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, 2017 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)

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



Title of Each Class		Name of Each Exchange on Which Registered
Common Stock, par value $0.01 per share		The NASDAQ Stock Market LLC

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, 2017, 182,835,801 shares of the registrant’s common stock were outstanding.

Table of Contents

GULFPORT ENERGY CORPORATION

TABLE OF CONTENTS



		Page
PART I FINANCIAL INFORMATION

Item 1.	Consolidated Financial Statements (unaudited):	2

	Consolidated Balance Sheets at March 31, 2017 and December 31, 2016	2

	Consolidated Statements of Operations for the Three Months Ended March 31, 2017 and 2016	3

	Consolidated Statements of Comprehensive Income (Loss) for the Three Months Ended March 31, 2017 and 2016	4

	Consolidated Statements of Stockholders’ Equity for the Three Months Ended March 31, 2017 and 2016	5

	Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2017 and 2016	6

	Notes to Consolidated Financial Statements	7

Item 2.	Management’s Discussion and Analysis of Financial Conditions and Results of Operations	32

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	46

Item 4.	Controls and Procedures	48

PART II OTHER INFORMATION

Item 1.	Legal Proceedings	49

Item 1A.	Risk Factors	49

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

Item 3.	Defaults Upon Senior Securities	50

Item 4.	Mine Safety Disclosures	50

Item 5.	Other Information	50

Item 6.	Exhibits	50

Signatures		52

Table of Contents

GULFPORT ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS

(Unaudited)



	March 31, 2017			December 31, 2016
	(In thousands, except share data)
Assets
Current assets:
Cash and cash equivalents	$	102,485		$	1,275,875
Restricted cash	—			185,000
Accounts receivable—oil and gas	158,154			136,761
Accounts receivable—related parties	39			16
Prepaid expenses and other current assets	16,005			7,639
Short-term derivative instruments	18,925			3,488
Total current assets	295,608			1,608,779
Property and equipment:
Oil and natural gas properties, full-cost accounting, $3,073,448 and $1,580,305 excluded from amortization in 2017 and 2016, respectively	8,146,321			6,071,920
Other property and equipment	75,107			68,986
Accumulated depletion, depreciation, amortization and impairment	(3,855,629		)	(3,789,780		)
Property and equipment, net	4,365,799			2,351,126
Other assets:
Equity investments	251,370			243,920
Long-term derivative instruments	23,515			5,696
Deferred tax asset	4,692			4,692
Other assets	12,945			8,932
Total other assets	292,522			263,240
Total assets	$	4,953,929		$	4,223,145
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable and accrued liabilities	$	406,139		$	265,124
Asset retirement obligation—current	195			195
Short-term derivative instruments	67,179			119,219
Current maturities of long-term debt	452			276
Total current liabilities	473,965			384,814
Long-term derivative instrument	5,259			26,759
Asset retirement obligation—long-term	41,142			34,081
Long-term debt, net of current maturities	1,631,809			1,593,599
Total liabilities	2,152,175			2,039,253
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, 182,835,801 issued and outstanding at March 31, 2017 and 158,829,816 at December 31, 2016	1,828			1,588
Paid-in capital	4,408,236			3,946,442
Accumulated other comprehensive loss	(51,685		)	(53,058		)
Retained deficit	(1,556,625		)	(1,711,080		)
Total stockholders’ equity	2,801,754			2,183,892
Total liabilities and stockholders’ equity	$	4,953,929		$	4,223,145

See accompanying notes to consolidated financial statements.

Table of Contents

GULFPORT ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)



	Three months ended March 31,
	2017			2016
	(In thousands, except share data)
Revenues:
Gas sales	$	177,837		$	74,094
Oil and condensate sales	24,411			15,839
Natural gas liquid sales	31,179			9,293
Net gain on gas, oil, and NGL derivatives	99,577			57,735
	333,004			156,961
Costs and expenses:
Lease operating expenses	19,303			16,657
Production taxes	3,906			3,111
Midstream gathering and processing	47,941			37,652
Depreciation, depletion and amortization	65,991			65,477
Impairment of oil and gas properties	—			218,991
General and administrative	12,600			10,620
Accretion expense	282			247
Acquisition expense	1,298			—
	151,321			352,755
INCOME (LOSS) FROM OPERATIONS	181,683			(195,794		)
OTHER (INCOME) EXPENSE:
Interest expense	23,479			16,023
Interest income	(842		)	(94		)
Loss from equity method investments, net	4,907			30,737
Other income	(316		)	(2		)
	27,228			46,664
INCOME (LOSS) BEFORE INCOME TAXES	154,455			(242,458		)
INCOME TAX BENEFIT	—			(191		)
NET INCOME (LOSS)	$	154,455		$	(242,267	)
NET INCOME (LOSS) PER COMMON SHARE:
Basic	$	0.91		$	(2.17	)
Diluted	$	0.91		$	(2.17	)
Weighted average common shares outstanding—Basic	170,272,685			111,509,585
Weighted average common shares outstanding—Diluted	170,488,519			111,509,585

See accompanying notes to consolidated financial statements.

Table of Contents

GULFPORT ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Unaudited)



	Three months ended March 31,
	2017		2016
	(In thousands)
Net income (loss)	$	154,455	$	(242,267	)
Foreign currency translation adjustment	1,373		9,058
Other comprehensive income	1,373		9,058
Comprehensive income (loss)	$	155,828	$	(233,209	)

See accompanying notes to consolidated financial statements.

Table of Contents

GULFPORT ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(Unaudited)



				Paid-in Capital			Accumulated Other Comprehensive Income (loss)			Retained Deficit			Total Stockholders’ Equity
	Common Stock
	Shares	Amount
	(In thousands, except share data)
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 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

Balance at January 1, 2016	108,322,250	$	1,082	$	2,824,303		$	(55,177	)	$	(731,371	)	$	2,038,837
Net loss	—	—		—			—			(242,267		)	(242,267		)
Other Comprehensive Income	—	—		—			9,058			—			9,058
Stock Compensation	—	—		3,341			—			—			3,341
Issuance of Common Stock in public offerings, net of related expenses	16,905,000	169		411,651			—			—			411,820
Issuance of Restricted Stock	100,310	1		(1		)	—			—			—
Balance at March 31, 2016	125,327,560	$	1,252	$	3,239,294		$	(46,119	)	$	(973,638	)	$	2,220,789

See accompanying notes to consolidated financial statements.

Table of Contents

GULFPORT ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)



	Three months ended March 31,
	2017			2016
	(In thousands)
Cash flows from operating activities:
Net income (loss)	$	154,455		$	(242,267	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Accretion of discount—Asset Retirement Obligation	282			247
Depletion, depreciation and amortization	65,991			65,477
Impairment of oil and gas properties	—			218,991
Stock-based compensation expense	1,532			2,005
Loss from equity investments	5,150			30,896
Change in fair value of derivative instruments	(106,796		)	7,685
Deferred income tax expense (benefit)	—			(191		)
Amortization of loan commitment fees	1,088			946
Amortization of note discount and premium	—			(563		)
Changes in operating assets and liabilities:
Increase in accounts receivable	(21,393		)	(6,629		)
Increase in accounts receivable—related party	(23		)	(1		)
(Increase) decrease in prepaid expenses	(8,366		)	1,150
Increase in other assets	(4,013		)	—
Increase in accounts payable, accrued liabilities and other	54,738			6,080
Settlement of asset retirement obligation	—			(52		)
Net cash provided by operating activities	142,645			83,774
Cash flows from investing activities:
Additions to other property and equipment	(5,444		)	(5,183		)
Acquisition of oil and gas properties	(1,338,964		)	—
Additions to oil and gas properties	(181,834		)	(151,293		)
Proceeds from sale of oil and gas properties	3,605			630
Funding of restricted cash	185,000			—
Contributions to equity method investments	(10,673		)	(1,821		)
Distributions from equity method investments	631			138
Net cash used in investing activities	(1,347,679		)	(157,529		)
Cash flows from financing activities:
Principal payments on borrowings	—			(1,685		)
Borrowings on line of credit	40,000			—
Borrowings on term loan	2,698			5,041
Debt issuance costs and loan commitment fees	(5,733		)	(116		)
Proceeds from issuance of common stock, net of offering costs	(5,321		)	411,918
Net cash provided by financing activities	31,644			415,158
Net (decrease) increase in cash and cash equivalents	(1,173,390		)	341,403
Cash and cash equivalents at beginning of period	1,275,875			112,974
Cash and cash equivalents at end of period	$	102,485		$	454,377
Supplemental disclosure of cash flow information:
Interest payments	$	347		$	80
Income tax payments	$	—		$	—
Supplemental disclosure of non-cash transactions:
Capitalized stock based compensation	$	1,021		$	1,336
Asset retirement obligation capitalized	$	6,779		$	1,914
Interest capitalized	$	3,122		$	1,862
Foreign currency translation gain on equity method investments	$	1,373		$	9,058

See accompanying notes to consolidated financial statements.

Table of Contents

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, 2017 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.

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 in the Vitruvian Acquisition to acquire the properties and the fair value amount of the assets acquired as of February 17, 2017. Both the consideration paid and the fair value assigned to the assets is preliminary and subject to adjustment.

Table of Contents



	(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 have contributed the following amounts of revenue to the Company’s consolidated statements of operations. The amount of net income contributed by the assets acquired is not presented below as it is impracticable to calculate due to the Company integrating the acquired assets into its overall operations using the full cost method of accounting.



	(In thousands)
Revenue	$	26,226

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, 2016. 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, 2016; furthermore, the financial information is not intended to be a projection of future results.



	Three months ended March 31,
	2017		2016
	(In thousands, except share data)
Pro forma revenue	$	368,903	$	203,712
Pro forma net income (loss)	$	175,881	$	(274,207	)
Pro forma earnings (loss) per share (basic)	$	1.03	$	(2.03	)
Pro forma earnings (loss) per share (diluted)	$	1.03	$	(2.03	)


2.	PROPERTY AND EQUIPMENT

The major categories of property and equipment and related accumulated depletion, depreciation, amortization and impairment as of March 31, 2017 and December 31, 2016 are as follows:

Table of Contents



	March 31, 2017			December 31, 2016
	(In thousands)
Oil and natural gas properties	$	8,146,321		$	6,071,920
Office furniture and fixtures	24,649			21,204
Building	45,204			42,530
Land	5,254			5,252
Total property and equipment	8,221,428			6,140,906
Accumulated depletion, depreciation, amortization and impairment	(3,855,629		)	(3,789,780		)
Property and equipment, net	$	4,365,799		$	2,351,126

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 gas properties. At March 31, 2017, 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, 2017. An impairment of $219.0 million was required for oil and natural gas properties for the three months ended March 31, 2016.

Included in oil and natural gas properties at March 31, 2017 is the cumulative capitalization of $138.3 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 $8.4 million and $7.1 million for three months ended March 31, 2017 and 2016, respectively.

The following table summarizes the Company’s non-producing properties excluded from amortization by area at March 31, 2017:



	March 31, 2017
	(In thousands)
Utica	$	1,592,683
MidCon	1,477,643
Niobrara	2,172
Southern Louisiana	484
Bakken	98
Other	368
	$	3,073,448

At December 31, 2016, approximately $1.6 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 have five-year extension terms which could extend this time frame beyond five years.

Table of Contents

A reconciliation of the Company’s asset retirement obligation for the three months ended March 31, 2017 and 2016 is as follows:



	March 31, 2017		March 31, 2016
	(In thousands)
Asset retirement obligation, beginning of period	$	34,276	$	26,437
Liabilities incurred	6,779		1,914
Liabilities settled	—		(52		)
Accretion expense	282		247
Asset retirement obligation as of end of period	41,337		28,546
Less current portion	195		75
Asset retirement obligation, long-term	$	41,142	$	28,471


3.	EQUITY INVESTMENTS

Investments accounted for by the equity method consist of the following as of March 31, 2017 and December 31, 2016:



			Carrying value				(Income) loss from equity method investments
	Approximate ownership %		March 31, 2017		December 31, 2016		Three months ended March 31,
	Approximate ownership %		March 31, 2017		December 31, 2016		2017			2016
			(In thousands)
Investment in Tatex Thailand II, LLC	23.5	%	$	—	$	—	$	(243	)	$	(159	)
Investment in Tatex Thailand III, LLC	17.9	%	—		—		—			—
Investment in Grizzly Oil Sands ULC	24.9999	%	46,838		45,213		365			23,685
Investment in Timber Wolf Terminals LLC	50.0	%	987		991		4			3
Investment in Windsor Midstream LLC	22.5	%	25,815		25,749		(311		)	(167		)
Investment in Stingray Cementing LLC	50.0	%	1,768		1,920		128			30
Investment in Blackhawk Midstream LLC	48.5	%	—		—		—			—
Investment in Stingray Energy Services LLC	50.0	%	3,967		4,215		197			502
Investment in Sturgeon Acquisitions LLC	25.0	%	20,458		20,526		68			377
Investment in Mammoth Energy Services, Inc.	24.2	%	110,875		111,717		2,158			6,466
Investment in Strike Force Midstream LLC	25.0	%	40,662		33,589		2,541			—
			$	251,370	$	243,920	$	4,907		$	30,737

The tables below summarize financial information for the Company’s equity investments as of March 31, 2017 and December 31, 2016.

Summarized balance sheet information:



	March 31, 2017		December 31, 2016
	March 31, 2017		December 31, 2016
	(In thousands)
Current assets	$	151,587	$	148,733
Noncurrent assets	$	1,342,012	$	1,305,407
Current liabilities	$	97,329	$	57,173
Noncurrent liabilities	$	59,721	$	67,680

Table of Contents

Summarized results of operations:



	Three months ended March 31,
	2017			2016
	(In thousands)
Gross revenue	$	94,478		$	43,307
Net loss	$	(25,339	)	$	(25,308	)

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 $0.2 million and $0.2 million in distributions from Tatex II during the three months ended March 31, 2017 and 2016, 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.

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, 2017, Grizzly had approximately 830,000 acres under lease in the Athabasca and Peace River oil sands regions of Alberta, Canada. Initiation of steam injection at its first project, Algar Lake Phase 1, commenced in January 2014 and first bitumen production was achieved during the second quarter of 2014. In April 2015, Grizzly determined to cease bitumen production at its Algar Lake facility due to the level of commodity prices. Grizzly continues to monitor market conditions as it assesses future plans for the facility. The Company reviewed its investment in Grizzly at March 31, 2016 for impairment based on FASB ASC 323 due to certain qualitative factors and as such, engaged an independent third party to assist management in determining fair value calculations of its investment. As a result of the calculated fair values and other qualitative factors, the Company concluded that an other than temporary impairment was required under FASB ASC 323, resulting in an impairment loss of $23.1 million for the three months ended March 31, 2016, which is included in loss from equity method investments, net in the consolidated statements of operations. As of and during the period ended March 31, 2017, commodity prices had increased as compared to the quarter ended March 31, 2016, and there were no impairment indicators that required further evaluation for impairment. If commodity prices decline in the future however, further impairment of the investment in Grizzly may be necessary. During the three months ended March 31, 2017, Gulfport paid $0.7 million in cash calls. Grizzly’s functional currency is the Canadian dollar. The Company’s investment in Grizzly was increased by $1.3 million and $10.3 million as a result of a foreign currency translation gain for the three months ended March 31, 2017 and 2016, 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.

Windsor Midstream LLC

At March 31, 2017, the Company held a 22.5% interest in Windsor Midstream LLC (“Midstream”). Midstream holds common units of EnLink Midstream Partners, LP (“EnLink”) as a result of the sale of Coronado Midstream LLC to EnLink that occurred in March 2015. The Company received $0.2 million and $0.1 million in distributions from Midstream during the three months ended March 31, 2017 and 2016, respectively.

Stingray Cementing LLC

Table of Contents

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. See Note 15 for subsequent event information regarding Mammoth Energy Services, Inc.’s pending acquisition of Stingray Cementing.

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. See Note 15 for subsequent event information regarding Mammoth Energy Services, Inc.’s pending acquisition of Stingray Energy.

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. See Note 15 for subsequent event information regarding Mammoth Energy Services, Inc.’s pending acquisition of Sturgeon.

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. Mammoth originally intended to pursue its initial public offering in 2014 or 2015; however, due to low commodity prices, the offering was postponed. 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 Services, Inc. (“Mammoth Energy”). The Company received 9,150,000 shares of Mammoth Energy common stock in return for its contribution. Following the contribution, Mammoth Energy completed its initial public offering (the “IPO”) of 7,750,000 shares of its common stock at a public offering price of $15.00 per share, of which 7,500,000 shares were sold by Mammoth Energy, and 250,000 shares were sold by certain selling stockholders, including 76,250 shares sold by the Company for which it received net proceeds of $1.1 million. At March 31, 2017, the Company owned an approximate 24.2% interest in Mammoth Energy. The Company’s investment in Mammoth Energy was increased by a $0.1 million foreign currency gain and decreased by a $1.2 million foreign currency loss resulting from Mammoth Energy’s foreign subsidiary for the three months ended March 31, 2017 and 2016, respectively. The (income) loss from equity method investments presented in the table above reflects any intercompany profit eliminations. See Note 15 for subsequent event information regarding Mammoth Energy’s pending acquisitions of Stingray Cementing, Stingray Energy and Sturgeon.

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 (the “dedicated areas”). The Company contributed certain gathering assets for a 25% interest in the newly formed entity called Strike Force Midstream LLC (“Strike Force”). Rice acts as operator and owns the remaining 75% interest in Strike Force. Construction of the gathering assets, which is underway, is expected to provide gathering services for Gulfport operated wells and connectivity of existing dry gas gathering systems. 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 accounted for its contribution to Strike Force at fair value under applicable codification guidance. The Company estimated the fair market value of its investment in Strike Force as of the contribution date using the discounted cash flow method under the income approach, based on an independently prepared valuation of the contributed assets. The fair market value was reduced by a discount factor for the lack of marketability due to the Company’s minority interest, resulting in

Table of Contents

a fair value of $22.5 million for the Company’s 25% interest. The fair value of the assets contributed was estimated using assumptions that represent Level 3 inputs. See “Note 11 - Fair Value Measurements” for additional discussion of the measurement inputs. 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, 2017, the Company held variable interests in the following variable interest entities (“VIEs”), but was not the primary beneficiary: Stingray Energy, Stingray Cementing, Sturgeon, 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 variable interest entity. 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 Mammoth Energy’s IPO, the Company determined that it no longer held an interest in a variable interest entity.

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, 2017 and December 31, 2016:



	March 31, 2017			December 31, 2016
	(In thousands)
Revolving credit agreement (1)	$	40,000		$	—
7.75% senior unsecured notes due 2020 (2)	—			—
6.625% senior unsecured notes due 2023 (3)	350,000			350,000
6.000% senior unsecured notes due 2024 (4)	650,000			650,000
6.375% senior unsecured notes due 2025 (5)	600,000			600,000
Net unamortized debt issuance costs (6)	(31,486		)	(27,174		)
Construction loan (7)	23,747			21,049
Less: current maturities of long term debt	(452		)	(276		)
Debt reflected as long term	$	1,631,809		$	1,593,599

The Company capitalized approximately $3.1 million and $1.6 million in interest expense to undeveloped oil and natural gas properties during the three months ended March 31, 2017 and 2016, respectively. During the three months ended March 31, 2016, the Company capitalized $0.3 million in interest expense related to building construction. Construction on the building was completed in December 2016 and, as such, the Company did not capitalize any interest expense related to building construction for the three months ended March 31, 2017.

(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 for a maximum facility amount of $1.5 billion and matures on June 6, 2018. On December 13, 2016, the Company further amended its revolving credit facility to, among other things, (a) reset the maturity date to December 31, 2021, (b) adjust lenders, (c) increase the basket for unsecured debt issuances to $1.6 billion, (d) increase the interest rates by 50 basis points, (e) increase the mortgage requirement to 85% (from 80%), and (f) add deposit account control agreement language. On March 29,

Table of Contents

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.

As of March 31, 2017, the borrowing base was set at $700.0 million and $40.0 million was outstanding under the revolving credit facility. At March 31, 2017, the total availability for future borrowings under the revolving credit facility, after giving effect to an aggregate of $238.7 million of letters of credit, was $421.3 million. The Company’s wholly-owned subsidiaries have guaranteed the obligations of the Company under the revolving credit facility.

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.

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 1.00% to 2.00%, 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 2.00% to 3.00%, 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, 2107, amounts borrowed under the credit facility bore interest at the eurodollar rate (3.18%).

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 and forward sales 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 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

Table of Contents

(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 all covenants at March 31, 2017.

(2) On October 17, 2012, the Company issued $250.0 million in aggregate principal amount of 7.75% Senior Notes due 2020 (the “October Notes”) under an indenture among the Company, its subsidiary guarantors and Wells Fargo Bank, National Association, as the trustee (the “senior note indenture”). On December 21, 2012, the Company issued an additional $50.0 million in aggregate principal amount of 7.75% Senior Notes due 2020 (the “December Notes”) as additional securities under the senior note indenture. On August 18, 2014, the Company issued an additional $300.0 million in aggregate principal amount of 7.75% Senior Notes due 2020 (the “August Notes”). The August Notes were issued as additional securities under the senior note indenture. The October Notes, December Notes and the August Notes are collectively referred to as the “2020 Notes.”

In October 2016, the Company repurchased (in a cash tender offer) or redeemed all of the 2020 Notes, of which $600.0 million in aggregate principal amount was then outstanding, with the net proceeds from the issuance of its 6.000% Senior Notes due 2024 (the “2024 Notes”) discussed below and cash on hand, and the indenture governing the 2020 Notes was fully satisfied and discharged.

(3) 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 will accrue at a rate of 6.625% per annum on the outstanding principal amount thereof from April 21, 2015, payable semi-annually on May 1 and November 1 of each year, commencing on November 1, 2015. The 2023 Notes are not guaranteed by Grizzly Holdings, Inc. and will not be guaranteed by any of the Company’s future unrestricted subsidiaries.

(4) 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 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.

(5) 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.

(6) In accordance with ASU 2015-03, loan issuance costs related to the 2023 Notes, the 2024 Notes and the 2025 Notes (collectively the “Notes”) have been presented as a reduction to the Notes. At March 31, 2017, total unamortized debt issuance costs were $5.8 million for the 2023 Notes, $10.7 million for the 2024 Notes and $14.9 million for the 2025 Notes. In addition, loan commitment fee costs for the construction loan agreement described immediately below were $0.1 million at March 31, 2017.

Table of Contents

(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 is payable on the last day of the month through May 31, 2017. Monthly interest and principal payments are due beginning June 30, 2017, with the final payment due June 4, 2025. At March 31, 2017, the total borrowings under the Construction Loan were approximately $23.7 million.


6.	COMMON STOCK AND CHANGES IN CAPITALIZATION

Issuance of Common Stock

On March 15, 2016, the Company issued 16,905,000 shares of its common stock in an underwritten public offering (which included 2,205,000 shares sold pursuant to an option to purchase shares sold pursuant to an option to purchase additional shares of the Company’s common stock granted by the Company to, and exercised in full by, the underwriters). The net proceeds from this equity offering were approximately $411.9 million, after underwriting discounts and commissions and offering expenses. The Company used the net proceeds from this offering primarily to fund a portion of its 2017 capital development plan and for general corporate purposes.

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.


7.	STOCK-BASED COMPENSATION

During the three months ended March 31, 2017 and 2016, the Company’s stock-based compensation cost was $2.6 million and $3.3 million, respectively, of which the Company capitalized $1.0 million and $1.3 million, respectively, relating to its exploration and development efforts.

The following table summarizes restricted stock activity for the three months ended March 31, 2017:



	Number of Unvested Restricted Shares		Weighted Average Grant Date Fair Value
Unvested shares as of January 1, 2017	613,056		$	32.90
Granted	477,768		17.74
Vested	(153,868	)	31.98
Forfeited	(65,438	)	31.23
Unvested shares as of March 31, 2017	871,518		$	24.88

Unrecognized compensation expense as of March 31, 2017 related to restricted shares was $18.1 million. The expense is expected to be recognized over a weighted average period of 1.66 years.

Table of Contents


8.	EARNINGS PER SHARE

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



	Three months ended March 31,
	2017					2016
	Income		Shares	Per Share		(Loss)			Shares	Per Share
	(In thousands, except share data)
Basic:
Net income (loss)	$	154,455	170,272,685	$	0.91	$	(242,267	)	111,509,585	$	(2.17	)
Effect of dilutive securities:
Stock options and awards	—		215,834			—			—
Diluted:			—
Net income (loss)	$	154,455	170,488,519	$	0.91	$	(242,267	)	111,509,585	$	(2.17	)

There were 650,606 shares of common stock that were considered anti-dilutive for the three months ended March 31, 2016.

Table of Contents


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, 2017, the plugging and abandonment trust totaled approximately $3.1 million. At March 31, 2017, the Company had plugged 513 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, 2017 were as follows:



	(In thousands)
Remaining 2017	$	129
2018	54
Total	$	183

Firm Transportation Commitments

The Company had approximately 2,952,375 MMBtu per day of firm sales contracted with third parties. The table below presents these commitments at March 31, 2017 as follows:



		(MMBtu per day)
Remaining 2017		725,625
2018		457,000
2019		604,750
2020		518,000
2021		371,000
Thereafter		276,000
Total		2,952,375

The Company also had approximately $3.8 billion of firm transportation contracted with third parties. The table below presents these commitments at March 31, 2017 as follows:



	(In thousands)
Remaining 2017	$	143,816
2018	241,709
2019	241,708
2020	240,746
2021	239,786
Thereafter	2,705,270
Total	$	3,813,035

Table of Contents

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 $1.3 million related to non-utilization fees during the three months ended March 31, 2016. 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, 2017 are as follows:



	(In thousands)
Remaining 2017	$	39,330
2018	39,330
Total	$	78,660

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 oil and gas field, 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 have filed a motion to remand, but both Courts have stayed further proceedings on the motions to remand pending a ruling from the United States Court of Appeals, Fifth Circuit on similar jurisdictional issues in another matter. In March 2017, the United States Court of Appeals, Fifth Circuit issued its ruling. Subsequently, the Vermillion Parish case and Cameron Parish case have

Table of Contents

both had their respective stays lifted. A hearing on the remand motions has been scheduled for May 17, 2017 in the Vermillion Parish case. No hearing on the remand motions has been set for the Cameron Parish case. The plaintiffs have granted all defendants an extension of time to file responsive pleadings to the Complaints until the District Courts rule on the motions to remand. The Company has not had the opportunity to evaluate the applicability of the allegations made in such complaints to their operations. Due to the early stages of these matters, management cannot determine the amount of loss, if any, that may result.

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, 2017.



	Location	Daily Volume (MMBtu/day)	Weighted Average Price
Remaining 2017	NYMEX Henry Hub	576,845	$	3.18
2018	NYMEX Henry Hub	543,767	$	3.09
2019	NYMEX Henry Hub	9,863	$	3.27



	Location	Daily Volume (Bbls/day)	Weighted Average Price
Remaining 2017	ARGUS LLS	1,665	$	52.32
Remaining 2017	NYMEX WTI	4,113	$	54.97
2018	NYMEX WTI	899	$	55.31



	Location	Daily Volume (Bbls/day)	Weighted Average Price
Remaining 2017	Mont Belvieu C3	3,000	$	26.63
Remaining 2017	Mont Belvieu C5	250	$	49.14

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
Remaining 2017	NYMEX Henry Hub	65,000	$	3.11
2018	NYMEX Henry Hub	80,000	$	3.29
2019	NYMEX Henry Hub	4,932	$	3.16

For a portion of the combined natural gas derivative instruments containing fixed price swaps and sold call options, the counterparty has an option to extend the original terms an additional twelve months for the period January 2018 through December 2018. The option to extend the terms expires in December 2017. If executed, the Company would have additional fixed price swaps for 30,000 MMBtu per day with the option to double at a weighted average price of $3.36 per MMBtu and additional short call options for 30,000 MMBtu per day with the option to double at a weighted average ceiling price of $3.36 per MMBtu.

In addition, the Company has entered into natural gas basis swap positions, which settle on the pricing index to basis differential of NGPL Mid-Continent to NYMEX Henry Hub. As of March 31, 2017, the Company had the following natural gas basis swap positions for NGPL Mid-Continent.



	Location	Daily Volume (MMBtu/day)	Hedged Differential
Remaining 2017	NGPL Mid-Continent	50,000	$	(0.26	)
2018	NGPL Mid-Continent	12,329	$	(0.26	)

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, 2017 and December 31, 2016:



	March 31, 2017		December 31, 2016
	(In thousands)
Short-term derivative instruments - asset	$	18,925	$	3,488
Long-term derivative instruments - asset	$	23,515	$	5,696
Short-term derivative instruments - liability	$	67,179	$	119,219
Long-term derivative instruments - liability	$	5,259	$	26,759

Gains and Losses

The following table presents the gain and loss recognized in Net gain on gas, oil and NGL derivatives in the accompanying consolidated statements of operations for the three months ended March 31, 2017 and 2016.



	Net gain (loss) on derivative instruments
	Three months ended March 31,
	2017		2016
	(In thousands)
Natural gas derivatives	$	86,277	$	57,000
Oil derivatives	10,905		1,282
Natural gas liquids derivatives	2,395		(547		)
Total	$	99,577	$	57,735

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, 2017
	Gross Assets (Liabilities)			Gross Amounts
	Presented in the			Subject to Master			Net
	Consolidated Balance Sheets			Netting Agreements			Amount
	(In thousands)
Derivative assets	$	42,440		$	(41,180	)	$	1,260
Derivative liabilities	$	(72,438	)	$	41,180		$	(31,258	)



	As of December 31, 2016
	Gross Assets (Liabilities)			Gross Amounts
	Presented in the			Subject to Master			Net
	Consolidated Balance Sheets			Netting Agreements			Amount
	(In thousands)
Derivative assets	$	9,184		$	(9,184	)	$	—
Derivative liabilities	$	(145,978	)	$	9,184		$	(136,794	)

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

Table of Contents

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, 2017 and December 31, 2016:



	March 31, 2017
	Level 1		Level 2		Level 3
	(In thousands)
Assets:
Derivative Instruments	$	—	$	42,440	$	—
Liabilities:
Derivative Instruments	$	—	$	72,438	$	—



	December 31, 2016
	Level 1		Level 2		Level 3
	(In thousands)
Assets:
Derivative Instruments	$	—	$	9,184	$	—
Liabilities:
Derivative Instruments	$	—	$	145,978	$	—

The Company estimates the fair value of all derivative instruments industry-standard models that considered 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 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 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, 2017 were approximately $6.8 million.

Due to the unobservable nature of the inputs, the fair value of the Company’s investment in Grizzly was estimated using assumptions that represent Level 3 inputs. The Company estimated the fair value of the investment as of March 31, 2016 to be approximately $39.1 million. See Note 3 for further discussion of the Company’s investment in Grizzly.

Due to the unobservable nature of the inputs, the fair value of the Company’s investment in Strike Force was estimated using assumptions that represent Level 3 inputs. The Company’s estimated fair value of the investment as of the February 1, 2016 contribution date was $22.5 million. See Note 3 for further discussion of the Company’s contribution to Strike Force.

Table of Contents


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, 2017, the carrying value of the outstanding debt represented by the Notes was approximately $1.6 billion, including the unamortized debt issuance cost of approximately $5.8 million related to the 2023 Notes, approximately $10.7 million related to the 2024 Notes and approximately $14.9 million related to the 2025 Notes. Based on the quoted market price, the fair value of the Notes was determined to be approximately $1.6 billion at March 31, 2017.


13.	CONDENSED CONSOLIDATING FINANCIAL INFORMATION

On October 17, 2012, December 21, 2012 and August 18, 2014, the Company issued the 2020 Notes in an aggregate of $600.0 million principal amount. The 2020 Notes were subsequently exchanged for substantially identical notes in the same aggregate principal amount that were registered under the Securities Act. In October 2016, the Company repurchased (in a cash tender offer) or redeemed all of the 2020 Notes, of which $600.0 million in aggregate principal amount was then outstanding, with the net proceeds from the issuance of the 2024 Notes discussed below and cash on hand.

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.

The 2020 Notes were, and the 2023 Notes, the 2024 Notes and the 2025 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 2020 Notes were not, and the 2023 Notes, the 2024 Notes and the 2025 Notes are not, guaranteed by Grizzly Holdings, 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 (loss) income 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.

Table of Contents

CONDENSED CONSOLIDATING BALANCE SHEETS

(Amounts in thousands)



	March 31, 2017
	Parent			Guarantors			Non-Guarantor			Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	71,934		$	30,550		$	1		$	—		$	102,485
Accounts receivable - oil and gas	106,008			52,146			—			—			158,154
Accounts receivable - related parties	39			—			—			—			39
Accounts receivable - intercompany	447,275			35,434			—			(482,709		)	—
Prepaid expenses and other current assets	12,330			3,675			—			—			16,005
Short-term derivative instruments	18,925			—			—			—			18,925
Total current assets	656,511			121,805			1			(482,709		)	295,608
Property and equipment:
Oil and natural gas properties, full-cost accounting	5,869,066			2,277,984			—			(729		)	8,146,321
Other property and equipment	75,064			43			—			—			75,107
Accumulated depletion, depreciation, amortization and impairment	(3,855,594		)	(35		)	—			—			(3,855,629		)
Property and equipment, net	2,088,536			2,277,992			—			(729		)	4,365,799
Other assets:
Equity investments and investments in subsidiaries	2,120,462			40,661			46,838			(1,956,591		)	251,370
Long-term derivative instruments	23,515			—			—			—			23,515
Deferred tax asset	4,692			—			—			—			4,692
Other assets	8,765			4,180			—			—			12,945
Total other assets	2,157,434			44,841			46,838			(1,956,591		)	292,522
Total assets	$	4,902,481		$	2,444,638		$	46,839		$	(2,440,029	)	$	4,953,929

Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable and accrued liabilities	$	326,175		$	79,964		$	—		$	—		$	406,139
Accounts payable - intercompany	35,005			447,577			127			(482,709		)	—
Asset retirement obligation	195			—			—			—			195
Derivative instruments	67,179			—			—			—			67,179
Current maturities of long-term debt	452			—			—			—			452
Total current liabilities	429,006			527,541			127			(482,709		)	473,965
Long-term derivative instrument	5,259			—			—			—			5,259
Asset retirement obligation	34,653			6,489			—			—			41,142
Long-term debt, net of current maturities	1,631,809			—			—			—			1,631,809
Total liabilities	2,100,727			534,030			127			(482,709		)	2,152,175

Stockholders’ equity:
Common stock	1,828			—			—			—			1,828
Paid-in capital	4,408,236			1,872,598			257,700			(2,130,298		)	4,408,236
Accumulated other comprehensive (loss) income	(51,685		)	—			(49,613		)	49,613			(51,685		)
Retained (deficit) earnings	(1,556,625		)	38,010			(161,375		)	123,365			(1,556,625		)
Total stockholders’ equity	2,801,754			1,910,608			46,712			(1,957,320		)	2,801,754
Total liabilities and stockholders’ equity	$	4,902,481		$	2,444,638		$	46,839		$	(2,440,029	)	$	4,953,929

Table of Contents

CONDENSED CONSOLIDATING BALANCE SHEETS

(Amounts in thousands)



	December 31, 2016
	Parent			Guarantors			Non-Guarantor			Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	1,273,882		$	1,993		$	—		$	—		$	1,275,875
Restricted Cash	185,000			—			—			—			$	185,000
Accounts receivable - oil and gas	137,087			37,496			—			(37,822		)	136,761
Accounts receivable - related parties	16			—			—			—			16
Accounts receivable - intercompany	449,517			1,151			—			(450,668		)	—
Prepaid expenses and other current assets	6,230			1,409			—			—			7,639
Short-term derivative instruments	3,488			—			—			—			3,488
Total current assets	2,055,220			42,049			—			(488,490		)	1,608,779

Property and equipment:
Oil and natural gas properties, full-cost accounting,	5,655,125			417,524			—			(729		)	6,071,920
Other property and equipment	68,943			43			—			—			68,986
Accumulated depletion, depreciation, amortization and impairment	(3,789,746		)	(34		)	—			—			(3,789,780		)
Property and equipment, net	1,934,322			417,533			—			(729		)	2,351,126
Other assets:
Equity investments and investments in subsidiaries	236,327			33,590			45,213			(71,210		)	243,920
Long-term derivative instruments	5,696			—			—			—			5,696
Deferred tax asset	4,692			—			—			—			4,692
Other assets	8,932			—			—			—			8,932
Total other assets	255,647			33,590			45,213			(71,210		)	263,240
Total assets	$	4,245,189		$	493,172		$	45,213		$	(560,429	)	$	4,223,145

Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable and accrued liabilities	$	255,966		$	9,158		$	—		$	—		$	265,124
Accounts payable - intercompany	31,202			457,163			126			(488,491		)	—
Asset retirement obligation	195			—			—			—			195
Derivative instruments	119,219			—			—			—			119,219
Current maturities of long-term debt	276			—			—			—			276
Total current liabilities	406,858			466,321			126			(488,491		)	384,814

Long-term derivative instrument	26,759			—			—			—			26,759
Asset retirement obligation	34,081			—			—			—			34,081
Long-term debt, net of current maturities	1,593,599			—			—			—			1,593,599
Total liabilities	2,061,297			466,321			126			(488,491		)	2,039,253

Stockholders’ equity:
Common stock	1,588			—			—			—			1,588
Paid-in capital	3,946,442			33,822			257,026			(290,848		)	3,946,442
Accumulated other comprehensive (loss) income	(53,058		)	—			(50,931		)	50,931			(53,058		)
Retained (deficit) earnings	(1,711,080		)	(6,971		)	(161,008		)	167,979			(1,711,080		)
Total stockholders’ equity	2,183,892			26,851			45,087			(71,938		)	2,183,892
Total liabilities and stockholders’ equity	$	4,245,189		$	493,172		$	45,213		$	(560,429	)	$	4,223,145

Table of Contents

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

(Amounts in thousands)



	Three months ended March 31, 2017
	Parent			Guarantors			Non-Guarantor			Eliminations			Consolidated

Total revenues	$	272,441		$	60,563		$	—		$	—		$	333,004

Costs and expenses:
Lease operating expenses	17,449			1,854			—			—			19,303
Production taxes	3,102			804			—			—			3,906
Midstream gathering and processing	37,724			10,217			—			—			47,941
Depreciation, depletion, and amortization	65,990			1			—			—			65,991
General and administrative	12,874			(275		)	1			—			12,600
Accretion expense	282			—			—			—			282
Acquisition expense	—			1,298			—			—			1,298
	137,421			13,899			1			—			151,321

INCOME (LOSS) FROM OPERATIONS	135,020			46,664			(1		)	—			181,683

OTHER (INCOME) EXPENSE:
Interest expense	25,048			(1,569		)	—			—			23,479
Interest income	(842		)	—			—			—			(842		)
(Income) loss from equity method investments and investments in subsidiaries	(42,614		)	2,541			365			44,615			4,907
Other (income) expense	(1,027		)	(189		)	—			900			(316		)
	(19,435		)	783			365			45,515			27,228

INCOME (LOSS) BEFORE INCOME TAXES	154,455			45,881			(366		)	(45,515		)	154,455
INCOME TAX EXPENSE	—			—			—			—			—

NET INCOME (LOSS)	$	154,455		$	45,881		$	(366	)	$	(45,515	)	$	154,455

Table of Contents

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

(Amounts in thousands)



	Three months ended March 31, 2016
	Parent			Guarantors			Non-Guarantor			Eliminations			Consolidated

Total revenues	$	156,751		$	210		$	—		$	—		$	156,961

Costs and expenses:
Lease operating expenses	16,472			185			—			—			16,657
Production taxes	3,087			24			—			—			3,111
Midstream gathering and processing	37,623			29			—			—			37,652
Depreciation, depletion, and amortization	65,476			1			—			—			65,477
Impairment of oil and gas properties	218,991			—			—			—			218,991
General and administrative	10,612			6			2			—			10,620
Accretion expense	247			—			—			—			247
	352,508			245			2			—			352,755

LOSS FROM OPERATIONS	(195,757		)	(35		)	(2		)	—			(195,794		)

OTHER (INCOME) EXPENSE:
Interest expense	16,022			1			—			—			16,023
Interest income	(94		)	—			—			—			(94		)
Loss (income) from equity method investments and investments in subsidiaries	30,773			—			23,685			(23,721		)	30,737
Other income	—			(2		)	—			—			(2		)
	46,701			(1		)	23,685			(23,721		)	46,664

(LOSS) INCOME BEFORE INCOME TAXES	(242,458		)	(34		)	(23,687		)	23,721			(242,458		)
INCOME TAX BENEFIT	(191		)										(191		)

NET (LOSS) INCOME	$	(242,267	)	$	(34	)	$	(23,687	)	$	23,721		$	(242,267	)

CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Amounts in thousands)



	Three months ended March 31, 2017
	Parent		Guarantors		Non-Guarantor			Eliminations			Consolidated

Net income (loss)	$	154,455	$	45,881	$	(366	)	$	(45,515	)	$	154,455
Foreign currency translation adjustment	1,373		55		1,318			(1,373		)	1,373
Other comprehensive income (loss)	1,373		55		1,318			(1,373		)	1,373
Comprehensive income (loss)	$	155,828	$	45,936	$	952		$	(46,888	)	$	155,828



	Three months ended March 31, 2016
	Parent			Guarantors			Non-Guarantor			Eliminations			Consolidated

Net (loss) income	$	(242,267	)	$	(34	)	$	(23,687	)	$	23,721		$	(242,267	)
Foreign currency translation adjustment	9,058			—			10,273			(10,273		)	9,058
Other comprehensive income (loss)	9,058			—			10,273			(10,273		)	9,058
Comprehensive (loss) income	$	(233,209	)	$	(34	)	$	(13,414	)	$	13,448		$	(233,209	)

Table of Contents

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

(Amounts in thousands)



	Three months ended March 31, 2017
	Parent			Guarantors			Non-Guarantor			Eliminations			Consolidated

Net cash provided by (used in) operating activities	$	139,260		$	3,384		$	1		$	—		$	142,645

Net cash (used in) provided by investing activities	(1,372,852		)	(1,348,964		)	(673		)	1,374,810			(1,347,679		)

Net cash provided by (used in) financing activities	31,644			1,374,137			673			(1,374,810		)	31,644

Net (decrease) increase in cash and cash equivalents	(1,201,948		)	28,557			1			—			(1,173,390		)

Cash and cash equivalents at beginning of period	1,273,882			1,993			—			—			1,275,875

Cash and cash equivalents at end of period	$	71,934		$	30,550		$	1		$	—		$	102,485



	Three months ended March 31, 2016
	Parent			Guarantors			Non-Guarantor			Eliminations			Consolidated

Net cash provided by (used in) operating activities	$	83,620		$	155		$	(1	)	$	—		$	83,774

Net cash (used in) provided by investing activities	(157,529		)	(22,500		)	(1,821		)	24,321			(157,529		)

Net cash provided by (used in) financing activities	415,158			22,500			1,821			(24,321		)	415,158

Net increase (decrease) in cash and cash equivalents	341,249			155			(1		)	—			341,403

Cash and cash equivalents at beginning of period	112,494			479			1			—			112,974

Cash and cash equivalents at end of period	$	453,743		$	634		$	—		$	—		$	454,377

Table of Contents


14.	RECENT ACCOUNTING PRONOUNCEMENTS

In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2014-09, Revenue from Contracts with Customers, which supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and most industry-specific guidance. The core principle of the new standard is for the recognition of revenue to depict the transfer of goods or services to customers in amounts that reflect the payment to which the company expects to be entitled in exchange for those goods or services. The new standard will also result in enhanced revenue disclosures, provide guidance for transactions that were not previously addressed comprehensively and improve guidance for multiple-element arrangements. The ASU is effective for annual periods beginning after December 15, 2016, and interim periods within those years, using either a full or a modified retrospective application approach. In July 2015, the FASB decided to defer the effective date by one year (until 2018). The Company is evaluating the impact of this ASU on its consolidated financial statements, and based on the continuing evaluation of its revenue streams, this ASU is not expected to have a material impact on its net income. The Company is still in the process of determining whether or not it will use the retrospective method or the modified retrospective approach to implementation.

In February 2016, the FASB issued ASU No. 2016-02, Leases. The guidance requires the lessee to recognize most leases on the balance sheet thereby resulting in the recognition of lease assets and liability for those leases currently classified as operating leases. The accounting for lessors is largely unchanged. The guidance is effective for periods after December 15, 2018, with early adoption permitted. The Company is in the process of evaluating the impact of this guidance on its consolidated financial statements and related disclosures; however, based on the Company’s current operating leases, it is not expected to have a material impact.

In March 2016, the FASB issued ASU No. 2016-05, Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships. The guidance was issued to clarify that change in the counterparty to a derivative instrument that had been designated as the hedging instrument under Topic 815, does not require designation of that hedging relationship provided that all other hedge accounting criteria continue to be met. The Company adopted the standard as of January 1, 2017. There was no impact on the Company’s consolidated financial statements because all current derivative instruments are not designated for hedge accounting.

In March 2016, the FASB issued ASU No. 2016-09, Improvements to Employee Share-Based Payment Accounting. This guidance was intended to simplify the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities and classification on the statement of cash flows. The Company adopted the standard as of January 1, 2017. The Company has elected to recognize forfeitures of awards as they occur. The adoption of this standard did not have a material impact on the Company's consolidated financial statements.

In May 2016, the FASB issued ASU No. 2016-11, Revenue Recognition and Derivatives and Hedging: Rescission of SEC Guidance Because of Accounting Standards Updates 2014-09 and 2014-16 Pursuant to Staff Announcements at the March 3, 2016 EITF Meeting. This guidance rescinds SEC Staff Observer comments that are codified in Topic 606, Revenue Recognition, and Topic 932, Extractive Activities--Oil and Gas. This amendment is effective upon adoption of Topic 606. The Company is in the process of evaluating the impact of this guidance on its consolidated financial statements.

In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments-Credit Losses: Measurement of Credit Losses on Financial Instruments. This ASU amends guidance on reporting credit losses for assets held at amortized cost basis and available for sale debt securities. For assets held at amortized cost basis, this ASU eliminates the probable initial recognition threshold in current GAAP and instead, requires an entity to reflect its current estimate of all expected credit losses. The amendments affect loans, debt securities, trade receivables, net investments in leases, off balance sheet credit exposure, reinsurance receivables and any other financial assets not excluded from the scope that have the contractual right to receive cash. The Company is currently evaluating the impact this standard will have on its financial statements and related disclosures and does not anticipate it to have a material affect.

In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments. This ASU provides guidance of eight specific cash flow issues. This ASU is effective for periods after December 15, 2017, with early adoption permitted. The Company is in the process of evaluating the impact of this guidance on its consolidated financial statements.

Table of Contents

amendment is effective for periods after December 15, 2017, with early adoption permitted. The Company is in the process of evaluating the impact of this ASU on its consolidated financial statements.

In January 2017, the FASB issued ASU No. 2017-01, Clarifying the Definition of a Business. Under the current business combination guidance, there are three elements of a business: inputs, processes and outputs. The revised guidance adds an initial screen test to determine if substantially all of the fair value of the gross assets acquired is concentrated in a single asset or group of similar assets. If that screen is met, the set of assets is not a business. The new framework also specifies the minimum required inputs and processes necessary to be a business. This amendment is effective for periods after December 15, 2017, with early adoption permitted. The Company is in the process of evaluating the impact of this ASU on its consolidated financial statements.


15.	SUBSEQUENT EVENTS

Derivatives

In April 2017, the Company entered into fixed price swaps for 2018 for approximately 65,000 MMBtu of natural gas per day at a weighted average price of $3.03 per MMBtu. For 2019, the Company entered into fixed price swaps for approximately 10,000 MMBtu of natural gas per day at a weighted average price of $3.01 per MMBtu. The Company’s fixed price swap contracts are tied to the commodity prices on NYMEX. The Company will receive the fixed price amount stated in the contract and pay to its counterparty the current market price as listed on NYMEX for natural gas.

Mammoth Energy Pending Acquisitions

In March 2017, Mammoth Energy entered into definitive agreements to acquire Sturgeon (which owns Taylor Frac, LLC, Taylor Real Estate Investments, LLC and South River Road, LLC), Stingray Energy and Stingray Cementing from the owners of such companies, including Gulfport, for an aggregate of 7.0 million shares of Mammoth Energy common stock. Mammoth Energy anticipates the transactions will close in the second quarter of 2017, subject to agreed closing conditions. Upon closing, the Company will receive approximately 2.0 million shares of Mammoth Energy common stock and hold approximately 25.1% of Mammoth Energy’s outstanding common stock.

Table of Contents


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.

Disclosure Regarding Forward-Looking Statements

This report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, or the Securities Act, and Section 21E of the Securities Exchange Act of 1934, as amended, or the Exchange Act. All statements other than statements of historical facts included in this report that address activities, events or developments that we expect or anticipate will or may occur in the future, including such things as estimated future net revenues from oil and natural gas reserves and the present value thereof, future capital expenditures (including the amount and nature thereof), 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 statements are based on certain assumptions and analysis made by us in light of our experience and our perception of historical trends, current conditions and expected future developments as well as other factors we believe are appropriate in the circumstances. However, whether actual results and developments will conform with our expectations and predictions is subject to a number of risks and uncertainties, general economic, market or business conditions; the opportunities (or lack thereof) that may be presented to and pursued by us; competitive actions by other oil and natural gas companies; our ability to identify, complete and integrate acquisitions of properties (including those recently acquired from Vitruvian II Woodford, LLC) and businesses; changes in laws or regulations; adverse weather conditions and natural disasters such as hurricanes and other factors, including those listed in the “Risk Factors” section of our most recent Annual Report on Form 10-K, Quarterly Reports on Form 10-Q or any other filings we make with the SEC, many of which are beyond our control. Consequently, all of the forward-looking statements made in this report are qualified by these cautionary statements, and we cannot assure you that the actual results or developments anticipated by us will be realized or, even if realized, that they will have the expected consequences to or effects on us, our business or operations. We have no intention, and disclaim any obligation, to update or revise any forward-looking statements, whether as a result of new information, future results or otherwise.

Overview

We are an independent oil and natural gas exploration and production company focused on the exploration, exploitation, acquisition and production of natural gas, crude oil and natural gas liquids in the United States. Our corporate strategy is to internally identify prospects, acquire lands encompassing those prospects and evaluate those prospects using subsurface geology and geophysical data and exploratory drilling. Using this strategy, we have developed an oil and natural gas portfolio of proved reserves, as well as development and exploratory drilling opportunities on high potential conventional and unconventional oil and natural gas prospects. Our principal properties are located in the Utica Shale primarily in Eastern Ohio and the SCOOP Woodford and SCOOP Springer plays in Oklahoma. In addition, among other interests, we hold an acreage position along the Louisiana Gulf Coast in the West Cote Blanche Bay, or WCBB, and Hackberry fields, an acreage position in the Alberta oil sands in Canada through our interest in Grizzly Oil Sands ULC, or Grizzly, and an approximate 24.2% equity interest in Mammoth Energy Services, Inc., or Mammoth Energy, an oil field services company listed on the NASDAQ Global Select Market (TUSK). We seek to achieve reserve growth and increase our cash flow through our annual drilling programs.

2017 Operational Highlights


•	Production increased 21% to 76,461 net million cubic feet of natural gas equivalent, or MMcfe, for the three months ended March 31, 2017 from 62,993 MMcfe for the three months ended March 31, 2016. Our net daily production mix for the 2017 period was comprised of approximately 87% of natural gas, 9% of natural gas liquids, or NGLs, and 4% of oil.

•

On February 17, 2017, we, through our wholly-owned subsidiary Gulfport MidCon LLC, or Gulfport MidCon, (formerly known as SCOOP Acquisition Company, LLC), completed our acquisition, which we refer to as the Acquisition, of certain assets from Vitruvian II Woodford, LLC, an unrelated third-party seller, for a total 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

Table of Contents

placed in an indemnity escrow). The Acquisition included approximately 46,000 net surface acres with multiple producing zones, including the Woodford and Springer formations in the South Central Oklahoma Oil Province, or SCOOP, resource play, in Grady, Stephens and Garvin Counties, Oklahoma.

•

During the three months ended March 31, 2017, we spud 26 gross (23.5 net) wells in the Utica Shale, participated in an additional six gross (2.0 net) wells that were drilled by other operators on our Utica Shale acreage and spud three gross and net wells and recompleted 39 gross and net wells on our Louisiana acreage. In addition, during the period from January 1, 2017 to March 31, 2017, five gross (4.2 net) wells were spud in the SCOOP, of which one gross well was spud by Gulfport after the closing of the acquisition on February 17, 2017. We also participated in an additional ten gross (0.5 net) wells that were drilled by other operators on our SCOOP acreage. Of the 34 new wells spud at March 31, 2017, 23 were in various stages of completion and 11 were being drilled. In addition, we turned-to-sales five gross (4.7 net) operated wells and 12 gross (0.8 net) non-operated wells during the three months ended March 31, 2017.


•	During the three months ended March 31, 2017, we reduced our unit lease operating expense by 5% to $0.25 per Mcfe from $0.26 per Mcfe during the three months ended March 31, 2016.


•	During the three months ended March 31, 2017, we decreased our unit general and administrative expense by 2% to $0.16 per Mcfe from $0.17 per Mcfe during the three months ended March 31, 2016.

Table of Contents

2017 Production and Drilling Activity

During the three months ended March 31, 2017, our total net production was 66,283,945 cubic feet, or Mcf, of natural gas, 513,654 barrels of oil and 49,667,157 gallons of NGLs for a total of 76,461 MMcfe, as compared to 53,306,532 Mcf of natural gas, 601,844 barrels of oil and 42,527,287 gallons of NGLs, or 62,993 MMcfe, for the three months ended March 31, 2016. Our total net production averaged approximately 849.6 MMcfe per day during the three months ended March 31, 2017 as compared to 692.2 MMcfe per day during the same period in 2016. The 21% increase in production is largely the result of the continuing development of our Utica Shale acreage and production attributable to the Acquisition.

Utica Shale. As of April 28, 2017, we held leasehold interests in approximately 230,000 gross (211,000 net) acres in the Utica Shale. From January 1, 2017 through April 28, 2017, we spud 33 gross (30.5 net) wells, of which 27 were in various stages of completion and six were being drilled at April 28, 2017. In addition, six gross (2.0 net) wells were drilled by other operators on our Utica Shale acreage during the three months ended March 31, 2017.

As of April 28, 2017, we had six rigs under contract on our Utica Shale acreage. We currently intend to spud 87 to 97 gross (67 to 74 net) wells, and commence sales from 72 to 80 gross (61 to 67 net) wells, on our Utica Shale acreage in 2017.

Aggregate net production from our Utica Shale acreage during the three months ended March 31, 2017 was approximately 67,559 MMcfe, or an average of 750.7 MMcfe per day, of which 91% was from natural gas and 9% was from oil and NGLs. Our average daily production during three months ended March 31, 2017 decreased approximately 2% from the fourth quarter of 2016 primarily due to the timing and number of wells turned-to-sales during the first quarter of 2017.

SCOOP. As of April 28, 2017, we held leasehold interests in approximately 46,400 net acres in the SCOOP. From January 1, 2017 through April 28, 2017, five gross (4.2 net) wells were spud, of which four were being drilled and one was waiting on completion at April 28, 2017. In addition, ten gross (0.5 net) wells were drilled by other operators on our SCOOP acreage during the period from February 17, 2017 to March 31, 2017.

As of April 28, 2017, we had four rigs under contract on our SCOOP acreage. We currently intend to spud 19 to 21 gross (16 to 18 net) wells, and commence sales from 17 to 19 gross (14 to 16 net) wells, on our SCOOP acreage in 2017.

Aggregate net production from our SCOOP acreage during the period from the closing date of February 17, 2017 to March 31, 2017 was approximately 7,398 MMcfe, of which 69% was from natural gas and 31% was from oil and NGLs.

WCBB. From January 1, 2017 through April 28, 2017, we spud no new wells and recompleted 37 wells. Aggregate net production from the WCBB field during the three months ended March 31, 2017 was approximately 1,099 MMcfe, or an average of 12.2 MMcfe per day, 100% of which was from oil.

East Hackberry Field. From January 1, 2017 through April 28, 2017, we spud five new wells and recompleted 13 wells. Aggregate net production from the East Hackberry field during the three months ended March 31, 2017 was approximately 274 MMcfe, or an average of 3.0 MMcfe per day, of which 99% was from oil and 1% was from natural gas.

West Hackberry Field. From January 1, 2017 through April 28, 2017, we did not spud any wells in our West Hackberry field. Aggregate net production from the West Hackberry field during the three months ended March 31, 2017 was approximately 43.0 MMcfe, or an average of 477.9 Mcfe per day, of which 98% was from oil and 2% was from natural gas.

Niobrara Formation. As of March 31, 2017, we held leases for approximately 4,000 net acres in the Niobrara Formation in Northwestern Colorado. From January 1, 2017 through April 28, 2017, there were no wells spud on our Niobrara Formation acreage. Aggregate net production was approximately 18.0 MMcfe, or an average of 200.4 Mcfe per day during the three months ended March 31, 2017, 100% of which was from oil.

Bakken. As of March 31, 2017, we held approximately 778 net acres in the Bakken Formation of Western North Dakota and Eastern Montana with interests in 18 wells and overriding royalty interests in certain existing and future wells. Aggregate net production from this acreage during the three months ended March 31, 2017 was approximately 69.4 MMcfe, or an average of 770.6 Mcfe per day, of which 81% was from oil, 12% was from natural gas and 7% was from NGLs.

Table of Contents

2017 Update Regarding Our Equity Investments

Mammoth Energy. In March 2017, Mammoth Energy entered into definitive agreements to acquire Sturgeon (which owns Taylor Frac, LLC, Taylor Real Estate Investments, LLC and South River Road, LLC), Stingray Energy and Stingray Cementing from the owners of such companies, including Gulfport, for an aggregate of 7.0 million shares of Mammoth Energy’s common stock. Mammoth Energy anticipates the transactions will close in the second quarter of 2017, subject to agreed closing conditions. Upon closing, we will receive approximately 2.0 million shares of Mammoth Energy’s common stock and hold approximately 25.1% of Mammoth Energy’s outstanding common stock.

Critical Accounting Policies and Estimates

Our discussion and analysis of our financial condition and results of operations are based upon consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America, or GAAP. The preparation of these consolidated financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. We have identified certain of these policies as being of particular importance to the portrayal of our financial position and results of operations and which require the application of significant judgment by our management. We analyze our estimates including those related to oil and natural gas properties, revenue recognition, income taxes and commitments and contingencies, and base our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions. We believe the following critical accounting policies affect our more significant judgments and estimates used in the preparation of our consolidated financial statements:

Oil and Natural Gas Properties. We use the full cost method of accounting for oil and natural gas operations. Accordingly, all costs, including non-productive costs and certain general and administrative costs directly associated with acquisition, exploration and development of oil and natural gas properties, are capitalized. Companies that use the full cost method of accounting for oil and gas properties are required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the oil and gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes or the cost center ceiling. The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on the 12-month unweighted average of the first-day-of-the-month price for the prior twelve months, adjusted for any contract provisions or financial derivatives, if any, that hedge our oil and natural gas revenue, and excluding the estimated abandonment costs for properties with asset retirement obligations recorded on the balance sheet, (b) the cost of properties not being amortized, if any, and (c) the lower of cost or market value of unproved properties included in the cost being amortized, including related deferred taxes for differences between the book and tax basis of the oil and natural gas properties. If the net book value, including related deferred taxes, exceeds the ceiling, an impairment or noncash writedown is required. Such capitalized costs, including the estimated future development costs and site remediation costs of proved undeveloped properties are depleted by an equivalent units-of-production method, converting gas to barrels at the ratio of six Mcf of gas to one barrel of oil. No gain or loss is recognized upon the disposal of oil and natural gas properties, unless such dispositions significantly alter the relationship between capitalized costs and proven oil and natural gas reserves. Oil and natural gas properties not subject to amortization consist of the cost of undeveloped leaseholds and totaled approximately $3.1 billion at March 31, 2017 and $1.6 billion at December 31, 2016. These costs are reviewed quarterly by management for impairment, with the impairment provision included in the cost of oil and natural gas properties subject to amortization. Factors considered by management in its impairment assessment include our drilling results and those of other operators, the terms of oil and natural gas leases not held by production and available funds for exploration and development.

Ceiling Test. Companies that use the full cost method of accounting for oil and gas properties are required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the oil and gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes or the cost center ceiling (as defined in the preceding paragraph). If the net book value, including related deferred taxes, exceeds the ceiling, an impairment or noncash writedown is required. Ceiling test impairment can give us a significant loss for a particular period; however, future depletion expense would be reduced. A decline in oil and gas prices may result in an impairment of oil and gas properties. For instance, as a result of the decline in commodity prices in 2015 and 2016 and subsequent reduction in our proved reserves, we recognized a ceiling test impairment of $715.5 million for the year ended December 31, 2016. At March 31, 2017, the calculated ceiling was greater than the net book value of our oil and natural gas properties, thus no ceiling test impairment was required for the three months ended March 31, 2017. If prices of oil, natural gas and natural gas liquids decline in the future, we may be required to further write down the value of our oil and natural gas properties, which could negatively affect our results of operations.

Table of Contents

Asset Retirement Obligations. We have obligations to remove equipment and restore land at the end of oil and gas production operations. Our removal and restoration obligations are primarily associated with plugging and abandoning wells and associated production facilities.

We account for abandonment and restoration liabilities under FASB ASC 410 which requires us to record a liability equal to the fair value of the estimated cost to retire an asset. The asset retirement liability is recorded in the period in which the obligation meets the definition of a liability, which is generally when the asset is placed into service. When the liability is initially recorded, we increase the carrying amount of the related long-lived asset by an amount equal to the original liability. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related long-lived asset. Upon settlement of the liability or the sale of the well, the liability is reversed. These liability amounts may change because of changes in asset lives, estimated costs of abandonment or legal or statutory remediation requirements.

The fair value of the liability associated with these retirement obligations is determined using significant assumptions, including current estimates of the plugging and abandonment or retirement, annual inflation of these costs, the productive life of the asset and our risk adjusted cost to settle such obligations discounted using our credit adjusted risk free interest rate. Changes in any of these assumptions can result in significant revisions to the estimated asset retirement obligation. Revisions to the asset retirement obligation are recorded with an offsetting change to the carrying amount of the related long-lived asset, resulting in prospective changes to depreciation, depletion and amortization expense and accretion of discount. Because of the subjectivity of assumptions and the relatively long life of most of our oil and natural gas assets, the costs to ultimately retire these assets may vary significantly from previous estimates.

Oil and Gas Reserve Quantities. Our estimate of proved reserves is based on the quantities of oil and natural gas that engineering and geological analysis demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. Netherland, Sewell & Associates, Inc. and to a lesser extent our personnel have prepared reserve reports of our reserve estimates at December 31, 2016 on a well-by-well basis for our properties.

Reserves and their relation to estimated future net cash flows impact our depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. Our reserve estimates and the projected cash flows derived from these reserve estimates have been prepared in accordance with the guidelines of the Securities and Exchange Commission, or SEC. The accuracy of our reserve estimates is a function of many factors including the following:


•	the quality and quantity of available data;


•	the interpretation of that data;


•	the accuracy of various mandated economic assumptions; and


•	the judgments of the individuals preparing the estimates.

Our proved reserve estimates are a function of many assumptions, all of which could deviate significantly from actual results. Therefore, reserve estimates may materially vary from the ultimate quantities of oil and natural gas eventually recovered.

Income Taxes. We use the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (1) temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities and (2) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income during the period the rate change is enacted. Deferred tax assets are recognized in the year in which realization becomes determinable. Periodically, management performs a forecast of its taxable income to determine whether it is more likely than not that a valuation allowance is needed, looking at both positive and negative factors. A valuation allowance for our deferred tax assets is established, if in management’s opinion, it is more likely than not that some portion will not be realized. At March 31, 2017, a valuation allowance of $595.7 million had been established against the net deferred tax asset, with the exception of certain state net operating losses, or NOL, and alternative minimum tax, or AMT, credits that we expect to be able to utilize with NOL carrybacks and tax planning in the amount of $4.7 million.

Table of Contents

Revenue Recognition. We derive almost all of our revenue from the sale of crude oil and natural gas produced from our oil and natural gas properties. Revenue is recorded in the month the product is delivered to the purchaser. We receive payment on substantially all of these sales from one to three months after delivery. At the end of each month, we estimate the amount of production delivered to purchasers that month and the price we will receive. Variances between our estimated revenue and actual payment received for all prior months are recorded at the end of the quarter after payment is received. Historically, our actual payments have not significantly deviated from our accruals.

Investments—Equity Method. Investments in entities greater than 20% and less than 50% and/or investments in which we have significant influence are accounted for under the equity method. Under the equity method, our share of investees’ earnings or loss is recognized in the statement of operations.

We review our investments to determine if a loss in value which is other than a temporary decline has occurred. If such loss has occurred, we recognize an impairment provision. For the three months ended March 31, 2016, we recognized an impairment loss related to our investment in Grizzly of approximately $23.1 million.

Commitments and Contingencies. Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. We are involved in certain litigation for which the outcome is uncertain. Changes in the certainty and the ability to reasonably estimate a loss amount, if any, may result in the recognition and subsequent payment of legal liabilities.

Derivative Instruments and Hedging Activities. We seek to reduce our exposure to unfavorable changes in oil, natural gas 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. We follow the provisions of FASB ASC 815, “Derivatives and Hedging,” as amended. It requires that all derivative instruments be recognized as assets or liabilities in the balance sheet, measured at fair value. We estimate the fair value of all derivative instruments using industry-standard models that considered various assumptions including current market and contractual prices for the underlying instruments, implied volatility, time value and nonperformance risk, as well as other relevant economic measures.

The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and the resulting designation. While we have historically designated derivative instruments as accounting hedges, effective January 1, 2015, we discontinued hedge accounting prospectively. Our current commodity derivative instruments are not designated as hedges for accounting purposes. Accordingly, the changes in fair value are recognized in the consolidated statements of operations in the period of change. Gains and losses on derivatives are included in cash flows from operating activities.

See Item 3. “Quantitative and Qualitative Disclosures About Market Risk” for a summary of our derivative instruments in place as of March 31, 2017.

RESULTS OF OPERATIONS

Comparison of the Three Months Ended March 31, 2017 and 2016

We reported net income of $154.5 million for the three months ended March 31, 2017 as compared to a net loss of $242.3 million for the three months ended March 31, 2016. This $396.7 million period-to-period increase was due primarily to (a) a $176.0 million increase in natural gas, oil and NGL revenues, (b) no impairment charge for the three months ended March 31, 2017 as compared to a $219.0 million impairment of oil and gas properties for the three months ended March 31, 2016 and (c) a $25.8 million decrease in loss from equity method investments, partially offset by a $10.2 million increase in midstream gathering and processing expenses, a $7.5 million increase in interest expense and a $2.6 million increase in lease operating expenses for the three months ended March 31, 2017 as compared to the three months ended March 31, 2016.

Oil and Gas Revenues. For the three months ended March 31, 2017, we reported natural gas, oil and NGL revenues of $333.0 million as compared to oil and natural gas revenues of $157.0 million during the same period in 2016. This $176.0 million, or 112%, increase in revenues was primarily attributable to the following:


•	A $41.8 million increase in natural gas, oil and NGL sales due to a favorable change in gains and losses from derivative instruments. Of the total change, $114.4 million was due to favorable changes in the fair value of our open derivative positions in each period, offset by $72.6 million unfavorable change in settlements related to our derivative positions.

Table of Contents


•	A $103.7 million increase in gas sales without the impact of derivatives due to a 93% increase in natural gas market prices and a 24% increase in gas sales volumes.


•	An $8.6 million increase in oil and condensate sales without the impact of derivatives due to an 81% increase in oil and condensate market prices, partially offset by a 15% decrease in oil and condensate sales volumes.


•	A $21.9 million increase in natural gas liquids sales without the impact of derivatives due to a 187% increase in natural gas liquids market prices and a 17% increase in natural gas liquids sales volumes.

The following table summarizes our oil and natural gas production and related pricing for the three months ended March 31, 2017, as compared to such data for the three months ended March 31, 2016:

Table of Contents



	Three months ended March 31,
	2017			2016
	($ In thousands)
Gas sales
Gas production volumes (MMcf)	66,284			53,307

Total gas sales	$	177,837		$	74,094

Gas sales without the impact of derivatives ($/Mcf)	$	2.68		$	1.39
Impact from settled derivatives ($/Mcf)	$	(0.11	)	$	1.10
Average gas sales price, including settled derivatives ($/Mcf)	$	2.57		$	2.49

Oil and condensate sales
Oil and condensate production volumes (MBbls)	514			602

Total oil and condensate sales	$	24,411		$	15,839

Oil and condensate sales without the impact of derivatives ($/Bbl)	$	47.52		$	26.32
Impact from settled derivatives ($/Bbl)	$	0.16		$	10.54
Average oil and condensate sales price, including settled derivatives ($/Bbl)	$	47.68		$	36.86

Natural gas liquids sales
Natural gas liquids production volumes (MGal)	49,667			42,527

Total natural gas liquids sales	$	31,179		$	9,293

Natural gas liquids sales without the impact of derivatives ($/Gal)	$	0.63		$	0.22
Impact from settled derivatives ($/Gal)	$	—		$	0.01
Average natural gas liquids sales price, including settled derivatives ($/Gal)	$	0.63		$	0.23

Gas, oil and condensate and natural gas liquids sales
Gas equivalents (MMcfe)	76,461			62,993

Total gas, oil and condensate and natural gas liquids sales	$	233,427		$	99,226

Gas, oil and condensate and natural gas liquids sales without the impact of derivatives ($/Mcfe)	$	3.05		$	1.58
Impact from settled derivatives ($/Mcfe)	$	(0.09	)	$	1.03
Average gas, oil and condensate and natural gas liquids sales price, including settled derivatives ($/Mcfe)	$	2.96		$	2.61

Production Costs:
Average production costs (per Mcfe)	$	0.25		$	0.26
Average production taxes and midstream costs (per Mcfe)	$	0.68		$	0.65
Total production and midstream costs and production taxes (per Mcfe)	$	0.93		$	0.91

Table of Contents

Lease Operating Expenses. Lease operating expenses, or LOE, not including production taxes increased to $19.3 million for the three months ended March 31, 2017 from $16.7 million for the three months ended March 31, 2016. This $2.6 million increase was primarily the result of an increase in expenses related to compression, location and facility repairs and maintenance, workover expenses, overhead and surface rentals, partially offset by decreases in ad valorem taxes and disposal costs. However, due to increased efficiencies and a 21% increase in our production volumes for the three months ended March 31, 2017 as compared to the three months ended March 31, 2016, our per unit LOE decreased by 5% from $0.26 per Mcfe to $0.25 per Mcfe.

Production Taxes. Production taxes increased $0.8 million to $3.9 million for the three months ended March 31, 2017 from $3.1 million for the three months ended March 31, 2016. This increase was related to an increase in realized prices and production volumes.

Midstream Gathering and Processing Expenses. Midstream gathering and processing expenses increased $10.2 million to $47.9 million for the three months ended March 31, 2017 from $37.7 million for the same period in 2016. This increase was primarily attributable to midstream expenses related to our increased production volumes in the Utica Shale resulting from our 2016 and 2017 drilling activities, as well as production volumes resulting from our recent SCOOP acquisition.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization, or DD&A, expense increased to $66.0 million for the three months ended March 31, 2017, and consisted of $64.5 million in depletion of oil and natural gas properties and $1.5 million in depreciation of other property and equipment, as compared to total DD&A expense of $65.5 million for the three months ended March 31, 2016. This increase was due to an increase in our full cost pool as a result of our SCOOP acquisition and an increase in our production, partially offset by an increase in our total proved reserves volume used to calculate our total DD&A expense.

General and Administrative Expenses. Net general and administrative expenses increased to $12.6 million for the three months ended March 31, 2017 from $10.6 million for the three months ended March 31, 2016. This $2.0 million increase was due to increases in salaries and benefits and consulting fees, partially offset by a decrease in employee stock compensation expense and bank service charges. However, during the three months ended March 31, 2017, we decreased our unit general and administrative expense by 2% to $0.16 per Mcfe from $0.17 per Mcfe during the three months ended March 31, 2016.

Accretion Expense. Accretion expense remained relatively flat at $0.3 million and $0.2 million for the three months ended March 31, 2017 and 2016, respectively.

Interest Expense. Interest expense increased to $23.5 million for the three months ended March 31, 2017 from $16.0 million for the three months ended March 31, 2016 due primarily to the issuance of $600.0 million of the 2025 Notes in December 2016. In addition, total weighted average debt outstanding under our revolving credit facility was $19.6 million for the three months ended March 31, 2017 as compared to no debt outstanding under such facility for the same period in 2016. As of March 31, 2017, amounts borrowed under our revolving credit facility bore interest at the Eurodollar rate of 3.18%. In addition, we capitalized approximately $3.1 million and $1.6 million in interest expense to undeveloped oil and natural gas properties during the three months ended March 31, 2017 and 2016, respectively. This increase in capitalized interest in the 2017 period was primarily due to the SCOOP Acquisition.

Income Taxes. As of March 31, 2017, we had a federal net operating loss carryforward of approximately $550.5 million, in addition to numerous temporary differences, which gave rise to a net deferred tax asset. Periodically, management performs a forecast of our taxable income to determine whether it is more likely than not that a valuation allowance is needed, looking at both positive and negative factors. A valuation allowance for our deferred tax assets is established if, in management’s opinion, it is more likely than not that some portion will not be realized. At March 31, 2017, a valuation allowance of $595.7 million was established against the net deferred tax asset, with the exception of certain state NOLs and AMT credits that we expect to be able to utilize with net operating loss carrybacks and tax planning in the amount of $4.7 million.

Liquidity and Capital Resources

Overview.

Historically, our primary sources of funds have been cash flow from our producing oil and natural gas properties, borrowings under our credit facility and issuances of equity and debt securities. Our ability to access any of these sources of funds can be significantly impacted by decreases in oil and natural gas prices or oil and natural gas production.

Table of Contents

Net cash flow provided by operating activities was $142.6 million for the three months ended March 31, 2017 as compared to net cash flow provided by operating activities of $83.8 million for the same period in 2016. This increase was primarily the result of an increase in cash receipts from our oil and natural gas purchasers due to a 37% increase in net revenues after giving effect to settled derivative instruments, partially offset by an increase in our operating expenses.

Net cash used in investing activities for the three months ended March 31, 2017 was $1,347.7 million as compared to $157.5 million for the same period in 2016. During the three months ended March 31, 2017, we spent $181.8 million in additions to oil and natural gas properties, of which $90.4 million was spent on our 2017 drilling, completion and recompletion activities, $50.7 million was spent on expenses attributable to wells spud, completed and recompleted during 2016, $0.1 million was spent on facility enhancements, $12.1 million was spent on lease related costs, primarily the acquisition of leases in the Utica Shale and $6.9 million was spent on seismic, with the remainder attributable mainly to future location development and capitalized general and administrative expenses. We also spent $1.3 billion on our SCOOP acquisition. In addition, $0.7 million was invested in Grizzly and $10.0 million was invested in Strike Force during the three months ended March 31, 2017. We did not make any investments in our other equity investments during the three months ended March 31, 2017.

Net cash provided by financing activities for the three months ended March 31, 2017 was $31.6 million as compared to $415.2 million for the same period in 2016. The 2017 amount provided by financing activities is primarily attributable to borrowings on our revolving credit facility. The 2016 amount provided by financing activities is primarily attributable to the net proceeds of approximately $411.9 million from our March 2016 equity offering.

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 certain lenders from time to time party thereto. The credit agreement provides for a maximum facility amount of $1.5 billion and matures on December 13, 2021. As of March 31, 2017, we had a borrowing base of $700.0 million and $40.0 million in borrowings outstanding, and total funds available for borrowing under our revolving credit facility, after giving effect to an aggregate of $238.7 million of outstanding letters of credit, were $421.3 million. This facility is secured by substantially all of our assets. Our wholly-owned subsidiaries guarantee our obligations under our revolving credit facility.

On May 4, 2017, the credit facility was further amended to increase the borrowing base from $700.0 million to $1.0 billion, adjust certain of our investment baskets and add five additional banks to the syndicate.

Advances under our revolving credit facility may be in the form of either base rate loans or eurodollar loans. The interest rate for base rate loans is equal to (1) the applicable rate, which ranges from 1.00% to 2.00%, 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 2.00% to 3.00%, plus (2) the London interbank offered rate that appears on pages LIBOR01 or LIBOR02 of the Reuters screen that displays such rate for deposits in U.S. dollars, or, if such rate is not available, the rate as administered by ICE Benchmark Administration (or any other person that takes over administration of such rate) per annum equal to the offered rate on such other page or other service that displays an average London interbank offered rate as administered by ICE Benchmark Administration (or any other person that takes over the administration of such rate) for deposits in U.S. dollars, or, if such rate is not available, the average quotations for three major New York money center banks of whom the agent shall inquire as the “London Interbank Offered Rate” for deposits in U.S. dollars. As of March 31, 2017, amounts borrowed under our revolving credit facility bore interest at the Eurodollar rate of 3.18%.

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; make investments; make fundamental changes; enter into swap contracts and forward sales contracts; dispose of assets; change the nature of their business; and enter into transactions with their affiliates. The negative covenants are subject to certain exceptions as specified in our revolving credit facility. Our revolving credit facility also contains certain affirmative covenants, including, but not limited to the following financial covenants: (1) the ratio of net funded debt to EBITDAX (net income, excluding (i) any non-cash revenue or expense associated with swap contracts resulting from ASC 815 and (ii) any cash or non-cash revenue or expense attributable to minority investment plus without duplication and, in 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

Table of Contents

such period, (d) all other non-cash charges, (e) exploration costs deducted in determining net income under successful efforts accounting, (f) actual cash distributions received from minority investments, (g) to the extent actually reimbursed by insurance, expenses with respect to liability on casualty events or business interruption, and (h) all reasonable transaction expenses related to dispositions and acquisitions of assets, investments and debt and equity offerings (provided that expenses related to any unsuccessful dispositions will be limited to $3.0 million in the aggregate) for a twelve-month period may not be greater than 4.00 to 1.00; and (2) the ratio of EBITDAX to interest expense for a twelve-month period may not be less than 3.00 to 1.00. We were in compliance with these financial covenants at March 31, 2017.

Senior Notes.

In October 2012, December 2012 and August 2014, we issued an aggregate of $600.0 million in principal amount of our 7.75% senior notes due 2020 which were issued under an indenture among us, our subsidiary guarantors and Wells Fargo Bank, National Association, as the trustee, and are referred to collectively as the 2020 Notes. In October 2016, we repurchased (in a cash tender offer) or redeemed all of the 2020 Notes, of which $600.0 million in aggregate principal amount was then outstanding, with the net proceeds from the issuance of our 6.000% Senior Notes due 2024, which are discussed below and are referred to herein as the 2024 Notes, and cash on hand, and the indenture governing the 2020 Notes was fully satisfied and discharged.

In April 2015, we issued an aggregate of $350.0 million in principal amount of our 6.625% senior notes due 2023 under a new indenture, dated as of April 21, 2015, among us, our subsidiary guarantors and Wells Fargo Bank, N.A., as trustee. Interest on these senior notes, which we refer to as the 2023 Notes, accrues at a rate of 6.625% per annum on the outstanding principal amount thereof from April 21, 2015, payable semi-annually on May 1 and November 1 of each year, commencing on November 1, 2015. The 2023 Notes will mature on May 1, 2023.

On October 14, 2016, we issued 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 us, the subsidiary guarantors party thereto and the senior note 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. Under this 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. We 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 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.

On December 21, 2016, we issued $600.0 million in aggregate principal amount of 2025 Notes. The 2025 Notes were issued under an indenture, dated as of December 21, 2016, among us, the subsidiary guarantors party thereto and the senior note 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 this 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. We received approximately $584.7 million in net proceeds from the offering of the 2025 Notes, which we used, together with the net proceeds from our December 2016 offering of common stock and cash on hand, to fund the cash portion of the purchase price for the SCOOP acquisition.

All of our existing and future restricted subsidiaries that guarantee our secured revolving credit facility or certain other debt guarantee the 2023 Notes, 2024 Notes and 2025 Notes, provided, however, that the 2023 Notes, 2024 Notes and 2025 Notes are not guaranteed by Grizzly Holdings, Inc. and will not be guaranteed by any of our future unrestricted subsidiaries. The guarantees rank equally in the right of payment with all of the senior indebtedness of the subsidiary guarantors and senior in the right of payment to any future subordinated indebtedness of the subsidiary guarantors. The 2023 Notes, 2024 Notes and 2025 Notes and the guarantees are effectively subordinated to all of our and the subsidiary guarantors’ secured indebtedness (including all borrowings and other obligations under our amended and restated credit agreement) to the extent of the value of the collateral securing such indebtedness, and structurally subordinated to all indebtedness and other liabilities of any of our subsidiaries that do not guarantee the 2023 Notes, 2024 Notes and 2025 Notes.

If we experience a change of control (as defined in the senior note indentures relating to the 2023 Notes, 2024 Notes and 2025 Notes), we will be required to make an offer to repurchase the 2023 Notes, 2024 Notes and 2025 Notes and at a price equal to 101% of the principal amount thereof, plus accrued and unpaid interest, if any, to the date of repurchase. If we sell certain assets and fail to use the proceeds in a manner specified in our senior note indentures, we will be required to use the

Table of Contents

remaining proceeds to make an offer to repurchase the 2023 Notes, 2024 Notes and 2025 Notes at a price equal to 100% of the principal amount thereof, plus accrued and unpaid interest, if any, to the date of repurchase. The senior note indentures relating to the 2023 Notes, 2024 Notes and 2025 Notes contain certain covenants that, subject to certain exceptions and qualifications, among other things, limit our ability and the ability of our restricted subsidiaries to incur or guarantee additional indebtedness, make certain investments, declare or pay dividends or make distributions on capital stock, prepay subordinated indebtedness, sell assets including capital stock of restricted subsidiaries, agree to payment restrictions affecting our restricted subsidiaries, consolidate, merge, sell or otherwise dispose of all or substantially all of our assets, enter into transactions with affiliates, incur liens, engage in business other than the oil and gas business and designate certain of our subsidiaries as unrestricted subsidiaries. Under the indenture relating to the 2023 Notes, 2024 Notes and 2025 Notes, certain of these covenants are subject to termination upon the occurrence of certain events, including in the event the 2023 Notes, 2024 Notes and 2025 Notes are ranked as “investment grade.”

In connection with the offerings of the 2024 Notes and the 2025 Notes, we and our subsidiary guarantors entered into registration rights agreements with the representatives of the initial purchasers pursuant to which we agreed to file a registration statement with respect to an offer to exchange the 2024 Notes and the 2025 Notes for new issues of substantially identical debt securities registered under the Securities Act.

Construction Loan.

On June 4, 2015, we entered into a construction loan agreement, or the construction loan, with InterBank for the construction of our new corporate headquarters in Oklahoma City, which was substantially completed in December 2016. The construction loan allows for maximum principal borrowings of $24.5 million and required us to fund 30% of the cost of the construction before any funds could be drawn, which occurred in January 2016. Interest accrues daily on the outstanding principal balance at a fixed rate of 4.50% per annum and is payable on the last day of the month through May 31, 2017. Monthly interest and principal payments are due beginning June 30, 2017, with the final payment due June 4, 2025. As of March 31, 2017, the total borrowings under the construction loan were approximately $23.7 million.

Capital Expenditures.

Our recent capital commitments have been primarily for the execution of our drilling programs, for acquisitions in the Utica Shale and our recent SCOOP acquisition, and for investments in entities that may provide services to facilitate the development of our acreage. Our strategy is to continue to (1) increase cash flow generated from our operations by undertaking new drilling, workover, sidetrack and recompletion projects to exploit our existing properties, subject to economic and industry conditions, (2) pursue acquisition and disposition opportunities and (3) pursue business integration opportunities.

Of our net reserves at December 31, 2016, 63.0% were categorized as proved undeveloped. Our proved reserves will generally decline as reserves are depleted, except to the extent that we conduct successful exploration or development activities or acquire properties containing proved developed reserves, or both. To realize reserves and increase production, we must continue our exploratory drilling, undertake other replacement activities or use third parties to accomplish those activities.

From January 1, 2017 through April 28, 2017, we spud 33 gross (30.5 net) wells in the Utica Shale. We currently expect to spud 87 to 97 gross (67 to 74 net) horizontal wells and commence sales from 72 to 80 gross (61 to 67 net) wells on our Utica Shale acreage during 2017. As of April 28, 2017, we had six operated horizontal rigs drilling in the play. We also anticipate an additional 30 to 34 gross (10 to 11 net) horizontal wells will be drilled, and sales commenced from 42 to 46 gross (nine to ten net) horizontal wells, on our Utica Shale acreage by other operators during 2017. We currently anticipate our 2017 capital expenditures to be $645.0 million to $690.0 million related to our operated and non-operated Utica Shale drilling and completion activity.

From January 1, 2017 through April 28, 2017, five gross (4.2 net) wells were spud in the SCOOP. We currently anticipate our 2017 capital expenditures to be $170.0 million to $190.0 million related to our operated and non-operated SCOOP drilling and completion activity. We currently expect to spud 19 to 21 gross (16 to 18 net) wells and commence sales from 17 to 19 gross (14 to 16 net) wells on the SCOOP acreage during 2017. As of April 28, 2017, we had four operated horizontal rigs drilling in the play. We also anticipate ten to 12 gross (one to two net) wells will be drilled, and sales commenced from ten to 12 gross (one to two net) wells on this SCOOP acreage by other operators during 2017.

In addition, we currently expect to spend an aggregate of $110.0 million to $120.0 million in 2017 for acreage expenses, primarily lease extensions, in the Utica Shale and SCOOP.

Table of Contents

From January 1, 2017 through April 28, 2017, we spud no new wells and recompleted 37 existing wells at our WCBB field. In our Hackberry fields, from January 1, 2017 through April 28, 2017, we spud five wells and recompleted 13 existing wells. We currently expect to spend $30.0 million to $35.0 million in 2017 to drill 12 to 15 gross and net wells and perform recompletion activities in Southern Louisiana.

From January 1, 2017 through April 28, 2017, no new wells were spud on our Niobrara Formation acreage. We do not currently anticipate any capital expenditures in the Niobrara Formation in 2017.

As of March 31, 2017, our net investment in Grizzly was approximately $46.8 million. We do not currently anticipate any material capital expenditures in 2017 related to Grizzly’s activities.

We had no capital expenditures during the three months ended March 31, 2017 related to our interests in Thailand. We do not currently anticipate any capital expenditures in Thailand in 2017.

In an effort to facilitate the development of our Utica Shale and other domestic acreage, we have invested in entities that can provide services that are required to support our operations. See Note 3 and Note 15 to our consolidated financial statements included elsewhere in this report for additional information regarding these other investments. During the three months ended March 31, 2017, we paid $10.0 million in cash calls related to Strike Force. We currently anticipate that we will also make $50.0 million to $60.0 million in cash contributions to Strike Force in 2017. We did not make any investments in any other of these entities during the three months ended March 31, 2017, and we do not currently anticipate any capital expenditures related to these entities in 2017.

During 2015 and 2016, we continued to focus on operational efficiencies in an effort to reduce our overall well costs and deliver better results in a more economical manner, particularly in light of the continued downturn in commodity prices. We have successfully leveraged the lower commodity price environment to gain access to higher-quality equipment and superior services for reduced costs, which has contributed to increased productivity. We have also renegotiated the contracts for our horizontal drilling rigs and locked in approximately 85% of our currently anticipated Utica Shale drilling and completion costs for 2017. This has allowed us to secure a base level of activity for 2017, hedge against expected increases in service costs and ensure access to quality equipment and experienced crews, all of which we expect to contribute to further efficiency gains.

Our total capital expenditures for 2017 are currently estimated to be in the range of $845.0 million to $915.0 million for drilling and completion expenditures, of which $238.1 million was spent as of March 31, 2017. In addition, we currently expect to spend $110.0 million to $120.0 million in 2017 for acreage expenses, primarily lease extensions in the Utica Shale, of which $12.1 million was spent as of March 31, 2017, and $50.0 million to $60.0 million to fund our investment in Strike Force, of which $10.0 million was spent as of March 31, 2017. Approximately 75% and 20% of our 2017 estimated capital expenditures are currently expected to be spent in the Utica Shale and in the SCOOP play in Oklahoma, respectively. The 2017 range of capital expenditures is higher than the $549.5 million spent in 2016, primarily due to the increase in current commodity prices and our expansion into the SCOOP play in Oklahoma.

We continually monitor market conditions and are prepared to adjust our drilling program if commodity prices dictate. Currently, we believe that our cash flow from operations, cash on hand and borrowings under our loan agreements will be sufficient to meet our normal recurring operating needs and capital requirements for the next twelve months. We believe that our strong liquidity position, hedge portfolio and conservative balance sheet position us well to react quickly to changing commodity prices and accelerate our activity within our Utica Basin and Mid-Continent operating areas, or to scale back our activity, as the market conditions warrant. Notwithstanding the foregoing, in the event commodity prices decline from current levels, our capital or other costs increase, our equity investments require additional contributions and/or we pursue additional equity method investments or acquisitions, we may be required to obtain additional funds which we would seek to do through traditional borrowings, offerings of debt or equity securities or other means, including the sale of assets. We regularly evaluate new acquisition opportunities. Needed capital may not be available to us on acceptable terms or at all. 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.

Commodity Price Risk

See Item 3. “Quantitative and Qualitative Disclosures about Market Risk” for information regarding our open fixed price swaps at March 31, 2017.

Table of Contents

Commitments

In connection with our acquisition in 1997 of the remaining 50% interest in the WCBB properties, we 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 our abandonment obligations to Chevron have been fulfilled. Beginning in 2009, we can access the trust for use in plugging and abandonment charges associated with the property. As of March 31, 2017, the plugging and abandonment trust totaled approximately $3.1 million. At March 31, 2017, we have plugged 513 wells at WCBB since we began our plugging program in 1997, which management believes fulfills our minimum plugging obligation.

Contractual and Commercial Obligations

We have various contractual obligations in the normal course of our operations and financing activities. There have been no material changes to our contractual obligations from those disclosed in our Annual Report on Form 10-K for the year ended December 31, 2016.

Off-balance Sheet Arrangements

We had no off-balance sheet arrangements as of March 31, 2017.

New Accounting Pronouncements

In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2014-09, Revenue from Contracts with Customers, which supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and most industry-specific guidance. The core principle of the new standard is for the recognition of revenue to depict the transfer of goods or services to customers in amounts that reflect the payment to which we expect to be entitled in exchange for those goods or services. The new standard will also result in enhanced revenue disclosures, provide guidance for transactions that were not previously addressed comprehensively and improve guidance for multiple-element arrangements. The ASU is effective for annual periods beginning after December 15, 2016, and interim periods within those years, using either a full or a modified retrospective application approach. In July 2015, the FASB decided to defer the effective date by one year (until 2018). We are evaluating the impact of this ASU on our consolidated financial statements, and based on the continuing evaluation of our revenue streams, this ASU is not expected to have a material impact on our net income. We are still in the process of determining whether or not we will use the retrospective method or the modified retrospective approach to implementation.

In February 2016, the FASB issued ASU No. 2016-02, Leases. The guidance requires the lessee to recognize most leases on the balance sheet thereby resulting in the recognition of lease assets and liability for those leases currently classified as operating leases. The accounting for lessors is largely unchanged. The guidance is effective for periods after December 15, 2018, with early adoption permitted. We are in the process of evaluating the impact of this guidance on our consolidated financial statements and related disclosures; however, based on our current operating leases, it is not expected to have a material impact.

In March 2016, the FASB issued ASU No. 2016-05, Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships. The guidance was issued to clarify that change in the counterparty to a derivative instrument that had been designated as the hedging instrument under Topic 815, does not require designation of that hedging relationship provided that all other hedge accounting criteria continue to be met. We adopted the standard as of January 1, 2017. There was no impact on our consolidated financial statements because all current derivative instruments are not designated for hedge accounting.

In March 2016, the FASB issued ASU No. 2016-09, Improvements to Employee Share-Based Payment Accounting. This guidance was intended to simplify the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities and classification on the statement of cash flows. We adopted the standard as of January 1, 2017. We elected to recognize forfeitures of awards as they occur. The adoption of this standard did not have a material impact on our consolidated financial statements.

Table of Contents

Recognition, and Topic 932, Extractive Activities--Oil and Gas. This amendment is effective upon adoption of Topic 606. We are in the process of evaluating the impact of this guidance on our consolidated financial statements.

In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments-Credit Losses: Measurement of Credit Losses on Financial Instruments. This ASU amends guidance on reporting credit losses for assets held at amortized cost basis and available for sale debt securities. For assets held at amortized cost basis, this ASU eliminates the probable initial recognition threshold in current GAAP and instead, requires an entity to reflect its current estimate of all expected credit losses. The amendments affect loans, debt securities, trade receivables, net investments in leases, off balance sheet credit exposure, reinsurance receivables and any other financial assets not excluded from the scope that have the contractual right to receive cash. We are currently evaluating the impact this standard will have on our financial statements and related disclosures and do not anticipate it to have a material affect.

In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments. This ASU provides guidance of eight specific cash flow issues. This ASU is effective for periods after December 15, 2017, with early adoption permitted. We are in the process of evaluating the impact of this guidance on our consolidated financial statements.

In December 2016, the FASB issued ASU No. 2016-20, Technical Corrections and Improvements to Topic 606, Revenue from Contracts with Customers. This guidance updates narrow aspects of the guidance issued in Update 2014-09. This amendment is effective for periods after December 15, 2017, with early adoption permitted. We in the process of evaluating the impact of this ASU on our consolidated financial statements.

In January 2017, the FASB issued ASU No. 2017-01, Clarifying the Definition of a Business. Under the current business combination guidance, there are three elements of a business: inputs, processes and outputs. The revised guidance adds an initial screen test to determine if substantially all of the fair value of the gross assets acquired is concentrated in a single asset or group of similar assets. If that screen is met, the set of assets is not a business. The new framework also specifies the minimum required inputs and processes necessary to be a business. This amendment is effective for periods after December 15, 2017, with early adoption permitted. We are in the process of evaluating the impact of this ASU on our consolidated financial statements.



ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Our revenues, operating results, profitability, future rate of growth and the carrying value of our oil and natural gas properties depend primarily upon the prevailing prices for oil and natural gas. Historically, oil and natural gas prices have been volatile and are subject to fluctuations in response to changes in supply and demand, market uncertainty and a variety of additional factors, including: worldwide and domestic supplies of oil and natural gas; the level of prices, and expectations about future prices, of oil and natural gas; the cost of exploring for, developing, producing and delivering oil and natural gas; the expected rates of declining current production; weather conditions, including hurricanes, that can affect oil and natural gas operations over a wide area; the level of consumer demand; the price and availability of alternative fuels; technical advances affecting energy consumption; risks associated with operating drilling rigs; the availability of pipeline capacity; the price and level of foreign imports; domestic and foreign governmental regulations and taxes; the ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls; political instability or armed conflict in oil and natural gas producing regions; and the overall economic environment.

These factors and the volatility of the energy markets make it extremely difficult to predict future oil and natural gas price movements with any certainty. During the past six years, the posted price for WTI, has ranged from a low of $26.05 per barrel, or Bbl, in February 2016 to a high of $113.39 per Bbl in April 2011. The Henry Hub spot market price of natural gas has ranged from a low of $1.61 per MMBtu in March 2016 to a high of $7.51 per MMBtu in January 2010. On April 28, 2017, the WTI posted price for crude oil was $49.33 per Bbl and the Henry Hub spot market price of natural gas was $3.20 per MMBtu. If the prices of oil and natural gas decline from current levels, our operations, financial condition and level of expenditures for the development of our oil and natural gas reserves may be materially and adversely affected. In addition, lower oil and natural gas prices may reduce the amount of oil and natural gas that we can produce economically. This may result in our having to make substantial downward adjustments to our estimated proved reserves. If this occurs or if our production estimates change or our exploration or development activities are curtailed, full cost accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties. Reductions in our reserves could also negatively impact the borrowing base under our revolving credit facility, which could further limit our liquidity and ability to conduct additional exploration and development activities.

Table of Contents

To mitigate the effects of commodity price fluctuations on our oil and natural gas production, we had the following open fixed price swap positions at March 31, 2017:



	Location	Daily Volume (MMBtu/day)	Weighted Average Price
Remaining 2017	NYMEX Henry Hub	576,845	$	3.18
2018	NYMEX Henry Hub	543,767	$	3.09
2019	NYMEX Henry Hub	9,863	$	3.27



	Location	Daily Volume (Bbls/day)	Weighted Average Price
Remaining 2017	ARGUS LLS	1,665	$	52.32
Remaining 2017	NYMEX WTI	4,113	$	54.97
2018	NYMEX WTI	899	$	55.31



	Location	Daily Volume (Bbls/day)	Weighted Average Price
Remaining 2017	Mont Belvieu C3	3,000	$	26.63
Remaining 2017	Mont Belvieu C5	250	$	49.14

We 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, we pay our counterparty an amount equal to the difference between the referenced settlement price and the price ceiling multiplied by the hedged contract volume.



	Location	Daily Volume (MMBtu/day)	Weighted Average Price
Remaining 2017	NYMEX Henry Hub	65,000	$	3.11
2018	NYMEX Henry Hub	80,000	$	3.29
2019	NYMEX Henry Hub	4,932	$	3.16

For a portion of the combined natural gas derivative instruments containing fixed price swaps and sold call options, the counterparty has an option to extend the original terms an additional twelve months for the period January 2018 through December 2018. The option to extend the terms expires in December 2017. If executed, we would have additional fixed price swaps for 30,000 MMBtu per day with the option to double at a weighted average price of $3.36 per MMBtu and additional short call options for 30,000 MMBtu per day with the option to double at a weighted average ceiling price of $3.36 per MMBtu.

In addition, we have entered into natural gas basis swap positions, which settle on the pricing index to basis differential of NGPL Mid-Continent to NYMEX Henry Hub natural gas price. As of March 31, 2017, we had the following natural gas basis swap positions for NGPL Mid-Continent.



	Location	Daily Volume (MMBtu/day)	Hedged Differential
Remaining 2017	NGPL Mid-Continent	50,000	$	(0.26	)
2018	NGPL Mid-Continent	12,329	$	(0.26	)

Under our 2017 contracts, we have hedged approximately 55% to 57% of our estimated 2017 production. Such arrangements may expose us to risk of financial loss in certain circumstances, including instances where production is less than expected or oil prices increase. At March 31, 2017, we had a net liability derivative position of $30.0 million as compared to a net asset derivative position of $178.8 million as of March 31, 2016, related to our fixed price swaps. Utilizing actual derivative contractual volumes, a 10% increase in underlying commodity prices would have reduced the fair value of these

Table of Contents

instruments by approximately $126.3 million, while a 10% decrease in underlying commodity prices would have increased the fair value of these instruments by approximately $126.3 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.

Our revolving amended and restated credit agreement is structured under floating rate terms, as advances under this facility may be in the form of either base rate loans or eurodollar loans. As such, our interest expense is sensitive to fluctuations in the prime rates in the U.S. or, if the eurodollar rates are elected, the eurodollar rates. At March 31, 2107, we had $40.0 million in borrowings outstanding under our credit facility which bore interest at the eurodollar rate of 3.18%. A 1.0% increase in the average interest rate for the three months ended March 31, 2017 would have resulted in an estimated $0.1 million increase in interest expense. As of March 31, 2017, we did not have any interest rate swaps to hedge our interest risks.



ITEM 4.	CONTROLS AND PROCEDURES

Evaluation of Disclosure Control and Procedures. Under the direction of our Chief Executive Officer and President and our Chief Financial Officer, we have established disclosure controls and procedures that are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. The disclosure controls and procedures are also intended to ensure that such information is accumulated and communicated to management, including our Chief Executive Officer and President and our Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosures.

As of March 31, 2017, an evaluation was performed under the supervision and with the participation of management, including our Chief Executive Officer and President and our Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Exchange Act. Based upon our evaluation, our Chief Executive Officer and President and our Chief Financial Officer have concluded that, as of March 31, 2017, our disclosure controls and procedures are effective.

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

Table of Contents

PART II



ITEM 1.	LEGAL PROCEEDINGS

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, we were 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 we 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 oil and gas field, 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.

We were 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 have filed a motion to remand, but both Courts have stayed further proceedings on the motions to remand pending a ruling from the United States Court of Appeals, Fifth Circuit on similar jurisdictional issues in another matter. In March 2017, the United States Court of Appeals, Fifth Circuit issued its ruling. Subsequently, the Vermillion Parish case and Cameron Parish case have both had their respective stays lifted. A hearing on the remand motions has been scheduled for May 17, 2017 in the Vermillion Parish case. No hearing on the remand motions has been set for the Cameron Parish case. The plaintiffs have granted all defendants an extension of time to file responsive pleadings to the Complaints until the District Courts rule on the motions to remand. We have not had the opportunity to evaluate the applicability of the allegations made in such complaints to our operations. Due to the early stages of these matters, management cannot determine the amount of loss, if any, that may result.

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



ITEM 1A.	RISK FACTORS

See risk factors previously disclosed in our Annual Report on Form 10-K for the year ended December 31, 2016.



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

On February 17, 2017, we, through our wholly-owned subsidiary, completed the acquisition of certain assets from Vitruvian II Woodford, LLC, an unrelated third-party seller. The aggregate initial purchase price for the acquisition was approximately $1.85 billion, consisting of $1.35 billion in cash, subject to certain adjustments, and approximately 23.9 million

Table of Contents

shares of our common stock (of which approximately 5.2 million shares were placed in an indemnity escrow). The shares of our common stock issued to the seller in the acquisition were issued in reliance upon the exemption from the registration requirements provided by Section 4(a)(2) of the Securities Act, as sales by an issuer not involving any public offering.

On April 18, 2017, we filed a shelf Registration Statement on Form S-3/ASR, as required under the registration right agreement with the seller entered in connection with the acquisition, registering under the Securities Act the resale of the shares received by the seller in the acquisition and any shares of our common stock that may be issued or distributed in respect of such shares upon certain events.

We do not have a share repurchase program, and during the three months ended March 31, 2017, we did not purchase any shares of our common stock.



ITEM 3.	DEFAULTS UPON SENIOR SECURITIES

Not applicable.



ITEM 4.	MINE SAFETY DISCLOSURES

Not applicable.



ITEM 5.	OTHER INFORMATION

None.



ITEM 6.	EXHIBITS



Exhibit Number		Description

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

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

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

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

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

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

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

4.5		Indenture, dated as of April 21, 2015, among the Company, the subsidiary guarantors party thereto and Wells Fargo Bank, N.A., as trustee (including the form of the Company’s 6.625% Senior Notes due 2023) (incorporated by reference to Exhibit 4.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on April 21, 2015).

4.6		Indenture, dated as of October 14, 2016, among Gulfport Energy Corporation, the subsidiary guarantors party thereto and Wells Fargo Bank, N.A., as trustee (including the form of Gulfport Energy Corporation’s 6.000% Senior Notes due 2024) (incorporated by reference to Exhibit 4.1 to the Form 8-K, File. No. 000-19514, filed by the Company with the SEC on October 19, 2016).

Table of Contents



4.7		Registration Rights Agreement, dated as of October 14, 2016, among Gulfport Energy Corporation, the subsidiary guarantors party thereto and Credit Suisse Securities (USA) LLC and Scotia Capital (USA) Inc., as representatives of the several initial purchasers (incorporated by reference to Exhibit 4.2 to the Form 8-K, File. No. 000-19514, filed by the Company with the SEC on October 19, 2016).

4.8		Indenture, dated as of December 21, 2016, among Gulfport Energy Corporation, the subsidiary guarantors party thereto and Wells Fargo Bank, N.A., as trustee (including the form of Gulfport Energy Corporation’s 6.375% Senior Notes due 2025) (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K, File No. 000-19514, filed by the Company with the SEC on December 21, 2016).

4.9		Registration Rights Agreement, dated as of December 21, 2016, among Gulfport Energy Corporation, the subsidiary guarantors party thereto and Credit Suisse Securities (USA) LLC and Merrill Lynch, Pierce, Fenner & Smith Incorporated, as representatives of the several initial purchasers (incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K, File No. 000-19514, filed by the Company with the SEC on December 21, 2016).

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

10.1		Eighth Amendment to Amended and Restated Credit Agreement, entered into as of March 29, 2017, among Gulfport Energy Corporation, as borrower, The Bank of Nova Scotia, as administrative agent and L/C issuer, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on April 4, 2017).

10.2*		Ninth Amendment to Amended and Restated Credit Agreement, entered into as of May 4, 2017, among Gulfport Energy Corporation, as borrower, The Bank of Nova Scotia, as administrative agent and L/C issuer, the existing lenders named therein and JPMorgan Chase Bank, N.A., Commonwealth Bank of Australia, ABN, AMRO Capital USA LLC, Fifth Third Bank and Canadian Imperial Bank of Commerce, New York branch, as new lenders.

10.3*		Employment Agreement, entered into as of April 28, 2017, effective as of January 1, 2017, by and between Gulfport Energy Corporation and Keri Crowell.

10.4*		Employment Agreement, entered into as of April 28, 2017, effective as of January 1, 2017, by and between Gulfport Energy Corporation and Stuart Maier.

10.5*		Employment Agreement, entered into as of April 28, 2017, effective as of January 1, 2917, by and between Gulfport Energy Corporation and Steve Baldwin.

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.

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.



*	Filed herewith.

Table of Contents

SIGNATURES

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

Date: May 9, 2017



GULFPORT ENERGY CORPORATION

By:		/s/ Keri Crowell
		Keri Crowell Chief Financial Officer