Gulfport Energy - 10-Q quarterly report FY2018 Q3

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 September 30, 2018 OR



¨	TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF SECURITIES EXCHANGE ACT OF 1934
	For the transition period from to

Commission File Number 000-19514

Gulfport Energy Corporation

(Exact Name of Registrant As Specified in Its Charter)



Delaware		73-1521290
(State or Other Jurisdiction of Incorporation or Organization)		(IRS Employer Identification Number)
3001 Quail Springs Parkway Oklahoma City, Oklahoma		73134
(Address of Principal Executive Offices)		(Zip Code)

(405) 252-4600

(Registrant Telephone Number, Including Area Code)

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

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

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

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

Emerging growth company ¨

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

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

As of October 29, 2018, 173,302,055 shares of the registrant’s common stock were outstanding.

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GULFPORT ENERGY CORPORATION

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		Page
PART I FINANCIAL INFORMATION

Item 1.	Consolidated Financial Statements (Unaudited):	2

	Consolidated Balance Sheets at September 30, 2018 and December 31, 2017	2

	Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2018 and 2017	3

	Consolidated Statements of Comprehensive Income for the Three and Nine Months Ended September 30, 2018 and 2017	4

	Consolidated Statements of Stockholders’ Equity for the Nine Months Ended September 30, 2018 and 2017	5

	Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2018 and 2017	6

	Notes to Consolidated Financial Statements	7

Item 2.	Management’s Discussion and Analysis of Financial Conditions and Results of Operations	38

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	56

Item 4.	Controls and Procedures	57

PART II OTHER INFORMATION

Item 1.	Legal Proceedings	59

Item 1A.	Risk Factors	59

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	59

Item 3.	Defaults Upon Senior Securities	60

Item 4.	Mine Safety Disclosures	60

Item 5.	Other Information	60

Item 6.	Exhibits	61

Signatures		63

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GULFPORT ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS

(Unaudited)



	September 30, 2018			December 31, 2017
	(In thousands, except share data)
Assets
Current assets:
Cash and cash equivalents	$	124,571		$	99,557
Accounts receivable—oil and natural gas sales	157,391			146,773
Accounts receivable—joint interest and other	39,511			35,440
Accounts receivable—related parties	79			—
Prepaid expenses and other current assets	9,742			4,912
Short-term derivative instruments	19,809			78,847
Total current assets	351,103			365,529
Property and equipment:
Oil and natural gas properties, full-cost accounting, $2,925,145 and $2,912,974 excluded from amortization in 2018 and 2017, respectively	9,936,714			9,169,156
Other property and equipment	92,388			86,754
Accumulated depletion, depreciation, amortization and impairment	(4,506,306		)	(4,153,733		)
Property and equipment, net	5,522,796			5,102,177
Other assets:
Equity investments	232,529			302,112
Long-term derivative instruments	3,530			8,685
Deferred tax asset	—			1,208
Inventories	8,234			8,227
Other assets	17,038			19,814
Total other assets	261,331			340,046
Total assets	$	6,135,230		$	5,807,752
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable and accrued liabilities	$	582,464		$	553,609
Asset retirement obligation—current	120			120
Short-term derivative instruments	62,601			32,534
Current maturities of long-term debt	647			622
Total current liabilities	645,832			586,885
Long-term derivative instruments	15,101			2,989
Asset retirement obligation—long-term	78,411			74,980
Deferred tax liability	3,046			—
Other non-current liabilities	—			2,963
Long-term debt, net of current maturities	2,100,825			2,038,321
Total liabilities	2,843,215			2,706,138
Commitments and contingencies (Note 9)
Preferred stock, $.01 par value; 5,000,000 authorized, 30,000 authorized as redeemable 12% cumulative preferred stock, Series A; 0 issued and outstanding	—			—
Stockholders’ equity:
Common stock - $.01 par value, 200,000,000 authorized, 173,218,643 issued and outstanding at September 30, 2018 and 183,105,910 at December 31, 2017	1,732			1,831
Paid-in capital	4,316,006			4,416,250
Accumulated other comprehensive loss	(46,354		)	(40,539		)
Retained deficit	(979,369		)	(1,275,928		)
Total stockholders’ equity	3,292,015			3,101,614
Total liabilities and stockholders’ equity	$	6,135,230		$	5,807,752

See accompanying notes to consolidated financial statements.

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GULFPORT ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)



	Three months ended September 30,						Nine months ended September 30,
	2018			2017			2018			2017
	(In thousands, except share data)
Revenues:
Natural gas sales	$	271,167		$	223,340		$	753,261		$	606,544
Oil and condensate sales	45,682			31,459			140,687			85,338
Natural gas liquid sales	53,776			33,559			141,883			88,985
Net (loss) gain on natural gas, oil, and NGL derivatives	(9,663		)	(22,860		)	(96,737		)	141,588
	360,962			265,498			939,094			922,455
Costs and expenses:
Lease operating expenses	22,325			20,020			64,143			60,044
Production taxes	9,348			5,419			23,861			14,464
Midstream gathering and processing	78,913			69,372			214,546			176,258
Depreciation, depletion and amortization	119,915			106,650			352,848			254,887
General and administrative	15,848			13,065			42,955			37,922
Accretion expense	1,037			456			3,056			1,148
Acquisition expense	—			33			—			2,391
	247,386			215,015			701,409			547,114
INCOME FROM OPERATIONS	113,576			50,483			237,685			375,341
OTHER (INCOME) EXPENSE:
Interest expense	33,253			27,130			100,922			74,797
Interest income	(92		)	(37		)	(162		)	(927		)
Litigation settlement	917			—			917			—
Insurance proceeds	—			—			(231		)	—
Gain on sale of equity method investments	(2,733		)	—			(124,768		)	(12,523		)
(Income) loss from equity method investments, net	(12,858		)	2,737			(35,282		)	33,468
Other income	(61		)	(345		)	(201		)	(863		)
	18,426			29,485			(58,805		)	93,952
INCOME BEFORE INCOME TAXES	95,150			20,998			296,490			281,389
INCOME TAX EXPENSE (BENEFIT)	—			2,763			(69		)	2,763
NET INCOME	$	95,150		$	18,235		$	296,559		$	278,626
NET INCOME PER COMMON SHARE:
Basic	$	0.55		$	0.10		$	1.69		$	1.56
Diluted	$	0.55		$	0.10		$	1.68		$	1.56
Weighted average common shares outstanding—Basic	173,057,538			182,957,416			175,776,312			178,736,569
Weighted average common shares outstanding—Diluted	173,304,914			183,008,436			176,440,461			179,130,570

See accompanying notes to consolidated financial statements.

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GULFPORT ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)



	Three months ended September 30,				Nine months ended September 30,
	2018		2017		2018			2017
	(In thousands)
Net income	$	95,150	$	18,235	$	296,559		$	278,626
Foreign currency translation adjustment	3,052		6,832		(5,815		)	12,719
Other comprehensive income (loss)	3,052		6,832		(5,815		)	12,719
Comprehensive income	$	98,202	$	25,067	$	290,744		$	291,345

See accompanying notes to consolidated financial statements.

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GULFPORT ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(Unaudited)



						Paid-in Capital			Accumulated Other Comprehensive (Loss) Income			Retained Deficit			Total Stockholders’ Equity
	Common Stock
	Shares		Amount
	(In thousands, except share data)
Balance at January 1, 2018	183,105,910		$	1,831		$	4,416,250		$	(40,539	)	$	(1,275,928	)	$	3,101,614
Net income	—		—			—			—			296,559			296,559
Other Comprehensive Loss	—		—			—			(5,815		)	—			(5,815		)
Stock-based Compensation	—		—			9,654			—			—			9,654
Shares Repurchased	(10,505,469	)	(105		)	(109,892		)	—			—			(109,997		)
Issuance of Restricted Stock	618,202		6			(6		)	—			—			—
Balance at September 30, 2018	173,218,643		$	1,732		$	4,316,006		$	(46,354	)	$	(979,369	)	$	3,292,015

Balance at January 1, 2017	158,829,816		$	1,588		$	3,946,442		$	(53,058	)	$	(1,711,080	)	$	2,183,892
Net income	—		—			—			—			278,626			278,626
Other Comprehensive Income									12,719			—			12,719
Stock-based Compensation	—		—			7,988			—			—			7,988
Issuance of Common Stock for the Vitruvian Acquisition, net of related expenses	23,852,117		239			459,197			—			—			459,436
Issuance of Restricted Stock	399,843		4			(4		)	—			—			—
Balance at September 30, 2017	183,081,776		$	1,831		$	4,413,623		$	(40,339	)	$	(1,432,454	)	$	2,942,661

See accompanying notes to consolidated financial statements.

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GULFPORT ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)



	Nine months ended September 30,
	2018			2017
	(In thousands)
Cash flows from operating activities:
Net income	$	296,559		$	278,626
Adjustments to reconcile net income to net cash provided by operating activities:
Accretion expense	3,056			1,148
Depletion, depreciation and amortization	352,848			254,887
Stock-based compensation expense	5,792			4,793
(Income) loss from equity investments	(35,040		)	34,018
Change in fair value of derivative instruments	106,373			(129,692		)
Deferred income tax benefit	(69		)	—
Amortization of loan commitment fees	4,554			3,548
Gain on sale of equity method investments	(124,768		)	(12,523		)
Distributions from equity method investments	1,978			—
Changes in operating assets and liabilities:
Increase in accounts receivable—oil and natural gas sales	(10,618		)	(20,056		)
Increase in accounts receivable—joint interest and other	(2,277		)	(23,289		)
Increase in accounts receivable—related parties	(79		)	(346		)
Increase in prepaid expenses and other current assets	(4,830		)	(2,531		)
Decrease (increase) in other assets	1,228			(5,665		)
Increase in accounts payable, accrued liabilities and other	14,968			111,335
Settlement of asset retirement obligation	(719		)	(2,520		)
Net cash provided by operating activities	608,956			491,733
Cash flows from investing activities:
Additions to other property and equipment	(7,134		)	(16,288		)
Acquisition of oil and natural gas properties	—			(1,339,456		)
Additions to oil and natural gas properties	(755,263		)	(789,743		)
Proceeds from sale of oil and natural gas properties	4,820			4,079
Proceeds from sale of other property and equipment	217			658
Proceeds from sale of equity method investments	226,487			—
Contributions to equity method investments	(2,318		)	(44,844		)
Distributions from equity method investments	446			4,114
Net cash used in investing activities	(532,745		)	(2,181,480		)
Cash flows from financing activities:
Principal payments on borrowings	(165,428		)	(183		)
Borrowings on line of credit	225,000			365,000
Borrowings on term loan	—			2,951
Debt issuance costs and loan commitment fees	(772		)	(8,261		)
Payments on repurchase of stock	(109,997		)	—
Proceeds from issuance of common stock, net of offering costs	—			(5,364		)
Net cash (used in) provided by financing activities	(51,197		)	354,143
Net increase (decrease) in cash, cash equivalents and restricted cash	25,014			(1,335,604		)
Cash, cash equivalents and restricted cash at beginning of period	99,557			1,460,875
Cash, cash equivalents and restricted cash at end of period	$	124,571		$	125,271
Supplemental disclosure of cash flow information:
Interest payments	$	75,045		$	50,826
Income tax payments	$	—		$	—
Supplemental disclosure of non-cash transactions:
Capitalized stock-based compensation	$	3,862		$	3,195
Asset retirement obligation capitalized	$	1,094		$	11,557
Interest capitalized	$	3,956		$	8,753
Foreign currency translation (loss) gain on equity method investments	$	(5,815	)	$	12,719

See accompanying notes to consolidated financial statements.

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GULFPORT ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

These consolidated financial statements have been prepared by Gulfport Energy Corporation (the “Company” or “Gulfport”) without audit, pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”), and reflect all adjustments which, in the opinion of management, are necessary for a fair presentation of the results for the interim periods, on a basis consistent with the annual audited consolidated financial statements. All such adjustments are of a normal recurring nature. Certain information, accounting policies, and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles ("GAAP") have been omitted pursuant to such rules and regulations, although the Company believes that the disclosures are adequate to make the information presented not misleading. These 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 and nine month periods ended September 30, 2018 are not necessarily indicative of the results expected for the full year.


1.	ACQUISITIONS

Vitruvian Acquisition

In December 2016, the Company, through its wholly-owned subsidiary Gulfport MidCon LLC (“Gulfport MidCon”) (formerly known as SCOOP Acquisition Company, LLC), entered into an agreement to acquire certain assets of Vitruvian II Woodford, LLC (“Vitruvian”), an unrelated third-party seller (the “Vitruvian Acquisition”). The assets included in the Vitruvian Acquisition include 46,400 net surface acres located in Grady, Stephens and Garvin Counties, Oklahoma. On February 17, 2017, the Company completed the Vitruvian Acquisition for a total initial purchase price of approximately $1.85 billion, consisting of $1.35 billion in cash, subject to certain adjustments, and approximately 23.9 million shares of the Company’s common stock (of which approximately 5.2 million shares were placed in an indemnity escrow). The cash portion of the purchase price was funded with the net proceeds from the Company's December 2016 common stock and senior note offerings and cash on hand. Acquisition costs of $0.03 million and $2.4 million were incurred during the three and nine months ended September 30, 2017, respectively, related to the Vitruvian Acquisition. No acquisition costs were incurred during the three and nine months ended September 30, 2018.

Allocation of Purchase Price

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

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

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

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

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

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

Post-Acquisition Operating Results

For the three months ended September 30, 2017 and the period from the acquisition date of February 17, 2017 to September 30, 2017, the assets acquired in the Vitruvian Acquisition contributed the following amounts of revenue to the Company's consolidated statements of operations. The amount of net income contributed by the assets 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.



			Period from
			February 17, 2017
	Three months ended		to
	September 30, 2017		September 30, 2017
	(In thousands)
Revenue	$	60,940	$	137,706

Pro Forma Information (Unaudited)

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



	Three months ended		Nine months ended
	September 30, 2017		September 30, 2017
	(In thousands, except share data)
Pro forma revenue	$	265,498	$	958,354
Pro forma net income	$	18,235	$	300,052
Pro forma earnings per share (basic)	$	0.10	$	1.68
Pro forma earnings per share (diluted)	$	0.10	$	1.68

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2.	PROPERTY AND EQUIPMENT

The major categories of property and equipment and related accumulated depletion, depreciation, amortization and impairment as of September 30, 2018 and December 31, 2017 are as follows:



	September 30, 2018			December 31, 2017
	(In thousands)
Oil and natural gas properties	$	9,936,714		$	9,169,156
Office furniture and fixtures	42,302			37,369
Building	44,565			44,565
Land	5,521			4,820
Total property and equipment	10,029,102			9,255,910
Accumulated depletion, depreciation, amortization and impairment	(4,506,306		)	(4,153,733		)
Property and equipment, net	$	5,522,796		$	5,102,177

Under the full cost method of accounting, the Company is required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the oil and natural gas properties. At September 30, 2018, the calculated ceiling was greater than the net book value of the Company’s oil and natural gas properties, thus no ceiling test impairment was required for the nine months ended September 30, 2018. No impairment was required for oil and natural gas properties for the nine months ended September 30, 2017.

Included in oil and natural gas properties at September 30, 2018 is the cumulative capitalization of $194.4 million in general and administrative costs incurred and capitalized to the full cost pool. General and administrative costs capitalized to the full cost pool represent management’s estimate of costs incurred directly related to exploration and development activities such as geological and other administrative costs associated with overseeing the exploration and development activities. All general and administrative costs not directly associated with exploration and development activities were charged to expense as they were incurred. Capitalized general and administrative costs were approximately $10.6 million and $28.8 million for the three and nine months ended September 30, 2018, respectively, and $8.9 million and $25.6 million for the three and nine months ended September 30, 2017, respectively.

The average depletion rate per Mcfe, which is a function of capitalized costs, future development costs and the related underlying reserves in the periods presented, was $0.94 and $0.89 per Mcfe for the nine months ended September 30, 2018 and 2017, respectively.

The following table summarizes the Company’s non-producing properties excluded from amortization by area at September 30, 2018:



	September 30, 2018
	(In thousands)
Utica	$	1,522,633
MidContinent	1,401,392
Niobrara	449
Southern Louisiana	571
Bakken	100
	$	2,925,145

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

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

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A reconciliation of the Company’s asset retirement obligation for the nine months ended September 30, 2018 and 2017 is as follows:



	September 30, 2018			September 30, 2017
	(In thousands)
Asset retirement obligation, beginning of period	$	75,100		$	34,276
Liabilities incurred	1,468			11,557
Liabilities settled	(719		)	(2,520		)
Accretion expense	3,056			1,148
Revisions in estimated cash flows	(374		)	—
Asset retirement obligation as of end of period	78,531			44,461
Less current portion	120			195
Asset retirement obligation, long-term	$	78,411		$	44,266


3.	EQUITY INVESTMENTS

Investments accounted for by the equity method consist of the following as of September 30, 2018 and December 31, 2017:



			Carrying value				(Income) loss from equity method investments
	Approximate ownership %		September 30, 2018		December 31, 2017		Three months ended September 30,						Nine months ended September 30,
	Approximate ownership %		September 30, 2018		December 31, 2017		2018			2017			2018			2017
			(In thousands)
Investment in Tatex Thailand II, LLC	23.5	%	$	—	$	—	$	(137	)	$	(95	)	$	(241	)	$	(549	)
Investment in Grizzly Oil Sands ULC	24.9999	%	53,381		57,641		275			296			833			869
Investment in Timber Wolf Terminals LLC	50.0	%	—		983		—			4			536			8
Investment in Windsor Midstream LLC	22.5	%	39		30		—			(2		)	(9		)	25,232
Investment in Stingray Cementing LLC⁽¹⁾	—	%	—		—		—			—			—			205
Investment in Stingray Energy Services LLC⁽¹⁾	—	%	—		—		—			—			—			282
Investment in Sturgeon Acquisitions LLC⁽¹⁾	—	%	—		—		—			—			—			(71		)
Investment in Mammoth Energy Services, Inc.⁽¹⁾	22.0	%	179,109		165,715		(12,996		)	2,407			(35,708		)	4,907
Investment in Strike Force Midstream LLC⁽²⁾	—	%	—		77,743		—			127			(693		)	2,585
			$	232,529	$	302,112	$	(12,858	)	$	2,737		$	(35,282	)	$	33,468




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

(2)	On May 1, 2018, the Company sold its 25% interest in Strike Force Midstream to EQT Midstream Partners, LP. See below under under Strike Force Midstream LLC for information regarding this transaction.

The tables below summarize financial information for the Company’s equity investments as of September 30, 2018 and December 31, 2017.

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Summarized balance sheet information:



	September 30, 2018		December 31, 2017
	September 30, 2018		December 31, 2017
	(In thousands)
Current assets	$	481,394	$	415,032
Noncurrent assets	$	1,336,604	$	1,542,090
Current liabilities	$	358,177	$	261,086
Noncurrent liabilities	$	48,328	$	148,839

Summarized results of operations:



	Three months ended September 30,				Nine months ended September 30,
	2018		2017		2018		2017
	(In thousands)
Gross revenue	$	384,043	$	160,950	$	1,451,580	$	357,901
Net income (loss)	$	68,414	$	2,101	$	181,884	$	(109,651	)

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 $0.5 million in distributions from Tatex II during the nine months ended September 30, 2018 and 2017, respectively.

Tatex Thailand III, LLC

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

Grizzly Oil Sands ULC

The Company, through its wholly owned subsidiary Grizzly Holdings Inc. (“Grizzly Holdings”), owns an interest in Grizzly Oil Sands ULC (“Grizzly”), a Canadian unlimited liability company. The remaining interest in Grizzly is owned by Grizzly Oil Sands Inc. (“Oil Sands”). As of September 30, 2018, Grizzly had approximately 830,000 acres under lease in the Athabasca, Peace River and Cold Lake oil sands regions of Alberta, Canada. Grizzly has high-graded three oil sands projects to various stages of development. Grizzly commenced commercial production from its Algar Lake Phase I steam-assisted gravity drainage ("SAGD") oil sand project during the second quarter of 2014 and has regulatory approval for up to 11,300 barrels per day of bitumen production. Algar Lake production peaked at 2,200 barrels per day during the ramp-up phase of the SAGD facility, however, in April 2015, Grizzly made the decision to suspend operations at its Algar Lake facility due to the commodity price drop and its effect on project economics. Grizzly continues to monitor market conditions as it assesses start up plans for the facility. The Company reviewed its investment in Grizzly for impairment at September 30, 2018 and 2017 and determined no impairment was required. If commodity prices decline in the future however, impairment of the investment in Grizzly may be necessary. During the nine months ended September 30, 2018, Gulfport paid $2.3 million in cash calls. Grizzly’s functional currency is the Canadian dollar. The Company’s investment in Grizzly was increased by a $2.9 million foreign currency translation gain and decreased by a $5.7 million foreign currency translation loss for the three and nine months ended September 30, 2018, respectively. The Company’s investment in Grizzly was increased by $6.7 million and $12.5 million as a result of a foreign currency translation gain for the three and nine months ended September 30, 2017, respectively.

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Timber Wolf Terminals LLC

During 2012, the Company invested in Timber Wolf Terminals LLC (“Timber Wolf”). Timber Wolf was formed to operate a crude/condensate terminal and a sand transloading facility in Ohio. During the nine months ended September 30, 2018 and 2017, the Company paid no cash calls to Timber Wolf. The Company received $0.4 million in distributions from Timber Wolf during the nine months ended September 30, 2018 resulting from the sale of assets held by Timber Wolf.

Windsor Midstream LLC

At September 30, 2018, the Company held a 22.5% interest in Windsor Midstream LLC (“Midstream”), an entity controlled and managed by an unrelated third party. The Company received no distributions from Midstream during the nine months ended September 30, 2018 and $0.5 million in distributions during the same period in 2017.

Stingray Cementing LLC

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

Stingray Energy Services LLC

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

Sturgeon Acquisitions LLC

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

Mammoth Energy Partners LP/Mammoth Energy Services, Inc.

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

On June 5, 2017, the Company contributed all of its membership interests in Sturgeon (which owned Taylor Frac, LLC, Taylor Real Estate Investments, LLC and South River Road, LLC), Stingray Energy and Stingray Cementing to Mammoth Energy in exchange for approximately 2.0 million shares of Mammoth Energy common stock (the "June 2017 Transactions"). The Company accounted for the transactions as a sale of financial assets under ASC 860, Transfers and Servicing. The Company valued the shares of Mammoth Energy common stock it received in the June 2017 Transactions at $18.50 per share, which was the closing price of Mammoth Energy common stock on June 5, 2017. During the second quarter of 2017, the Company recognized a gain of $12.5 million from the June 2017 Transactions, which is included in gain on sale of equity method investments in the accompanying consolidated statement of operations.

On June 29, 2018, the Company sold 1,235,600 shares of its Mammoth Energy common stock in an underwritten public offering for net proceeds of approximately $47.0 million. In connection with the Company's public offering of a portion of its shares of Mammoth Energy common stock, the Company granted the underwriters an option to purchase additional shares of its Mammoth Energy common stock. On July 26, 2018, the underwriters exercised this option, in part, and on July 30, 2018, the

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Company sold an additional 118,974 shares for net proceeds of approximately $4.5 million. Following the sales of these shares, the Company owned 9,829,548 shares, or approximately 22.0%, of Mammoth Energy's outstanding common stock. As a result of the sales, the Company recorded a gain of $2.7 million and $28.3 million for the three and nine months ended September 30, 2018, which is included in gain on sale of equity method investments in the accompanying consolidated statements of operations.

The Company’s investment in Mammoth Energy was increased by a $0.1 million foreign currency gain and decreased by a $0.2 million foreign currency loss resulting from Mammoth Energy’s foreign subsidiary for the three and nine months ended September 30, 2018, respectively. The Company’s investment in Mammoth Energy was increased by a $0.16 million and $0.2 million foreign currency gain resulting from Mammoth Energy’s foreign subsidiary for the three and nine months ended September 30, 2017, respectively. During the nine months ended September 30, 2018, Gulfport received distributions of $1.2 million from Mammoth Energy as a result of a $0.125 per share dividend in August 2018. The (income) loss from equity method investments presented in the table above reflects any intercompany profit eliminations.

Strike Force Midstream LLC

In February 2016, the Company, through its wholly-owned subsidiary Gulfport Midstream Holdings, LLC (“Midstream Holdings”), entered into an agreement with Rice Midstream Holdings LLC (“Rice”), then a subsidiary of Rice Energy Inc., to develop natural gas gathering assets in eastern Belmont County and Monroe County, Ohio through Strike Force Midstream LLC ("Strike Force"). In 2017, Rice was acquired by EQT Corporation ("EQT"). Prior to the sale of the Company's interest in Strike Force (discussed below), the Company owned a 25% interest in Strike Force, and EQT acted as operator and owned the remaining 75% interest. Strike Force's gathering assets provide gathering services for wells operated by Gulfport and other operators and connectivity of existing dry gas gathering systems. Prior to the sale of its interest in Strike Force, the Company elected to report its proportionate share of Strike Force’s earnings on a one-quarter lag as permitted under ASC 323, Investments - Equity Method and Joint Ventures. The (income) loss from equity method investments presented in the table above reflects any intercompany profit eliminations.

During the nine months ended September 30, 2018, Gulfport received distributions of $0.8 million from Strike Force. During the nine months ended September 30, 2017, Gulfport paid $43.0 million in cash calls to Strike Force and received distributions of $3.6 million from Strike Force.

On May 1, 2018, the Company sold its 25% interest in Strike Force to EQT Midstream Partners, LP for proceeds of $175.0 million in cash. As a result of the sale, the Company recognized a gain of $96.4 million net of transaction fees, which is included in gain on sale of equity method investments in the accompanying consolidated statement of operations.


4.	VARIABLE INTEREST ENTITIES

As of September 30, 2018, the Company held variable interests in the following variable interest entities (“VIEs”), but was not the primary beneficiary: Midstream and Timber Wolf. These entities have governing provisions that are the functional equivalent of a limited partnership and are considered VIEs because the limited partners or non-managing members lack substantive kick-out or participating rights which causes the equity owners, as a group, to lack a controlling financial interest. The Company is a limited partner or non-managing member in each of these VIEs and is not the primary beneficiary because it does not have a controlling financial interest. The general partner or managing member has power to direct the activities that most significantly impact the VIEs’ economic performance. The Company also held a variable interest in Strike Force prior to the sale of that interest due to the fact that it did not have sufficient equity capital at risk. The Company was not the primary beneficiary of this entity. Prior to Mammoth Energy’s initial public offering, or "IPO", Mammoth LLC was considered a VIE. As a result of the Company’s contribution of its interest in Mammoth LLC to Mammoth Energy in exchange for Mammoth Energy common stock and the completion of Mammoth Energy’s IPO, the Company determined that it no longer held an interest in a VIE. Prior to the contribution of Stingray Energy, Stingray Cementing and Sturgeon to Mammoth Energy, these entities were considered VIEs. As a result of the Company’s contribution of its membership interests in Stingray Energy, Stingray Cementing and Sturgeon to Mammoth Energy in exchange for Mammoth Energy common stock, the Company determined that it no longer held an interest in a VIE.

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

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5.	LONG-TERM DEBT

Long-term debt consisted of the following items as of September 30, 2018 and December 31, 2017:



	September 30, 2018			December 31, 2017
	(In thousands)
Revolving credit agreement (1)	$	60,000		$	—
6.625% senior unsecured notes due 2023 (2)	350,000			350,000
6.000% senior unsecured notes due 2024 (3)	650,000			650,000
6.375% senior unsecured notes due 2025 (4)	600,000			600,000
6.375% senior unsecured notes due 2026 (5)	450,000			450,000
Net unamortized debt issuance costs (6)	(31,824		)	(34,781		)
Construction loan (7)	23,296			23,724
Less: current maturities of long term debt	(647		)	(622		)
Debt reflected as long term	$	2,100,825		$	2,038,321

The Company capitalized approximately $1.6 million and $4.0 million in interest expense to undeveloped oil and natural gas properties during the three and nine months ended September 30, 2018, respectively. The Company capitalized approximately $2.1 million and $8.8 million in interest expense to undeveloped oil and natural gas properties during the three and nine months ended September 30, 2017, respectively.

(1) The Company has entered into a senior secured revolving credit facility, as amended, with The Bank of Nova Scotia, as the lead arranger and administrative agent and certain lenders from time to time party thereto. The credit agreement provides for a maximum facility amount of $1.5 billion and matures on December 31, 2021. On March 29, 2017, the Company further amended its revolving credit facility to, among other things, amend the definition of the term EBITDAX to permit pro forma treatment of acquisitions that involve the payment of consideration by Gulfport and its subsidiaries in excess of $50.0 million and of dispositions of property or series of related dispositions of properties that yields gross proceeds to Gulfport or any of its subsidiaries in excess of $50.0 million. On May 4, 2017, the revolving credit facility was further amended to increase the borrowing base from $700.0 million to $1.0 billion, adjust certain of the Company’s investment baskets and add five additional banks to the syndicate. On November 21, 2017, the Company further amended its revolving credit facility to, among other things, (a) decrease the applicable rate for all loans by 0.5% and (b) add a provision that allows Gulfport to elect a commitment amount (the “Elected Commitment Amount”) that is less than the borrowing base. In connection with this amendment, the borrowing base was set at $1.2 billion, with an elected commitment of $1.0 billion. On May 21, 2018, the Company further amended its revolving credit facility to, among other things, (a) decrease the applicable rate for all loans by 0.25%, (b) permit Gulfport and each of its subsidiaries to use the proceeds from dispositions of certain investments to acquire the common stock or other equity interests of Gulfport, subject to certain limitations and (c) increase the borrowing base to $1.4 billion, with an elected commitment of $1.0 billion.

As of September 30, 2018, $60.0 million was outstanding under the revolving credit facility and the total availability for future borrowings under this facility, after giving effect to an aggregate of $316.2 million of letters of credit, was $623.8 million. The Company’s wholly-owned subsidiaries have guaranteed the obligations of the Company under the revolving credit facility.

Advances under the revolving credit facility may be in the form of either base rate loans or eurodollar loans. The interest rate for base rate loans is equal to (1) the applicable rate, which ranges from 0.25% to 1.25%, plus (2) the highest of: (a) the federal funds rate plus 0.50%, (b) the rate of interest in effect for such day as publicly announced from time to time by agent as its “prime rate,” and (c) the eurodollar rate for an interest period of one month plus 1.00%. The interest rate for eurodollar loans is equal to (1) the applicable rate, which ranges from 1.25% to 2.25%, plus (2) the London interbank offered rate that appears on pages LIBOR01 or LIBOR02 of the Reuters screen that displays such rate for deposits in U.S. dollars, or, if such rate is not available, the rate as administered by ICE Benchmark Administration (or any other person that takes over administration of such rate) per annum equal to the offered rate on such other page or 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

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September 30, 2018, amounts borrowed under the credit facility bore interest at the eurodollar rate with a weighted average of 3.72%.

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

•incur indebtedness;

•grant liens;

•pay dividends and make other restricted payments;

•make investments;

•make fundamental changes;

•enter into swap contracts;

•dispose of assets;

•change the nature of their business; and

•enter into transactions with affiliates.

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

(i) the ratio of net funded debt to EBITDAX (net income, excluding (i) any non-cash revenue or expense associated with swap contracts resulting from ASC 815 and (ii) any cash or non-cash revenue or expense attributable to minority investments plus without duplication and, in the case of expenses, to the extent deducted from revenues in determining net income, the sum of (a) the aggregate amount of consolidated interest expense for such period, (b) the aggregate amount of income, franchise, capital or similar tax expense (other than ad valorem taxes) for such period, (c) all amounts attributable to depletion, depreciation, amortization and asset or goodwill impairment or writedown for such period, (d) all other non-cash charges, (e) exploration costs deducted in determining net income under successful efforts accounting, (f) actual cash distributions received from minority investments, (g) to the extent actually reimbursed by insurance, expenses with respect to liability on casualty events or business interruption, and (h) all reasonable transaction expenses related to dispositions and acquisitions of assets, investments and debt and equity offerings (provided that expenses related to any unsuccessful disposition will be limited to $3.0 million in the aggregate) for a twelve-month period may not be greater than 4.00 to 1.00; and

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

The Company was in compliance with its financial covenants at September 30, 2018.

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

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

(3) On October 14, 2016, the Company issued $650.0 million in aggregate principal amount of 6.000% Senior Notes due 2014 (the "2024 Notes"). 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

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received approximately $638.9 million in net proceeds from the offering of the 2024 Notes, which was used, together with cash on hand, to purchase the then outstanding 2020 Notes in a concurrent cash tender offer, to pay fees and expenses thereof, and to redeem any of the 2020 Notes that remained outstanding after the completion of the tender offer.

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

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

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

(6) Loan issuance costs related to the 2023 Notes, the 2024 Notes, the 2025 Notes and the 2026 Notes (collectively the “Notes”) have been presented as a reduction to the Notes. At September 30, 2018, total unamortized debt issuance costs were $4.6 million for the 2023 Notes, $9.0 million for the 2024 Notes, $12.9 million for the 2025 Notes and $5.2 million for the 2026 Notes. In addition, loan commitment fee costs for the construction loan agreement described immediately below were $0.1 million at September 30, 2018.

(7) On June 4, 2015, the Company entered into a construction loan agreement (the “Construction Loan”) with InterBank for the construction of a new corporate headquarters in Oklahoma City, which was substantially completed in December 2016. The Construction Loan allows for maximum principal borrowings of $24.5 million and required the Company to fund 30% of the cost of the construction before any funds could be drawn, which occurred in January 2016. Interest accrues daily on the outstanding principal balance at a fixed rate of 4.50% per annum and was payable on the last day of the month through May 31, 2017. Starting June 30, 2017, the Company began making monthly payments of principal and interest, with the final payment due June 4, 2025. At September 30, 2018, the total borrowings under the Construction Loan were approximately $23.3 million.


6.	COMMON STOCK AND CHANGES IN CAPITALIZATION

Issuance of Common Stock

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

Stock Repurchase Program

In January 2018, the board of directors of the Company approved a stock repurchase program to acquire up to $100 million of the Company's outstanding stock during 2018. In May 2018, the Company's board of directors authorized the expansion of

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its stock repurchase program, authorizing the Company to acquire up to an additional $100 million of its outstanding common stock during 2018 for a total of up to $200 million. Purchases under the repurchase program may be made from time to time in open market or privately negotiated transactions, and are subject to market conditions, applicable legal requirements, contractual obligations and other factors. The repurchase program does not require the Company to acquire any specific number of shares. This repurchase program is authorized to extend through December 31, 2018 and may be suspended from time to time, modified, extended or discontinued by the board of directors at any time. The Company repurchased 0.4 million and 10.5 million shares for a cost of approximately $5.0 million and $110.0 million during the three and nine months ended September 30, 2018, respectively. All repurchased shares have been retired.


7.	STOCK-BASED COMPENSATION

During the three and nine months ended September 30, 2018, the Company’s stock-based compensation cost was $3.6 million and $9.7 million, respectively, of which the Company capitalized $1.4 million and $3.9 million, respectively, relating to its exploration and development efforts. During the three and nine months ended September 30, 2017, the Company’s stock-based compensation cost was $2.8 million and $8.0 million, respectively, of which the Company capitalized $1.1 million and $3.2 million, respectively, relating to its exploration and development efforts.

The following table summarizes restricted stock activity for the nine months ended September 30, 2018:



	Number of Unvested Restricted Shares		Weighted Average Grant Date Fair Value
Unvested shares as of January 1, 2018	976,027		$	18.71
Granted	1,197,628		9.45
Vested	(618,202	)	17.77
Forfeited	(32,633	)	17.31
Unvested shares as of September 30, 2018	1,522,820		$	11.84

Unrecognized compensation expense as of September 30, 2018 related to restricted shares was $15.5 million. The expense is expected to be recognized over a weighted average period of 1.63 years.

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8.	EARNINGS PER SHARE

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



	Three months ended September 30,
	2018					2017
	Income		Shares	Per Share		Income		Shares	Per Share
	(In thousands, except share data)
Basic:
Net income	$	95,150	173,057,538	$	0.55	$	18,235	182,957,416	$	0.10
Effect of dilutive securities:
Stock options and awards	—		247,376			—		51,020
Diluted:
Net income	$	95,150	173,304,914	$	0.55	$	18,235	183,008,436	$	0.10




	Nine months ended September 30,
	2018					2017
	Income		Shares	Per Share		Income		Shares	Per Share
	(In thousands, except share data)
Basic:
Net income	$	296,559	175,776,312	$	1.69	$	278,626	178,736,569	$	1.56
Effect of dilutive securities:
Stock options and awards	—		664,149			—		394,001
Diluted:
Net income	$	296,559	176,440,461	$	1.68	$	278,626	179,130,570	$	1.56

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9.	COMMITMENTS AND CONTINGENCIES

Plugging and Abandonment Funds

In connection with the Company’s acquisition in 1997 of the remaining 50% interest in its WCBB properties, the Company assumed the seller’s (Chevron) obligation to contribute approximately $18,000 per month through March 2004 to a plugging and abandonment trust and the obligation to plug a minimum of 20 wells per year for 20 years commencing March 11, 1997. 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 September 30, 2018, the plugging and abandonment trust totaled approximately $3.1 million. At September 30, 2018, the Company had plugged 555 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 September 30, 2018 were as follows:



	(In thousands)
Remaining 2018	$	39
2019	144
2020	90
2021	38
Total	$	311

Firm Transportation and Sales Commitments

The Company had approximately 2,659,000 MMBtu per day of firm sales contracted with third parties. The table below presents these commitments at September 30, 2018 as follows:



		(MMBtu per day)
Remaining 2018		590,000
2019		659,000
2020		526,000
2021		372,000
2022		272,000
Thereafter		240,000
Total		2,659,000

The Company also had approximately $3.6 billion of firm transportation contracted with third parties. The table below presents these commitments at September 30, 2018 as follows:



	(In thousands)
Remaining 2018	$	62,012
2019	251,644
2020	247,581
2021	246,620
2022	246,620
Thereafter	2,511,853
Total	$	3,566,330

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Other Commitments

Effective October 1, 2014, the Company entered into a Sand Supply Agreement with Muskie Proppant LLC (“Muskie”), a subsidiary of Mammoth Energy. Effective August 3, 2018, the Company extended the agreement through December 31, 2021. 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 and $1.5 million in non-utilization fees under this agreement during the three and nine months ended September 30, 2018, respectively. The Company did not incur any non-utilization fees during the nine months ended September 30, 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. Pursuant to this agreement, as amended effective July 1, 2018, Stingray Pressure has agreed to provide hydraulic fracturing, stimulation and related completion and rework services to the Company and the Company has agreed to pay Stingray Pressure a monthly service fee plus the associated costs of the services provided. The Company has the right to suspend services of one crew and only one crew at any point in time without payment, fee or other obligation associated with the suspended crew, given appropriate notification of suspension.

Future minimum commitments under these agreements at September 30, 2018 are $154.2 million.

Litigation

In two separate complaints, one filed by the State of Louisiana and the Parish of Cameron in the 38th Judicial District Court for the Parish of Cameron on February 9, 2016 and the other filed by the State of Louisiana and the District Attorney for the 15^th Judicial District of the State of Louisiana in the 15^th Judicial District Court for the Parish of Vermilion 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 Vermilion Parish complaint, or the Complaints. The Complaints were filed under the State and Local Coastal Resources Management Act of 1978, as amended, and the rules, regulations, orders and ordinances adopted thereunder, which the Company referred to collectively as the CZM Laws, and allege that certain of the defendants’ oil and gas exploration, production and transportation operations associated with the development of the East Hackberry and West Hackberry oil and gas fields, in the case of the Cameron Parish complaint, and the Tigre Lagoon and Lac Blanc oil and gas fields, in the case of the Vermilion 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 Vermilion 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 Vermilion Parish suit. Shortly after the Complaints were filed, certain defendants removed the cases to the United States District Court for the Western District of Louisiana. In both cases, the plaintiffs filed motions to remand the lawsuits to state court, which were ultimately granted by the district courts. However, on May 23, 2018, a group of defendants again removed the Cameron Parish and Vermilion Parish lawsuits to federal court. In response, the plaintiffs again filed motions to remand the cases to state court. The removing defendants have opposed plaintiffs’ motions to remand. The motions to remand remain pending, and further action in the cases will be stayed until the courts rule on the motions to remand. Also, shortly after the May 23, 2018 removal, the removing defendants filed motions with the United States Judicial Panel on Multidistrict Litigation (the “MDL Panel”) requesting that the Cameron Parish and Vermilion Parish lawsuits be consolidated with 40 similar lawsuits so that pre-trial proceedings in the cases could be coordinated. The MDL Panel denied the motion to

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consolidate the lawsuits. Due to the procedural posture of lawsuits, the cases are still in their early stages and the parties have conducted very little discovery. As a result, the Company has not had the opportunity to evaluate the applicability of the allegations made in plaintiffs' complaints to the Company's operations and 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 ("NGLs") prices, which are subject to significant and often volatile fluctuation, by entering into over-the-counter fixed price swaps, basis swaps and various types of option contracts. These contracts allow the Company to predict with greater certainty the effective natural gas, oil and NGLs 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, pentane and ethane. Below is a summary of the Company’s open fixed price swap positions as of September 30, 2018.



	Location	Daily Volume (MMBtu/day)	Weighted Average Price
Remaining 2018	NYMEX Henry Hub	1,010,000	$	3.01
2019	NYMEX Henry Hub	1,154,000	$	2.81
2020	NYMEX Henry Hub	204,000	$	2.77



	Location	Daily Volume (Bbls/day)	Weighted Average Price
Remaining 2018	ARGUS LLS	2,000	$	56.22
2019	ARGUS LLS	1,000	$	59.55
Remaining 2018	NYMEX WTI	4,500	$	53.72
2019	NYMEX WTI	4,000	$	58.28



	Location	Daily Volume (Bbls/day)	Weighted Average Price
2019	Mont Belvieu C2	1,000	$	18.48
Remaining 2018	Mont Belvieu C3	4,000	$	29.34
2019	Mont Belvieu C3	4,000	$	28.87
Remaining 2018	Mont Belvieu C5	500	$	46.62
2019	Mont Belvieu C5	500	$	54.08

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
October 2018 - March 2019	NYMEX Henry Hub	50,000	$	3.13
April 2019 - December 2019	NYMEX Henry Hub	30,000	$	3.10

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

In addition, the Company entered into natural gas basis swap positions, which settle on the pricing index to basis differential of Transco Zone 4 to NYMEX Henry Hub natural gas price. As of September 30, 2018, the Company had the following natural gas basis swap positions for Transco Zone 4.



	Location	Daily Volume (MMBtu/day)	Weighted Average Price
Remaining 2018	Transco Zone 4	40,000	$	(0.05	)
2019	Transco Zone 4	60,000	$	(0.05	)
2020	Transco Zone 4	60,000	$	(0.05	)

Balance Sheet Presentation

The Company reports the fair value of derivative instruments on the consolidated balance sheets as derivative instruments under current assets, noncurrent assets, current liabilities and noncurrent liabilities on a gross basis. The Company determines the current and noncurrent classification based on the timing of expected future cash flows of individual trades. The following table presents the fair value of the Company’s derivative instruments on a gross basis at September 30, 2018 and December 31, 2017:



	September 30, 2018		December 31, 2017
	(In thousands)
Short-term derivative instruments - asset	$	19,809	$	78,847
Long-term derivative instruments - asset	$	3,530	$	8,685
Short-term derivative instruments - liability	$	62,601	$	32,534
Long-term derivative instruments - liability	$	15,101	$	2,989

Gains and Losses

The following table presents the gain and loss recognized in net (loss) gain on natural gas, oil and NGL derivatives in the accompanying consolidated statements of operations for the three and nine months ended September 30, 2018 and 2017.



	Net (loss) gain on derivative instruments
	Three months ended September 30,						Nine months ended September 30,
	2018			2017			2018			2017
	(In thousands)
Natural gas derivatives	$	14,101		$	(7,077	)	$	(26,789	)	$	135,868
Oil derivatives	(11,610		)	(6,571		)	(45,176		)	12,477
Natural gas liquids derivatives	(12,154		)	(9,212		)	(24,772		)	(6,757		)
Total	$	(9,663	)	$	(22,860	)	$	(96,737	)	$	141,588

Offsetting of derivative assets and liabilities

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



	As of September 30, 2018
	Gross Assets (Liabilities)			Gross Amounts
	Presented in the			Subject to Master			Net
	Consolidated Balance Sheets			Netting Agreements			Amount
	(In thousands)
Derivative assets	$	23,339		$	(17,053	)	$	6,286
Derivative liabilities	$	(77,702	)	$	17,053		$	(60,649	)



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

Concentration of Credit Risk

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


11.	FAIR VALUE MEASUREMENTS

The Company records certain financial and non-financial assets and liabilities on the balance sheet at fair value in accordance with ASC 820, Fair Value Measurement and Disclosures (“ASC 820”). 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

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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 ASC 820 valuation level as of September 30, 2018 and December 31, 2017:



	September 30, 2018
	Level 1		Level 2		Level 3
	(In thousands)
Assets:
Derivative Instruments	$	—	$	23,339	$	—
Liabilities:
Derivative Instruments	$	—	$	77,702	$	—



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

The Company estimates the fair value of all derivative instruments using industry-standard models that consider various assumptions, including current market and contractual prices for the underlying instruments, implied volatility, time value, nonperformance risk, as well as other relevant economic measures. Substantially all of these inputs are observable in the marketplace throughout the full term of the instrument and can be supported by observable data.

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

The Company estimates asset retirement obligations pursuant to the provisions of ASC Topic 410, Asset Retirement and Environmental Obligations (“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 nine months ended September 30, 2018 were approximately $1.5 million.

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


12.	FAIR VALUE OF FINANCIAL INSTRUMENTS

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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 September 30, 2018, the carrying value of the outstanding debt represented by the Notes was approximately $2.0 billion, including the unamortized debt issuance cost of approximately $4.6 million related to the 2023 Notes, approximately $9.0 million related to the 2024 Notes, approximately $12.9 million related to the 2025 Notes and approximately $5.2 million related to the 2026 Notes. Based on the quoted market price, the fair value of the Notes was determined to be approximately $2.0 billion at September 30, 2018.


13.	REVENUE FROM CONTRACTS WITH CUSTOMERS

Revenue Recognition

On January 1, 2018, the Company adopted Accounting Standards Update ("ASU") No. 2014-09, Revenue from Contracts with Customers ("ASC 606") using the modified retrospective transition applied to contracts that were not completed as of that date. The adoption did not result in a material change in the Company’s accounting or have a material effect on the Company’s financial position, including measurement of revenue, the timing of revenue recognition and the recognition of contract assets, liabilities and related costs. For periods through December 31, 2017, the Company accounted for its revenue using ASC 605, Revenue Recognition.

The Company’s revenues are primarily derived from the sale of natural gas, oil and condensate and NGLs. Sales of natural gas, oil and condensate and NGLs are recognized in the period that the performance obligations are satisfied. The Company generally considers the delivery of each unit (MMBtu or Bbl) to be separately identifiable and represents a distinct performance obligation that is satisfied at a point-in-time once control of the product has been transferred to the customer. The Company considers a variety of facts and circumstances in assessing the point of control transfer, including but not limited to (i) whether the purchaser can direct the use of the product, (ii) the transfer of significant risks, (iii) the Company’s right to payment and (iv) transfer of legal title.

Revenue is measured based on consideration specified in the contract with the customer, and excludes any amounts collected on behalf of third parties. These contracts typically include variable consideration that is based on pricing tied to market indices and volumes delivered in the current month. As such, this market pricing may be constrained (i.e., not estimable) at the inception of the contract but will be recognized based on the applicable market pricing, which will be known upon transfer of the goods to the customer. The payment date is usually within 30 days of the end of the calendar month in which the commodity is delivered.

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

The Company has elected to exclude from the measurement of the transaction price all taxes assessed by governmental authorities that are both imposed on and concurrent with a specific revenue-producing transaction and collected by the Company from a customer, such as sales tax, use tax, value-added tax and similar taxes.

Transaction Price Allocated to Remaining Performance Obligations

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

For product sales that have a contract term greater than one year, the Company has utilized the practical expedient that exempts the Company from disclosure of the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product generally represents a separate performance obligation; therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. Currently, the Company's product sales

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that have a contractual term greater than one year have no long-term fixed consideration.

Contract Balances

Receivables from contracts with customers are recorded when the right to consideration becomes unconditional, generally when control of the product has been transferred to the customer. Receivables from contracts with customers were $157.4 million and $146.8 million as of September 30, 2018 and December 31, 2017, respectively, and are reported in accounts receivable - oil and natural gas sales on the consolidated balance sheet. The Company currently has no assets or liabilities related to its revenue contracts, including no upfront or rights to deficiency payments.

Contract Modifications

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

Prior-Period Performance Obligations

The Company records revenue in the month production is delivered to the purchaser. However, settlement statements for certain gas and NGLs sales may be received for 30 to 90 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production that was delivered to the purchaser and the price that will be received for the sale of the product. The differences between the estimates and the actual amounts for product sales is recorded in the month that payment is received from the purchaser. The Company has internal controls in place for the estimation process and any identified differences between revenue estimates and actual revenue received historically have not been significant. For the nine months ended September 30, 2018, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.

14. INCOME TAXES

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

For the three and nine months ended September 30, 2018, the Company's estimated annual effective tax rate remained nominal as a result of the full valuation allowance on deferred tax assets. Based on the Company's estimated results for the year ending December 31, 2018, the Company anticipates remaining in a net deferred tax asset position. Based on the available positive and negative evidence, the Company expects to maintain a full valuation allowance as it cannot objectively assert that the deferred tax assets are more likely than not to be realized. A significant piece of negative evidence is the cumulative loss incurred over the three year period ending September 30, 2018. However, given the Company's current earnings and anticipated future earnings, it believes that there is a reasonable possibility that within the next 12 months sufficient positive evidence regarding recent cumulative income may become available, which may allow it to reach a conclusion that a significant portion of the valuation allowance will no longer be needed. Release of the valuation allowance would result in the recognition of certain net deferred tax assets and a decrease to income tax expense for the period the release is recorded. However, the exact timing and amount of any potential valuation allowance release is subject to change based on the levels of profitability that the Company is able to actually achieve.

On December 22, 2017, the President of the United States signed into law Public Law No. 115-97, a comprehensive tax reform bill commonly referred to as the Tax Cuts and Jobs Act ("Tax Act") that significantly reformed the Internal Revenue Code of 1986, as amended. The Tax Act substantially revised numerous areas of U.S. federal income tax law, including reducing the maximum corporate income tax rate from 35% to 21%, allowing for full expensing of certain capital expenditures, modifying the limitations on the utilization of net operating losses, and repealing the corporate alternative minimum tax. The various estimates included in determining the Company's tax provision as of December 31, 2017 remain provisional through the nine months ended September 30, 2018 and may be adjusted through subsequent events such as the filing of its 2017 consolidated federal income tax return and the issuance of additional guidance from the Internal Revenue Service or from state tax authorities. There were no material changes to the provisional estimates during the quarter ended September 30, 2018.

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15. CONDENSED CONSOLIDATING FINANCIAL INFORMATION

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

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

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

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

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

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

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

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CONDENSED CONSOLIDATING BALANCE SHEETS

(Amounts in thousands)



	September 30, 2018
	Parent			Guarantors			Non-Guarantor			Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	89,214		$	35,357		$	—		$	—		$	124,571
Accounts receivable - oil and natural gas sales	111,463			45,928			—			—			157,391
Accounts receivable - joint interest and other	19,066			20,445			—			—			39,511
Accounts receivable - related parties	79			—			—			—			79
Accounts receivable - intercompany	662,319			240,373			—			(902,692		)	—
Prepaid expenses and other current assets	7,521			2,221			—			—			9,742
Short-term derivative instruments	19,809			—			—			—			19,809
Total current assets	909,471			344,324			—			(902,692		)	351,103

Property and equipment:
Oil and natural gas properties, full-cost accounting	7,003,396			2,934,047			—			(729		)	9,936,714
Other property and equipment	91,637			751			—			—			92,388
Accumulated depletion, depreciation, amortization and impairment	(4,506,267		)	(39		)	—			—			(4,506,306		)
Property and equipment, net	2,588,766			2,934,759			—			(729		)	5,522,796
Other assets:
Equity investments and investments in subsidiaries	2,723,140			—			53,380			(2,543,991		)	232,529
Long-term derivative instruments	3,530			—			—			—			3,530
Inventories	6,800			1,434			—			—			8,234
Other assets	13,018			4,020			—			—			17,038
Total other assets	2,746,488			5,454			53,380			(2,543,991		)	261,331
Total assets	$	6,244,725		$	3,284,537		$	53,380		$	(3,447,412	)	$	6,135,230

Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable and accrued liabilities	$	464,426		$	118,038		$	—		$	—		$	582,464
Accounts payable - intercompany	240,310			662,254			128			(902,692		)	—
Asset retirement obligation - current	120			—			—			—			120
Short-term derivative instruments	62,601			—			—			—			62,601
Current maturities of long-term debt	647			—			—			—			647
Total current liabilities	768,104			780,292			128			(902,692		)	645,832
Long-term derivative instruments	15,101			—			—			—			15,101
Asset retirement obligation - long-term	65,634			12,777			—			—			78,411
Deferred tax liability	3,046			—			—			—			3,046
Long-term debt, net of current maturities	2,100,825			—			—			—			2,100,825
Total liabilities	2,952,710			793,069			128			(902,692		)	2,843,215

Stockholders’ equity:
Common stock	1,732			—			—			—			1,732
Paid-in capital	4,316,006			1,915,598			261,626			(2,177,224		)	4,316,006
Accumulated other comprehensive (loss) income	(46,354		)	—			(44,338		)	44,338			(46,354		)
Retained (deficit) earnings	(979,369		)	575,870			(164,036		)	(411,834		)	(979,369		)
Total stockholders’ equity	3,292,015			2,491,468			53,252			(2,544,720		)	3,292,015
Total liabilities and stockholders’ equity	$	6,244,725		$	3,284,537		$	53,380		$	(3,447,412	)	$	6,135,230

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CONDENSED CONSOLIDATING BALANCE SHEETS

(Amounts in thousands)



	December 31, 2017
	Parent			Guarantors			Non-Guarantor			Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	67,908		$	31,649		$	—		$	—		$	99,557
Accounts receivable - oil and natural gas sales	112,686			34,087			—			—			146,773
Accounts receivable - joint interest and other	15,435			20,005			—			—			35,440
Accounts receivable - intercompany	554,439			63,374			—			(617,813		)	—
Prepaid expenses and other current assets	4,719			193			—			—			4,912
Short-term derivative instruments	78,847			—			—			—			78,847
Total current assets	834,034			149,308			—			(617,813		)	365,529

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

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

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

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CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

(Amounts in thousands)



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

Total revenues	$	235,683		$	125,279		$	—		$	—		$	360,962

Costs and expenses:
Lease operating expenses	16,502			5,823			—			—			22,325
Production taxes	4,505			4,843			—			—			9,348
Midstream gathering and processing	54,397			24,516			—			—			78,913
Depreciation, depletion and amortization	119,914			1			—			—			119,915
General and administrative	16,314			(467		)	1			—			15,848
Accretion expense	812			225			—			—			1,037
	212,444			34,941			1			—			247,386

INCOME (LOSS) FROM OPERATIONS	23,239			90,338			(1		)	—			113,576

OTHER (INCOME) EXPENSE:
Interest expense	34,254			(1,001		)	—			—			33,253
Interest income	(86		)	(6		)	—			—			(92		)
Litigation settlement	917			—			—			—			917
Gain on sale of equity method investments	(2,733		)	—			—			—			(2,733		)
(Income) loss from equity method investments and investments in subsidiaries	(104,226		)	(1		)	275			91,094			(12,858		)
Other income	(37		)	(24		)	—			—			(61		)
	(71,911		)	(1,032		)	275			91,094			18,426

INCOME (LOSS) BEFORE INCOME TAXES	95,150			91,370			(276		)	(91,094		)	95,150
INCOME TAX BENEFIT	—			—			—			—			—

NET INCOME (LOSS)	$	95,150		$	91,370		$	(276	)	$	(91,094	)	$	95,150

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CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

(Amounts in thousands)



	Three months ended September 30, 2017
	Parent			Guarantors			Non-Guarantor			Eliminations			Consolidated

Total revenues	$	188,390		$	77,108		$	—		$	—		$	265,498

Costs and expenses:
Lease operating expenses	16,019			4,001			—			—			20,020
Production taxes	4,052			1,367			—			—			5,419
Midstream gathering and processing	52,725			16,647			—			—			69,372
Depreciation, depletion and amortization	106,649			1			—			—			106,650
General and administrative	13,956			(892		)	1			—			13,065
Accretion expense	335			121			—			—			456
Acquisition expense	(5		)	38			—			—			33
	193,731			21,283			1			—			215,015

(LOSS) INCOME FROM OPERATIONS	(5,341		)	55,825			(1		)	—			50,483

OTHER (INCOME) EXPENSE:
Interest expense	27,914			(784		)	—			—			27,130
Interest income	(29		)	(8		)	—			—			(37		)
(Income) loss from equity method investments and investments in subsidiaries	(53,880		)	128			296			56,193			2,737
Other income	(344		)	(1		)	—			—			(345		)
	(26,339		)	(665		)	296			56,193			29,485

INCOME (LOSS) BEFORE INCOME TAXES	20,998			56,490			(297		)	(56,193		)	20,998
INCOME TAX EXPENSE	2,763			—			—			—			2,763

NET INCOME (LOSS)	$	18,235		$	56,490		$	(297	)	$	(56,193	)	$	18,235

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CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

(Amounts in thousands)



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

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

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

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

OTHER (INCOME) EXPENSE:
Interest expense	103,310			(2,388		)	—			—			100,922
Interest income	(144		)	(18		)	—			—			(162		)
Litigation settlement	917			—			—			—			917
Insurance proceeds	(231		)	—			—			—			(231		)
Gain on sale of equity method investments	(28,349		)	(96,419		)	—			—			(124,768		)
(Income) loss from equity method investments and investments in subsidiaries	(387,991		)	(694		)	833			352,570			(35,282		)
Other (income) expense	(1,167		)	(34		)	—			1,000			(201		)
	(313,655		)	(99,553		)	833			353,570			(58,805		)

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

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

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CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

(Amounts in thousands)



	Nine months ended September 30, 2017
	Parent			Guarantors			Non-Guarantor			Eliminations			Consolidated

Total revenues	$	710,184		$	212,271		$	—		$	—		$	922,455

Costs and expenses:
Lease operating expenses	49,891			10,153			—			—			60,044
Production taxes	10,799			3,665			—			—			14,464
Midstream gathering and processing	132,740			43,518			—			—			176,258
Depreciation, depletion, and amortization	254,884			3			—			—			254,887
General and administrative	39,882			(1,963		)	3			—			37,922
Accretion expense	908			240			—			—			1,148
Acquisition expense	—			2,391			—			—			2,391
	489,104			58,007			3			—			547,114

INCOME (LOSS) FROM OPERATIONS	221,080			154,264			(3		)	—			375,341

OTHER (INCOME) EXPENSE:
Interest expense	79,095			(4,298		)	—			—			74,797
Interest income	(913		)	(14		)	—			—			(927		)
Gain on sale of equity method investments	(12,523		)	—			—			—			(12,523		)
(Income) loss from equity method investments and investments in subsidiaries	(124,446		)	2,586			869			154,459			33,468
Other (income) expense	(1,522		)	(241		)	—			900			(863		)
	(60,309		)	(1,967		)	869			155,359			93,952

INCOME (LOSS) BEFORE INCOME TAXES	281,389			156,231			(872		)	(155,359		)	281,389
INCOME TAX EXPENSE	2,763			—			—			—			2,763

NET INCOME (LOSS)	$	278,626		$	156,231		$	(872	)	$	(155,359	)	$	278,626

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CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Amounts in thousands)



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

Net income (loss)	$	95,150	$	91,370	$	(276	)	$	(91,094	)	$	95,150
Foreign currency translation adjustment	3,052		103		2,949			(3,052		)	3,052
Other comprehensive income (loss)	3,052		103		2,949			(3,052		)	3,052
Comprehensive income (loss)	$	98,202	$	91,473	$	2,673		$	(94,146	)	$	98,202



	Three months ended September 30, 2017
	Parent		Guarantors		Non-Guarantor			Eliminations			Consolidated

Net income (loss)	$	18,235	$	56,490	$	(297	)	$	(56,193	)	$	18,235
Foreign currency translation adjustment	6,832		158		6,674			(6,832		)	6,832
Other comprehensive income (loss)	6,832		158		6,674			(6,832		)	6,832
Comprehensive income (loss)	$	25,067	$	56,648	$	6,377		$	(63,025	)	$	25,067



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

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



	Nine months ended September 30, 2017
	Parent		Guarantors		Non-Guarantor			Eliminations			Consolidated

Net income (loss)	$	278,626	$	156,231	$	(872	)	$	(155,359	)	$	278,626
Foreign currency translation adjustment	12,719		232		12,487			(12,719		)	12,719
Other comprehensive income (loss)	12,719		232		12,487			(12,719		)	12,719
Comprehensive income (loss)	$	291,345	$	156,463	$	11,615		$	(168,078	)	$	291,345

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CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

(Amounts in thousands)



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

Net cash provided by (used in) operating activities	$	416,833		$	192,123		$	(1	)	$	1		$	608,956

Net cash (used in) provided by investing activities	(344,330		)	(188,415		)	(2,318		)	2,318			(532,745		)

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

Net increase in cash, cash equivalents and restricted cash	21,306			3,708			—			—			25,014

Cash, cash equivalents and restricted cash at beginning of period	67,908			31,649			—			—			99,557

Cash, cash equivalents and restricted cash at end of period	$	89,214		$	35,357		$	—		$	—		$	124,571



	Nine months ended September 30, 2017
	Parent			Guarantors			Non-Guarantor			Eliminations			Consolidated

Net cash provided by (used in) operating activities	$	310,624		$	181,108		$	(1	)	$	2		$	491,733

Net cash (used in) provided by investing activities	(2,034,554		)	(1,554,063		)	(1,843		)	1,408,980			(2,181,480		)

Net cash provided by (used in) financing activities	354,143			1,407,137			1,845			(1,408,982		)	354,143

Net (decrease) increase in cash, cash equivalents and restricted cash	(1,369,787		)	34,182			1			—			(1,335,604		)

Cash, cash equivalents and restricted cash at beginning of period	1,458,882			1,993			—			—			1,460,875

Cash, cash equivalents and restricted cash at end of period	$	89,095		$	36,175		$	1		$	—		$	125,271

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16.	RECENT ACCOUNTING PRONOUNCEMENTS

In May 2014, the Financial Accounting Standards Board (“FASB”) issued ASC 606. ASC 606 supersedes existing industry specific revenue recognition guidance and increases disclosure requirements. 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 Company adopted ASC 606 as of January 1, 2018 using the modified retrospective transition method applied to contracts that were not completed as of that date. Results for reporting periods beginning after January 1, 2018 are presented under the new revenue standard. Under the modified retrospective method, the Company recognizes the cumulative effect of initially applying the new revenue standard as an adjustment to the opening balance of retained earnings; however, no adjustment was required as a result of adopting the new revenue standard. The comparative information has not been restated and continues to be reported under the historic accounting standards in effect for those periods. The impact of the adoption of the new revenue standard is not expected to be material to the Company’s net income on an ongoing basis.

In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842). The standard supersedes the previous lease guidance by requiring lessees to recognize a right-to-use asset and lease liability on the balance sheet for all leases with lease terms of greater than one year while maintaining substantially similar classifications for financing and operating leases. The guidance is effective for periods after December 15, 2018, and the Company will not early adopt. The Company expects to apply the transition method permitted by ASU No. 2018-11, Leases (Topic 842): Targeted Improvements, issued in August 2018, which permits an entity to recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption with no adjustment made to the comparative periods presented in the consolidated financial statements. The Company also expects to utilize the practical expedient provided by ASU 2018-11 to not separate non-lease components from the associated lease component and, instead, to account for those components as a single component if the non-lease components would be accounted for under ASC 606 and other conditions are met.

The Company has identified its portfolio of leased assets under the new standard and is in the process of evaluating the impact of this guidance on its consolidated financial statements and related disclosures. The adoption will increase asset and liability balances on the consolidated balance sheets due to the required recognition of right-of-use assets and corresponding lease liabilities; however, that impact is currently not known. The Company is in the process of designing processes and controls needed to comply with the requirements of the new standard, which includes the implementation of a lease accounting software solution to support lease portfolio management and accounting and disclosures.

Additionally, in January 2018, the FASB issued ASU No. 2018-01, Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842. The amendments in this update provide an optional expedient to not evaluate existing or expired land easements that were not previously accounted for under current leases guidance in Topic 840. An entity that elects this practical expedient should evaluate new or modified land easements beginning at the date of adoption. The Company does not currently account for any land easements under Topic 840 and plans to utilize this practical expedient in conjunction with the adoption of ASU 2016-02.

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 guidance is effective for periods after December 15, 2019, with early adoption permitted. 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 effect.

In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments. This ASU clarifies how certain cash receipts and cash payments should be classified and presented in the statement of cash flows. The Company adopted this standard in the first quarter of 2018 and has made an accounting policy election to classify distributions received from equity method investees using the nature of the distribution approach, which classifies distributions received from investees as either cash inflows from operating activities or cash inflows from investing activities in the statement of cash flows based on the nature of the activities of the investee that generated the distribution. The impact of adopting this ASU was not material to prior periods presented.

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In November 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash. This ASU requires that amounts generally described as restricted cash and restricted cash equivalents be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period amounts shown on the statement of cash flows and to provide a reconciliation of the totals in the statement of cash flows to the related captions in the balance sheet when the cash, cash equivalents, restricted cash, and restricted cash equivalents are presented in more than one line item on the balance sheet. The Company adopted this standard in the first quarter of 2018 using the retrospective transition method. The adoption of this standard had no impact on the statement of cash flows for the nine months ended September 30, 2018 and resulted in the addition of $185.0 million of restricted cash to the beginning cash balance and an increase to net cash used in investing activities by the same amount on the statement of cash flows for the nine months ended September 30, 2017.

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. The Company adopted this standard in the first quarter of 2018 with no significant effect on its financial statements or related disclosures.

In February 2018, the FASB issued ASU No. 2018-02, Income statement - Reporting Comprehensive Income (Topic 220) - Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income, which allows a reclassification from accumulated other comprehensive income to retained earnings for standard tax effects resulting from the Tax Cuts and Jobs Act of 2017. The amendment will be effective for reporting periods beginning after December 15, 2018, and early adoption is permitted. The Company is currently assessing the impact of the ASU on its consolidated financial statements and related disclosures.

In August 2018, the FASB issued ASU No. 2018-13, Fair Value Measurement (Topic 820): Disclosure Framework—Changes to the Disclosure Requirements for Fair Value Measurement which removes, modifies, and adds certain disclosure requirements on fair value measurements. The amendment will be effective for reporting periods beginning after December 15, 2019, and early adoption is permitted. The Company is currently assessing the impact of the ASU on its consolidated financial statements and related disclosures.

In August 2018, the FASB also issued ASU No. 2018-15 , Intangibles—Goodwill and Other—Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract, which aligns the accounting for costs associated with implementing a cloud computing arrangement in a hosting arrangement that is a service contract with the accounting for implementation costs incurred to develop or obtain internal-use software. The amendment will be effective for reporting periods beginning after December 15, 2019, and early adoption is permitted. The Company is currently assessing the impact of the ASU on its consolidated financial statements and related disclosures.


17.	SUBSEQUENT EVENTS

At September 30, 2018, accounts receivable-related parties totaled $79,000 and represented personal charges made by the former chief executive officer of the Company on his Company credit card. These charges were paid in full in October 2018 and no personal charges are currently outstanding.

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ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

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 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 22.0% equity interest in Mammoth Energy Services, Inc., or Mammoth Energy, an energy services company listed on the Nasdaq Global Select Market (TUSK). We seek to achieve reserve growth and increase our cash flow through our annual drilling programs.

2018 Operational and Other Highlights

•

Production increased 31% to 368,366 net million cubic feet of natural gas equivalent, or MMcfe, for the nine months ended September 30, 2018 from 281,318 MMcfe for the nine months ended September 30, 2017. Our net daily production for the nine months ended September 30, 2018 averaged 1,349.3 MMcfe per day and was comprised of approximately 89% natural gas, 8% natural gas liquids, or NGLs, and 3% oil.

•

During the nine months ended September 30, 2018, we spud 23 gross (19.6 net) wells in the Utica Shale, participated in an additional 28 gross (6.9 net) wells that were drilled by other operators on our Utica Shale acreage and recompleted 47 gross and net wells on our Louisiana acreage. In addition, during the nine months ended September 30, 2018, we spud 12 gross (11.0 net) wells in the SCOOP and participated in an additional 33 gross (3.0 net) wells that were drilled by other operators on our SCOOP acreage. Of the 35 new wells we spud, at September 30, 2018, 32 were in various stages of completion and three were being drilled. In addition, 28 gross and net operated wells and 29

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gross (9.1 net) non-operated wells were turned-to-sales in our Utica Shale operating area and 15 gross (12.6 net) operated wells and 29 gross (0.9 net) non-operated wells were turned-to-sales in our SCOOP operating area during the nine months ended September 30, 2018.


•	During the nine months ended September 30, 2018, we reduced our unit lease operating expense by 19% to $0.17 per Mcfe from $0.21 per Mcfe during the nine months ended September 30, 2017.


•	During the nine months ended September 30, 2018, we decreased our unit general and administrative expense by 8% to $0.12 per Mcfe from $0.13 per Mcfe during the nine months ended September 30, 2017.


•	During the nine months ended September 30, 2018, we decreased our unit midstream gathering and processing expense by 8% per Mcfe to $0.58 per Mcfe from $0.63 per Mcfe during the nine months ended September 30, 2017.

•

In January 2018, our board of directors approved a stock repurchase program to acquire up to $100.0 million of our outstanding common stock, and in May 2018 expanded this program to acquire up to an additional $100.0 million of our common stock, during 2018 for a total of up to $200.0 million, which we believe underscores the confidence we have in our business model, financial performance and asset base. During the nine months ended September 30, 2018, we purchased 10.5 million shares of our outstanding common stock for a total of approximately $110.0 million.


•	On May 1, 2018, we sold our 25% equity interest in Strike Force Midstream LLC, or Strike Force, to EQT Midstream Partners, LP for $175.0 million in cash.

•

On June 29, 2018, we sold 1,235,600 shares, and on July 30, 2018, we sold an additional 118,974 shares, of our Mammoth Energy common stock in an underwritten public offering and related partial exercise of the underwriters' option to purchase additional shares for net proceeds to us of approximately $47.0 million and $4.5 million, respectively. Following the sale of these shares, we owned 9,829,548 shares, or approximately 22.0%, of Mammoth Energy’s outstanding common stock.

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2018 Production and Drilling Activity

During the three months ended September 30, 2018, our total net production was 116,993,594 thousand cubic feet, or Mcf, of natural gas, 664,633 barrels of oil and 72,427,030 gallons of NGLs for a total of 131,328 MMcfe, as compared to 97,824,927 Mcf of natural gas, 685,316 barrels of oil and 59,007,909 gallons of NGLs, or 110,367 MMcfe, for the three months ended September 30, 2017. Our total net production averaged approximately 1,427.5 MMcfe per day during the three months ended September 30, 2018, as compared to 1,199.6 MMcfe per day during the same period in 2017. The 19% increase in production is largely the result of the continuing development of our Utica Shale acreage and the development of our SCOOP acreage.

Utica Shale. From January 1, 2018 through September 30, 2018, we spud 23 gross (19.6 net) wells in the Utica Shale, of which 22 were in various stages of completion and one was being drilled at September 30, 2018. We also participated in an additional 28 gross (6.9 net) wells that were drilled by other operators on our Utica Shale acreage. From October 1, 2018 through October 26, 2018, we did not spud any new wells in the Utica Shale.

As of October 26, 2018, we had completed our 2018 drilling activity in the Utica Shale and we do not have any rigs running in the play. We intend to commence sales from a total of 35 gross and net wells on our Utica Shale acreage in 2018.

Aggregate net production from our Utica Shale acreage during the three months ended September 30, 2018 was approximately 104,975 MMcfe, or an average of 1,141.0 MMcfe per day, of which 96% was from natural gas and 4% was from oil and NGLs.

SCOOP. From January 1, 2018 through September 30, 2018, we spud 12 gross (11.0 net) wells in the SCOOP, of which two were being drilled and ten were in various stages of completion at September 30, 2018. We also participated in an additional 33 gross (3.0 net) wells that were drilled by other operators on our SCOOP acreage. From October 1, 2018 through October 26, 2018, we spud one gross and net well.

As of October 26, 2018, we had two operated horizontal rigs running on our SCOOP acreage. We currently expect to spud a total of 15 gross (13 net) horizontal wells during 2018 and have concluded our completion activity for the year with a total of 15 gross (12 net) wells turned to sales on our SCOOP acreage during 2018.

Aggregate net production from our SCOOP acreage during the three months ended September 30, 2018 was approximately 25,259 MMcfe, or an average of 274.6 MMcfe per day, of which 66% was from natural gas and 34% was from oil and NGLs.

WCBB. From January 1, 2018 through October 26, 2018, we did not spud any new wells and recompleted 32 wells. Aggregate net production from the WCBB field during the three months ended September 30, 2018 was approximately 841 MMcfe, or an average of 9.1 MMcfe per day, of which 99% was from oil and 1% was from natural gas.

East Hackberry Field. From January 1, 2018 through October 26, 2018, we did not spud any new wells and recompleted 15 wells. Aggregate net production from the East Hackberry field during the three months ended September 30, 2018 was approximately 147 MMcfe, or an average of 1.6 MMcfe per day, all of which was from oil.

West Hackberry Field. From January 1, 2018 through October 26, 2018, we did not spud any wells in our West Hackberry field. Aggregate net production from the West Hackberry field during the three months ended September 30, 2018 was approximately 21.2 MMcfe, or an average of 230.7 Mcfe per day, all of which was from oil.

We currently intend to perform only recompletion activities on our acreage in Southern Louisiana in 2018.

Niobrara Formation. From January 1, 2018 through October 26, 2018, there were no wells spud on our Niobrara Formation acreage. Aggregate net production was approximately 22.4 MMcfe, or an average of 243.4 Mcfe per day during the three months ended September 30, 2018, all of which was from oil.

Bakken. As of September 30, 2018, we had an interest in 18 wells and overriding royalty interests in certain existing and future wells. Aggregate net production from this acreage during the three months ended September 30, 2018 was approximately 60.5 MMcfe, or an average of 657.5 Mcfe per day, of which 80% was from oil, 13% was from natural gas and 7% was from NGLs.

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2018 Update Regarding Our Equity Investments

Mammoth Energy Services, Inc.

Strike Force Midstream LLC

On May 1, 2018, we sold our 25% interest in Strike Force to EQT Midstream Partners, LP for proceeds of $175.0 million in cash.

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 $2.9 billion at September 30, 2018 and $2.9 billion at December 31, 2017. 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 September 30, 2018, the calculated

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ceiling was greater than the net book value of our oil and natural gas properties, thus no ceiling test impairment was required for the nine months ended September 30, 2018. 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.

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 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, 2017 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. Quarterly, 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

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deferred tax assets is established, if in management’s opinion, it is more likely than not that some portion will not be realized. At September 30, 2018, a valuation allowance of $236.1 million had been provided against the net deferred tax asset.

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.

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 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 instrument depends on the intended use of the derivative and the resulting designation. 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 September 30, 2018.

RESULTS OF OPERATIONS

Comparison of the Three Months Ended September 30, 2018 and 2017

We reported net income of $95.2 million for the three months ended September 30, 2018 as compared to net income of $18.2 million for the three months ended September 30, 2017. This $77.0 million period-to-period increase was due primarily to a $95.5 million increase in natural gas, oil and NGL revenues, a $15.6 million increase in income from equity method investments and a $2.7 million increase in gain on sale of equity investments, partially offset by a $9.5 million increase in midstream gathering and processing expenses, a $6.1 million increase in interest expense and a $13.3 million increase in depreciation, depletion and amortization for the three months ended September 30, 2018 as compared to the three months ended September 30, 2017. The gain on sale of equity investments in 2018 is a result of our sale of Mammoth Energy common stock during the three months ended September 30, 2018.

Oil and Gas Revenues. For the three months ended September 30, 2018, we reported natural gas, oil and NGL revenues of $361.0 million as compared to oil and natural gas revenues of $265.5 million during the same period in 2017. This $95.5 million, or 36%, increase in revenues was primarily attributable to the following:


•	A $13.3 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, $32.9 million was due to favorable changes in the fair value of our open derivative positions in each period, partially offset by a $19.6 million unfavorable change in settlements related to our

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derivative positions. The favorable change in fair value of our open derivative positions is primarily a result of the decrease in the forward curve prices for natural gas from the previous reporting period.


•	A $47.8 million increase in natural gas sales without the impact of derivatives due to a 20% increase in natural gas sales volumes and a 2% increase in natural gas market prices.


•	A $14.2 million increase in oil and condensate sales without the impact of derivatives due to a 50% increase in oil and condensate market prices, partially offset by a 3% decrease in oil and condensate sales volumes.


•	A $20.2 million increase in natural gas liquids sales without the impact of derivatives due to a 30% increase in natural gas liquids market prices and a 23% 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 September 30, 2018, as compared to such data for the three months ended September 30, 2017:

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	Three months ended September 30,
	2018			2017
	($ In thousands)
Natural gas sales
Natural gas production volumes (MMcf)	116,994			97,825

Total natural gas sales	$	271,167		$	223,340

Natural gas sales without the impact of derivatives ($/Mcf)	$	2.32		$	2.28
Impact from settled derivatives ($/Mcf)	$	0.08		$	0.13
Average natural gas sales price, including settled derivatives ($/Mcf)	$	2.40		$	2.41

Oil and condensate sales
Oil and condensate production volumes (MBbls)	665			685

Total oil and condensate sales	$	45,682		$	31,459

Oil and condensate sales without the impact of derivatives ($/Bbl)	$	68.73		$	45.90
Impact from settled derivatives ($/Bbl)	$	(14.76	)	$	4.36
Average oil and condensate sales price, including settled derivatives ($/Bbl)	$	53.97		$	50.26

Natural gas liquids sales
Natural gas liquids production volumes (MGal)	72,427			59,008

Total natural gas liquids sales	$	53,776		$	33,559

Natural gas liquids sales without the impact of derivatives ($/Gal)	$	0.74		$	0.57
Impact from settled derivatives ($/Gal)	$	(0.07	)	$	(0.03	)
Average natural gas liquids sales price, including settled derivatives ($/Gal)	$	0.67		$	0.54

Natural gas, oil and condensate and natural gas liquids sales
Natural gas equivalents (MMcfe)	131,328			110,367

Total natural gas, oil and condensate and natural gas liquids sales	$	370,625		$	288,358

Natural gas, oil and condensate and natural gas liquids sales without the impact of derivatives ($/Mcfe)	$	2.82		$	2.61
Impact from settled derivatives ($/Mcfe)	$	(0.04	)	$	0.13
Average natural gas, oil and condensate and natural gas liquids sales price, including settled derivatives ($/Mcfe)	$	2.78		$	2.74

Production Costs:
Average production costs (per Mcfe)	$	0.17		$	0.18
Average production taxes and midstream costs (per Mcfe)	$	0.67		$	0.68
Total production and midstream costs and production taxes (per Mcfe)	$	0.84		$	0.86

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Lease Operating Expenses. Lease operating expenses, or LOE, not including production taxes increased to $22.3 million for the three months ended September 30, 2018 from $20.0 million for the three months ended September 30, 2017. This $2.3 million increase was primarily the result of an increase in expenses related to water hauling and disposal and field telemetry, partially offset by a decrease in location and facility repairs and maintenance, surface rentals, compression and contract labor and field supervision. In addition, due to increased efficiencies and a 19% increase in our production volumes for the three months ended September 30, 2018 as compared to the three months ended September 30, 2017, our per unit LOE decreased by 6% from $0.18 per Mcfe to $0.17 per Mcfe.

Production Taxes. Production taxes increased $3.9 million to $9.3 million for the three months ended September 30, 2018 from $5.4 million for the three months ended September 30, 2017. This increase was related to an increase in production volumes.

Midstream Gathering and Processing Expenses. Midstream gathering and processing expenses increased $9.5 million to $78.9 million for the three months ended September 30, 2018 from $69.4 million for the same period in 2017. This increase was primarily attributable to midstream expenses related to our increased production volumes in the Utica Shale and SCOOP resulting from our 2017 and 2018 drilling activities.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization, or DD&A, expense increased to $119.9 million for the three months ended September 30, 2018, and consisted of $117.3 million in depletion of oil and natural gas properties and $2.6 million in depreciation of other property and equipment, as compared to total DD&A expense of $106.7 million for the three months ended September 30, 2017. This increase was due to an increase in our full cost pool 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 $15.8 million for the three months ended September 30, 2018 from $13.1 million for the three months ended September 30, 2017. This $2.7 million increase was due to increases in salaries and benefits, employee stock compensation, computer expense and legal fees, partially offset by a decrease in consulting fees.

Interest Expense. Interest expense increased to $33.3 million for the three months ended September 30, 2018 from $27.1 million for the three months ended September 30, 2017 due primarily to the issuance of $450.0 million in aggregate principal amount of our 6.375% Senior Notes due 2026, or the 2026 Notes, in October 2017. In addition, total weighted average debt outstanding under our revolving credit facility was $74.0 million for the three months ended September 30, 2018 as compared to $273.7 million debt outstanding under such facility for the same period in 2017. As of September 30, 2018, amounts borrowed under our revolving credit facility bore interest at the Eurodollar rate which resulted in a weighted average rate of 3.72%. In addition, we capitalized approximately $1.6 million and $2.1 million in interest expense to undeveloped oil and natural gas properties during the three months ended September 30, 2018 and 2017, respectively. This decrease in capitalized interest in the 2018 period was primarily the result of changes to our development plan for our oil and natural gas properties.

Income Taxes. As of September 30, 2018, we had a federal net operating loss carryforward of approximately $312.2 million from prior years, in addition to numerous temporary differences, which gave rise to a net deferred tax asset. Quarterly, management performs a forecast of our taxable income 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 September 30, 2018, a valuation allowance of $236.1 million had been provided against the net deferred tax assets. On December 22, 2017, the President of the United States signed into law the Tax Cuts and Jobs Act. Further information on the tax impacts of the Tax Cuts and Jobs Act is included in Note 14 of our consolidated financial statements.

Comparison of the Nine Months Ended September 30, 2018 and 2017

We reported net income of $296.6 million for the nine months ended September 30, 2018 as compared to net income of $278.6 million for the nine months ended September 30, 2017. This $18.0 million period-to-period increase was due primarily to an increase in income from equity method investments of $68.8 million, a $112.2 million increase in gain on sale of equity investments and a $16.6 million increase in natural gas, oil and NGL revenues, partially offset by a $38.2 million increase in midstream gathering and processing expenses, a $26.1 million increase in interest expense, a $98.0 million increase in depreciation, depletion and amortization and a $9.4 million increase in production taxes for the nine months ended September 30, 2018 as compared to the nine months ended September 30, 2017. The gain on sale of equity investments in 2018 is a result of our sale of our interest in Strike Force and sale of Mammoth Energy common stock during 2018.

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Oil and Gas Revenues. For the nine months ended September 30, 2018, we reported oil and natural gas revenues of $939.1 million as compared to oil and natural gas revenues of $922.5 million during the same period in 2017. This $16.6 million, or 2%, increase in revenues was primarily attributable to the following:

•

A $238.3 million decrease in natural gas, oil and NGL sales due to an unfavorable change in gains and losses from derivative instruments. Of the total change, $236.0 million was due to unfavorable changes in the fair value of our open derivative positions in each period. In addition, $2.3 million of this decrease was due to an unfavorable change in settlements related to our derivative positions. The loss from changes in fair value of our open derivative positions is primarily the result of the increase in the forward curve prices for natural gas, oil and NGLs from the previous reporting period.


•	A $146.7 million increase in natural gas sales without the impact of derivatives due to a 32% increase in natural gas sales volumes, partially offset by a 6% decrease in natural gas market prices.


•	A $55.3 million increase in oil and condensate sales without the impact of derivatives due to a 41% increase in oil and condensate market prices and a 17% increase in oil and condensate sales volumes.


•	A $52.9 million increase in natural gas liquid sales without the impact of derivatives due to a 32% increase in natural gas liquids market prices and a 21% increase in natural gas liquids sales volumes.

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The following table summarizes our oil and natural gas production and related pricing for the nine months ended September 30, 2018, as compared to such data for the nine months ended September 30, 2017:



	Nine months ended September 30,
	2018			2017
	($ In thousands)
Natural gas sales
Natural gas production volumes (MMcf)	327,272			247,012

Total natural gas sales	$	753,261		$	606,544

Natural gas sales without the impact of derivatives ($/Mcf)	$	2.30		$	2.46
Impact from settled derivatives ($/Mcf)	$	0.14		$	0.03
Average natural gas sales price, including settled derivatives ($/Mcf)	$	2.44		$	2.49

Oil and condensate sales
Oil and condensate production volumes (MBbls)	2,166			1,849

Total oil and condensate sales	$	140,687		$	85,338

Oil and condensate sales without the impact of derivatives ($/Bbl)	$	64.96		$	46.15
Impact from settled derivatives ($/Bbl)	$	(10.28	)	$	2.92
Average oil and condensate sales price, including settled derivatives ($/Bbl)	$	54.68		$	49.07

Natural gas liquids sales
Natural gas liquids production volumes (MGal)	196,695			162,483

Total natural gas liquids sales	$	141,883		$	88,985

Natural gas liquids sales without the impact of derivatives ($/Gal)	$	0.72		$	0.55
Impact from settled derivatives ($/Gal)	$	(0.06	)	$	(0.01	)
Average natural gas liquids sales price, including settled derivatives ($/Gal)	$	0.66		$	0.54

Natural gas, oil and condensate and natural gas liquids sales
Gas equivalents (MMcfe)	368,366			281,318

Total natural gas, oil and condensate and natural gas liquids sales	$	1,035,831		$	780,867

Natural gas, oil and condensate and natural gas liquids sales without the impact of derivatives ($/Mcfe)	$	2.81		$	2.78
Impact from settled derivatives ($/Mcfe)	$	0.03		$	0.04
Average natural gas, oil and condensate and natural gas liquids sales price, including settled derivatives ($/Mcfe)	$	2.84		$	2.82

Production Costs:
Average production costs (per Mcfe)	$	0.17		$	0.21
Average production taxes and midstream costs (per Mcfe)	$	0.65		$	0.68
Total production and midstream costs and production taxes (per Mcfe)	$	0.82		$	0.89

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Lease Operating Expenses. Lease operating expenses, or LOE, not including production taxes increased to $64.1 million for the nine months ended September 30, 2018 from $60.0 million for the nine months ended September 30, 2017. This increase was mainly the result of an increase in expenses related to field supervision, overhead and water hauling and disposal, partially offset by a decrease in location repairs and maintenance, surface rentals, contract labor and compressors. However, due to increased efficiencies and a 31% increase in our production volumes for the nine months ended September 30, 2018 as compared to the nine months ended September 30, 2017, our per unit LOE decreased by 19% from $0.21 per Mcfe to $0.17 per Mcfe.

Production Taxes. Production taxes increased $9.4 million to $23.9 million for the nine months ended September 30, 2018 from $14.5 million for the same period in 2017. This increase was primarily related to an increase in production volumes, as well as changes in our product mix and production location.

Midstream Gathering and Processing Expenses. Midstream gathering and processing expenses increased by $38.2 million to $214.5 million for the nine months ended September 30, 2018 from $176.3 million for the same period in 2017. This increase was primarily attributable to midstream expenses related to our increased production volumes in the Utica Shale and SCOOP resulting from our 2017 and 2018 drilling activities.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization, or DD&A, expense increased to $352.8 million for the nine months ended September 30, 2018, and consisted of $345.1 million in depletion of oil and natural gas properties and $7.7 million in depreciation of other property and equipment, as compared to total DD&A expense of $254.9 million for the nine months ended September 30, 2017. This increase was due to an increase in our full cost pool 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 $43.0 million for the nine months ended September 30, 2018 from $37.9 million for the nine months ended September 30, 2017. This $5.1 million increase was due to increases in salaries and benefits, employee stock compensation expense, legal fees, travel expenses and computer support, partially offset by a decrease in group health insurance. However, during the nine months ended September 30, 2018, we decreased our unit general and administrative expense by 8% to $0.12 per Mcfe from $0.13 per Mcfe during the nine months ended September 30, 2017.

Interest Expense. Interest expense increased to $100.9 million for the nine months ended September 30, 2018 from $74.8 million for the nine months ended September 30, 2017 due primarily to the issuance of $450.0 million in aggregate principal amount of our 2026 Notes in October 2017. In addition, total weighted average debt outstanding under our revolving credit facility was $91.3 million for the nine months ended September 30, 2018 as compared to $146.0 million for the same period in 2017. Additionally, we capitalized approximately $4.0 million and $8.8 million in interest expense to undeveloped oil and natural gas properties during the nine months ended September 30, 2018 and September 30, 2017, respectively. This decrease in capitalized interest in the 2018 period was primarily the result of changes to our development plan for our oil and natural gas properties.

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.

Net cash flow provided by operating activities was $609.0 million for the nine months ended September 30, 2018 as compared to $491.7 million for the same period in 2017. This increase was primarily the result of an increase in cash receipts

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from our oil and natural gas purchasers due to a 32% increase in net revenues after giving effect to settled derivative instruments, partially offset by an increase in our operating expenses. In addition, we received $0.8 million in distributions from our investment in Strike Force and $1.2 million in dividends from our investment in Mammoth Energy.

Net cash used in investing activities for the nine months ended September 30, 2018 was $532.7 million as compared to $2.2 billion for the same period in 2017. During the nine months ended September 30, 2018, we spent $755.3 million in additions to oil and natural gas properties, of which $388.1 million was spent on our 2018 drilling, completion and recompletion activities, $192.0 million was spent on expenses attributable to wells spud, completed and recompleted during 2017, $2.1 million was spent on facility enhancements, $110.1 million was spent on lease related costs, primarily the acquisition of leases in the Utica Shale, with the remainder attributable mainly to future location development and capitalized general and administrative expenses. During the nine months ended September 30, 2018, we received $175.0 million from the sale of our equity investment in Strike Force and $51.5 million from the sale of Mammoth Energy's common stock. In addition, we invested $2.3 million in Grizzly, and we received $0.4 million in distributions from our investment in Timberwolf during the nine months ended September 30, 2018. We did not make any investments in our other equity investments during the nine months ended September 30, 2018. During the first quarter of 2017, we spent $1.3 billion to fund the cash portion of the purchase price for our SCOOP acquisition.

Net cash used in financing activities for the nine months ended September 30, 2018 was $51.2 million as compared to net cash provided by financing activities of $354.1 million for the same period in 2017. The 2018 amount used in financing activities is primarily attributable to purchases under our stock repurchase program of approximately $110.0 million, partially offset by net borrowings under our revolving credit facility.

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 September 30, 2018, we had a borrowing base of $1.4 billion, with an elected commitment of $1.0 billion, and $60.0 million in borrowings outstanding. Total funds available for borrowing under our revolving credit facility, after giving effect to an aggregate of $316.2 million of outstanding letters of credit, were $623.8 million as of September 30, 2018. This facility is secured by substantially all of our assets. Our wholly-owned subsidiaries guarantee our obligations under our revolving credit facility.

Advances under our revolving credit facility may be in the form of either base rate loans or eurodollar loans. The interest rate for base rate loans is equal to (1) the applicable rate, which ranges from 0.25% to 1.25%, plus (2) the highest of: (a) the federal funds rate plus 0.50%, (b) the rate of interest in effect for such day as publicly announced from time to time by agent as its “prime rate,” and (c) the eurodollar rate for an interest period of one month plus 1.00%. The interest rate for eurodollar loans is equal to (1) the applicable rate, which ranges from 1.25% to 2.25%, plus (2) the London interbank offered rate that appears on pages LIBOR01 or LIBOR02 of the Reuters screen that displays such rate for deposits in U.S. dollars, or, if such rate is not available, the rate as administered by ICE Benchmark Administration (or any other person that takes over administration of such rate) per annum equal to the offered rate on such other page or other service that displays an average London interbank offered rate as administered by ICE Benchmark Administration (or any other person that takes over the administration of such rate) for deposits in U.S. dollars, or, if such rate is not available, the average quotations for three major New York money center banks of whom the agent shall inquire as the “London Interbank Offered Rate” for deposits in U.S. dollars. As of September 30, 2018, amounts borrowed under our revolving credit facility bore interest at the Eurodollar rate which resulted in a weighted average rate of 3.72%.

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 such period, (d) all other non-cash charges, (e) exploration costs deducted in determining net income under successful efforts

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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 September 30, 2018.

Senior Notes.

In April 2015, we issued an aggregate of $350.0 million in principal amount of our Senior Notes due 2023, or the 2023 Notes. Interest on these senior notes accrues at a rate of 6.625% per annum on the outstanding principal amount thereof from April 21, 2015, payable semi-annually on May 1 and November 1 of each year, commencing on November 1, 2015. The 2023 Notes will mature on May 1, 2023.

On October 14, 2016, we issued an aggregate of $650.0 million in principal amount of our Senior Notes due 2024, or the 2024 Notes. Interest on the 2024 Notes accrues at a rate of 6.000% per annum on the outstanding principal amount thereof from October 14, 2016, payable semi-annually on April 15 and October 15 of each year, commencing on April 15, 2017. The 2024 Notes will mature on October 15, 2024.

On December 21, 2016, we issued an aggregate of $600.0 million in principal amount of our Senior Notes due 2025, or the 2025 Notes. Interest on the 2025 Notes accrues at a rate of 6.375% per annum on the outstanding principal amount thereof from December 21, 2016, payable semi-annually on May 15 and November 15 of each year, commencing on May 15, 2017. The 2025 Notes will mature on May 15, 2025.

On October 11, 2017, we issued $450.0 million in aggregate principal amount of our 2026 Notes. Interest on the 2026 Notes accrues at a rate of 6.375% per annum on the outstanding principal amount thereof from October 11, 2017, payable semi-annually on January 15 and July 15 of each year, commencing on January 15, 2018. The 2026 Notes will mature on January 15, 2026. We received approximately $444.1 million in net proceeds from the offering of the 2026 Notes, a portion of which was used to repay all of our outstanding borrowings under our secured revolving credit facility on October 11, 2017 and the balance was used to fund the remaining outspend related to our 2017 capital development plans.

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, 2025 Notes and 2026 Notes, provided, however, that the 2023 Notes, 2024 Notes, 2025 Notes and 2026 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, 2025 Notes and 2026 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, 2025 Notes and 2026 Notes.

If we experience a change of control (as defined in the senior note indentures relating to the 2023 Notes, 2024 Notes, 2025 Notes and 2026 Notes), we will be required to make an offer to repurchase the 2023 Notes, 2024 Notes, 2025 Notes and 2026 Notes and at a price equal to 101% of the principal amount thereof, plus accrued and unpaid interest, if any, to the date of repurchase. If we sell certain assets and fail to use the proceeds in a manner specified in our senior note indentures, we will be required to use the remaining proceeds to make an offer to repurchase the 2023 Notes, 2024, 2025 Notes and 2026 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, 2025 Notes and 2026 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, 2025 Notes and 2026 Notes, certain of these covenants are subject to termination upon the occurrence of certain events, including in the event the 2023 Notes, 2024 Notes, 2025 Notes and 2026 Notes are ranked as “investment grade.”

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

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 was payable on the last day of the month through May 31, 2017, after which date we began making monthly payments of interest and principal. The final payment is due June 4, 2025. As of September 30, 2018, the total borrowings under the construction loan were approximately $23.3 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, 2017, 64.9% 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, 2018 through September 30, 2018, we spud 23 gross (19.6 net) wells in the Utica Shale. As of October 26, 2018, we had completed our 2018 drilling activity in the Utica and we did not have any rigs running in the play. We intend to commence sales from a total of 35 gross and net wells on our Utica Shale acreage in 2018. We also anticipate an additional seven net horizontal wells will be drilled, and sales commenced from ten net horizontal wells, on our Utica Shale acreage by other operators during 2018. We currently anticipate our 2018 capital expenditures will be approximately $455.0 million related to our operated and non-operated Utica Shale drilling and completion activity.

From January 1, 2018 through September 30, 2018, we spud 12 gross (11.0 net) wells in the SCOOP. We currently anticipate our 2018 capital expenditures will be approximately $210.0 million related to our operated and non-operated SCOOP drilling and completion activity. As of October 26, 2018, we had two operated horizontal rigs running on our SCOOP acreage. We currently expect to spud a total of 15 gross (13 net) wells during 2018 and have concluded our completion activity for the year with a total of 15 gross (12 net) wells turned to sales on our SCOOP acreage during 2018. We also anticipate three net wells will be drilled, and sales commenced from four net wells, on this SCOOP acreage by other operators during 2018.

From January 1, 2018 through October 26, 2018, we recompleted 32 existing wells and spud no new wells at our WCBB field. In our Hackberry fields, from January 1, 2018 through October 26, 2018, we recompleted 15 existing wells and spud no new wells. We currently expect to spend approximately $20.0 million in 2018 to perform recompletion activities in Southern Louisiana.

From January 1, 2018 through October 26, 2018, no new wells were spud on our Niobrara Formation acreage. We do not currently anticipate any capital expenditures in the Niobrara Formation in 2018.

As of September 30, 2018, our net investment in Grizzly was approximately $53.4 million. We do not currently anticipate any material capital expenditures in 2018 related to Grizzly’s activities.

We had no capital expenditures during the nine months ended September 30, 2018 related to our interests in Thailand. We do not currently anticipate any capital expenditures in Thailand in 2018.

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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 to our consolidated financial statements included elsewhere in this report for additional information regarding these other investments. During the nine months ended September 30, 2018, we received $0.8 million in distributions from Strike Force. We did not make any investments in any other of these entities during the nine months ended September 30, 2018.

On May 1, 2018, we sold our 25% equity interest in Strike Force to EQT Midstream Partners, LP for $175.0 million in cash. As a result of this transaction, all future capital obligations associated with Strike Force were eliminated, including $20.0 million that had been budgeted for the balance of 2018.

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. In 2017, an increase in commodity prices allowed us to increase our capital budget as compared to 2016 and the resulting 2017 development activities enabled us to reach a size and scale, both financially and operationally, where we can navigate the current commodity price environment and adjust our business model accordingly. In response to forward natural gas prices, we are focused on delivering growth within cash flow by exercising strict capital discipline and, as such, currently expect to reduce our planned capital expenditures by approximately 25% as compared to 2017.

Our total capital expenditures for 2018 are currently estimated to be $685.0 million for drilling and completion expenditures, of which $638.1 million was spent as of September 30, 2018. In addition, we currently expect to spend approximately $130.0 million in 2018 for non-drilling and completion expenditures, which includes acreage expenses, primarily lease extensions in the Utica Shale, of which $96.3 million was spent as of September 30, 2018. Approximately 67% and 30% of our 2018 estimated drilling and completion capital expenditures are currently expected to be spent in the Utica Shale and in the SCOOP, respectively. The 2018 range of capital expenditures is lower than the $1.2 billion spent in 2017, primarily due to the decrease in current commodity prices, specifically natural gas prices, and our desire to fund our capital development program within cash flow.

In January 2018, our board of directors approved a stock repurchase program to acquire up to $100.0 million of our outstanding common stock during 2018, which we executed in full in the first quarter of 2018. Additionally, in May 2018, our board of directors authorized the expansion of the stock repurchase program, authorizing us to acquire up to an additional $100.0 million of our outstanding common stock during 2018 for a total of up to $200.0 million. We repurchased approximately $5.0 million of our outstanding common stock during the third quarter of 2018, resulting in a program total of $110.0 million as of September 30, 2018. We believe the repurchase of our outstanding common stock underscores the confidence we have in our business model, financial performance and asset base. Purchases under the expanded repurchase program may be made from time to time in open market or privately negotiated transactions, and will be subject to market conditions, applicable legal requirements, contractual obligations and other factors. The repurchase program does not require us to acquire any specific number of shares. We intend to purchase shares under the repurchase program opportunistically with available funds while maintaining sufficient liquidity to fund our 2018 capital development program. This repurchase program is authorized to extend through December 31, 2018 and may be suspended from time to time, modified, extended or discontinued by the board of directors at any time.

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 or decelerate our activity within the Utica Basin and SCOOP 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.

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Commodity Price Risk

See Item 3. “Quantitative and Qualitative Disclosures about Market Risk” for information regarding our open fixed price swaps at September 30, 2018.

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. Beginning in 2009, we can access the trust for use in plugging and abandonment charges associated with the property. As of September 30, 2018, the plugging and abandonment trust totaled approximately $3.1 million. At September 30, 2018, we have plugged 555 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, 2017.

Off-balance Sheet Arrangements

We had no off-balance sheet arrangements as of September 30, 2018.

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 ("ASC 606"). ASC 606 supersedes existing industry specific revenue recognition guidance and increases disclosure requirements. 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. We adopted ASC 606 as of January 1, 2018 using the modified retrospective transition method applied to contracts that were not completed as of that date. Results for reporting periods beginning after January 1, 2018 are presented under the new revenue standard. Under the modified retrospective method, we recognize the cumulative effect of initially applying the new revenue standard as an adjustment to the opening balance of retained earnings; however, no adjustment was required as a result of adopting the new revenue standard. The comparative information has not been restated and continues to be reported under the historic accounting standards in effect for those periods. The impact of the adoption of the new revenue standard is not expected to be material to our net income on an ongoing basis.

In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842). The standard supersedes the previous lease guidance by requiring lessees to recognize a right-to-use asset and lease liability on the balance sheet for all leases with lease terms of greater than one year while maintaining substantially similar classifications for financing and operating leases. The guidance is effective for periods after December 15, 2018, and we will not early adopt. We expect to apply the transition method permitted by ASU No. 2018-11, Leases (Topic 842): Targeted Improvements, issued in August 2018, which permits an entity to recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption with no adjustment made to the comparative periods presented in the consolidated financial statements. We also expect to utilize the practical expedient provided by ASU 2018-11 to not separate non-lease components from the associated lease component and, instead, to account for those components as a single component if the non-lease components would be accounted for under ASC 606 and other conditions are met.

We have identified our portfolio of leased assets under the new standard and are in the process of evaluating the impact of this guidance on our consolidated financial statements and related disclosures. The adoption will increase asset and liability balances on the consolidated balance sheets due to the required recognition of right-of-use assets and corresponding lease liabilities; however, that impact is currently not known. We are in the process of designing processes and controls needed to comply with the requirements of the new standard, which includes the implementation of a lease accounting software solution to support lease portfolio management and accounting and disclosures.

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Additionally, in January 2018, the FASB issued ASU No. 2018-01, Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842. The amendments in this update provide an optional expedient to not evaluate existing or expired land easements that were not previously accounted for under current leases guidance in Topic 840. An entity that elects this practical expedient should evaluate new or modified land easements beginning at the date of adoption. We do not currently account for any land easements under Topic 840 and plan to utilize this practical expedient in conjunction with the adoption of ASU 2016-02.

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 effect.

In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments. This ASU clarifies how certain cash receipts and cash payments should be classified and presented in the statement of cash flows. We have made an accounting policy election to classify distributions received from equity method investees using the nature of the distribution approach, which classifies distributions received from investees as either cash inflows from operating activities or cash inflows from investing activities in the statement of cash flows based on the nature of the activities of the investee that generated the distribution. The impact of adopting this ASU was not material to prior periods presented.

In November 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash. This ASU requires that amounts generally described as restricted cash and restricted cash equivalents be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period amounts shown on the statement of cash flows and to provide a reconciliation of the totals in the statement of cash flows to the related captions in the balance sheet when the cash, cash equivalents, restricted cash, and restricted cash equivalents are presented in more than one line item on the balance sheet. We adopted this standard in the first quarter of 2018 using the retrospective transition method. The adoption of this standard had no impact on our statement of cash flows for the nine months ended September 30, 2018 and resulted in the addition of $185.0 million of restricted cash to the beginning cash balance and an increase to net cash used in investing activities by the same amount on our statement of cash flows for the nine months ended September 30, 2017.

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. We adopted this standard in the first quarter of 2018 with no significant effect on our financial statements or related disclosures.

In February 2018, the FASB issued ASU No. 2018-02, Income statement - Reporting Comprehensive Income (Topic 220) - Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income, which allows a reclassification from accumulated other comprehensive income to retained earnings for standard tax effects resulting from the Tax Cuts and Jobs Act of 2017. The amendment will be effective for reporting periods beginning after December 15, 2018, and early adoption is permitted. We are currently assessing the impact of the ASU on our consolidated financial statements and related disclosures.

In August 2018, the FASB issued ASU No. 2018-13, Fair Value Measurement (Topic 820): Disclosure Framework—Changes to the Disclosure Requirements for Fair Value Measurement which removes, modifies, and adds certain disclosure requirements on fair value measurements. The amendment will be effective for reporting periods beginning after December 15, 2019, and early adoption is permitted. We are currently assessing the impact of the ASU on our consolidated financial statements and related disclosures

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adoption is permitted. We are currently assessing the impact of the ASU on our consolidated financial statements and related disclosures.



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 2017, WTI prices ranged from $42.48 to $60.46 per barrel and the Henry Hub spot market price of natural gas ranged from $2.44 to $3.71 per MMBtu. On October 26, 2018, the WTI posted price for crude oil was $67.59 per Bbl and the Henry Hub spot market price of natural gas was $3.27 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.

To mitigate the effects of commodity price fluctuations on our oil and natural gas production, we had the following open fixed price swap positions at September 30, 2018:



	Location	Daily Volume (MMBtu/day)	Weighted Average Price
Remaining 2018	NYMEX Henry Hub	1,010,000	$	3.01
2019	NYMEX Henry Hub	1,154,000	$	2.81
2020	NYMEX Henry Hub	204,000	$	2.77



	Location	Daily Volume (Bbls/day)	Weighted Average Price
Remaining 2018	ARGUS LLS	2,000	$	56.22
2019	ARGUS LLS	1,000	$	59.55
Remaining 2018	NYMEX WTI	4,500	$	53.72
2019	NYMEX WTI	4,000	$	58.28

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	Location	Daily Volume (Bbls/day)	Weighted Average Price
2019	Mont Belvieu C2	1,000	$	18.48
Remaining 2018	Mont Belvieu C3	4,000	$	29.34
2019	Mont Belvieu C3	4,000	$	28.87
Remaining 2018	Mont Belvieu C5	500	$	46.62
2019	Mont Belvieu C5	500	$	54.08

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
October 2018 - March 2019	NYMEX Henry Hub	50,000	$	3.13
April 2019 - December 2019	NYMEX Henry Hub	30,000	$	3.10

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

In addition, we have entered into natural gas basis swap positions, which settle on the pricing index to basis differential of Transco Zone 4 to NYMEX Henry Hub natural gas price. As of September 30, 2018, we had the following natural gas basis swap positions for Transco Zone 4.



	Location	Daily Volume (MMBtu/day)	Weighted Average Price
Remaining 2018	Transco Zone 4	40,000	$	(0.05	)
2019	Transco Zone 4	60,000	$	(0.05	)
2020	Transco Zone 4	60,000	$	(0.05	)

Under our 2018 contracts, we have hedged approximately 74% to 75% of our estimated 2018 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 September 30, 2018, we had a net liability derivative position of $54.4 million as compared to a net liability derivative position of $7.1 million as of September 30, 2017, 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 instruments by approximately $193.1 million, while a 10% decrease in underlying commodity prices would have increased the fair value of these instruments by approximately $190.3 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 September 30, 2018, we had $60.0 million in borrowings outstanding under our credit facility which bore interest at the eurodollar rate of 3.72%. A 1.0% increase in the average interest rate for the nine months ended September 30, 2018 would have resulted in an estimated $0.7 million increase in interest expense. As of September 30, 2018, we did not have any interest rate swaps to hedge our interest risks.



ITEM 4.	CONTROLS AND PROCEDURES

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Evaluation of Disclosure Control and Procedures. Under the direction of our Interim Chief Executive Officer 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 Interim Chief Executive Officer and our Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosures.

As of September 30, 2018, an evaluation was performed under the supervision and with the participation of management, including our Interim Chief Executive Officer 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 Interim Chief Executive Officer and our Chief Financial Officer have concluded that, as of September 30, 2018, our disclosure controls and procedures were not effective solely due to the matters noted below.

In September 2018, the Audit Committee of our Board of Directors was informed that unauthorized use of the Company’s chartered aircraft by our Chief Executive Officer during the past four years was not timely identified, quantified and disclosed by the Company in the Company’s proxy statement on Schedule 14A. The method the Company has used to determine the aggregate incremental costs related to aircraft use not directly related and integral to the performance of the Chief Executive Officer’s duties includes those excess costs that the Company would not have incurred but for such use by the Chief Executive Officer and personal guests and excludes any fixed costs. Because the aircraft provided was chartered from a third party, these costs include the hourly fee charged by the charter company for the specific flight, and per flight fees, fuel variable charges, domestic segment fees, federal excise tax and other actual fees charged by the charter company related to the specific flight. Personal guests on a flight that was directly related and integral to the Chief Executive Officer’s duties incurred negligible incremental costs and are not included in the calculation. The aggregate incremental aircraft usage costs associated with our Chief Executive Officer’s personal use of the aircraft were approximately $107,300, $175,800, $138,700, $163,600 and $63,800 for 2014, 2015, 2016, 2017 and 2018, respectively. The Company is seeking reimbursement for these costs. None of the Company’s other named executive officers used the Company aircraft for personal purposes during this period. Also in September 2018, the Audit Committee was informed that our Chief Executive Officer had made personal charges on his Company credit card. These unauthorized charges were repaid periodically during the course of the year in which they were made and no personal charges are currently outstanding. Although these personal charges were recorded and reported correctly and within the requisite time periods in the Company’s financial statements, such personal charges may have constituted personal loans that are not permissible under Section 402 of the Sarbanes-Oxley Act of 2002. The maximum outstanding balances for personal charges at any time during any year in the period 2007 through 2018 ranged from a low of $808 in 2007 to a high of $347,164 in 2017, and the incremental cost to the Company for these personal charges prior to their repayment, based on the Company’s weighted average borrowing rate under its revolving credit facility during the applicable period (regardless of whether any amounts were actually outstanding under the revolving credit facility during such period), ranged from approximately an aggregate of $12 in 2007 to an aggregate of $5,016 in 2017. The total incremental cost to the Company during the full 11-year period was approximately $9,493. The Company is seeking reimbursement for these costs.

Following an in-depth review of the facts and circumstances surrounding these matters performed at the request of the Audit Committee by independent counsel, the Board of Directors has recommended, and the Company is undertaking, comprehensive remedial measures related to executive use of corporate aircraft and corporate credit cards.

These remedial measures include:

•Adoption and implementation of a new Private Aircraft Use Policy and additional training and reinforcement with respect to existing travel and expense policies;

•Quarterly review and reporting to the Audit Committee with respect to compliance by the Company’s named executive officers with travel and expense policies; and

•Additional resources to ensure full compliance with the Company’s new and existing policies and procedures.

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

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PART II



ITEM 1.	LEGAL PROCEEDINGS

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 Vermilion 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 Vermilion 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 and Lac Blanc oil and gas fields, in the case of the Vermilion 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 Vermilion 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 Vermilion Parish suit. Shortly after the Complaints were filed, certain defendants removed the cases to the United States District Court for the Western District of Louisiana. In both cases, the plaintiffs filed motions to remand the lawsuits to state court, which were ultimately granted by the district courts. However, on May 23, 2018, a group of defendants again removed the Cameron Parish and Vermilion Parish lawsuits to federal court. In response, the plaintiffs again filed motions to remand the cases to state court. The removing defendants have opposed plaintiffs’ motions to remand. The motions to remand remain pending, and further action in the cases will be stayed until the courts rule on the motions to remand. Also, shortly after the May 23, 2018 removal, the removing defendants filed motions with the United States Judicial Panel on Multidistrict Litigation, or MDL Panel, requesting that the Cameron Parish and Vermilion Parish lawsuits be consolidated with 40 similar lawsuits so that pre-trial proceedings in the cases could be coordinated. The MDL Panel denied the motion to consolidate the lawsuits. Due to the procedural posture of lawsuits, the cases are still in their early stages and the parties have conducted very little discovery. As a result, we have not had the opportunity to evaluate the applicability of the allegations made in plaintiffs' complaints to our operations and 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, 2017.



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

Unregistered Sales of Equity Securities

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None.

Issuer Repurchases of Equity Securities

Our common stock repurchase activity for the three months ended September 30, 2018 was as follows:



Period	Total number of shares purchased	Average price paid per share		Total number of shares purchased as part of publicly announced plans or programs ⁽¹⁾	Approximate maximum dollar value of shares that may yet be purchased under the plans or programs ⁽²⁾
July 2018	400,597	$	12.48	400,597	$	90,003,000
August 2018	—	$	—	—	$	90,003,000
September 2018	—	$	—	—	$	90,003,000
Total	400,597	$	12.48	400,597



(1)	In January 2018, our board of directors approved a stock repurchase program to acquire up to $100.0 million of our outstanding common stock, and in May 2018 expanded this program authorizing us to acquire up to an additional $100.0 million of our outstanding common stock, during 2018 for a total of up to $200.0 million. The repurchase program does not require us to acquire any specific number of shares. This repurchase program is authorized to extend through December 31, 2018 and may be suspended from time to time, modified, extended or discontinued by our board of directors at any time.
(2)	During the three months ended September 30, 2018, we repurchased and canceled approximately 0.4 million shares of our common stock at an average price of $12.48 per share for a total of $5.0 million. During the nine months ended September 30, 2018, we repurchased 10,505,469 shares under this program at a weighted average price of $10.47 per share.



ITEM 3.	DEFAULTS UPON SENIOR SECURITIES

Not applicable.



ITEM 4.	MINE SAFETY DISCLOSURES

Not applicable.



ITEM 5.	OTHER INFORMATION

Effective October 29, 2018, Michael G. Moore stepped down from his position as our Chief Executive Officer and President and as a member of our board of directors. His resignation from the board was not a result of any disagreement with us or our operations.

Effective October 29, 2018, Donnie Moore, our Chief Operating Officer, assumed the duties of our principal executive officer on an interim basis until such time as we appoint a new Chief Executive Officer. Mr. Donnie Moore (who is not related to Michael G. Moore) has served as our Chief Operating Officer since January 2018. Mr. Moore’s biographical information and compensation, as well as other applicable information required by Items 401(b), (d) and (e) and 404(a) of Regulation S-K, are included in our Definitive Proxy Statement on Schedule 14A, filed with the Securities and Exchange Commission on April 30, 2018.

In connection with Mr. Moore’s departure, we entered into a Separation and Release Agreement with Mr. Moore which we refer to as the separation agreement. Under the terms of the separation agreement, we agreed to pay Mr. Moore separation payments in the aggregate amount of $400,000, payable on or before December 31, 2018, of which $300,000 is subject to Mr. Moore not revoking his agreement to release age discrimination claims during a seven-day revocation period that ends on November 8, 2018. Also, subject to the expiration of the seven-day revocation period and the executive’s proper election of COBRA continuation benefits, we agreed to reimburse Mr. Moore’s portion of COBRA premiums for a maximum of six

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months, which reimbursement will cease at any time he becomes eligible for group medical coverage from another employer. The separation agreement also includes a release of claims by Mr. Moore against us, our directors, stockholders, employees, agents, attorneys, consultants and affiliates.

The preceding summary of the separation agreement is qualified in its entirety by reference to the full text of such agreement, a copy of which is attached as Exhibit 10.3 to this report and incorporated herein by reference.



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).

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

4.8		Indenture, dated as of October 11, 2017, among Gulfport Energy Corporation, the subsidiary guarantors party thereto and Wells Fargo Bank, N.A., as trustee (including the form of Gulfport Energy Corporation’s 6.375% Senior Notes due 2026) (incorporated by reference to Exhibit 4.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on October 11, 2017).

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

10.1#		Amendment No. 2, dated as of July 10, 2018, between Stingray Pressure Pumping, LLC and Gulfport Energy Corporation to that certain Amended & Restated Master Services Agreement for Pressure Pumping Services, effective as of October 1, 2014, as amended effective January 1, 2016 (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q, File No. 000-19514, filed by the Company with the SEC on August 2, 2018).

10.2*		Second Amendment to Sand Supply Agreement, dated as of August 6, 2018, between Gulfport Energy Corporation and Muskie Proppant LLC.

10.3*+		Separation and Release Agreement, effective October 29, 2018, by and between Gulfport Energy Corporation and Michael G. Moore.

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31.1*		Certification of Interim 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 Interim 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.
#	Confidential treatment as to certain portions was granted with respect to this amendment and extended with respect to the original agreement by the SEC on September 17, 2018, which portions have been omitted and filed separately with the SEC.
+	Management contract, compensatory plan or arrangement.

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SIGNATURES

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

Date: November 1, 2018



GULFPORT ENERGY CORPORATION

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

Gulfport Energy - 10-Q quarterly report FY2018 Q3

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