Document

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)



ý	QUARTERLY REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the quarterly period ended March 31, 2018 OR



¨	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)

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 and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted 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 and post such files). Yes ý No ¨

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

Large Accelerated filer ý Accelerated filer ¨ Non-accelerated filer ¨ Smaller reporting company ¨

Emerging growth company ¨

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

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

As of May 1, 2018, 173,657,895 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):	2

	Consolidated Balance Sheets at March 31, 2018 and December 31, 2017	2

	Consolidated Statements of Operations for the Three Months Ended March 31, 2018 and 2017	3

	Consolidated Statements of Comprehensive Income for the Three Months Ended March 31, 2018 and 2017	4

	Consolidated Statements of Stockholders’ Equity for the Three Months Ended March 31, 2018 and 2017	5

	Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2018 and 2017	6

	Notes to Consolidated Financial Statements	7

Item 2.	Management’s Discussion and Analysis of Financial Conditions and Results of Operations	35

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	48

Item 4.	Controls and Procedures	50

PART II OTHER INFORMATION

Item 1.	Legal Proceedings	51

Item 1A.	Risk Factors	51

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	51

Item 3.	Defaults Upon Senior Securities	52

Item 4.	Mine Safety Disclosures	52

Item 5.	Other Information	52

Item 6.	Exhibits	52

Signatures		54

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GULFPORT ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS

(Unaudited)



	March 31, 2018			December 31, 2017
	(In thousands, except share data)
Assets
Current assets:
Cash and cash equivalents	$	118,613		$	99,557
Accounts receivable—oil and natural gas	199,457			182,213
Prepaid expenses and other current assets	7,564			4,912
Short-term derivative instruments	50,906			78,847
Total current assets	376,540			365,529
Property and equipment:
Oil and natural gas properties, full-cost accounting, $2,971,119 and $2,912,974 excluded from amortization in 2018 and 2017, respectively	9,470,697			9,169,156
Other property and equipment	89,648			86,754
Accumulated depletion, depreciation, amortization and impairment	(4,264,647		)	(4,153,733		)
Property and equipment, net	5,295,698			5,102,177
Other assets:
Equity investments	311,694			302,112
Long-term derivative instruments	15,769			8,685
Deferred tax asset	—			1,208
Inventories	8,505			8,227
Other assets	20,186			19,814
Total other assets	356,154			340,046
Total assets	$	6,028,392		$	5,807,752
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable and accrued liabilities	$	577,548		$	553,609
Asset retirement obligation—current	120			120
Short-term derivative instruments	37,570			32,534
Current maturities of long-term debt	629			622
Total current liabilities	615,867			586,885
Long-term derivative instruments	2,499			2,989
Asset retirement obligation—long-term	76,267			74,980
Deferred tax liability	2,884			—
Other non-current liabilities	2,963			2,963
Long-term debt, net of current maturities	2,239,023			2,038,321
Total liabilities	2,939,503			2,706,138
Commitments and contingencies (Note 9)
Preferred stock, $.01 par value; 5,000,000 authorized, 30,000 authorized as redeemable 12% cumulative preferred stock, Series A; 0 issued and outstanding	—			—
Stockholders’ equity:
Common stock - $.01 par value, 200,000,000 authorized, 173,523,487 issued and outstanding at March 31, 2018 and 183,105,910 at December 31, 2017	1,735			1,831
Paid-in capital	4,319,034			4,416,250
Accumulated other comprehensive loss	(46,042		)	(40,539		)
Retained deficit	(1,185,838		)	(1,275,928		)
Total stockholders’ equity	3,088,889			3,101,614
Total liabilities and stockholders’ equity	$	6,028,392		$	5,807,752

See accompanying notes to consolidated financial statements.

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GULFPORT ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)



	Three months ended March 31,
	2018			2017
	(In thousands, except share data)
Revenues:
Natural gas sales	$	249,399		$	177,837
Oil and condensate sales	45,686			24,411
Natural gas liquid sales	46,836			31,179
Net (loss) gain on natural gas, oil, and NGL derivatives	(16,529		)	99,577
	325,392			333,004
Costs and expenses:
Lease operating expenses	18,906			19,303
Production taxes	6,854			3,906
Midstream gathering and processing	64,193			47,941
Depreciation, depletion and amortization	111,018			65,991
General and administrative	13,099			12,600
Accretion expense	1,004			282
Acquisition expense	—			1,298
	215,074			151,321
INCOME FROM OPERATIONS	110,318			181,683
OTHER (INCOME) EXPENSE:
Interest expense	33,965			23,479
Interest income	(37		)	(842		)
(Income) loss from equity method investments, net	(13,536		)	4,907
Other income	(95		)	(316		)
	20,297			27,228
INCOME BEFORE INCOME TAXES	90,021			154,455
INCOME TAX BENEFIT	(69		)	—
NET INCOME	$	90,090		$	154,455
NET INCOME PER COMMON SHARE:
Basic	$	0.50		$	0.91
Diluted	$	0.50		$	0.91
Weighted average common shares outstanding—Basic	180,714,881			170,272,685
Weighted average common shares outstanding—Diluted	180,802,301			170,488,519

See accompanying notes to consolidated financial statements.

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GULFPORT ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)



	Three months ended March 31,
	2018			2017
	(In thousands)
Net income	$	90,090		$	154,455
Foreign currency translation adjustment	(5,503		)	1,373
Other comprehensive (loss) income	(5,503		)	1,373
Comprehensive income	$	84,587		$	155,828

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 Income (loss)			Retained Deficit			Total Stockholders’ Equity
	Common Stock
	Shares		Amount
	(In thousands, except share data)
Balance at January 1, 2018	183,105,910		$	1,831		$	4,416,250		$	(40,539	)	$	(1,275,928	)	$	3,101,614
Net income	—		—			—			—			90,090			90,090
Other Comprehensive Income	—		—			—			(5,503		)	—			(5,503		)
Stock-based Compensation	—		—			2,685			—			—			2,685
Shares Repurchased	(9,692,356	)	(97		)	(99,900		)	—			—			(99,997		)
Issuance of Restricted Stock	109,933		1			(1		)	—			—			—
Balance at March 31, 2018	173,523,487		$	1,735		$	4,319,034		$	(46,042	)	$	(1,185,838	)	$	3,088,889

Balance at January 1, 2017	158,829,816		$	1,588		$	3,946,442		$	(53,058	)	$	(1,711,080	)	$	2,183,892
Net income	—		—			—			—			154,455			154,455
Other Comprehensive Income	—		—			—			1,373			—			1,373
Stock-based Compensation	—		—			2,553			—			—			2,553
Issuance of Common Stock for the Vitruvian Acquisition, net of related expenses	23,852,117		239			459,242			—			—			459,481
Issuance of Restricted Stock	153,868		1			(1		)	—			—			—
Balance at March 31, 2017	182,835,801		$	1,828		$	4,408,236		$	(51,685	)	$	(1,556,625	)	$	2,801,754

See accompanying notes to consolidated financial statements.

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GULFPORT ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)



	Three months ended March 31,
	2018			2017
	(In thousands)
Cash flows from operating activities:
Net income	$	90,090		$	154,455
Adjustments to reconcile net income to net cash provided by operating activities:
Accretion	1,004			282
Depletion, depreciation and amortization	111,018			65,991
Stock-based compensation expense	1,611			1,532
(Gain) loss from equity investments	(13,495		)	5,150
Change in fair value of derivative instruments	25,403			(106,796		)
Deferred income tax benefit	(69		)	—
Amortization of loan commitment fees	1,488			1,088
Changes in operating assets and liabilities:
Increase in accounts receivable	(15,450		)	(21,393		)
Increase in accounts receivable—related party	—			(23		)
Increase in prepaid expenses and other current assets	(2,652		)	(8,366		)
Decrease (increase) in other assets	14			(4,013		)
Increase in accounts payable, accrued liabilities and other	27,486			54,738
Settlement of asset retirement obligation	(99		)	—
Net cash provided by operating activities	226,349			142,645
Cash flows from investing activities:
Additions to other property and equipment	(3,329		)	(5,444		)
Acquisition of oil and natural gas properties	—			(1,338,964		)
Additions to oil and natural gas properties	(302,799		)	(181,834		)
Proceeds from sale of oil and natural gas properties	—			3,605
Proceeds from sale of other property and equipment	76			—
Contributions to equity method investments	(1,569		)	(10,673		)
Distributions from equity method investments	750			631
Net cash used in investing activities	(306,871		)	(1,532,679		)
Cash flows from financing activities:
Principal payments on borrowings	(145		)	—
Borrowings on line of credit	200,000			40,000
Borrowings on term loan	—			2,698
Debt issuance costs and loan commitment fees	(280		)	(5,733		)
Payments on repurchase of stock	(99,997		)	—
Proceeds from issuance of common stock, net of offering costs	—			(5,321		)
Net cash provided by financing activities	99,578			31,644
Net increase (decrease) in cash, cash equivalents and restricted cash	19,056			(1,358,390		)
Cash, cash equivalents and restricted cash at beginning of period	99,557			1,460,875
Cash, cash equivalents and restricted cash at end of period	$	118,613		$	102,485
Supplemental disclosure of cash flow information:
Interest payments	$	7,944		$	347
Income tax payments	$	—		$	—
Supplemental disclosure of non-cash transactions:
Capitalized stock-based compensation	$	1,074		$	1,021
Asset retirement obligation capitalized	$	382		$	6,779
Interest capitalized	$	843		$	3,122
Foreign currency translation (loss) gain on equity method investments	$	(5,503	)	$	1,373

See accompanying notes to consolidated financial statements.

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GULFPORT ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

These consolidated financial statements have been prepared by Gulfport Energy Corporation (the “Company” or “Gulfport”) without audit, pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”), and reflect all adjustments which, in the opinion of management, are necessary for a fair presentation of the results for the interim periods, 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 have been omitted pursuant to such rules and regulations, although the Company believes that the disclosures are adequate to make the information presented not misleading. These consolidated financial statements should be read in conjunction with the consolidated financial statements and the summary of significant accounting policies and notes thereto included in the Company’s most recent annual report on Form 10-K. Results for the three month period ended March 31, 2018 are not necessarily indicative of the results expected for the full year.


1.	ACQUISITIONS

Vitruvian Acquisition

In December 2016, the Company, through its wholly-owned subsidiary Gulfport MidCon LLC (“Gulfport MidCon”) (formerly known as SCOOP Acquisition Company, LLC), entered into an agreement to acquire certain assets of Vitruvian II Woodford, LLC (“Vitruvian”), an unrelated third-party seller (the “Vitruvian Acquisition”). The assets included in the Vitruvian Acquisition include 46,400 net surface acres located in Grady, Stephens and Garvin Counties, Oklahoma. On February 17, 2017, the Company completed the Vitruvian Acquisition for a total initial purchase price of approximately $1.85 billion, consisting of $1.35 billion in cash, subject to certain adjustments, and approximately 23.9 million shares of the Company’s common stock (of which approximately 5.2 million shares were placed in an indemnity escrow). The cash portion of the purchase price was funded with the net proceeds from the December 2016 common stock and senior note offerings and cash on hand. Acquisition costs of $1.3 million were incurred during the three months ended March 31, 2017 related to the Vitruvian Acquisition. No acquisition costs were incurred during the three months ended March 31, 2018.

Allocation of Purchase Price

The Vitruvian Acquisition qualified as a business combination for accounting purposes and, as such, the Company estimated the fair value of the acquired properties as of the February 17, 2017 acquisition date. The fair value of the assets acquired and liabilities assumed was estimated using assumptions that represent Level 3 inputs. See Note 11 for additional discussion of the measurement inputs.

The Company estimated that the consideration paid in the Vitruvian Acquisition for these properties approximated the fair value that would be paid by a typical market participant. As a result, no goodwill or bargain purchase gain was recognized in conjunction with the purchase.

The following table summarizes the consideration paid by the Company in the Vitruvian Acquisition to acquire the properties and the fair value amount of the assets acquired as of February 17, 2017.

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	(In thousands)
Consideration:
Cash, net of purchase price adjustments	$	1,354,093
Fair value of Gulfport’s common stock issued	464,639
Total consideration	$	1,818,732

Estimated fair value of identifiable assets acquired and liabilities assumed:
Oil and natural gas properties
Proved properties	$	362,264
Unproved properties	1,462,957
Asset retirement obligations	(6,489		)
Total fair value of net identifiable assets acquired	$	1,818,732

The equity consideration included in the initial purchase price was based on an equity offering price of $20.96 on December 15, 2016. The decrease in the price of Gulfport’s common stock from $20.96 on December 15, 2016 to $19.48 on February 17, 2017 resulted in a decrease to the fair value of the total consideration paid as compared to the initial purchase price of approximately $35.3 million, which resulted in a closing date fair value lower than the initial purchase price.

Post-Acquisition Operating Results

For the period from the acquisition date of February 17, 2017 to March 31, 2017, the assets acquired in the Vitruvian Acquisition contributed $26.2 million of revenue to the Company’s consolidated statements of operations. The amount of net income contributed by the assets is impracticable to calculate due to the Company integrating the acquired assets into its overall operations using the full cost method of accounting.

Pro Forma Information (Unaudited)

The following unaudited pro forma combined financial information presents the Company’s results as though the Vitruvian Acquisition had been completed at January 1, 2017. The pro forma combined financial information has been included for comparative purposes and is not necessarily indicative of the results that might have actually occurred had the Vitruvian Acquisition taken place on January 1, 2017; furthermore, the financial information is not intended to be a projection of future results.



	Three months ended
	March 31, 2017
	(In thousands, except share data)
Pro forma revenue	$	368,903
Pro forma net income	$	175,881
Pro forma earnings per share (basic)	$	1.03
Pro forma earnings per share (diluted)	$	1.03

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2.	PROPERTY AND EQUIPMENT

The major categories of property and equipment and related accumulated depletion, depreciation, amortization and impairment as of March 31, 2018 and December 31, 2017 are as follows:



	March 31, 2018			December 31, 2017
	(In thousands)
Oil and natural gas properties	$	9,470,697		$	9,169,156
Office furniture and fixtures	40,236			37,369
Building	44,592			44,565
Land	4,820			4,820
Total property and equipment	9,560,345			9,255,910
Accumulated depletion, depreciation, amortization and impairment	(4,264,647		)	(4,153,733		)
Property and equipment, net	$	5,295,698		$	5,102,177

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 oil and natural gas properties. At March 31, 2018, the calculated ceiling was greater than the net book value of the Company’s oil and natural gas properties, thus no ceiling test impairment was required for the three months ended March 31, 2018. No impairment was required for oil and natural gas properties for the three months ended March 31, 2017.

Included in oil and natural gas properties at March 31, 2018 is the cumulative capitalization of $174.4 million in general and administrative costs incurred and capitalized to the full cost pool. General and administrative costs capitalized to the full cost pool represent management’s estimate of costs incurred directly related to exploration and development activities such as geological and other administrative costs associated with overseeing the exploration and development activities. All general and administrative costs not directly associated with exploration and development activities were charged to expense as they were incurred. Capitalized general and administrative costs were approximately $8.8 million and $8.4 million for the three months ended March 31, 2018 and 2017, 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 $0.93 and $0.84 per Mcfe for the three months ended March 31, 2018 and 2017, respectively.

The following table summarizes the Company’s non-producing properties excluded from amortization by area at March 31, 2018:



	March 31, 2018
	(In thousands)
Utica	$	1,548,121
MidContinent	1,421,853
Niobrara	449
Southern Louisiana	552
Bakken	99
Other	45
	$	2,971,119

At December 31, 2017, approximately $2.9 billion of non-producing leasehold costs was not subject to amortization.

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

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A reconciliation of the Company’s asset retirement obligation for the three months ended March 31, 2018 and 2017 is as follows:



	March 31, 2018			March 31, 2017
	(In thousands)
Asset retirement obligation, beginning of period	$	75,100		$	34,276
Liabilities incurred	329			6,779
Liabilities settled	(99		)	—
Accretion expense	1,004			282
Revisions in estimated cash flows	53			—
Asset retirement obligation as of end of period	76,387			41,337
Less current portion	120			195
Asset retirement obligation, long-term	$	76,267		$	41,142


3.	EQUITY INVESTMENTS

Investments accounted for by the equity method consist of the following as of March 31, 2018 and December 31, 2017:



			Carrying value				(Income) loss from equity method investments
	Approximate ownership %		March 31, 2018		December 31, 2017		Three months ended March 31,
	Approximate ownership %		March 31, 2018		December 31, 2017		2018			2017
			(In thousands)
Investment in Tatex Thailand II, LLC	23.5	%	$	—	$	—	$	(41	)	$	(243	)
Investment in Grizzly Oil Sands ULC	24.9999	%	53,564		57,641		330			365
Investment in Timber Wolf Terminals LLC	50.0	%	980		983		2			4
Investment in Windsor Midstream LLC	22.5	%	30		30		—			(311		)
Investment in Stingray Cementing LLC⁽¹⁾	—	%	—		—		—			128
Investment in Blackhawk Midstream LLC	48.5	%	—		—		—			—
Investment in Stingray Energy Services LLC⁽¹⁾	—	%	—		—		—			197
Investment in Sturgeon Acquisitions LLC⁽¹⁾	—	%	—		—		—			68
Investment in Mammoth Energy Services, Inc.⁽¹⁾	25.1	%	179,770		165,715		(13,470		)	2,158
Investment in Strike Force Midstream LLC	25.0	%	77,350		77,743		(357		)	2,541
			$	311,694	$	302,112	$	(13,536	)	$	4,907




(1)	On June 5, 2017, Mammoth Energy Services, Inc. ("Mammoth Energy") acquired Stingray Cementing LLC, Stingray Energy Services LLC and Sturgeon Acquisitions LLC. See below under Mammoth Energy Partners LP/Mammoth Energy Services, Inc. for information regarding these transactions.

The tables below summarize financial information for the Company’s equity investments as of March 31, 2018 and December 31, 2017.

Summarized balance sheet information:



	March 31, 2018		December 31, 2017
	March 31, 2018		December 31, 2017
	(In thousands)
Current assets	$	395,679	$	415,032
Noncurrent assets	$	2,109,829	$	1,542,090
Current liabilities	$	285,521	$	261,086
Noncurrent liabilities	$	87,259	$	148,839

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Summarized results of operations:



	Three months ended March 31,
	2018		2017
	(In thousands)
Gross revenue	$	511,133	$	94,478
Net income (loss)	$	64,452	$	(25,339	)

Tatex Thailand II, LLC

The Company has an indirect ownership interest in Tatex Thailand II, LLC (“Tatex II”). Tatex II holds an 8.5% interest in APICO, LLC (“APICO”), an international oil and gas exploration company. APICO has a reserve base located in Southeast Asia through its ownership of concessions covering approximately 180,000 acres which includes the Phu Horm Field. The Company received an immaterial amount and $0.2 million in distributions from Tatex II during the three months ended March 31, 2018 and 2017, respectively.

Tatex Thailand III, LLC

The Company has an ownership interest in Tatex Thailand III, LLC (“Tatex III”). Tatex III previously owned a concession covering approximately 245,000 acres in Southeast Asia. As of December 31, 2014, the Company reviewed its investment in Tatex III and, together with Tatex III, made the decision to allow the concession to expire in January 2015. As such, the Company fully impaired the asset as of December 31, 2014. In December 2017, Tatex III was dissolved and the Company received a final distribution of $0.2 million.

Grizzly Oil Sands ULC

The Company, through its wholly owned subsidiary Grizzly Holdings Inc. (“Grizzly Holdings”), owns an interest in Grizzly Oil Sands ULC (“Grizzly”), a Canadian unlimited liability company. The remaining interest in Grizzly is owned by Grizzly Oil Sands Inc. (“Oil Sands”). As of March 31, 2018, Grizzly had approximately 830,000 acres under lease in the Athabasca, Peace River and Cold Lake oil sands regions of Alberta, Canada. Grizzly has high-graded three oil sands projects to various stages of development. Grizzly commenced commercial production from its Algar Lake Phase I steam-assisted gravity drainage ("SAGD") oil sand project during the second quarter of 2014 and has regulatory approval for up to 11,300 barrels per day of bitumen production. Algar Lake production peaked at 2,200 barrels per day during the ramp-up phase of the SAGD facility, however, in April 2015, Grizzly made the decision to suspend operations at its Algar Lake facility due to the commodity price drop and its effect on project economics. Grizzly continues to monitor market conditions as it assesses start up plans for the facility. The Company reviewed its investment in Grizzly for impairment based on FASB ASC 323 at March 31, 2018 and 2017 and determined no impairment was required. If commodity prices decline in the future however, impairment of the investment in Grizzly may be necessary. During the three months ended March 31, 2018, Gulfport paid $1.6 million in cash calls. Grizzly’s functional currency is the Canadian dollar. The Company’s investment in Grizzly was decreased by $5.3 million as a result of a foreign currency translation loss and increased by $1.3 million as a result of a foreign currency translation gain for the three months ended March 31, 2018 and 2017, respectively.

Timber Wolf Terminals LLC

During 2012, the Company invested in Timber Wolf Terminals LLC (“Timber Wolf”). Timber Wolf was formed to operate a crude/condensate terminal and a sand transloading facility in Ohio. During the three months ended March 31, 2018 and 2017, the Company paid no cash calls to Timber Wolf.

Windsor Midstream LLC

At March 31, 2018, the Company held a 22.5% interest in Windsor Midstream LLC (“Midstream”), an entity controlled and managed by an unrelated third party. Midstream previously owned a 28.4% interest in Coronado Midstream LLC (“Coronado”), a gas processing plant in West Texas. In March 2015, Coronado was sold to EnLink Midstream Partners, LP (“EnLink”). As a result of the sale of Coronado to EnLink, Midstream received common units of EnLink, which were subsequently sold by Midstream. The Company received $0.2 million in distributions from Midstream during the three months ended March 31, 2017 and no distributions during the same period in 2018.

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Stingray Cementing LLC

During 2012, the Company invested in Stingray Cementing LLC (“Stingray Cementing”). Stingray Cementing provides well cementing services. The (income) loss from equity method investments presented in the table above reflects any intercompany profit eliminations. On June 5, 2017, the Company contributed all of its membership interests in Stingray Cementing to Mammoth Energy. See below under Mammoth Energy Partners LP/Mammoth Energy Services, Inc. for information regarding this transaction.

Blackhawk Midstream LLC

During 2012, the Company invested in Blackhawk Midstream LLC (“Blackhawk”). Blackhawk coordinated gathering, compression, processing and marketing activities for the Company in connection with the development of its Utica Shale acreage. Blackhawk does not have any current activities.

Stingray Energy Services LLC

During 2013, the Company invested in Stingray Energy Services LLC (“Stingray Energy”). Stingray Energy provides rental tools for land-based oil and natural gas drilling, completion and workover activities as well as the transfer of fresh water to wellsites. The (income) loss from equity method investments presented in the table above reflects any intercompany profit eliminations. On June 5, 2017, the Company contributed all of its membership interests in Stingray Energy to Mammoth Energy. See below under Mammoth Energy Partners LP/Mammoth Energy Services, Inc. for information regarding this transaction.

Sturgeon Acquisitions LLC

During 2014, the Company invested $20.7 million and received an ownership interest of 25% in Sturgeon Acquisitions LLC (“Sturgeon”). Sturgeon owns and operates sand mines that produce hydraulic fracturing grade sand. On June 5, 2017, the Company contributed all of its membership interests in Sturgeon to Mammoth Energy. See below under Mammoth Energy Partners LP/Mammoth Energy Services, Inc. for information regarding this transaction.

Mammoth Energy Partners LP/Mammoth Energy Services, Inc.

In the fourth quarter of 2014, the Company contributed its investments in four entities to Mammoth Energy Partners LP (“Mammoth”) for a 30.5% interest in this entity. In October 2016, Mammoth converted from a limited partnership into a limited liability company named Mammoth Energy Partners LLC (“Mammoth LLC”) and the Company and the other members of Mammoth LLC contributed their interests in Mammoth LLC to Mammoth Energy. Following the contribution, Mammoth Energy completed its initial public offering of shares of its common stock.

On June 5, 2017, the Company contributed all of its membership interests in Sturgeon (which owns Taylor Frac, LLC, Taylor Real Estate Investments, LLC and South River Road, LLC), Stingray Energy and Stingray Cementing to Mammoth Energy in exchange for approximately 2.0 million shares of Mammoth Energy common stock (the "June 2017 Transactions"). As of March 31, 2018, the Company held approximately 25.1% of Mammoth Energy’s outstanding common stock. The Company accounted for the transactions as a sale of financial assets under FASB ASC 860. The Company valued the shares of Mammoth Energy common stock it received in the June 2017 Transactions at $18.50 per share, which was the closing price of Mammoth Energy common stock on June 5, 2017. During the second quarter of 2017, the Company recognized a gain of $12.5 million from the June 2017 Transactions.

The Company’s investment in Mammoth Energy was decreased by a $0.2 million foreign currency loss and increased by a $0.1 million foreign currency gain resulting from Mammoth Energy’s foreign subsidiary for the three months ended March 31, 2018 and 2017, respectively. The (income) loss from equity method investments presented in the table above reflects any intercompany profit eliminations.

Strike Force Midstream LLC

In February 2016, the Company, through its wholly owned subsidiary Gulfport Midstream Holdings, LLC (“Midstream Holdings”), entered into an agreement with Rice Midstream Holdings LLC (“Rice”), a subsidiary of Rice Energy Inc., to develop natural gas gathering assets in eastern Belmont County and Monroe County, Ohio through Strike Force Midstream LLC ("Strike Force"). In 2017, Rice was acquired by EQT Corporation ("EQT"). The Company owns a 25% interest in Strike

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Force, and EQT acts as operator and owns the remaining 75% interest in Strike Force. Construction of the gathering assets, which is ongoing, provides gathering services for wells operated by Gulfport and other operators and connectivity of existing dry gas gathering systems. During the three months ended March 31, 2018, Gulfport received distributions of $0.8 million from Strike Force. During the three months ended March 31, 2017, Gulfport paid $10.0 million in cash calls to Strike Force and received distributions of $0.4 million from Strike Force.

The Company has elected to report its proportionate share of Strike Force’s earnings on a one-quarter lag as permitted under FASB ASC 323. The (income) loss from equity method investments presented in the table above reflects any intercompany profit eliminations.


4.	VARIABLE INTEREST ENTITIES

As of March 31, 2018, the Company held variable interests in the following variable interest entities (“VIEs”), but was not the primary beneficiary: Midstream and Timber Wolf. These entities have governing provisions that are the functional equivalent of a limited partnership and are considered VIEs because the limited partners or non-managing members lack substantive kick-out or participating rights which causes the equity owners, as a group, to lack a controlling financial interest. The Company is a limited partner or non-managing member in each of these VIEs and is not the primary beneficiary because it does not have a controlling financial interest. The general partner or managing member has power to direct the activities that most significantly impact the VIEs’ economic performance. The Company also held a variable interest in Strike Force due to the fact that it does not have sufficient equity capital at risk. The Company is not the primary beneficiary of this entity. Prior to Mammoth Energy’s IPO, Mammoth LLC was considered a VIE. As a result of the Company’s contribution of its interest in Mammoth LLC to Mammoth Energy in exchange for Mammoth Energy common stock and the completion of Mammoth Energy’s IPO, the Company determined that it no longer held an interest in a VIE. Prior to the contribution of Stingray Energy, Stingray Cementing and Sturgeon to Mammoth Energy, these entities were considered VIEs. As a result of the Company’s contribution of its membership interests in Stingray Energy, Stingray Cementing and Sturgeon to Mammoth Energy in exchange for Mammoth Energy common stock, the Company determined that it no longer held an interest in a VIE.

The Company accounts for its investment in these VIEs following the equity method of accounting. The carrying amounts of the Company’s equity investments are classified as other non-current assets on the accompanying consolidated balance sheets. The Company’s maximum exposure to loss as a result of its involvement with these VIEs is based on the Company’s capital contributions and the economic performance of the VIEs, and is equal to the carrying value of the Company’s investments which is the maximum loss the Company could be required to record in the consolidated statements of operations. See Note 3 for further discussion of these entities, including the carrying amounts of each investment.


5.	LONG-TERM DEBT

Long-term debt consisted of the following items as of March 31, 2018 and December 31, 2017:



	March 31, 2018			December 31, 2017
	(In thousands)
Revolving credit agreement (1)	$	200,000		$	—
6.625% senior unsecured notes due 2023 (2)	350,000			350,000
6.000% senior unsecured notes due 2024 (3)	650,000			650,000
6.375% senior unsecured notes due 2025 (4)	600,000			600,000
6.375% senior unsecured notes due 2026 (5)	450,000			450,000
Net unamortized debt issuance costs (6)	(33,927		)	(34,781		)
Construction loan (7)	23,579			23,724
Less: current maturities of long term debt	(629		)	(622		)
Debt reflected as long term	$	2,239,023		$	2,038,321

The Company capitalized approximately $0.8 million and $3.1 million in interest expense to undeveloped oil and natural gas properties during the three months ended March 31, 2018 and 2017, respectively.

(1) The Company has entered into a senior secured revolving credit facility, as amended, with The Bank of Nova Scotia, as the lead arranger and administrative agent and certain lenders from time to time party thereto. The credit agreement provides

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for a maximum facility amount of $1.5 billion and matures on December 31, 2021. On March 29, 2017, the Company further amended its revolving credit facility to, among other things, amend the definition of the term EBITDAX to permit pro forma treatment of acquisitions that involve the payment of consideration by Gulfport and its subsidiaries in excess of $50.0 million and of dispositions of property or series of related dispositions of properties that yields gross proceeds to Gulfport or any of its subsidiaries in excess of $50.0 million. On May 4, 2017, the revolving credit facility was further amended to increase the borrowing base from $700.0 million to $1.0 billion, adjust certain of the Company’s investment baskets and add five additional banks to the syndicate. On November 21, 2017, the Company further amended its revolving credit facility to, among other things, (a) decrease the applicable rate for all loans by 0.5% and (b) add a provision that allows Gulfport to elect a commitment amount (the “Elected Commitment Amount”) that is less than the borrowing base. In connection with this amendment, the borrowing base was set at $1.2 billion, with an elected commitment of $1.0 billion.

As of March 31, 2018, $200.0 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 $242.8 million of letters of credit, was $557.2 million. The Company’s wholly-owned subsidiaries have guaranteed the obligations of the Company under the revolving credit facility.

Advances under the revolving credit facility may be in the form of either base rate loans or eurodollar loans. The interest rate for base rate loans is equal to (1) the applicable rate, which ranges from 0.50% to 1.50%, plus (2) the highest of: (a) the federal funds rate plus 0.50%, (b) the rate of interest in effect for such day as publicly announced from time to time by agent as its “prime rate,” and (c) the eurodollar rate for an interest period of one month plus 1.00%. The interest rate for eurodollar loans is equal to (1) the applicable rate, which ranges from 1.50% to 2.50%, plus (2) the London interbank offered rate that appears on pages LIBOR01 or LIBOR02 of the Reuters screen that displays such rate for deposits in U.S. dollars, or, if such rate is not available, the rate as administered by ICE Benchmark Administration (or any other person that takes over administration of such rate) per annum equal to the offered rate on such other page or service that displays on average London interbank offered rate as determined by ICE Benchmark Administration (or any other person that takes over administration of such rate) for deposits in U.S. dollars, or, if such rate is not available, the average quotations for three major New York money center banks of whom the agent shall inquire as the “London Interbank Offered Rate” for deposits in U.S. dollars. At March 31, 2018, amounts borrowed under the credit facility bore interest at the eurodollar rate with a weighted average of 3.52%.

The revolving credit facility contains customary negative covenants including, but not limited to, restrictions on the Company’s and its subsidiaries’ ability to:

•incur indebtedness;

•grant liens;

•pay dividends and make other restricted payments;

•make investments;

•make fundamental changes;

•enter into swap contracts;

•dispose of assets;

•change the nature of their business; and

•enter into transactions with affiliates.

The negative covenants are subject to certain exceptions as specified in the revolving credit facility. The revolving credit facility also contains certain affirmative covenants, including, but not limited to the following financial covenants:

(i) the ratio of net funded debt to EBITDAX (net income, excluding (i) any non-cash revenue or expense associated with swap contracts resulting from ASC 815 and (ii) any cash or non-cash revenue or expense attributable to minority investments plus without duplication and, in the case of expenses, to the extent deducted from revenues in determining net income, the sum of (a) the aggregate amount of consolidated interest expense for such period, (b) the aggregate amount of income, franchise, capital or similar tax expense (other than ad valorem taxes) for such period, (c) all amounts attributable to depletion, depreciation, amortization and asset or goodwill impairment or writedown for such period, (d) all other non-cash charges, (e) exploration costs deducted in determining net income under successful efforts accounting, (f) actual cash distributions received from minority investments, (g) to the extent actually reimbursed by insurance, expenses with respect to liability on casualty

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events or business interruption, and (h) all reasonable transaction expenses related to dispositions and acquisitions of assets, investments and debt and equity offerings (provided that expenses related to any unsuccessful disposition will be limited to $3.0 million in the aggregate) for a twelve-month period may not be greater than 4.00 to 1.00; and

(ii) the ratio of EBITDAX to interest expense for a twelve-month period may not be less than 3.00 to 1.00.

The Company was in compliance with its financial covenants at March 31, 2018.

In connection with the Company's 2018 spring redetermination under the revolving credit facility, the lead lenders have proposed to increase the Company's borrowing base from $1.2 billion to $1.4 billion, with an elected commitment of $1.0 billion, and decrease the interest rate by 25 basis points, subject to the approval of the additional required banks within the syndicate.

(2) On April 21, 2015, the Company issued $350.0 million in aggregate principal amount of 6.625% Senior Notes due 2023 (the “2023 Notes”) to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to certain non-U.S. persons in accordance with Regulation S under the Securities Act (the “2023 Notes Offering”). The Company received net proceeds of approximately $343.6 million after initial purchaser discounts and commissions and estimated offering expenses.

The 2023 Notes were issued under an indenture, dated as of April 21, 2015, among the Company, the subsidiary guarantors party thereto and Wells Fargo Bank, National Association, as trustee. In October 2015, the 2023 Notes were exchanged for a new issue of substantially identical debt securities registered under the Securities Act. Pursuant to the indenture relating to the 2023 Notes, interest on the 2023 Notes accrues at a rate of 6.625% per annum on the outstanding principal amount thereof, payable semi-annually on May 1 and November 1 of each year. The 2023 Notes are not guaranteed by Grizzly Holdings, Inc. and will not be guaranteed by any of the Company’s future unrestricted subsidiaries.

(3) On October 14, 2016, the Company issued the 2024 Notes in aggregate principal amount of $650.0 million. The 2024 Notes were issued under an indenture, dated as of October 14, 2016, among the Company, the subsidiary guarantors party thereto and the senior note indenture trustee (the “2024 Indenture”), to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to certain non-U.S. persons in accordance with Regulation S under the Securities Act (the “2024 Notes Offering”). Under the 2024 Indenture, interest on the 2024 Notes accrues at a rate of 6.000% per annum on the outstanding principal amount thereof from October 14, 2016, payable semi-annually on April 15 and October 15 of each year, commencing on April 15, 2017. The 2024 Notes will mature on October 15, 2024. The Company received approximately $638.9 million in net proceeds from the offering of the 2024 Notes, which was used, together with cash on hand, to purchase the then outstanding 2020 Notes in a concurrent cash tender offer, to pay fees and expenses thereof, and to redeem any of the 2020 Notes that remained outstanding after the completion of the tender offer.

(4) On December 21, 2016, the Company issued $600.0 million in aggregate principal amount of 6.375% Senior Notes due 2025 (the “2025 Notes”). The 2025 Notes were issued under an indenture, dated as of December 21, 2016, among the Company, the subsidiary guarantors party thereto and the senior note indenture trustee (the “2025 Indenture”), to qualified institutional buyers pursuant to Rule 144A under the Securities Act of 1933, and to certain non-U.S. persons in accordance with Regulation S under the Securities Act. Under the 2025 Indenture, interest on the 2025 Notes accrues at a rate of 6.375% per annum on the outstanding principal amount thereof from December 21, 2016, payable semi-annually on May 15 and November 15 of each year, commencing on May 15, 2017. The 2025 Notes will mature on May 15, 2025. The Company received approximately $584.7 million in net proceeds from the offering of the 2025 Notes, which was used, together with the net proceeds from the Company’s December 2016 common stock offering and cash on hand, to fund the cash portion of the purchase price for the Vitruvian Acquisition. See “Note 1 – Acquisitions” for additional discussion of the Vitruvian Acquisition.

(5) On October 11, 2017, the Company issued $450.0 million in aggregate principal amount of its 6.375% Senior Notes due 2026 (the “2026 Notes”) to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to certain non-U.S. persons in accordance with Regulation S under the Securities Act. Interest on the 2026 Notes accrues at a rate of 6.375% per annum on the outstanding principal amount thereof from October 11, 2017, payable semi-annually on January 15 and July 15 of each year, commencing on January 15, 2018. The 2026 Notes will mature on January 15, 2026. The Company received approximately $444.1 million in net proceeds from the offering of the 2026 Notes, a portion of which was used to repay all of the Company's outstanding borrowings under its secured revolving credit facility on October 11, 2017 and the balance was used to fund the remaining outspend related to the Company's 2017 capital development plans.

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In connection with the 2026 Notes offering, the Company and its subsidiary guarantors entered into a registration rights agreement pursuant to which the Company agreed to file a registration statement with respect to an offer to exchange the 2026 Notes for a new issue of substantially identical debt securities registered under the Securities Act. On January 18, 2018, the Company filed a registration statement on Form S-4 with respect to an offer to exchange the 2026 Notes for substantially identical debt securities registered under the Securities Act, which registration statement was declared effective by the SEC on February 12, 2018. The exchange offer relating to the 2026 notes closed on March 22, 2018.

(6) Loan issuance costs related to the 2023 Notes, the 2024 Notes, the 2025 Notes and the 2026 Notes (collectively the “Notes”) have been presented as a reduction to the Notes. At March 31, 2018, total unamortized debt issuance costs were $5.0 million for the 2023 Notes, $9.6 million for the 2024 Notes, $13.6 million for the 2025 Notes and $5.5 million for the 2026 Notes. In addition, loan commitment fee costs for the construction loan agreement described immediately below were $0.1 million at March 31, 2018.

(7) On June 4, 2015, the Company entered into a construction loan agreement (the “Construction Loan”) with InterBank for the construction of a new corporate headquarters in Oklahoma City, which was substantially completed in December 2016. The Construction Loan allows for maximum principal borrowings of $24.5 million and required the Company to fund 30% of the cost of the construction before any funds could be drawn, which occurred in January 2016. Interest accrues daily on the outstanding principal balance at a fixed rate of 4.50% per annum and was payable on the last day of the month through May 31, 2017. Starting June 30, 2017, the Company began making monthly payments of principal and interest, with the final payment due June 4, 2025. At March 31, 2018, the total borrowings under the Construction Loan were approximately $23.6 million.


6.	COMMON STOCK AND CHANGES IN CAPITALIZATION

Issuance of Common Stock

On February 17, 2017, the Company completed the Vitruvian Acquisition for a total initial purchase price of approximately $1.85 billion, consisting of $1.35 billion in cash, subject to certain adjustments, and approximately 23.9 million shares of the Company’s common stock (of which approximately 5.2 million shares are subject to the indemnity escrow). See “Note 1 - Acquisitions” for additional discussion of the Vitruvian Acquisition.

Stock Repurchase Program

In January 2018, the board of directors of the Company approved a stock repurchase program to acquire up to $100 million of the Company's outstanding stock during 2018. Purchases under the repurchase program may be made from time to time in open market or privately negotiated transactions, and are subject to market conditions, applicable legal requirements, contractual obligations, and other factors. The repurchase program does not require the Company to acquire any specific number of shares. This repurchase program is authorized to extend through December 31, 2018 and may be suspended from time to time, modified, extended, or discontinued by the board of directors at any time. During the three months ended March 31, 2018, the Company repurchased 9.7 million shares for a total cost of approximately $100.0 million. All repurchased shares have been retired.


7.	STOCK-BASED COMPENSATION

During the three months ended March 31, 2018 and 2017, the Company’s stock-based compensation cost was $2.7 million and $2.6 million, respectively, of which the Company capitalized $1.1 million and $1.0 million, respectively, relating to its exploration and development efforts.

The following table summarizes restricted stock activity for the three months ended March 31, 2018:



	Number of Unvested Restricted Shares		Weighted Average Grant Date Fair Value
Unvested shares as of January 1, 2018	976,027		$	18.71
Granted	140,041		8.77
Vested	(109,933	)	21.42
Forfeited	(5,937	)	17.34
Unvested shares as of March 31, 2018	1,000,198		$	17.03

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Unrecognized compensation expense as of March 31, 2018 related to restricted shares was $12.9 million. The expense is expected to be recognized over a weighted average period of 1.53 years.

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8.	EARNINGS PER SHARE

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



	Three months ended March 31,
	2018					2017
	Income		Shares	Per Share		Income		Shares	Per Share
	(In thousands, except share data)
Basic:
Net income	$	90,090	180,714,881	$	0.50	$	154,455	170,272,685	$	0.91
Effect of dilutive securities:
Stock options and awards	—		87,420			—		215,834
Diluted:
Net income	$	90,090	180,802,301	$	0.50	$	154,455	170,488,519	$	0.91

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9.	COMMITMENTS AND CONTINGENCIES

Plugging and Abandonment Funds

In connection with the Company’s acquisition in 1997 of the remaining 50% interest in its WCBB properties, the Company assumed the seller’s (Chevron) obligation to contribute approximately $18,000 per month through March 2004 to a plugging and abandonment trust and the obligation to plug a minimum of 20 wells per year for 20 years commencing March 11, 1997. Chevron retained a security interest in production from these properties until the Company’s abandonment obligations to Chevron have been fulfilled. Beginning in 2009, the Company could access the trust for use in plugging and abandonment charges associated with the property, although it has not yet done so. As of March 31, 2018, the plugging and abandonment trust totaled approximately $3.1 million. At March 31, 2018, the Company had plugged 551 wells at WCBB since it began its plugging program in 1997, which management believes fulfills its minimum plugging obligation.

Operating Leases

The Company leases office facilities under non-cancellable operating leases exceeding one year. Future minimum lease commitments under these leases at March 31, 2018 were as follows:



	(In thousands)
Remaining 2018	$	80
2019	54
Total	$	134

Firm Transportation Commitments

The Company had approximately 2,621,000 MMBtu per day of firm sales contracted with third parties. The table below presents these commitments at March 31, 2018 as follows:



		(MMBtu per day)
Remaining 2018		552,000
2019		659,000
2020		526,000
2021		372,000
2022		272,000
Thereafter		240,000
Total		2,621,000

The Company also had approximately $3.7 billion of firm transportation contracted with third parties. The table below presents these commitments at March 31, 2018 as follows:



	(In thousands)
Remaining 2018	$	186,036
2019	251,644
2020	247,581
2021	246,620
2022	246,620
Thereafter	2,511,853
Total	$	3,690,354

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Other Commitments

Effective October 1, 2014, the Company entered into a Sand Supply Agreement with Muskie Proppant LLC (“Muskie”), a subsidiary of Mammoth Energy, that expires on September 30, 2018. Pursuant to this agreement, as amended, the Company has agreed to purchase annual and monthly amounts of proppant sand subject to exceptions specified in the agreement at agreed pricing plus agreed costs and expenses. Failure by either Muskie or the Company to deliver or accept the minimum monthly amount results in damages calculated per ton based on the difference between the monthly obligation amount and the amount actually delivered or accepted, as applicable. The Company incurred $0.9 million in non-utilization fees during the three months ended March 31, 2018. The Company did not incur any non-utilization fees during the three months ended March 31, 2017.

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, that expires on September 30, 2018. Pursuant to this agreement, as amended, Stingray Pressure has agreed to provide hydraulic fracturing, stimulation and related completion and rework services to the Company and the Company has agreed to pay Stingray Pressure a monthly service fee plus the associated costs of the services provided.

Future minimum commitments under these agreements at March 31, 2018 are $26.2 million.

Litigation

In two separate complaints, one filed by the State of Louisiana and the Parish of Cameron in the 38th Judicial District Court for the Parish of Cameron on February 9, 2016 and the other filed by the State of Louisiana and the District Attorney for the 15^th Judicial District of the State of Louisiana in the 15^th Judicial District Court for the Parish of Vermillion on July 29, 2016, the Company was named as a defendant, among 26 oil and gas companies, in the Cameron Parish complaint and among more than 40 oil and gas companies in the Vermillion Parish complaint, or the Complaints. The Complaints were filed under the State and Local Coastal Resources Management Act of 1978, as amended, and the rules, regulations, orders and ordinances adopted thereunder, which the Company referred to collectively as the CZM Laws, and allege that certain of the defendants’ oil and gas exploration, production and transportation operations associated with the development of the East Hackberry and West Hackberry oil and gas fields, in the case of the Cameron Parish complaint, and the Tigre Lagoon and Lac Blanc oil and gas fields, in the case of the Vermillion Parish complaint, were conducted in violation of the CZM Laws. The Complaints allege that such activities caused substantial damage to land and waterbodies located in the coastal zone of the relevant Parish, including due to defendants’ design, construction and use of waste pits and the alleged failure to properly close the waste pits and to clear, re-vegetate, detoxify and return the property affected to its original condition, as well as the defendants’ alleged discharge of waste into the coastal zone. The Complaints also allege that the defendants’ oil and gas activities have resulted in the dredging of numerous canals, which had a direct and significant impact on the state coastal waters within the relevant Parish and that the defendants, among other things, failed to design, construct and maintain these canals using the best practical techniques to prevent bank slumping, erosion and saltwater intrusion and to minimize the potential for inland movement of storm-generated surges, which activities allegedly have resulted in the erosion of marshes and the degradation of terrestrial and aquatic life therein. The Complaints also allege that the defendants failed to re-vegetate, refill, clean, detoxify and otherwise restore these canals to their original condition. In these two petitions, 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 pre-judgment and post judgment interest.

The Company was served with the Cameron complaint in early May 2016 and with the Vermillion complaint in early September 2016. The Louisiana Attorney General and the Louisiana Department of Natural Resources intervened in both the Cameron Parish suit and the Vermillion Parish suit. Shortly after the Complaints were filed, certain defendants removed the cases to the lawsuit to the United States District Court for the Western District of Louisiana. In both cases, the plaintiffs filed a motion to remand, and the plaintiffs agreed to an extension of time for all defendants to file responsive pleadings until the District Courts ruled on the motions to remand. In the Vermilion Parish case, the District Court entered an order on September 26, 2017 remanding the lawsuit to the 15th Judicial District Court, State of Louisiana, Parish of Vermilion. In the Cameron Parish lawsuit, the federal magistrate, on January 18, 2018, issued a report and recommendation that the Cameron Parish lawsuit be remanded to the 38th Judicial District Court, State of Louisiana, Parish of Cameron. Due to the procedural posture of lawsuits and that responsive pleadings have not been filed, the parties have not begun discovery and the Company has not had the opportunity to evaluate the applicability of the allegations made in plaintiffs' complaints to the Company's operations, management cannot determine the amount of loss, if any, that may result.

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In addition, due to the nature of the Company’s business, it is, from time to time, involved in routine litigation or subject to disputes or claims related to its business activities, including workers’ compensation claims and employment related disputes. In the opinion of the Company’s management, none of the pending litigation, disputes or claims against the Company, if decided adversely, will have a material adverse effect on its financial condition, cash flows or results of operations.


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 prices, which are subject to significant and often volatile fluctuation, by entering into over-the-counter fixed price swaps, basis swaps and various types of option contracts. These contracts allow the Company to predict with greater certainty the effective natural gas, oil and natural gas liquids 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, Argus Louisiana Light Sweet Crude for oil, the NYMEX West Texas Intermediate for oil, and Mont Belvieu for propane and pentane. Below is a summary of the Company’s open fixed price swap positions as of March 31, 2018.



	Location	Daily Volume (MMBtu/day)	Weighted Average Price
Remaining 2018	NYMEX Henry Hub	927,000	$	3.02
2019	NYMEX Henry Hub	647,000	$	2.84
2020	NYMEX Henry Hub	45,000	$	2.77



	Location	Daily Volume (Bbls/day)	Weighted Average Price
Remaining 2018	ARGUS LLS	2,000	$	56.22
2019	ARGUS LLS	1,000	$	59.55
Remaining 2018	NYMEX WTI	4,000	$	53.99
2019	NYMEX WTI	3,000	$	57.62



	Location	Daily Volume (Bbls/day)	Weighted Average Price
Remaining 2018	Mont Belvieu C3	4,000	$	28.97
2019	Mont Belvieu C3	1,000	$	27.05
Remaining 2018	Mont Belvieu C5	500	$	46.62

The Company sold call options and used the associated premiums to enhance the fixed price for a portion of the fixed price natural gas swaps listed above. Each short call option has an established ceiling price. When the referenced settlement price is above the price ceiling established by these short 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
April 2018 - March 2019	NYMEX Henry Hub	50,000	$	3.13
April 2019 - December 2019	NYMEX Henry Hub	30,000	$	3.10

For a portion of the natural gas fixed price swaps listed above, the counterparty has an option to extend the original terms an additional twelve months for the period January 2019 through December 2019. The option to extend the terms expires in December 2018. If executed, the Company would have additional fixed price swaps for 100,000 MMBtu per day at a weighted average price of $3.05 per MMBtu.

Balance Sheet Presentation

The Company reports the fair value of derivative instruments on the consolidated balance sheets as derivative instruments under current assets, noncurrent assets, current liabilities and noncurrent liabilities on a gross basis. The Company determines the current and noncurrent classification based on the timing of expected future cash flows of individual trades. The following table presents the fair value of the Company’s derivative instruments on a gross basis at March 31, 2018 and December 31, 2017:



	March 31, 2018		December 31, 2017
	(In thousands)
Short-term derivative instruments - asset	$	50,906	$	78,847
Long-term derivative instruments - asset	$	15,769	$	8,685
Short-term derivative instruments - liability	$	37,570	$	32,534
Long-term derivative instruments - liability	$	2,499	$	2,989

Gains and Losses

The following table presents the gain and loss recognized in Net (loss) gain on natural gas, oil and NGL derivatives in the accompanying consolidated statements of operations for the three months ended March 31, 2018 and 2017.



	Net (loss) gain on derivative instruments
	Three months ended March 31,
	2018			2017
	(In thousands)
Natural gas derivatives	$	(9,696	)	$	86,277
Oil derivatives	(9,147		)	10,905
Natural gas liquids derivatives	2,314			2,395
Total	$	(16,529	)	$	99,577

Offsetting of derivative assets and liabilities

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



	As of March 31, 2018
	Gross Assets (Liabilities)			Gross Amounts
	Presented in the			Subject to Master			Net
	Consolidated Balance Sheets			Netting Agreements			Amount
	(In thousands)
Derivative assets	$	66,675		$	(27,431	)	$	39,244
Derivative liabilities	$	(40,069	)	$	27,431		$	(12,638	)



	As of December 31, 2017
	Gross Assets (Liabilities)			Gross Amounts
	Presented in the			Subject to Master			Net
	Consolidated Balance Sheets			Netting Agreements			Amount
	(In thousands)
Derivative assets	$	87,532		$	(22,199	)	$	65,333
Derivative liabilities	$	(35,523	)	$	22,199		$	(13,324	)

Concentration of Credit Risk

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


11.	FAIR VALUE MEASUREMENTS

The Company records certain financial and non-financial assets and liabilities on the balance sheet at fair value in accordance with FASB ASC 820, “Fair Value Measurement and Disclosures” (“FASB ASC 820”). FASB ASC 820 defines fair value as 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. The statement establishes market or observable inputs as the preferred sources of values, followed by assumptions based on hypothetical transactions in the absence of market inputs. The statement requires fair value measurements be 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 FASB ASC 820 valuation level as of March 31, 2018 and December 31, 2017:



	March 31, 2018
	Level 1		Level 2		Level 3
	(In thousands)
Assets:
Derivative Instruments	$	—	$	66,675	$	—
Liabilities:
Derivative Instruments	$	—	$	40,069	$	—

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	December 31, 2017
	Level 1		Level 2		Level 3
	(In thousands)
Assets:
Derivative Instruments	$	—	$	87,532	$	—
Liabilities:
Derivative Instruments	$	—	$	35,523	$	—

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.

The estimated fair values of proved oil and natural gas properties assumed in business combinations are based on a discounted cash flow model and market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk-adjusted discount rates. The estimated fair values of unevaluated oil and natural gas properties was based on geological studies, historical well performance, location and applicable mineral lease terms. Based on the unobservable nature of certain of the inputs, the estimated fair value of the oil and gas properties assumed is deemed to use Level 3 inputs. The asset retirement obligations assumed as part of the business combination were estimated using the same assumptions and methodology as described below. See Note 1 for further discussion of the Vitruvian Acquisition.

The Company estimates asset retirement obligations pursuant to the provisions of FASB ASC Topic 410, Asset Retirement and Environmental Obligations (“FASB ASC 410”). The initial measurement of asset retirement obligations at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with oil and gas properties. Given the unobservable nature of the inputs, including plugging costs and reserve lives, the initial measurement of the asset retirement obligation liability is deemed to use Level 3 inputs. See Note 2 for further discussion of the Company’s asset retirement obligations. Asset retirement obligations incurred during the three months ended March 31, 2018 were approximately $0.4 million.

The fair value of the common stock received from Mammoth Energy in connection with the Company’s contribution of all of its membership interests in Sturgeon, Stingray Energy and Stingray Cementing was estimated using Level 1 inputs, as the price per share was a quoted price in an active market for identical Mammoth Energy common shares.


12.	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 Construction Loan is carried at cost, which approximates market value based on the borrowing rates currently available to the Company with similar terms and maturities.

At March 31, 2018, the carrying value of the outstanding debt represented by the Notes was approximately $2.0 billion, including the unamortized debt issuance cost of approximately $5.0 million related to the 2023 Notes, approximately $9.6 million related to the 2024 Notes, approximately $13.6 million related to the 2025 Notes and approximately $5.5 million related to the 2026 Notes. Based on the quoted market price, the fair value of the Notes was determined to be approximately $2.0 billion at March 31, 2018.


13.	REVENUE FROM CONTRACTS WITH CUSTOMERS

Revenue Recognition

On January 1, 2018, the Company adopted Accounting Standards Update ("ASU") No. 2014-09, Revenue from Contracts with Customers ("ASC 606") using the modified retrospective transition applied to contracts that were not completed as of that

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date. Results for reporting periods beginning after January 1, 2018 are presented under ASC 606 while prior period amounts are not adjusted and continue to be reported in accordance with historic revenue recognition guidance. The Company’s revenues are primarily derived from the sale of natural gas, oil and condensate and natural gas liquids (“NGLs”). Sales of natural gas, oil and condensate and NGLs 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 a point-in-time once control of the product has been transferred to the customer upon delivery to an agreed upon delivery point. The Company considers a variety of facts and circumstances in assessing the point of control transfer, including but not limited to: (i) whether the purchaser can direct the use of the product, (ii) the transfer of significant risks, (iii) the Company’s right to payment and (iv) transfer of legal title. 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. The payment date is usually within 30 days of the end of the calendar month in which the commodity is delivered.

The recognition of gains or losses on derivative instruments is outside the scope of ASC 606 and is not considered revenue from contracts with customers subject to ASC 606. The Company may use financial or physical contracts accounted for as derivatives as economic hedges to manage price risk associated with normal sales, or in limited cases may use them for contracts the Company intends to physically settle but do not meet all of the criteria to be treated as normal sales.

Taxes assessed by a governmental authority that are both imposed on and concurrent with a specific revenue-producing transaction, and that are collected by the Company from a customer, are excluded from revenue.

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 $125.8 million and $135.0 million as of March 31, 2018 and December 31, 2017, respectively, and are reported in accounts receivable - oil and natural gas on the consolidated balance sheet. The Company currently has no assets or liabilities related to its revenue contracts, including no upfront or rights to deficiency payments.

Contract Modifications

For contracts modified prior to the beginning of the earliest reporting period presented under ASC 606, the Company has elected to reflect the aggregate of the effect of all modifications that occurred before the beginning of the earliest period presented under the new standard when identifying the satisfied and unsatisfied performance obligations, determining the transaction price and allocating the transaction price to the satisfied and unsatisfied performance obligations for the modified contracts at transition.

Prior-Period Performance Obligations

The Company records revenue in the month production is delivered to the purchaser. However, settlement statements for certain gas and NGLs sales may be received for 30 to 90 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production that was delivered to the purchaser and the price that will be received for the sale of the product. The differences between the estimates and the actual amounts for product sales is recorded

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in the month that payment is received from the purchaser. The Company has internal controls in place for the estimation process and any identified differences between revenue estimates and actual revenue received historically have not been significant. For the three months ended March 31, 2018, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.

14. INCOME TAXES

On December 22, 2017, the President of the United States signed into law Public Law No. 115-97, a comprehensive tax reform bill commonly referred to as the Tax Cuts and Jobs Act, or the Tax Act, that significantly reformed the Internal Revenue Code of 1986, as amended. The Tax act substantially revised numerous areas of U.S. federal income tax law, including reducing the maximum corporate income tax rate from 35% to 21%, allowing for full expensing of certain capital expenditures, modifying the limitations on the utilization of net operating losses, and repealing the corporate alternative minimum tax. The various estimates included in determining the Company's tax provision as of December 31, 2017 remain provisional through the three months ended March 31, 2018 and may be adjusted through subsequent events such as the filing of its 2017 consolidated federal income tax return and the issuance of additional guidance from the Internal Revenue Service or from state tax authorities. There were no material changes to the provisional estimates during the quarter ended March 31, 2018.

15. CONDENSED CONSOLIDATING FINANCIAL INFORMATION

On April 21, 2015, the Company issued $350.0 million in aggregate principal amount of the 2023 Notes to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to certain non-U.S. persons in accordance with Regulation S under the Securities Act. In connection with the 2023 Notes Offering, the Company and its subsidiary guarantors entered into a registration rights agreement, dated as of April 21, 2015, pursuant to which the Company agreed to file a registration statement with respect to an offer to exchange the 2023 Notes for a new issue of substantially identical debt securities registered under the Securities Act. The exchange offer for the 2023 Notes was completed on October 13, 2015.

On October 14, 2016, the Company issued $650.0 million in aggregate principal amount of the 2024 Notes to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to certain non-U.S. persons in accordance with Regulation S under the Securities Act. The net proceeds from the issuance of the 2024 Notes, together with cash on hand, were used to repurchase or redeem all of the then-outstanding 2020 Notes in October 2016.

On December 21, 2016, the Company issued $600.0 million in aggregate principal amount of the 2025 Notes to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to certain non-U.S. persons in accordance with Regulation S under the Securities Act. The Company used the net proceeds from the issuance of the 2025 Notes, together with the net proceeds from the December 2016 underwritten offering of the Company’s common stock and cash on hand, to fund the cash portion of the purchase price for the Vitruvian Acquisition.

In connection with the 2024 Notes and the 2025 Notes Offerings, the Company and its subsidiary guarantors entered into two registration rights agreements, pursuant to which the Company agreed to file a registration statement with respect to offers to exchange the 2024 Notes and the 2025 Notes for new issues of substantially identical debt securities registered under the Securities Act. The exchange offers for the 2024 Notes and the 2025 Notes were completed on September 13, 2017.

On October 11, 2017, the Company issued $450.0 million in aggregate principal amount of the 2026 Notes to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to certain non-U.S. persons in accordance with Regulation S under the Securities Act. A portion of the net proceeds from the issuance of the 2026 Notes was used to repay all of the Company's outstanding borrowings under its secured revolving credit facility on October 11, 2017 and the balance was used to fund the remaining outspend related to the Company's 2017 capital development plans.

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 2023 Notes, the 2024 Notes, the 2025 Notes and the 2026 Notes are not guaranteed by Grizzly Holdings,

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Inc. (the “Non-Guarantor”). 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.

The following condensed consolidating balance sheets, statements of operations, statements of comprehensive income (loss) and statements of cash flows are provided for the Parent, the Guarantors and the Non-Guarantor 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-Guarantor.

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CONDENSED CONSOLIDATING BALANCE SHEETS

(Amounts in thousands)



	March 31, 2018
	Parent			Guarantors			Non-Guarantor			Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	81,357		$	37,254		$	2		$	—		$	118,613
Accounts receivable - oil and natural gas	133,387			66,070			—			—			199,457
Accounts receivable - intercompany	585,111			64,492			—			(649,603		)	—
Prepaid expenses and other current assets	6,115			1,449			—			—			7,564
Short-term derivative instruments	50,906			—			—			—			50,906
Total current assets	856,876			169,265			2			(649,603		)	376,540

Property and equipment:
Oil and natural gas properties, full-cost accounting	6,769,164			2,702,262			—			(729		)	9,470,697
Other property and equipment	89,597			51			—			—			89,648
Accumulated depletion, depreciation, amortization and impairment	(4,264,609		)	(38		)	—			—			(4,264,647		)
Property and equipment, net	2,594,152			2,702,275			—			(729		)	5,295,698
Other assets:
Equity investments and investments in subsidiaries	2,458,237			77,350			53,563			(2,277,456		)	311,694
Long-term derivative instruments	15,769			—			—			—			15,769
Deferred tax asset	—			—			—			—			—
Inventories	6,045			2,460			—			—			8,505
Other assets	13,569			6,617			—			—			20,186
Total other assets	2,493,620			86,427			53,563			(2,277,456		)	356,154
Total assets	$	5,944,648		$	2,957,967		$	53,565		$	(2,927,788	)	$	6,028,392

Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable and accrued liabilities	$	443,963		$	133,585		$	—		$	—		$	577,548
Accounts payable - intercompany	64,980			584,495			128			(649,603		)	—
Asset retirement obligation - current	120			—			—			—			120
Short-term derivative instruments	37,570			—			—			—			37,570
Current maturities of long-term debt	629			—			—			—			629
Total current liabilities	547,262			718,080			128			(649,603		)	615,867
Long-term derivative instruments	2,499			—			—			—			2,499
Asset retirement obligation - long-term	64,091			12,176			—			—			76,267
Deferred tax liability	2,884			—			—			—			2,884
Other non-current liabilities	—			2,963			—			—			2,963
Long-term debt, net of current maturities	2,239,023			—			—			—			2,239,023
Total liabilities	2,855,759			733,219			128			(649,603		)	2,939,503

Stockholders’ equity:
Common stock	1,735			—			—			—			1,735
Paid-in capital	4,319,034			1,915,598			260,877			(2,176,475		)	4,319,034
Accumulated other comprehensive (loss) income	(46,042		)	—			(43,909		)	43,909			(46,042		)
Retained (deficit) earnings	(1,185,838		)	309,150			(163,531		)	(145,619		)	(1,185,838		)
Total stockholders’ equity	3,088,889			2,224,748			53,437			(2,278,185		)	3,088,889
Total liabilities and stockholders’ equity	$	5,944,648		$	2,957,967		$	53,565		$	(2,927,788	)	$	6,028,392

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CONDENSED CONSOLIDATING BALANCE SHEETS

(Amounts in thousands)



	December 31, 2017
	Parent			Guarantors			Non-Guarantor			Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	67,908		$	31,649		$	—		$	—		$	99,557
Accounts receivable - oil and natural gas	128,121			54,092			—			—			182,213
Accounts receivable - intercompany	554,439			63,374			—			(617,813		)	—
Prepaid expenses and other current assets	4,719			193			—			—			4,912
Short-term derivative instruments	78,847			—			—			—			78,847
Total current assets	834,034			149,308			—			(617,813		)	365,529

Property and equipment:
Oil and natural gas properties, full-cost accounting,	6,562,147			2,607,738			—			(729		)	9,169,156
Other property and equipment	86,711			43			—			—			86,754
Accumulated depletion, depreciation, amortization and impairment	(4,153,696		)	(37		)	—			—			(4,153,733		)
Property and equipment, net	2,495,162			2,607,744			—			(729		)	5,102,177
Other assets:
Equity investments and investments in subsidiaries	2,361,575			77,744			57,641			(2,194,848		)	302,112
Long-term derivative instruments	8,685			—			—			—			8,685
Deferred tax asset	1,208			—			—			—			1,208
Inventories	5,816			2,411			—			—			8,227
Other assets	12,483			7,331			—			—			19,814
Total other assets	2,389,767			87,486			57,641			(2,194,848		)	340,046
Total assets	$	5,718,963		$	2,844,538		$	57,641		$	(2,813,390	)	$	5,807,752

Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable and accrued liabilities	$	416,249		$	137,361		$	—		$	(1	)	$	553,609
Accounts payable - intercompany	63,373			554,313			127			(617,813		)	—
Asset retirement obligation - current	120			—			—			—			120
Short-term derivative instruments	32,534			—			—			—			32,534
Current maturities of long-term debt	622			—			—			—			622
Total current liabilities	512,898			691,674			127			(617,814		)	586,885
Long-term derivative instruments	2,989			—			—			—			2,989
Asset retirement obligation - long-term	63,141			11,839			—			—			74,980
Other non-current liabilities	—			2,963			—			—			2,963
Long-term debt, net of current maturities	2,038,321			—			—			—			2,038,321
Total liabilities	2,617,349			706,476			127			(617,814		)	2,706,138

Stockholders’ equity:
Common stock	1,831			—			—			—			1,831
Paid-in capital	4,416,250			1,915,598			259,307			(2,174,905		)	4,416,250
Accumulated other comprehensive (loss) income	(40,539		)	—			(38,593		)	38,593			(40,539		)
Retained (deficit) earnings	(1,275,928		)	222,464			(163,200		)	(59,264		)	(1,275,928		)
Total stockholders’ equity	3,101,614			2,138,062			57,514			(2,195,576		)	3,101,614
Total liabilities and stockholders’ equity	$	5,718,963		$	2,844,538		$	57,641		$	(2,813,390	)	$	5,807,752

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CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

(Amounts in thousands)



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

Total revenues	$	213,561	$	111,831	$	—	$	—	$	325,392