Gulfport Energy - 10-Q quarterly report FY2020 Q1

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)



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

For the quarterly period ended 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 May 1, 2020, 159,872,688 shares of the registrant’s common stock were outstanding.

Table of Contents

GULFPORT ENERGY CORPORATION

TABLE OF CONTENTS



		Page
PART I FINANCIAL INFORMATION

Item 1.	Consolidated Financial Statements (Unaudited):	2

	Consolidated Balance Sheets at March 31, 2020 and December 31, 2019	2

	Consolidated Statements of Operations for the Three Months Ended March 31, 2020 and 2019	3

	Consolidated Statements of Comprehensive Income for the Three Months Ended March 31, 2020 and 2019	4

	Consolidated Statements of Stockholders’ Equity for the Three Months Ended March 31, 2020 and 2019	4

	Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2020 and 2019	5

	Notes to Consolidated Financial Statements	6

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

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	43

Item 4.	Controls and Procedures	45

PART II OTHER INFORMATION

Item 1.	Legal Proceedings	46

Item 1A.	Risk Factors	47

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	49

Item 3.	Defaults Upon Senior Securities	49

Item 4.	Mine Safety Disclosures	49

Item 5.	Other Information	49

Item 6.	Exhibits	51

Signatures		53

Table of Contents

GULFPORT ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS



	March 31, 2020			December 31, 2019
	(Unaudited)
	(In thousands, except share data)
Assets
Current assets:
Cash and cash equivalents	$	1,633		$	6,060
Accounts receivable—oil and natural gas sales	74,099			121,210
Accounts receivable—joint interest and other	42,547			47,975
Prepaid expenses and other current assets	11,848			4,431
Short-term derivative instruments	171,755			126,201
Total current assets	301,882			305,877
Property and equipment:
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	96,882			96,719
Accumulated depletion, depreciation, amortization and impairment	(7,859,873		)	(7,228,660		)
Property and equipment, net	2,904,541			3,463,794
Other assets:
Equity investments	6,225			32,044
Long-term derivative instruments	—			563
Deferred tax asset	—			7,563
Operating lease assets	10,186			14,168
Operating lease assets—related parties	—			43,270
Other assets	41,453			15,540
Total other assets	57,864			113,148
Total assets	$	3,264,287		$	3,882,819
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable and accrued liabilities	$	437,453		$	415,218
Short-term derivative instruments	67			303
Current portion of operating lease liabilities	9,873			13,826
Current portion of operating lease liabilities—related parties	—			21,220
Current maturities of long-term debt	688			631
Total current liabilities	448,081			451,198
Long-term derivative instruments	70,829			53,135
Asset retirement obligation	59,444			60,355
Uncertain tax position liability	3,209			3,127
Non-current operating lease liabilities	313			342
Non-current operating lease liabilities—related parties	—			22,050
Long-term debt, net of current maturities	1,898,362			1,978,020
Total liabilities	2,480,238			2,568,227
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 - $.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	4,209,578			4,207,554
Accumulated other comprehensive loss	(61,863		)	(46,833		)
Accumulated deficit	(3,365,264		)	(2,847,726		)
Total stockholders’ equity	784,049			1,314,592
Total liabilities and stockholders’ equity	$	3,264,287		$	3,882,819

See accompanying notes to consolidated financial statements.

Table of Contents

GULFPORT ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)



	Three months ended March 31,
	2020			2019
	(In thousands, except share data)
Revenues:
Natural gas sales	$	108,547		$	276,016
Oil and condensate sales	23,151			32,482
Natural gas liquid sales	16,913			32,125
Net gain (loss) on natural gas, oil and NGL derivatives	98,266			(20,045		)
	246,877			320,578
Costs and expenses:
Lease operating expenses	15,986			19,807
Production taxes	4,799			7,921
Midstream gathering and processing expenses	57,896			70,282
Depreciation, depletion and amortization	78,028			118,433
Impairment of oil and natural gas properties	553,345			—
General and administrative expenses	16,169			10,057
Accretion expense	741			1,067
	726,964			227,567
(LOSS) INCOME FROM OPERATIONS	(480,087		)	93,011
OTHER EXPENSE (INCOME):
Interest expense	32,990			35,621
Interest income	(152		)	(152		)
Gain on debt extinguishment	(15,322		)	—
Loss (income) from equity method investments, net	10,789			(4,273		)
Other expense (income)	1,856			(427		)
	30,161			30,769
(LOSS) INCOME BEFORE INCOME TAXES	(510,248		)	62,242
INCOME TAX EXPENSE	7,290			—
NET (LOSS) INCOME	$	(517,538	)	$	62,242
NET (LOSS) INCOME PER COMMON SHARE:
Basic	$	(3.24	)	$	0.38
Diluted	$	(3.24	)	$	0.38
Weighted average common shares outstanding—Basic	159,760,222			162,823,997
Weighted average common shares outstanding—Diluted	159,760,222			163,099,409

See accompanying notes to consolidated financial statements.

Table of Contents

GULFPORT ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE (LOSS) INCOME

(Unaudited)



	Three months ended March 31,
	2020			2019
	(In thousands)
Net (loss) income	$	(517,538	)	$	62,242
Foreign currency translation adjustment	(15,030		)	3,801
Other comprehensive (loss) income	(15,030		)	3,801
Comprehensive (loss) income	$	(532,568	)	$	66,043

See accompanying notes to consolidated financial statements.

GULFPORT ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(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
	Common Stock
	Shares		Amount
	(In thousands)
Balance at January 1, 2019	162,986		$	1,630		$	4,227,532		$	(56,026	)	$	(845,368	)	$	3,327,768
Net Income	—		—			—			—			62,242			62,242
Other Comprehensive Income	—		—			—			3,801			—			3,801
Stock Compensation	—		—			2,785			—			—			2,785
Shares Repurchased	(3,619	)	(37		)	(28,293		)	—			—			(28,330		)
Issuance of Restricted Stock	55		1			(1		)	—			—			—
Balance at March 31, 2019	159,422		$	1,594		$	4,202,023		$	(52,225	)	$	(783,126	)	$	3,368,266

See accompanying notes to consolidated financial statements.

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GULFPORT ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)



	Three months ended March 31,
	2020			2019
	(In thousands)
Cash flows from operating activities:
Net (loss) income	$	(517,538	)	$	62,242
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depletion, depreciation and amortization	78,028			118,433
Impairment of oil and natural gas properties	553,345			—
Loss (income) from equity investments	10,789			(4,132		)
Gain on debt extinguishment	(15,322		)	—
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 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	130,838			239,765
Cash flows from investing activities:
Additions to oil and natural gas properties	(113,744		)	(241,391		)
Proceeds from sale of oil and natural gas properties	44,383			52
Additions to other property and equipment	(539		)	(3,848		)
Proceeds from sale of other property and equipment	91			56
Contributions to equity method investments	—			(432		)
Net cash used in investing activities	(69,809		)	(245,563		)
Cash flows from financing activities:
Principal payments on borrowings	(180,106		)	(150,151		)
Borrowings on line of credit	125,000			150,000
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	(65,456		)	(28,503		)
Net decrease in cash, cash equivalents and restricted cash	(4,427		)	(34,301		)
Cash, cash equivalents and restricted cash at beginning of period	6,060			52,297
Cash, cash equivalents and restricted cash at end of period	$	1,633		$	17,996
Supplemental disclosure of cash flow information:
Interest payments	$	14,034		$	15,266
Income tax receipts	$	—		$	(1,794	)
Supplemental disclosure of non-cash transactions:
Capitalized stock-based compensation	$	934		$	1,114
Asset retirement obligation capitalized	$	381		$	1,952
Asset retirement obligation removed due to divestiture	$	(2,033	)	$	—
Interest capitalized	$	187		$	766
Fair value of contingent consideration asset on date of divestiture	$	23,090		$	—
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 AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

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

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

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 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 not experienced significant disruptions in executing its 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.

Impact on 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 three months ended 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 $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 Adopted Accounting Standards

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

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including historical experience, current conditions and reasonable and supportable forecasts that affect the collectibility of the reported amount. The Company adopted the new standard using the prospective transition method, and it did not have a material impact on the Company's consolidated financial statements and related disclosures.


2.	PROPERTY AND EQUIPMENT

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



	March 31, 2020			December 31, 2019
	(In thousands)
Oil and natural gas properties	$	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	91,361			91,198
Land	5,521			5,521
Accumulated DD&A	(39,211		)	(36,703		)
Other property and equipment, net	57,671			60,016
Property and equipment, net	$	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 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 March 31, 2020. As a result, the Company was required to record an impairment of its oil and natural gas properties in the amount of $553.3 million for the three months ended March 31, 2020. No impairment was required for oil and natural gas properties for the three months ended March 31, 2019.

Based on prices for the last nine months 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 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. Any future full cost impairments are not expected to have any impact to the 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 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 $5.4 million and $7.7 million for the three months ended 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 $0.79 and $1.02 per Mcfe for the three months ended March 31, 2020 and 2019, respectively.

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



	March 31, 2020
	(In thousands)
Utica	$	908,481
MidContinent	697,909
Other	2,250
	$	1,608,640

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

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

Asset Retirement Obligation

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



	March 31, 2020			March 31, 2019
	(In thousands)
Asset retirement obligation, beginning of period	$	60,355		$	79,952
Liabilities incurred	381			969
Liabilities settled	—			(71		)
Liabilities removed due to divestitures	(2,033		)	—
Accretion expense	741			1,067
Revisions in estimated cash flows	—			983
Asset retirement obligation as of end of period	59,444			82,900


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 no 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 March 31, 2020 and December 31, 2019:



			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 March 31, 2020 and December 31, 2019.

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Summarized balance sheet information:



	March 31, 2020		December 31, 2019
	March 31, 2020		December 31, 2019
	(In thousands)
Current assets	$	440,801	$	421,326
Noncurrent assets	$	1,104,297	$	1,260,075
Current liabilities	$	131,175	$	132,569
Noncurrent liabilities	$	171,132	$	163,241

Summarized results of operations:



	Three months ended March 31,
	2020			2019
	(In thousands)
Gross revenue	$	97,383		$	264,844
Net (loss) income	$	(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 no 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 no 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 zero 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 no 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 no distributions and $0.1 million in distributions from Tatex during the three months ended March 31, 2020 and 2019, respectively. Tatex previously held an 8.5% interest in APICO, LLC (“APICO”), an international oil and gas exploration company, before selling its interest in June 2019. APICO has a reserve base located in Southeast Asia through its ownership of concessions covering approximately 108,000 acres which includes the Phu Horm Field.

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5.	LONG-TERM DEBT

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



	March 31, 2020			December 31, 2019
	(In thousands)
Revolving credit agreement⁽¹⁾	$	65,000		$	120,000
6.625% senior unsecured notes due 2023	329,467			329,467
6.000% senior unsecured notes due 2024	595,903			603,428
6.375% senior unsecured notes due 2025	521,360			529,525
6.375% senior unsecured notes due 2026	387,367			397,529
Net unamortized debt issuance costs⁽²⁾	(22,395		)	(23,751		)
Construction loan	22,348			22,453
Less: current maturities of long term debt	(688		)	(631		)
Debt reflected as long term	$	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 November 25, 2019, the borrowing base under the Company's revolving credit facility was reduced to $1.2 billion, and the Company's elected commitment remained at $1.0 billion.

As of 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 $236.8 million letters of credit, was $698.2 million. The Company’s wholly owned subsidiaries have guaranteed the obligations of the Company under the revolving credit facility.

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

The Company was in compliance with its financial covenants under the revolving credit facility at 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 March 31, 2020, total unamortized debt issuance costs were $3.1 million for the 2023 Notes, $6.5 million for the 2024 Notes, $9.1 million for the 2025 Notes and $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 March 31, 2020.

The Company capitalized approximately $0.2 million and $0.8 million in interest expense to its unevaluated oil and natural gas properties during the three months ended March 31, 2020 and 2019, 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 March 31, 2020, the Company used borrowings under its revolving credit facility to repurchase in the open market approximately $25.9 million aggregate principal amount of its outstanding Notes for $10.2 million. This included approximately $7.5 million principal amount of the 2024 Notes, $8.2 million principal amount of the 2025 Notes, and $10.2 million principal amount of the 2026 Notes. The Company recognized a $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.


6.	CHANGES IN CAPITALIZATION

Stock Repurchases

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

For the three months ended March 31, 2019, the Company repurchased 3.6 million shares for a cost of approximately $28.2 million under this repurchase program. Additionally, during the three months ended March 31, 2020 and 2019, the Company repurchased 80,000 and 15,000 shares, respectively, for a cost of approximately $0.1 million 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.


7.	STOCK-BASED COMPENSATION

The Company has granted restricted stock units to employees and directors pursuant to the 2019 Amended and Restated Incentive Stock Plan ("2019 Plan"), as discussed below. During the three months ended March 31, 2020 and 2019, the Company’s stock-based compensation cost was $2.1 million and $2.8 million, respectively, of which the Company capitalized $0.9 million and $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 three months ended 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
Unvested shares as of January 1, 2020	4,098,318		$	4.73	1,783,660		$	2.96
Granted	1,985,452		0.67		—		—
Vested	(211,090	)	8.65		—		—
Forfeited	(344,112	)	5.00		(225,484	)	1.98
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 March 31, 2020 related to restricted stock units was $12.9 million. The expense is expected to be recognized over a weighted average period of 1.96 years.

Performance Vesting Restricted Stock Units

The Company has awarded performance vesting units to certain of its executive officers under the 2019 Plan. The number of shares of common stock issued pursuant to the award will be based on relative total shareholder return ("RTSR"). RTSR is an incentive measure whereby participants will earn from 0% to 200% of the target award based on the Company’s RTSR ranking compared to the RTSR of the companies in the Company’s designated peer group at the end of the performance period. Awards will be earned and vested over a performance period measured from January 1, 2019 to December 31, 2021, subject to earlier termination of the performance period in the event of a change in control. Unrecognized compensation expense as of March 31, 2020 related to performance vesting restricted shares was $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 1.77 years.

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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 March 31,
	2020							2019
	Loss			Shares	Per Share			Income		Shares	Per Share
	(In thousands, except share data)
Basic:
Net (loss) income	$	(517,538	)	159,760,222	$	(3.24	)	$	62,242	162,823,997	$	0.38
Effect of dilutive securities:
Stock awards	—			—				—		275,412
Diluted:
Net (loss) income	$	(517,538	)	159,760,222	$	(3.24	)	$	62,242	163,099,409	$	0.38

There were 1,552,423 shares of common stock that were considered anti-dilutive for the three months ended March 31, 2020. There were no potential shares of common stock that were considered anti-dilutive for the three months ended March 31, 2019.

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9.	COMMITMENTS AND CONTINGENCIES

Future Firm Sales Commitments

The Company has entered into various firm sales contracts to deliver and sell natural gas. The Company expects to fulfill its delivery commitments primarily with production from proved developed reserves. The Company's proved reserves have 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)
Remaining 2020		316,000
2021		192,000
2022		70,000
2023		17,000
Total		595,000

Future Firm Transportation Commitments

The Company has contractual commitments with pipeline carriers for future transportation of natural gas from the Company's production areas to downstream markets. Commitments related to future firm transportation agreements are not recorded as obligations in the accompanying consolidated balance sheets; however, the costs associated with these commitments are reflected in the Company's estimates of proved reserves and future net revenues.

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



	Total MMBtu	(In thousands)
Remaining 2020	395,625,000	$	206,292
2021	531,075,000	285,789
2022	531,075,000	286,626
2023	515,867,000	282,945
2024	489,525,000	265,568
Thereafter	3,769,092,000	2,160,732
Total	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 $1.9 million and $0.3 million in non-utilization fees under this agreement during the three months ended March 31, 2020 and 2019, respectively.

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Future minimum commitments under this agreement at March 31, 2020 are:



	(In thousands)
Remaining 2020	$	5,625
2021	7,500
Total	$	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 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 many other oil and gas companies in the 16th Judicial District Court for the Parish of Iberia in Louisiana. The suit alleges negligence, strict liability and various violations of Louisiana statutes relating to property damage in connection with the historic development of the Company’s Louisiana properties and seeks unspecified damages (including punitive damages), an injunction to return the affected property to its original condition, and the payment of reasonable attorney fees and legal expenses and interest.

In September 2019, a stockholder of Mammoth Energy filed a derivative action on behalf of Mammoth Energy against members of Mammoth Energy’s board of directors, including a director designated by the Company, and its significant stockholders, including the Company, in the United States District Court for the Western District of Oklahoma. The complaint alleges, among other things, that the members of Mammoth Energy’s board of directors breached their fiduciary duties and violated the Securities Exchange Act of 1934, as amended, in connection with Mammoth Energy’s activities in Puerto Rico following Hurricane Maria. The complaint seeks unspecified damages, the payment of reasonable attorney fees and legal expenses and interest and to force Mammoth Energy and its board of directors to make specified corporate governance reforms.

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

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 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, the Company has not had the opportunity to evaluate the allegations made in the plaintiffs' complaints and intends to vigorously defend the suits.

SEC Investigation

The SEC has commenced an investigation with respect to certain actions by former Company management, including alleged improper personal use of Company assets, and potential violations by former 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 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 environmental risks. They conduct periodic reviews, on a company-wide basis, to assess changes in their environmental risk profile. Environmental reserves are established for environmental liabilities for which economic losses are probable and reasonably estimable. The Company manages its exposure to environmental liabilities in acquisitions by using an evaluation process that seeks to identify pre-existing contamination or compliance concerns and address the potential liability. Depending on the extent of an identified environmental concern, they may, among other things, exclude a property from the transaction, require the seller to remediate the property to their satisfaction in an acquisition or agree to assume liability for the remediation of the property.

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

Other Matters

Based on management’s current assessment, they are of the opinion that no pending or threatened lawsuit or dispute relating to its business operations is likely to have a material adverse effect on their future consolidated financial position, results of operations or cash flows. The final resolution of such matters could exceed amounts accrued, however, and actual results could differ materially from management’s estimates.


10.	DERIVATIVE INSTRUMENTS

Natural Gas, Oil and Natural Gas Liquids Derivative Instruments

The Company seeks to reduce its exposure to unfavorable changes in natural gas, oil and natural gas liquids ("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 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 March 31, 2020.



	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 2020	NYMEX WTI	6,000	$	59.83



	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
2022	NYMEX Henry Hub	628,000	$	2.90
2023	NYMEX Henry Hub	628,000	$	2.90

In addition, the Company 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	)

Contingent Consideration Arrangement

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



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



(1)	Based on the "WTI NYMEX + Argus LLS Differential," as published by Argus Media.
(2)	Payment will be assessed monthly from July 2020 through June 2021. If threshold is met, payment shall be received within five business days after the end of each calendar month.
(3)	If average daily price, as defined in (1), is greater than $52.62 but less than $60.65, payment received will be $150,000 multiplied by a fraction, the numerator of which is the amount determined by subtracting $52.62 from such average daily price, and the denominator of which is $8.03.

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 March 31, 2020 and December 31, 2019:



	March 31, 2020		December 31, 2019
	(In thousands)
Commodity derivative instruments	$	171,755	$	125,383
Contingent consideration arrangement	—		818
Total short-term derivative instruments - asset	$	171,755	$	126,201

Contingent consideration arrangement	—		563
Total long-term derivative instruments - asset	$	—	$	563

Total short-term derivative instruments - liability	$	67	$	303

Total long-term derivative instruments - liability	$	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 NGL derivatives in the accompanying consolidated statements of operations for the three months ended March 31, 2020 and 2019.



	Net gain (loss) on derivative instruments
	Three months ended March 31,
	2020			2019
	(In thousands)
Natural gas derivatives	$	45,853		$	(16,431	)
Oil derivatives	52,874			(454		)
NGL derivatives	920			(3,160		)
Contingent consideration arrangement	(1,381		)	—
Total	$	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 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, 2019
	Gross Assets (Liabilities)			Gross Amounts
	Presented in the			Subject to Master			Net
	Consolidated Balance Sheets			Netting Agreements			Amount
	(In thousands)
Derivative assets	$	126,764		$	(53,438	)	$	73,326
Derivative liabilities	$	(53,438	)	$	53,438		$	—

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.


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 March 31, 2020 and December 31, 2019:



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



	December 31, 2019
	Level 1		Level 2		Level 3
	(In thousands)
Assets:
Derivative Instruments	$	—	$	126,764	$	—
Liabilities:
Derivative Instruments	$	—	$	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 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 fair value in earnings in that period. The Company recognized a gain of $0.2 million on changes in fair value of the contingent consideration during the three months ended March 31, 2020, which is included in 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 three months ended March 31, 2020 were approximately $0.4 million.

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.


12.	REVENUE FROM CONTRACTS WITH CUSTOMERS

Revenue Recognition

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

Transaction Price Allocated to Remaining Performance Obligations

A significant number of the Company's product sales are short-term in nature generally through evergreen contracts with contract terms of one year or less. These contracts typically automatically renew under the same provisions. For those contracts, the Company has utilized the practical expedient allowed in the new revenue accounting standard that exempts the Company from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less.

For product sales that have a contract term greater than one year, the Company has utilized the practical expedient that exempts the Company from disclosure of the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product generally represents a separate performance obligation; therefore, future volumes are wholly unsatisfied and disclosure 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 $74.1 million and $121.2 million as of March 31, 2020 and December 31, 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 three months ended March 31, 2020, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.


13.	LEASES

Nature of Leases

The Company has operating leases associated with drilling rig commitments, 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 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. 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 of use assets and lease liabilities associated with the 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 March 31, 2020 were as follows:



	(In thousands)
Remaining 2020	$	9,920
2021	129
2022	115
2023	90
2024	30
Total lease payments	$	10,284
Less: Imputed interest	(98		)
Total	$	10,186

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

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	Three months ended March 31,
	2020		2019
	(In thousands)
Operating lease cost	$	4,082	$	8,536
Operating lease cost—related party	—		5,610
Variable lease cost	224		429
Variable lease cost—related party	—		31,453
Short-term lease cost	2,810		—
Total lease cost⁽¹⁾	$	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 three months ended 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)
Operating cash flows from operating leases	$	36	$	52
Investing cash flow from operating leases	$	3,997	$	4,858
Investing cash flow from operating leases—related party	$	6,800	$	6,545

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


14.	INCOME TAXES

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

For the 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. On April 30, 2020, the Company's Board of Directors approved the adoption of a tax benefits preservation plan that is intended to protect value by preserving the Company's ability to use its tax attributes, such as NOLs, to offset potential future income taxes for federal income tax purposes. See Note 16 for more 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)



	March 31, 2020
	Parent			Guarantors			Non-Guarantors			Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	897		$	541		$	195		$	—		$	1,633
Accounts receivable - oil and natural gas sales	860			73,239			—			—			74,099
Accounts receivable - joint interest and other	8,521			34,026			—			—			42,547
Accounts receivable - intercompany	1,277,124			1,052,317			—			(2,329,441		)	—
Prepaid expenses and other current assets	11,452			320			76			—			11,848
Short-term derivative instruments	171,755			—			—			—			171,755
Total current assets	1,470,609			1,160,443			271			(2,329,441		)	301,882

Property and equipment:
Oil and natural gas properties, full-cost accounting	1,247,661			9,414,738			5,862			(729		)	10,667,532
Other property and equipment	92,812			51			4,019			—			96,882
Accumulated depletion, depreciation, amortization and impairment	(1,421,230		)	(6,436,959		)	(1,684		)	—			(7,859,873		)
Property and equipment, net	(80,757		)	2,977,830			8,197			(729		)	2,904,541
Other assets:
Equity investments and investments in subsidiaries	2,486,108			6,332			6,186			(2,492,401		)	6,225
Operating lease assets	10,186			—			—			—			10,186
Other assets	32,591			8,863			(1		)	—			41,453
Total other assets	2,528,885			15,195			6,185			(2,492,401		)	57,864
Total assets	$	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	$	63,863		$	373,554		$	36		$	—		$	437,453
Accounts payable - intercompany	1,087,484			1,237,368			4,589			(2,329,441		)	—
Short-term derivative instruments	67			—			—			—			67
Current portion of operating lease liabilities	9,873			—			—			—			9,873
Current maturities of long-term debt	688			—			—			—			688
Total current liabilities	1,161,975			1,610,922			4,625			(2,329,441		)	448,081
Long-term derivative instruments	70,829			—			—			—			70,829
Asset retirement obligation - long-term	—			59,444			—			—			59,444
Uncertain tax position liability	3,209			—			—			—			3,209
Non-current operating lease liabilities	313			—			—			—			313
Long-term debt, net of current maturities	1,898,362			—			—			—			1,898,362
Total liabilities	3,134,688			1,670,366			4,625			(2,329,441		)	2,480,238

Stockholders’ equity:
Common stock	1,598			—			—			—			1,598
Paid-in capital	4,209,578			4,171,409			267,558			(4,438,967		)	4,209,578
Accumulated other comprehensive loss	(61,863		)	—			(59,434		)	59,434			(61,863		)
Accumulated deficit	(3,365,264		)	(1,688,307		)	(198,096		)	1,886,403			(3,365,264		)
Total stockholders’ equity	784,049			2,483,102			10,028			(2,493,130		)	784,049
Total liabilities and stockholders’ equity	$	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, 2019
	Parent			Guarantors			Non-Guarantor			Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	2,768		$	3,097		$	195		$	—		$	6,060
Accounts receivable - oil and natural gas sales	859			120,351			—			—			121,210
Accounts receivable - joint interest and other	5,279			42,696			—			—			47,975
Accounts receivable - intercompany	1,065,593			843,223			—			(1,908,816		)	—
Prepaid expenses and other current assets	4,047			308			76			—			4,431
Short-term derivative instruments	126,201			—			—			—			126,201
Total current assets	1,204,747			1,009,675			271			(1,908,816		)	305,877
Property and equipment:
Oil and natural gas properties, full-cost accounting,	1,314,933			9,273,681			7,850			(729		)	10,595,735
Other property and equipment	92,650			50			4,019			—			96,719
Accumulated depletion, depreciation, amortization and impairment	(1,418,888		)	(5,808,254		)	(1,518		)	—			(7,228,660		)
Property and equipment, net	(11,305		)	3,465,477			10,351			(729		)	3,463,794
Other assets:
Equity investments and investments in subsidiaries	3,064,503			6,332			21,000			(3,059,791		)	32,044
Long-term derivative instruments	563			—			—			—			563
Deferred tax asset	7,563			—			—			—			7,563
Operating lease assets	14,168			—			—			—			14,168
Operating lease assets - related parties	43,270			—			—			—			43,270
Other assets	10,026			5,514			—			—			15,540
Total other assets	3,140,093			11,846			21,000			(3,059,791		)	113,148
Total assets	$	4,333,535		$	4,486,998		$	31,622		$	(4,969,336	)	$	3,882,819

Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable and accrued liabilities	$	48,006		$	367,088		$	124		$	—		$	415,218
Accounts payable - intercompany	878,283			1,026,249			4,285			(1,908,817		)	—
Short-term derivative instruments	303			—			—			—			303
Current portion of operating lease liabilities	13,826			—			—			—			13,826
Current portion of operating lease liabilities - related parties	21,220			—			—			—			21,220
Current maturities of long-term debt	631			—			—			—			631
Total current liabilities	962,269			1,393,337			4,409			(1,908,817		)	451,198
Long-term derivative instruments	53,135			—			—			—			53,135
Asset retirement obligation - long-term	—			58,322			2,033			—			60,355
Uncertain tax position liability	3,127			—			—			—			3,127
Non-current operating lease liabilities	342			—			—			—			342
Non-current operating lease liabilities - related parties	22,050			—			—			—			22,050
Long-term debt, net of current maturities	1,978,020			—			—			—			1,978,020
Total liabilities	3,018,943			1,451,659			6,442			(1,908,817		)	2,568,227

Stockholders’ equity:
Common stock	1,597			—			—			—			1,597
Paid-in capital	4,207,554			4,171,408			267,557			(4,438,965		)	4,207,554
Accumulated other comprehensive loss	(46,833		)	—			(44,763		)	44,763			(46,833		)
Accumulated deficit retained earnings	(2,847,726		)	(1,136,069		)	(197,614		)	1,333,683			(2,847,726		)
Total stockholders’ equity	1,314,592			3,035,339			25,180			(3,060,519		)	1,314,592
Total liabilities and stockholders’ equity	$	4,333,535		$	4,486,998		$	31,622		$	(4,969,336	)	$	3,882,819

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CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

(Amounts in thousands)



	Three months ended March 31, 2020
	Parent			Guarantors			Non-Guarantors			Eliminations			Consolidated

Total revenues	$	98,268		$	148,609		$	—		$	—		$	246,877

Costs and expenses:
Lease operating expenses	—			15,986			—			—			15,986
Production taxes	—			4,799			—			—			4,799
Midstream gathering and processing expenses	—			57,896			—			—			57,896
Depreciation, depletion and amortization	2,502			75,360			166			—			78,028
Impairment of oil and natural gas properties	—			553,345			—			—			553,345
General and administrative expenses	24,646			(8,650		)	173			—			16,169
Accretion expense	—			741			—			—			741
	27,148			699,477			339			—			726,964

INCOME (LOSS) FROM OPERATIONS	71,120			(550,868		)	(339		)	—			(480,087		)

OTHER EXPENSE (INCOME):
Interest expense	33,177			(187		)	—			—			32,990
Interest income	(59		)	(93		)	—			—			(152		)
Gain on debt extinguishment	(15,322		)	—			—			—			(15,322		)
Loss from equity method investments and investments in subsidiaries	563,366			—			143			(552,720		)	10,789
Other expense	206			1,650			—			—			1,856
	581,368			1,370			143			(552,720		)	30,161

LOSS BEFORE INCOME TAXES	(510,248		)	(552,238		)	(482		)	552,720			(510,248		)
INCOME TAX EXPENSE	7,290			—			—			—			7,290

NET LOSS	$	(517,538	)	$	(552,238	)	$	(482	)	$	552,720		$	(517,538	)

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CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

(Amounts in thousands)



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

Total revenues	$	186,246		$	134,332		$	—		$	—		$	320,578

Costs and expenses:
Lease operating expenses	14,893			4,914			—			—			19,807
Production taxes	3,261			4,660			—			—			7,921
Midstream gathering and processing expenses	43,299			26,983			—			—			70,282
Depreciation, depletion and amortization	118,432			1			—			—			118,433
General and administrative expenses	10,731			(675		)	1			—			10,057
Accretion expense	951			116			—			—			1,067
	191,567			35,999			1			—			227,567

(LOSS) INCOME FROM OPERATIONS	(5,321		)	98,333			(1		)	—			93,011

OTHER (INCOME) EXPENSE:
Interest expense	35,925			(304		)	—			—			35,621
Interest income	(147		)	(5		)	—			—			(152		)
(Income) loss from equity method investments and investments in subsidiaries	(102,914		)	—			393			98,248			(4,273		)
Other income	(427		)	—			—			—			(427		)
	(67,563		)	(309		)	393			98,248			30,769

INCOME (LOSS) BEFORE INCOME TAXES	62,242			98,642			(394		)	(98,248		)	62,242
INCOME TAX BENEFIT	—			—			—			—			—

NET INCOME (LOSS)	$	62,242		$	98,642		$	(394	)	$	(98,248	)	$	62,242

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CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Amounts in thousands)



	Three months ended March 31, 2020
	Parent			Guarantors			Non-Guarantors			Eliminations		Consolidated

Net loss	$	(517,538	)	$	(552,238	)	$	(482	)	$	552,720	$	(517,538	)
Foreign currency translation adjustment	(15,030		)	(360		)	(14,670		)	15,030		(15,030		)
Other comprehensive loss	(15,030		)	(360		)	(14,670		)	15,030		(15,030		)
Comprehensive loss	$	(532,568	)	$	(552,598	)	$	(15,152	)	$	567,750	$	(532,568	)



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

Net income (loss)	$	62,242	$	98,642	$	(394	)	$	(98,248	)	$	62,242
Foreign currency translation adjustment	3,801		94		3,707			(3,801		)	3,801
Other comprehensive income	3,801		94		3,707			(3,801		)	3,801
Comprehensive income (loss)	$	66,043	$	98,736	$	3,313		$	(102,049	)	$	66,043

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

(Amounts in thousands)



	Three months ended March 31, 2020
	Parent			Guarantors			Non-Guarantors			Eliminations			Consolidated

Net cash provided by (used in) operating activities	$	64,033		$	66,805		$	(435	)	$	435		$	130,838

Net cash used in investing activities	(448		)	(69,361		)	—			—			(69,809		)

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

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	2,768			3,097			195			—			6,060

Cash, cash equivalents and restricted cash at end of period	$	897		$	541		$	195		$	—		$	1,633



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

Net cash provided by (used in) operating activities	$	210,928		$	28,837		$	(1	)	$	1		$	239,765

Net cash used in investing activities	(200,970		)	(44,593		)	(432		)	432			(245,563		)

Net cash (used in) provided by financing activities	(28,503		)	—			433			(433		)	(28,503		)

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	25,585			26,711			1			—			52,297

Cash, cash equivalents and restricted cash at end of period	$	7,040		$	10,955		$	1		$	—		$	17,996

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16.	SUBSEQUENT EVENTS

Derivatives

In April 2020, the Company early terminated its 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 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 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 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.

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 $2.46 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

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

Cautionary Note Regarding Forward-Looking Statements

This Form 10-Q may include forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended (the "Securities Act"), Section 21E of the Securities Exchange Act of 1934, as amended (the "Exchange Act"), and the Private Securities Litigation Reform Act of 1995, that are subject to risks and uncertainties. These statements involve known and unknown risks, uncertainties and other factors that may cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by the forward-looking statements. In some cases, you can identify forward looking statements by terms such as “may,” “will,” “should,” “could,” “would,” “expects,” “plans,” “anticipates,” “intends,” “believes,” “estimates,” “projects,” “predicts,” “potential” and similar expressions intended to identify forward-looking statements. All statements, other than statements of historical facts, included in this Form 10-Q that address activities, events or developments that we expect or anticipate will or may occur in the future, including such things as the expected impact of the COVID-19 pandemic on our business, our industry and the global economy, estimated future net revenues from oil and gas reserves and the present value thereof, future capital expenditures (including the amount and nature thereof), the effect of our remediation plan for a material weakness, business strategy and measures to implement strategy, competitive strength, goals, expansion and growth of our business and operations, plans, references to future success, reference to intentions as to future matters and other such matters are forward-looking statements.

These forward-looking statements are largely based on our expectations and beliefs concerning future events, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors relating to our operations and business environment, all of which are difficult to predict and many of which are beyond our control.

Although we believe our estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In addition, management's assumptions about future events may prove to be inaccurate. Management cautions all readers that the forward-looking statements contained in this Form 10-Q are not guarantees of future performance, and we cannot assure any reader that those statements will be realized or the forward-looking events and circumstances will occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to the factors listed in Item 1A. “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2019 and elsewhere in this Form 10-Q. All forward-looking statements speak only as of the date of this Form 10-Q.

All forward-looking statements, expressed or implied, included in this Quarterly Report are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.

Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this Quarterly Report.

Investors should note that we announce financial information in SEC filings, press releases and public conference calls. We may use the Investors section of our website (www.gulfportenergy.com) to communicate with investors. It is possible that the financial and other information posted there could be deemed to be material information. The information on our website is not part of this Quarterly Report on Form 10-Q.

Overview

We are an independent natural gas-weighted exploration and production company focused on the exploration, acquisition and production of natural gas, crude oil and natural gas liquids ("NGL") in the United States with primary focus in the Appalachia and Mid-Continent basins. Our principal properties are in Eastern Ohio targeting the Utica formation and in central Oklahoma targeting the SCOOP Woodford and SCOOP Springer formations.

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COVID-19

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

Our total net production averaged approximately 1,053.8 MMcfe per day during the three months ended March 31, 2020, as compared to 1,263.6 MMcfe per day during the same period in 2019. The 16% decrease in production is largely the result of a decrease in development activities of our Utica Shale and SCOOP operating areas beginning in the third and fourth quarters of 2019.

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Utica Shale. From January 1, 2020 through March 31, 2020, we spud seven gross and net wells in the Utica Shale, of which one was being drilled and six were in various stages of completion at March 31, 2020. In addition, we completed 15 gross and net operated wells. We did not participate in any additional wells that were drilled by other operators on our Utica Shale acreage.

As of May 1, 2020, we had one operated drilling rig running in the play and expect to continue with this level of activity through October 2020.

Aggregate net production from our Utica Shale acreage during the three months ended March 31, 2020 was approximately 73,575 MMcfe, or an average of 808.5 MMcfe per day, of which 97% was natural gas and 3% was oil and NGL.

SCOOP. From January 1, 2020 through March 31, 2020, we spud five gross (4.3 net) wells in the SCOOP, of which two were being drilled and three were in various stages of completion at March 31, 2020. In addition. we completed 4 gross (3.8 net) operated wells. We also participated in an additional four gross wells that were drilled by other operators on our SCOOP acreage.

As of May 1, 2020, we had one operated drilling rig running in the play and expect to continue with this level of activity for the remainder of 2020.

Aggregate net production from our SCOOP acreage during the three months ended March 31, 2020 was approximately 22,274 MMcfe, or an average of 244.8 MMcfe per day, of which 65% was from natural gas and 35% was from oil and NGL.

Niobrara Formation. From January 1, 2020 through May 1, 2020, there were no wells spud on our Niobrara Formation acreage. Aggregate net production was approximately 21.7 MMcfe, or an average of 238.4 Mcfe per day during the three months ended March 31, 2020, all of which was from oil.

Bakken. As of March 31, 2020, we had an 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 March 31, 2020 was approximately 24.3 MMcfe, or an average of 266.9 Mcfe per day, of which 86% was from oil and 14% was from natural gas and natural gas liquids.

RESULTS OF OPERATIONS

Comparison of the Three Month Periods Ended March 31, 2020 and 2019

We reported a net loss of $517.5 million for the three months ended March 31, 2020 as compared to net income of $62.2 million for the three months ended March 31, 2019. Included in the loss for the three months ended March 31, 2020 was a $553.3 million non-cash impairment of our oil and natural gas properties, which was the main driver of the change in our net (loss) income during the period. The remaining variance was related to a $73.7 million decrease in oil and natural gas revenues, a $15.1 million decrease in 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

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	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 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 production for the three months ended March 31, 2020 as compared to the three months ended March 31, 2019.

Depreciation, Depletion and Amortization

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	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 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 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, compared to no impairment charge of oil and gas properties during the three months ended 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 second quarter of 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.

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	)%

The decrease in income from equity method investments is primarily related to a $10.6 million loss related to our investment in Mammoth Energy during the three months ended March 31, 2020. See Note 4 to our consolidated financial statements for further discussion on 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 increase in general and administrative expenses, gross was due primarily due to an increase in non-recurring legal and consulting charges for the three months ended March 31, 2020 as compared to 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 March 31, 2020 as compared to the three months ended March 31, 2019.

Interest Expense

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	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

Decrease in interest expense for three months ended March 31, 2020 as compared to the three months ended March 31, 2019 was primarily due to continued repurchases of our senior notes.

Income Taxes. We recorded income tax expense of $7.3 million for three months ended March 31, 2020 compared to no income tax expense for the three months ended March 31, 2019. As of March 31, 2020, we had a federal net operating loss carryforward of approximately $1.4 billion, in addition to numerous temporary differences, which gave rise to a net deferred tax asset. Quarterly, management performs a forecast of our taxable income and analyzes other relevant factors to determine whether it is more likely than not that a valuation allowance is needed, looking at both positive and negative factors. A valuation allowance for our deferred tax assets is established if, in management’s opinion, it is more likely than not that some portion will not be realized. At March 31, 2020, a valuation allowance of $756.7 million has been maintained against the net deferred tax asset. Income tax expense during the three months ended March 31, 2020 is related to the recognition of a valuation allowance against a state deferred tax asset. On April 30, 2020, our Board of Directors approved the adoption of a tax benefits preservation plan that is intended to protect value by preserving our ability to use our tax attributes, such as NOLs, to offset potential future income taxes for federal income tax purposes. See Note 16 of the notes to our consolidated financial statement for more information.

Liquidity and Capital Resources

Overview. Historically, our primary sources of capital funding and liquidity have been our operating cash flow, borrowings under our revolving credit facility and issuances of equity and debt securities. Our ability to access 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, oil and NGL derivative activities, when combined with our sales of natural gas, oil and NGL, allow us to predict with greater certainty the total revenue we will receive.

As of 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 value of our oil swaps by monetizing our remaining position in April 2020 and entered into additional contracts to hedge our remaining 2020 and 2021 production in April and May 2020.

Credit Facility. We have entered into a senior secured revolving credit facility, as amended, with The Bank of Nova Scotia, as the lead arranger and administrative agent and other lenders. The credit agreement provides for a maximum facility amount of $1.5 billion and matures on December 13, 2021. As of March 31, 2020, we had a borrowing base of $1.2 billion, with an elected commitment of $1.0 billion, and $65.0 million in borrowings outstanding. Total funds available for borrowing under our revolving credit facility, after giving effect to an aggregate of $236.8 million of outstanding letters of credit, were $698.2 million as of 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.

Our revolving credit facility contains customary negative covenants including, but not limited to, restrictions on our and our subsidiaries’ ability to: incur indebtedness; grant liens; pay dividends and make other restricted payments; agree to payment restrictions affecting our restricted subsidiaries; make investments; undertake fundamental changes including selling all or substantially all of our assets; enter into swap contracts and forward sales contracts; dispose of assets; change the nature of their business; enter into transactions with their affiliates; and engage in certain transactions with restricted subsidiaries. The negative covenants are subject to certain exceptions as specified in our revolving credit facility. Our revolving credit facility also contains certain affirmative covenants, including, but not limited to the following financial covenants: (1) the ratio of net funded debt to EBITDAX (as defined under the revolving credit agreement) may not be greater than 4.00 to 1.00 for the twelve-month period of the end of each fiscal quarter; and (2) the ratio of EBITDAX to interest expense for the twelve-month period at the end of each fiscal quarter may not be less than 3.00 to 1.00. 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 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. During the three months ended March 31, 2020, we used borrowings under our revolving credit facility to repurchase in the open market approximately $25.9 million aggregate principal amount of our outstanding Notes for $10.2 million. This included approximately $7.5 million principal amount of the 2024 Notes, $8.2 million principal amount of the 2025 Notes, and $10.2 million principal amount of the 2026 Notes. We recognized a $15.3 million gain on debt extinguishment, which included retirement of unamortized issuance costs and fees associated with the repurchased debt.

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

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

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

Capital Expenditures. Our capital commitments have been primarily for the execution of our drilling programs and discounted repurchases of our senior notes. Our capital investment strategy is focused on prudently developing our existing properties to generate sustainable cash flow considering current and forecasted commodity prices while also selectively pursuing mergers or acquisitions in our current operating regions in an effort to gain scale and deepen our drilling inventory.

Our capital expenditures for 2020 are currently estimated to be in the range of $265.0 million to $285.0 million for drilling and completion expenditures. In addition, we currently expect to spend $20.0 million to $25.0 million in 2020 for non-drilling and completion expenditures, which includes acreage expenses, primarily lease extensions in the Utica Shale. The midpoint of the 2020 range of capital expenditures is 51% lower than the $602.5 million spent in 2019, primarily due to our decision to reduce capital activity in response to lower commodity prices, specifically natural gas prices, and our desire to fund our capital development program primarily with cash flow from operations. As a result of our decreased capital spending program for 2020 and the impact of our 2019 property divestitures, we expect our production volumes in 2020 to be approximately 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 loan agreements will be sufficient to meet our normal recurring operating needs and capital requirements for the next twelve months. We have the ability to react quickly to changing commodity prices and accelerate or decelerate our activity within our operating areas as market conditions warrant. Notwithstanding the foregoing, in the event commodity prices decline from current levels or our capital or other costs increase we may be required to obtain additional funds which we would seek to do through borrowings, offerings of debt or equity securities or other means, including the sale of assets. To the extent that access to 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 merger, acquisition and divestiture opportunities. Capital may not be available to us on acceptable terms or at all in the future. Further, if we are unable to obtain funds when needed or on acceptable terms, we may be required to delay or curtail implementation of our business plan or not be able to complete acquisitions that may be favorable to us. If the current low commodity price environment worsens, our revenues, cash flows, results of operations, liquidity and reserves may be materially and adversely affected.

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 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, 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 March 31, 2020, our material off-balance sheet arrangements and transactions include $236.8 million in letters of credit outstanding against our revolving credit facility and $105.1 million in surety bonds issued. Both the letters of credit and surety bonds are being used as financial assurance on certain firm transportation agreements. Management believes these items will expire without being funded. There are no other transactions, arrangements or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect our liquidity or availability of our capital resources. See Note 9 to our consolidated financial statements for further discussion of the various financial guarantees we have issued.

Critical Accounting Policies and Estimates

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

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ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

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

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

We determine the notional volume potentially subject to derivative contracts by reviewing our overall estimated future production levels, which are derived from extensive examination of existing producing reserve estimates and estimates of likely production from new drilling. Production forecasts are updated at least monthly and adjusted if necessary to actual results and activity levels. We do not enter into derivative contracts for volumes in excess of our share of forecasted production, and if production estimates were lowered for future periods and derivative instruments are already executed for some volume above the new production forecasts, the positions would be 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 market conditions and other factors. See Note 10 of the notes to our consolidated financial statements for further discussion of the fair value measurements associated with our derivatives.

As of March 31, 2020, our natural gas, oil and NGL derivative instruments consisted of the following types of instruments:


•	Swaps: We receive a fixed price and pay a floating market price to the counterparty for the hedged commodity. In exchange for higher fixed prices on certain of our swap trades, we may sell call options.


•	Basis Swaps: These instruments are arrangements that guarantee a fixed price differential to NYMEX from a specified delivery point. We receive the fixed price differential and pay the floating market price differential to the counterparty for the hedged commodity.

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•	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 March 31, 2020:



	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 2020	NYMEX WTI	6,000	$	59.83



	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
2022	NYMEX Henry Hub	628,000	$	2.90
2023	NYMEX Henry Hub	628,000	$	2.90

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 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 swap contracts for the 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 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 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 $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, we will cash-settle the difference with the counterparty.

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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 March 31, 2020, we had a net asset derivative position of $100.9 million as compared to a net liability derivative position of $8.3 million as of March 31, 2019, related to our 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 $63.9 million, while a 10% decrease in underlying commodity prices would have increased the fair value of these instruments by approximately $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 United States, or, if the eurodollar rates are elected, the eurodollar rates. At March 31, 2020, we had $65.0 million in borrowings outstanding under our revolving credit facility which bore interest at a weighted average rate of 2.45%. As of 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.

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

Remediation Plan for the Material Weakness. Our management is actively engaged in the implementation of remediation efforts to address the material weakness identified in the fourth quarter of 2019. Specifically, our management is in the process of implementing new controls and processes over the evaluation and transfer of unevaluated costs to the amortizable base. Our management believes that these actions will remediate the material weakness in internal control over financial reporting 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, its experience and the experience of others in similar cases or proceedings, and the opinions and views of legal counsel. Significant judgment is required in making these estimates and their final liabilities may ultimately be materially different.

We, along with a number of other oil and gas companies, have been named as a defendant in two separate complaints, one filed by the State of Louisiana and the Parish of Cameron in the 38th Judicial District Court for the Parish of Cameron on February 9, 2016 and the other filed by the State of Louisiana and the District Attorney for the 15th Judicial District of the State of Louisiana in the 15th Judicial District Court for the Parish of Vermilion on July 29, 2016 (together, the "Complaints"). The Complaints allege that certain of the defendants’ operations violated the State and Local Coastal Resources Management Act of 1978, as amended, and the rules, regulations, orders and ordinances adopted thereunder (the "CZM Laws") by causing substantial damage to land and waterbodies located in the coastal zone of the relevant Parish. The plaintiffs seek damages and other appropriate relief under the CZM Laws, including the payment of costs necessary to clear, re-vegetate, detoxify and otherwise restore the affected coastal zone of the relevant Parish to its original condition, actual restoration of such coastal zone to its original condition, and the payment of reasonable attorney fees and legal expenses and interest. The United States District Court for the Western District of Louisiana issued orders remanding the cases to their respective state court, and the defendants have appealed the remand orders to the 5th Circuit Court of Appeals.

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

In September 2019, a stockholder of Mammoth Energy filed a derivative action on behalf of Mammoth Energy against members of Mammoth Energy’s board of directors, including a director designated by us, and its significant stockholders, including us, in the United States District Court for the Western District of Oklahoma. The complaint alleges, among other things, that the members of Mammoth Energy’s board of directors breached their fiduciary duties and violated the Securities Exchange Act of 1934, as amended, in connection with Mammoth Energy’s activities in Puerto Rico following Hurricane Maria. The complaint seeks unspecified damages, the payment of reasonable attorney fees and legal expenses and interest and to force Mammoth Energy and its board of directors to make specified corporate governance reforms.

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

In March 2020, Robert F. Woodley, individually and on behalf of all others similarly situated, filed a federal securities class action against us, David M. Wood, Keri Crowell and Quentin R. Hicks in the United States District Court for the Southern District of New York. The complaint alleges that we made materially false and misleading statements regarding our business and operations in violation of the federal securities laws and seeks unspecified damages, the payment of reasonable attorneys’ fees, expert fees and other costs, pre-judgment and post-judgment interest, and such other and further relief that may be deemed just and proper.

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.

SEC Investigation

The SEC has commenced an investigation with respect to certain actions by our former management, including alleged improper personal use of company assets, and potential violations by our former management and the company of the Sarbanes-Oxley Act of 2002 in connection with such actions. We have fully cooperated and intend to continue to cooperate fully with the SEC’s investigation. Although it is not possible to predict the ultimate resolution or financial 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 Gulfport and its subsidiaries. They have implemented various policies, programs, procedures, training and audits to reduce and mitigate environmental risks. They conduct periodic reviews, on a company-wide basis, to assess changes in their environmental risk profile. Environmental reserves are established for environmental liabilities for which economic losses are probable and reasonably estimable. We manage our exposure to environmental liabilities in acquisitions by using an evaluation process that seeks to identify pre-existing contamination or compliance concerns and address the potential liability. Depending on the extent of an identified environmental concern, they may, among other things, exclude a property from the transaction, require the seller to remediate the property to their satisfaction in an acquisition or agree to assume liability for the remediation of the property.

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

Other Matters



ITEM 1A.	RISK FACTORS

Our business has many risks. Factors that could materially adversely affect our business, financial condition, operating results or liquidity and the trading price of our common stock or senior notes are described under "Risk Factors" in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2019. The risk factor below updates our risk factors previously discussed in our Annual Report on Form 10-K for the fiscal year ended December 31, 2019.

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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 a default under our revolving credit facility or the indentures governing our senior notes. Additionally, our credit ratings may be lowered, we may reduce or delay our planned capital expenditures or investments, and we may revise or delay our strategic plans.

We expect that the principal areas of operational risk for us are availability of service providers and supply chain disruption. Active development operations, including drilling and fracking operations, represent the greatest risk for transmission given 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 delay development operations.

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

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

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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 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	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 February 2020, we repurchased and canceled 80,115 shares of our common stock at a weighted average price of $0.98 to satisfy tax withholding requirements incurred upon the vesting of restricted stock unit awards.
(2)	In January 2019, our board of directors approved a new stock repurchase program to acquire up to $400.0 million of our outstanding common stock within a 24 month period. The program was suspended in the fourth quarter of 2019, and the May 1, 2020 amendment to our revolving credit facility prohibits further repurchases.



ITEM 3.	DEFAULTS UPON SENIOR SECURITIES

Not applicable.



ITEM 4.	MINE SAFETY DISCLOSURES

Not applicable.



ITEM 5.	OTHER INFORMATION

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



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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31.2

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

32.1

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

32.2

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

101.INS

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101.SCH

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101.CAL

XBRL Taxonomy Extension Calculation Linkbase Document.

101.DEF

XBRL Taxonomy Extension Definition Linkbase Document.

101.LAB

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101.PRE

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+	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: May 8, 2020



GULFPORT ENERGY CORPORATION

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

Gulfport Energy - 10-Q quarterly report FY2020 Q1

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