gpor-20200630

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)


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

For the quarterly period ended June 30, 2020


☐			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 ¨ Accelerated filer ý

Non-accelerated filer ¨ Smaller reporting company ☐

Emerging growth company ☐

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

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

As of July 31, 2020, 160,115,829 shares of the registrant’s common stock were outstanding.

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GULFPORT ENERGY CORPORATION

TABLE OF CONTENTS

Page

PART I FINANCIAL INFORMATION

Item 1.

Consolidated Financial Statements (Unaudited):

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

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

Consolidated Statements of Comprehensive Income for the Three and Six Months Ended June 3 0 , 2020 and 2019

Consolidated Statements of Stockholders’ Equity for the Six Months Ended June 30 , 2020 and 2019

Consolidated Statements of Cash Flows for the Six Months Ended June 30 , 2020 and 2019

Notes to Consolidated Financial Statements

Item 2.

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

Item 3.

Quantitative and Qualitative Disclosures About Market Risk

Item 4.

Controls and Procedures

PART II OTHER INFORMATION

Item 1.

Legal Proceedings

Item 1A.

Risk Factors

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds

Item 3.

Defaults Upon Senior Securities

Item 4.

Mine Safety Disclosures

Item 5.

Item 6.

GULFPORT ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS


	June 30, 2020		December 31, 2019
	(Unaudited)
	(In thousands, except share data)
Assets
Current assets:
Cash and cash equivalents	$	2,817	$	6,060


Accounts receivable—oil and natural gas sales	65,645		121,210
Accounts receivable—joint interest and other	19,389		47,975

Prepaid expenses and other current assets	10,862		4,431
Short-term derivative instruments	53,188		126,201
Total current assets	151,901		305,877
Property and equipment:
Oil and natural gas properties, full-cost accounting, $1,564,189 and $1,686,666 excluded from amortization in 2020 and 2019, respectively	10,730,992		10,595,735
Other property and equipment	96,838		96,719
Accumulated depletion, depreciation, amortization and impairment	(8,457,464)		(7,228,660)
Property and equipment, net	2,370,366		3,463,794
Other assets:
Equity investments	13,052		32,044
Long-term derivative instruments	4,298		563
Deferred tax asset	—		7,563

Operating lease assets	3,640		14,168
Operating lease assets—related parties	—		43,270
Other assets	37,000		15,540
Total other assets	57,990		113,148
Total assets	$	2,580,257	$	3,882,819
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable and accrued liabilities	$	315,575	$	415,218

Short-term derivative instruments	8,540		303
Current portion of operating lease liabilities	3,356		13,826
Current portion of operating lease liabilities—related parties	—		21,220
Current maturities of long-term debt	649		631
Total current liabilities	328,120		451,198
Long-term derivative instruments	45,615		53,135
Asset retirement obligation	61,371		60,355
Uncertain tax position liability	3,209		3,127

Non-current operating lease liabilities	284		342
Non-current operating lease liabilities—related parties	—		22,050
Long-term debt, net of current maturities	1,910,318		1,978,020
Total liabilities	2,348,917		2,568,227
Commitments and contingencies (Note 9)
Preferred stock, $0.01 par value; 5.0 million shares authorized (30 thousand authorized as redeemable 12% cumulative preferred stock, Series A), and none issued and outstanding	—		—
Stockholders’ equity:
Common stock - $0.01 par value, 200.0 million shares authorized, 160.1 million issued and outstanding at June 30, 2020 and 159.7 million at December 31, 2019	1,601		1,597
Paid-in capital	4,211,062		4,207,554
Accumulated other comprehensive loss	(54,991)		(46,833)
Accumulated deficit	(3,926,332)		(2,847,726)
Total stockholders’ equity	231,340		1,314,592
Total liabilities and stockholders’ equity	$	2,580,257	$	3,882,819

See accompanying notes to consolidated financial statements.

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GULFPORT ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)


	Three months ended June 30,						Six months ended June 30,
	2020		2019		2020		2019
	(In thousands)
REVENUES:
Natural gas sales	$	86,797	$	225,257	$	195,344	$	501,273
Oil and condensate sales	8,390		36,910		31,541		69,392
Natural gas liquid sales	10,252		25,687		27,165		57,812
Net gain on natural gas, oil and NGL derivatives	26,971		171,140		125,237		151,095
Total Revenues	132,410		458,994		379,287		779,572
OPERATING EXPENSES:
Lease operating expenses	15,686		22,388		31,672		42,195
Production taxes	3,605		8,098		8,404		16,019
Midstream gathering and processing expenses	59,974		72,015		117,870		142,297
Depreciation, depletion and amortization	64,790		124,951		142,818		243,384
Impairment of oil and natural gas properties	532,880		—		1,086,225		—
General and administrative expenses	10,470		11,727		26,639		21,784
Accretion expense	755		1,359		1,496		2,426

Total Operating Expenses	688,160		240,538		1,415,124		468,105
(LOSS) INCOME FROM OPERATIONS	(555,750)		218,456		(1,035,837)		311,467
OTHER EXPENSE (INCOME):
Interest expense	32,366		36,418		65,356		72,039
Interest income	(78)		(159)		(230)		(311)
Gain on debt extinguishment	(34,257)		—		(49,579)		—

Loss from equity method investments, net	45		125,582		10,834		121,309
Other expense	7,242		990		9,098		563
Total Other Expense	5,318		162,831		35,479		193,600
(LOSS) INCOME BEFORE INCOME TAXES	(561,068)		55,625		(1,071,316)		117,867
Income Tax Expense (Benefit)	—		(179,331)		7,290		(179,331)
NET (LOSS) INCOME	$	(561,068)	$	234,956	$	(1,078,606)	$	297,198
NET (LOSS) INCOME PER COMMON SHARE:
Basic	$	(3.51)	$	1.47	$	(6.75)	$	1.85
Diluted	$	(3.51)	$	1.47	$	(6.75)	$	1.84
Weighted average common shares outstanding—Basic	159,934		159,325		159,847		161,065
Weighted average common shares outstanding—Diluted	159,934		159,507		159,847		161,590

See accompanying notes to consolidated financial statements.

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GULFPORT ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE (LOSS) INCOME

(Unaudited)


	Three months ended June 30,						Six months ended June 30,
	2020		2019		2020		2019
	(In thousands)
Net (loss) income	$	(561,068)	$	234,956	$	(1,078,606)	$	297,198
Foreign currency translation adjustment	6,872		3,610		(8,158)		7,411

Other comprehensive income (loss)	6,872		3,610		(8,158)		7,411
Comprehensive (loss) income	$	(554,196)	$	238,566	$	(1,086,764)	$	304,609

See accompanying notes to consolidated financial statements.

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GULFPORT ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(Unaudited)


				Paid-in Capital		Accumulated Other Comprehensive (Loss) Income		Accumulated Deficit		Total Stockholders’ Equity
	Common Stock
	Shares	Amount
	(In thousands)
Balance at January 1, 2020	159,711	$	1,597	$	4,207,554	$	(46,833)	$	(2,847,726)	$	1,314,592
Net Loss	—	—		—		—		(517,538)		(517,538)
Other Comprehensive Loss	—	—		—		(15,030)		—		(15,030)
Stock Compensation	—	—		2,104		—		—		2,104
Shares Repurchased	(80)	(1)		(78)		—		—		(79)
Issuance of Restricted Stock	211	2		(2)		—		—		—
Balance at March 31, 2020	159,842	$	1,598	$	4,209,578	$	(61,863)	$	(3,365,264)	$	784,049
Net Loss	—	—		—		—		(561,068)		(561,068)
Other Comprehensive Income	—	—		—		6,872		—		6,872
Stock Compensation	—	—		1,515		—		—		1,515
Shares Repurchased	(27)	—		(28)		—		—		(28)
Issuance of Restricted Stock	301	3		(3)		—		—		—
Balance at June 30, 2020	160,116	$	1,601	$	4,211,062	$	(54,991)	$	(3,926,332)	$	231,340


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

See accompanying notes to consolidated financial statements.

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GULFPORT ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Six months ended June 30,
	2020		2019
	(In thousands)
Cash flows from operating activities:
Net (loss) income	$	(1,078,606)	$	297,198
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depletion, depreciation and amortization	142,818		243,384
Impairment of oil and natural gas properties	1,086,225		—
Loss (income) from equity investments	10,834		121,449
Gain on debt extinguishment	(49,579)		—
Net gain on derivative instruments	(125,237)		(151,095)
Net cash receipts (payments) on settled derivative instruments	195,232		(1,494)
Deferred income tax expense	7,290		(179,331)

Other, net	9,844		11,341
Changes in operating assets and liabilities:
Decrease in accounts receivable—oil and natural gas sales	55,565		78,525
Decrease (increase) in accounts receivable—joint interest and other	29,159		(24,148)

(Decrease) increase in accounts payable and accrued liabilities	(30,620)		3,220
Other, net	(5,703)		720
Net cash provided by operating activities	247,222		399,769
Cash flows from investing activities:

Additions to oil and natural gas properties	(274,851)		(508,315)
Proceeds from sale of oil and natural gas properties	45,185		745
Additions to other property and equipment	(575)		(4,298)

Proceeds from sale of other property and equipment	151		130


Contributions to equity method investments	—		(432)
Distributions from equity method investments	—		1,945

Net cash used in investing activities	(230,090)		(510,225)
Cash flows from financing activities:
Principal payments on borrowings	(323,322)		(345,350)
Borrowings on line of credit	326,000		455,000

Repurchases of senior notes	(22,827)		—
Payments for repurchases of stock under approved stock repurchase program	—		(30,000)
Other, net	(226)		(714)

Net cash (used in) provided by financing activities	(20,375)		78,936
Net decrease in cash, cash equivalents and restricted cash	(3,243)		(31,520)
Cash, cash equivalents and restricted cash at beginning of period	6,060		52,297
Cash, cash equivalents and restricted cash at end of period	$	2,817	$	20,777
Supplemental disclosure of cash flow information:
Interest payments	$	60,523	$	67,472
Income tax receipts	$	—	$	(1,794)
Supplemental disclosure of non-cash transactions:
Capitalized stock-based compensation	$	1,891	$	2,252
Asset retirement obligation capitalized	$	1,553	$	6,230
Asset retirement obligation removed due to divestiture	$	(2,033)	$	—
Interest capitalized	$	710	$	1,771
Fair value of contingent consideration asset on date of divestiture	$	23,090	$	—
Foreign currency translation (loss) gain on equity method investments	$	(8,158)	$	7,411

See accompanying notes to consolidated financial statements.

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GULFPORT ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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

Basis of Presentation

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

The consolidated financial statements should be read in conjunction with the consolidated financial statements and the summary of significant accounting policies and notes included in the Company’s most recent annual report on Form 10-K. Results for the three and six months ended June 30, 2020 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 have imposed regulations in efforts to control the spread of COVID-19 such as shelter-in-place orders, quarantines, executive orders and similar restrictions.

Gulfport remains focused on protecting the health and well-being of its employees and the communities in which it operates while assuring the continuity of its business operations. The Company implemented preventative measures and developed corporate and field response plans to minimize unnecessary risk of exposure and prevent infection. Additionally, the Company has a crisis management team for health, safety and environmental matters and personnel issues, and has established a COVID-19 Response Team to address various impacts of the situation, as they have been developing. Gulfport has modified certain business practices (including remote working for its corporate employees and restricted employee business travel) to conform to government restrictions and best practices encouraged by the Centers for Disease Control and Prevention, the World Health Organization and other governmental and regulatory authorities. In May 2020, the Company began its phased transition back to the office for its corporate employees. As part of this transition, the Company put into place preventative measures to focus on social distancing and minimizing unnecessary risk of exposure. As of the date of this filing, Gulfport has transitioned approximately 60% of its corporate employees back to the corporate office. The Company will continue to monitor trends and governmental guidelines and may adjust its return to office plans accordingly to ensure the health and safety of its employees. As a result of its business continuity measures, the Company has not experienced significant disruptions in executing its business operations in 2020.

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

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

Liquidity, Management's Plans and Going Concern

As noted above, decreased demand for oil and natural gas as a result of the COVID-19 pandemic and the accompanying decrease in commodity prices has significantly impaired the Company's ability to access capital markets and to refinance its

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

In the current depressed commodity price environment and period of economic uncertainty, the Company has taken various steps over the last several months to improve its balance sheet and preserve liquidity including (1) exercising capital discipline by reducing 2020 capital spending by 50% as compared to 2019, (2) focusing on operational efficiencies to reduce operating costs as evidenced by the recent reductions in Development and Completion costs per lateral foot, (3) reducing corporate general and administrative costs significantly, (4) and repurchasing unsecured notes at a deep discount.

Although management’s actions listed above have helped to improve our liquidity and leverage profile, continued macro headwinds including the depressed state of energy capital markets and the extraordinarily low commodity price environments present significant risks to the Company's ability to fund its operations going forward. Accordingly, management has determined there is substantial doubt about its ability to continue as a going concern over the next twelve months from the issuance of these financial statements. The Company has engaged financial and legal advisors to assist with the evaluation of a range of liability management alternatives. Additionally, the Company maintains an active dialogue with its senior lenders and bondholders regarding liability management alternatives to improve its balance sheet. There can be no assurances that the Company will be able to successfully complete a liability management transaction that materially improves the Company’s leverage profile or liquidity position.

The consolidated financial statements (i) have been prepared on a going concern basis, which contemplates the realization of assets and satisfaction of liabilities and other commitments in the normal course of business and (ii) do not include any adjustments to reflect the possible future effects of the uncertainty on the recoverability or classification of recorded asset amounts or the amounts or classifications of liabilities.

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 six months ended June 30, 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 $90.8 million with a corresponding increase in net cash flows used in investing activities. The Company has evaluated the effect of the previous 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, including historical experience, current conditions and reasonable and supportable forecasts that affect the collectibility of the

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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 June 30, 2020 and December 31, 2019 are as follows:


	June 30, 2020		December 31, 2019
	(In thousands)
Oil and natural gas properties	$	10,730,992	$	10,595,735
Accumulated DD&A and impairment	(8,415,756)		(7,191,957)
Oil and natural gas properties, net	2,315,236		3,403,778
Other depreciable property and equipment	91,317		91,198
Land	5,521		5,521
Accumulated DD&A	(41,708)		(36,703)
Other property and equipment, net	55,130		60,016
Property and equipment, net	$	2,370,366	$	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 June 30, 2020, the net book value of the Company's oil and gas properties, less related deferred income taxes, was above the calculated ceiling primarily as a result of reduced commodity prices for the period leading up to June 30, 2020. As a result, the Company was required to record impairments of its oil and natural gas properties of $532.9 million and $1.1 billion for the three and six months ended June 30, 2020, respectively. No impairments were required for oil and natural gas properties for the three and six months ended June 30, 2019.

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

General 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 exploration and development activities. All general and administrative costs not directly associated with exploration and development activities are charged to expense as they are incurred. Capitalized general and administrative costs were approximately $8.2 million and $13.6 million for the three and six months ended June 30, 2020, respectively, and $8.8 million and $16.5 million for the three and six months ended June 30, 2019, respectively.

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

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


	June 30, 2020
	(In thousands)
Utica	$	874,886
MidContinent	687,169
Other	2,134
	$	1,564,189

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

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

Asset Retirement Obligation

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


	June 30, 2020		June 30, 2019
	(In thousands)
Asset retirement obligation, beginning of period	$	60,355	$	79,952
Liabilities incurred	1,553		5,153
Liabilities settled	—		(117)
Liabilities removed due to divestitures	(2,033)		—
Accretion expense	1,496		2,426
Revisions in estimated cash flows	—		1,077
Asset retirement obligation as of end of period	61,371		88,491

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 June 30, 2020 and December 31, 2019:


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

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

Summarized balance sheet information:

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	June 30, 2020		December 31, 2019

	(In thousands)
Current assets	$	434,966	$	421,326
Noncurrent assets	$	1,107,221	$	1,260,075
Current liabilities	$	115,281	$	132,569
Noncurrent liabilities	$	172,478	$	163,241

Summarized results of operations:


	Three months ended June 30,						Six months ended June 30,
	2020		2019		2020		2019
	(In thousands)
Gross revenue	$	60,109	$	179,114	$	157,492	$	443,958
Net (loss) income	$	(14,922)	$	(4,072)	$	(99,953)	$	20,684

Grizzly Oil Sands ULC

The Company, through its wholly owned subsidiary Grizzly Holdings Inc. (“Grizzly Holdings”), owns an approximate 24.6% interest in Grizzly Oil Sands ULC (“Grizzly”), a Canadian unlimited liability company. The remaining interest in Grizzly is owned by Grizzly Oil Sands Inc. As of June 30, 2020, Grizzly had approximately 830,000 acres under lease in the Athabasca, Peace River and Cold Lake oil sands regions of Alberta, Canada. The Company reviewed its investment in Grizzly for impairment at June 30, 2020 and 2019 and determined no impairment was required. The Company paid $0.4 million in cash calls during the six months ended June 30, 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 increased by $6.9 million as a result of a foreign currency translation gain and decreased by $7.8 million as a result of a foreign currency translation loss for the three and six months ended June 30, 2020, respectively. The Company's investment in Grizzly was increased by $3.5 million and $7.3 million for the three and six months ended June 30, 2019, respectively, as a result of a foreign currency translation gain.

Mammoth Energy Services, Inc.

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

At March 31, 2020, the Company's share of net loss of Mammoth was in excess of the carrying value of its investment. As such, the Company's investment value was reduced to zero at March 31, 2020. During the second quarter of 2020, the Company's share of net loss of Mammoth continued to be in excess of the carrying value of its investment and, therefore, the Company's investment value remained at zero at June 30, 2020.

The Company received no distributions from Mammoth Energy during the six months ended June 30, 2020 and distributions of $2.5 million during the six months ended June 30, 2019 as a result of $0.125 per share dividends in February 2019 and May 2019. The loss (income) from equity method investments presented in the table above reflects any intercompany profit eliminations.

Windsor Midstream LLC

At June 30, 2020, the Company held a 22.5% interest in Windsor Midstream LLC (“Midstream”), an entity controlled and managed by an unrelated third party. The Company received no distributions from Midstream during the six months ended June 30, 2020.

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Tatex Thailand II, LLC

The Company has an indirect ownership interest in Tatex Thailand II, LLC ("Tatex") and received no distributions and $2.1 million in distributions from Tatex during the six months ended June 30, 2020 and 2019, respectively. Tatex previously held an 8.5% interest in APICO, LLC (“APICO”), an international oil and gas exploration company, before selling its interest in June 2019. APICO has a reserve base located in Southeast Asia through its ownership of concessions covering approximately 108,000 acres which includes the Phu Horm Field.

5.LONG-TERM DEBT

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


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

(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 May 1, 2020, the Company entered into the fifteenth amendment to the Amended and Restated Credit Agreement. As part of the amendment, the Company's borrowing base and elected commitment were reduced from $1.2 billion and $1.0 billion, respectively, to $700.0 million. Additionally, the amendment added a requirement to maintain a ratio of Net Secured Debt to EBITDAX (as defined under the revolving credit agreement) not exceeding 2.00 to 1.00, deferred the requirement to maintain a ratio of Net Funded Debt to EBITDAX of 4.00 to 1.00 until September 30, 2021 and added a limitation on the repurchase of unsecured notes, among other amendments.

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

As of June 30, 2020, $123.0 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 $324.1 million letters of credit, was $252.9 million. The Company’s wholly owned subsidiaries have guaranteed the obligations of the Company under the revolving credit facility.

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

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

(2) Loan issuance costs related to the 6.625% Senior Notes due 2023 (the "2023 Notes"), the 6.000% Senior Notes due 2024 (the "2024 Notes"), the 6.375% Senior Notes due 2025 (the "2025 Notes") and the 6.375% Senior Notes due 2026 (the "2026 Notes") (collectively the “Notes”) have been presented as a reduction to the principal amount of the Notes. At June 30, 2020, total unamortized debt issuance costs were $2.8 million for the 2023 Notes, $6.1 million for the 2024 Notes, $8.5 million for the 2025 Notes and $3.4 million for the 2026 Notes. In addition, loan commitment fee costs for the Company's construction loan agreement were $0.1 million at June 30, 2020.

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

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

Debt Repurchases

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

Fair Value of Debt

At June 30, 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 $930.2 million at June 30, 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 stock repurchases.

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

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

7.STOCK-BASED COMPENSATION

The Company has granted restricted stock units to employees and directors pursuant to the 2019 Amended and Restated Incentive Stock Plan ("2019 Plan"), as discussed below. During the three and six months ended June 30, 2020, the Company’s stock-based compensation cost was $2.2 million and $4.3 million, respectively, of which the Company capitalized $1.0 million and $1.9 million, respectively, relating to its exploration and development efforts. During the three and six months ended June 30, 2019, the Company’s stock-based compensation cost was $2.8 million and $5.6 million, respectively, of which the Company capitalized $1.1 million and $2.3 million, respectively, relating to its exploration and development efforts. Stock compensation costs, net of the amounts capitalized, are included in general and administrative expenses in the accompanying consolidated statements of operations.

The following table summarizes restricted stock unit activity for the six months ended June 30, 2020:

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	Number of Unvested Restricted Stock Units	Weighted Average Grant Date Fair Value		Number of Unvested Performance Vesting Restricted Stock Units	Weighted Average Grant Date Fair Value
Unvested shares as of January 1, 2020	4,098,318	$	4.73	1,783,660	$	2.96
Granted	1,985,452	0.67		—	—
Vested	(512,283)	7.19		—	—
Forfeited	(979,929)	3.82		(830,323)	1.98
Unvested shares as of June 30, 2020	4,591,558	$	3.00	953,337	$	3.82

Restricted Stock Units

Restricted stock units awarded under the 2019 Plan generally vest over a period of one year in the case of directors and three years in the case of employees and vesting is dependent upon the recipient meeting applicable service requirements. Stock-based compensation costs are recorded ratably over the service period. The grant date fair value of restricted stock units represents the closing market price of the Company's common stock on the date of grant. Unrecognized compensation expense as of June 30, 2020 related to restricted stock units was $9.4 million. The expense is expected to be recognized over a weighted average period of 1.75 years.

Performance Vesting Restricted Stock Units

The Company has awarded performance vesting units to certain of its executive officers under the 2019 Plan. The number of shares of common stock issued pursuant to the award will be based on relative total shareholder return ("RTSR"). RTSR is an incentive measure whereby participants will earn from 0% to 200% of the target award based on the Company’s RTSR ranking compared to the RTSR of the companies in the Company’s designated peer group at the end of the performance period. Awards will be earned and vested over a performance period measured from January 1, 2019 to December 31, 2021, subject to earlier termination of the performance period in the event of a change in control. Unrecognized compensation expense as of June 30, 2020 related to performance vesting restricted shares was $2.2 million. The expense is expected to be recognized over a weighted average period of 1.78 years.

Cash Incentive Awards

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

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

8.EARNINGS PER SHARE

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

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



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

There were 1,281,773 and 1,610,572 shares of common stock that were considered anti-dilutive for the three and six months ended June 30, 2020, respectively. There were no potential shares of common stock that were considered anti-dilutive for the three and six months ended June 30, 2019.

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 June 30, 2020 are set forth in the table below:


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


Total						590,000

Future Firm Transportation Commitments

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

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

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


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

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

Other Commitments

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

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


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

Total	$	11,250

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

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

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

In December 2019, the Company filed a lawsuit against Stingray Pressure Pumping LLC, a subsidiary of Mammoth Energy (“Stingray”), for breach of contract and to terminate the Master Services Agreement for pressure pumping services, effective as of October 1, 2014, as amended (the “Master Services Agreement”), between Stingray and the Company. In March 2020, Stingray filed a counterclaim against the Company in the Superior Court of the State of Delaware. The counterclaim alleges that the Company has breached the Master Services Agreement. The counterclaim seeks actual damages, which the complaint calculates to be approximately $28.0 million as of June 2020 (such amount to increase each month), the payment of reasonable attorney fees and legal expenses and pre- and post-judgment interest as allowed, and such other and further relief which it may be justly entitled.

In April 2020, Bryon Lefort, individually and on behalf of similarly situated individuals, filed an action against the Company in the United States District Court for the Southern District of Ohio Eastern Division. The complaint alleges that the Company violated the Fair Labor Standards Act (“FLSA”), the Ohio Wage Act and the Ohio Prompt Pay Act by classifying the plaintiffs as independent contractors and paying them a daily rate with no overtime compensation for hours worked in excess of 40 hours per week. The complaint seeks to recover unpaid regular and overtime wages, liquidated damages in an amount equal

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to six 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.

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

Other Matters

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

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, costless collars 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 June 30, 2020.

Location

Daily Volume
(MMBtu/day)

Weighted
Average Price

Remaining 2020

NYMEX Henry Hub

357,000

2.86

Location

Daily Volume
(Bbls/day)

Weighted
Average Price

Remaining 2020

NYMEX WTI

3,000

35.49

Location

Daily Volume
(Bbls/day)

Weighted
Average Price

Remaining 2020

Mont Belvieu C3

1,500

20.27

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

The Company entered into costless collars based off the NYMEX Henry Hub natural gas index. Each two-way price collar has a set floor and ceiling price for the hedged production. If the applicable monthly price indices are outside of the ranges set by the floor and ceiling prices in the various collars, the Company will cash-settle the difference with the counterparty.


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

In addition, the Company entered into natural gas basis swap positions. As of June 30, 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)

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

Contingent Consideration Arrangement

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


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


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

Balance Sheet Presentation

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


	June 30, 2020		December 31, 2019
	(In thousands)
Commodity Contracts:
Short-term derivative asset	$	53,188	$	125,383
Long-term derivative asset	4,298		—
Short-term derivative liability	(8,540)		(303)
Long-term derivative liability	(45,615)		(53,135)
Total commodity derivative position	$	3,331	$	71,945

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

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

Gains and Losses

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


	Net gain (loss) on derivative instruments
	Three months ended June 30,						Six months ended June 30,
	2020		2019		2020		2019
	(In thousands)
Natural gas derivatives	$	35,689	$	152,475	$	81,542	$	136,044
Oil derivatives	(7,937)		11,871		44,937		11,417
NGL derivatives	(781)		6,794		139		3,634
Contingent consideration arrangement	—		—		(1,381)		—
Total	$	26,971	$	171,140	$	125,237	$	151,095

Offsetting of Derivative Assets and Liabilities

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


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


	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.

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11.FAIR VALUE MEASUREMENTS

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

Level 1 – Quoted prices in active markets for identical assets and liabilities.

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

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

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

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


	June 30, 2020
	Level 1		Level 2		Level 3
	(In thousands)
Assets:
Derivative Instruments	$	—	$	57,486	$	—
Liabilities:
Derivative Instruments	$	—	$	54,155	$	—


	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 June 30, 2020, the fair value of the contingent consideration was $19.8 million, of which $0.8 million is included in prepaid expenses and other assets and $19.0 million is included in other assets in the accompanying consolidated balance sheets. The fair value of the contingent consideration arrangement is calculated using discounted cash flow techniques and is based on internal estimates of the Company's future development program and water production levels. Given the unobservable nature of the inputs, the fair value measurement of the contingent consideration arrangement is deemed to use Level 3 inputs. The Company has elected the fair value option for this contingent consideration arrangement and, therefore, records changes in fair value in earnings. The Company recognized a loss of $3.2 million and $3.0 million on changes in fair value of the contingent consideration during the three and six months ended June 30, 2020, respectively, which is included in other expense (income) in

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

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 six months ended June 30, 2020 were approximately $1.6 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 $65.6 and $121.2 million as of June 30, 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

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estimate the amount of production that was delivered to the purchaser and the price that will be received for the sale of the product. The differences between the estimates and the actual amounts for product sales is recorded in the month that payment is received from the purchaser. For the six months ended June 30, 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 a contract for a drilling rig with a third party to ensure rig availability. 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 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 be exercised; therefore, renewal options are not considered in the lease term for drilling contracts. The operating lease liability associated with its rig commitment is based on the minimum contractual obligation, primarily standby rate, and does not include variable amounts based on actual activity in a given period. The Company has also entered into 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 the Master Services Agreement for pressure pumping with Stingray Pressure. As a result, in the first quarter of 2020, Gulfport has removed the related right of use assets and lease liabilities associated with the terminated contract.

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.

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Maturities of operating lease liabilities as of June 30, 2020 were as follows:


	(In thousands)
Remaining 2020	$	3,321
2021	129
2022	115
2023	90
2024	30
Total lease payments	$	3,685
Less: Imputed interest	(45)
Total	$	3,640

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


	Three months ended June 30,						Six months ended June 30,
	2020		2019		2020		2019
	(In thousands)
Operating lease cost	$	2,196	$	7,748	$	6,278	$	16,284
Operating lease cost—related party	—		5,610		—		11,220
Variable lease cost	235		531		460		960
Variable lease cost—related party	—		28,158		—		59,611
Short-term lease cost	2,629		183		5,439		183
Total lease cost⁽¹⁾	$	5,060	$	42,230	$	12,177	$	88,258

(1)

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

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


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

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

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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 and six months ended June 30, 2020, the Company's estimated annual effective tax rate before discrete items remained near zero as a result of the valuation allowance on its deferred tax assets. During the first quarter of 2020, 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 and six months ended June 30, 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 NOLs that corporations can use to offset income, and increasing the amount of deductible interest under section 163(j). The Company does not expect to be materially impacted by the CARES Act provision and does not anticipate the CARES Act to have a material effect on its 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 board of directors of the Company adopted a tax benefits preservation plan in order to protect against a possible limitation on the Company’s ability to use its tax net operating losses and certain other tax benefits to reduce potential future U.S. federal income tax obligations. The Tax Benefits Preservation Plan is intended to prevent against such an ownership change by deterring any person or group from acquiring beneficial ownership of 4.9% or more of the Company’s securities.

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15.CONDENSED CONSOLIDATING FINANCIAL INFORMATION

The 2023 Notes, the 2024 Notes, the 2025 Notes and the 2026 Notes are guaranteed on a senior unsecured basis by all existing consolidated subsidiaries that guarantee the Company’s secured revolving credit facility or certain other debt (the “Guarantors”). The Notes are not guaranteed by Grizzly Holdings or Mule Sky LLC ("Mule Sky") (the “Non-Guarantors”). The Guarantors are 100% owned by Gulfport (the “Parent”), and the guarantees are full, unconditional, joint and several. There are no significant restrictions on the ability of the Parent or the Guarantors to obtain funds from each other in the form of a dividend or loan. Effective June 1, 2019, the Parent contributed interests in certain oil and gas assets and related liabilities to certain of the Guarantors.

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

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CONDENSED CONSOLIDATING BALANCE SHEETS

(Amounts in thousands)


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

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

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


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

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

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

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

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

Non-current operating lease liabilities	284		—		—		—		284

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

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

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CONDENSED CONSOLIDATING BALANCE SHEETS

(Amounts in thousands)


	December 31, 2019
	Parent		Guarantors		Non-Guarantor		Eliminations		Consolidated
Assets
Current assets:
Cash and cash equivalents	$	2,768	$	3,097	$	195	$	—	$	6,060

Accounts receivable - oil and natural gas sales	859		120,351		—		—		121,210
Accounts receivable - joint interest and other	5,279		42,696		—		—		47,975
Accounts receivable - intercompany	1,065,593		843,223		—		(1,908,816)		—
Prepaid expenses and other current assets	4,047		308		76		—		4,431
Short-term derivative instruments	126,201		—		—		—		126,201
Total current assets	1,204,747		1,009,675		271		(1,908,816)		305,877
Property and equipment:
Oil and natural gas properties, full-cost accounting,	1,314,933		9,273,681		7,850		(729)		10,595,735
Other property and equipment	92,650		50		4,019		—		96,719
Accumulated depletion, depreciation, amortization and impairment	(1,418,888)		(5,808,254)		(1,518)		—		(7,228,660)
Property and equipment, net	(11,305)		3,465,477		10,351		(729)		3,463,794
Other assets:
Equity investments and investments in subsidiaries	3,064,503		6,332		21,000		(3,059,791)		32,044
Long-term derivative instruments	563		—		—		—		563
Deferred tax asset	7,563		—		—		—		7,563
Operating lease assets	14,168		—		—		—		14,168
Operating lease assets - related parties	43,270		—		—		—		43,270
Other assets	10,026		5,514		—		—		15,540
Total other assets	3,140,093		11,846		21,000		(3,059,791)		113,148
Total assets	$	4,333,535	$	4,486,998	$	31,622	$	(4,969,336)	$	3,882,819

Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable and accrued liabilities	$	48,006	$	367,088	$	124	$	—	$	415,218
Accounts payable - intercompany	878,283		1,026,249		4,285		(1,908,817)		—

Short-term derivative instruments	303		—		—		—		303
Current portion of operating lease liabilities	13,826		—		—		—		13,826
Current portion of operating lease liabilities - related parties	21,220		—		—		—		21,220
Current maturities of long-term debt	631		—		—		—		631
Total current liabilities	962,269		1,393,337		4,409		(1,908,817)		451,198
Long-term derivative instruments	53,135		—		—		—		53,135
Asset retirement obligation - long-term	—		58,322		2,033		—		60,355
Uncertain tax position liability	3,127		—		—		—		3,127
Non-current operating lease liabilities	342		—		—		—		342
Non-current operating lease liabilities - related parties	22,050		—		—		—		22,050

Long-term debt, net of current maturities	1,978,020		—		—		—		1,978,020
Total liabilities	3,018,943		1,451,659		6,442		(1,908,817)		2,568,227

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

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CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

(Amounts in thousands)


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

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

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

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

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



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

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

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

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CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

(Amounts in thousands)


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

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

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

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


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

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

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



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

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

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

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CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

(Amounts in thousands)


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

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

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

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

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



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

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

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

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CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

(Amounts in thousands)


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

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

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

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

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

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

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



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

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

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

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CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Amounts in thousands)


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

Net loss	$	(561,068)	$	(562,178)	$	(324)	$	562,502	$	(561,068)
Foreign currency translation adjustment	6,872		—		6,872		(6,872)		6,872
Other comprehensive loss	6,872		—		6,872		(6,872)		6,872
Comprehensive loss	$	(554,196)	$	(562,178)	$	6,548	$	555,630	$	(554,196)


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

Net income (loss)	$	234,956	$	78,291	$	(104)	$	(78,187)	$	234,956
Foreign currency translation adjustment	3,610		61		3,549		(3,610)		3,610


Other comprehensive income	3,610		61		3,549		(3,610)		3,610
Comprehensive income	$	238,566	$	78,352	$	3,445	$	(81,797)	$	238,566


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

Net loss	$	(1,078,606)	$	(1,114,416)	$	(806)	$	1,115,222	$	(1,078,606)
Foreign currency translation adjustment	(8,158)		(360)		(7,798)		8,158		(8,158)
Other comprehensive loss	(8,158)		(360)		(7,798)		8,158		(8,158)
Comprehensive loss	$	(1,086,764)	$	(1,114,776)	$	(8,604)	$	1,123,380	$	(1,086,764)


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

Net income (loss)	$	297,198	$	176,933	$	(498)	$	(176,435)	$	297,198
Foreign currency translation adjustment	7,411		155		7,256		(7,411)		7,411
Other comprehensive income	7,411		155		7,256		(7,411)		7,411
Comprehensive income	$	304,609	$	177,088	$	6,758	$	(183,846)	$	304,609

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CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

(Amounts in thousands)


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

Net cash provided by (used in) operating activities	$	18,854	$	228,317	$	(384)	$	435	$	247,222

Net cash used in investing activities	(424)		(229,666)		—		—		(230,090)

Net cash (used in) provided by financing activities	(20,375)		—		435		(435)		(20,375)

Net (decrease) increase in cash, cash equivalents and restricted cash	(1,945)		(1,349)		51		—		(3,243)

Cash, cash equivalents and restricted cash at beginning of period	2,768		3,097		195		—		6,060

Cash, cash equivalents and restricted cash at end of period	$	823	$	1,748	$	246	$	—	$	2,817


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

Net cash provided by (used in) operating activities	$	312,267	$	84,146	$	3,355	$	1	$	399,769

Net cash used in investing activities	(405,848)		(101,058)		(3,751)		432		(510,225)

Net cash (used in) provided by financing activities	78,936		—		433		(433)		78,936

Net decrease in cash, cash equivalents and restricted cash	(14,645)		(16,912)		37		—		(31,520)

Cash, cash equivalents and restricted cash at beginning of period	25,585		26,711		1		—		52,297

Cash, cash equivalents and restricted cash at end of period	$	10,940	$	9,799	$	38	$	—	$	20,777

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16.SUBSEQUENT EVENTS

Amendment to Credit Facility

On July 27, 2020, Gulfport entered into a Sixteenth Amendment to the Amended and Restated Credit Agreement. Among other changes, the Sixteenth Amendment amends the Credit Agreement to: (i) require that, in the event of any issuances of Senior Notes, including Second Lien Notes, after the effective date, the then effective borrowing base will be reduced by a variable amount prescribed in the Credit Agreement to the extent the proceeds are not used to satisfy previously issued senior notes within 90 days of such issuance; (ii) require that each Loan Notice specify the amount of the then effective Borrowing Base and Pro Forma Borrowing Base, the Aggregate Elected Commitment Amount, and the current Total Outstandings, both with and without regard to the requested Borrowing; (iii) permit the Borrower or any Restricted Subsidiary to enter into obligations in connection with a Permitted Bond Hedge Transaction or Permitted Warrant Transaction; (iv) permit the Borrower to make any payments of Senior Notes and Subordinated Obligation prior to their scheduled maturity, in any event not to exceed $750,000,000 or, if lesser, the net cash proceeds of any Senior Notes issued within 90 days before such payment; (v) require that the Senior Notes have a stated maturity date of no earlier than March 13, 2024, as well as not require payment of principal prior to such date, in order for the Borrower to be permitted to secure indebtedness under the Senior Notes; (vi) permit certain additional liens securing obligations in respect of the incurrence or issuance of any Permitted Refinancing Notes (as such term is defined in the Credit Agreement) not to exceed $750,000,000, subject to the terms of an intercreditor agreement; and (vii) amend and restate the Applicable Rate Grid to provide as follows:


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

Derivatives

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

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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

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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.

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.

We remain focused on protecting the health and well-being 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 for our corporate employees and restricted employee business travel) to conform to government restrictions and best practices encouraged by the Centers for Disease Control and Prevention, the World Health Organization and other governmental and regulatory authorities.

On May 18, 2020, we began our phased transition back to the office for our corporate employees. As part of this transition, we have put into place preventative measures to focus on social distancing and minimizing unnecessary risk of exposure. Such measures include, but are not limited to, daily health surveys, protective masks in public areas of the building, no outside visitors, limiting the number of employees on elevators, additional sanitizing and 100% of the corporate employees working remotely on Fridays to provide additional time for deep cleaning. As of the date of this filing, we have transitioned approximately 60% of our corporate employees back to the corporate office. We will continue to monitor trends and governmental guidelines and may adjust our return to office plans accordingly to ensure the health and safety of our employees.

As a result of our business continuity measures, we have not experienced significant disruptions in executing our business operations in the first and second quarters of 2020. While we have not experienced significant disruptions to our operations in 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, we chose to shut in a portion of our operated low margin, liquids-weighted production during the second quarter of 2020, largely consisting of legacy vertical production in the SCOOP. We also experienced shut ins across both the SCOOP and Utica from our non-operated partners. Nearly all liquids-weighted volumes on both our operated assets and those of our non-operated partners have returned to production. A sharp decline in prices or a pro-longed depressed environment may result in additional future shut ins. In addition, the COVID-19 pandemic

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

We cannot predict the full impact that COVID-19 or the significant disruption and volatility currently being experienced in the oil and natural gas markets will have on our business, cash flows, liquidity, financial condition and results of operations at this time, due to numerous uncertainties. The ultimate impacts will depend on future developments, including, among others, the ultimate geographic spread of the virus, the consequences of governmental and other measures designed to prevent the spread of the virus, the development of effective treatments, the duration of the outbreak, actions taken by members of OPEC and other foreign, oil-exporting countries, governmental authorities, customers, suppliers and other thirds parties, workforce availability, and the timing and extent to which normal economic and operating conditions resume. For additional discussion regarding risks associated with the COVID-19 pandemic, see Item 1A “Risk Factors” in this report.

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

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

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

2020 Operational and Financial Highlights

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

•Continued our efforts to improve our balance sheet by reducing long-term debt by approximately $70 million 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 18.5 days in the first half of 2020, which was a 6% improvement from full year 2019 levels. In the SCOOP, our average spud to rig release time was 37 days, representing a 32% improvement compared to full year 2019 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

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

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2020 Production and Drilling Activity

Production Volumes


	Three months ended June 30,
	2020	% of Total		2019	% of Total		Change	% Change
	($ In thousands)
Natural gas (Mcf/day)
Utica Shale	775,070	83	%	1,014,302	83	%	(239,232)	(24)	%
SCOOP	158,813	17	%	211,898	17	%	(53,085)	(25)	%
Other	53	—	%	205	—	%	(152)	(74)	%
Total	933,936			1,226,405			(292,469)	(24)	%
Oil and condensate (Bbls/day)
Utica Shale	308	7	%	621	9	%	(313)	(50)	%
SCOOP	4,186	91	%	4,899	69	%	(713)	(15)	%
Other	83	2	%	1,614	22	%	(1,531)	(95)	%
Total	4,577			7,134			(2,557)	(36)	%
NGL (Gal/day)
Utica Shale	106,333	23	%	228,871	36	%	(122,538)	(54)	%
SCOOP	353,252	77	%	399,368	64	%	(46,116)	(12)	%
Other	72	—	%	208	—	%	(136)	(65)	%
Total	459,657			628,447			(168,790)	(27)	%
Combined (Mcfe/day)
Utica Shale	792,106	77	%	1,050,724	77	%	(258,618)	(25)	%
SCOOP	234,396	23	%	298,343	22	%	(63,947)	(21)	%
Other	563	—	%	9,922	1	%	(9,359)	(94)	%
Total	1,027,065			1,358,989			(331,924)	(24)	%

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

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

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

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

As of July 31, 2020, we had one operated drilling rig running in the play and expect to continue with this level of activity through the third quarter of 2020.

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

SCOOP. From January 1, 2020 through June 30, 2020, we spud six gross (5.2 net) wells in the SCOOP, of which one was being drilled and five were in various stages of operations at June 30, 2020. In addition. we completed 4 gross (3.8 net) operated wells. We also participated in an additional five gross wells that were drilled by other operators on our SCOOP acreage.

As of July 31, 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.

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

RESULTS OF OPERATIONS

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

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

Natural Gas, Oil and NGL Sales


	Three months ended June 30,
	2020		2019		change
	($ In thousands)
Natural gas	86,797		225,257		(61)	%
Oil and condensate	8,390		36,910		(77)	%
NGL	10,252		25,687		(60)	%
Natural gas, oil and NGL sales	$	105,439	$	287,854	(63)	%

The decrease in natural gas sales without the impact of derivatives was due to a 49% decrease in realized natural gas prices and a 24% decrease in natural gas sales volumes.

The decrease in oil and condensate sales without the impact of derivatives was due to a 65% decrease in realized oil and condensate prices and a 36% decrease in oil and condensate sales volumes.

The decrease in NGL sales without the impact of derivatives was due to a 45% decrease in realized NGL prices and a 27% decrease in NGL sales volumes.

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Natural Gas, Oil and NGL Derivatives


	Three months ended June 30,
	2020		2019
	($ In thousands)
Natural gas derivatives - fair value (losses) gains	$	(48,146)	$	132,760
Natural gas derivatives - settlement gains	83,835		19,715
Total gains on natural gas derivatives	35,689		152,475

Oil and condensate derivatives - fair value (losses) gains	(48,386)		11,501
Oil and condensate derivatives - settlement gains	40,449		370
Total (losses) gains on oil and condensate derivatives	(7,937)		11,871

NGL derivatives - fair value (losses) gains	(997)		3,537
NGL derivatives - settlement gains	216		3,257
Total (losses) gains on NGL derivatives	(781)		6,794

Contingent consideration arrangement - fair value losses	—		—
Total gains on natural gas, oil and NGL derivatives	$	26,971	$	171,140

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

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	Three months ended June 30,
	2020		2019
	($ In thousands)
Natural gas sales
Natural gas production volumes (MMcf)	84,988		111,603

Total natural gas sales	$	86,797	$	225,257

Natural gas sales without the impact of derivatives ($/Mcf)	$	1.02	$	2.02
Impact from settled derivatives ($/Mcf)	$	0.99	$	0.18
Average natural gas sales price, including settled derivatives ($/Mcf)	$	2.01	$	2.20

Oil and condensate sales
Oil and condensate production volumes (MBbls)	417		649

Total oil and condensate sales	$	8,390	$	36,910

Oil and condensate sales without the impact of derivatives ($/Bbl)	$	20.14	$	56.85
Impact from settled derivatives ($/Bbl)	$	97.12	$	0.57
Average oil and condensate sales price, including settled derivatives ($/Bbl)	$	117.26	$	57.42

NGL sales
NGL production volumes (MGal)	41,829		57,189

Total NGL sales	$	10,252	$	25,687

NGL sales without the impact of derivatives ($/Gal)	$	0.25	$	0.45
Impact from settled derivatives ($/Gal)	$	—	$	0.06
Average NGL sales price, including settled derivatives ($/Gal)	$	0.25	$	0.51

Natural gas, oil and condensate and NGL sales
Natural gas equivalents (MMcfe)	93,463		123,668

Total natural gas, oil and condensate and NGL sales	$	105,439	$	287,854

Natural gas, oil and condensate and NGL sales without the impact of derivatives ($/Mcfe)	$	1.13	$	2.33
Impact from settled derivatives ($/Mcfe)	$	1.33	$	0.19
Average natural gas, oil and condensate and NGL sales price, including settled derivatives ($/Mcfe)	$	2.46	$	2.52

Production Costs:
Average lease operating expenses ($/Mcfe)	$	0.17	$	0.18
Average production taxes ($/Mcfe)	$	0.04	$	0.07
Average midstream gathering and processing ($/Mcfe)	$	0.64	$	0.58
Total lease operating expenses, midstream costs and production taxes ($/Mcfe)	$	0.85	$	0.83

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Lease Operating Expenses


	Three months ended June 30,
	2020		2019		change
	($ In thousands, except per unit)
Lease operating expenses
Utica	$	12,996	$	13,646	(5)	%
SCOOP	2,551		4,143		(38)	%
Other⁽¹⁾	139		4,599		(97)	%
Total lease operating expenses	$	15,686	$	22,388	(30)	%

Lease operating expenses per Mcfe
Utica	$	0.18	$	0.14	26	%
SCOOP	0.12		0.15		(22)	%
Other⁽¹⁾	2.72		5.09		(47)	%
Total lease operating expenses per Mcfe	$	0.17	$	0.18	(7)	%

_____________________

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

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

Production Taxes


	Three months ended June 30,
	2020		2019		change
	($ In thousands, except per unit)
Production taxes	$	3,605	$	8,098	(55)	%
Production taxes per Mcfe	$	0.04	$	0.07	(41)	%

The decrease in production taxes was primarily related to a decrease in realized prices and production for the three months ended June 30, 2020 as compared to the three months ended June 30, 2019.

Midstream Gathering and Processing Expenses


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

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

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Depreciation, Depletion and Amortization


	Three months ended June 30,
	2020		2019		change
	($ In thousands, except per unit)
Depreciation, depletion and amortization	$	64,790	$	124,951	(48)	%
Depreciation, depletion and amortization per Mcfe	$	0.69	$	1.01	(32)	%

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

Impairment of Oil and Gas Properties. During the three months ended June 30, 2020, we incurred a $532.9 million oil and natural gas properties impairment charge related primarily to the decline in the twelve month trailing first of month average price for natural gas, oil and NGL, compared to no impairment charge of oil and gas properties during the three months ended June 30, 2019.

Based on prices for the last nine months and the short-term pricing outlook for the third quarter of 2020, we expect to recognize an additional full cost impairment in the third 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 June 30,
	2020		2019		change
	($ In thousands, except per unit)

Loss from equity method investments, net	$	45	$	125,582	(100)	%

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

General and Administrative Expenses


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

General and administrative expenses, net per Mcfe	$	0.11	$	0.09	22	%

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

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

Interest Expense


	Three months ended June 30,
	2020		2019
	($ In thousands, except per unit)
Interest expense on senior notes	28,179		32,281
Interest expense on revolving credit agreement	2,860		3,224
Interest expense on construction loan and other	310		312
Capitalized interest	(523)		(1,005)
Amortization of loan costs	1,540		1,606

Total interest expense	$	32,366	$	36,418

Interest expense per Mcfe	$	0.35	$	0.29

Weighted average debt outstanding under revolving credit facility	$	132,077	$	168,791

The decrease in interest expense for three months ended June 30, 2020 as compared to the three months ended June 30, 2019 was primarily due to repurchases of our senior notes in the second half of 2019 and the first half of 2020.

Income Taxes. We recorded no income tax expense for three months ended June 30, 2020 compared to income tax benefit of $179.3 million for the three months ended June 30, 2019. As of June 30, 2020, we had a federal net operating loss carryforward of approximately $1.5 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 June 30, 2020, a valuation allowance of $879.3 million has been maintained against the full net deferred tax asset. The tax benefit recorded during the three months ended June 30, 2019 was a result of management's determination there was sufficient positive evidence that it was more likely than not that the federal and some state net operating loss carryforwards would be realized.

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

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

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

Natural Gas, Oil and NGL Sales


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

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

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

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

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Natural Gas, Oil and NGL Derivatives


	Six months ended June 30,
	2020		2019
	($ In thousands)
Natural gas derivatives - fair value (losses) gains	$	(63,271)	$	142,098
Natural gas derivatives - settlement gains (losses)	144,813		(6,054)
Total gains on natural gas derivatives	81,542		136,044

Oil and condensate derivatives - fair value (losses) gains	(5,012)		11,027
Oil and condensate derivatives - settlement gains	49,949		390
Total gains on oil and condensate derivatives	44,937		11,417

NGL derivatives - fair value losses	(332)		(536)
NGL derivatives - settlement gains	471		4,170
Total gains on NGL derivatives	139		3,634

Contingent consideration arrangement - fair value losses	(1,381)		—
Total gains on natural gas, oil and NGL derivatives	$	125,237	$	151,095

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

Natural Gas, Oil and NGL Production and Pricing

The following table summarizes our oil and condensate, natural gas and NGL production and related pricing for the six months ended June 30, 2020, as compared to such data for the six months ended June 30, 2019:

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	Six months ended June 30,
	2020		2019
	($ In thousands)
Natural gas sales
Natural gas production volumes (MMcf)	171,047		213,682

Total natural gas sales	$	195,344	$	501,273

Natural gas sales without the impact of derivatives ($/Mcf)	$	1.14	$	2.35
Impact from settled derivatives ($/Mcf)	$	0.85	$	(0.03)
Average natural gas sales price, including settled derivatives ($/Mcf)	$	1.99	$	2.32

Oil and condensate sales
Oil and condensate production volumes (MBbls)	948		1,261

Total oil and condensate sales	$	31,541	$	69,392

Oil and condensate sales without the impact of derivatives ($/Bbl)	$	33.26	$	55.03
Impact from settled derivatives ($/Bbl)	$	52.67	$	0.31
Average oil and condensate sales price, including settled derivatives ($/Bbl)	$	85.93	$	55.34

NGL sales
NGL production volumes (MGal)	88,346		113,019

Total NGL sales	$	27,165	$	57,812

NGL sales without the impact of derivatives ($/Gal)	$	0.31	$	0.51
Impact from settled derivatives ($/Gal)	$	—	$	0.04
Average NGL sales price, including settled derivatives ($/Gal)	$	0.31	$	0.55

Natural gas, oil and condensate and NGL sales
Natural gas equivalents (MMcfe)	189,359		237,394

Total natural gas, oil and condensate and NGL sales	$	254,050	$	628,477

Natural gas, oil and condensate and NGL sales without the impact of derivatives ($/Mcfe)	$	1.34	$	2.65
Impact from settled derivatives ($/Mcfe)	$	1.03	$	(0.01)
Average natural gas, oil and condensate and NGL sales price, including settled derivatives ($/Mcfe)	$	2.37	$	2.64

Production Costs:
Average lease operating expenses ($/Mcfe)	$	0.17	$	0.18
Average production taxes ($/Mcfe)	$	0.04	$	0.07
Average midstream gathering and processing ($/Mcfe)	$	0.62	$	0.60
Total lease operating expenses, midstream costs and production taxes ($/Mcfe)	$	0.83	$	0.85

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Lease Operating Expenses


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

Lease operating expenses per Mcfe
Utica	$	0.17	$	0.14	21	%
SCOOP	0.17		0.15		9	%
Other(1)	1.77		4.96		(64)	%
Total lease operating expenses per Mcfe	$	0.17	$	0.18	(6)	%

_____________________

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

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

Production Taxes


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

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


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

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

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Depreciation, Depletion and Amortization


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

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

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

Equity Investments


	Six months ended June 30,
	2020		2019		change
	($ In thousands, except per unit)

Loss from equity method investments, net	$	10,834	$	121,309	(91)	%

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

General and Administrative Expenses


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

General and administrative expenses, net per Mcfe	$	0.14	$	0.09	53	%

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

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Interest Expense


	Six months ended June 30,
	2020		2019
	($ In thousands, except per unit)
Interest expense on senior notes	57,299		64,562
Interest expense on revolving credit agreement	5,025		5,479
Interest expense on construction loan and other	650		578
Capitalized interest	(710)		(1,771)
Amortization of loan costs	3,092		3,191

Total interest expense	$	65,356	$	72,039

Interest expense per Mcfe	$	0.35	$	0.30

Weighted average debt outstanding under revolving credit facility	$	107,027	$	123,287

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

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

Liquidity and Capital Resources

Overview. Historically, our primary sources of capital funding and liquidity have been our operating cash flow, borrowings under our revolving credit facility 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.

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

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

As of June 30, 2020, we had a cash balance of $2.8 million compared to $6.1 million as of December 31, 2019, and a net working capital deficit of $176.2 million as of June 30, 2020, compared to a net working capital deficit of $145.3 million as of December 31, 2019. As of June 30, 2020, our working capital deficit includes $0.6 million of debt due in the next 12 months. Our total principal debt as of June 30, 2020 was $1.9 billion compared to $2.0 billion as of December 31, 2019. As of June 30, 2020, we had $252.9 million of borrowing capacity available under the revolving credit facility, with outstanding borrowings of $123.0 million and $324.1 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 June 30, 2020, we had the following open natural gas, oil and NGL derivative instruments:

Natural Gas Derivatives

Year

Type of Derivative Instrument

Index

Daily Volume (MMBtu/day)

Weighted
Average Price ($)

2020

Swaps

NYMEX Henry Hub

357,000

2.86

2020

Basis Swaps

Various

70,000

(0.12)

2021

Costless Collars

NYMEX Henry Hub

250,000

2.46/2.81

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

3,000

35.49

NGL Derivatives

Year

Type of Derivative Instrument

Index

Daily Volume (Bbls/day)

Weighted
Average Price ($)

2020

Swaps

Mont Belvieu C3

1,500

20.27

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 June 30, 2020, we had a borrowing base and elected commitment of $700.0 million and $123.0 million in borrowings outstanding. Total funds available for borrowing under our revolving credit facility, after giving effect to an aggregate of $324.1 million of outstanding letters of credit, were $252.9 million as of June 30, 2020. This facility is secured by substantially all of our assets. Our wholly owned subsidiaries, excluding Grizzly Holdings Inc. ("Grizzly Holdings") and Mule Sky LLC ("Mule Sky"), guarantee our obligations under our revolving credit facility.

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

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

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

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

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

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

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

Capital Expenditures. Our capital commitments 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 more than 50% lower than the $602.5 million spent in 2019, primarily due to our decision to reduce capital activity in response to lower commodity prices, specifically natural gas prices, and our desire to fund our capital development program primarily with cash flow from operations. As a result of our decreased capital spending program for 2020 and the impact of our 2019 property divestitures, we expect our production volumes in 2020 to be approximately 22% to 27% lower than 2019. Coupled with forecasted lower commodity prices, we expect 2020 revenues, operating cash flows and EBITDA to be significantly lower in 2020 as compared to 2019.

We continually monitor market conditions and are prepared to adjust our drilling program if commodity prices dictate. Currently, we believe that our cash flow from operations, cash on hand and borrowing base availability under our revolving credit agreement 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 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 $247.2 million for the six months ended June 30, 2020 as compared to $399.8 million for the same period in 2019. This decrease was primarily the result of a significant decrease in our realized gas prices as well as decreases in our production volumes.

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

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


	Six months ended June 30,
	2020		2019
	(In thousands)
Oil and Natural Gas Property Cash Expenditures:
Drilling and completion costs	255,904		435,583
Leasehold acquisitions	10,098		25,778
Other	8,849		46,954
Total oil and natural gas property expenditures	$	274,851	$	508,315
Other Uses of Cash and Cash Equivalents
Cash paid to repurchase senior notes	22,827		—
Cash paid to repurchase common stock under approved stock repurchase program	—		30,000
Other	801		5,444
Total other uses of cash and cash equivalents	$	23,628	$	35,444
Total uses of cash and cash equivalents	$	298,479	$	543,759

Drilling and Completion Costs. During six months ended June 30, 2020, we spud 12 gross (11.1 net) and commenced sales from 13 gross and net operated wells in the Utica Shale for a total cost of approximately $141.5 million. During the six months ended June 30, 2020, we spud six gross (5.2 net) and commenced sales from four gross (3.8 net) operated wells in the SCOOP for a total cost of approximately $42.2 million.

During the six months ended June 30, 2020, we did not participate in any wells that were spud or turned to sales by other operators on our Utica Shale acreage. In addition, 5.00 gross (0.03 net) wells were spud and 5.00 gross (3.5 net) wells were turned to sales by other operators on our SCOOP acreage during the six months ended June 30, 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 June 30, 2020, our material off-balance sheet arrangements and transactions include $324.1 million in letters of credit outstanding against our revolving credit facility and $119.5 million in surety bonds issued. Both the letters of credit and surety bonds are being used as financial assurance, primarily on certain firm transportation agreements. Management believes these items will expire without being funded. There are no other transactions, arrangements or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect our liquidity or availability of our capital

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resources. See Note 9 to our consolidated financial statements for further discussion of the various financial guarantees we have issued.

Critical Accounting Policies and Estimates

As of June 30, 2020, 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, options and costless collars. All of these are described in more detail below. We typically use swaps for a large portion of the oil and natural gas price risk we hedge. We have also sold calls, taking advantage of premiums associated with market price volatility.

We determine the notional volume potentially subject to derivative contracts by reviewing our overall estimated future production levels, which are derived from extensive examination of existing producing reserve estimates and estimates of likely 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 June 30, 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.

•Costless Collars: These instruments have a set floor and ceiling price for the hedged production. If the applicable monthly price indices are outside of the ranges set by the floor and ceiling prices in the various collars, we will cash-settle the difference with the counterparty.

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

Location

Daily Volume (MMBtu/day)

Weighted
Average Price

Remaining 2020

NYMEX Henry Hub

357,000

2.86

Location

Daily Volume
(Bbls/day)

Weighted
Average Price

Remaining 2020

NYMEX WTI

3,000

35.49

Location

Daily Volume
(Bbls/day)

Weighted
Average Price

Remaining 2020

Mont Belvieu C3

1,500

20.27

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. We had the following open sold call option positions at June 30, 2020:


	Location	Daily Volume (MMBtu/day)	Weighted Average Price

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

We had the following open costless collar positions at June 30, 2020:


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

As of June 30, 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 August 2020, we entered into natural gas fixed price swap contracts for the fourth quarter of 2020 covering approximately 100,000 MMBtu of natural gas per day at an average swap price of $2.38 per MMBtu.

Our fixed price swap contracts are tied to the commodity prices on NYMEX Henry Hub for natural gas 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.

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Under our 2020 contracts, we have hedged approximately 59% to 63% of our estimated 2020 production. Such arrangements may expose us to risk of financial loss in certain circumstances, including instances where production is less than expected or commodity prices increase. At June 30, 2020, we had a net asset derivative position of $3.3 million as compared to a net asset derivative position of $139.5 million as of June 30, 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 $48.8 million, while a 10% decrease in underlying commodity prices would have increased the fair value of these instruments by approximately $43.1 million. However, any realized derivative gain or loss would be substantially offset by a decrease or increase, respectively, in the actual sales value of production covered by the derivative instrument.

Interest Rate Risk. Our revolving amended and restated credit agreement is structured under floating rate terms, as advances under this facility may be in the form of either base rate loans or eurodollar loans. As such, our interest expense is sensitive to fluctuations in the prime rates in the United States, or, if the eurodollar rates are elected, the eurodollar rates. At June 30, 2020, we had $123.0 million in borrowings outstanding under our revolving credit facility which bore interest at a weighted average rate of 2.44%. As of June 30, 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 June 30, 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 June 30, 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.

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

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PART II


ITEM 1.			LEGAL PROCEEDINGS

Litigation and Regulatory Proceedings

We are involved in a number of litigation and regulatory proceedings including those described below. Many of these proceedings are in early stages, and many of them seek or may seek damages and penalties, the amount of which is indeterminate. Our total accrued liabilities in respect of litigation and regulatory proceedings is determined on a case-by-case basis and represents an estimate of probable losses after considering, among other factors, the progress of each case or proceeding, its experience and the experience of others in similar cases or proceedings, and the opinions and views of legal counsel. Significant judgment is required in making these estimates and their final liabilities may ultimately be materially different.

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

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

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

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

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

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

In December 2019, we filed a lawsuit against Stingray Pressure Pumping LLC, a subsidiary of Mammoth Energy (“Stingray”), for breach of contract and to terminate the Master Services Agreement for pressure pumping services, effective as of October 1, 2014, as amended (the “Master Services Agreement”), between Stingray and us. In March 2020, Stingray filed a counterclaim against us in the Superior Court of the State of Delaware. The counterclaim alleges that we have breached the Master Services Agreement. The counterclaim seeks actual damages, which the complaint calculates to be approximately 28 million as of June 2020 (such amount to increase each month), the payment of reasonable attorney fees and legal expenses and pre- and post-judgment interest as allowed, and such other and further relief which it may be justly entitled.

In April 2020, Bryon Lefort, individually and on behalf of similarly situated individuals, filed an action against us in the United States District Court for the Southern District of Ohio Eastern Division. The complaint alleges that we violated the Fair Labor Standards Act (“FLSA”), the Ohio Wage Act and the Ohio Prompt Pay Act by classifying the plaintiffs as independent contractors and paying them a daily rate with no overtime compensation for hours worked in excess of 40 hours per week. The complaint seeks to recover unpaid regular and overtime wages, liquidated damages in an amount equal to six percent of all unpaid overtime compensation, the payment of reasonable attorney fees and legal expenses and pre-judgment and post-judgment interest, and such other damages that may be owed to the workers.

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

SEC Investigation

The SEC has commenced an investigation with respect to certain actions by our former management, including alleged improper personal use of company assets, and potential violations by our former management and the company of the Sarbanes-Oxley Act of 2002 in connection with such actions. We have fully cooperated and intend to continue to cooperate fully with the SEC’s investigation. Although it is not possible to predict the ultimate resolution or financial 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.

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

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

Other Matters


ITEM 1A.			RISK FACTORS

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

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

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

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

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

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

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

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

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

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

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

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

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


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

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Unregistered Sales of Equity Securities

None.

Issuer Repurchases of Equity Securities

Our common stock repurchase activity for the three months ended June 30, 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)
April 2020	18,338	$	0.72	—	$	370,000,000
May 2020	—	$	—	—	$	370,000,000
June 2020	8,956	$	1.69	—	$	370,000,000
Total	27,294	$	1.04	—


(1)			During the three months ended June 30, 2020, we repurchased and canceled 27,294 shares of our common stock at a weighted average price of $1.04 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.

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ITEM 5.			OTHER INFORMATION

Incentive compensation program

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

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

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

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


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

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


Named Executive Officer			Restricted Stock Units
Donnie Moore			19,498

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ITEM 6.			EXHIBITS


INDEX OF EXHIBITS
		Incorporated by Reference
Exhibit Number	Description	Form	SEC File Number	Exhibit	Filing Date	Filed or Furnished Herewith
3.1	Restated Certificate of Incorporation.	8-K	000-19514	3.1	4/26/2006

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

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

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

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

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

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

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

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

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

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

4.6	Tax Benefits Preservation Plan, dated as of April 30, 2020, between Gulfport Energy Corporation and Computershare Trust Company, N.A., as rights agent (which includes the Form of Rights Certificate as Exhibit B thereto)	8-A	001-19514	4.1	4/30/2020

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

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10.2+

Form of 2020 Cash Award under Gulfport Energy Corporation 2020 Incentive Plan.

8-K

000-19514

10.2

3/17/2020

10.3

Fifteenth Amendment to the Amended and Restated Credit Agreement, dated as of May 1, 2020, between Gulfport Energy Corporation, as Borrower, the Bank of Nova Scotia, as Administrative Agent and the lenders party thereto

10.4

Sixteenth Amendment to the Amended and Restated Credit Agreement, dated as of July 27, 2020, between Gulfport Energy Corporation, as Borrower, the Bank of Nova Scotia, as Administrative Agent and the lenders party thereto

8-K

001-19514

10.1

7/30/2020

31.1

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

31.2

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

32.1

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

32.2

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

101.INS

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

101.SCH

XBRL Taxonomy Extension Schema Document.

101.CAL

XBRL Taxonomy Extension Calculation Linkbase Document.

101.DEF

XBRL Taxonomy Extension Definition Linkbase Document.

101.LAB

XBRL Taxonomy Extension Labels Linkbase Document.

101.PRE

XBRL Taxonomy Extension Presentation Linkbase Document.

104

Cover Page Interactive Data File - the cover page interactive data file does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.


+			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: August 6, 2020

GULFPORT ENERGY CORPORATION

By:

/s/ Quentin Hicks

Quentin Hicks
Executive Vice President & Chief Financial Officer