term derivative instruments	13,992			—			—			—			13,992			53,135			—			—			—			53,135
Asset retirement obligation - long-term	66,859			13,093			—			—			79,952			—			58,322			2,033			—			60,355
Uncertain tax position liability	3,127			—			—			—			3,127			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	2,086,765			—			—			—			2,086,765			1,978,020			—			—			—			1,978,020
Total liabilities	2,931,161			783,074			130			(991,097		)	2,723,268			3,018,943			1,451,659			6,442			(1,908,817		)	2,568,227

Stockholders’ equity:
Common stock	1,630			—			—			—			1,630			1,597			—			—			—			1,597
Paid-in capital	4,227,532			1,915,598			261,626			(2,177,224		)	4,227,532			4,207,554			4,171,408			267,557			(4,438,965		)	4,207,554
Accumulated other comprehensive loss	(56,026		)	—			(53,783		)	53,783			(56,026		)	(46,833		)	—			(44,763		)	44,763			(46,833		)
(Accumulated deficit) retained earnings	(845,368		)	706,126			(163,713		)	(542,413		)	(845,368		)
Accumulated deficit retained earnings																(2,847,726		)	(1,136,069		)	(197,614		)	1,333,683			(2,847,726		)
Total stockholders’ equity	3,327,768			2,621,724			44,130			(2,665,854		)	3,327,768			1,314,592			3,035,339			25,180			(3,060,519		)	1,314,592
Total liabilities and stockholders’ equity	$	6,258,929		$	3,404,798		$	44,260		$	(3,656,951	)	$	6,051,036		$	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 September 30, 2019															Three months ended March 31, 2020
	Parent			Guarantors			Non-Guarantors			Eliminations			Consolidated			Parent			Guarantors			Non-Guarantors			Eliminations			Consolidated
	As Restated
Total revenues	$	27,358		$	257,817		$	—		$	—		$	285,175		$	98,268		$	148,609		$	—		$	—		$	246,877

Costs and expenses:
Lease operating expenses	(231		)	22,704			—			—			22,473			—			15,986			—			—			15,986
Production taxes	36			6,529			—			—			6,565			—			4,799			—			—			4,799
Midstream gathering and processing expenses	—			78,435			—			—			78,435			—			57,896			—			—			57,896
Depreciation, depletion and amortization	2,686			160,418			166			—			163,270			2,502			75,360			166			—			78,028
Impairment of oil and natural gas properties	—			571,442			—			—			571,442			—			553,345			—			—			553,345
General and administrative expenses	27,218			(12,675		)	116			—			14,659			24,646			(8,650		)	173			—			16,169
Accretion expense	—			747			—			—			747			—			741			—			—			741
	29,709			827,600			282			—			857,591			27,148			699,477			339			—			726,964

LOSS FROM OPERATIONS	(2,351		)	(569,783		)	(282		)	—			(572,416		)
INCOME (LOSS) FROM OPERATIONS																71,120			(550,868		)	(339		)	—			(480,087		)

OTHER EXPENSE (INCOME):
Interest expense	35,105			(1,010		)	—			—			34,095			33,177			(187		)	—			—			32,990
Interest income	(187		)	(151		)	—			—			(338		)	(59		)	(93		)	—			—			(152		)
Gain on debt extinguishment	(23,600		)	—			—			—			(23,600		)	(15,322		)	—			—			—			(15,322		)
Loss from equity method investments and investments in subsidiaries	616,348			—			40			(573,306		)	43,082			563,366			—			143			(552,720		)	10,789
Other (income) expense	(1,168		)	3,362			—			1,000			3,194
Other expense																206			1,650			—			—			1,856
	626,498			2,201			40			(572,306		)	56,433			581,368			1,370			143			(552,720		)	30,161

LOSS BEFORE INCOME TAXES	(628,849		)	(571,984		)	(322		)	572,306			(628,849		)	(510,248		)	(552,238		)	(482		)	552,720			(510,248		)
INCOME TAX BENEFIT	(144,047		)	—			—			—			(144,047		)
INCOME TAX EXPENSE																7,290			—			—			—			7,290

NET LOSS	$	(484,802	)	$	(571,984	)	$	(322	)	$	572,306		$	(484,802	)	$	(517,538	)	$	(552,238	)	$	(482	)	$	552,720		$	(517,538	)

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CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

(Amounts in thousands)


	Three months ended September 30, 2018															Three months ended March 31, 2019
	Parent			Guarantors			Non-Guarantor			Eliminations			Consolidated			Parent			Guarantors			Non-Guarantor			Eliminations			Consolidated

Total revenues	$	235,683		$	125,279		$	—		$	—		$	360,962		$	186,246		$	134,332		$	—		$	—		$	320,578

Costs and expenses:
Lease operating expenses	16,502			5,823			—			—			22,325			14,893			4,914			—			—			19,807
Production taxes	4,505			4,843			—			—			9,348			3,261			4,660			—			—			7,921
Midstream gathering and processing expenses	54,397			24,516			—			—			78,913			43,299			26,983			—			—			70,282
Depreciation, depletion and amortization	119,914			1			—			—			119,915			118,432			1			—			—			118,433
General and administrative expenses	16,314			(467		)	1			—			15,848			10,731			(675		)	1			—			10,057
Accretion expense	812			225			—			—			1,037			951			116			—			—			1,067
	212,444			34,941			1			—			247,386			191,567			35,999			1			—			227,567

INCOME (LOSS) FROM OPERATIONS	23,239			90,338			(1		)	—			113,576
(LOSS) INCOME FROM OPERATIONS																(5,321		)	98,333			(1		)	—			93,011

OTHER (INCOME) EXPENSE:
Interest expense	34,254			(1,001		)	—			—			33,253			35,925			(304		)	—			—			35,621
Interest income	(86		)	(6		)	—			—			(92		)	(147		)	(5		)	—			—			(152		)
Gain on sale of equity method investments	(2,733		)	—			—			—			(2,733		)
(Income) loss from equity method investments and investments in subsidiaries	(104,226		)	(1		)	275			91,094			(12,858		)	(102,914		)	—			393			98,248			(4,273		)
Other expense (income)	880			(24		)	—			—			856
Other income																(427		)	—			—			—			(427		)
	(71,911		)	(1,032		)	275			91,094			18,426			(67,563		)	(309		)	393			98,248			30,769

INCOME (LOSS) BEFORE INCOME TAXES	95,150			91,370			(276		)	(91,094		)	95,150			62,242			98,642			(394		)	(98,248		)	62,242
INCOME TAX BENEFIT	—			—			—			—			—			—			—			—			—			—

NET INCOME (LOSS)	$	95,150		$	91,370		$	(276	)	$	(91,094	)	$	95,150		$	62,242		$	98,642		$	(394	)	$	(98,248	)	$	62,242

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~~CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS~~

~~(Amounts in thousands)~~

Nine months ended September 30, 2019
Parent Guarantors Non-Guarantors Eliminations Consolidated
As Restated
Total revenues $ 493,895
$ 570,852
$ —
$ —
$ 1,064,747

Costs and expenses:
Lease operating expenses 26,918
37,750
—
—
64,668
Production taxes 6,117
16,467
—
—
22,584
Midstream gathering and processing expenses 71,420
149,312
—
—
220,732
Depreciation, depletion, and amortization 201,250
205,183
221
—
406,654
Impairment of oil and gas properties —
571,442
—
—
571,442
General and administrative expenses 56,195
(16,933 ) 220
—
39,482
Accretion expense 1,389
1,784
—
—
3,173
363,289
965,005
441
—
1,328,735

INCOME (LOSS) FROM OPERATIONS 130,606
(394,153 ) (441 ) —
(263,988 )

OTHER EXPENSE (INCOME):
Interest expense 105,364
(2,269 ) —
—
103,095
Interest income (454 ) (195 ) —
—
(649 )
Gain on debt extinguishment (23,600 ) —
—
—
(23,600 )
Loss from equity method investments and investments in subsidiaries 560,883
—
379
(396,871 ) 164,391
Other (income) expense (605 ) 3,362
—
1,000
3,757
641,588
898
379
(395,871 ) 246,994

LOSS BEFORE INCOME TAXES (510,982 ) (395,051 ) (820 ) 395,871
(510,982 )
INCOME TAX BENEFIT (323,378 ) —
—
—
(323,378 )

NET LOSS $ (187,604 ) $ (395,051 ) $ (820 ) $ 395,871
$ (187,604 )

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~~CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS~~

~~(Amounts in thousands)~~

Nine months ended September 30, 2018
Parent Guarantors Non-Guarantor Eliminations Consolidated

Total revenues $ 596,018
$ 343,076
$ —
$ —
$ 939,094

Costs and expenses:
Lease operating expenses 46,926
17,217
—
—
64,143
Production taxes 13,309
10,552
—
—
23,861
Midstream gathering and processing expenses 152,605
61,941
—
—
214,546
Depreciation, depletion, and amortization 352,846
2
—
—
352,848
General and administrative expenses 45,100
(2,148 ) 3
—
42,955
Accretion expense 2,397
659
—
—
3,056
613,183
88,223
3
—
701,409

(LOSS) INCOME FROM OPERATIONS (17,165 ) 254,853
(3 ) —
237,685

OTHER (INCOME) EXPENSE:
Interest expense 103,310
(2,388 ) —
—
100,922
Interest income (144 ) (18 ) —
—
(162 )
Gain on sale of equity method investments (28,349 ) (96,419 ) —
—
(124,768 )
(Income) loss from equity method investments and investments in subsidiaries (387,991 ) (694 ) 833
352,570
(35,282 )
Other (income) expense (481 ) (34 ) —
1,000
485
(313,655 ) (99,553 ) 833
353,570
(58,805 )

INCOME (LOSS) BEFORE INCOME TAXES 296,490
354,406
(836 ) (353,570 ) 296,490
INCOME TAX BENEFIT (69 ) —
—
—
(69 )

NET INCOME (LOSS) $ 296,559
$ 354,406
$ (836 ) $ (353,570 ) $ 296,559

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CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Amounts in thousands)


	Three months ended September 30, 2019														Three months ended March 31, 2020
	Parent			Guarantors			Non-Guarantors			Eliminations		Consolidated			Parent			Guarantors			Non-Guarantors			Eliminations		Consolidated
	As Restated
Net loss	$	(484,802	)	$	(571,984	)	$	(322	)	$	572,306	$	(484,802	)	$	(517,538	)	$	(552,238	)	$	(482	)	$	552,720	$	(517,538	)
Foreign currency translation adjustment	(2,064		)	(43		)	(2,021		)	2,064		(2,064		)	(15,030		)	(360		)	(14,670		)	15,030		(15,030		)
Other comprehensive loss	(2,064		)	(43		)	(2,021		)	2,064		(2,064		)	(15,030		)	(360		)	(14,670		)	15,030		(15,030		)
Comprehensive loss	$	(486,866	)	$	(572,027	)	$	(2,343	)	$	574,370	$	(486,866	)	$	(532,568	)	$	(552,598	)	$	(15,152	)	$	567,750	$	(532,568	)


	Three months ended September 30, 2018												Three months ended March 31, 2019
	Parent		Guarantors		Non-Guarantor			Eliminations			Consolidated		Parent		Guarantors		Non-Guarantor			Eliminations			Consolidated

Net income (loss)	$	95,150	$	91,370	$	(276	)	$	(91,094	)	$	95,150	$	62,242	$	98,642	$	(394	)	$	(98,248	)	$	62,242
Foreign currency translation adjustment	3,052		103		2,949			(3,052		)	3,052		3,801		94		3,707			(3,801		)	3,801
Other comprehensive income	3,052		103		2,949			(3,052		)	3,052		3,801		94		3,707			(3,801		)	3,801
Comprehensive income	$	98,202	$	91,473	$	2,673		$	(94,146	)	$	98,202
Comprehensive income (loss)													$	66,043	$	98,736	$	3,313		$	(102,049	)	$	66,043

Nine months ended September 30, 2019
Parent Guarantors Non-Guarantors Eliminations Consolidated
As Restated
Net loss $ (187,604 ) $ (395,051 ) $ (820 ) $ 395,871
$ (187,604 )
Foreign currency translation adjustment 5,347
112
5,235
(5,347 ) 5,347
Other comprehensive income 5,347
112
5,235
(5,347 ) 5,347
Comprehensive (loss) income $ (182,257 ) $ (394,939 ) $ 4,415
$ 390,524
$ (182,257 )

Nine months ended September 30, 2018
Parent Guarantors Non-Guarantor Eliminations Consolidated

Net income (loss) $ 296,559
$ 354,406
$ (836 ) $ (353,570 ) $ 296,559
Foreign currency translation adjustment (5,815 ) (70 ) (5,745 ) 5,815
(5,815 )
Other comprehensive loss (5,815 ) (70 ) (5,745 ) 5,815
(5,815 )
Comprehensive income (loss) $ 290,744
$ 354,336
$ (6,581 ) $ (347,755 ) $ 290,744

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CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

(Amounts in thousands)


	Nine months ended September 30, 2019															Three months ended March 31, 2020
	Parent			Guarantors			Non-Guarantors			Eliminations			Consolidated			Parent			Guarantors			Non-Guarantors			Eliminations			Consolidated
	As Restated
Net cash (used in) provided by operating activities	$	(7,604	)	$	621,511		$	3,445		$	3		$	617,355
Net cash provided by (used in) operating activities																$	64,033		$	66,805		$	(435	)	$	435		$	130,838

Net cash provided by (used in) investing activities	9,178			(644,507		)	(3,751		)	432			(638,648		)
Net cash used in investing activities																(448		)	(69,361		)	—			—			(69,809		)

Net cash (used in) provided by financing activities	(20,880		)	—			435			(435		)	(20,880		)	(65,456		)	—			435			(435		)	(65,456		)

Net (decrease) increase in cash, cash equivalents and restricted cash	(19,306		)	(22,996		)	129			—			(42,173		)
Net decrease in cash, cash equivalents and restricted cash																(1,871		)	(2,556		)	—			—			(4,427		)

Cash, cash equivalents and restricted cash at beginning of period	25,585			26,711			1			—			52,297			2,768			3,097			195			—			6,060

Cash, cash equivalents and restricted cash at end of period	$	6,279		$	3,715		$	130		$	—		$	10,124		$	897		$	541		$	195		$	—		$	1,633


	Nine months ended September 30, 2018															Three months ended March 31, 2019
	Parent			Guarantors			Non-Guarantor			Eliminations			Consolidated			Parent			Guarantors			Non-Guarantor			Eliminations			Consolidated

Net cash provided by (used in) operating activities	$	427,351		$	203,446		$	(1	)	$	1		$	630,797		$	210,928		$	28,837		$	(1	)	$	1		$	239,765

Net cash (used in) provided by investing activities	(354,848		)	(199,738		)	(2,318		)	2,318			(554,586		)
Net cash used in investing activities																(200,970		)	(44,593		)	(432		)	432			(245,563		)

Net cash (used in) provided by financing activities	(51,197		)	—			2,319			(2,319		)	(51,197		)	(28,503		)	—			433			(433		)	(28,503		)

Net increase in cash, cash equivalents and restricted cash	21,306			3,708			—			—			25,014
Net decrease in cash, cash equivalents and restricted cash																(18,545		)	(15,756		)	—			—			(34,301		)

Cash, cash equivalents and restricted cash at beginning of period	67,908			31,649			—			—			99,557			25,585			26,711			1			—			52,297

Cash, cash equivalents and restricted cash at end of period	$	89,214		$	35,357		$	—		$	—		$	124,571		$	7,040		$	10,955		$	1		$	—		$	17,996

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16.	SUBSEQUENT EVENTS

Derivatives

In ~~October 2019,~~April 2020, the Company early terminated ~~some of~~ its remaining oil fixed price swaps ~~for oil and natural gas scheduled to settle during the fourth quarter of 2019 covering~~which represented approximately ~~1,000 BBls~~6,000 Bbls of oil per day for the remainder of 2020. The early termination resulted in a cash settlement of approximately $40.5 million. Subsequent to this early termination, the Company entered into oil fixed price swap contracts for the second half of 2020 covering 2,000 Bbls per day of oil at a weighted average swap price of $35.60 per Bbl.

In April and ~~120,000~~May 2020, the Company entered into natural gas fixed price swap contracts for the third quarter of 2020 covering approximately 20,000 MMBtu of natural gas per ~~day. The value~~day at an average swap price of ~~these early terminations was used to enhance~~$2.50 per MMBtu and for the ~~fixed price for new natural gas swaps for~~fourth quarter of 2020 covering approximately ~~28,000~~170,000 MMBtu of natural gas per day at an average swap price of $2.64 per MMBtu.

In April 2020, the Company entered into costless collars for 2021 covering approximately 250,000 MMBtu of natural gas per day at a weighted average floor price of ~~$2.85~~$2.46 per MMBtu and a weighted average ceiling price of $2.81 per MMBtu. The two-way price collars set a floor and ceiling price for the hedged production. If the applicable monthly price indices are outside of the ranges set by the floor and ceiling prices in the various collars, the Company will cash-settle the difference with the counterparty.

Debt Repurchases

In April 2020, the Company used borrowings under its revolving credit facility to repurchase in the open market approximately $47.6 million aggregate principal amount of its 2023 Notes, 2024 Notes, 2025 Notes, and 2026 Notes for $12.6 million.

Borrowing Base Redetermination

On May 1, 2020, the Company entered into a 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 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 31, 2021, and added a limitation on the repurchase of unsecured notes, among other amendments. The Company remained in compliance with its financial covenants under the revolving credit facility following the amendment.

The Tax Benefits Preservation Plan

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. As noted in Note 14, if the Company experiences an ownership change, as defined in Section 382, its ability to fully utilize the NOLs and certain other tax benefits would be substantially limited and the timing of the usage of the NOLs and such other benefits could be substantially delayed, which could significantly impair the value of those assets. 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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ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

As discussed in Note 1 - Basis of Presentation, Restatement and Summary of Significant Accounting Policies to the consolidated financial statements included in Item 1, Part 1 of this Amendment, the Company has restated its financial statements as of and for the three and nine months ended September 30, 2019, and the following information reflects the impact of that restatement.

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 ~~report includes “forward-looking statements”~~Form 10-Q may include forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended ~~("the Securities~~(the "Securities Act"), ~~and~~ Section 21E of the Securities Exchange Act of 1934, as amended ("(the "Exchange Act"), and the ~~Exchange Act"). When used in this Quarterly Report,~~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 ~~words "could", "believe", "anticipate", "intend", "estimate", "expect", "project"~~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 ~~are~~ intended to identify forward-looking ~~statements, although not all forward-looking statements contain such identifying words.~~

statements. All statements, other than statements of historical facts, included in this ~~report~~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 expected impact of the COVID-19 pandemic on our business, our industry and the global economy, estimated future net revenues from oil and ~~natural~~ 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 ~~strengths,~~strength, goals, expansion and growth of our business and operations, plans, references to future success, ~~references~~reference to intentions as to future matters and other such matters are forward-looking statements.

These forward-looking statements are largely based on certain assumptions and analysis made by us in light of our experience and our perception of historical trends, current conditions and expected future developments as well as other factors we believe are appropriate in the circumstances. However, whether actual results and developments will conform with our expectations and ~~predictions is subject~~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 ~~including general economic, market~~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 ~~business conditions; commodity prices;~~ the ~~opportunities (or lack thereof) that~~forward-looking events and circumstances will occur. Actual results may ~~be presented~~differ materially from those anticipated or implied in the forward-looking statements due to and pursued by us; competitive actions by other oil and natural gas companies; adverse developments or losses from pending or future litigation and regulatory proceedings; our ability to identify, complete and integrate acquisitions of properties and businesses; changesthe factors listed in laws or regulations; adverse weather conditions and natural disasters such as hurricanes, our ability to maintain effective internal controls over financial reporting and other factors, including those listed under Item ~~1A,~~1A. “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, ~~2018,~~2019 and elsewhere in this ~~Quarterly Report on~~ Form 10-Q and in our other filings with the SEC, many of which are beyond our control and may cause our actual results, performance or achievements to differ materially from anticipated future results, performance or achievements expressed or implied by such10-Q. All forward-looking ~~statements. Should one or more~~statements speak only as of the ~~risks or uncertainties described in~~date of this ~~Quarterly Report occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.~~Form 10-Q.

All ~~forward‑looking~~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~~forward-looking statements that we or persons acting on our behalf may ~~issue~~issue.

Except as otherwise required by applicable law, we disclaim any duty to update any ~~forward‑looking~~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 ~~Gulfport announces~~we announce financial information in SEC filings, press releases and public conference calls. ~~Gulfport~~We may use the Investors section of ~~its~~our website (~~www.gulfportenergy.com~~)(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 ~~Gulfport’s~~our website is not part of this Quarterly Report on Form 10-Q.

Overview

We are an independent ~~oil and~~ natural ~~gas~~gas-weighted exploration and production company focused on the exploration, ~~exploitation,~~ acquisition and production of natural gas, crude oil and natural gas liquids ("~~NGLs"~~NGL") in the United ~~States. Our corporate strategy is to internally identify prospects, acquire lands encompassing those prospects~~States with primary focus in the Appalachia and evaluate those prospects using subsurface geology and geophysical data and exploratory drilling. Using this strategy, we have developed an oil and natural gas portfolio of proved reserves, as well as development and exploratory drilling opportunities on high potential conventional and unconventional oil and natural gas prospects.Mid-Continent basins. Our principal properties are ~~located~~ in Eastern Ohio targeting the Utica ~~Shale primarily~~formation and in ~~Eastern Ohio~~

~~Table of Contents~~

~~and~~central Oklahoma targeting the SCOOP Woodford and SCOOP Springer plays in Oklahoma. In addition, among other interests, we hold an acreage position in the Alberta oil sands in Canada through our interest in Grizzly Oil Sands ULC ("Grizzly"), and an approximate 21.8% equity interest in Mammoth Energy Services, Inc. ("Mammoth Energy"), an energy services company listed on the Nasdaq Global Select Market (TUSK). We seek to achieve reserve growth and increase our cash flow through our annual drilling programs.

~~2019 Operational and Other Highlights~~

During the nine months ended September 30, 2019, we spud 13 gross (11.4 net) wells in the Utica Shale and participated in five additional gross (0.9 net) wells that were drilled by other operators on our Utica Shale acreage. In addition, during the nine months ended September 30, 2019, we spud eight gross (6.7 net) wells in the SCOOP and participated in an additional 36 gross (0.8 net) wells that were drilled by other operators on our SCOOP acreage. Of the 21 new wells we spud, at September 30, 2019, 13 were in various stages of completion, six were turned-to-sales and two were being drilled. In addition, 47 gross (41.5 net) operated wells were turned-to-sales in our Utica Shale operating area and nine gross (8.7 net) operated wells were turned-to-sales in our SCOOP operating area during the nine months ended September 30, 2019.

In January 2019, our board of directors approved a new stock repurchase program to acquire a portion of our outstanding common stock within a 24 month period, which we believe underscores the confidence we have in our business model, financial performance and asset base. As of October 25, 2019, we have repurchased approximately 3.8 million shares of our outstanding common stock pursuant to the plan for total consideration of approximately $30.0 million.

During the three months ended September 30, 2019, we used borrowings under our revolving credit facility to repurchase in the open market approximately $104.4 million aggregate principal amount of our outstanding 6.625% Senior Notes due 2023 ("2023 Notes"), 6.000% Senior Notes due 2024 ("2024 Notes"), 6.375% Senior Notes due 2025 ("2025 Notes"), and 6.375% Senior Notes due 2026 ("2026 Notes") (collectively the "Notes"), for $80.3 million. We recognized a $23.6 million gain on debt extinguishment, which included retirement of unamortized issuance costs and fees associated with the repurchased debt.

In December of 2018, we entered into an agreement to sell our non-core assets located in the West Cote Blanche Bay ("WCBB") and Hackberry fields of Louisiana to an undisclosed third party for a purchase price of approximately $19.7 million. The sale closed on July 3, 2019, subject to customary post-closing terms and conditions, with an effective date of August 15, 2018. We received approximately $9.2 million in cash and retained contingent overriding royalty interests. In addition, we could also receive contingent payments based on commodity prices exceeding specified thresholds over the two years following the closing date. See Note 9 for further discussion of the contingent consideration arrangement, which was determined to be an embedded derivative. The buyer assumed all plugging and abandonment liabilities associated with these assets which totaled approximately $30.0 million at the divestiture date.

formations.

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COVID-19

In March 2020, the World Health Organization classified the outbreak 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 imposed regulations in efforts to control the spread of COVID-19 such as shelter-in-place orders, quarantines, executive orders and similar restrictions.

While we continue to deliver energy resources to the United States, we remain focused on protecting the health and wellbeing of our employees 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 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.

As a result of our business continuity measures, we have not experienced significant disruptions in executing our business operations in the first quarter of 2020. While we did not experience significant disruptions to our operations during the first quarter of 2020, 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 of service providers and supply chain disruption. 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, as well as the current outlook for low oil prices throughout the second quarter of 2020, we plan to shut in a minimal amount production over the next few months, including a large number of vertical wells in the SCOOP. We expect these shut ins to impact our production by less than 20 MMcfe per day. We also anticipate some of our non-operated production may be negatively impacted by voluntary shut ins due to low prices. In addition, the COVID-19 pandemic creates risks of delays in new drilling and completion activities that could negatively impact us, our non-operated partners or our service providers. Considering all of these factors, our previously provided production guidance for full year 2020 should no longer be relied upon.

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 regarding risks associated with the COVID-19 pandemic, see Item 1A “Risk Factors” in this report.

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2020 Operational and Other Highlights

Despite the challenges our company and the entire upstream energy 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 months ended March 31, 2020, we had the following notable achievements:

Continued our efforts to improve our balance sheet by reducing long-term debt by $79.6 million as of March 31, 2020 as compared to December 31, 2019 primarily through discounted bond repurchases.

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 17.7 days in the first quarter, which was an 11% improvement from full year 2019 levels. In the SCOOP, our average spud to rig release time was 37.4 days, representing a 32% improvement compared to full year 2019 levels.

Closed on the sale of our SCOOP water infrastructure assets on January 2, 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 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.

2020 Production and Drilling Activity

Production Volumes



	Three months ended March 31,
	2020	% of Total		2019
Natural gas (Mcf/day)
Utica Shale	785,781	83	%	952,227
SCOOP	159,886	17	%	181,846
Other	39	—	%	140
Total	945,706			1,134,213
Oil and condensate (Bbls/day)
Utica Shale	592	10	%	729
SCOOP	5,174	89	%	4,421
Other	78	1	%	1,647
Total	5,844			6,797
NGL (Gal/day)
Utica Shale	134,293	26	%	259,286
SCOOP	376,890	74	%	360,888
Other	—	—	%	163
Total	511,183			620,337
Combined (Mcfe/day)
Utica Shale	808,520	77	%	993,643
SCOOP	244,771	23	%	259,930
Other	508	—	%	10,044
Total	1,053,799			1,263,617

~~During the three months ended September 30, 2019, our total net prod~~uc~~tion was~~ ~~130,071,046~~ ~~thousand cubic feet ("Mcf") of natural gas,~~ ~~474,407~~ ~~barrels of oil and~~ ~~52,950,681~~ ~~gallons of NGLs for a total of 140,482 million cubic feet of natural gas equivalent ("MMcfe") as compared to 116,993,594 Mcf of natural gas, 664,633 barrels of oil and 72,427,030 gallons of NGLs, or 131,328 MMcfe, for the three months ended September 30, 2018.~~ Our total net production averaged approximately ~~1,527.0~~1,053.8 MMcfe per day during the three months ended ~~September 30, 2019,~~March 31, 2020, as compared to ~~1,427.5~~1,263.6 MMcfe per day during the same period in ~~2018~~2019. The ~~7% increase~~16% decrease in production is largely the result of ~~the continuing~~a decrease in development activities of our Utica Shale and SCOOP ~~acreage.~~operating areas beginning in the third and fourth quarters of 2019.

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Utica Shale. From January 1, ~~2019~~2020 through ~~September 30, 2019,~~March 31, 2020, we spud 13seven gross (~~11.4~~ ~~net)~~and net wells in the Utica Shale, of which ~~six were turned-to-sales,~~ one was being drilled and six were in various stages of completion at ~~September 30, 2019.~~March 31, 2020. In addition, we completed 15 gross and net operated wells. We ~~also participated~~did not participate in ~~five~~any additional ~~gross (0.9 net)~~ wells that were drilled by other operators on our Utica Shale acreage. ~~From October 1, 2019 through October 25, 2019, we spud one gross and net well in the Utica Shale.~~

As of ~~October 25, 2019,~~May 1, 2020, we had one operated drilling rig running in the ~~Utica Shale. We currently intend~~play and expect to ~~spud a total~~continue with this level of 16 gross (14.4 net) horizontal wells, and commence sales from a total of 47 gross (41.5 net) horizontal wells, on our Utica Shale acreage in 2019. We also anticipate an additional two to three net horizontal wells will be drilled, and sales commenced from two to three net horizontal wells, on our Utica Shale acreage by other operators during 2019.activity through October 2020.

Aggregate net production from our Utica Shale acreage during the three months ended ~~September 30, 2019~~March 31, 2020 was approximately ~~114,459~~73,575 MMcfe, or an average of ~~1,244.1~~808.5 MMcfe per day, of which ~~98%~~97% was natural gas and 2%3% was oil and ~~NGLs.~~NGL.

SCOOP. From January 1, ~~2019~~2020 through ~~September 30, 2019,~~March 31, 2020, we spud ~~eight~~five gross (~~6.7~~(4.3 net) wells in the SCOOP, of which ~~one~~two ~~was~~were being drilled and ~~seven~~three were in various stages of completion at ~~September 30, 2019.~~March 31, 2020. In addition. we completed 4 gross (3.8 net) operated wells. We also participated in an additional 36four gross (~~0.8~~ ~~net)~~ wells that were drilled by other operators on our SCOOP acreage. ~~From October 1, 2019 through October 25, 2019, we did not spud any wells on our SCOOP acreage.~~

As of ~~October 25, 2019,~~May 1, 2020, we had one operated drilling rig running ~~on our SCOOP acreage. We currently intend~~in the play and expect to ~~spud a total~~continue with this level of ~~nine gross (7.7 net) horizontal wells, and commence sales from a total~~activity for the remainder of 14 gross (12.6 net) horizontal wells, on our SCOOP acreage in 2019. We also anticipate one to two net wells will be drilled, and sales commenced from one to two net wells on our SCOOP acreage by other operators during 2019.2020.

Aggregate net production from our SCOOP acreage during the three months ended ~~September 30, 2019~~March 31, 2020 was approximately ~~25,897~~22,274 MMcfe, or an average of ~~281.5~~244.8 MMcfe per day, of which ~~71%~~65% was from natural gas and ~~29%~~35% was from oil and ~~NGLs.~~NGL.

~~South Louisiana~~. From January 1, 2019 through July 3, 2019, we did not spud any new wells or recomplete any wells in the South Louisiana fields. Our aggregate net production from the South Louisiana fields during the three months ended September 30, 2019 was approximately 38.3 MMcfe, or an average of 416.2 Mcfe per day, all of which was from oil. On July 3, 2019, we closed on the sale of all of our South Louisiana assets.

~~We had no further capital obligations related to the South Louisiana fields after July 3, 2019.~~

Niobrara Formation. From January 1, ~~2019~~2020 through ~~October 25, 2019~~,May 1, 2020, there ~~wer~~ewere no wells spud ~~spud~~ on our Niobrara Formation acreage. Aggregate net production was approximately ~~26.0~~ 21.7 MMcfe, or an average of ~~282.4~~238.4 Mcfe per day during the three months ended ~~September 30, 2019,~~March 31, 2020, all of which was from oil.

Bakken. As of ~~September 30, 2019,~~March 31, 2020, we had an ~~interest~~interest in 18 wells and overriding royalty interests in certain existing and future wells. Aggregate net production from this acreage during the three months ended ~~September 30, 2019~~March 31, 2020 was approximately ~~60.6~~24.3 MMcfe, or an average of ~~658.3~~266.9 Mcfe per day, of which ~~96%~~86% was from oil and 4%14% was from natural gas and natural gas liquids.

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~~Equity Investments~~

~~Mammoth Energy Services, Inc.~~

In connection with the preparation of financial statements for the three months ended September 30, 2019, we reviewed our investment in Mammoth Energy for impairment based on certain qualitative and quantitative factors. As a result of the calculated fair values and other qualitative factors, we concluded that an other than temporary impairment was indicated. This resulted in recording an aggregate impairment loss of $35.5 million and $160.8 million for the three and nine months ended September 30, 2019, respectively, which is included in loss (income) from equity method investments, net in the accompanying consolidated statements of operations. If Mammoth Energy's common stock continues to trade below the carrying value for a prolonged period of time, further impairment of our investment in Mammoth Energy may be necessary.

RESULTS OF OPERATIONS

Comparison of the Three Month Periods Ended ~~September 30,~~March 31, 2020 and 2019 ~~and 2018~~

We reported a net loss of ~~$484.8~~$517.5 million for the three months ended ~~September 30, 2019~~March 31, 2020 as compared to net income of ~~$95.2~~$62.2 million for the three months ended ~~September 30, 2018. This $580.0~~March 31, 2019. Included in the loss for the three months ended March 31, 2020 was a $553.3 million ~~period-to-period decrease~~non-cash impairment of our oil and natural gas properties, which was ~~due primarily~~the main driver of the change in our net (loss) income during the period. The remaining variance was related to a ~~$75.8~~$73.7 milliondecrease in oil and natural gas revenues, a ~~$55.9~~$15.1 million ~~increase~~decrease in ~~loss~~income from equity method investments and a $6.1 million increase in general and administrative expenses, partially offset by a $40.4 million decrease in DD&A, a $15.3 million gain on debt extinguishment, a $12.4 million decrease in midstream gathering and processing expenses, a $3.8 million decrease in lease operating expenses and a $3.1 million decrease in production taxes for the three months ended March 31, 2020 as compared to the three months ended March 31, 2019.

Natural Gas, Oil and NGL Sales



	Three months ended March 31,
	2020		2019		change
	($ In thousands)
Natural gas	108,547		276,016		(61	)%
Oil and condensate	23,151		32,482		(29	)%
NGL	16,913		32,125		(47	)%
Natural gas, oil and NGL revenues	$	148,611	$	340,623	(56	)%

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The decrease in natural gas sales without the impact of derivatives was due to a 53% decrease in natural gas market prices and a 16% decrease in natural gas sales volumes.

The decrease in oil and condensate sales without the impact of derivatives was due to an 18% decrease in oil and condensate market prices and a 13% decrease in oil and condensate sales volumes.

The decrease in NGL sales without the impact of derivatives was due to a 37% decrease in NGL market prices and a 17% decrease in NGL sales volumes.

Natural Gas, Oil and NGL Derivatives



	Three months ended March 31,
	2020			2019
	($ In thousands)
Natural gas derivatives - fair value (losses) gains	$	(15,125	)	$	9,338
Natural gas derivatives - settlement gains (losses)	60,978			(25,769		)
Total gains (losses) on natural gas derivatives	45,853			(16,431		)

Oil and condensate derivatives - fair value gains (losses)	43,374			(474		)
Oil and condensate derivatives - settlement gains	9,500			20
Total gains (losses) on oil and condensate derivatives	52,874			(454		)

NGL derivatives - fair value gains (losses)	665			(4,074		)
NGL derivatives - settlement gains	255			914
Total gains (losses) on NGL derivatives	920			(3,160		)

Contingent consideration arrangement - fair value losses	(1,381		)	—
Total gains (losses) on natural gas, oil and NGL derivatives	$	98,266		$	(20,045	)

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



	Three months ended March 31,
	2020		2019
	($ In thousands)
Natural gas sales
Natural gas production volumes (MMcf)	86,059		102,079

Total natural gas sales	$	108,547	$	276,016

Natural gas sales without the impact of derivatives ($/Mcf)	$	1.26	$	2.70
Impact from settled derivatives ($/Mcf)	$	0.71	$	(0.25	)
Average natural gas sales price, including settled derivatives ($/Mcf)	$	1.97	$	2.45

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Oil and condensate sales
Oil and condensate production volumes (MBbls)	532		612

Total oil and condensate sales	$	23,151	$	32,482

Oil and condensate sales without the impact of derivatives ($/Bbl)	$	43.53	$	53.10
Impact from settled derivatives ($/Bbl)	$	17.86	$	0.03
Average oil and condensate sales price, including settled derivatives ($/Bbl)	$	61.39	$	53.13

NGL sales
NGL production volumes (MGal)	46,518		55,830

Total NGL sales	$	16,913	$	32,125

NGL sales without the impact of derivatives ($/Gal)	$	0.36	$	0.58
Impact from settled derivatives ($/Gal)	$	0.01	$	0.01
Average NGL sales price, including settled derivatives ($/Gal)	$	0.37	$	0.59

Natural gas, oil and condensate and NGL sales
Natural gas equivalents (MMcfe)	95,896		113,726

Total natural gas, oil and condensate and NGL sales	$	148,611	$	340,623

Natural gas, oil and condensate and NGL sales without the impact of derivatives ($/Mcfe)	$	1.55	$	3.00
Impact from settled derivatives ($/Mcfe)	$	0.74	$	(0.22	)
Average natural gas, oil and condensate and NGL sales price, including settled derivatives ($/Mcfe)	$	2.29	$	2.78

Production Costs:
Average production costs ($/Mcfe)	$	0.17	$	0.17
Average production taxes ($/Mcfe)	$	0.05	$	0.07
Average midstream gathering and processing ($/Mcfe)	$	0.60	$	0.62
Total production costs, midstream costs and production taxes ($/Mcfe)	$	0.82	$	0.86

Lease Operating Expenses

Table of Contents



	Three months ended March 31,
	2020		2019		change
	($ In thousands, except per unit)
Lease operating expenses
Utica	$	11,185	$	11,827	(5	)%
SCOOP	4,769		3,614		32	%
Other⁽¹⁾	32		4,366		(99	)%
Total lease operating expenses	$	15,986	$	19,807	(19	)%

Lease operating expenses per Mcfe
Utica	$	0.15	$	0.13	15	%
SCOOP	0.21		0.15		39	%
Other⁽¹⁾	0.71		4.83		(85	)%
Total lease operating expenses per Mcfe	$	0.17	$	0.17	(4	)%

_____________________


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

The decrease in total lease operating expenses ("LOE"), not including ~~a $35.5 million impairment~~production taxes, for the three months ended March 31, 2020 as compared to the three months ended March 31, 2019 was primarily the result of overall decreases in production. Per unit LOE was relatively flat for the three months ended March 31, 2020 as compared to the three months ended March 31, 2019.

Production Taxes



	Three months ended March 31,
	2020		2019		change
	($ In thousands, except per unit)
Production taxes	$	4,799	$	7,921	(39	)%
Production taxes per Mcfe	$	0.05	$	0.07	(28	)%

The decrease in production taxes was primarily related to a decrease in realized prices and production for the three months ended March 31, 2020 as compared to the three months ended March 31, 2019.

Midstream Gathering and Processing Expenses



	Three months ended March 31,
	2020		2019		change
	($ In thousands, except per unit)
Midstream gathering and processing expenses	$	57,896	$	70,282	(18	)%
Midstream gathering and processing expenses per Mcfe	$	0.60	$	0.62	(2	)%

The decrease in Midstream gathering and processing expenses was primarily related to a decrease in our ~~investment~~production for the three months ended March 31, 2020 as compared to the three months ended March 31, 2019.

Depreciation, Depletion and Amortization

Table of Contents



	Three months ended March 31,
	2020		2019		change
	($ In thousands, except per unit)
Depreciation, depletion and amortization	$	78,028	$	118,433	(34	)%
Depreciation, depletion and amortization per Mcfe	$	0.81	$	1.04	(22	)%

Depreciation, depletion and amortization ("DD&A") expense consisted of $75.4 million in ~~Mammoth Energy,~~depletion of oil and natural gas properties and $2.6 million in depreciation of other property and equipment, compared to $115.2 million in depletion of oil and natural gas properties and $3.2 million in depreciation of other property and equipment for the three months ended March 31, 2019. The decrease in DD&A was due to both a ~~$571.4~~decrease in our depletion rate as a result of a decrease in our amortization base from full cost ceiling test impairments recorded during 2019, as well as a decrease in our production.

Impairment of Oil and Gas Properties. During the three months ended March 31, 2020, we had a $553.3 million oil and natural gas properties impairment charge related primarily to the decline in commodity prices, ~~a $43.4 million increase in DD&A~~compared to no impairment charge of oil and ~~a $2.7 million decrease in gain on sale of equity method investments, partially offset by a $23.6 million gain on debt extinguishment and a $144.0 million increase in income tax benefit for~~gas properties during the three months ended ~~September 30, 2019 as compared~~March 31, 2019.

Based on prices for the last nine months and the short-term pricing outlook for the second quarter of 2020, we expect to recognize additional full cost impairment in the ~~three months ended September 30, 2018. Additional impairments~~second quarter of ~~oil and natural gas properties are expected to occur in upcoming quarters should commodity prices continue below the average of the previous 12 months. However, the~~2020. The amount of any future impairments is difficult to predict as it depends on changes in commodity prices, production rates, proved reserves, evaluation of costs excluded from amortization, future development costs and production costs. ~~The gain on sale of equity investments in 2018 was the result of the sale of Mammoth Energy common stock during 2018.~~

Equity Investments



	Three months ended March 31,
	2020		2019			change
	($ In thousands, except per unit)
Loss (income) from equity method investments, net	$	10,789	$	(4,273	)	(352	)%

~~Natural Gas, Oil and NGL Revenues~~. For the three months ended September 30, 2019, we reported oil and natural gas revenues of $285.2 million as compared to oil and natural gas revenues of $361.0 million during the same period in 2018. This $75.8 million, or 21%,The decrease in ~~revenues was~~income from equity method investments is primarily ~~attributable to the following:~~

~~A $21.1 million decrease in oil and condensate sales without the impact of derivatives due~~related to a ~~25% decrease in oil and condensate market prices and a 29% decrease in oil and condensate sales volumes.~~

~~A $33.5~~$10.6 million ~~decrease in NGLs sales without the impact of derivatives due to a 48% decrease in NGLs market prices and a 27% decrease in NGLs sales volumes.~~

~~A $57.9 million decrease in natural gas sales without the impact of derivatives due to a 29% decrease in natural gas market prices, partially offset by an 11% increase in natural gas sales volumes.~~

A $1.0 million decrease in natural gas, oil and condensate and NGLs sales due to an unfavorable change in the fair value of the contingent consideration arrangement related to the Louisiana asset sale.

~~These decreases were partially offset by:~~

A $37.7 million increase in natural gas, oil and condensate and NGLs sales due to a favorable change in gains and losses from derivative instruments. Of the total change, $87.7 million was due to favorable changes in settlementsloss related to our ~~derivative positions, partially offset by $50.0 million~~investment in unfavorable change in the fair value of our open derivative positions in each period. The unfavorable change in fair value of our open derivative positions is primarily a result of new options contracts entered intoMammoth Energy during the three months ended ~~September 30, 2019, partially offset by fair value gain~~March 31, 2020. See Note 4 to our consolidated financial statements for further discussion on ~~swap contracts as a result of the decrease in forward curve prices for natural gas from the previous reporting period.~~our equity investments.

General and Administrative Expenses



	Three months ended March 31,
	2020			2019			change
	($ In thousands, except per unit)
General and administrative expenses, gross	$	24,652		$	20,441		21	%
Reimbursed from third parties	$	(3,052	)	$	(2,689	)	13	%
Capitalized general and administrative expenses	$	(5,431	)	$	(7,695	)	(29	)%
General and administrative expenses, net	$	16,169		$	10,057		61	%

General and administrative expenses, net per Mcfe	$	0.17		$	0.09		89	%

The ~~following table summarizes our oil~~increase in general and ~~condensate, natural gas~~administrative expenses, gross was due primarily due to an increase in non-recurring legal and ~~NGLs production and related pricing~~consulting charges for the three months ended ~~September 30, 2019,~~March 31, 2020 as compared to ~~such data~~the three months ended March 31, 2019. The decrease in capitalized general and administrative expenses was due to lower development activities for the three months ended ~~September 30, 2018:~~March 31, 2020 as compared to the three months ended March 31, 2019.

Interest Expense

4138

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Three months ended September 30,
2019 2018
($ In thousands)
Natural gas sales
Natural gas production volumes (MMcf) 130,071
116,994

Total natural gas sales $ 213,227
$ 271,167

Natural gas sales without the impact of derivatives ($/Mcf) $ 1.64
$ 2.32
Impact from settled derivatives ($/Mcf) $ 0.57
$ 0.08
Average natural gas sales price, including settled derivatives ($/Mcf) $ 2.21
$ 2.40

Oil and condensate sales
Oil and condensate production volumes (MBbls) 474
665

Total oil and condensate sales $ 24,550
$ 45,682

Oil and condensate sales without the impact of derivatives ($/Bbl) $ 51.75
$ 68.73
Impact from settled derivatives ($/Bbl) $ 4.65
$ (14.76 )
Average oil and condensate sales price, including settled derivatives ($/Bbl) $ 56.40
$ 53.97

NGLs sales
NGLs production volumes (MGal) 52,951
72,427

Total NGLs sales $ 20,324
$ 53,776

NGLs sales without the impact of derivatives ($/Gal) $ 0.38
$ 0.74
Impact from settled derivatives ($/Gal) $ 0.11
$ (0.07 )
Average NGLs sales price, including settled derivatives ($/Gal) $ 0.49
$ 0.67

Natural gas, oil and condensate and NGLs sales
Natural gas equivalents (MMcfe) 140,482
131,328

Total natural gas, oil and condensate and NGLs sales $ 258,101

$ 370,625

Natural gas, oil and condensate and NGLs sales without the impact of derivatives ($/Mcfe) $ 1.84
$ 2.82
Impact from settled derivatives ($/Mcfe) $ 0.58
$ (0.04 )
Average natural gas, oil and condensate and NGLs sales price, including settled derivatives ($/Mcfe) $ 2.42
$ 2.78

Production Costs:
Average production costs ($/Mcfe) $ 0.16
$ 0.17
Average production taxes ($/Mcfe) $ 0.05
$ 0.07
Average midstream gathering and processing ($/Mcfe) $ 0.56
$ 0.60
Total production costs, midstream costs and production taxes ($/Mcfe) $ 0.77
$ 0.84



	Three months ended March 31,
	2020			2019
	($ In thousands, except per unit)
Interest expense on senior notes	29,119			32,281
Interest expense on revolving credit agreement	2,165			2,255
Interest expense on construction loan and other	340			266
Capitalized interest	(187		)	(766		)
Amortization of loan costs	1,553			1,585
Total interest expense	$	32,990		$	35,621

Interest expense per Mcfe	$	0.34		$	0.31

Weighted average debt outstanding under revolving credit facility	$	81,978		$	77,278

~~Table of Contents~~

~~Lease Operating Expenses. Lease operating expenses ("LOE") not including production taxes increased to $22.5 million~~Decrease in interest expense for ~~the~~ three months ended September 30, 2019 from $22.3 million for the three months ended September 30, 2018. This $0.2 million, or 1%, increase was primarily the result of an increase in location repairs and disposal costs, partially offset by a decrease in property taxes. However, due to a 7% increase in our production volumes for the three months ended September 30, 2019March 31, 2020 as compared to the three months ended ~~September 30, 2018,~~March 31, 2019 was primarily due to continued repurchases of our ~~per unit LOE decreased by 6% from $0.17 per Mcfe to $0.16 per Mcfe.~~senior notes.

~~Production~~Income Taxes. ~~Production taxes decreased $2.7~~We recorded income tax expense of $7.3 million ~~or 29%,~~for three months ended March 31, 2020 compared to ~~$6.6 million~~no income tax expense for the three months ended September 30, 2019 from $9.3 million for the three months ended September 30, 2018. This decrease was primarily due to a decrease in commodity prices, as taxes in Ohio are assessed off of value, and the sale of our Louisiana assets, partially offset by an increase in the production tax rate associated with our SCOOP production.

~~Midstream Gathering and Processing Expenses~~. Midstream gathering and processing expenses decreased to $78.4 million for the three months ended September 30, 2019 from $78.9 million for the same period in 2018. This $0.5 million, or 1%, decrease was primarily attributable to a decrease in production volumes related to our Utica Shale non-operated properties partially offset by an increase in our production volumes related to both our Utica Shale operated properties and SCOOP non-operated properties.

~~Depreciation, Depletion and Amortization~~. Depreciation, depletion and amortization ("DD&A") expense increased to $163.3 million for the three months ended September 30, 2019, and consisted of $160.5 million in depletion of oil and natural gas properties and $2.8 million in depreciation of other property and equipment, as compared to total DD&A expense of $119.9 million for the three months ended September 30, 2018. This $43.4 million, or 36%, increase was primarily due to an increase in our depletion rate as a result of a decrease in our total proved reserves volumes used to calculate our total DD&A expense, as well as an increase in our production.

~~Impairment of Oil and Gas Properties.~~ During the three months ended September 30, 2019, we had a $571.4 million oil and natural gas properties impairment charge related primarily to the decline in commodity prices, compared to no impairment charge of oil and gas properties in 2018. If prices of natural gas, oil and NGL continue to decline, the Company may be required to further write down the value of its oil and natural gas properties, which could negatively affect its results of operations.

~~General and Administrative Expenses~~. Net general and administrative expenses decreased to $14.7 million for the three months ended September 30, 2019 from $15.8 million for the three months ended September 30, 2018. This $1.1 million, or 7%, decrease was primarily due to decreases in salaries and benefits, consulting fees and travel expense, partially offset by increases in legal expense. In addition, for the three months ended September 30, 2019, we decreased our unit general and administrative expense by 17% to $0.10 per Mcfe from $0.12 per Mcfe for the three months ended September 30, 2018.

~~Interest Expense~~. Interest expense increased to $34.1 million for the three months ended September 30, 2019 as compared to $33.3 million for the three months ended September 30, 2018 due primarily to increased borrowings on our revolving credit facility as compared to the same period in 2018, partially offset by a decrease in outstanding senior notes as a result of debt repurchases. In addition, total weighted average debt outstanding under our revolving credit facility was $223.1 million for the three months ended September 30, 2019 as compared to $74.0 million debt outstanding under such facility.March 31, 2019. As of September 30, 2019, amounts borrowed under our revolving credit facility bore interest at a weighted average rate of 3.52%. In addition, we capitalized approximately $1.0 million and $1.6 million in interest expense to undeveloped oil and natural gas properties during the three months ended September 30, 2019 and 2018, respectively. This $0.6 million decrease in capitalized interest in the 2019 period was primarily the result of changes to our development plan for our oil and natural gas properties.

~~Income Taxes. As of September 30, 2019,~~March 31, 2020, we had a federal net operating loss carryforward of approximately $1.4 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. During the three months ending September 30, 2019, management determined there was sufficient positive evidence that it was more likely than not that the federal and some state net operating loss carryforwards should be realized and recorded a discrete tax benefit of $27.7 million. We will maintainAt March 31, 2020, a valuation allowance of ~~$5.0~~$756.7 million has been maintained against the net deferred tax ~~asset for certain~~asset. Income tax ~~attributes for which we have determined it is more likely than not those attribute carryforwards will expire prior to utilization.~~

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~~Comparison of~~expense during the ~~Nine Month Periods Ended September 30, 2019 and 2018~~

~~We reported net loss of $187.6 million for the nine~~three months ended September 30, 2019 as compared to net income of $296.6 million for the nine months ended September 30, 2018. This $484.2 million period-to-period decrease was due primarily to a $199.7 million increase in loss from equity method investments, including a $160.8 million impairment related to our investment in Mammoth Energy, a $124.8 million decrease in gain on sale of equity method investments, a $571.4 million oil and natural gas properties impairment chargeMarch 31, 2020 is related to the decline in commodity prices, a $53.8 million increase in DD&A and a $6.2 million increase in midstream gathering and processing expenses, partially offset by a $323.3 million increase in income tax benefit, a $125.7 million increase in natural gas, oil and NGL revenues and a $23.6 million increase in gain on debt extinguishment for the nine months ended September 30, 2019 as compared to the nine months ended September 30, 2018. Additional impairments of oil and natural gas properties are expected to occur in upcoming quarters should commodity prices continue below the average of the previous 12 months. However, the amount of any future impairments is difficult to predict as it depends on changes in commodity prices, production rates, proved reserves, evaluation of costs excluded from amortization, future development costs and production costs. The gain on sale of equity investments in 2018 was a result of the sale of our interest in Strike Force Midstream LLC ("Strike Force") and the sale of Mammoth Energy common stock during 2018.

~~Oil and Gas Revenues~~. For the nine months ended September 30, 2019, we reported oil and natural gas revenues of $1.1 billion as compared to oil and natural gas revenues of $939.1 million during the same period in 2018. This $125.7 million, or 13%, increase in revenues was primarily attributable to the following:

A $275.9 million increase in natural gas, oil and condensate and NGLs sales due to a favorable change in gains and losses from derivative instruments. Of the total change, $204.8 million was due to favorable changes in the fair value of our open derivative positions in each period and $71.1 million was due to a favorable change in settlements related to our derivative positions. The favorable change in fair value of our open derivative positions is primarily a result of the decrease in the forward curve prices for natural gas from the previous reporting period.

~~These increases were partially offset by:~~


•	A ~~$38.8 milliondecrease~~ ~~in natural gas sales without the impact of derivatives due to a 10% decrease in natural gas market prices, partially offset by a~~ 5%~~increase~~ ~~in natural gas sales volumes.~~


•	~~A $46.7 million decrease in oil and condensate sales without the impact of derivatives due to a~~ ~~20%decrease~~ ~~in oil and condensate sales volumes and a 17% decrease in oil and condensate market prices.~~


•	~~A $63.7 million decrease in NGLs sales without the impact of derivatives due to~~ ~~a 35% decrease in~~ ~~NGLs market prices and a 16% decrease in NGLs sales volumes.~~

The following table summarizes our oil and condensate, natural gas and NGLs production and related pricing for the nine months ended September 30, 2019, as compared to such data for the nine months ended September 30, 2018:

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Nine months ended September 30,
2019 2018
($ In thousands)
Natural gas sales
Natural gas production volumes (MMcf) 343,753
327,272

Total natural gas sales $ 714,500
$ 753,261

Natural gas sales without the impact of derivatives ($/Mcf) $ 2.08
$ 2.30
Impact from settled derivatives ($/Mcf) $ 0.20
$ 0.14
Average natural gas sales price, including settled derivatives ($/Mcf) $ 2.28
$ 2.44

Oil and condensate sales
Oil and condensate production volumes (MBbls) 1,735
2,166

Total oil and condensate sales $ 93,942
$ 140,687

Oil and condensate sales without the impact of derivatives ($/Bbl) $ 54.13
$ 64.96
Impact from settled derivatives ($/Bbl) $ 1.50
$ (10.28 )
Average oil and condensate sales price, including settled derivatives ($/Bbl) $ 55.63
$ 54.68

NGLs sales
NGLs production volumes (MGal) 165,970
196,695

Total NGLs sales $ 78,136
$ 141,883

NGLs sales without the impact of derivatives ($/Gal) $ 0.47
$ 0.72
Impact from settled derivatives ($/Gal) $ 0.06
$ (0.06 )
Average NGLs sales price, including settled derivatives ($/Gal) $ 0.53
$ 0.66

Natural gas, oil and condensate and NGLs sales
Gas equivalents (MMcfe) 377,875
368,366

Total natural gas, oil and condensate and NGLs sales $ 886,578
$ 1,035,831

Natural gas, oil and condensate and NGLs sales without the impact of derivatives ($/Mcfe) $ 2.35
$ 2.81
Impact from settled derivatives ($/Mcfe) $ 0.21
$ 0.03
Average natural gas, oil and condensate and NGLs sales price, including settled derivatives ($/Mcfe) $ 2.56
$ 2.84

Production Costs:
Average production costs ($/Mcfe) $ 0.17
$ 0.17
Average production taxes ($/Mcfe) $ 0.06
$ 0.07
Average midstream gathering and processing ($/Mcfe) $ 0.58
$ 0.58
Total production costs, midstream costs and production taxes ($/Mcfe) $ 0.81
$ 0.82

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~~Lease Operating Expenses. Lease operating expenses not including production taxes increased to$64.7 million~~ ~~for the nine months ended September 30, 2019 from $64.1 million for the nine months ended September 30, 2018. This~~ ~~$0.6 million~~, or 1%, increase was primarily the result of an increase in expenses related to location repair, disposal costs and overhead, partially offset by a decrease in wireline services, facility maintenance expense and insurance.

~~Production Taxes. Production taxes~~ ~~decreased~~ to $22.6 million for the nine months ended September 30, 2019 from $23.9 million for the same period in 2018. This $1.3 million, or 5%, decrease was primarily related to a decrease in commodity prices, as taxes in Ohio are assessed off of value, and the sale of our Louisiana assets, partially offset by an increase in the production tax rate associated with our SCOOP production.

~~Midstream Gathering and Processing Expenses. Midstream gathering and processing expenses~~ ~~increased~~ to ~~$220.7 million~~ ~~for the nine months ended September 30, 2019 from $214.5 million for the same period in 2018. This~~ ~~$6.2 million, or~~ 3%, ~~increase~~ was primarily attributable to midstream expenses related to our increased production volumes in the Utica Shale and SCOOP resulting from our 2018 and 2019 drilling activities as well as routine contract escalations associated with our Utica Shale production.

~~Depreciation, Depletion and Amortization~~. Depreciation, depletion and amortization expense increased to $406.7 million for the nine months ended September 30, 2019, and consisted of $398.2 million in depletion of oil and natural gas properties and $8.5 million in depreciation of other property and equipment, as compared to total DD&A expense of $352.8 million for the nine months ended September 30, 2018. This $53.8 million, or 15%, increase was primarily due to an increase in our depletion rate as a resultrecognition of a ~~decrease in our total proved reserves volumes used to calculate our total DD&A expense and an increase in our production.~~

~~Impairment of Oil and Gas Properties.~~ ~~During the nine months ended September 30, 2019, we had~~valuation allowance against a $571.4 million oil and natural gas properties impairment charge related primarily to the decline in commodity prices, compared to no impairment charge of oil and gas properties in 2018. If prices of natural gas, oil and NGL continue to decline, the Company may be required to further write down the value of its oil and natural gas properties, which could negatively affect its results of operations.

~~General and Administrative Expenses. Net general and administrative expenses~~ ~~decreased~~ to ~~$39.5 million~~ ~~for the nine months ended September 30, 2019 from $43.0 million for the nine months ended September 30, 2018. This~~ ~~$3.5 million, or~~ 8%, ~~decrease~~ ~~was primarily due to decreases in salaries and benefits, consulting fees and travel expense, partially offset by increases in tax services and computer support. In addition,~~ ~~for the nine months ended September 30, 2019, we~~ ~~decreased our unit general and administrative expense by~~ ~~17%~~ to ~~$0.10~~ ~~per Mcfe from $0.12 per Mcfe the nine months ended September 30, 2018.~~

~~Interest Expense. Interest expense increased to$103.1 million~~ for the nine months ended September 30, 2019 from $100.9 million for the nine months ended September 30, 2018 due primarily to increased borrowings on our revolving credit facility as compared to the same period in 2018, partially offset by a decrease in outstanding senior notes as a result of debt repurchases. Total weighted average debt outstanding under our revolving credit facility was $156.9 million for the nine months ended September 30, 2019 as compared to $91.3 million for the same period in 2018. Additionally, we capitalized approximately $2.8 million and $4.0 million in interest expense to undeveloped oil and natural gas properties during the nine months ended September 30, 2019 and September 30, 2018, respectively. This $1.2 million decrease in capitalized interest in the 2019 period was primarily the result of changes to our development plan for our oil and natural gas properties.

~~Income Taxes. As of September 30, 2019, we had a federal net operating loss carryforward of approximately $1.4 billion from prior years, in addition to numerous temporary differences, which gave rise to a net~~state deferred tax asset. ~~Quarterly, management performs~~On April 30, 2020, our Board of Directors approved the adoption of a ~~forecast of~~tax benefits preservation plan that is intended to protect value by preserving our ~~taxable income and analyzes other relevant factors~~ability 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~~use our deferred tax assets is established if, in management’s opinion, it is more likely than not that some portion will not be realized. During the nine months ending September 30, 2019, management determined there was sufficient positive evidence that it was more likely than not that the federal and some state net operating loss carryforwards should be realized and recorded a discrete tax benefit of $207.0 million. We will maintain a valuation allowance of $5.0 million against the net deferred tax asset for certain tax attributes, such as NOLs, to offset potential future income taxes for ~~which we have determined it is~~federal income tax purposes. See Note 16 of the notes to our consolidated financial statement for more ~~likely than not those attribute carryforwards will expire prior to utilization.~~information.

Liquidity and Capital Resources

Overview.

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Historically, our primary sources of ~~funds~~capital funding and liquidity have been our operating cash flow, ~~from our producing oil and natural gas properties,~~ borrowings under our revolving credit facility and issuances of equity and debt securities. Our ability to access ~~any of~~ these sources of funds can be significantly impacted by changes in capital markets, decreases in commodity prices and decreases in our production levels.

Based on our cash balance, forecasted cash flows from operating activities and availability under our revolving credit facility, we expect to be able to fund our planned capital expenditures, meet our debt service requirements and fund our other commitments and obligations for the next 12 months.

As of March 31, 2020, we had a cash balance of $1.6 million compared to $6.1 million as of December 31, 2019, and a net working capital deficit of $146.2 million as of March 31, 2020, compared to a net working capital deficit of $145.3 million as of December 31, 2019. As of March 31, 2020, our working capital deficit includes $0.7 million of debt due in the next 12 months. Our total principal debt as of March 31, 2020 was $1.9 billion compared to $2.0 billion as of December 31, 2019. As of March 31, 2020, we had $698.2 million of borrowing capacity available under the revolving credit facility, with outstanding borrowings of $65.0 million and $236.8 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.

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, ~~prices or~~ oil and NGL derivative activities, when combined with our sales of natural gas, ~~production.~~oil and NGL, allow us to predict with greater certainty the total revenue we will receive.

~~Net cash flow provided by operating activities was $617.4 million~~As of March 31, 2020, we had the following open natural gas, oil and NGL derivative instruments:

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Natural Gas Derivatives
Year	Type of Derivative Instrument	Index	Daily Volume (MMBtu/day)	Weighted Average Price
2020	Swaps	NYMEX Henry Hub	432,000	$	2.92
2020	Basis Swaps	Various	70,000	$	(0.12	)
2022	Sold Call Options	NYMEX Henry Hub	628,000	$	2.90
2023	Sold Call Options	NYMEX Henry Hub	628,000	$	2.90
Oil Derivatives
Year	Type of Derivative Instrument	Index	Daily Volume (Bbls/day)	Weighted Average Price
2020	Swaps	NYMEX WTI	6,000	$	59.83
NGL Derivatives
Year	Type of Derivative Instrument	Index	Daily Volume (Bbls/day)	Weighted Average Price
2020	Swaps	Mont Belvieu C3	500	$	21.63

See Note 10 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 ~~nine months ended September 30, 2019 as compared to $630.8 million for the same period in 2018. This $13.4 million decrease was primarily the result~~value of ~~a decrease in cash receipts from~~ our oil swaps by monetizing our remaining position in April 2020 and ~~natural gas purchasers due~~entered into additional contracts to ~~a 7% decrease~~hedge our remaining 2020 and 2021 production in ~~net revenues after giving effect to settled derivative instruments~~April and ~~an increase in our operating expenses. In addition, we received $2.5 million in dividends from our investment in Mammoth Energy during the nine months ended September 30, 2019.~~

Net cash used in investing activities for the nine months ended September 30, 2019 was $638.6 million as compared to $554.6 million for the same period in 2018. During the nine months ended September 30, 2019, we spent $646.5 million in additions to oil and natural gas properties, of which $364.6 million was spent on our 2019 drilling and completion activities, $183.6 million was spent on expenses attributable to wells spud, completed and recompleted during 2018, $34.9 million was spent on lease related costs, primarily the acquisition of leases in the Utica Shale and $32.5 million was spent on tubulars, with the remainder attributable mainly to future location development and capitalized general and administrative expenses. During the nine months ended September 30, 2019, we invested $0.4 million in Grizzly and received a distribution of $2.1 million from Tatex Thailand II, LLC ("Tatex II"). We did not make any investments in our other equity investments during the nine months ended September 30, 2019.

Net cash used in financing activities for the nine months ended September 30, 2019 was $20.9 million as compared to $51.2 million for the same period in 2018. The 2019 amount used in financing activities is primarily attributable to purchases under our stock repurchase program of approximately $30.0 million and repurchase of senior notes of $79.5 million, partially offset by net borrowings under our credit facility.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 ~~September 30, 2019,~~March 31, 2020, we had a borrowing base of ~~$1.4~~$1.2 billion, with an elected commitment of $1.0 billion, and ~~$135.0~~$65.0 million in borrowings outstanding. Total funds available for borrowing under our revolving credit facility, after giving effect to an aggregate of ~~$248.6~~$236.8 million of outstanding letters of credit, were ~~$616.4~~$698.2 million as of ~~September 30, 2019.~~March 31, 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.

Advances under our 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 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 agent shall inquire as the “London Interbank Offered Rate” for deposits in U.S. dollars. At September 30, 2019, amounts borrowed under our credit facility bore interest at ~~a weighted average rate of~~ ~~3.52%.~~

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; ~~make~~undertake fundamental ~~changes;~~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; ~~and~~ enter into transactions with their ~~affiliates.~~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 funded debt to EBITDAX (net income, excluding (i) any non-cash revenue or expense associated with swap contracts resulting from ASC 815 and (ii) any cash or non-cash revenue or expense attributable to minority investment plus without duplication and, in(as defined under the ~~case of expenses, to the extent deducted from revenues in determining net income, the sum of (a) the aggregate amount of consolidated interest expense for~~

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such period, (b) the aggregate amount of income, franchise, capital or similar tax expense (other than ad valorem taxes) for such period, (c) all amounts attributable to depletion, depreciation, amortization and asset or goodwill impairment or writedown for such period, (d) all other non-cash charges, (e) exploration costs deducted in determining net income under successful efforts accounting, (f) actual cash distributions received from minority investments, (g) to the extent actually reimbursed by insurance, expenses with respect to liability on casualty events or business interruption, and (h) all reasonable transaction expenses related to dispositions and acquisitions of assets, investments and debt and equity offerings (provided that expenses related to any unsuccessful dispositions will be limited to $3.0 million in the aggregate) for a twelve-month periodrevolving credit agreement) may not be greater than 4.00 to ~~1.00;~~1.00 for the twelve-month period of the end of each fiscal quarter; and (2) the ratio of EBITDAX to interest expense for athe twelve-month period at the end of each fiscal quarter may not be less than 3.00 to 1.00. We were in compliance with these financial covenants at March 31, 2020.

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 a requirement to maintain a ratio of Net Secured Debt to EBITDAX 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, 2019.~~31, 2021, and added a limitation on the repurchase of unsecured notes, among other amendments. We remained in compliance with our financial covenants under the revolving credit facility following the amendment.

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 from April 21, 2015, payable semi-annually on May 1 and November 1 of each year, commencing on November 1, 2015. The 2023 Notes will mature on May 1, 2023.

On October 14, 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 from October 14, 2016, payable semi-annually on April 15 and October 15 of each year, commencing on April 15, 2017. The 2024 Notes will mature on October 15, 2024.

On December 21, 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 from December 21, 2016, payable semi-annually on May 15 and November 15 of each year, commencing on May 15, 2017. The 2025 Notes will mature on May 15, 2025.

On October 11, 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 from October 11, 2017, payable semi-annually on January 15 and July 15 of each year, commencing on January 15, 2018. The 2026 Notes will mature on January 15, 2026.

During the three months ended ~~September 30, 2019,~~March 31, 2020, we used borrowings under our revolving credit facility to repurchase in the open market approximately ~~$104.4~~$25.9 million aggregate principal amount of our outstanding Notes for ~~$80.3 million.~~$10.2 million. This included approximately ~~$10.0 million principal amount of the 2023 Notes, $19.2~~$7.5 million principal amount of the 2024 Notes, ~~$22.7~~$8.2 million principal amount of the 2025 Notes, and ~~$52.5~~$10.2 million principal amount of the 2026 Notes. We recognized a ~~$23.6~~$15.3 million gain on debt extinguishment, which included retirement of unamortized issuance costs and fees associated with the repurchased debt.

~~All of~~Subject to restrictions in our ~~existing and future restricted subsidiaries that guarantee our secured~~own revolving credit facility, or certain other debt guarantee the Notes, provided, however, that the Notes are not guaranteed by Grizzly Holdings or Mule Sky, and will not be guaranteed by any of our future unrestricted subsidiaries. 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 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.

If we experience a change of control (as defined in the senior note indentures relating to the Notes), we will be required to make an offer to repurchase the Notes and at a price equal to 101% of the principal amount thereof, plus accrued and unpaid interest, if any, to the date of repurchase. If we sell certain assets and fail to use the proceeds in a manner specified in our senior note indentures, we will be required to use the remaining proceeds to make an offer to repurchase the Notes at a price equal to 100% of the principal amount thereof, plus accrued and unpaid interest, if any, to the date of repurchase. The senior note indentures relating to the Notes contain certain covenants that, subject to certain exceptions and qualifications, among other things, limit our ability and the ability of our restricted subsidiaries to incur or guarantee additional indebtedness, make certain investments, declare or pay dividends or make distributions on capital stock, prepay subordinated indebtedness, sell assets including capital stock of restricted subsidiaries, agree to payment restrictions affecting our restricted subsidiaries, consolidate, merge, sell or otherwise dispose of all or substantially all of our assets, enter into transactions with affiliates, incur

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liens, engage in business other than the oil and gas business and designate certain of our subsidiaries as unrestricted subsidiaries. Under the indentures relating to the Notes, certain of these covenants are subject to termination upon the occurrence of certain events, including in the event the Notes are ranked as “investment grade.”

In connection with the issuance of the 2024 Notes, 2025 Notes and 2026 Notes, we and our subsidiary guarantors entered into registration rights agreements, pursuant to which we agreed to file a registration statement with respect to offers to exchange the 2024 Notes, 2025 Notes and 2026 Notes, as applicable, for new issues of substantially identical debt securities registered under the Securities Act. The exchange offers for the 2024 Notes and 2025 Notes were completed on September 13, 2017, and the exchange offer for the 2026 Notes was completed on March 22, 2018.

We may use a combination of cash and ~~borrowings~~borrowing under our

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

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

~~Construction Loan.~~

On June 4, 2015, we entered into a construction loan agreement (the "construction loan") with InterBank for the construction of our new corporate headquarters in Oklahoma City, which was substantially completed in December 2016. The construction loan allows for maximum principal borrowings of $24.5 million and required us to fund 30% of the cost of the construction before any funds could be drawn, which occurred in January 2016. Interest accrues daily on the outstanding principal balance at a fixed rate of 4.50% per annum and we make monthly payments of interest and principal. The final payment is due June 4, 2025. As of September 30, 2019, the total borrowings under the construction loan were approxim~~ately~~ ~~$22.7 million.~~

Capital Expenditures.

Our ~~recent~~ capital commitments have been primarily for the execution of our drilling programs ~~for acquisitions in the Utica Shale~~ and ~~our SCOOP acquisition in 2017, and for investments in entities that may provide services to facilitate the development~~discounted repurchases of our ~~acreage.~~senior notes. Our capital investment strategy is ~~to continue to (1) increase cash flow generated from our operations by undertaking new drilling and workover projects to exploit~~focused on prudently developing our existing properties ~~subject~~ to ~~economic~~generate sustainable cash flow considering current and ~~industry conditions~~forecasted commodity prices while also selectively pursuing mergers or acquisitions in our current operating regions in an effort to gain scale and ~~(2) pursue select acquisition and disposition opportunities.~~deepen our drilling inventory.

~~Of our net reserves at December 31, 2018, 55.4% were categorized as proved undeveloped.~~ Our proved reserves will generally decline as reserves are depleted, except to the extent that we conduct successful exploration or development activities or acquire properties containing proved developed reserves, or both. To realize reserves and increase production, we must continue our exploratory drilling, undertake other replacement activities or use third parties to accomplish those activities.

~~For further discussion on activities related to our~~ capital expenditures ~~incurred through September 30, 2019 see 2019 Production~~for 2020 are currently estimated to be in the range of $265.0 million to $285.0 million for drilling and ~~Drilling Activity section above.~~

~~As of September 30, 2019, our net investment in Grizzly was approximately~~ ~~$49.5~~ ~~million. We do not currently anticipate any material capital expenditures in 2019 related to Grizzly’s activities.~~

completion expenditures. In response to current declining forward natural gas prices, we are shifting to building an organization that is focused on disciplined capital allocation, cash flow generation and a commitment to executing a thoughtful, clearly communicated business plan that enhances value for all of our stockholders. We plan to maximize results with the core assets in our portfolio today and focus on returns that will allow us to operate within operating cash flow in 2019. As a result,addition, we currently expect ~~2019 capital expenditures~~ to ~~be approximately 29% lower than 2018.~~

Our operated drilling and completion capital expenditures for 2019 were weighted to the first half of the year. For the nine months ended September 30, 2019 we incurred $423.7 million for operated drilling and completion capital expenditures and $72.6 million for non-operated drilling and completion capital expenditures. We currently expect to incur $40.0spend $20.0 million to ~~$50.0~~$25.0 million in ~~2019~~2020 for non-drilling and completion expenditures, which includes acreage expenses, primarily lease extensions in the Utica ~~Shale, of which $33.1 million was incurred as of September 30, 2019. Additionally, we are pursuing the sale of certain non-operated Utica Shale interests. Net~~Shale. The midpoint of the ~~planned divestiture of certain non-operated interests, we continue to expect our capital expenditures to be within our previously provided guidance range of $565.0 million to $600.0 million. The 2019~~2020 range of capital expenditures is 51% lower than the ~~$814.7~~$602.5 million ~~incurred~~spent in ~~2018,~~2019, primarily due to ~~the decrease~~our decision to reduce capital activity in

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~~current~~ response to lower commodity prices, specifically natural gas prices, and our desire to fund our capital development program ~~within cash flow, as well as to generate free cash flow.~~

In January 2019, our board of directors approved a new stock repurchase program to acquire a portion of our outstanding common stock within a 24 month period. We intend to purchase shares under the repurchase program opportunisticallyprimarily with ~~available funds primarily from~~ cash flow from ~~operations~~operations. As a result of our decreased capital spending program for 2020 and ~~sale~~the impact of ~~non-core assets while maintaining sufficient liquidity~~our 2019 property divestitures, we expect our production volumes in 2020 to ~~fund our capital development programs.~~be approximately 18% lower than 2019. Coupled with forecasted lower commodity prices, we expect 2020 revenues, operating cash flows and EBITDA to be 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 believe that our cash flow from operations, cash on hand and borrowings under our ~~revolving credit facility~~loan agreements will be sufficient to meet our normal recurring operating needs and capital requirements for the next twelve months. We ~~believe that our strong liquidity position, hedge portfolio and conservative balance sheet position us well~~have the ability to react quickly to changing commodity prices and accelerate or decelerate our activity within ~~the Utica Shale and the SCOOP~~our operating areas as ~~the~~ market conditions warrant. Notwithstanding the foregoing, in the event commodity prices decline from current levels or our capital or other costs increase ~~our equity method investments require additional contributions and/or we pursue additional equity method investments or acquisitions,~~ we may be required to obtain additional funds which we would seek to do through ~~traditional~~ borrowings, offerings of debt or equity securities or other means, including the sale of assets. To the extent that access to the 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 ~~new~~merger, acquisition and divestiture opportunities. ~~Needed capital~~Capital may not be available to us on acceptable terms or at ~~all.~~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.

Cash Flow from Operating Activities. Net cash flow provided by operating activities was $130.8 million for the three months ended March 31, 2020 as compared to $239.8 million for the same period in 2019. This decrease was primarily the result of a significant decrease in our realized gas price as well as decreases in our production volumes.

Divestitures. During the three months ended March 31, 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 of Funds. The following table presents the uses of our cash and cash equivalents for the three months ended March 31, 2020 and 2019:

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	Three months ended March 31,
	2020		2019
	(In thousands)
Oil and Natural Gas Property Expenditures:
Drilling and completion costs	97,538		194,526
Leasehold acquisitions	7,346		22,709
Other	8,860		24,156
Total oil and natural gas property expenditures	$	113,744	$	241,391
Other Uses of Cash and Cash Equivalents
Cash paid to repurchase senior notes	10,204		—
Principal payments on borrowings, net	55,106		151
Cash paid to repurchase common stock under approved stock repurchase program	—		28,212
Other	685		4,420
Total other uses of cash and cash equivalents	$	65,995	$	32,783
Total uses of cash and cash equivalents	$	179,739	$	274,174

Drilling and Completion Costs. During three months ended March 31, 2020, we spud seven gross and net and commenced sales from three gross and net wells in the Utica Shale for a total cost of approximately $95.8 million. During the three months ended March 31, 2020, we spud five gross (4.34 net) and commenced sales from four gross (3.76 net) wells in the SCOOP for a total cost of approximately $31.5 million.

During the three months ended March 31, 2020, no wells were spud or turned to sales by other operators on our Utica Shale acreage. In addition, 4.00 gross (0.01 net) wells were spud and 5.00 gross (0.03 net) wells were turned to sales by other operators on our SCOOP acreage during the three months ended March 31, 2020. We incurred total non-operated drilling and completion costs during the three months ended March 31, 2020 of approximately $3.4 million.

Commodity Price Risk

See Item 3. “Quantitative and Qualitative Disclosures about Market Risk” for information regarding our open fixed price swaps at ~~September 30, 2019.~~March 31, 2020.

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 of the notes to our consolidated financial statements for further discussion of the termination of our Master Services Agreement with Stingray Pressure Pumping LLC, a subsidiary of Mammoth Energy Services, Inc. and a related party. 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, ~~2018.~~ 2019.

Off-balance Sheet Arrangements

We may enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. As of ~~September 30, 2019,~~March 31, 2020, our material off-balance sheet arrangements and transactions include ~~$248.6~~$236.8 million in letters of credit outstanding against our ~~2019~~ revolving credit facility and ~~$63.0~~$105.1 million in surety bonds ~~issued~~issued. Both the letters of credit and surety bonds are being used as financial assurance on ~~midstream~~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 resources. See Note 89 to our consolidated financial statements for further discussion of the various financial guarantees we have issued.

Critical Accounting Policies and Estimates

As of ~~September 30, 2019,~~March 31, 2020, there have been no significant changes in our critical accounting policies from those disclosed in our ~~2018~~2019 Annual Report on Form 10-K.

~~New Accounting Pronouncements~~

~~In February 2016, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2016-02,~~ ~~Leases (Topic 842).~~ The standard supersedes the previous lease guidance by requiring lessees to recognize a right-to-use asset and lease liability on the balance sheet for all leases with lease terms of greater than one year while maintaining substantially similar classifications for financing and operating leases. Subsequent to ASU 2016-02, the FASB issued several related ASU’s to clarify the application of the lease standard. We adopted the new standard as of January 1, 2019 on a prospective basis using the simplified transition method permitted by ASU 2018-11, ~~Leases (Topic 842): Targeted Improvements.~~ ~~The comparative information has not been restated and continues to be reported under the historic accounting~~

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~~standards in effect for those periods. See Note 13 to our consolidated financial statements for further discussion of the lease standard.~~

~~In June 2016, the FASB issued ASU No. 2016-13,~~ ~~Financial Instruments-Credit Losses: Measurement of Credit Losses on Financial Instruments~~. This ASU amends guidance on reporting credit losses for assets held at amortized cost basis and available for sale debt securities. For assets held at amortized cost basis, this ASU eliminates the probable initial recognition threshold in current GAAP and instead, requires an entity to reflect its current estimate of all expected credit losses. The amendments affect loans, debt securities, trade receivables, net investments in leases, off balance sheet credit exposure, reinsurance receivables and any other financial assets not excluded from the scope that have the contractual right to receive cash. Additionally, in May 2019, the FASB issued ASU No. 2019-05, ~~Financial Instruments—Credit Losses (Topic 326): Targeted Transition Relief~~. The amendments in this update allow preparers to irrevocably elect the fair value option, on an instrument-by-instrument basis, for eligible financial assets measured at amortized cost basis upon adoption of 2016-13. The guidance is effective for periods after December 15, 2019, with early adoption permitted. We are in the process of designing processes and controls needed to comply with the requirements of the new standard. Although the standard will have an impact, we do not currently anticipate the ASU to have a material effect on our consolidated financial statements and related disclosures.

~~In August 2018, the FASB issued ASU No. 2018-13,~~ ~~Fair Value Measurement (Topic 820): Disclosure Framework—Changes to the Disclosure Requirements for Fair Value Measurement~~ which removes, modifies, and adds certain disclosure requirements on fair value measurements. The amendment will be effective for reporting periods beginning after December 15, 2019, and early adoption is permitted. We do not anticipate the new standard to have a material effect on our consolidated financial statements and related disclosures.

~~In August 2018, the FASB also issued ASU No. 2018-15,~~ ~~Intangibles—Goodwill and Other—Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract~~, which aligns the accounting for costs associated with implementing a cloud computing arrangement in a hosting arrangement that is a service contract with the accounting for implementation costs incurred to develop or obtain internal-use software. The amendment will be effective for reporting periods beginning after December 15, 2019, and early adoption is permitted. We do not anticipate the new standard to have a material effect on our consolidated financial statements and related disclosures.

~~In November 2018, the FASB issued ASU No. 2018-18,~~ ~~Collaborative Arrangements (Topic 808): Clarifying the Interaction Between Topic 808 and Topic 606~~, which provides guidance on how to assess whether certain transactions between participants in a collaborative arrangement should be accounted for within the ASU No. 2014-09 revenue recognition standard discussed above. The amendment will be effective for reporting periods beginning after December 15, 2019, and early adoption is permitted. We do not anticipate the new standard to have a material effect on our consolidated financial statements and related disclosures.

~~In July 2019, the FASB issued ASU No. 2019-07,~~ Codification Updates to SEC Sections, Amendments to SEC Paragraphs Pursuant to SEC Final Rule Releases No. 33-10532, Disclosure Update and Simplification, and Nos. 33-10231 and 33-10442, Investment Company Reporting Modernization, and Miscellaneous Updates. This ASU amends various SEC sections within the FASB Codification to align with the updated requirements of certain SEC final rules and includes miscellaneous updates to agree the language in the Codification to the electronic Code of Federal Regulations. ASU No. 2019-07 is effective upon issuance, and we have adopted the changes with no material impacts.



ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Natural Gas, Oil and Natural Gas Liquids Derivative Instruments. Our ~~revenues, operating~~ results ~~profitability, future rate~~ of ~~growth~~operations and ~~the carrying value~~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 ~~properties depend primarily upon~~storage inventory levels, industry decline rates for base production and weather trends. Executive management is involved in all risk management activities and the ~~prevailing prices~~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 and options. All of these are described in more detail below. We typically use swaps for ~~oil and natural gas. Historically,~~a large portion of the oil and natural gas ~~prices~~price risk we hedge. We have ~~been volatile and are~~also sold calls, taking advantage of premiums associated with market price volatility.

We determine the notional volume potentially subject to ~~fluctuations~~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 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 ~~response~~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 reversed. The actual fixed price on our derivative instruments is derived from the reference NYMEX price, as reflected in current NYMEX trading. The pricing dates of our derivative contracts follow NYMEX futures. 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 and discount factors. 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 ~~supply~~market conditions and ~~demand, market uncertainty and a variety~~other factors. See Note 10 of ~~additional factors, including: worldwide and domestic supplies~~the notes to our consolidated financial statements for further discussion of the fair value measurements associated with our derivatives.

As of March 31, 2020, our natural gas, oil and natural gas; the level of prices, and expectations about future prices, of oil and natural gas; the cost of exploring for, developing, producing and delivering oil and natural gas; the expected rates of declining current production; weather conditions, including hurricanes, that can affect oil and natural gas operations over a wide area; the level of consumer demand; the price and availability of alternative fuels; technical advances affecting energy consumption; risks associated with operating drilling rigs; the availability of pipeline capacity; the price and level of foreign imports; domestic and foreign governmental regulations and taxes; the abilityNGL derivative instruments consisted of the ~~members~~following types of ~~the~~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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Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls; political instability or armed conflict in oil and natural gas producing regions; and the overall economic environment.

These factors and the volatility of the energy markets make it extremely difficult to predict future oil and natural gas price movements with any certainty. During 2018, West Texas Intermediate ("WTI") prices ranged from $44.48 to $77.41 per barrel and the Henry Hub spot market price of natural gas ranged from $2.49 to $6.24 per MMBtu. On October 25, 2019, the WTI posted price for crude oil was $56.46 per Bbl and the Henry Hub spot market price for natural gas was $2.28 per MMBtu. If the prices of oil and natural gas decline from current levels, our operations, financial condition and level of expenditures for the development of our oil and natural gas reserves may be materially and adversely affected. In addition, lower oil and natural gas prices may reduce the amount of oil and natural gas that we can produce economically. This may result in our having to make substantial downward adjustments to our estimated proved reserves. If this occurs or if our production estimates change or our exploration or development activities are curtailed, full cost accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties. Reductions in our reserves could also negatively impact the borrowing base under our revolving credit facility, which could further limit our liquidity and ability to conduct additional exploration and development activities.


•	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.

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 ~~September 30, 2019:~~March 31, 2020:

Location Daily Volume (MMBtu/day) Weighted
Average Price
Remaining 2019 NYMEX Henry Hub 1,380,000
$ 2.81
2020 NYMEX Henry Hub 519,000
$ 2.88



	Location	Daily Volume (MMBtu/day)	Weighted Average Price
Remaining 2020	NYMEX Henry Hub	432,000	$	2.92

Location Daily Volume
(Bbls/day) Weighted
Average Price
Remaining 2019 NYMEX WTI 6,000
$ 60.81
2020 NYMEX WTI 6,000
$ 59.82



	Location	Daily Volume (Bbls/day)	Weighted Average Price
Remaining 2020	NYMEX WTI	6,000	$	59.83

Location Daily Volume
(Bbls/day) Weighted
Average Price
Remaining 2019 Mont Belvieu C2 1,000
$ 18.48
Remaining 2019 Mont Belvieu C3 4,000
$ 29.02
Remaining 2019 Mont Belvieu C5 1,000
$ 53.71



	Location	Daily Volume (Bbls/day)	Weighted Average Price
Remaining 2020	Mont Belvieu C3	500	$	21.63

We sold call options in exchange for a premium, and used the associated premiums to enhance the fixed price for a portion of the fixed price natural gas swaps primarily for 2020 listed above. Each call option has an established ceiling price. When the referenced settlement price is above the price ceiling established by these call options, we pay our counterparty an amount equal to the difference between the referenced settlement price and the price ceiling multiplied by the hedged contract volumes.


	Location	Daily Volume (MMBtu/day)	Weighted Average Price		Location	Daily Volume (MMBtu/day)	Weighted Average Price
Remaining 2019	NYMEX Henry Hub	30,000	$	3.10
2022	NYMEX Henry Hub	628,000	$	2.90	NYMEX Henry Hub	628,000	$	2.90
2023	NYMEX Henry Hub	628,000	$	2.90	NYMEX Henry Hub	628,000	$	2.90

~~For~~In addition, we entered into natural gas basis swap positions. As of March 31, 2020, the Company had the following natural gas 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	)

In April 2020, we early terminated our remaining 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 ~~portion~~cash settlement of approximately $40.5 million. Subsequent to this early termination, we entered into oil fixed price swap contracts for the second half of 2020 covering 2,000 Bbls per day of oil at a weighted average swap price of $35.60 per Bbl.

In April and May 2020, we entered into natural gas fixed price ~~swaps listed above, the counterparty has an option to extend the original terms an additional twelve months~~swap contracts for the ~~period January 2019 through December 2019. In December 2018, the counterparties chose to exercise all~~third quarter of 2020 covering approximately 20,000 MMBtu of natural gas per day at an average swap price of $2.50 per MMBtu and for the fourth quarter of 2020 covering approximately 170,000 MMBtu of natural gas per day at an average swap price of $2.64 per MMBtu.

Our fixed price ~~swaps, resulting~~swap contracts are tied to the commodity prices on NYMEX Henry Hub for natural gas and Mont Belvieu for propane, pentane and ethane. We will receive the fixed priced amount stated in ~~an additional 100,000~~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.

In April 2020, we entered into costless collars for 2021 covering approximately 250,000 MMBtu of natural gas per day at a weighted average floor price of ~~$3.05~~$2.46 per MMBtu ~~which is included~~and a weighted average ceiling price of $2.81 per MMBtu. The two-way price collars set a 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 ~~natural gas fixed price swaps listed above.~~various collars, we will cash-settle the difference with the counterparty.

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~~In addition, we have entered into natural gas basis swap positions. As of September 30, 2019, we had the following natural gas basis swap positions open:~~

~~Contingent Consideration Arrangement~~

The purchase and sale agreement for the sale of our non-core assets located in the WCBB and Hackberry fields of Louisiana included a contingent consideration arrangement that entitles us to receive bonus payments if commodity prices exceed specified thresholds. The calculated fair value of this contingent payment arrangement was approximately $1.1 million as of the closing date of the divestiture. 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.

~~Under our 2019 contracts, we have hedged approximately 91% to 94% of our estimated 2019 production.~~ Such arrangements may expose us to risk of financial loss in certain circumstances, including instances where production is less than expected or commodity prices increase. At ~~September 30, 2019,~~March 31, 2020, we had a net asset derivative position of ~~$85.5~~$100.9 million as compared to a net liability derivative position of ~~$54.4~~$8.3 million as of ~~September 30, 2018,~~March 31, 2019, related to our ~~fixed price swaps.~~hedging portfolio. Utilizing actual derivative contractual volumes, a 10% increase in underlying commodity prices would have reduced the fair value of these instruments by approximately ~~$139.1~~$63.9 million, while a 10% decrease in underlying commodity prices would have increased the fair value of these instruments by approximately ~~$124.3~~$53.2 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 ~~U.S.~~United States, or, if the eurodollar rates are elected, the eurodollar rates. At ~~September 30, 2019,~~March 31, 2020, we had ~~$135.0~~$65.0 million in borrowings outstanding under our revolving credit facility which bore interest at a weighted average rate of ~~3.52%~~2.45%. ~~A 1.0% increase in the average interest rate for the nine months ended September 30, 2019 would have resulted in an estimated $0.7 million increase in interest expense.~~ As of ~~September 30, 2019,~~March 31, 2020, we did not have any interest rate swaps to hedge our interest 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. ~~Management recognizes that any controls and procedures, no matter how well designed and operated, can provide only~~

~~Table~~As of ~~Contents~~

~~reasonable assurance of achieving their objectives and management necessarily applies its judgment in evaluating the cost-benefit relationship of possible controls and procedures.~~

~~At the time of our Original Filing on November 1, 2019,~~March 31, 2020, 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 ~~that~~our evaluation, our Chief Executive Officer and President and our Chief Financial Officer have concluded that, as of ~~September 30, 2019,~~March 31, 2020, our disclosure controls and procedures were effective. Subsequent to the evaluation made in connection with our Original Filing, a material weakness was identified in our internal control over financial reporting. Our Chief Executive Officer and President and our Chief Financial Officer have re-evaluated the effectiveness of the design and operation of our disclosure controls and procedures and concluded that, as a resultnot effective because of the material weakness in our internal control over financial reporting ~~discussed below, our disclosure controls and procedures were not effective as of September 30, 2019.~~

~~Material Weakness~~described in Management’s Report on Internal Control Over Financial Reporting~~. A material weakness is a deficiency, or a combination~~ appearing under Item 9A of ~~deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement~~Part II of ~~the Company's annual or interim financial statements will not be prevented or detected~~our Annual Report on ~~a timely basis.~~

During the fourth quarter of fiscal year 2019, management identified a material weakness in our controls related to the completeness and accuracy of the accounting for transfers of unevaluated capitalized costs into the amortization baseForm 10-K for the ~~three and nine month periods~~year ended ~~September 30,~~December 31, 2019. ~~The following deficiencies primarily contributed to management’s assessment:~~

~~The processes and controls relating to transfer of unproved property costs were not sufficient to identify certain leases that had been drilled, abandoned or expired.~~

Management determined it did not effectively design controls for timely and consistent reviews of accounting entries and supporting documentation related to transfers of unproved oil and gas property costs into the amortization base and related to timely performance and review of reconciliations of land records to the general ledger.

~~This material weakness resulted in a material error in the amount of impairment expense recorded in relation to our oil and gas properties~~Remediation Plan for the ~~nine months ended September 30, 2019 and resulted in the Company restating its consolidated financial statements as of and for the three and nine months ended September 30, 2019.~~

~~Plan for Remediation of~~ Material ~~Weakness~~Weakness.. Our management is actively engaged in the ~~planning for, and~~ implementation of remediation efforts to address the material weakness ~~identified.~~identified in the fourth quarter of 2019. Specifically, our management is ~~currently evaluating our policies and procedures related to its~~in the process of ~~accounting for unproved oil~~implementing new controls and ~~gas properties. We plan to design~~processes over the evaluation and ~~implement additional controls to ensure that we are properly and timely identifying and transferring leasehold~~transfer of unevaluated costs ~~associated acreage expirations, lease transfers and proved reserve additions from the unevaluated capitalized cost pool~~ to the ~~evaluated amortization~~amortizable base. We will do that through continued focus on (i) redesigning controls over the completeness and reconciliation of costs associated with acreage movements; (ii) identifying new resources to execute and monitor the redesigned controls; (iii) process enhancements and (iv) additional technical training of our accounting staff. Our management believes that these actions will remediate the material weakness in internal control over financial reporting described above. The material weakness will not be considered remediated until the controls are in place for a sufficient period of time and management has concluded, through testing, that the controls are operating effectively.by June 30, 2020.

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, ~~our~~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 ~~our~~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 15^th15th Judicial District of the State of Louisiana in the 15^th15th 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 ~~a number of~~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, Saydee Resources, LLC, on behalf of itself and a class of similarly situated royalty holders, filed an action against us in the District Court of Grady County Oklahoma. The suit alleges that we underpaid royalty holders and seeks unspecified damages for breach of contract, tortious breach of contract, fraud and unjust enrichment.

~~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.

As previously disclosed, 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

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approximately $6.7 million as of February 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.

We filed an action against TH Exploration, LLC ("TH") in Tarrant County, TX. The suit alleges breach of purchase and sale agreement providing for the our disposition of certain oil and gas properties in Ohio to TH. We are seeking specific

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~~performance, related to TH's obligations to close the transaction and tender the purchase price, along with any additional relief available to us.~~

SEC Investigation

The SEC has commenced an investigation with respect to certain actions by our former ~~Company~~ management, including alleged improper personal use of ~~Company~~company assets, and potential violations by our former management and the ~~Company~~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 liability with respect to this matter, we believe that the outcome 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 and disputes incidental to our 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 usGulfport and ~~our~~its subsidiaries. WeThey have implemented various policies, programs, procedures, training and audits to reduce and mitigate ~~such~~ environmental risks. WeThey conduct periodic reviews, on a company-wide basis, to assess changes in ~~our~~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, wethey may, among other things, exclude a property from the transaction, require the seller to remediate the property to ~~our~~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 1217 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 ~~may result~~resulted in monetary sanctions of ~~more than $100,000.~~ approximately $1.7 million.

Other Matters

Based on management’s current assessment, wethey are of the opinion that no pending or threatened lawsuit or dispute relating to ~~our~~its business operations ~~are~~is likely to have a material adverse effect on ~~our~~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.



ITEM 1A.	RISK FACTORS

We have identified a material weakness in internal controls. If we fail to remediate this material weakness or otherwise fail to develop, implement and maintain effective internal controls in future periods,Our business has many risks. Factors that could materially adversely affect our ~~ability to report our~~business, financial condition, operating results or liquidity and ~~results~~the trading price of ~~operations accurately and~~our common stock or senior notes are described under "Risk Factors" in Item 1A of our Annual Report on ~~a timely basis could be adversely affected.~~

~~We have identified a material weakness~~Form 10-K for the year ended December 31, 2019. The risk factor below updates our risk factors previously discussed in our ~~internal controls over~~Annual Report on Form 10-K for the ~~completeness and accuracy of the accounting of transfers of unevaluated capitalized costs into the amortization base. Accordingly, based on our management’s assessment, we believe that, as of~~fiscal year ended December 31, ~~2019, our disclosure controls and procedures were not effective. We also determined that this material weakness existed as of September 30,~~ 2019.

A "material weakness" is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of our annual or interim financial statements would not be prevented or detected on a timely basis. We cannot assure you that we will adequately remediate the material weakness or that additional material weaknesses in our internal controls will not be identified in the future. Any failure to maintain or implement required new or improved controls, or any difficulties we encounter in the implementation, could result in additional material weaknesses,

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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;

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, NGL and oil, 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, NGL and oil 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 ~~material misstatements in~~a default under our ~~financial statements. These misstatements could result in restatements~~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 ~~our financial statements, cause~~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 that 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 ~~fail to meet our reporting obligations or cause investors to lose confidence in our reported financial information.~~delay development operations.

~~We are~~In addition, the COVID-19 pandemic has increased volatility and caused negative pressure in the ~~process~~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 ~~remediating~~variables, including many beyond our control) and, to the ~~identified material weakness in~~extent our ~~internal controls, but~~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 ~~at this time~~ to ~~estimate when~~obtain the ~~remediation will~~capital necessary for our planned capital budget or our operations, we could be ~~completed. If we fail~~required to ~~remediate this material weakness, there will continue to be an increased risk that~~curtail our ~~future financial statements could contain errors that will be undetected. Further~~operations and ~~continued determinations that there are material weaknesses in~~ the ~~effectiveness~~development of our ~~internal controls~~properties, which in turn could ~~reduce~~lead to a decline in our ~~ability~~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 ~~obtain financing or could increase~~our financial performance and debt obligations. The rapid development and fluidity of this situation precludes any prediction as to the ~~cost~~ultimate adverse impact of ~~any financing~~COVID-19 on our business, which will depend on numerous evolving factors and future developments that we ~~obtain~~are not able to predict, including the length of time that the pandemic continues, its effect on the demand for natural gas, NGL and ~~require additional expenditures~~oil, the response of ~~resources~~the overall economy and the financial markets as well as the effect of governmental actions taken in response to ~~comply with applicable requirements.~~the pandemic.

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

Unregistered Sales of Equity Securities

None.

Issuer Repurchases of Equity Securities

Our common stock repurchase activity for the three months ended ~~September 30, 2019~~March 31, 2020 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 (1) Approximate maximum dollar value of shares that may yet be purchased under the plans or programs (2)
July 2019 —
$ —
—
$ 370,000,000
August 2019 35,977
$ 2.45
—
$ 370,000,000
September 2019 —
$ —
—
$ 370,000,000
Total 35,977
$ 2.45
—



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)
January 2020	—	$	—	—	$	370,000,000
February 2020	80,155	$	0.98	—	$	370,000,000
March 2020	—	$	—	—	$	370,000,000
Total	80,155	$	0.98	—



(1)	In ~~August 2019,~~February 2020, we repurchased and canceled ~~35,977~~80,115 shares of our common stock at a weighted average price of ~~$2.45~~$0.98 to satisfy tax withholding requirements incurred upon the vesting of restricted stock unit awards. ~~No repurchases were made under our repurchase program during the three months ended September 30, 2019.~~
(2)	In January 2019, our board of directors approved a new stock repurchase program to acquire up to ~~$400~~$400.0 million of our outstanding common stock within a 24 month period. ~~This repurchase~~The program ~~may be~~was suspended ~~from time~~in the fourth quarter of 2019, and the May 1, 2020 amendment to ~~time, modified, extended or discontinued by~~ our ~~board of directors at any time.~~revolving credit facility prohibits further repurchases.



ITEM 3.	DEFAULTS UPON SENIOR SECURITIES

Not applicable.



ITEM 4.	MINE SAFETY DISCLOSURES

Not applicable.



ITEM 5.	OTHER INFORMATION

~~None.~~2020 Annual Meeting

As required by Rule 14a-5(f) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), the Company hereby discloses that the 2020 Annual Meeting of Stockholders (the “2020 Annual Meeting”) has been scheduled to be held on July 16, 2020.

Since the 2020 Annual Meeting will be held on a date that is more than 30 days after the first anniversary of the Company’s 2019 Annual Meeting of Stockholders, the Company has set May 18, 2020 as the new deadline for receipt of any stockholder proposals for inclusion in the Company’s proxy statement for the 2020 Annual Meeting pursuant to Rule 14a-8 under the Exchange Act (“Rule 14a-8”). Stockholder proposals submitted pursuant to Rule 14a-8 must be received by the Corporate Secretary on or by such deadline and comply with all rules of the SEC pertaining to stockholders’ proposals.

Additionally, notice of proposals or nominations for the 2020 Annual Meeting submitted pursuant to the advance notice provisions of the Restated Certificate of Incorporation of the Company, as amended, and the Amended and Restated Bylaws of the Company must be submitted to the Corporate Secretary not earlier than April 18, 2020 and not later than May 18, 2020. Notwithstanding the foregoing, as indicated in the Company’s proxy statement for the 2019 Annual Meeting, the Company will treat as timely any such notice submitted between February 7, 2020 and March 8, 2020.

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All written stockholder proposals should be addressed to the Corporate Secretary at Gulfport Energy Corporation, 3001 Quail Springs Parkway, Oklahoma City, Oklahoma 73134.

Restricted Stock Grants to Named Executive Officers

On March 11, 2020 and pursuant to our 2019 Amended and Restated Stock Incentive Plan, we granted our named executive officers the number of restricted stock units reflected in the table below, which will vest ratably over a period of three years from the date of the grants.



Named Executive Officer		Restricted Stock Units
David M. Wood		809,644
Donnie Moore		352,981
Quentin R. Hicks		191,441
Patrick K. Craine		195,945
Michael Sluiter		145,386

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ITEM 6.	EXHIBITS



~~Exhibit~~ ~~Number~~		~~Description~~

~~3.1~~		~~Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on April 26, 2006).~~

~~3.2~~		Certificate of Amendment No. 1 to Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.2 to Form 10-Q, File No. 000-19514, filed by the Company with the SEC on November 6, 2009).

~~3.3~~		Certificate of Amendment No. 2 to Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on July 23, 2013).

~~3.4~~		~~Amended and Restated Bylaws (incorporated by reference to Exhibit 3.2 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on July 12, 2006).~~

~~3.5~~		~~First Amendment to the Amended and Restated Bylaws (incorporated by reference to Exhibit 3.2 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on July 23, 2013).~~

~~3.6~~		~~Second Amendment to the Amended and Restated Bylaws (incorporated by reference to Exhibit 3.1 to the Form 8-K, File No. 000-19514, filed by the Company on May 2, 2014).~~

~~4.1~~		Form of Common Stock certificate (incorporated by reference to Exhibit 4.1 to Amendment No. 2 to the Registration Statement on Form SB-2, File No. 333-115396, filed by the Company with the SEC on July 22, 2004).



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 Amendment to the Amended and Restated Bylaws of Gulfport Energy Corporation.	8-K	000-19514	3.1	2/27/2020

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

10.1+	Gulfport Energy Corporation 2020 Incentive Plan.	8-K	000-19514	10.1	3/17/2020

10.2+	Form of 2020 Cash Award under Gulfport Energy Corporation 2020 Incentive Plan.	8-K	000-19514	10.2	3/17/2020

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

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~~4.5~~

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) (incorporated by reference to Exhibit 4.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on April 21, 2015).

~~4.6~~

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) (incorporated by reference to Exhibit 4.1 to the Form 8-K, File. No. 000-19514, filed by the Company with the SEC on October 19, 2016).

~~4.7~~

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) (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K, File No. 000-19514, filed by the Company with the SEC on December 21, 2016).

~~4.8~~

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) (incorporated by reference to Exhibit 4.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on October 11, 2017).

~~4.9~~

Registration Rights Agreement, dated as of February 17, 2017, by and between Gulfport Energy Corporation and Vitruvian II Woodford, LLC (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K, File No. 000-19514, filed by the Company with the SEC on February 24, 2017).

~~10.1+~~

Employment Agreement, effective as of August 26, 2019, by and between Gulfport Energy Corporation and Quentin Hicks (incorporated by reference to Exhibit 10.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on August 12, 2019).

~~10.2+~~

Separation and Release Agreement, effective August 9, 2019, by and between Gulfport Energy Corporation and Keri Crowell (incorporated by reference to Exhibit 10.2 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on August 12, 2019).

~~10.3+~~

2019 Amended and Restated Stock Incentive Plan Form of Performance Share Award Agreement (incorporated by reference to Exhibit 10.3 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on August 12, 2019).

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*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*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*32.2

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

101.INS*101.INS

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*	~~Filed herewith.~~
+	Management contract, compensation plan or arrangement.

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SIGNATURES

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

Date: ~~February 27,~~May 8, 2020



GULFPORT ENERGY CORPORATION

By:		/s/ Quentin Hicks
		Quentin Hicks Executive Vice President & Chief Financial Officer

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	September 30, 2019
	As Reported			Adjustments		As Restated
	(In thousands)
Accumulated depletion, depreciation, amortization and impairment	(5,063,413		)	(553,575	)	(5,616,988		)
Property and equipment, net⁽¹⁾	5,584,533			(553,575	)	5,030,958

Deferred tax asset	205,853			117,525		323,378
Total other assets	384,278			117,525		501,803
Total assets	$	6,273,148		(436,050	)	$	5,837,098

Accumulated deficit	(596,922		)	(436,050	)	(1,032,972		)
Total stockholders’ equity	3,559,154			(436,050	)	3,123,104
Total liabilities and stockholders’ equity	$	6,273,148		(436,050	)	$	5,837,098

⁽¹⁾ Amount excluded from amortization in 2019	$	2,814,334		(553,575	)	$	2,260,759



	Total Stockholders' Equity
	As Reported			Adjustments		As Restated
	(In thousands)
Net loss	$	(48,752	)	(436,050	)	$	(484,802	)
Balance at September 30, 2019	$	3,559,154		(436,050	)	$	3,123,104



	As of September 30, 2019
	Gross Assets (Liabilities)			Gross Amounts
	Presented in the			Subject to Master			Net
	Consolidated Balance Sheets			Netting Agreements			Amount
	(In thousands)
Derivative assets	$	157,990		$	(72,469	)	$	85,521
Derivative liabilities	$	(72,469	)	$	72,469		$	—