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~~June 30, ~~2017~~ 2019
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~~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~~	Oklahoma	73134
(Address of Principal Executive Offices)			(Zip Code)

~~(405)~~ (405) 252-4600

(Registrant Telephone Number, Including Area Code)

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



Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Common stock, par value $0.01 per share	GPOR	Nasdaq Global Select Market

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

Indicate by check mark whether the registrant has submitted electronically ~~and posted on its corporate Web site, if any,~~ every Interactive Data File required to be submitted ~~and posted~~ pursuant to Rule 405 of Regulation S-T (Section 232.405 of this chapter) during the preceding 12 months (or such shorter period that the registrant was required to submit ~~and post~~ such files). Yesý 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 filerý 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 27, 2017~~July 26, 2019, ~~183,081,776~~159,396,017 shares of the registrant’s common stock were outstanding.

Table of Contents

GULFPORT ENERGY CORPORATION

TABLE OF CONTENTS



		Page
PART I FINANCIAL INFORMATION

Item 1.	Consolidated Financial Statements ~~(unaudited)~~(Unaudited):	2

	Consolidated Balance Sheets at ~~September~~June 30, ~~2017~~2019 and December 31, ~~2016~~2018	2

	Consolidated Statements of Operations for the Three and ~~Nine~~Six Months Ended ~~September~~June 30, ~~2017~~2019 and ~~2016~~2018	3

	Consolidated Statements of Comprehensive Income ~~(Loss)~~ for the Three and ~~Nine~~Six Months Ended ~~September~~June 30, ~~2017~~2019 and ~~2016~~2018	4

	Consolidated Statements of Stockholders’ Equity for the ~~Nine~~Six Months Ended ~~September~~June 30, ~~2017~~2019 and ~~2016~~2018	5

	Consolidated Statements of Cash Flows for the ~~Nine~~Six Months Ended ~~September~~June 30, ~~2017~~2019 and ~~2016~~	6

	~~Notes to Consolidated Financial Statements~~2018	7

	Notes to Consolidated Financial Statements	8

Item 2.	Management’s Discussion and Analysis of Financial Conditions and Results of Operations	3736

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	50

Item 4.	Controls and Procedures	52

PART II OTHER INFORMATION

Item 1.	Legal Proceedings	53

Item 1A.	Risk Factors	54

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	54

Item 3.	Defaults Upon Senior Securities	54

Item 4.	~~Controls and Procedures~~Mine Safety Disclosures	54

Item 5.	Other Information	54

Item 6.	Exhibits	56

~~PART II OTHER INFORMATION~~Signatures

~~Item 1.~~	~~Legal Proceedings~~	58

~~Item 1A.~~	~~Risk Factors~~	58

~~Item 2.~~	~~Unregistered Sales of Equity Securities and Use of Proceeds~~	58

~~Item 3.~~	~~Defaults Upon Senior Securities~~	59

~~Item 4.~~	~~Mine Safety Disclosures~~	59

~~Item 5.~~	~~Other Information~~	59

~~Item 6.~~	~~Exhibits~~	59

~~Signatures~~		61

Table of Contents

GULFPORT ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS

(Unaudited)


	September 30, 2017			December 31, 2016			June 30, 2019			December 31, 2018
	(In thousands, except share data)						(In thousands, except share data)
Assets
Current assets:
Cash and cash equivalents	$	125,271		$	1,275,875		$	20,777		$	52,297
Restricted cash	—			185,000
Accounts receivable—oil and natural gas	180,106			136,761
Accounts receivable—related parties	362			16
Accounts receivable—oil and natural gas sales							131,675			210,200
Accounts receivable—joint interest and other							46,645			22,497
Prepaid expenses and other current assets	5,666			3,135			9,474			10,607
Short-term derivative instruments	35,332			3,488			134,920			21,352
Total current assets	346,737			1,604,275			343,491			316,953
Property and equipment:
Oil and natural gas properties, full-cost accounting, $2,956,732 and $1,580,305 excluded from amortization in 2017 and 2016, respectively	8,867,239			6,071,920
Oil and natural gas properties, full-cost accounting, $2,836,441 and $2,873,037 excluded from amortization in 2019 and 2018, respectively							10,510,427			10,026,836
Other property and equipment	84,225			68,986			96,413			92,667
Accumulated depletion, depreciation, amortization and impairment	(4,043,879		)	(3,789,780		)	(4,882,729		)	(4,640,098		)
Property and equipment, net	4,907,585			2,351,126			5,724,111			5,479,405
Other assets:
Equity investments	279,282			243,920			119,307			236,121
Long-term derivative instruments	6,409			5,696			5,036			—
Deferred tax asset	4,692			4,692			179,331			—
Inventories	13,908			4,504			9,001			4,754
Operating lease assets							19,334			—
Operating lease assets - related parties							53,579			—
Other assets	18,985			8,932			12,280			13,803
Total other assets	323,276			267,744			397,868			254,678
Total assets	$	5,577,598		$	4,223,145		$	6,465,470		$	6,051,036
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable and accrued liabilities	$	582,928		$	265,124		$	493,830		$	518,380
Asset retirement obligation—current	195			195
Short-term derivative instruments	29,130			119,219			198			20,401
Current portion of operating lease liabilities							17,999			—
Current portion of operating lease liabilities - related parties							20,817			—
Current maturities of long-term debt	570			276			615			651
Total current liabilities	612,823			384,814			533,459			539,432
Long-term derivative instrument	19,712			26,759
Long-term derivative instruments							210			13,992
Asset retirement obligation—long-term	44,266			34,081			88,491			79,952
Deferred tax liability							3,127			3,127
Non-current operating lease liabilities							1,335			—
Non-current operating lease liabilities - related parties							32,762			—
Long-term debt, net of current maturities	1,958,136			1,593,599			2,198,678			2,086,765
Total liabilities	2,634,937			2,039,253			2,858,062			2,723,268
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	—			—
Commitments and contingencies (Note 7)
Preferred stock, $0.01 par value; 5,000,000 shares authorized (30,000 authorized as redeemable 12% cumulative preferred stock, Series A), and none issued and outstanding							—			—
Stockholders’ equity:
Common stock - $.01 par value, 200,000,000 authorized, 183,081,776 issued and outstanding at September 30, 2017 and 158,829,816 at December 31, 2016	1,831			1,588
Common stock - $0.01 par value, 200,000,000 shares authorized, 159,396,017 issued and outstanding at June 30, 2019 and 162,986,045 at December 31, 2018							1,594			1,630
Paid-in capital	4,413,623			3,946,442			4,202,599			4,227,532
Accumulated other comprehensive loss	(40,339		)	(53,058		)	(48,615		)	(56,026		)
Retained deficit	(1,432,454		)	(1,711,080		)
Accumulated deficit							(548,170		)	(845,368		)
Total stockholders’ equity	2,942,661			2,183,892			3,607,408			3,327,768
Total liabilities and stockholders’ equity	$	5,577,598		$	4,223,145		$	6,465,470		$	6,051,036

See accompanying notes to consolidated financial statements.

Table of Contents

GULFPORT ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)


	Three months ended September 30,						Nine months ended September 30,						Three months ended June 30,						Six months ended June 30,
	2017			2016			2017			2016			2019			2018			2019			2018
	(In thousands, except share data)												(In thousands, except share data)
Revenues:
Natural gas sales	$	223,340		$	122,018		$	606,544		$	271,873		$	225,257		$	232,695		$	501,273		$	482,094
Oil and condensate sales	31,459			21,799			85,338			60,799			36,910			49,319			69,392			95,005
Natural gas liquid sales	33,559			14,594			88,985			34,198			25,687			41,271			57,812			88,107
Net (loss) gain on natural gas, oil, and NGL derivatives	(22,860		)	35,281			141,588			(44,376		)
Net gain (loss) on natural gas, oil and NGLs derivatives													171,140			(70,545		)	151,095			(87,074		)
	265,498			193,692			922,455			322,494			458,994			252,740			779,572			578,132
Costs and expenses:
Lease operating expenses	20,020			17,471			60,044			48,789			22,388			22,912			42,195			41,818
Production taxes	5,419			3,525			14,464			9,492			8,098			7,659			16,019			14,513
Midstream gathering and processing	69,372			45,475			176,258			122,476
Midstream gathering and processing expenses													72,015			71,440			142,297			135,633
Depreciation, depletion and amortization	106,650			62,285			254,887			183,414			124,951			121,915			243,384			232,933
Impairment of oil and natural gas properties	—			212,194			—			601,806
General and administrative	13,065			10,467			37,922			32,941
General and administrative expenses													13,265			14,008			24,823			27,107
Accretion expense	456			269			1,148			777			1,359			1,015			2,426			2,019
Acquisition expense	33			—			2,391			—
	215,015			351,686			547,114			999,695			242,076			238,949			471,144			454,023
INCOME (LOSS) FROM OPERATIONS	50,483			(157,994		)	375,341			(677,201		)
OTHER (INCOME) EXPENSE:
INCOME FROM OPERATIONS													216,918			13,791			308,428			124,109
OTHER EXPENSE (INCOME):
Interest expense	27,130			12,787			74,797			44,892			34,880			33,704			69,000			67,669
Interest income	(37		)	(337		)	(927		)	(822		)	(159		)	(33		)	(311		)	(70		)
Insurance proceeds	—			(3,750		)	—			(3,750		)	(83		)	(231		)	(83		)	(231		)
Gain on sale of equity method investments													—			(122,035		)	—			(122,035		)
Loss (income) from equity method investments, net	2,737			(5,997		)	20,945			25,576			125,582			(8,888		)	121,309			(22,424		)
Other income	(345		)	6			(863		)	(3		)
Other expense (income)													1,073			(45		)	646			(140		)
	29,485			2,709			93,952			65,893			161,293			(97,528		)	190,561			(77,231		)
INCOME (LOSS) BEFORE INCOME TAXES	20,998			(160,703		)	281,389			(743,094		)
INCOME TAX EXPENSE (BENEFIT)	2,763			(3,407		)	2,763			(3,755		)
NET INCOME (LOSS)	$	18,235		$	(157,296	)	$	278,626		$	(739,339	)
NET INCOME (LOSS) PER COMMON SHARE:
INCOME BEFORE INCOME TAXES													55,625			111,319			117,867			201,340
INCOME TAX BENEFIT													(179,331		)	—			(179,331		)	(69		)
NET INCOME													$	234,956		$	111,319		$	297,198		$	201,409
NET INCOME PER COMMON SHARE:
Basic	$	0.10		$	(1.25	)	$	1.56		$	(6.12	)	$	1.47		$	0.64		$	1.85		$	1.14
Diluted	$	0.10		$	(1.25	)	$	1.56		$	(6.12	)	$	1.47		$	0.64		$	1.84		$	1.13
Weighted average common shares outstanding—Basic	182,957,416			125,408,866			178,736,569			120,771,046			159,324,909			173,623,630			161,064,787			177,158,230
Weighted average common shares outstanding—Diluted	183,008,436			125,408,866			179,130,570			120,771,046			159,506,826			174,140,627			161,590,087			177,737,282

See accompanying notes to consolidated financial statements.

Table of Contents

GULFPORT ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME ~~(LOSS)~~

(Unaudited)



	Three months ended June 30,					Six months ended June 30,
	2019		2018			2019		2018
	(In thousands)
Net income	$	234,956	$	111,319		$	297,198	$	201,409
Foreign currency translation adjustment	3,610		(3,364		)	7,411		(8,867		)
Other comprehensive income (loss)	3,610		(3,364		)	7,411		(8,867		)
Comprehensive income	$	238,566	$	107,955		$	304,609	$	192,542

Three months ended September 30, Nine months ended September 30,
2017 2016 2017 2016
(In thousands)
Net income (loss) $ 18,235
$ (157,296 ) $ 278,626
$ (739,339 )
Foreign currency translation adjustment (1) 6,832
(4,013 ) 12,719
4,361
Other comprehensive income (loss) 6,832
(4,013 ) 12,719
4,361
Comprehensive income (loss) $ 25,067
$ (161,309 ) $ 291,345
$ (734,978 )

~~(1) Net of $2.8 million in taxes for each of the three and nine months ended September 30, 2016.~~

See accompanying notes to consolidated financial statements.

Table of Contents

GULFPORT ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(Unaudited)

Paid-in
Capital

Accumulated
Other
Comprehensive Income (loss)

Retained
Deficit

Total
Stockholders’
Equity
Common Stock
Shares Amount
(In thousands, except share data)
Balance at January 1, 2017 158,829,816
$ 1,588
$ 3,946,442
$ (53,058 ) $ (1,711,080 ) $ 2,183,892
Net income —
—
—
—
278,626
278,626
Other Comprehensive Income

12,719
—
12,719
Stock 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

Balance at January 1, 2016 108,322,250
$ 1,082
$ 2,824,303
$ (55,177 ) $ (731,371 ) $ 2,038,837
Net loss —
—
—
—
(739,339 ) (739,339 )
Other Comprehensive Income —
—
—
4,361
—
4,361
Stock Compensation —
—
9,550
—
—
9,550
Issuance of Common Stock in public offerings, net of related expenses 16,905,000
169
411,542
—
—
411,711
Issuance of Restricted Stock 226,283
2
(2 ) —
—
—
Balance at September 30, 2016 125,453,533
$ 1,253
$ 3,245,393
$ (50,816 ) $ (1,470,710 ) $ 1,725,120



						Paid-in Capital			Accumulated Other Comprehensive (Loss) Income			Accumulated Deficit			Total Stockholders’ Equity
	Common Stock
	Shares		Amount
	(In thousands, except share data)
Balance at January 1, 2019	162,986,045		$	1,630		$	4,227,532		$	(56,026	)	$	(845,368	)	$	3,327,768
Net Income	—		—			—			—			62,242			62,242
Other Comprehensive Income	—		—			—			3,801			—			3,801
Stock Compensation	—		—			2,785			—			—			2,785
Shares Repurchased	(3,618,634	)	(37		)	(28,293		)	—			—			(28,330		)
Issuance of Restricted Stock	54,554		1			(1		)	—			—			—
Balance at March 31, 2019	159,421,965		$	1,594		$	4,202,023		$	(52,225	)	$	(783,126	)	$	3,368,266
Net Income	—		—			—			—			234,956			234,956
Other Comprehensive Income	—		—			—			3,610			—			3,610
Stock Compensation	—		—			2,846			—			—			2,846
Shares Repurchased	(296,587	)	(3		)	(2,267		)	—			—			(2,270		)
Issuance of Restricted Stock	270,639		3			(3		)	—			—			—
Balance at June 30, 2019	159,396,017		$	1,594		$	4,202,599		$	(48,615	)	$	(548,170	)	$	3,607,408

(Continued on next page)

Table of Contents

GULFPORT ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (continued)

(Unaudited)



						Paid-in Capital			Accumulated Other Comprehensive (Loss) Income			Accumulated Deficit			Total Stockholders’ Equity
	Common Stock
	Shares		Amount
	(In thousands, except share data)
Balance at January 1, 2018	183,105,910		$	1,831		$	4,416,250		$	(40,539	)	$	(1,275,928	)	$	3,101,614
Net Income	—		—			—			—			90,090			90,090
Other Comprehensive Loss	—		—			—			(5,503		)	—			(5,503		)
Stock Compensation	—		—			2,685			—			—			2,685
Shares Repurchased	(9,692,356	)	(97		)	(99,900		)	—			—			(99,997		)
Issuance of Restricted Stock	109,933		1			(1		)	—			—			—
Balance at March 31, 2018	173,523,487		$	1,735		$	4,319,034		$	(46,042	)	$	(1,185,838	)	$	3,088,889
Net Income	—		—			—			—			111,319			111,319
Other Comprehensive Loss	—		—			—			(3,364		)	—			(3,364		)
Stock Compensation	—		—			3,355			—			—			3,355
Shares Repurchased	(412,516	)	(4		)	(4,996		)	—			—			(5,000		)
Issuance of Restricted Stock	191,084		2			(2		)	—			—			—
Balance at June 30, 2018	173,302,055		$	1,733		$	4,317,391		$	(49,406	)	$	(1,074,519	)	$	3,195,199

See accompanying notes to consolidated financial statements.

Table of Contents

GULFPORT ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Nine months ended September 30,						Six months ended June 30,
	2017			2016			2019			2018
	(In thousands)						(In thousands)
Cash flows from operating activities:
Net income (loss)	$	278,626		$	(739,339	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Accretion of discount—Asset Retirement Obligation	1,148			777
Net income							$	297,198		$	201,409
Adjustments to reconcile net income to net cash provided by operating activities:
Accretion expense							2,426			2,019
Depletion, depreciation and amortization	254,887			183,414			243,384			232,933
Impairment of oil and natural gas properties	—			601,806
Stock-based compensation expense	4,793			5,730			3,379			3,624
Loss from equity investments	21,495			25,988
Loss (income) from equity investments							121,449			(22,322		)
Change in fair value of derivative instruments	(129,692		)	184,013			(152,589		)	102,248
Deferred income tax expense (benefit)	—			17,211
Amortization of loan commitment fees	3,548			2,912
Amortization of note discount and premium	—			(1,716		)
Deferred income tax benefit							(179,331		)	(69		)
Amortization of loan costs							3,191			3,006
Gain on sale of equity investments and other assets							(112		)	(122,035		)
Distributions from equity method investments							2,457			—
Changes in operating assets and liabilities:
Increase in accounts receivable	(43,345		)	(55,916		)
Increase in accounts receivable—related party	(346		)	(80		)
Increase in prepaid expenses	(2,531		)	(6,835		)
Decrease in accounts receivable—oil and natural gas sales							78,525			6,564
Increase in accounts receivable—joint interest and other							(24,148		)	(16,385		)
Increase in accounts receivable—related parties							—			(110		)
Decrease (increase) in prepaid expenses and other current assets							1,133			(5,786		)
Increase in other assets	(5,665		)	—			(296		)	(1,517		)
Increase in accounts payable, accrued liabilities and other	111,335			28,265
(Decrease) increase in accounts payable, accrued liabilities and other							(87,560		)	28,184
Settlement of asset retirement obligation	(2,520		)	(955		)	(117		)	(719		)
Net cash provided by operating activities	491,733			245,275			308,989			411,044
Cash flows from investing activities:
Deductions to cash held in escrow	—			8
Additions to other property and equipment	(16,288		)	(20,131		)	(4,298		)	(6,252		)
Acquisition of oil and natural gas properties	(1,339,456		)	—
Additions to oil and natural gas properties	(789,743		)	(441,128		)	(417,535		)	(579,734		)
Proceeds from sale of oil and natural gas properties	4,079			41,534			745			3,762
Proceeds from sale of other property and equipment	658			—			130			167
Funding of restricted cash	185,000			—
Proceeds from sale of equity method investments							—			221,965
Contributions to equity method investments	(44,844		)	(18,510		)	(432		)	(1,569		)
Distributions from equity method investments	4,114			14,220			1,945			1,196
Insurance proceeds	—			3,750
Net cash used in investing activities	(1,996,480		)	(420,257		)	(419,445		)	(360,465		)
Cash flows from financing activities:
Principal payments on borrowings	(183		)	(1,685		)	(345,350		)	(150,285		)
Borrowings on line of credit	365,000			—			455,000			225,000
Borrowings on term loan	2,951			16,499
Debt issuance costs and loan commitment fees	(8,261		)	(241		)	(114		)	(624		)
Proceeds from issuance of common stock, net of offering costs	(5,364		)	411,711
Net cash provided by financing activities	354,143			426,284
Net (decrease) increase in cash and cash equivalents	(1,150,604		)	251,302
Cash and cash equivalents at beginning of period	1,275,875			112,974
Cash and cash equivalents at end of period	$	125,271		$	364,276
Payments for repurchase of stock							(30,600		)	(104,997		)
Net cash provided by (used in) financing activities							78,936			(30,906		)
Net (decrease) increase in cash, cash equivalents and restricted cash							(31,520		)	19,673
Cash, cash equivalents and restricted cash at beginning of period							52,297			99,557
Cash, cash equivalents and restricted cash at end of period							$	20,777		$	119,230
Supplemental disclosure of cash flow information:
Interest payments	$	50,826		$	35,193		$	67,472		$	59,915
Income tax payments	$	—		$	—
Income tax receipts							$	(1,794	)	$	—
Supplemental disclosure of non-cash transactions:
Capitalized stock based compensation	$	3,195		$	3,820
Capitalized stock-based compensation							$	2,252		$	2,416
Asset retirement obligation capitalized	$	11,557		$	6,726		$	6,230		$	535
Interest capitalized	$	8,753		$	8,920		$	1,771		$	2,351
Foreign currency translation gain on equity method investments	$	12,719		$	7,137
Foreign currency translation gain (loss) on equity method investments							$	7,411		$	(8,867	)

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,~~that, in the opinion of management, are necessary for a fair presentation of the results for the interim periods in all material respects, on a basis consistent with the annual audited consolidated financial statements. All such adjustments are of a normal, recurring nature. Certain information, accounting policies, and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles ("GAAP") have been omitted pursuant to such rules and regulations, although the Company believes that the disclosures are adequate to make the information presented not misleading. 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~~six months ended ~~September~~June 30, ~~2017~~2019 are not necessarily indicative of the results expected for the full year.


1.	~~ACQUISITIONS~~

~~Vitruvian Acquisition~~

In December 2016, the Company, through its wholly-owned subsidiary Gulfport MidCon LLC (“Gulfport MidCon”) (formerly known as SCOOP Acquisition Company, LLC), entered into an agreement to acquire certain assets of Vitruvian II Woodford, LLC (“Vitruvian”), an unrelated third-party seller (the “Vitruvian Acquisition”). The assets included in the Vitruvian Acquisition include 46,400 net surface acres located in Grady, Stephens and Garvin Counties, Oklahoma. On February 17, 2017, the Company completed the Vitruvian Acquisition for a total initial purchase price of approximately $1.85 billion, consisting of $1.35 billion in cash, subject to certain adjustments, and approximately 23.9 million shares of the Company’s common stock (of which approximately 5.2 million shares were placed in an indemnity escrow). The cash portion of the purchase price was funded with the net proceeds from the December 2016 common stock and senior note offerings and cash on hand. Acquisition costs of $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.~~

~~Allocation of Purchase Price~~

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

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

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

~~Table of Contents~~

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

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

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

~~Post-Acquisition Operating Results~~

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

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, 2016. The pro forma combined financial information has been included for comparative purposes and is not necessarily indicative of the results that might have actually occurred had the Vitruvian Acquisition taken place on January 1, 2016; furthermore, the financial information is not intended to be a projection of future results.

Three months ended September 30, Nine months ended September 30,
2017 2016 2017 2016
(In thousands, except share data)
Pro forma revenue $ 265,498
$ 250,258
$ 958,354
$ 425,958
Pro forma net income (loss) $ 18,235
$ (200,005 ) $ 300,052
$ (935,219 )
Pro forma earnings (loss) per share (basic) $ 0.10
$ (1.34 ) $ 1.68
$ (6.47 )
Pro forma earnings (loss) per share (diluted) $ 0.10
$ (1.34 ) $ 1.68
$ (6.47 )

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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~~June 30, ~~2017~~2019 and December 31, ~~2016~~2018 are as follows:



	June 30, 2019			December 31, 2018
	(In thousands)
Oil and natural gas properties	$	10,510,427		$	10,026,836
Office furniture and fixtures	46,327			42,581
Building	44,565			44,565
Land	5,521			5,521
Total property and equipment	10,606,840			10,119,503
Accumulated depletion, depreciation, amortization and impairment	(4,882,729		)	(4,640,098		)
Property and equipment, net	$	5,724,111		$	5,479,405

September 30, 2017 December 31, 2016
(In thousands)
Oil and natural gas properties $ 8,867,239
$ 6,071,920
Office furniture and fixtures 34,875
21,204
Building 44,530
42,530
Land 4,820
5,252
Total property and equipment 8,951,464
6,140,906
Accumulated depletion, depreciation, amortization and impairment (4,043,879 ) (3,789,780 )
Property and equipment, net $ 4,907,585
$ 2,351,126

Under the full cost method of accounting, the Company is required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the Company's oil and natural gas properties. At ~~September~~June 30, ~~2017,~~2019, the calculated ceiling was greater than the net book value of the Company’s oil and natural gas properties, ~~thus~~and no ceiling test impairment was required for the ~~nine~~three and six months ended ~~September~~June 30, ~~2017. An~~2019. No impairment of~~$212.2 million~~ ~~and~~ ~~$601.8 million~~was required for oil and natural gas properties for the three and~~nine~~ six months ended ~~September~~June 30, ~~2016, respectively.~~2018.

Included in oil and natural gas properties at ~~September~~June 30, ~~2017~~2019 is the cumulative capitalization of ~~$155.5~~$219.8 million in general and administrative costs incurred and capitalized to the full cost pool. General and administrative costs capitalized to the full cost pool represent management’s estimate of costs incurred directly related to exploration and development activities such as geological and other administrative costs associated with overseeing ~~the~~ exploration and development activities. All general and administrative costs not directly associated with exploration and development activities were charged to expense as they were incurred. Capitalized general and administrative costs were approximately ~~$8.9~~$8.8 million and ~~$25.6~~$16.5 million for the three and ~~nine~~six months ended ~~September~~June 30, ~~2017,~~2019, respectively, and ~~$7.2~~$9.4 million and ~~$22.2~~$18.2 million for the three and ~~nine~~six months ended ~~September~~June 30, ~~2016,~~2018, 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 $1.00 and $0.96 per Mcfe for the six months ended June 30, 2019 and 2018, respectively.

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The following table summarizes the Company’s non-producing properties excluded from amortization by area at ~~September~~June 30, ~~2017:~~2019:



	June 30, 2019
	(In thousands)
Utica	$	1,475,997
MidContinent	1,359,279
Niobrara	454
Southern Louisiana	611
Bakken	100
	$	2,836,441

September 30, 2017
(In thousands)
Utica $ 1,517,555
MidContinent 1,435,992
Niobrara 2,182
Southern Louisiana 536
Bakken 99
Other 368
$ 2,956,732

At December 31, ~~2016,~~2018, approximately ~~$1.6~~$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.

~~Table of Contents~~

A reconciliation of the Company’s asset retirement obligation for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2019 and ~~2016~~2018 is as follows:



	June 30, 2019			June 30, 2018
	(In thousands)
Asset retirement obligation, beginning of period	$	79,952		$	75,100
Liabilities incurred	5,153			909
Liabilities settled	(117		)	(719		)
Accretion expense	2,426			2,019
Revisions in estimated cash flows	1,077			(374		)
Asset retirement obligation as of end of period	88,491			76,935
Less current portion	—			120
Asset retirement obligation, long-term	$	88,491		$	76,815

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September 30, 2017 September 30, 2016
(In thousands)
Asset retirement obligation, beginning of period $ 34,276
$ 26,437
Liabilities incurred 11,557
6,726
Liabilities settled (2,520 ) (955 )
Accretion expense 1,148
777
Asset retirement obligation as of end of period 44,461
32,985
Less current portion 195
75
Asset retirement obligation, long-term $ 44,266
$ 32,910


3.2.	EQUITY INVESTMENTS

Investments accounted for by the equity method consist of the following as of ~~September~~June 30, ~~2017~~2019 and December 31, ~~2016:~~2018:



			Carrying value				Loss (income) from equity method investments
	Approximate ownership %		June 30, 2019		December 31, 2018		Three months ended June 30,						Six months ended June 30,
	Approximate ownership %		June 30, 2019		December 31, 2018		2019			2018			2019			2018
			(In thousands)
Investment in Tatex Thailand II, LLC	23.5	%	$	—	$	—	$	(1,945	)	$	(63	)	$	(2,085	)	$	(104	)
Investment in Grizzly Oil Sands ULC	24.9999	%	51,607		44,259		(54		)	228			339			558
Investment in Timber Wolf Terminals LLC⁽¹⁾	—	%	—		—		—			534			—			536
Investment in Windsor Midstream LLC	22.5	%	39		39		—			(9		)	—			(9		)
Investment in Mammoth Energy Services, Inc.	21.8	%	67,661		191,823		127,581			(9,242		)	123,055			(22,712		)
Investment in Strike Force Midstream LLC⁽²⁾	—	%	—		—		—			(336		)	—			(693		)
			$	119,307	$	236,121	$	125,582		$	(8,888	)	$	121,309		$	(22,424	)

Carrying value
(Income) loss from equity method investments

Approximate ownership % September 30, 2017 December 31, 2016 Three months ended September 30, Nine months ended September 30,
2017 2016 2017 2016
(In thousands)
Investment in Tatex Thailand II, LLC 23.5 % $ —
$ —
$ (95 ) $ (253 ) $ (549 ) $ (412 )
Investment in Tatex Thailand III, LLC 17.9 % —
—
—
—
—
—
Investment in Grizzly Oil Sands ULC 24.9999 % 58,674
45,213
296
363
869
24,811
Investment in Timber Wolf Terminals LLC 50.0 % 983
991
4
3
8
7
Investment in Windsor Midstream LLC 22.5 % 31
25,749
(2 ) (9,014 ) 25,232
(12,062 )
Investment in Stingray Cementing LLC⁽¹⁾
— % —
1,920
—
79
205
187
Investment in Blackhawk Midstream LLC 48.5 % —
—
—
—
—
—
Investment in Stingray Energy Services LLC⁽¹⁾
— % —
4,215
—
294
282
935
Investment in Sturgeon Acquisitions LLC⁽¹⁾
— % —
20,526
—
112
(71 ) 623
Investment in Mammoth Energy Services, Inc.⁽¹⁾
25.1 % 149,219
111,717
2,407
2,518
(7,616 ) 11,527
Investment in Strike Force Midstream LLC 25.0 % 70,375
33,589
127
(99 ) 2,585
(40 )
$ 279,282

$ 243,920

$ 2,737
$ (5,997 ) $ 20,945
$ 25,576




(1)	On June 5, ~~2017, Mammoth Energy Services, Inc. acquired Stingray Cementing~~2018, the Company received its final distribution from Timber Wolf Terminals LLC ~~Stingray Energy Services LLC and Sturgeon Acquisitions LLC.~~("Timber Wolf"). See below under ~~Mammoth Energy Partners LP/Mammoth Energy Services, Inc.~~ Timber Wolf Terminals LLC for information regarding ~~these transactions.~~the subsequent dissolution of Timber Wolf.
(2)		On May 1, 2018, the Company sold its 25% interest in Strike Force Midstream LLC ("Strike Force") to EQT Midstream Partners, LP. See below 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~~June 30, ~~2017~~2019 and December 31, ~~2016.~~2018.

~~Table of Contents~~

Summarized balance sheet information:



	June 30, 2019		December 31, 2018
	June 30, 2019		December 31, 2018
	(In thousands)
Current assets	$	477,559	$	471,733
Noncurrent assets	$	1,353,113	$	1,302,488
Current liabilities	$	167,901	$	239,975
Noncurrent liabilities	$	190,200	$	94,575

September 30, 2017 December 31, 2016

(In thousands)
Current assets $ 201,557
$ 148,733
Noncurrent assets $ 1,494,770
$ 1,305,407
Current liabilities $ 130,178
$ 57,173
Noncurrent liabilities $ 164,759
$ 67,680

Summarized results of operations:



	Three months ended June 30,					Six months ended June 30,
	2019			2018		2019		2018
	(In thousands)
Gross revenue	$	179,114		$	566,404	$	443,958	$	1,067,537
Net (loss) income	$	(4,072	)	$	49,018	$	20,684	$	113,470

Three months ended September 30, Nine months ended September 30,
2017 2016 2017 2016
(In thousands)
Gross revenue $ 160,950
$ 76,627
$ 357,901
$ 206,666
Net income (loss) $ 2,101
$ 35,212
$ (109,651 ) $ 9,344

Tatex Thailand II, LLC

The Company has an indirect ownership interest in Tatex Thailand II, LLC (“("Tatex ~~II”~~II"). Tatex II ~~holds~~held an 8.5% interest in APICO, LLC (“APICO”), an international oil and gas exploration ~~company.~~company, before selling its interest in June 2019. APICO has a reserve base located in Southeast Asia through its ownership of concessions covering approximately ~~180,000~~108,000 acres which includes the Phu Horm Field. The Company received ~~$0.5 million and $0.4~~$2.1 million in distributions from Tatex II during the ~~nine~~six months ended ~~September~~June 30, ~~2017 and 2016, respectively.~~

~~Tatex Thailand III, LLC~~

~~The Company has an ownership~~2019, of which $1.9 million related to proceeds from the sale of its interest in ~~Tatex Thailand III, LLC (“Tatex III”). Tatex III previously owned a concession covering approximately 245,000 acres in Southeast Asia. As~~APICO.

Table 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.Contents

Grizzly Oil Sands ULC

The Company, through its wholly owned subsidiary Grizzly Holdings Inc. (“Grizzly Holdings”), owns an approximate 24.9999% 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~~June 30, ~~2017,~~2019, Grizzly had approximately 830,000 acres under lease in the Athabasca, ~~and~~ Peace River and Cold Lake oil sands regions of Alberta, Canada. Initiation of steam injection at its first project, Algar Lake Phase 1, commenced in January 2014 and first bitumen production was achieved during the second quarter of 2014. In April 2015, Grizzly determined to cease bitumen production at its Algar Lake facility due to the level of commodity prices. Grizzly continues to monitor market conditions as it assesses future plans for the facility. The Company reviewed its investment in Grizzly ~~at March 31, 2016~~ for impairment ~~based on FASB ASC 323 due to certain qualitative factors~~at June 30, 2019 and ~~as such, engaged an independent third party to assist management in determining fair value calculations of its investment. As a result of the calculated fair values~~2018 and ~~other qualitative factors, the Company concluded that an other than temporary~~determined no impairment was required under FASB ASC 323, resulting in an impairment loss of $23.1 million for the three months ended March 31, 2016, which is included in loss from equity method investments, net in the consolidated statements of operations. As of and during the nine months ended September 30, 2017, commodity prices had increased as compared to the quarter ended March 31, 2016, and there were no impairment indicators that required further evaluation for impairment.required. If commodity prices decline in the future however, ~~further~~ impairment of the Company's investment in Grizzly may be necessary. During the ~~nine~~six months ended ~~September~~June 30, ~~2017,~~2019, Gulfport paid ~~$1.8~~$0.4 million in cash calls. Grizzly’s functional currency is the Canadian dollar. The Company’s investment in Grizzly was increased by ~~$6.7~~$3.5 million and ~~$12.5~~$7.3 million for the three and six months ended June 30, 2019, respectively, as a result of a foreign currency translation ~~gain for the three and nine months ended September 30, 2017, respectively.~~gain. The Company's investment in Grizzly was decreased by ~~$1.4~~$3.4 million and $8.7 million for the three and six months ended June 30, 2018, respectively, as a result of a foreign currency translation ~~loss and increased by $8.3 million as a result of a foreign currency translation gain for the three and nine months ended September 30, 2016, respectively.~~

~~Table of Contents~~

loss.

Timber Wolf Terminals LLC

During 2012, the Company invested in Timber ~~Wolf Terminals LLC (“Timber Wolf”).~~Wolf. Timber Wolf was formed to operate a crude/condensate terminal and a sand transloading facility in Ohio. Timber Wolf was dissolved in 2018.

Windsor Midstream LLC

At ~~September~~June 30, ~~2017,~~2019, the Company held a 22.5% interest in Windsor Midstream LLC (“Midstream”), an entity controlled and managed by an unrelated third party. Midstream previously owned a 28.4% interest in Coronado Midstream LLC (“Coronado”), a gas processing plant in West Texas. In March 2015, Coronado was sold to EnLink Midstream Partners, LP (“EnLink”). As a result of the sale of Coronado to EnLink, Midstream received common units of EnLink, which were subsequently sold by Midstream. During the nine months ended September 30, 2017, the Company noted that Midstream had not recorded certain activity and fair value treatment of Midstream's investment in EnLink common units in a timely manner. The corresponding effect of this treatment was immaterial to the Company's previously issued financial statements and the recording of the correction in the current periods' financial statements was not material to the Company's estimated net income for the current full fiscal year. For the nine months ended September 30, 2017, approximately $23.4 million of the loss from equity method investments, net was related to the out-of-period activity associated with the accounting for Midstream's investment in EnLink common units. The Company received ~~$0.5 million and $14.2 million in~~no distributions from Midstream during the ~~nine~~six months ended ~~September~~June 30, ~~2017 and 2016, respectively.~~2019.

~~Stingray Cementing LLC~~

~~During 2012,~~As of June 30, 2019, 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, Mammoth Energy Services, Inc. (“Mammoth Energy”) acquired Stingray Cementing. See below under ~~Mammoth Energy Partners LP/Mammoth Energy Services, Inc.~~ ~~for information regarding this transaction.~~

~~Blackhawk~~determined that Midstream ~~LLC~~

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

~~Stingray Energy Services LLC~~

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

~~Sturgeon Acquisitions LLC~~

During 2014, the Company invested $20.7 million and received an ownership interest of 25% in Sturgeon Acquisitions LLC (“Sturgeon”). Sturgeon owns and operates sand mines that produce hydraulic fracturing grade sand. On June 5, 2017, Mammoth Energy acquired Sturgeon. 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~~was a 30.5% interest in this entity. Mammoth originally intended to pursue its initial public offering in 2014 or 2015; however, due to low commodity prices, the offering was postponed. In October 2016, Mammoth converted from a limited partnership into a limited liability company named Mammoth Energy Partners LLC (“Mammoth LLC”) and the Company and the other members of Mammoth LLC contributed their interests in Mammoth LLC to Mammoth Energy. The Company received 9,150,000 shares of Mammoth Energy common stock in return for its contribution. Following the contribution, Mammoth Energy completed its initial public offering (the “IPO”) of 7,750,000 shares of its common stock at a

~~Table of Contents~~

public offering price of $15.00 per share, of which 7,500,000 shares were sold by Mammoth Energy, and 250,000 shares were sold by certain selling stockholders, including 76,250 shares sold by the Company for which it received net proceeds of $1.1 million.

On June 5, 2017, the Company contributed all of its membership interests in Sturgeon (which owns Taylor Frac, LLC, Taylor Real Estate Investments, LLC and South River Road, LLC), Stingray Energy and Stingray Cementing to Mammoth Energy in exchange for approximately 2.0 million shares of Mammoth Energy common stock. As of September 30, 2017, the Company held approximately 25.1% of Mammoth Energy’s outstanding common stock. The Company accounted for the transactions as a sale of financial assets under FASB ASC 860. The Company valued the shares of Mammoth Energy common stock it received in the transactions at $18.50 per share, which was the closing price of Mammoth Energy common stock on June 5, 2017. The Company recognized a gain of $12.5 million from the transactions, which is included in loss from equity method investments, net in the accompanying consolidated statements of operations.

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. The Company's investment in Mammoth Energy was increased by a $0.2 million foreign currency gain and decreased by a $1.1 million foreign currency loss resulting from Mammoth Energy's foreign subsidiary for the three and nine months ended September 30, 2016, respectively. The (income) loss from equity method investments presented in the table above reflects any intercompany profit eliminations.

~~Strike Force Midstream LLC~~

In February 2016, the Company, through its wholly owned subsidiary Gulfport Midstream Holdings, LLC (“Midstream Holdings”), entered into an agreement with Rice Midstream Holdings LLC (“Rice”), a subsidiary of Rice Energy Inc., to develop natural gas gathering assets in eastern Belmont County and Monroe County, Ohio (the “dedicated areas”). The Company contributed certain gathering assets for a 25% interest in the newly formed entity called Strike Force Midstream LLC (“Strike Force”). Rice acts as operator and owns the remaining 75% interest in Strike Force. Construction of the gathering assets, which is ongoing, is expected to provide gathering services for Gulfport operated wells and connectivity of existing dry gas gathering systems. 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. During the nine months ended September 30, 2016, Gulfport paid $4.0 million in cash calls to Strike Force.

The Company accounted for its initial contribution to Strike Force at fair value under applicable codification guidance. The Company estimated the fair market value of its investment in Strike Force as of the contribution date using the discounted cash flow method under the income approach, based on an independently prepared valuation of the contributed assets. The fair market value was reduced by a discount factor for the lack of marketability due to the Company’s minority interest, resulting in a fair value of $22.5 million for the Company’s 25% interest. The fair value of the assets contributed was estimated using assumptions that represent Level 3 inputs. See “Note 11 - Fair Value Measurements” for additional discussion of the measurement inputs. The Company has elected to report its proportionate share of Strike Force’s earnings on a one-quarter lag as permitted under FASB ASC 323. The (income) loss from equity method investments presented in the table above reflects any intercompany profit eliminations.


4.	~~VARIABLE INTEREST ENTITIES~~

~~As of September 30, 2017, the Company held variable interests in the following~~ variable interest ~~entities (“VIEs”~~entity ("VIE"), 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.~~interest in Midstream. This entity is considered a VIE because the limited partners lack substantive kick-out or participating rights over the general partner. The general partner ~~or managing member~~ has power to direct the activities that most significantly impact ~~the VIEs’~~Midstream's economic performance. The Company also held a variable interest in Strike Force due to the fact that it does not have sufficient equity capital at risk. The Company is not the primary beneficiary of this entity. Prior to Mammoth Energy’s IPO, Mammoth LLC was considered a variable interest entity. As a result of the Company’s contribution of its interest in Mammoth LLC to Mammoth Energy in exchange for Mammoth Energy common stock and Mammoth Energy’s IPO, the Company determined that it no longer held an interest in a variable interest entity. 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 variable interest entity.

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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

Mammoth Energy Services, Inc.

At June 30, 2019, the Company owned 9,829,548 shares, or approximately 21.8%, of the outstanding common stock of Mammoth Energy Services, Inc. ("Mammoth Energy"). The Company reviewed its investment in Mammoth Energy as of June 30, 2019 for impairment based on certain qualitative and quantitative factors. As a result of the calculated fair values and other qualitative factors, the Company concluded that an other than temporary impairment was indicated. This resulted in recording an aggregate impairment loss of $125.4 million for the six months ended June 30, 2019, which is included in loss (income) from equity method investments, net in the accompanying consolidated statements of operations. ~~See Note 3~~If Mammoth Energy's common stock continues to trade below the Company's carrying value for a prolonged period of time, further ~~discussion~~impairment of ~~these entities, including~~ the ~~carrying amounts~~Company's investment in Mammoth Energy may be necessary. The Company’s investment in Mammoth Energy was increased by $0.1 million and $0.2 million foreign currency gains resulting from Mammoth Energy's foreign subsidiary for the three and six months ended June 30, 2019, respectively. The Company’s investment in Mammoth Energy was decreased by a $0.1 million and $0.3 million foreign currency loss resulting from Mammoth Energy’s foreign subsidiary for the three and six months ended June 30, 2018, respectively. During the six months ended June 30, 2019, Gulfport received distributions of ~~each investment.~~$2.5 million from Mammoth Energy as a result of $0.125 per share dividends in February 2019 and May 2019. The approximate fair value of the Company's investment in Mammoth Energy's common stock at June 30, 2019 was $67.7 million based on the quoted market price of Mammoth Energy's common stock. The loss (income) from equity method investments presented in the table above reflects any intercompany profit eliminations.

Strike Force Midstream LLC

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develop natural gas gathering assets in eastern Belmont County and Monroe County, Ohio through Strike Force. In 2017, Rice was acquired by EQT Corporation ("EQT"). The Company owned a 25% interest in Strike Force, which was sold to EQT Midstream Partners, LP in May 2018. The loss (income) from equity method investments presented in the table above reflects any intercompany profit eliminations.


5.3.	LONG-TERM DEBT

Long-term debt consisted of the following items as of ~~September~~June 30, ~~2017~~2019 and December 31, ~~2016:~~2018:



	June 30, 2019			December 31, 2018
	(In thousands)
Revolving credit agreement⁽¹⁾	$	155,000		$	45,000
6.625% senior unsecured notes due 2023	350,000			350,000
6.000% senior unsecured notes due 2024	650,000			650,000
6.375% senior unsecured notes due 2025	600,000			600,000
6.375% senior unsecured notes due 2026	450,000			450,000
Net unamortized debt issuance costs⁽²⁾	(28,426		)	(30,733		)
Construction loan	22,719			23,149
Less: current maturities of long term debt	(615		)	(651		)
Debt reflected as long term	$	2,198,678		$	2,086,765

September 30, 2017 December 31, 2016
(In thousands)
Revolving credit agreement (1) $ 365,000
$ —
7.75% senior unsecured notes due 2020 (2) —
—
6.625% senior unsecured notes due 2023 (3) 350,000
350,000
6.000% senior unsecured notes due 2024 (4) 650,000
650,000
6.375% senior unsecured notes due 2025 (5) 600,000
600,000
Net unamortized debt issuance costs (6) (30,111 ) (27,174 )
Construction loan (7) 23,817
21,049
Less: current maturities of long term debt (570 ) (276 )
Debt reflected as long term $ 1,958,136
$ 1,593,599

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. The Company capitalized approximately $4.7 million and $7.7 million in interest expense to undeveloped oil and natural gas properties during the three and nine months ended September 30, 2016, respectively. During the three and nine months ended September 30, 2016, the Company also capitalized approximately $0.5 million and $1.2 million, respectively, in interest expense related to building construction. Construction on the building was completed in December 2016 and, as such, the Company did not capitalize any interest expense related to building construction for the three and nine months ended September 30, 2017.

(1) The Company has entered into a senior secured revolving credit facility, as amended (the "revolving credit facility"), with The Bank of Nova Scotia, as the lead arranger and administrative agent and ~~certain lenders from time to time party thereto. The credit agreement provides for a maximum facility amount of $1.5 billion and matures on~~other lenders. On June ~~6, 2018. On December 13, 2016,~~3, 2019, the Company further amended its revolving credit facility to, among other things, (a) reset the maturity date to December 31, 2021, (b) adjust lenders, (c) increase the basket for unsecured debt issuances to $1.6 billion, (d) increase the interest rates by 50 basis points, (e) increase the mortgage requirement to 85% (from 80%), and (f) add deposit account control agreement language. On March 29, 2017,allow 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 anydesignate certain of its subsidiaries ~~in excess of $50.0 million. On May 4, 2017, the revolving credit facility was further amended~~as unrestricted subsidiaries and to ~~increase~~include LIBOR replacement provisions. Additionally, the borrowing base ~~from $700.0 million to $1.0~~was reaffirmed at $1.4 billion, ~~adjust certain of~~and the Company’s ~~investment baskets and add five additional banks to the syndicate.~~elected commitment amount remained at $1.0 billion.

As of ~~September~~June 30, ~~2017, $365.0~~2019, $155.0 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 ~~$237.5~~$251.5 million of letters of credit, was ~~$397.5~~$593.5 million. The Company’s ~~wholly-owned~~wholly owned subsidiaries have guaranteed the obligations of the Company under the revolving credit facility.

In connection with the Company's fall redetermination under its revolving credit facility, the lead lenders have proposed to increase the Company's borrowing base from $1.0 million to $1.2 billion, with an elected commitment of $1.0 billion, and decrease the interest rate by 50 basis points, subject to the approval of the additional required banks within the syndicate.

~~Advances~~At June 30, 2019, amounts borrowed under the revolving credit facility may be in the form of either base rate loans or eurodollar loans. The interest rate for base rate loans is equal to (1) the applicable rate, which ranges from 1.00% to 2.00%, plus (2) the highest of: (a) the

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federal funds rate plus 0.50%, (b) the rate of interest in effect for such day as publicly announced from time to time by agent as its “prime rate,” and (c) the eurodollar rate for an interest period of one month plus 1.00%. The interest rate for eurodollar loans is equal to (1) the applicable rate, which ranges from 2.00% to 3.00%, plus (2) the London interbank offered rate that appears on pages LIBOR01 or LIBOR02 of the Reuters screen that displays such rate for deposits in U.S. dollars, or, if such rate is not available, the rate as administered by ICE Benchmark Administration (or any other person that takes over administration of such rate) per annum equal to the offered rate on such other page or service that displays on average London interbank offered rate as determined by ICE Benchmark Administration (or any other person that takes over administration of such rate) for deposits in U.S. dollars, or, if such rate is not available, the average quotations for three major New York money center banks of whom the agent shall inquire as the “London Interbank Offered Rate” for deposits in U.S. dollars. At September 30, 2017, amounts borrowed under the credit facility bore interest at ~~the eurodollar~~a weighted average rate ~~(3.74%).~~

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

•~~incur indebtedness;~~

•~~grant liens;~~

•~~pay dividends and make other restricted payments;~~

•~~make investments;~~

•~~make fundamental changes;~~

•~~enter into swap contracts and forward sales contracts;~~

•~~dispose~~ of ~~assets;~~

•~~change the nature of their business; and~~

•~~enter into transactions with affiliates.~~

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

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

~~(ii) the ratio of EBITDAX to interest expense for a twelve-month period may not be less than 3.00 to 1.00.~~3.93%.

The Company was in compliance with ~~all~~its financial covenants under the revolving credit facility at ~~September~~June 30, ~~2017.~~2019.

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

In October 2016, the Company repurchased (in a cash tender offer) or redeemed all of the 2020 Notes, of which $600.0 million in aggregate principal amount was then outstanding, with the net proceeds from the issuance of its 6.000% Senior Notes

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~~due 2024 (the “2024 Notes”) discussed below and cash on hand, and the indenture governing the 2020 Notes was fully satisfied and discharged.~~

~~(3) On April 21, 2015, the Company issued $350.0 million in aggregate principal amount of~~ 6.625% Senior Notes due 2023 (the ~~“2023 Notes”~~"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~~6.000% Senior Notes due 2024 (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.

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

~~(5) On December 21, 2016, the Company issued $600.0 million in aggregate principal amount of~~ 6.375% Senior Notes due 2025 (the ~~“2025 Notes”~~"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~~6.375% Senior Notes due 2026 (the ~~“2025 Indenture”~~"2026 Notes"), to qualified institutional buyers pursuant to Rule 144A under the Securities Act of 1933, and to certain non-U.S. persons in accordance with Regulation S under the Securities Act. Under the 2025 Indenture, interest on the 2025 Notes accrues at a rate of 6.375% per annum on the outstanding principal amount thereof from December 21, 2016, payable semi-annually on May 15 and November 15 of each year, commencing on May 15, 2017. The 2025 Notes will mature on May 15, 2025. The Company received approximately $584.7 million in net proceeds from the offering of the 2025 Notes, which was used, together with the net proceeds from the Company’s December 2016 common stock offering and cash on hand, to fund the cash portion of the purchase price for the Vitruvian Acquisition. See “Note 1 – Acquisitions” for additional discussion of the Vitruvian Acquisition.

~~(6) In accordance with ASU 2015-03, loan issuance costs related to the 2023 Notes, the 2024 Notes and the 2025 Notes~~ (collectively the “Notes”) have been presented as a reduction to the Notes. At ~~September~~June 30, ~~2017,~~2019, total unamortized debt issuance costs were ~~$5.5~~$4.0 million for the 2023 Notes, ~~$10.2~~$8.1 million for the 2024 Notes, ~~and $14.3~~$11.7 million for the 2025 Notes and $4.7 million for the 2026 Notes. In addition, loan commitment fee costs for the Company's construction loan agreement ~~described immediately below~~ were $0.1 million at ~~September~~June 30, ~~2017.~~2019.

~~(7) On June 4, 2015, the~~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 $24.5capitalized approximately $1.0 million and ~~required~~$1.8 million in interest expense to undeveloped oil and natural gas properties during 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 annumthree and ~~was payable on the last day of the month through May 31, 2017. Monthly interest and principal payments are due beginning~~six months ended June 30, ~~2017, with~~2019, respectively. The Company capitalized approximately $1.5 million and $2.4 million in interest expense to undeveloped oil and natural gas properties during the ~~final payment due~~three and six months ended June ~~4, 2025. At September~~ 30, ~~2017, the total borrowings under the Construction Loan were approximately $23.8 million.~~2018, respectively.


6.4.	COMMON STOCK AND CHANGES IN CAPITALIZATION

~~Issuance~~Stock Repurchase Program

In January 2018, the board of ~~Common Stock~~

~~On March 15, 2016,~~directors of the Company ~~issued 16,905,000~~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 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. The repurchase program did not require the Company to acquire any

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specific number of shares. This repurchase program was authorized to extend through December 31, 2018 and the Company repurchased 20.7 million shares of ~~its~~ common stock in ~~an underwritten public offering (which included 2,205,000 shares sold pursuant to an option to purchase shares sold pursuant to an option to purchase additional shares~~2018 for $200.0 million in aggregate consideration.

~~Table~~In January 2019, the board of ~~Contents~~

directors of the ~~Company’s~~Company approved a new stock repurchase program to acquire up to $400 million of the Company's outstanding common stock ~~granted by~~within a 24 month period. 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, 2020 and ~~exercised in full~~may be suspended, modified, extended or discontinued by the ~~underwriters). The net proceeds from this equity offering were approximately $411.7 million, after underwriting discounts and commissions and offering expenses.~~board of directors at any time. The Company ~~used~~repurchased approximately 0.2 million and 3.8 million shares for a cost of approximately $1.8 million and $30.0 million during the ~~net proceeds from this offering primarily to fund a portion~~three and six months ended June 30, 2019, respectively. Additionally, during each of ~~its 2017 capital development plan~~the three and ~~for general corporate purposes.~~

~~On February 17, 2017,~~six months ended June 30, 2019, the Company ~~completed the Vitruvian Acquisition~~repurchased approximately 0.1 million shares for a ~~total initial purchase price~~cost of approximately ~~$1.85 billion, consisting~~$0.5 million and $0.6 million, respectively, to satisfy tax withholding requirements incurred upon the vesting of ~~$1.35 billion in cash, subject to certain adjustments,~~restricted stock. All repurchased shares have been canceled and ~~approximately 23.9 million shares of the Company’s common stock (of which approximately 5.2 million shares are subject~~returned to the ~~indemnity escrow). See “Note 1 - Acquisitions” for additional discussion~~status of ~~the Vitruvian Acquisition.~~authorized but unissued shares.


7.5.	STOCK-BASED COMPENSATION

The Company has granted restricted stock units to employees and directors pursuant to the 2013 Restated Incentive Stock Plan ("2013 Plan"), as discussed below. During the three and ~~nine~~six months ended ~~September~~June 30, ~~2017,~~2019, the Company’s stock-based compensation cost was $2.8 million and ~~$8.0~~$5.6 million, respectively, of which the Company capitalized $1.1 million and ~~$3.2~~$2.3 million, respectively, relating to its exploration and development efforts. During the three and ~~nine~~six months ended ~~September~~June 30, ~~2016,~~2018, the Company's stock-based compensation cost was ~~$3.0~~$3.3 million and ~~$9.6~~$6.0 million, respectively, of which the Company capitalized ~~$1.2~~$1.3 million and ~~$3.8~~$2.4 million, respectively, relating to its exploration and development efforts. Stock compensation costs, net of the amounts capitalized, are included in general and administrative expenses in the accompanying consolidated statements of operations.

The following table summarizes restricted stock unit activity for the ~~nine~~six months ended ~~September~~June 30, ~~2017:~~2019:



	Number of Unvested Restricted Stock Units		Weighted Average Grant Date Fair Value		Number of Unvested Performance Vesting Restricted Stock Units		Weighted Average Grant Date Fair Value
Unvested shares as of January 1, 2019	1,535,811		$	11.57	$	—	$	—
Granted	770,661		6.96		228,659		9.66
Vested	(325,193	)	10.08		—		—
Forfeited	(8,776	)	12.44		—		—
Unvested shares as of June 30, 2019	1,972,503		$	10.01	228,659		$	9.66

Number of
Unvested
Restricted Shares

Weighted
Average
Grant Date
Fair Value
Unvested shares as of January 1, 2017 613,056
$ 32.90
Granted 870,358
15.15
Vested (399,843 ) 28.77
Forfeited (74,024 ) 30.45
Unvested shares as of September 30, 2017 1,009,547
$ 19.42
Restricted Stock Units

Restricted stock units awarded under the 2013 Plan generally vest over a period of one year in the case of directors and three years in the case of employees and vesting is dependent upon the recipient meeting applicable service requirements. Stock-based compensation costs are recorded ratably over the service period. The grant date fair value of restricted stock units represents the closing market price of the Company's common stock on the date of grant. Unrecognized compensation expense as of ~~September~~June 30, ~~2017~~2019 related to restricted ~~shares~~stock units was ~~$17.2~~$13.8 million. The expense is expected to be recognized over a weighted average period of ~~1.61~~1.90 years.

Performance Vesting Restricted Stock Units

During the six months ended June 30, 2019, the Company awarded performance vesting units to its Chief Executive Officer under the 2013 Plan. The number of shares of common stock that will ultimately be issued will be determined by comparing the Company's total stockholder return relative to the total stockholder return of a predetermined group of peer companies at the end of the 36-month performance period. The grant date fair value was determined using the Monte Carlo simulation method and is being recorded ratably over the performance period. Expected volatilities utilized in the Monte Carlo model were estimated using a historical period consistent with the remaining performance period of approximately three years. The risk-free interest rate was based on the U.S. Treasury rate for a term commensurate with the expected life of the grant. The Company assumed a risk-free interest rate of 2.42% and a range of expected volatilities of 30.5% to 72.6% to estimate the fair

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value of performance vesting units granted during the six months ended June 30, 2019. Unrecognized compensation expense as of June 30, 2019 related to performance vesting restricted shares was $1.9 million. The expense is expected to be recognized over a weighted average period of 2.51 years.

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8.6.	EARNINGS PER SHARE

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



	Three months ended June 30,
	2019					2018
	Income		Shares	Per Share		Income		Shares	Per Share
	(In thousands, except share data)
Basic:
Net income	$	234,956	159,324,909	$	1.47	$	111,319	173,623,630	$	0.64
Effect of dilutive securities:
Stock options and awards	—		181,917			—		516,997
Diluted:
Net income	$	234,956	159,506,826	$	1.47	$	111,319	174,140,627	$	0.64

Three months ended September 30,
2017 2016
Income Shares
Per
Share
(Loss) Shares
Per
Share
(In thousands, except share data)
Basic:
Net income (loss) $ 18,235
182,957,416
$ 0.10
$ (157,296 ) 125,408,866
$ (1.25 )
Effect of dilutive securities:

Stock options and awards —
51,020

—
—

Diluted:
—

0
Net income (loss) $ 18,235
183,008,436
$ 0.10
$ (157,296 ) 125,408,866
$ (1.25 )



	Six months ended June 30,
	2019					2018
	Income		Shares	Per Share		Income		Shares	Per Share
	(In thousands, except share data)
Basic:
Net income	$	297,198	161,064,787	$	1.85	$	201,409	177,158,230	$	1.14
Effect of dilutive securities:
Stock options and awards	—		525,300			—		579,052
Diluted:
Net income	$	297,198	161,590,087	$	1.84	$	201,409	177,737,282	$	1.13

Nine months ended September 30,
2017 2016
Income Shares Per
Share (Loss) Shares Per
Share
(In thousands, except share data)
Basic:
Net income (loss) $ 278,626
178,736,569
$ 1.56
$ (739,339 ) 120,771,046
$ (6.12 )
Effect of dilutive securities:

Stock options and awards —
394,001

—
—

Diluted:
—

—

Net income (loss) $ 278,626
179,130,570
$ 1.56
$ (739,339 ) 120,771,046
$ (6.12 )

~~There were 603,068 and 598,753 shares of common stock that were considered anti-dilutive for the three months and nine months ended September 30, 2016, respectively.~~

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9.7.	COMMITMENTS AND CONTINGENCIES

~~Plugging and Abandonment Funds~~

In connection with the Company’s acquisition in 1997 of the remaining 50% interest in its WCBB properties, the Company assumed the seller’s (Chevron) obligation to contribute approximately $18,000 per month through March 2004 to a plugging and abandonment trust and the obligation to plug a minimum of 20 wells per year for 20 years commencing March 11, 1997. Chevron retained a security interest in production from these properties until the Company’s abandonment obligations to Chevron have been fulfilled. Beginning in 2009, the Company could access the trust for use in plugging and abandonment charges associated with the property, although it has not yet done so. As of September 30, 2017, the plugging and abandonment trust totaled approximately $3.1 million. At September 30, 2017, the Company had plugged 551 wells at WCBB since it began its plugging program in 1997, which management believes fulfills its minimum plugging obligation.

~~Operating Leases~~

~~The Company leases office facilities under non-cancellable operating leases exceeding one year. Future minimum lease commitments under these leases at September 30, 2017 were as follows:~~

(In thousands)
Remaining 2017 $ 27
2018 54
Total $ 81

Firm Transportation and Sales Commitments

~~The Company had approximately 3,077,000 MMBtu per day of firm sales contracted with third parties.~~ The table below presents ~~these~~the firm sales commitments ~~at September 30, 2017 as follows:~~by year:



		(MMBtu per day)
Remaining 2019		493,000
2020		276,000
2021		179,000
2022		70,000
2023		42,000
Thereafter		25,000
Total		1,085,000

(MMBtu per day)
Remaining 2017 710,000
2018 561,000
2019 659,000
2020 526,000
2021 372,000
Thereafter 249,000
Total 3,077,000

~~The Company also had approximately $3.7 billion of firm transportation contracted with third parties.~~ The table below presents ~~these~~the firm transportation commitments ~~at September 30, 2017 as follows:~~by year:



	(In thousands)
Remaining 2019	$	122,128
2020	273,973
2021	273,011
2022	273,011
2023	268,209
Thereafter	2,283,229
Total	$	3,493,561

(In thousands)
Remaining 2017 $ 49,052
2018 238,767
2019 243,389
2020 240,746
2021 239,786
Thereafter 2,715,005
Total $ 3,726,745

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Other Commitments

Effective October 1, 2014, the Company entered into a Sand Supply Agreement with Muskie Proppant LLC (“Muskie”), a subsidiary of Mammoth Energy ~~that expires on September 30, 2018.~~and a related party. Pursuant to this agreement, as amended effective August 3, 2018, the Company has agreed to purchase annual and monthly amounts of proppant sand subject to exceptions specified in the agreement at agreed pricing plus agreed costs and ~~expenses.~~expenses through 2021. Failure by either Muskie or the Company to deliver or accept the minimum monthly amount results in damages calculated per ton based on the difference between the monthly obligation amount and the amount actually delivered or accepted, as applicable. The Company ~~incurred $0.2 million and $2.1 million related to~~did not incur any non-utilization fees under this agreement during the three months ended June 30, 2019 and ~~nine~~incurred $0.3 million of such fees during the six months ended ~~September~~June 30, ~~2016, respectively.~~2019. The Company did not incur any non-utilization fees during the three ~~and nine~~ months ended ~~September~~June 30, ~~2017.~~

~~Effective October 1, 2014,~~2018 and incurred $0.9 million of such fees during the Company entered into an Amended and Restated Master Services Agreement for pressure pumping services with Stingray Pressure Pumping LLC (“Stingray Pressure”), a subsidiary of Mammoth Energy, that expires on Septembersix months ended June 30, 2018. Pursuant to this agreement, as amended, Stingray Pressure has agreed to provide hydraulic fracturing, stimulation and related completion and rework services to the Company and the Company has agreed to pay Stingray Pressure a monthly service fee plus the associated costs of the services provided.

Future minimum commitments under this agreement at June 30, 2019 are:



	(In thousands)
Remaining 2019	$	12,000
2020	24,000
2021	24,000
Total	$	60,000

Litigation and Regulatory Proceedings

The Company is involved in a number of litigation and regulatory proceedings including those described below. Many of these ~~agreements at September 30, 2017~~proceedings are ~~as follows:~~in early stages, and many of them seek or may seek damages and penalties, the amount of which is

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(In thousands)
Remaining 2017 $ 13,110
2018 39,330
Total $ 52,440

~~Litigation~~indeterminate. The Company's total accrued liabilities in respect of litigation and regulatory proceedings is determined on a case-by-case basis and represents an estimate of probable losses after considering, among other factors, the progress of each case or proceeding, its experience and the experience of others in similar cases or proceedings, and the opinions and views of legal counsel. Significant judgment is required in making these estimates and their final liabilities may ultimately be materially different.

InThe Company, along with a number of other oil and gas companies, has been named as a defendant in two separate complaints, one filed by the State of Louisiana and the Parish of Cameron in the 38th Judicial District Court for the Parish of Cameron on February 9, 2016 and the other filed by the State of Louisiana and the District Attorney for the 15^th Judicial District of the State of Louisiana in the 15^th Judicial District Court for the Parish of ~~Vermillion~~Vermilion on July 29, 2016 (together, the ~~Company was named as a defendant, among 26 oil and gas companies, in the Cameron Parish complaint and among more than 40 oil and gas companies in the Vermillion Parish complaint, or the Complaints.~~"Complaints"). The Complaints ~~were filed under~~allege that certain of the defendants’ operations violated the State and Local Coastal Resources Management Act of 1978, as amended, and the rules, regulations, orders and ordinances adopted thereunder which the Company referred to collectively as the CZM Laws, and allege that certain of the defendants’ oil and gas exploration, production and transportation operations associated with the development of the East Hackberry and West Hackberry oil and gas fields, in the case of the Cameron Parish complaint, and the Tigre Lagoon and Lac Blanc oil and gas fields, in the case of the Vermillion Parish complaint, were conducted in violation of the CZM Laws. The Complaints allege that such activities caused(the "CZM Laws") by causing 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.Parish. The Complaints also allege that the defendants’ oil and gas activities have resulted in the dredging of numerous canals, which had a direct and significant impact on the state coastal waters within the relevant Parish and that the defendants, among other things, failed to design, construct and maintain these canals using the best practical techniques to prevent bank slumping, erosion and saltwater intrusion and to minimize the potential for inland movement of storm-generated surges, which activities allegedly have resulted in the erosion of marshes and the degradation of terrestrial and aquatic life therein. The Complaints also allege that the defendants failed to re-vegetate, refill, clean, detoxify and otherwise restore these canals to their original condition. In these two petitions, the plaintiffs seek damages and other appropriate relief under the CZM Laws, including the payment of costs necessary to clear, re-vegetate, detoxify and otherwise restore the affected coastal zone of the relevant Parish to its original condition, actual restoration of such coastal zone to its original condition, and the payment of reasonable attorney fees and legal expenses and ~~pre-judgment and post judgment~~ interest.

The Company was served with the Cameron complaint in early May 2016 and with the Vermillion complaint in early September 2016. The Louisiana Attorney General and the Louisiana Department of Natural Resources intervened in both the Cameron Parish suit and the Vermillion Parish suit. Shortly after the Complaints were filed, certain defendantscases have been removed ~~the cases to the lawsuit~~ to the United States District Court for the Western District of ~~Louisiana. In both cases, the plaintiffs filed a motion~~Louisiana, and motions to remand and the plaintiffs agreed to an extension of time for all defendants to file responsive pleadings until the District Courts ruled on the motions to remand. In the Vermilion Parish case, the District Court entered an order on September 26, 2017 remanding the lawsuit to the 15th Judicial District Court, State of Louisiana, Parish of Vermilion. Pursuant to anare pending.

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~~agreement with plaintiffs’ counsel, all defendants have an extension of time through November 27, 2017 to file responsive pleadings to plaintiffs’ petitions~~The cases are still in the Vermilion Parish lawsuit. In the Cameron Parish lawsuit, the District Court has not ruled on plaintiffs’ motion to remand. Briefing on the motion to remand has been completed; however, no hearing has been set for the motion to remand,their early stages and the District Court has not given the parties any indication regarding when a ruling should be expected. Due the procedural posture of lawsuits, the fact that responsive pleadings have not been filed and the fact that the parties have ~~not begun discovery,~~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~~SEC Investigation

The SEC has commenced an investigation with respect to certain actions by former Company management, including alleged improper personal use of Company assets, and potential violations by former management and the Company of the Sarbanes-Oxley Act of 2002 in connection with such actions. The Company has fully cooperated and intends to continue to cooperate fully with the SEC’s investigation. Although it is not possible to predict the ultimate resolution or financial liability with respect to this matter, the Company believes that the outcome of this matter will not have a material effect on the Company’s business, financial condition or results of operations.

Business Operations

The Company is involved in various lawsuits and disputes incidental to its business operations, including commercial disputes, personal injury claims, royalty claims, property damage claims and contract actions.

Environmental Contingencies

The nature of the ~~Company’s~~oil and gas business carries with it certain environmental risks for Gulfport and its subsidiaries. They have implemented various policies, programs, procedures, training and audits to reduce and mitigate such environmental risks. They conduct periodic reviews, on a company-wide basis, to assess changes in their environmental risk profile. Environmental reserves are established for environmental liabilities for which economic losses are probable and reasonably estimable. The Company manages its exposure to environmental liabilities in acquisitions by using an evaluation process that seeks to identify pre-existing contamination or compliance concerns and address the potential liability. Depending on the extent of an identified environmental concern, they may, among other things, exclude a property from the transaction, require the seller to remediate the property to their satisfaction in an acquisition or agree to assume liability for the remediation of the property.

The Company received several Finding of Violation (“FOVs”) from the United States Environmental Protection Agency ("USEPA") alleging violations of the Clean Air Act at approximately 12 locations in Ohio. The first FOV for one site was dated December 11, 2013. Two subsequent FOVs incorporated and expanded the scope on January 4, 2017 and April 15, 2019. The Company has exchanged information with the USEPA and is ~~from time to time, involved~~engaged in ~~routine litigation~~discussions aimed at resolving the allegations. Resolution of the matter may result in monetary sanctions of more than $100,000.

Other Matters

Based on management’s current assessment, they are of the opinion that no pending or ~~subject to disputes~~threatened lawsuit or ~~claims related~~dispute relating 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, willoperations is likely to have a material adverse effect on ~~its~~their future consolidated financial ~~condition, cash flows or~~ position,

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results of ~~operations.~~operations or cash flows. The final resolution of such matters could exceed amounts accrued, however, and actual results could differ materially from management’s estimates.


~~10.~~8.	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 ~~natural gas liquids~~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 ~~pentane.~~ethane. Below is a summary of the Company’s open fixed price swap positions as of ~~September~~June 30, ~~2017.~~2019.



	Location	Daily Volume (MMBtu/day)	Weighted Average Price
Remaining 2019	NYMEX Henry Hub	1,380,000	$	2.81
2020	NYMEX Henry Hub	204,000	$	2.77

Location Daily Volume (MMBtu/day) Weighted
Average Price
Remaining 2017 NYMEX Henry Hub 765,000
$ 3.19
2018 NYMEX Henry Hub 898,000
$ 3.06
2019 NYMEX Henry Hub 112,000
$ 3.01



	Location	Daily Volume (Bbls/day)	Weighted Average Price
Remaining 2019	NYMEX WTI	6,000	$	60.81
2020	NYMEX WTI	6,000	$	59.82



	Location	Daily Volume (Bbls/day)	Weighted Average Price
Remaining 2019	Mont Belvieu C2	1,000	$	18.48
Remaining 2019	Mont Belvieu C3	4,000	$	29.02
Remaining 2019	Mont Belvieu C5	1,000	$	53.71

Location Daily Volume
(Bbls/day) Weighted
Average Price
Remaining 2017 ARGUS LLS 1,500
$ 53.12
2018 ARGUS LLS 1,000
$ 53.91
Remaining 2017 NYMEX WTI 4,500
$ 54.89
2018 NYMEX WTI 3,000
$ 52.24

Location Daily Volume
(Bbls/day) Weighted
Average Price
Remaining 2017 Mont Belvieu C3 3,000
$ 26.63
2018 Mont Belvieu C3 3,500
$ 28.03
Remaining 2017 Mont Belvieu C5 250
$ 49.14
2018 Mont Belvieu C5 500
$ 46.62

The Company sold call options and used the associated premiums to enhance the fixed price for a portion of the fixed price natural gas swaps listed above. Each short call option has an established ceiling price. When the referenced settlement price is above the price ceiling established by these short call options, the Company pays its counterparty an amount equal to the difference between the referenced settlement price and the price ceiling multiplied by the hedged contract volumes.



	Location	Daily Volume (MMBtu/day)	Weighted Average Price
Remaining 2019	NYMEX Henry Hub	30,000	$	3.10

Location Daily Volume (MMBtu/day) Weighted Average Price
Remaining 2017 NYMEX Henry Hub 65,000
$ 3.11
2018 NYMEX Henry Hub 103,000
$ 3.25
2019 NYMEX Henry Hub 135,000
$ 3.07

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

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

In addition, the Company ~~has~~ entered into natural gas basis swap ~~positions, which settle on the pricing index to basis differential of NGPL Mid-Continent to NYMEX Henry Hub.~~positions. As of ~~September~~June 30, ~~2017,~~2019, the Company had the following natural gas basis swap positions ~~for NGPL Mid-Continent.~~open:



	Gulfport Pays	Gulfport Receives	Daily Volume (MMBtu/day)	Weighted Average Fixed Spread
Remaining 2019	Transco Zone 4	NYMEX Plus Fixed Spread	60,000	$	(0.05	)
2020	Transco Zone 4	NYMEX Plus Fixed Spread	60,000	$	(0.05	)
2020	Fixed Spread	ONEOK Minus NYMEX	10,000	$	(0.54	)

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

Balance Sheet Presentation

The Company reports the fair value of derivative instruments on the consolidated balance sheets as derivative instruments under current assets, noncurrent assets, current liabilities and noncurrent liabilities on a gross basis. The Company determines the current and noncurrent classification based on the timing of expected future cash flows of individual trades. The following table presents the fair value of the Company’s derivative instruments on a gross basis at ~~September~~June 30, ~~2017~~2019 and December 31, ~~2016:~~2018:



	June 30, 2019		December 31, 2018
	(In thousands)
Short-term derivative instruments - asset	$	134,920	$	21,352
Long-term derivative instruments - asset	$	5,036	$	—
Short-term derivative instruments - liability	$	198	$	20,401
Long-term derivative instruments - liability	$	210	$	13,992

September 30, 2017 December 31, 2016
(In thousands)
Short-term derivative instruments - asset $ 35,332
$ 3,488
Long-term derivative instruments - asset $ 6,409
$ 5,696
Short-term derivative instruments - liability $ 29,130
$ 119,219
Long-term derivative instruments - liability $ 19,712
$ 26,759

Gains and Losses

The following table presents the gain and loss recognized in ~~Net~~net gain (loss) ~~gain~~ on natural gas, oil and NGL derivatives in the accompanying consolidated statements of operations for the three and ~~nine~~six months ended ~~September~~June 30, ~~2017~~2019 and ~~2016.~~2018.



	Net gain (loss) on derivative instruments
	Three months ended June 30,					Six months ended June 30,
	2019		2018			2019		2018
	(In thousands)
Natural gas derivatives	$	152,475	$	(31,194	)	$	136,044	$	(40,890	)
Oil derivatives	11,871		(24,419		)	11,417		(33,566		)
NGL derivatives	6,794		(14,932		)	3,634		(12,618		)
Total	$	171,140	$	(70,545	)	$	151,095	$	(87,074	)

Net (loss) gain on derivative instruments
Three months ended September 30, Nine months ended September 30,
2017 2016 2017 2016
(In thousands)
Natural gas derivatives $ (7,077 ) $ 33,167
$ 135,868
$ (43,454 )
Oil derivatives (6,571 ) 1,708
12,477
362
Natural gas liquids derivatives (9,212 ) 406
(6,757 ) (1,284 )
Total $ (22,860 ) $ 35,281
$ 141,588
$ (44,376 )

Offsetting of ~~derivative assets~~Derivative Assets and ~~liabilities~~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, 2017									As of June 30, 2019
	Gross Assets (Liabilities)			Gross Amounts						Gross Assets (Liabilities)			Gross Amounts
	Presented in the			Subject to Master			Net			Presented in the			Subject to Master			Net
	Consolidated Balance Sheets			Netting Agreements			Amount			Consolidated Balance Sheets			Netting Agreements			Amount
	(In thousands)									(In thousands)
Derivative assets	$	41,741		$	(36,969	)	$	4,772		$	139,956		$	(408	)	$	139,548
Derivative liabilities	$	(48,842	)	$	36,969		$	(11,873	)	$	(408	)	$	408		$	—

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



	As of December 31, 2018
	Gross Assets (Liabilities)			Gross Amounts
	Presented in the			Subject to Master			Net
	Consolidated Balance Sheets			Netting Agreements			Amount
	(In thousands)
Derivative assets	$	21,352		$	(19,289	)	$	2,063
Derivative liabilities	$	(34,393	)	$	19,289		$	(15,104	)

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.~~9.	FAIR VALUE MEASUREMENTS

The Company records certain financial and non-financial assets and liabilities on the balance sheet at fair value. Fair value ~~in accordance with FASB ASC 820,~~ ~~“Fair Value Measurement and Disclosures”~~ ~~(“FASB ASC 820”). FASB ASC 820 defines fair value as~~is the price that would be received to sell an asset or paid to transfer a liability (exit price) in an orderly transaction between market participants at the measurement date. ~~The statement establishes market~~Market or observable inputs asare the preferred

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sources of values, followed by assumptions based on hypothetical transactions in the absence of market inputs. ~~The statement requires fair~~Fair value measurements beare classified and disclosed in one of the following categories:

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

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

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

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

The following tables summarize the Company’s financial and non-financial assets and liabilities by ~~FASB ASC 820~~ valuation level as of ~~September~~June 30, ~~2017~~2019 and December 31, ~~2016:~~2018:


	September 30, 2017						June 30, 2019
	Level 1		Level 2		Level 3		Level 1		Level 2		Level 3
	(In thousands)						(In thousands)
Assets:
Derivative Instruments	$	—	$	41,741	$	—	$	—	$	139,956	$	—
Liabilities:
Derivative Instruments	$	—	$	48,842	$	—	$	—	$	408	$	—

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	December 31, 2016						December 31, 2018
	Level 1		Level 2		Level 3		Level 1		Level 2		Level 3
	(In thousands)						(In thousands)
Assets:
Derivative Instruments	$	—	$	9,184	$	—	$	—	$	21,352	$	—
Liabilities:
Derivative Instruments	$	—	$	145,978	$	—	$	—	$	34,393	$	—

The Company estimates the fair value of all derivative instruments using industry-standard models that ~~considered~~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~~

The fair value of the ~~Vitruvian Acquisition.~~Company's investment in Mammoth Energy as of June 30, 2019 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.

~~The Company estimates asset retirement obligations pursuant to the provisions of FASB ASC Topic 410,~~ ~~Asset Retirement and Environmental Obligations~~ ~~(“FASB ASC 410”).~~ The initial measurement of asset retirement obligations at fair value is

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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 21 for further discussion of the Company’s asset retirement obligations. Asset retirement obligations incurred during the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2019 were approximately ~~$11.6~~$5.2 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.

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

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


~~12.~~10.	FAIR VALUE OF FINANCIAL INSTRUMENTS

The carrying amounts on the accompanying consolidated balance sheet for cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities, and current debt are carried at cost, which approximates market value due to their short-term nature. Long-term debt related to the ~~Construction Loan~~Company's construction loan is carried at cost, which approximates market value based on the borrowing rates currently available to the Company with similar terms and maturities.

At ~~September~~June 30, ~~2017,~~2019, the carrying value of the outstanding debt represented by the Notes was approximately ~~$1.6~~$2.0 billion, including the unamortized debt issuance cost of approximately ~~$5.5~~$4.0 million related to the 2023 Notes, approximately ~~$10.2~~$8.1 million related to the 2024 Notes, ~~and~~ approximately ~~$14.3~~$11.7 million related to the 2025 Notes and approximately $4.7 million related to the 2026 Notes. Based on the quoted market price, the fair value of the Notes was determined to be approximately $1.6 billion at ~~September~~June 30, ~~2017.~~2019.


~~13.~~11.	~~CONDENSED CONSOLIDATING FINANCIAL INFORMATION~~REVENUE FROM CONTRACTS WITH CUSTOMERS

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

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payment date is usually within 30 days of the end of the calendar month in which the commodity is delivered. 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, and the Company's product sales that have a contractual term greater than one year have no long-term fixed consideration.

Contract Balances

Receivables from contracts with customers are recorded when the right to consideration becomes unconditional, generally when control of the product has been transferred to the customer. Receivables from contracts with customers were $131.7 million and $210.2 million as of June 30, 2019 and December 31, 2018, 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.

Prior-Period Performance Obligations

The Company records revenue in the month production is delivered to the purchaser. However, settlement statements for certain sales may be received for 30 to 90 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production that was delivered to the purchaser and the price that will be received for the sale of the product. The differences between the estimates and the actual amounts for product sales is recorded in the month that payment is received from the purchaser. For the six months ended June 30, 2019, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.


12.	LEASES

Effective January 1, 2019, the Company adopted Accounting Standards Update ("ASU") No. 2016-02, Leases (Topic 842). The new standard supersedes the previous lease guidance by requiring lessees to recognize a right-of-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 Company adopted the new standard on a prospective basis using the simplified transition method permitted by ASU No. 2018-11, Leases (Topic 842): Targeted Improvements. Offsetting right-of-use assets and corresponding lease liabilities recognized by the Company on the adoption date totaled approximately $110 million, representing minimum payment obligations associated with identified leases with contractual durations exceeding one year. No cumulative-effect adjustment to retained earnings was required upon adoption of the new standard. The Company elected the package of practical expedients permitted under the new standard, which among other things, allows for lease and non-lease components in a contract to be accounted for as a single lease component for all asset classes and the carry forward of historical lease classifications.

Nature of Leases

The Company has operating leases associated with drilling rig commitments, pressure pumping services, field offices and other equipment with remaining lease terms with contractual durations in excess of one year. Short-term leases that have an initial term of one year or less are not capitalized.

The Company has entered into contracts for drilling rigs with third parties to ensure rig availability in its key operating areas. The Company has concluded its drilling rig contracts are operating leases as the assets are identifiable and the evaluation that the Company has the right to control the identified assets. The Company's drilling rig commitments are typically structured with an initial term of one to two years and expire at various dates through 2021. These agreements typically include renewal options at the end of the initial term. Due to the nature of the Company's drilling schedules and potential volatility in commodity prices, the Company is unable to determine at commencement with reasonable certainty if the renewal options will be exercised; therefore, renewal options are not considered in the lease term for drilling contracts. The operating lease liabilities associated with these rig commitments are based on the minimum contractual obligations, primarily standby rates, and do not include variable amounts based on actual activity in a given period. Pursuant to the full cost method of accounting, these costs are capitalized as part of oil and natural gas properties on the accompanying consolidated balance sheets. A portion of these costs are borne by other interest owners.

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Effective October ~~17, 2012, December 21, 2012 and August 18,~~1, 2014, the Company ~~issued~~entered into an Amended and Restated Master Services Agreement for pressure pumping services with Stingray Pressure Pumping LLC (“Stingray Pressure”), a subsidiary of Mammoth Energy and a related party. Pursuant to this agreement, as amended effective July 1, 2018, Stingray Pressure has agreed to provide hydraulic fracturing, stimulation and related completion and rework services to the ~~2020 Notes~~Company through 2021 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. The Company has determined that the agreement with Stingray Pressure is an ~~aggregate~~operating lease due to the implicit identification of ~~$600.0 million principal amount.~~assets and the evaluation that the Company has the right to control the identified assets. The ~~2020 Notes were subsequently exchanged~~operating lease liability associated with this agreement is based on the minimum contractual obligations, which is the monthly service fee for ~~substantially identical notes~~one crew, and does not include variable amounts based on actual activity in a given period. Pursuant to the full cost method of accounting, these costs are capitalized as part of oil and natural gas properties on the accompanying consolidated balance sheets. A portion of these costs are borne by other interest owners.

The Company rents office space for its field locations and certain other equipment from third parties, which expire at various dates through 2024. These agreements are typically structured with non-cancelable terms of one to five years. The Company has determined these agreements represent operating leases with a lease term that equals the primary non-cancelable contract term. The Company has included any renewal options that it has determined are reasonably certain of exercise in the ~~same aggregate principal amount that were registered under~~determination of the ~~Securities Act. In October 2016,~~lease terms.

Discount Rate

As most of the Company's leases do not provide an implicit rate, the Company ~~repurchased (in~~uses its incremental borrowing rate based on the information available at commencement date in determining the present value of lease payments. The Company's incremental borrowing rate reflects the estimated rate of interest that it would pay to borrow on a collateralized basis over a similar term an amount equal to the lease payments in a similar economic environment.

Maturities of operating lease liabilities as of June 30, 2019 were as follows:



	(In thousands)
Remaining 2019	$	25,243
2020	27,481
2021	22,731
2022	115
2023	90
Thereafter	30
Total lease payments	$	75,690
Less: Imputed interest	(2,777		)
Total	$	72,913

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



	(In thousands)
Operating lease cost	$	16,284
Operating lease cost - related party	11,220
Variable lease cost	960
Variable lease cost - related party	59,611
Short-term lease cost	183
Total lease cost⁽¹⁾	$	88,258



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

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Supplemental cash ~~tender offer)~~flow information for the six months ended June 30, 2019 related to leases was as follows:



Cash paid for amounts included in the measurement of lease liabilities	(In thousands)
Operating cash flows from operating leases	$	120
Investing cash flow from operating leases	$	12,288
Investing cash flow from operating leases - related party	$	43,925

The weighted-average remaining lease term as of June 30, 2019 was 1.86 years. The weighted-average discount rate used to determine the operating lease liability as of June 30, 2019 was 3.78%.

13. 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 ~~redeemed~~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.

The Company’s ability to utilize NOL carryforwards and other tax attributes to reduce future federal taxable income is subject to potential limitations under Internal Revenue Code Section 382 (“Section 382”) and its related tax regulations. The utilization of these attributes may be limited if certain ownership changes by 5% stockholders (as defined in Treasury regulations pursuant to Section 382) and the effects of stock issuances by the Company during any three-year period result in a cumulative change of more than 50% in the beneficial ownership of Gulfport. The Company updates its Section 382 analysis to determine if an ownership change has occurred at each reporting period. If it is determined that an ownership change has occurred under these rules, the Company would generally be subject to an annual limitation on the use of pre-ownership change NOL carryforwards and certain other losses and/or credits. In addition, certain future transactions regarding the Company's equity, including the cumulative effects of small transactions as well as transactions beyond the Company’s control, could cause an ownership change and therefore a potential limitation on the annual utilization of its deferred tax assets.

For the three and six months ended June 30, 2019, the Company's estimated annual effective tax rates were approximately (322.5)% and (152.2)%, respectively. The change is primarily due to the release of the valuation allowance that was previously recorded against deferred tax assets of $179.3 million as a discrete adjustment in the quarter. The Company considered the release of the valuation allowance resulting from current period earnings in the estimated annual effective tax rate and recognized the tax benefit associated with future earnings as a discrete item.

For the three month period ended March 31, 2019, the Company maintained a full valuation allowance against its deferred tax assets based on its conclusion, considering all available evidence (both positive and negative), that it was more likely than not that the deferred tax assets would not be realized. A valuation allowance for deferred tax assets, including net operating losses, is recognized when it is more likely than not that some or all of the ~~2020 Notes, of which $600.0 million in aggregate principal amount was then outstanding, with the net proceeds~~benefit from the ~~issuance~~deferred tax assets will not be realized. To assess that likelihood, the Company uses estimates and judgment regarding future taxable income, and considers the tax laws in the jurisdiction where such taxable income is generated, to determine whether a valuation allowance is required. Such evidence can include current financial position, results of operations, both actual and forecasted, the reversal of deferred tax liabilities and tax planning strategies as well as the current and forecasted business economics of the ~~2024 Notes discussed below~~oil and ~~cash on hand.~~gas industry.

~~On April 21, 2015,~~

As of each reporting date, management considers new evidence, both positive and negative, that could affect its view of the future realization of deferred tax assets. As of June 30, 2019, in part because in the current year the Company ~~issued $350.0 million~~achieved more than three years of cumulative pretax income in ~~aggregate principal amount of~~ the ~~2023 Notes to qualified institutional buyers pursuant to Rule 144A under the Securities Act~~U.S. federal tax jurisdiction 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~~determined that an ownership change under Internal Revenue Code Section 382 did not occur that would further limit its ~~subsidiary guarantors entered into a registration rights agreement, dated as~~ability to utilize net operating loss carryforwards, management determined that there was sufficient positive evidence to conclude that it is more likely than not that additional deferred taxes 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~~$207.2 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.are realizable. The Company ~~used~~will recognize $27.7 million of valuation allowance release as part of its estimated annualized effective tax rate and $179.3 million as a discrete adjustment during the six month period ending June 30, 2019. It therefore reduced the valuation allowance accordingly. The Company maintained a valuation allowance of $4.8 million related to foreign tax credits, general business credits and 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 priceoperating losses in jurisdictions for ~~the Vitruvian Acquisition.~~which it has determined that it is more likely than not that deferred tax assets would not be realized.

14. CONDENSED CONSOLIDATING FINANCIAL INFORMATION

2524

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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.

The ~~2020 Notes were, and the~~ 2023 Notes, the 2024 Notes, the 2025 Notes and the ~~2025~~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 ~~2020 Notes were not, and the 2023 Notes, the 2024 Notes and the 2025~~ Notes are not guaranteed by Grizzly Holdings ~~Inc.~~or Mule Sky LLC ("Mule Sky") (the ~~“Non-Guarantor”~~“Non-Guarantors”). The Guarantors are 100% owned by Gulfport (the “Parent”), and the guarantees are full, unconditional, joint and several. There are no significant restrictions on the ability of the Parent or the Guarantors to obtain funds from each other in the form of a dividend or loan. Effective June 1, 2019, the Parent contributed interests in certain oil and gas assets and related liabilities to certain of the Guarantors.

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

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CONDENSED CONSOLIDATING BALANCE SHEETS

(Amounts in thousands)



	June 30, 2019
	Parent			Guarantors			Non-Guarantors			Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	10,940		$	9,799		$	38		$	—		$	20,777
Accounts receivable - oil and natural gas sales	4,116			127,559			—			—			131,675
Accounts receivable - joint interest and other	9,043			37,602			—			—			46,645
Accounts receivable - intercompany	819,584			433,776			—			(1,253,360		)	—
Prepaid expenses and other current assets	5,948			3,451			75			—			9,474
Short-term derivative instruments	134,920			—			—			—			134,920
Total current assets	984,551			612,187			113			(1,253,360		)	343,491

Property and equipment:
Oil and natural gas properties, full-cost accounting	1,352,894			9,158,193			69			(729		)	10,510,427
Other property and equipment	92,343			751			3,319			—			96,413
Accumulated depletion, depreciation, amortization and impairment	(1,414,011		)	(3,468,663		)	(55		)	—			(4,882,729		)
Property and equipment, net	31,226			5,690,281			3,333			(729		)	5,724,111
Other assets:
Equity investments and investments in subsidiaries	5,171,925			—			51,607			(5,104,225		)	119,307
Long-term derivative instruments	5,036			—			—			—			5,036
Deferred tax asset	179,331			—			—			—			179,331
Inventories	188			8,813			—			—			9,001
Operating lease assets	19,334			—			—			—			19,334
Operating lease assets - related parties	53,579			—			—			—			53,579
Other assets	11,682			598			—			—			12,280
Total other assets	5,441,075			9,411			51,607			(5,104,225		)	397,868
Total assets	$	6,456,852		$	6,311,879		$	55,053		$	(6,358,314	)	$	6,465,470

Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable and accrued liabilities	$	74,597		$	419,190		$	43		$	—		$	493,830
Accounts payable - intercompany	469,071			780,600			3,689			(1,253,360		)	—
Short-term derivative instruments	198			—			—			—			198
Current portion of operating lease liabilities	17,999			—			—			—			17,999
Current portion of operating lease liabilities - related parties	20,817			—			—			—			20,817
Current maturities of long-term debt	615			—			—			—			615
Total current liabilities	583,297			1,199,790			3,732			(1,253,360		)	533,459
Long-term derivative instruments	210			—			—			—			210
Asset retirement obligation - long-term	30,035			58,456			—			—			88,491
Deferred tax liability	3,127			—			—			—			3,127
Non-current operating lease liabilities	1,335			—			—			—			1,335
Non-current operating lease liabilities - related parties	32,762			—			—			—			32,762
Long-term debt, net of current maturities	2,198,678			—			—			—			2,198,678
Total liabilities	2,849,444			1,258,246			3,732			(1,253,360		)	2,858,062

Stockholders’ equity:
Common stock	1,594			—			—			—			1,594
Paid-in capital	4,202,599			4,170,574			262,059			(4,432,633		)	4,202,599
Accumulated other comprehensive loss	(48,615		)	—			(46,527		)	46,527			(48,615		)
(Accumulated deficit) retained earnings	(548,170		)	883,059			(164,211		)	(718,848		)	(548,170		)
Total stockholders’ equity	3,607,408			5,053,633			51,321			(5,104,954		)	3,607,408
Total liabilities and stockholders’ equity	$	6,456,852		$	6,311,879		$	55,053		$	(6,358,314	)	$	6,465,470

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CONDENSED CONSOLIDATING BALANCE SHEETS

(Amounts in thousands)



	December 31, 2018
	Parent			Guarantors			Non-Guarantor			Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	25,585		$	26,711		$	1		$	—		$	52,297
Accounts receivable - oil and natural gas sales	146,075			64,125			—			—			210,200
Accounts receivable - joint interest and other	16,212			6,285			—			—			22,497
Accounts receivable - intercompany	671,633			319,464			—			(991,097		)	—
Prepaid expenses and other current assets	8,433			2,174			—			—			10,607
Short-term derivative instruments	21,352			—			—			—			21,352
Total current assets	889,290			418,759			1			(991,097		)	316,953

Property and equipment:
Oil and natural gas properties, full-cost accounting,	7,044,550			2,983,015			—			(729		)	10,026,836
Other property and equipment	91,916			751			—			—			92,667
Accumulated depletion, depreciation, amortization and impairment	(4,640,059		)	(39		)	—			—			(4,640,098		)
Property and equipment, net	2,496,407			2,983,727			—			(729		)	5,479,405
Other assets:
Equity investments and investments in subsidiaries	2,856,988			—			44,259			(2,665,126		)	236,121
Inventories	3,620			1,134			—			—			4,754
Other assets	12,624			1,178			—			1			13,803
Total other assets	2,873,232			2,312			44,259			(2,665,125		)	254,678
Total assets	$	6,258,929		$	3,404,798		$	44,260		$	(3,656,951	)	$	6,051,036

Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable and accrued liabilities	$	419,107		$	99,273		$	—		$	—		$	518,380
Accounts payable - intercompany	320,259			670,708			130			(991,097		)	—
Short-term derivative instruments	20,401			—			—			—			20,401
Current maturities of long-term debt	651			—			—			—			651
Total current liabilities	760,418			769,981			130			(991,097		)	539,432
Long-term derivative instruments	13,992			—			—			—			13,992
Asset retirement obligation - long-term	66,859			13,093			—			—			79,952
Deferred tax liability	3,127			—			—			—			3,127
Long-term debt, net of current maturities	2,086,765			—			—			—			2,086,765
Total liabilities	2,931,161			783,074			130			(991,097		)	2,723,268

Stockholders’ equity:
Common stock	1,630			—			—			—			1,630
Paid-in capital	4,227,532			1,915,598			261,626			(2,177,224		)	4,227,532
Accumulated other comprehensive loss	(56,026		)	—			(53,783		)	53,783			(56,026		)
(Accumulated deficit) retained earnings	(845,368		)	706,126			(163,713		)	(542,413		)	(845,368		)
Total stockholders’ equity	3,327,768			2,621,724			44,130			(2,665,854		)	3,327,768
Total liabilities and stockholders’ equity	$	6,258,929		$	3,404,798		$	44,260		$	(3,656,951	)	$	6,051,036

September 30, 2017
Parent Guarantors Non-Guarantor Eliminations Consolidated
Assets
Current assets:
Cash and cash equivalents $ 89,095
$ 36,175
$ 1
$ —
$ 125,271
Accounts receivable - oil and natural gas 126,746
53,360
—
—
180,106
Accounts receivable - related parties 362
—
—
—
362
Accounts receivable - intercompany 514,187
57,927
—
(572,114 ) —
Prepaid expenses and other current assets 5,486
180
—
—
5,666
Short-term derivative instruments 35,332
—
—
—
35,332
Total current assets 771,208
147,642
1
(572,114 ) 346,737
Property and equipment:
Oil and natural gas properties, full-cost accounting 6,371,324
2,496,644
—
(729 ) 8,867,239
Other property and equipment 84,182
43
—
—
84,225
Accumulated depletion, depreciation, amortization and impairment (4,043,843 ) (36 ) —
—
(4,043,879 )
Property and equipment, net 2,411,663
2,496,651
—
(729 ) 4,907,585
Other assets:
Equity investments and investments in subsidiaries 2,262,011
70,375
58,674
(2,111,778 ) 279,282
Long-term derivative instruments 6,409
—
—
—
6,409
Deferred tax asset 4,692
—
—
—
4,692
Inventories 9,438
4,470
—
—
13,908
Other assets 10,561
8,424
—
—
18,985
Total other assets 2,293,111
83,269
58,674
(2,111,778 ) 323,276
Total assets $ 5,475,982
$ 2,727,562
$ 58,675
$ (2,684,621 ) $ 5,577,598

Liabilities and Stockholders’ Equity

Current liabilities:
Accounts payable and accrued liabilities $ 430,195
$ 152,733
$ —
$ —
$ 582,928
Accounts payable - intercompany 57,927
514,060
127
(572,114 ) —
Asset retirement obligation - current 195
—
—
—
195
Derivative instruments 29,130
—
—
—
29,130
Current maturities of long-term debt 570
—
—
—
570
Total current liabilities 518,017
666,793
127
(572,114 ) 612,823
Long-term derivative instrument 19,712
—
—
—
19,712
Asset retirement obligation - long-term 37,456
6,810
—
—
44,266
Long-term debt, net of current maturities 1,958,136
—
—
—
1,958,136
Total liabilities 2,533,321
673,603
127
(572,114 ) 2,634,937

Stockholders’ equity:
Common stock 1,831
—
—
—
1,831
Paid-in capital 4,413,623
1,905,599
258,871
(2,164,470 ) 4,413,623
Accumulated other comprehensive (loss) income (40,339 ) —
(38,443 ) 38,443
(40,339 )
Retained (deficit) earnings (1,432,454 ) 148,360
(161,880 ) 13,520
(1,432,454 )
Total stockholders’ equity 2,942,661
2,053,959
58,548
(2,112,507 ) 2,942,661
Total liabilities and stockholders’ equity
$ 5,475,982
$ 2,727,562
$ 58,675
$ (2,684,621 ) $ 5,577,598

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~~CONDENSED CONSOLIDATING BALANCE SHEETS~~

~~(Amounts in thousands)~~

December 31, 2016
Parent Guarantors Non-Guarantor Eliminations Consolidated
Assets
Current assets:
Cash and cash equivalents $ 1,273,882
$ 1,993
$ —
$ —
$ 1,275,875
Restricted Cash 185,000
—
—
—
185,000
Accounts receivable - oil and natural gas 137,087
37,496
—
(37,822 ) 136,761
Accounts receivable - related parties 16
—
—
—
16
Accounts receivable - intercompany 449,517
1,151
—
(450,668 ) —
Prepaid expenses and other current assets 3,135
—
—
—
3,135
Short-term derivative instruments 3,488
—
—
—
3,488
Total current assets 2,052,125
40,640
—
(488,490 ) 1,604,275

Property and equipment:
Oil and natural gas properties, full-cost accounting, 5,655,125
417,524
—
(729 ) 6,071,920
Other property and equipment 68,943
43
—
—
68,986
Accumulated depletion, depreciation, amortization and impairment (3,789,746 ) (34 ) —
—
(3,789,780 )
Property and equipment, net 1,934,322
417,533
—
(729 ) 2,351,126
Other assets:
Equity investments and investments in subsidiaries 236,327
33,590
45,213
(71,210 ) 243,920
Long-term derivative instruments 5,696
—
—
—
5,696
Deferred tax asset 4,692
—
—
—
4,692
Inventories 3,095
1,409
—
—
4,504
Other assets 8,932
—
—
—
8,932
Total other assets 258,742
34,999
45,213
(71,210 ) 267,744
Total assets $ 4,245,189
$ 493,172
$ 45,213
$ (560,429 ) $ 4,223,145

Liabilities and Stockholders’ Equity

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

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

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

~~Table of Contents~~

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

(Amounts in thousands)



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

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

Costs and expenses:
Lease operating expenses	12,256			10,132			—			—			22,388
Production taxes	2,820			5,278			—			—			8,098
Midstream gathering and processing expenses	28,121			43,894			—			—			72,015
Depreciation, depletion and amortization	80,132			44,764			55			—			124,951
General and administrative expenses	16,745			(3,583		)	103			—			13,265
Accretion expense	438			921			—			—			1,359
	140,512			101,406			158			—			242,076

INCOME (LOSS) FROM OPERATIONS	139,779			77,297			(158		)	—			216,918

OTHER EXPENSE (INCOME):
Interest expense	35,835			(955		)	—			—			34,880
Interest income	(120		)	(39		)	—			—			(159		)
Insurance proceeds	(83		)	—			—			—			(83		)
Loss (income) from equity method investments and investments in subsidiaries	47,449			—			(54		)	78,187			125,582
Other expense	1,073			—			—			—			1,073
	84,154			(994		)	(54		)	78,187			161,293

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

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

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

2928

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CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

(Amounts in thousands)



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

Total revenues	$	146,774		$	105,966		$	—		$	—		$	252,740

Costs and expenses:
Lease operating expenses	16,593			6,319			—			—			22,912
Production taxes	4,793			2,866			—			—			7,659
Midstream gathering and processing expenses	52,542			18,898			—			—			71,440
Depreciation, depletion and amortization	121,915			—			—			—			121,915
General and administrative expenses	14,975			(968		)	1			—			14,008
Accretion expense	795			220			—			—			1,015
	211,613			27,335			1			—			238,949

(LOSS) INCOME FROM OPERATIONS	(64,839		)	78,631			(1		)	—			13,791

OTHER (INCOME) EXPENSE:
Interest expense	34,663			(959		)	—			—			33,704
Interest income	(27		)	(6		)	—			—			(33		)
Insurance proceeds	(231		)	—			—			—			(231		)
Gain on sale of equity method investments	(25,616		)	(96,419		)	—			—			(122,035		)
(Income) loss from equity method investments and investments in subsidiaries	(183,901		)	(336		)	228			175,121			(8,888		)
Other (income) expense	(1,046		)	1			—			1,000			(45		)
	(176,158		)	(97,719		)	228			176,121			(97,528		)

INCOME (LOSS) BEFORE INCOME TAXES	111,319			176,350			(229		)	(176,121		)	111,319
INCOME TAX BENEFIT	—			—			—			—			—

NET INCOME (LOSS)	$	111,319		$	176,350		$	(229	)	$	(176,121	)	$	111,319

Three months ended September 30, 2016
Parent Guarantors Non-Guarantor Eliminations Consolidated

Total revenues $ 193,227
$ 465
$ —
$ —
$ 193,692

Costs and expenses:
Lease operating expenses 17,283
188
—
—
17,471
Production taxes 3,495
30
—
—
3,525
Midstream gathering and processing 45,385
90
—
—
45,475
Depreciation, depletion, and amortization 62,284
1
—
—
62,285
Impairment of oil and natural gas properties 212,194
—
—
—
212,194
General and administrative 10,772
(305 ) —
—
10,467
Accretion expense 269
—
—
—
269
351,682
4
—
—
351,686

(LOSS) INCOME FROM OPERATIONS (158,455 )
461

—

—

(157,994 )

OTHER (INCOME) EXPENSE:
Interest expense 12,787
—
—
—
12,787
Interest income (337 ) —
—
—
(337 )
Insurance Proceeds (3,750 ) —
—
—
(3,750 )
(Income) loss from equity method investments and investments in subsidiaries (6,457 ) (99 ) 364
195
(5,997 )
Other income 5
1

6
2,248
(98 ) 364
195
2,709

(LOSS) INCOME BEFORE INCOME TAXES (160,703 )
559

(364 )
(195 )
(160,703 )
INCOME TAX BENEFIT (3,407 ) —
—
—
(3,407 )

NET (LOSS) INCOME $ (157,296 ) $ 559
$ (364 ) $ (195 ) $ (157,296 )

3029

Table of Contents

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

(Amounts in thousands)



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

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

Costs and expenses:
Lease operating expenses	27,149			15,046			—			—			42,195
Production taxes	6,081			9,938			—			—			16,019
Midstream gathering and processing expenses	71,420			70,877			—			—			142,297
Depreciation, depletion, and amortization	198,564			44,765			55			—			243,384
General and administrative expenses	28,977			(4,258		)	104			—			24,823
Accretion expense	1,389			1,037			—			—			2,426
	333,580			137,405			159			—			471,144

INCOME (LOSS) FROM OPERATIONS	132,957			175,630			(159		)	—			308,428

OTHER EXPENSE (INCOME):
Interest expense	70,259			(1,259		)	—			—			69,000
Interest income	(267		)	(44		)	—			—			(311		)
Insurance proceeds	(83		)	—			—			—			(83		)
(Income) loss from equity method investments and investments in subsidiaries	(55,465		)	—			339			176,435			121,309
Other expense	646			—			—			—			646
	15,090			(1,303		)	339			176,435			190,561

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

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

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 )
(Income) loss from equity method investments and investments in subsidiaries (136,969 ) 2,586
869
154,459
20,945
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

3130

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CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

(Amounts in thousands)



	Six months ended June 30, 2018
	Parent			Guarantors			Non-Guarantor			Eliminations			Consolidated

Total revenues	$	360,335		$	217,797		$	—		$	—		$	578,132

Costs and expenses:
Lease operating expenses	30,424			11,394			—			—			41,818
Production taxes	8,804			5,709			—			—			14,513
Midstream gathering and processing expenses	98,208			37,425			—			—			135,633
Depreciation, depletion, and amortization	232,932			1			—			—			232,933
General and administrative expenses	28,786			(1,681		)	2			—			27,107
Accretion expense	1,585			434			—			—			2,019
	400,739			53,282			2			—			454,023

(LOSS) INCOME FROM OPERATIONS	(40,404		)	164,515			(2		)	—			124,109

OTHER (INCOME) EXPENSE:
Interest expense	69,056			(1,387		)	—			—			67,669
Interest income	(58		)	(12		)	—			—			(70		)
Insurance proceeds	(231		)	—			—			—			(231		)
Gain on sale of equity method investments	(25,616		)	(96,419		)	—			—			(122,035		)
(Income) loss from equity method investments and investments in subsidiaries	(283,765		)	(693		)	558			261,476			(22,424		)
Other (income) expense	(1,130		)	(10		)	—			1,000			(140		)
	(241,744		)	(98,521		)	558			262,476			(77,231		)

INCOME (LOSS) BEFORE INCOME TAXES	201,340			263,036			(560		)	(262,476		)	201,340
INCOME TAX BENEFIT	(69		)	—			—			—			(69		)

NET INCOME (LOSS)	$	201,409		$	263,036		$	(560	)	$	(262,476	)	$	201,409

Nine months ended September 30, 2016
Parent Guarantors Non-Guarantor Eliminations Consolidated

Total revenues $ 321,404
$ 1,090
$ —
$ —
$ 322,494

Costs and expenses:
Lease operating expenses 48,246
543
—
—
48,789
Production taxes 9,410
82
—
—
9,492
Midstream gathering and processing 122,250
226
—
—
122,476
Depreciation, depletion, and amortization 183,411
3

183,414
Impairment of oil and natural gas properties 601,806
—
—
—
601,806
General and administrative 33,230
(291 ) 2
—
32,941
Accretion expense 777
—
—
—
777
999,130
563
2
—
999,695

(LOSS) INCOME FROM OPERATIONS (677,726 ) 527
(2 ) —
(677,201 )

OTHER (INCOME) EXPENSE:
Interest expense 44,891
1
—
—
44,892
Interest income (822 ) —
—
—
(822 )
Insurance Proceeds (3,750 ) —
—
—
(3,750 )
Loss (income) from equity method investments and investments in subsidiaries 25,044
(40 ) 24,812
(24,240 ) 25,576
Other income 5
(8 ) —
—
(3 )
65,368
(47 ) 24,812
(24,240 ) 65,893

(LOSS) INCOME BEFORE INCOME TAXES (743,094 ) 574
(24,814 ) 24,240
(743,094 )
INCOME TAX BENEFIT (3,755 ) —
—
—
(3,755 )

NET (LOSS) INCOME $ (739,339 ) $ 574
$ (24,814 ) $ 24,240
$ (739,339 )

3231

Table of Contents

CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Amounts in thousands)



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

Net income (loss)	$	234,956	$	78,291	$	(104	)	$	(78,187	)	$	234,956
Foreign currency translation adjustment	3,610		61		3,549			(3,610		)	3,610
Other comprehensive income (loss)	3,610		61		3,549			(3,610		)	3,610
Comprehensive income (loss)	$	238,566	$	78,352	$	3,445		$	(81,797	)	$	238,566

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



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

Net income (loss)	$	111,319		$	176,350	$	(229	)	$	(176,121	)	$	111,319
Foreign currency translation adjustment	(3,364		)	14		(3,378		)	3,364			(3,364		)
Other comprehensive (loss) income	(3,364		)	14		(3,378		)	3,364			(3,364		)
Comprehensive income (loss)	$	107,955		$	176,364	$	(3,607	)	$	(172,757	)	$	107,955

Three months ended September 30, 2016
Parent Guarantors Non-Guarantor Eliminations Consolidated

Net (loss) income $ (157,296 ) $ 559
$ (364 ) $ (195 ) $ (157,296 )
Foreign currency translation adjustment (4,013 ) —
(1,417 ) 1,417
(4,013 )
Other comprehensive (loss) income (4,013 ) —
(1,417 ) 1,417
(4,013 )
Comprehensive (loss) income $ (161,309 ) $ 559
$ (1,781 ) $ 1,222
$ (161,309 )



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

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

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



	Six months ended June 30, 2018
	Parent			Guarantors			Non-Guarantor			Eliminations			Consolidated

Net income (loss)	$	201,409		$	263,036		$	(560	)	$	(262,476	)	$	201,409
Foreign currency translation adjustment	(8,867		)	(173		)	(8,694		)	8,867			(8,867		)
Other comprehensive (loss) income	(8,867		)	(173		)	(8,694		)	8,867			(8,867		)
Comprehensive income (loss)	$	192,542		$	262,863		$	(9,254	)	$	(253,609	)	$	192,542

Nine months ended September 30, 2016
Parent Guarantors Non-Guarantor Eliminations Consolidated

Net (loss) income $ (739,339 ) $ 574
$ (24,814 ) $ 24,240
$ (739,339 )
Foreign currency translation adjustment 4,361
—
8,252
(8,252 ) 4,361
Other comprehensive income (loss) 4,361
—
8,252
(8,252 ) 4,361
Comprehensive (loss) income $ (734,978 ) $ 574
$ (16,562 ) $ 15,988
$ (734,978 )

3332

Table of Contents

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

(Amounts in thousands)



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

Net cash provided by operating activities	$	230,776		$	74,857		$	3,355		$	1		$	308,989

Net cash (used in) provided by investing activities	(324,357		)	(91,769		)	(3,751		)	432			(419,445		)

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

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

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

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

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 (1,849,554 ) (1,554,063 ) (1,843 ) 1,408,980
(1,996,480 )

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 and cash equivalents (1,184,787 ) 34,182
1
—
(1,150,604 )

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

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



	Six months ended June 30, 2018
	Parent			Guarantors			Non-Guarantor			Eliminations			Consolidated

Net cash provided by operating activities	$	370,965		$	40,078		$	—		$	1		$	411,044

Net cash (used in) provided by investing activities	(327,362		)	(33,103		)	(1,569		)	1,569			(360,465		)

Net cash (used in) provided by financing activities	(30,906		)	—			1,570			(1,570		)	(30,906		)

Net increase in cash, cash equivalents and restricted cash	12,697			6,975			1			—			19,673

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	$	80,605		$	38,624		$	1		$	—		$	119,230

Nine months ended September 30, 2016
Parent Guarantors Non-Guarantor Eliminations Consolidated

Net cash provided by (used in) operating activities $ 244,758
$ 517
$ 3,998
$ (3,998 ) $ 245,275

Net cash (used in) provided by investing activities (420,257 ) (26,500 ) (18,510 ) 45,010
(420,257 )

Net cash provided by (used in) financing activities 426,284
26,500
14,512
(41,012 ) 426,284

Net increase in cash and cash equivalents 250,785
517
—
—
251,302

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

Cash and cash equivalents at end of period $ 363,279
$ 996
$ 1
$ —
$ 364,276

3433

Table of Contents


~~14.~~15.	RECENT ACCOUNTING PRONOUNCEMENTS

In ~~May 2014,~~February 2016, the Financial Accounting Standards Board ~~(“FASB”~~("FASB") issued ~~Accounting Standards Update (“ASU”)~~ASU No. ~~2014-09,~~ ~~Revenue from Contracts with Customers, which~~2016-02, Leases (Topic 842). The standard supersedes the ~~revenue recognition requirements in Topic 605,~~ ~~Revenue Recognition~~,previous lease guidance by requiring lessees to recognize a right-to-use asset and ~~most industry-specific guidance. The core principle~~lease liability on the balance sheet for all leases with lease terms of ~~the new standard is~~greater than one year while maintaining substantially similar classifications for ~~the recognition of revenue~~financing and operating leases. Subsequent to depict the transfer of goods or services to customers in amounts that reflect the payment to which the company expects to be entitled in exchange for those goods or services. The new standard will also result in enhanced revenue disclosures, provide guidance for transactions that were not previously addressed comprehensively and improve guidance for multiple-element arrangements. The ASU is effective for annual periods beginning after December 15, 2016, and interim periods within those years. The new standard permits retrospective application using either of the following methodologies: (i) restatement of each prior reporting period presented (full retrospective method) or (ii) recognition of a cumulative-effect adjustment as of the date of initial application (modified retrospective method). In July 2015,2016-02, the FASB ~~decided~~issued several related ASU’s to defer the effective date by one year (until 2018). The Company is evaluating the impact of this ASU on its consolidated financial statements and working to identify any potential differences that would result from applying the requirements of the ASU to existing contracts and current accounting policies and practices. This evaluation requires, among other things, a review of the contracts it has with customers within each of the revenue streams identified within the Company's business, including natural gas sales, oil and condensate sales and natural gas liquid sales. The Company does not believe further disaggregation of revenue will be required under the new standard. Substantially all of the Company's revenue is earned pursuant to agreements under which they have currently interpreted one performance obligation, which is satisfied at a point-in-time. As part of the evaluation work to-date, the Company has substantially completed its contract reviews and documentation. Due to industry-wide ongoing discussions on certain application issues, the Company cannot reasonably estimate the expected financial statement impact; however, it does not expect the impact ofclarify the application of the new standard to have a material impact on net income or cash flows based on the reviews performed to-date. The Company is currently assessing the requirements for additional disclosures and documentation of new policies, procedures, system, control and data requirements. The Company’s expectation is to adopt the standard on January 1, 2018, using the modified retrospective method. Based on the analysis to-date, the Company has not identified any material impact on their consolidated financial statements other than additional disclosures requirements.

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

~~In March 2016, the FASB issued ASU No. 2016-05,~~ ~~Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships.~~ The guidance was issued to clarify that change in the counterparty to a derivative instrument that had been designated as the hedging instrument under Topic 815, does not require designation of that hedging relationship provided that all other hedge accounting criteria continue to be met.standard. The Company adopted the new standard as of January 1, ~~2017. There was no impact~~2019 on a prospective basis using the ~~Company’s consolidated financial statements because all current derivative instruments are~~simplified transition method permitted by ASU 2018-11, Leases (Topic 842): Targeted Improvements. The comparative information has not ~~designated~~been restated and continues to be reported under the historic accounting standards in effect for ~~hedge accounting.~~those periods. See Note 12 for further discussion of the lease standard.

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

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

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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. Additionally, in May 2019, the FASB issued ASU No. 2019-05, Financial Instruments—Credit Losses (Topic 326): Targeted Transition Relief. The amendments in this update allow preparers to irrevocably elect the fair value option, on an instrument-by-instrument basis, for eligible financial assets measured at amortized cost basis upon adoption of 2016-13. 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 ~~affect.~~effect.

In ~~August 2016,~~February 2018, the FASB issued ASU No. ~~2016-15,~~ ~~Statement of Cash Flows: Classification~~2018-02, Income statement - Reporting Comprehensive Income (Topic 220) - Reclassification of Certain ~~Cash Receipts~~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 ~~Cash Payments.~~ ~~This ASU provides guidance~~Jobs Act of ~~eight specific cash flow issues. This ASU is~~2017. The amendment will be effective for reporting periods beginning after December 15, ~~2017, with~~2018, and early adoption is permitted. The Company ~~is in the process of evaluating~~assessed the impact of ~~this guidance~~the ASU on its consolidated financial ~~statements.~~statements and related disclosures, and determined there was no material impact.

In ~~December 2016,~~August 2018, the FASB issued ASU No. ~~2016-20,~~ ~~Technical Corrections~~2018-13, Fair Value Measurement (Topic 820): Disclosure Framework—Changes to the Disclosure Requirements for Fair Value Measurement which removes, modifies, and ~~Improvements to Topic 606, Revenue from Contracts with Customers. This guidance updates narrow aspects of the guidance issued in Update 2014-09. This~~adds certain disclosure requirements on fair value measurements. The amendment iswill be effective for reporting periods beginning after December 15, ~~2017, with~~2019, and early adoption is permitted. The Company is ~~in the process of evaluating~~currently assessing the impact of ~~this~~the ASU on its consolidated financial ~~statements.~~statements and related disclosures.

In ~~January 2017,~~August 2018, the FASB also 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~~2018-15 , Intangibles—Goodwill 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~~Other—Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a ~~single asset~~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 ~~group of similar assets. If that screen is met, the set of assets is not a business.~~obtain internal-use software. The ~~new framework also specifies the minimum required inputs and processes necessary to~~amendment will be ~~a business. This amendment is~~ effective for reporting periods beginning after December 15, ~~2017, with~~2019, and early adoption is permitted. The Company is ~~in the process of evaluating~~currently assessing the impact of ~~this~~the ASU on its consolidated financial ~~statements.~~statements and related disclosures.

In November 2018, the FASB also issued ASU No. 2018-18, Collaborative Arrangements (Topic 808): Clarifying the Interaction Between Topic 808 and Topic 606, which provides guidance on how to assess whether certain transactions between participants in a collaborative arrangement should be accounted for within the ASU No. 2014-09 revenue recognition standard discussed above. 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.


~~15.~~16.	SUBSEQUENT EVENTS

~~Derivatives~~Sale of Southern Louisiana Assets

In ~~October~~December of ~~2017,~~2018, the Company entered into ~~fixed price swaps~~an agreement to sell its non-core assets located in the WCBB and Hackberry fields of Louisiana to an undisclosed third party for ~~2018 for approximately 1,500 Bbls of oil per day at~~ a ~~weighted average~~purchase price of ~~$52.05 per Bbl.~~approximately $19.7 million. The ~~Company’s fixed price swap contracts are tied to~~Company

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received approximately $9.2 million in cash and retained contingent overriding royalty interests. In addition, the Company could also receive contingent payments based on commodity prices exceeding certain thresholds over the next two years. The buyer has agreed to assume all plugging and abandonment liabilities associated with these assets. The effective date of the transaction is August 15, 2018. The sale closed on ~~NYMEX WTI. The~~July 3, 2019, subject to customary post-closing terms and conditions.

Debt Repurchases

In July 2019, the Company ~~will receive the fixed price amount stated~~used borrowings under its revolving credit facility to repurchase in the ~~contract and pay to its counterparty the current~~open market ~~price as listed on NYMEX for oil.~~

~~Senior Notes Offering~~

~~On October 11, 2017, the Company issued $450.0~~approximately $104.4 million in aggregate principal amount of its ~~6.375% Senior~~outstanding 2023 Notes, ~~due 2026 (the “2026 Notes”) to qualified institutional buyers pursuant to Rule 144A under the Securities Act~~2024 Notes, 2025 Notes 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. 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 will be used to fund the remaining anticipated outspend related to the Company's 2017 capital development plans.for $80.3 million.

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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~~Cautionary Note 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,~~Act"), and Section 21E of the Securities Exchange Act of 1934, as amended or ("the Exchange ~~Act.~~ Act"). When used in this Quarterly Report, the words "could", "believe", "anticipate", "intend", "estimate", "expect", "project" and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.

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,~~strengths, goals, expansion and growth of our business and operations, plans, references to future success, ~~reference~~references 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, including, general economic, market or business conditions; commodity prices; the opportunities (or lack thereof) that may be presented to and pursued by us; competitive actions by other oil and natural gas companies; adverse developments or losses from pending or future litigation and regulatory proceedings; our ability to identify, complete and integrate acquisitions of properties ~~(including those recently acquired from Vitruvian II Woodford, LLC)~~ and businesses; changes in laws or regulations; adverse weather conditions and natural disasters such as hurricanes and other factors, including those listed ~~in the~~under Item 1A, “Risk Factors” ~~section of~~in our ~~most recent~~ Annual Report on Form 10-K for the year ended December 31, 2018, this Quarterly ~~Reports~~Report on Form 10-Q ~~or any~~and in our other filings ~~we make~~ with the SEC, many of which are beyond our ~~control. Consequently,~~control and may cause our actual results, performance or achievements to differ materially from anticipated future results, performance or achievements expressed or implied by such forward-looking statements. Should one or more of the risks or uncertainties described in this Quarterly Report occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.

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

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

Investors should note that Gulfport announces financial information in SEC filings, press releases and ~~we cannot assure you~~public conference calls. Gulfport may use the Investors section of its website (www.gulfportenergy.com) to communicate with investors. It is possible that the ~~actual results or developments anticipated by us will~~financial and other information posted there could be ~~realized or, even if realized, that they will have the expected consequences~~deemed to ~~or effects~~be material information. The information 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~~Gulfport’s website is not part of ~~new information, future results or otherwise.~~this Quarterly Report on Form 10-Q.

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, or NGLs, 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~~

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position in the Alberta oil sands in Canada through our interest in Grizzly Oil Sands ULC ~~or Grizzly,~~("Grizzly"), and an approximate ~~25.1%~~21.8% equity interest in Mammoth Energy Services, Inc. ("Mammoth Energy"), ~~or Mammoth Energy,~~ an ~~oil field~~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.

~~2017~~2019 Operational and Other Highlights

~~Production increased 63% to 110,367 net million cubic feet of natural gas equivalent, or MMcfe, for~~During the ~~three~~six months ended ~~September~~June 30, 2017 from 67,541 MMcfe for the three months ended September 30, 2016. Our net daily production mix for the third quarter of 2017 averaged 1,199.6 MMcfe per day and was comprised of approximately 88% natural gas, 8% natural gas liquids, or NGLs, and 4% oil.

On February 17, 2017, we, through our wholly-owned subsidiary Gulfport MidCon LLC, or Gulfport MidCon (formerly known as SCOOP Acquisition Company, LLC), completed our acquisition, which we refer to as the Acquisition, of certain assets from Vitruvian II Woodford, LLC, an unrelated third-party seller, for a total purchase price of approximately $1.85 billion, consisting of $1.35 billion in cash, subject to certain adjustments, and approximately 23.9 million shares of the Company’s common stock (of which approximately 5.2 million shares were

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

On June 5, 2017, we acquired approximately 2.0 million shares of Mammoth Energy common stock in connection with our contribution of all of our membership interests in Sturgeon Acquisitions LLC, Stingray Energy Services LLC and Stingray Cementing LLC, which we refer to as Sturgeon, Stingray Energy and Stingray Cementing, respectively, bringing our equity interest in Mammoth Energy to approximately 25.1%.

~~During the three months ended September 30, 2017,~~2019, we spud 2311 gross ~~(23.0~~(9.4 net) wells in the Utica Shale and participated in anthree additional ~~four~~ gross ~~(1.3~~(0.8 net) wells that were drilled by other operators on our Utica Shale ~~acreage and spud six gross and net wells and recompleted nine gross and net wells on our Louisiana~~ acreage. In addition, during the ~~three~~six months ended ~~September~~June 30, ~~2017,~~2019, we spud seven gross ~~(6.1~~(5.7 net) wells ~~were spud~~ in the ~~SCOOP. We also~~SCOOP and participated in an additional ~~three~~28 gross ~~(0.03~~(0.6 net) wells that were drilled by other operators on our SCOOP acreage. Of the 3618 new wells we spud, at ~~September~~June 30, ~~2017, 28~~2019, 16 were in various stages of completion and ~~eight~~two were being drilled. In addition, 1931 gross ~~(17.9 net)~~and net operated ~~wells and nine gross (2.1 net) non-operated~~ wells were turned-to-sales in our Utica Shale operating area and ~~six~~nine gross ~~(5.6~~(8.7 net) operated ~~wells and 12 gross (0.43 net) non-operated~~ wells were turned-to-sales in our SCOOP operating area during the ~~three~~six months ended ~~September~~June 30, ~~2017.~~2019.

~~During~~For the ~~nine~~six months ended ~~September~~June 30, ~~2017, we reduced our unit lease operating expense by 16% to $0.21 per Mcfe from $0.26 per Mcfe during the nine months ended September 30, 2016.~~

~~During the nine months ended September 30, 2017,~~2019, we decreased our unit general and administrative expense by ~~22%~~9% to ~~$0.13~~$0.10 per Mcfe from ~~$0.17~~$0.11 per Mcfe ~~during~~for the ~~nine~~six months ended ~~September~~June 30, ~~2016.~~2018.

~~On October 11, 2017,~~

In January 2019, our board of directors approved a new stock repurchase program to acquire up to $400 million of our outstanding common stock within a 24 month period, which we ~~issued $450.0~~believe underscores the confidence we have in our business model, financial performance and asset base. As of July 26, 2019, we have repurchased approximately 3.8 million shares of our outstanding common stock pursuant to the plan for total consideration of approximately $30.0 million.

In December of 2018, we entered into an agreement to sell our non-core assets located in the WCBB and Hackberry fields of Louisiana to an undisclosed third party for a purchase price of approximately $19.7 million. We received approximately $9.2 million in cash and retained contingent overriding royalty interests. In addition, we could also receive contingent payments based on commodity prices exceeding certain thresholds over the next two years. The buyer has agreed to assume all plugging and abandonment liabilities associated with these assets. The effective date of the transaction is August 15, 2018. The sale closed on July 3, 2019, subject to customary post-closing terms and conditions.

In July 2019, we used borrowings under our revolving credit facility to repurchase in the open market approximately $104.4 million aggregate principal amount of our ~~6.375% Senior~~outstanding 2023 Notes, ~~due 2026, or the~~2024 Notes, 2025 Notes and 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. A portion of the net proceeds from the issuance of the 2026 Notes was used to repay all of our outstanding borrowings under our secured revolving credit facility on October 11, 2017 and the balance will be used to fund the remaining anticipated outspend related to our 2017 capital development plans.for $80.3 million.

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~~2017~~2019 Production and Drilling Activity

During the three months ended ~~September~~June 30, ~~2017,~~2019, our total net ~~production~~production was ~~97,824,927~~111,602,875 thousand cubic feet, or Mcf, of natural gas, ~~685,316~~649,216 barrels of oil and ~~59,007,909~~57,188,687 gallons of ~~NGLs~~NGLs for a total of ~~110,367 MMcfe,~~123,668 million cubic feet of natural gas equivalent, or MMcfe, as compared to ~~58,150,669~~108,236,412 Mcf of natural gas, ~~521,356~~744,311 barrels of oil and ~~43,837,087~~58,511,924 gallons of NGLs, or ~~67,541~~121,061 MMcfe, for the three months ended ~~September~~June 30, ~~2016.~~2018. Our total net production averaged ~~approximately 1,199.6~~approximately 1,359.0 MMcfe per day during the three months ended ~~September~~June 30, ~~2017~~2019, as compared to ~~734.1~~1,330.3 MMcfe per day during the same period in ~~2016.~~2018. The ~~63%~~2% increase in production is largely the result of the continuing development of our Utica Shale ~~acreage~~ and ~~production attributable to the Acquisition.~~SCOOP acreage.

Utica Shale. ~~As of November~~From January 1, ~~2017,~~2019 through June 30, 2019, we ~~held leasehold interests in approximately 235,000~~spud 11 gross ~~(213,000~~(9.4 net) ~~acres~~wells in the Utica ~~Shale. From January 1, 2017 through November 1, 2017, we spud 89 gross (84.1 net) wells,~~Shale, of which ~~16 were producing, 69~~one was being drilled and ten were in various stages of completion ~~and four were being drilled~~ at ~~November 1, 2017. In addition, 16~~June 30, 2019. We also participated in three additional gross ~~(5.5~~(0.8 net) wells that were drilled by other operators on our Utica Shale ~~acreage during~~acreage. From July 1, 2019 through July 26, 2019, we spud two gross (2.0 net) well in the ~~nine months ended September 30, 2017.~~Utica Shale.

As of ~~November 1, 2017,~~July 26, 2019, we had ~~four~~one operated horizontal ~~rigs under contract on our~~rig running in the Utica ~~Shale acreage.~~Shale. We currently intend to spud 9613 to 15 gross ~~(91~~(10 to 11 net) horizontal wells, and commence sales from 6847 to 51 gross ~~(61~~(40 to 45 net) horizontal wells, on our Utica Shale acreage in ~~2017.~~2019. We also anticipate an additional two to three net horizontal wells will be drilled, and sales commenced from two to three net horizontal wells, on our Utica Shale acreage by other operators during 2019.

Aggregate net production from our Utica Shale acreage during the three months ended ~~September~~June 30, ~~2017~~2019 was approximately ~~90,822~~95,616 MMcfe, or an average of ~~987.2~~1,050.7 MMcfe per day, of which ~~94%~~97% was ~~from~~ natural gas and 6%3% was ~~from~~ oil and NGLs.

SCOOP. ~~As of November 1, 2017, we held leasehold interests in approximately 50,400 net acres in the SCOOP.~~ From January 1, ~~2017~~2019 through ~~November 1, 2017, 16~~June 30, 2019, we spud seven gross ~~(13.6~~(5.7 net) wells ~~were spud,~~in the SCOOP, of which ~~four were~~one was being drilled and 12six were ~~waiting on~~in various stages of completion at ~~November 1, 2017. In addition, 25~~June 30, 2019. We also participated in an additional 28 gross ~~(0.8~~(0.6 net) wells that were drilled by other operators on our SCOOP ~~acreage during the period from February 17, 2017 to September 30, 2017.~~acreage. From July 1, 2019 through July 26, 2019, we did not spud any wells on our SCOOP acreage.

As of ~~November 1, 2017,~~July 26, 2019, we had ~~four~~one operated horizontal ~~rigs under contract~~rig running on our SCOOP acreage. We currently intend to spud 22nine to ten gross ~~(18~~(seven to eight net) horizontal wells, and commence sales from 1815 to 17 gross ~~(16~~(14 to 15 net) horizontal wells, on our SCOOP acreage in ~~2017.~~2019. We also anticipate one to two net wells will be drilled, and sales commenced from one to two net wells on our SCOOP acreage by other operators during 2019.

Aggregate net production from our SCOOP acreage during the three months ended ~~September~~June 30, ~~2017~~2019 was approximately ~~17,888~~27,149 MMcfe, or an average of ~~194.4~~298.3 MMcfe per day, of which ~~70%~~71% was from natural gas and ~~30%~~29% was from oil and NGLs.

WCBB. From January 1, ~~2017~~2019 through ~~November 1, 2017,~~July 3, 2019, we did not spud ~~ten~~any new wells ~~and recompleted 59 wells. Aggregate~~or recomplete any wells in the WCBB field. Our aggregate net production from the WCBB field during the three months ended ~~September~~June 30, ~~2017~~2019 was approximately ~~1,255~~685 MMcfe, or an average of ~~13.6~~7.5 MMcfe per day, ~~98%~~all of which was from oil. On July 3, 2019, we closed on the sale of all of our WCBB assets.

East Hackberry Field. From January 1, ~~2017~~2019 through ~~November 1, 2017,~~July 3, 2019, we did not spud ~~five~~any new wells ~~and recompleted 20~~or recomplete any wells. ~~Aggregate~~Our aggregate net production from the East Hackberry field during the three months ended ~~September~~June 30, ~~2017~~2019 was approximately ~~296~~91.3 MMcfe, or an average of ~~3.2~~1.0 MMcfe per day, all of which ~~98%~~ was from ~~oil and 2% was from natural gas.~~oil. On July 3, 2019, we closed on the sale of our East Hackberry assets.

West Hackberry Field. From January 1, ~~2017~~2019 through ~~November 1, 2017,~~July 3, 2019, we did not spud any new wells in our West Hackberry field. ~~Aggregate~~Our aggregate net production from the West Hackberry field during the three months ended ~~September~~June 30, ~~2017~~2019 was approximately ~~19.7~~17.0 MMcfe, or an average of ~~214.5~~186.5 Mcfe per day, all of which was from oil. On July 3, 2019, we closed on the sale of our West Hackberry assets.

We ~~currently intend~~have no further capital obligations related to ~~drill 15 gross and net wells and perform recompletion activities on our acreage in Southern Louisiana.~~the Louisiana fields after July 3, 2019.

Niobrara Formation. ~~As of September 30, 2017, we held leases for approximately 4,000 net acres in the Niobrara Formation in Northwestern Colorado.~~ From January 1, ~~2017~~2019 through ~~November 1, 2017,~~July 26, 2019, there were no wells spud on our Niobrara Formation acreage. Aggregate net production was approximately ~~19.9~~17.0 MMcfe, or an average of ~~216.5~~187.0 Mcfe per day during the three months ended ~~September~~June 30, ~~2017,~~2019, all of which was from oil.

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Bakken. As of ~~September~~June 30, ~~2017,~~2019, we ~~held approximately 778 net acres in the Bakken Formation of Western North Dakota and Eastern Montana with interests~~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~~June 30, ~~2017~~2019 was approximately ~~64.5~~92.5 MMcfe, or an average of ~~701.4 Mcfe~~1.0 MMcfe per day, of which ~~78%~~77% was from oil ~~15%~~and 23% was from natural gas and ~~7% was from NGLs.~~natural gas liquids.

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~~Critical Accounting Policies~~RESULTS OF OPERATIONS

Comparison of the Three Month Periods Ended June 30, 2019 and ~~Estimates~~2018

~~Our discussion~~We reported net income of $235.0 million for the three months ended June 30, 2019 as compared to net income of $111.3 million for the three months ended June 30, 2018. This $123.7 million period-to-period increase was due primarily to a $206.3 million increase in oil and ~~analysis~~natural gas revenues and a $179.3 million increase in income tax benefit, partially offset by a $134.5 million increase in loss from equity method investments, including a $125.4 million impairment related to our investment in Mammoth Energy and a $122.0 million decrease in gain on sale of equity method investments for the three months ended June 30, 2019 as compared to the three months ended June 30, 2018. If Mammoth Energy's common stock continues to trade below our carrying value for a prolonged period of time, further impairment of our ~~financial condition and results~~investment in Mammoth Energy may be necessary. The gain on sale of ~~operations are based upon consolidated financial statements, which have been prepared~~equity investments in ~~accordance with accounting principles generally accepted in~~2018 was the ~~United States~~result 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~~sale of our ~~financial position~~interest in Strike Force and ~~results~~the sale of ~~operations~~Mammoth Energy common stock during 2018.

Natural Gas, Oil and ~~which require~~NGL Revenues. For the ~~application~~three months ended June 30, 2019, we reported oil and natural gas revenues of ~~significant judgment by our management. We analyze our estimates including those related~~$459.0 million as compared to oil and natural gas ~~properties, revenue recognition, income taxes~~revenues of $252.7 million during the same period in 2018. This $206.3 million, or 82%, increase in revenues was primarily attributable to the following:

A $241.7 million increase in natural gas, oil and ~~commitments~~condensate and ~~contingencies,~~NGLs sales due to a favorable change in gains and ~~base our estimates on historical experience and various other assumptions that we believe~~losses from derivative instruments. Of the total change, $224.6 million was due 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 useda favorable change in the ~~preparation~~fair value of our ~~consolidated financial statements:~~open derivative positions in each period and $17.1 million was due to favorable changes in settlements related to our 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.

~~Oil and Natural Gas Properties. We use the full cost method of accounting for~~Such increases were partially offset by:

A $12.4 million decrease in oil and condensate sales without the impact of derivatives due to a 14% decrease in oil and condensate market prices and a 13% decrease in oil and condensate sales volumes.

A $15.6 million decrease in NGLs sales without the impact of derivatives due to a 36% decrease in NGLs market prices and a 2% decrease in NGLs sales volumes.

A $7.4 million decrease in natural gas ~~operations. Accordingly, all~~sales without the impact of derivatives due to a 6% decrease in natural gas market prices, partially offset by a 3% increase in natural gas sales volumes.

The following table summarizes our oil and condensate, natural gas and NGLs production and related pricing for the three months ended June 30, 2019, as compared to such data for the three months ended June 30, 2018:



	Three months ended June 30,
	2019		2018
	($ In thousands)
Natural gas sales
Natural gas production volumes (MMcf)	111,603		108,236

Total natural gas sales	$	225,257	$	232,695

Natural gas sales without the impact of derivatives ($/Mcf)	$	2.02	$	2.15
Impact from settled derivatives ($/Mcf)	$	0.18	$	0.17
Average natural gas sales price, including settled derivatives ($/Mcf)	$	2.20	$	2.32

Oil and condensate sales
Oil and condensate production volumes (MBbls)	649		744

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Total oil and condensate sales	$	36,910	$	49,319

Oil and condensate sales without the impact of derivatives ($/Bbl)	$	56.85	$	66.26
Impact from settled derivatives ($/Bbl)	$	0.57	$	(10.97	)
Average oil and condensate sales price, including settled derivatives ($/Bbl)	$	57.42	$	55.29

NGLs sales
NGLs production volumes (MGal)	57,189		58,512

Total NGLs	$	25,687	$	41,271

NGLs sales without the impact of derivatives ($/Gal)	$	0.45	$	0.71
Impact from settled derivatives ($/Gal)	$	0.06	$	(0.07	)
Average NGLs sales price, including settled derivatives ($/Gal)	$	0.51	$	0.64

Natural gas, oil and condensate and NGLs sales
Natural gas equivalents (MMcfe)	123,668		121,061

Total natural gas, oil and condensate and NGLs sales	$	287,854	$	323,285

Natural gas, oil and condensate and NGLs sales without the impact of derivatives ($/Mcfe)	$	2.33	$	2.67
Impact from settled derivatives ($/Mcfe)	$	0.19	$	0.05
Average natural gas, oil and condensate and NGLs sales price, including settled derivatives ($/Mcfe)	$	2.52	$	2.72

Production Costs:
Average production costs ($/Mcfe)	$	0.18	$	0.19
Average production taxes ($/Mcfe)	$	0.07	$	0.06
Average midstream gathering and processing ($/Mcfe)	$	0.58	$	0.59
Total production costs, midstream costs and production taxes ($/Mcfe)	$	0.83	$	0.84

Lease Operating Expenses. Lease operating expenses ("LOE") not including production taxes decreased to $22.4 million for the three months ended June 30, 2019 from $22.9 million for the three months ended June 30, 2018. This $0.5 million, or 2%, decrease was primarily the result of a decrease in wireline services, production chemicals, contract labor and facility maintenance expense, partially offset by an increase in disposal costs, ~~including non-productive costs~~location repairs and ~~certain general~~ad valorem taxes. In addition, due to increased efficiencies and ~~administrative costs directly~~a 2% increase in our production volumes for the three months ended June 30, 2019 as compared to the three months ended June 30, 2018, our per unit LOE decreased by 5% from $0.19 per Mcfe to $0.18 per Mcfe.

Production Taxes. Production taxes increased $0.4 million, or 5%, to $8.1 million for the three months ended June 30, 2019 from $7.7 million for the three months ended June 30, 2018. This increase was primarily due to an increase in production volumes and an increase in the production tax rate associated with ~~acquisition, exploration~~our SCOOP production.

Midstream Gathering and ~~development~~Processing Expenses. Midstream gathering and processing expenses increased to $72.0 million for the three months ended June 30, 2019 from $71.4 million for the same period in 2018. This $0.6 million, or 1%, increase was primarily attributable to midstream expenses related to our increased production volumes in the Utica Shale and SCOOP resulting from our 2018 and 2019 drilling activities.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization ("DD&A") expense increased to $125.0 million for the three months ended June 30, 2019, and consisted of $122.5 million in depletion of oil and natural gas

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properties ~~are capitalized. Companies that use~~and $2.5 million in depreciation of other property and equipment, as compared to total DD&A expense of $121.9 million for the three months ended June 30, 2018. This $3.1 million, or 3%, increase was primarily due to an increase in our depletion rate as a result of a decrease in our full cost ~~method~~pool and a decrease in our total proved reserves volumes used to calculate our total DD&A expense, as well as an increase in our production.

General and Administrative Expenses. Net general and administrative expenses decreased to $13.3 million for the three months ended June 30, 2019 from $14.0 million for the three months ended June 30, 2018. This $0.7 million, or 5%, decrease was primarily due to decreases in consulting fees and travel expense, partially offset by increases in computer support and tax services. In addition, for the three months ended June 30, 2019, we decreased our unit general and administrative expense by 8% to $0.11 per Mcfe from $0.12 per Mcfe for the three months ended June 30, 2018.

Interest Expense. Interest expense increased to $34.9 million for the three months ended June 30, 2019 as compared to $33.7 million for the three months ended June 30, 2018 due primarily to increased borrowings on our revolving credit facility as compared to the same period in 2018. In addition, total weighted average debt outstanding under our revolving credit facility was $168.8 million for the three months ended June 30, 2019 as compared to $112.9 million debt outstanding under such facility. As of ~~accounting for~~June 30, 2019, amounts borrowed under our revolving credit facility bore interest at a weighted average rate of 3.93%. In addition, we capitalized approximately $1.0 million and $1.5 million in interest expense to undeveloped oil and natural gas properties ~~are required~~during the three months ended June 30, 2019 and 2018, respectively. This $0.5 million decrease in capitalized interest in the 2019 period was primarily the result of changes 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 priceour development plan 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~~properties.

Income Taxes. As of ~~properties not being amortized, if any, and (c) the lower~~June 30, 2019, we had a federal net operating loss carryforward of ~~cost or market value of unproved properties included~~approximately $920.4 million from prior years, in ~~the cost being amortized, including related deferred taxes for~~addition to numerous temporary differences, between the book and tax basis of the oil and natural gas properties. If the net book value, including related deferred taxes, exceeds the ceiling, an impairment or noncash writedown is required. Such capitalized costs, including the estimated future development costs and site remediation costs of proved undeveloped properties are depleted by an equivalent units-of-production method, converting gas to barrels at the ratio of six Mcf of gas to one barrel of oil. No gain or loss is recognized upon the disposal of oil and natural gas properties, unless such dispositions significantly alter the relationship between capitalized costs and proven oil and natural gas reserves. Oil and natural gas properties not subject to amortization consist of the cost of undeveloped leaseholds and totaled approximately $3.0 billion at September 30, 2017 and $1.6 billion at December 31, 2016. These costs are reviewed quarterly by management for impairment, with the impairment provision included in the cost of oil and natural gas properties subject to amortization. Factors considered by management in its impairment assessment include our drilling results and those of other operators, the terms of oil and natural gas leases not held by production and available funds for exploration and development.

~~Ceiling Test~~. Companies that use the full cost method of accounting for oil and gas properties are required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the oil and gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes or the cost center ceiling (as defined in the preceding paragraph). If the net book value, including related deferred taxes, exceeds the ceiling, an impairment or noncash writedown is required. Ceiling test impairment can give us a significant loss for a particular period; however, future depletion expense would be reduced. A decline in oil and gas prices may result in an impairment of oil and gas properties. For instance, as a result of the decline in commodity prices in 2015 and 2016 and subsequent reduction in our proved reserves, we recognized a ceiling test impairment of $715.5 million for the year ended December 31, 2016. At September 30, 2017, the calculated ceiling was greater than the net book value of our oil and natural gas properties, thus no ceiling test impairment was required for the nine months ended September 30, 2017. If prices of oil, natural gas and natural gas liquids decline in the future, we may be required to further write down the value of our oil and natural gas properties, which ~~could negatively affect our results of operations.~~

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

We account for abandonment and restoration liabilities under FASB ASC 410 which requires us to record a liability equal to the fair value of the estimated cost to retire an asset. The asset retirement liability is recorded in the period in which the obligation meets the definition of a liability, which is generally when the asset is placed into service. When the liability is initially recorded, we increase the carrying amount of the related long-lived asset by an amount equal to the original liability. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related

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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. andgave rise to a ~~lesser extent our personnel have prepared reserve reports of our reserve estimates at December 31, 2016 on a well-by-well basis for our properties.~~

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

~~the quality and quantity of available data;~~

~~the interpretation of that data;~~

~~the accuracy of various mandated economic assumptions; and~~

~~the judgments of the individuals preparing the estimates.~~

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

~~Income Taxes. We use the asset and liability method of accounting for income taxes, under which~~ deferred tax assets and liabilities are recognized for the future tax consequences of (1) temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities and (2) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income during the period the rate change is enacted. Deferred tax assets are recognized in the year in which realization becomes determinable. Periodically,asset. Quarterly, management performs a forecast of ~~its~~our taxable income and analyzes other relevant factors to determine whether it is more likely than not that a valuation allowance is needed, looking at both positive and negative factors. A valuation allowance for our deferred tax assets is established if, in management’s opinion, it is more likely than not that some portion will not be realized. ~~At September~~During the three months ending June 30, ~~2017,~~2019, management determined there was sufficient positive evidence that it was more likely than not that the federal and some state net operating loss carryforwards should be realized and recorded a discrete tax benefit of $179.3 million. We will recognize through the annual effective tax rate a projected release of valuation allowance of an additional $27.7 million with respect to current year earnings. We will maintain a valuation allowance of ~~$548.4~~$4.8 million ~~had been provided~~ against the net deferred tax asset ~~with the exception of~~for certain ~~state net operating losses, or NOL, and alternative minimum~~ tax ~~or AMT, credits that we expect to be able to utilize with NOL carrybacks and tax planning in the amount of $4.7 million.~~

~~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 receivedattributes 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.~~

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

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

~~Commitments and Contingencies. Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when~~determined 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 abilitymore likely than not those attribute carryforwards will expire prior to ~~reasonably estimate a loss amount, if any, may result in the recognition and subsequent payment of legal liabilities.~~

~~Derivative Instruments and Hedging Activities~~. We seek to reduce our exposure to unfavorable changes in oil, natural gas and natural gas liquids prices, which are subject to significant and often volatile fluctuation, by entering into over-the-counter fixed price swaps, basis swaps and various types of option contracts. We follow the provisions of FASB ASC 815, “~~Derivatives and Hedging~~,” as amended. It requires that all derivative instruments be recognized as assets or liabilities in the balance sheet, measured at fair value. We estimate the fair value of all derivative instruments using industry-standard models that considered various assumptions including current market and contractual prices for the underlying instruments, implied volatility, time value and nonperformance risk, as well as other relevant economic measures.

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

~~See Item 3. “Quantitative and Qualitative Disclosures About Market Risk” for a summary of our derivative instruments in place as of September 30, 2017.~~utilization.

~~RESULTS OF OPERATIONS~~

Comparison of the ~~Three Months~~Six Month Periods Ended ~~September~~June 30, ~~2017~~2019 and ~~2016~~2018

We reported net income of ~~$18.2~~$297.2 million for the ~~three~~six months ended ~~September~~June 30, ~~2017~~2019 as compared to a net ~~loss~~income of ~~$157.3~~$201.4 million for the ~~three~~six months ended ~~September~~June 30, ~~2016.~~2018. This ~~$175.5~~$95.8 million period-to-period increase was due primarily to a ~~$71.8~~$201.4 million increase in natural gas, oil and NGL revenues and ~~no impairment charge for the three months ended September 30, 2017 as compared to~~ a ~~$212.2~~$179.3 million ~~impairment of oil and natural gas properties for the three months ended September 30, 2016,~~increase in income tax benefit, partially offset by a ~~$23.9~~$143.7 million increase in loss from equity method investments, including a $125.4 million impairment related to our investment in Mammoth Energy, a $122.0 million decrease in gain on sale of equity method investments, a $10.5 million increase in DD&A and a $6.7 million increase in midstream gathering and processing expenses ~~an $8.7 million increase in loss from equity method investments, net, a $14.3 million increase in interest expense and a $2.5 million increase in lease operating expenses~~ for the ~~three~~six months ended ~~September~~June 30, ~~2017~~2019 as compared to the ~~three~~six months ended ~~September~~June 30, ~~2016.~~2018. If Mammoth Energy's common stock continues to trade below our carrying value for a prolonged period of time, further impairment of our investment in Mammoth Energy may be necessary. The gain on sale of equity investments in 2018 was a result of the sale of our interest in Strike Force and the sale of Mammoth Energy common stock during 2018.

Oil and Gas Revenues. For the ~~three~~six months ended ~~September~~June 30, ~~2017,~~2019, we reported oil and natural gas ~~oil and NGL~~ revenues of ~~$265.5~~$779.6 million as compared to oil and natural gas revenues of ~~$193.7~~$578.1 million during the same period in ~~2016.~~2018. This ~~$71.8~~$201.4 million, or ~~37%~~35%, increase in revenues was primarily attributable to the following:

A ~~$58.1~~$238.1 million ~~decrease~~increase in in natural gas, oil and ~~NGL~~condensate and NGLs sales due to ~~an unfavorable~~a favorable change in gains and losses from derivative instruments. Of the total change, ~~$59.3~~$254.8 million was due to ~~unfavorable~~favorable changes in the fair value of our open derivative positions in each period, partially offset by a ~~$1.2~~$16.7 million ~~favorable~~unfavorable change in settlements related to our 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 ~~$101.3~~$19.2 million increase in natural gas sales without the impact of derivatives due to ~~an 8%~~a 2% increase in natural gas sales volumes and a 2% increase in natural gas market ~~prices and a 68% increase in natural gas sales volumes.~~prices.

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Such increases were partially offset by:

A ~~$9.6~~$25.6 million ~~increase~~decrease in oil and condensate sales without the impact of derivatives due to a ~~9% increase~~16% decrease in oil and condensate sales volumes and a 13% decrease in oil and condensate market ~~prices and a 31% increase in oil and condensate sales volumes.~~prices.

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A ~~$19.0~~$30.3 million ~~increase~~decrease in ~~natural gas liquids~~NGLs sales without the impact of derivatives due to a ~~73% increase~~28% decrease in ~~natural gas liquids~~NGLs market prices and a ~~35% increase~~9% decrease in ~~natural gas liquids~~NGLs sales volumes.

The following table summarizes our oil and condensate, natural gas and NGLs production and related pricing for the ~~three~~six months ended ~~September~~June 30, ~~2017,~~2019, as compared to such data for the ~~three~~six months ended ~~September~~June 30, ~~2016:~~2018:

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	Three months ended September 30,					Six months ended June 30,
	2017			2016		2019			2018
	($ In thousands)					($ In thousands)
Natural gas sales
Natural gas production volumes (MMcf)	97,825			58,151		213,682			210,278

Total natural gas sales	$	223,340		$	122,018	$	501,273		$	482,094

Natural gas sales without the impact of derivatives ($/Mcf)	$	2.28		$	2.10	$	2.35		$	2.29
Impact from settled derivatives ($/Mcf)	$	0.13		$	0.21	$	(0.03	)	$	0.17
Average natural gas sales price, including settled derivatives ($/Mcf)	$	2.41		$	2.31	$	2.32		$	2.46

Oil and condensate sales
Oil and condensate production volumes (MBbls)	685			521		1,261			1,501

Total oil and condensate sales	$	31,459		$	21,799	$	69,392		$	95,005

Oil and condensate sales without the impact of derivatives ($/Bbl)	$	45.90		$	41.81	$	55.03		$	63.29
Impact from settled derivatives ($/Bbl)	$	4.36		$	1.62	$	0.31		$	(8.29	)
Average oil and condensate sales price, including settled derivatives ($/Bbl)	$	50.26		$	43.43	$	55.34		$	55.00

Natural gas liquids sales
Natural gas liquids production volumes (MGal)	59,008			43,837
NGLs sales
NGLs production volumes (MGal)						113,019			124,268

Total natural gas liquids sales	$	33,559		$	14,594
Total NGLs sales						$	57,812		$	88,107

Natural gas liquids sales without the impact of derivatives ($/Gal)	$	0.57		$	0.33
NGLs sales without the impact of derivatives ($/Gal)						$	0.51		$	0.71
Impact from settled derivatives ($/Gal)	$	(0.03	)	$	—	$	0.04		$	(0.05	)
Average natural gas liquids sales price, including settled derivatives ($/Gal)	$	0.54		$	0.33
Average NGLs sales price, including settled derivatives ($/Gal)						$	0.55		$	0.66

Natural gas, oil and condensate and natural gas liquids sales
Natural gas, oil and condensate and NGLs sales
Gas equivalents (MMcfe)	110,367			67,541		237,394			237,038

Total natural gas, oil and condensate and natural gas liquids sales	$	288,358		$	158,411
Total natural gas, oil and condensate and NGLs sales						$	628,477		$	665,206

Natural gas, oil and condensate and natural gas liquids sales without the impact of derivatives ($/Mcfe)	$	2.61		$	2.35
Natural gas, oil and condensate and NGLs sales without the impact of derivatives ($/Mcfe)						$	2.65		$	2.81
Impact from settled derivatives ($/Mcfe)	$	0.13		$	0.19	$	(0.01	)	$	0.06
Average natural gas, oil and condensate and natural gas liquids sales price, including settled derivatives ($/Mcfe)	$	2.74		$	2.54
Average natural gas, oil and condensate and NGLs sales price, including settled derivatives ($/Mcfe)						$	2.64		$	2.87

Production Costs:
Average production costs (per Mcfe)	$	0.18		$	0.26
Average production taxes and midstream costs (per Mcfe)	$	0.68		$	0.73
Total production and midstream costs and production taxes (per Mcfe)	$	0.86		$	0.99
Average production costs ($/Mcfe)						$	0.18		$	0.18
Average production taxes ($/Mcfe)						$	0.07		$	0.06
Average midstream gathering and processing ($/Mcfe)						$	0.60		$	0.57
Total production costs, midstream costs and production taxes ($/Mcfe)						$	0.85		$	0.81

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Lease Operating Expenses. Lease operating expenses ~~or LOE,~~ not including production taxes increased to ~~$20.0~~$42.2 million for the ~~three~~six months ended ~~September~~June 30, ~~2017~~2019 from ~~$17.5~~$41.8 million for the ~~three~~six months ended ~~September~~June 30, ~~2016.~~2018. This ~~$2.5~~$0.4 million, or 1%, increase was primarily the result of an increase in expenses related to location repair, disposal costs and ad valorem taxes, ~~location and facility repairs and maintenance, supervision and labor expenses, chemicals, surface rentals and water hauling,~~ partially offset by a decrease in ~~water disposal~~wireline services, facility maintenance expense and workover expenses. However, due to increased efficiencies and a 63% increase in our production volumes for the three months ended September 30, 2017 as compared to the three months ended September 30, 2016, our per unit LOE decreased by 30% from $0.26 per Mcfe to $0.18 per Mcfe.surface rentals.

Production Taxes. Production taxes increased ~~$1.9 million~~ to ~~$5.4~~$16.0 million for the ~~three~~six months ended ~~September~~June 30, ~~2017~~2019 from ~~$3.5~~$14.5 million for the ~~three months ended September 30, 2016.~~same period in 2018. This $1.5 million, or 10%, increase was primarily related to an increase in ~~realized prices and~~the production ~~volumes.~~tax rate associated with our SCOOP production.

Midstream Gathering and Processing Expenses. Midstream gathering and processing expenses increased ~~$23.9 million~~ to ~~$69.4~~$142.3 million for the ~~three~~six months ended ~~September~~June 30, ~~2017~~2019 from ~~$45.5~~$135.6 million for the same period in ~~2016.~~2018. This $6.7 million, or 5%, increase was primarily attributable to midstream expenses related to our increased production volumes in the Utica Shale and SCOOP resulting from our ~~2016~~2018 and ~~2017~~2019 drilling activities as well as ~~production volumes resulting from~~routine contract escalations associated with our ~~recent SCOOP acquisition.~~Utica Shale production.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization ~~or DD&A,~~ expense increased to ~~$106.7~~$243.4 million for the ~~three~~six months ended ~~September~~June 30, ~~2017,~~2019, and consisted of ~~$105.1~~$237.7 million in depletion of oil and natural gas properties and ~~$1.6~~$5.7 million in depreciation of other property and equipment, as compared to total DD&A expense of ~~$62.3~~$232.9 million for the ~~three~~six months ended ~~September~~June 30, ~~2016.~~2018. This $10.5 million, or 4%, increase was primarily due to an increase in our ~~full cost pool~~depletion rate as a result of ~~our SCOOP acquisition and an increase~~a decrease in our ~~production, partially offset by an increase~~full cost pool and a decrease in our total proved reserves ~~volume~~volumes used to calculate our total DD&A ~~expense.~~expense and an increase in our production.

General and Administrative Expenses. Net general and administrative expenses ~~increased~~decreased to ~~$13.1~~$24.8 million for the ~~three~~six months ended ~~September~~June 30, ~~2017~~2019 from ~~$10.5~~$27.1 million for the ~~three~~six months ended ~~September~~June 30, ~~2016.~~2018. This ~~$2.6~~$2.3 million, ~~increase~~or 8%, decrease was primarily due to ~~increases~~decreases in ~~salaries and benefits,~~ consulting fees and ~~bank service charges,~~travel expenses, partially offset by ~~a decrease~~increases in ~~employee stock compensation expense~~tax services and ~~legal fees. However, during~~computer support. In addition, for the ~~three~~six months ended ~~September~~June 30, ~~2017,~~2019, we decreased our unit general and administrative expense by ~~24%~~9% to ~~$0.12~~$0.10 per Mcfe from ~~$0.15~~$0.11 per Mcfe ~~during~~ the ~~three~~six months ended ~~September~~June 30, ~~2016.~~2018.

~~Accretion Expense. Accretion expense remained relatively flat at $0.5 million and $0.3 million for the three months ended September 30, 2017 and 2016, respectively.~~

Interest Expense. Interest expense increased to ~~$27.1~~$69.0 million for the ~~three~~six months ended ~~September~~June 30, ~~2017~~2019 from ~~$12.8~~$67.7 million for the ~~three~~six months ended ~~September~~June 30, ~~2016~~2018 due primarily to ~~the issuance of $600.0 million in aggregate principal amount of~~increased borrowings on our ~~6.375% Senior Notes due 2025, or the 2025 Notes, in December 2016. In addition, total~~revolving credit facility. Total weighted average debt outstanding under our revolving credit facility was ~~$273.7~~$123.3 million for the ~~three~~six months ended ~~September~~June 30, ~~2017~~2019 as compared to ~~no debt outstanding under such facility~~$100.1 million for the same period in ~~2016. As of September 30, 2017, amounts borrowed under our revolving credit facility bore interest at the Eurodollar rate of 3.74%. In addition,~~2018. Additionally, we capitalized approximately ~~$2.1~~$1.8 million and ~~$4.7~~$2.4 million in interest expense to undeveloped oil and natural gas properties during the ~~three~~six months ended ~~September~~June 30, ~~2017~~2019 and ~~2016,~~June 30, 2018, respectively. This $0.6 million decrease in capitalized interest in the ~~2017~~2019 period was primarily ~~due~~the result of changes to ~~a decrease in~~ our ~~average undeveloped leasehold costs in the Utica, partially offset by the SCOOP Acquisition.~~development plan for our oil and natural gas properties.

Income Taxes. As of ~~September~~June 30, ~~2017,~~2019, we had a federal net operating loss carryforward of approximately ~~$606.5~~$920.4 million from prior years, in addition to numerous temporary differences, which gave rise to a net deferred tax asset. ~~Periodically,~~Quarterly, management performs a forecast of our taxable income and analyzes other relevant factors to determine whether it is more likely than not that a valuation allowance is needed, looking at both positive and negative factors. A valuation allowance for our deferred tax assets is established if, in management’s opinion, it is more likely than not that some portion will not be realized. ~~At September~~During the six months ending June 30, ~~2017,~~2019, management determined there was sufficient positive evidence that it was more likely than not that the federal and some state net operating loss carryforwards should be realized and recorded a discrete tax benefit of $179.3 million. We will recognize through the annual effective tax rate a projected release of valuation allowance of an additional $27.7 million with respect to current year earnings. We will maintain a valuation allowance of ~~$548.4~~$4.8 million ~~had been provided~~ against the net deferred tax asset ~~with the exception of~~for certain ~~state NOLs and AMT credits that~~tax attributes for which we ~~expect to be able to utilize with NOL carrybacks and tax planning in the amount of $4.7 million.~~

~~Comparison of the Nine Months Ended September 30, 2017 and 2016~~

We reported net income of $278.6 million for the nine months ended September 30, 2017 as compared to a net loss of $739.3 million for the nine months ended September 30, 2016. This $1.0 billion period-to-period increase was due primarily to a $600.0 million increase in natural gas, oil and NGL revenues and no impairment charge for the nine months ended September 30, 2017 as compared to a $601.8 million impairment of oil and natural gas properties for the nine months ended

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September 30, 2016, partially offset by a $53.8 million increase in midstream gathering and processing expenses, a $29.9 million increase in interest expense and an $11.3 million increase in lease operating expenses for the nine months ended September 30, 2017 as compared to the nine months ended September 30, 2016.

~~Oil and Gas Revenues~~. For the nine months ended September 30, 2017, we reported oil and natural gas revenues of $922.5 million as compared to oil and natural gas revenues of $322.5 million during the same period in 2016. This $600.0 million, or 186%, increase in revenues was primarily attributable to the following:

A $186.0 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, $313.7 million was due to favorable changes in the fair value of our open derivative positions in each period, offset by $127.7 million unfavorable change in settlements related to our derivative positions.

~~A $334.7 million increase in natural gas sales without the impact of derivatives due to a 48% increase in natural gas market prices and a 50% increase in natural gas sales volumes.~~

~~A $24.5 million increase in oil and condensate sales without the impact of derivatives due to a 27% increase in oil and condensate market prices and a 10% increase in oil and condensate sales volumes.~~

A $54.8 million increase in natural gas liquid sales without the impact of derivatives due to a 90% increase in natural gas liquids market prices and a 39% 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, 2017, as compared to such data for the nine months ended September 30, 2016:

Nine months ended September 30,
2017 2016
($ In thousands)
Natural gas sales
Natural gas production volumes (MMcf) 247,012
164,233

Total natural gas sales $ 606,544
$ 271,873

Natural gas sales without the impact of derivatives ($/Mcf) $ 2.46
$ 1.66
Impact from settled derivatives ($/Mcf) $ 0.03
$ 0.78
Average natural gas sales price, including settled derivatives ($/Mcf) $ 2.49
$ 2.44

Oil and condensate sales
Oil and condensate production volumes (MBbls) 1,849
1,675

Total oil and condensate sales $ 85,338
$ 60,799

Oil and condensate sales without the impact of derivatives ($/Bbl) $ 46.15
$ 36.31
Impact from settled derivatives ($/Bbl) $ 2.92
$ 6.42
Average oil and condensate sales price, including settled derivatives ($/Bbl) $ 49.07
$ 42.73

Natural gas liquids sales
Natural gas liquids production volumes (MGal) 162,483
117,217

Total natural gas liquids sales $ 88,985
$ 34,198

Natural gas liquids sales without the impact of derivatives ($/Gal) $ 0.55
$ 0.29
Impact from settled derivatives ($/Gal) $ (0.01 ) $ —
Average natural gas liquids sales price, including settled derivatives ($/Gal) $ 0.54
$ 0.29

Natural gas, oil and condensate and natural gas liquids sales
Gas equivalents (MMcfe) 281,318
191,026

Total natural gas, oil and condensate and natural gas liquids sales $ 780,867
$ 366,870

Natural gas, oil and condensate and natural gas liquids sales without the impact of derivatives ($/Mcfe) $ 2.78
$ 1.92
Impact from settled derivatives ($/Mcfe) $ 0.04
$ 0.73
Average natural gas, oil and condensate and natural gas liquids sales price, including settled derivatives ($/Mcfe) $ 2.82
$ 2.65

Production Costs:
Average production costs (per Mcfe) $ 0.21
$ 0.26
Average production taxes and midstream costs (per Mcfe) $ 0.68
$ 0.69
Total production and midstream costs and production taxes (per Mcfe) $ 0.89
$ 0.95

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~~Lease Operating Expenses~~. Lease operating expenses, or LOE, not including production taxes increased to $60.0 million for the nine months ended September 30, 2017 from $48.8 million for the nine months ended September 30, 2016. This increase was mainly the result of an increase in expenses related to supervision and labor, overhead, compressors, surface rentals, water hauling and treatment, chemicals, workover costs and road, location and equipment repairs and maintenance, partially offset by a decrease in ad valorem taxes and disposal costs. However, due to increased efficiencies and a 47% increase in our production volumes for the nine months ended September 30, 2017 as compared to the nine months ended September 30, 2016, our per unit LOE decreased by 16% from $0.26 per Mcfe to $0.21 per Mcfe.

~~Production Taxes~~. Production taxes increased $4.9 million to $14.5 million for the nine months ended September 30, 2017 from $9.5 million for the same period in 2016. This increase was primarily related to an increase in realized prices and production volumes.

~~Midstream Gathering and Processing Expenses~~. Midstream gathering and processing expenses increased by $53.8 million to $176.3 million for the nine months ended September 30, 2017 from $122.5 million for the same period in 2016. This increase was primarily attributable to midstream expenses related to our increased production volumes in the Utica Shale resulting from our 2016 and 2017 drilling activities, as well as production volumes resulting from our recent SCOOP acquisition.

~~Depreciation, Depletion and Amortization~~. Depreciation, depletion and amortization, or DD&A, expense increased to $254.9 million for the nine months ended September 30, 2017, and consisted of $250.5 million in depletion of oil and natural gas properties and $4.4 million in depreciation of other property and equipment, as compared to total DD&A expense of $183.4 million for the nine months ended September 30, 2016. This increase was due to an increase in our full cost pool as a result of our SCOOP acquisition and an increase in our production, partially offset by an increase in our total proved reserves volume used to calculate our total DD&A expense.

~~General and Administrative Expenses~~. Net general and administrative expenses increased to $37.9 million for the nine months ended September 30, 2017 from $32.9 million for the nine months ended September 30, 2016. This $5.0 million increase was due to increases in salaries and benefits, consulting fees, bank service charges, computer support and franchise taxes, partially offset by a decrease in employee stock compensation expense and legal fees. However, during the nine months ended September 30, 2017, we decreased our unit general and administrative expense by 22% to $0.13 per Mcfe from $0.17 per Mcfe during the nine months ended September 30, 2016.

~~Accretion Expense. Accretion expense was $1.1 million and $0.8 million for the nine months ended September 30, 2017 and 2016, respectively.~~

~~Interest Expense~~. Interest expense increased to $74.8 million for the nine months ended September 30, 2017 from $44.9 million for the nine months ended September 30, 2016 due primarily to the issuance of $600.0 million of the 2025 Notes in December 2016. In addition, total weighted average debt outstanding under our revolving credit facility was $146.0 million for the nine months ended September 30, 2017 as compared to no debt outstanding under such facility for the same period in 2016. Additionally, we capitalized approximately $8.8 million and $7.7 million in interest expense to undeveloped oil and natural gas properties during the nine months ended September 30, 2017 and September 30, 2016, respectively. This increase in capitalized interest in the 2017 period was primarily due to the SCOOP Acquisition.

~~Income Taxes~~. As of September 30, 2017, we had a net operating loss carryforward of approximately $606.5 million, in addition to numerous temporary differences, which gave rise to a net deferred tax asset. Periodically, management performs a forecast of our taxable income to determine whetherhave determined 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 portionthose attribute carryforwards will not be realized. At September 30, 2017, a valuation allowance of $548.4 million had been provided against the net deferred tax asset, with the exception of certain state NOLs and AMT credits that we expectexpire prior to ~~be able to utilize with NOL carrybacks and tax planning in the amount of $4.7 million.~~utilization.

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 revolving 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.

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Net cash flow provided by operating activities was ~~$491.7~~$309.0 million for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2019 as compared to ~~net cash flow provided by operating activities of $245.3~~$411.0 million for the same period in ~~2016.~~2018. This ~~increase~~$102.0 million decrease was primarily the result of ~~an increase~~a decrease in cash receipts from our oil and natural gas purchasers due to ~~a 57% increase~~an 8% decrease in net revenues after giving effect to settled derivative

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instruments ~~partially offset by~~and an increase in our operating expenses. In addition, we received $2.5 million in dividends from our investment in Mammoth Energy during the six months ended June 30, 2019.

Net cash used in investing activities for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2019 was ~~$2.0 billion~~$419.4 million as compared to ~~$420.3~~$360.5 million for the same period in ~~2016.~~2018. During the ~~nine~~six months ended ~~September~~June 30, ~~2017,~~2019, we spent ~~$789.7~~$417.5 million in additions to oil and natural gas properties, of which ~~$528.2~~$256.7 million was spent on our ~~2017~~2019 drilling and completion ~~and recompletion~~ activities, ~~$86.3~~$83.9 million was spent on expenses attributable to wells spud, completed and recompleted during ~~2016, $1.9 million was spent on facility enhancements, $96.5~~2018, $25.8 million was spent on lease related costs, primarily the acquisition of leases in the Utica Shale and ~~$7.2~~$27.8 million was spent on ~~seismic,~~tubulars, with the remainder attributable mainly to future location development and capitalized general and administrative expenses. ~~We also spent $1.3 billion to fund~~During the ~~cash portion of the purchase price for our SCOOP acquisition. In addition, $1.8~~six months ended June 30, 2019, we invested $0.4 million ~~was invested~~ in Grizzly and ~~$39.4~~received a distribution of $1.9 million ~~was invested in Strike Force, net of distributions, during the nine months ended September 30, 2017.~~from Tatex. We did not make any investments in our other equity investments during the ~~nine~~six months ended ~~September~~June 30, ~~2017.~~2019.

Net cash provided by financing activities for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2019 was ~~$354.1~~$78.9 million as compared to ~~$426.3~~net cashed used in financing activities of $30.9 million for the same period in ~~2016.~~2018. The ~~2017~~2019 amount provided by financing activities is primarily attributable to net borrowings under our ~~revolving~~ credit ~~facility. The 2016 amount provided~~facility partially offset by ~~financing activities is primarily attributable to the net proceeds~~purchases under our stock repurchase program of approximately ~~$411.7 million from our March 2016 equity offering.~~$30.0 million.

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.~~other lenders. The credit agreement provides for a maximum facility amount of $1.5 billion and matures on December 13, 2021. As of ~~September~~June 30, ~~2017,~~2019, we had a borrowing base of $1.4 billion, with an elected commitment of $1.0 billion, and ~~$365.0~~$155.0 million in borrowings ~~outstanding, and total~~outstanding. Total funds available for borrowing under our revolving credit facility, after giving effect to an aggregate of ~~$237.5~~$251.5 million of outstanding letters of credit, were ~~$397.5 million.~~$593.5 million as of June 30, 2019. This facility is secured by substantially all of our assets. Our ~~wholly-owned~~wholly owned subsidiaries, excluding Grizzly Holdings Inc. ("Grizzly Holdings") and Mule Sky LLC ("Mule Sky") guarantee our obligations under our revolving credit facility.

In connection with our fall redetermination under our revolving credit facility, the lead lenders have proposed to increase our borrowing base from $1.0 million to $1.2 billion, with an elected commitment of $1.0 billion, and decrease the interest rate by 50 basis points, subject to the approval of the additional banks within the syndicate.

Advances under our revolving credit facility may be in the form of either base rate loans or eurodollar loans. The interest rate for base rate loans is equal to (1) the applicable rate, which ranges from ~~1.00%~~0.25% to ~~2.00%~~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 ~~2.00%~~1.25% to ~~3.00%~~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~~At June 30, ~~2017,~~2019, amounts borrowed under our ~~revolving~~ credit facility bore interest at ~~the Eurodollar~~a weighted average rate of ~~3.74%~~ 3.93%.

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

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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 dispositions will be limited to $3.0 million in the aggregate) for a twelve-month period may not be greater than

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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~~June 30, ~~2017.~~2019.

Senior Notes.

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

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

On October 14, 2016, we issued ~~the 2024 Notes~~an aggregate of $650.0 million in ~~aggregate~~ principal amount of ~~$650.0 million.~~our Senior Notes due 2024 (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. We received approximately $638.9 million in net proceeds from the offering of the 2024 Notes, which was used, together with cash on hand, to purchase the outstanding 2020 Notes in a concurrent cash tender offer, to pay fees and expenses thereof, and to redeem any of the 2020 Notes that remained outstanding after the completion of the tender offer.

On December 21, 2016, we issued an aggregate of $600.0 million in ~~aggregate~~ principal amount of our Senior Notes due 2025 ~~Notes.~~(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. We received approximately $584.7 million in net proceeds from the offering of the 2025 Notes, which we used, together with the net proceeds from our December 2016 offering of common stock and cash on hand, to fund the cash portion of the purchase price for the SCOOP acquisition.

In connection with the issuance of the 2024 Notes and the 2025 Notes, we and our subsidiary guarantors entered into two registration rights agreements, pursuant to which we 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, we issued $450.0 million in aggregate principal amount of our Senior Notes due 2026 ~~Notes.~~(the "2026 Notes" and, together with the 2023 Notes, the 2024 Notes, and the 2025 Notes, the "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. ~~A portion of the~~We received approximately $444.1 million in net proceeds from the ~~issuance~~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 ~~will be~~was used to fund the remaining ~~anticipated~~ 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 and 2025 Notes;~~ provided, however, that the ~~2023 Notes, 2024 Notes and 2025~~ Notes are not guaranteed by Grizzly Holdings ~~Inc.~~or Mule Sky, and will not be guaranteed by any of our future unrestricted subsidiaries. The guarantees rank equally in the right of payment with all of the senior indebtedness of the subsidiary guarantors and senior in the right of payment to any future subordinated indebtedness of the subsidiary guarantors. The ~~2023 Notes, 2024 Notes and 2025~~ Notes and the guarantees are effectively subordinated to all of our and the subsidiary guarantors’ secured indebtedness (including all borrowings and other obligations under our amended and restated credit agreement) to the extent of the value of

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the collateral securing such indebtedness, and structurally subordinated to all indebtedness and other liabilities of any of our subsidiaries that do not guarantee the ~~2023 Notes, 2024 Notes and 2025~~ Notes.

If we experience a change of control (as defined in the senior note indentures relating to the ~~2023 Notes, 2024 Notes and 2025~~ Notes), we will be required to make an offer to repurchase the ~~2023 Notes, 2024 Notes and 2025~~ Notes and at a price equal to 101% of the principal amount thereof, plus accrued and unpaid interest, if any, to the date of repurchase. If we sell certain assets and fail to use the proceeds in a manner specified in our senior note indentures, we will be required to use the remaining proceeds to make an offer to repurchase the ~~2023 Notes, 2024 Notes and 2025~~ Notes at a price equal to 100% of the principal amount thereof, plus accrued and unpaid interest, if any, to the date of repurchase. The senior note indentures relating to the ~~2023 Notes, 2024 Notes and 2025~~ Notes contain certain covenants that, subject to certain exceptions and qualifications, among other things, limit our ability and the ability of our restricted subsidiaries to incur or guarantee additional indebtedness, make certain investments, declare or pay dividends or make distributions on capital stock, prepay subordinated indebtedness, sell assets including capital stock of restricted subsidiaries, agree to payment restrictions affecting our restricted subsidiaries, consolidate, merge, sell or otherwise dispose of all or substantially all of our assets, enter into transactions with affiliates, incur liens, engage in business other than the oil and gas business and designate certain of our subsidiaries as unrestricted subsidiaries. Under the ~~indenture~~indentures relating to the ~~2023 Notes, 2024 Notes and 2025~~ Notes, certain of these covenants are subject to termination upon the occurrence of certain events, including in the event the ~~2023 Notes, 2024 Notes and 2025~~ Notes are ranked as “investment grade.”

In connection with the 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.

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We may use a combination of cash and borrowings under our revolving credit facility to retire our outstanding debt, through privately negotiated transactions, open market repurchases, redemptions, tender offers or otherwise, but we are under no obligation to do so.

Construction Loan.

On June 4, 2015, we entered into a construction loan agreement ~~or the construction loan,~~(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~~we make monthly payments of ~~the month through May 31, 2017. Monthly~~ interest and ~~principal payments are due beginning June 30, 2017, with the~~principal. The final payment is due June 4, 2025. As of ~~September~~June 30, ~~2017,~~2019, the total borrowings under the construction loan were ~~approximately $23.8~~approximately $22.7 million.

Capital Expenditures.

Our recent capital commitments have been primarily for the execution of our drilling programs, for acquisitions in the Utica Shale and our ~~recent~~ SCOOP acquisition in 2017, and for investments in entities that may provide services to facilitate the development of our acreage. Our strategy is to continue to (1) increase cash flow generated from our operations by undertaking new drilling, workover, sidetrack and recompletion projects to exploit our existing properties, subject to economic and industry conditions, (2) pursue acquisition and disposition opportunities and (3) pursue business integration opportunities.

Of our net reserves at December 31, ~~2016, 63.0%~~2018, 55.4% were categorized as proved undeveloped. Our proved reserves will generally decline as reserves are depleted, except to the extent that we conduct successful exploration or development activities or acquire properties containing proved developed reserves, or both. To realize reserves and increase production, we must continue our exploratory drilling, undertake other replacement activities or use third parties to accomplish those activities.

From January 1, 2017 through November 1, 2017, we spud 89 gross (84.1 net) wells in the Utica Shale. We currently expect to spud 96 gross (91 net) horizontal wells and commence sales from 68 gross (61 net) wellsFor further discussion on our Utica Shale acreage during 2017. As of November 1, 2017, we had four operated horizontal rigs drilling in the play. We also anticipate an additional 24 gross (eight net) horizontal wells will be drilled, and sales commenced from 45 gross (nine net) horizontal wells, on our Utica Shale acreage by other operators during 2017. We currently anticipate our 2017 capital expenditures to be approximately $735.0 millionactivities related to our ~~operated and non-operated Utica Shale drilling and completion activity.~~

~~From January 1, 2017 through November 1, 2017, 16 gross (13.6 net) wells were spud in the SCOOP. We currently anticipate our 2017~~ capital expenditures ~~to be approximately $215.0 million related to our operated~~incurred through June 30, 2019 see 2019 Production and non-operated SCOOP drilling and completion activity. We currently expect to spud 22 gross (18 net) wells and commence sales from 18 gross (16 net) wells on the SCOOP acreage during 2017. As of November 1, 2017, we had four operated horizontal rigs drilling in the play. We also anticipate 30 gross (one net) wells will be drilled, and sales commenced from 11 gross (one net) wells on this SCOOP acreage by other operators during 2017.

~~In addition, we currently expect to spend an aggregate of approximately $130.0 million in 2017 for acreage expenses, primarily lease extensions, in the Utica Shale and SCOOP.~~

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From January 1, 2017 through November 1, 2017, we spud ten new wells and recompleted 59 existing wells at our WCBB field. In our Hackberry fields, from January 1, 2017 through November 1, 2017, we spud five new wells and recompleted 20 existing wells. We currently expect to spend approximately $35.0 million in 2017 to drill 15 gross and net wells and perform recompletion activities in Southern Louisiana.

~~From January 1, 2017 through November 1, 2017, no new wells were spud on our Niobrara Formation acreage. We do not currently anticipate any capital expenditures in the Niobrara Formation in 2017.~~Drilling Activity section above.

As of ~~September~~June 30, ~~2017,~~2019, our net investment in Grizzly was approximately ~~$58.7~~$51.6 million. We do not currently anticipate any material capital expenditures in ~~2017~~2019 related to Grizzly’s activities.

We had no capital expenditures during the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2019 related to our interests in Thailand. We do not currently anticipate any capital expenditures in Thailand in ~~2017.~~2019.

In response to current declining forward natural gas prices, we are shifting to building an ~~effort~~organization that is focused on disciplined capital allocation, cash flow generation and a commitment to ~~facilitate the development~~executing a thoughtful, clearly communicated business plan that enhances value for all of our ~~Utica Shale~~stockholders. We plan to maximize results with the core assets in our portfolio today 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, 2017, we paid $39.4 million in net cash calls related to Strike Force. We currently anticipate that we will make approximately $45.0 million in cash contributions to Strike Force in 2017. We did not make any investments in any other of these entities during the nine months ended September 30, 2017, and we do not currently anticipate any capital expenditures related to these entities in 2017.

~~During 2015 and 2016, we continued to~~ focus on ~~operational efficiencies~~returns that will allow us to operate within our cash flow in ~~an effort~~2019. As a result, we currently expect to reduce our overall well costs and deliver better results in a more economical manner, particularly in light of the continued downturn in commodity prices. We have successfully leveraged the lower commodity price environment to gain access to higher-quality equipment and superior services for reduced costs, which has contributed to increased productivity. We have also renegotiated the contracts for our horizontal drilling rigs and locked in approximately 85% of our currently anticipated Utica Shale drilling and completion costs for 2017. This has allowed us to secure a base level of activity for 2017, hedge against expected increases in service costs and ensure access to quality equipment and experienced crews, all of which we expect to contribute to further efficiency gains.

In 2017, we focused our leasehold efforts on adding acreage organically within units scheduled in our near-term development plan. This strategy has allowed us to focus our leasehold spend on the highest return potential for deployed capital, resulting in the acquisition of additional core acreage in the dry gas window of the Utica play. These efforts, coupled with our active leasehold trading efforts, have led to a significant increase in our working interests on wells spud in the Utica Shale during 2017, equating to an incremental 22.0 net wells spud, thereby resulting in an increase in our anticipatedplanned capital expenditures ~~this year.~~by approximately 29% as compared to 2018.

Our total capital expenditures for ~~2017~~2019 are currently estimated to be ~~$985.0~~in the range of $525.0 million to $550.0 million for drilling and completion expenditures, with activity weighted to the first half of the year, of which ~~$846.0~~$436.0 million was spent as of ~~September~~June 30, ~~2017.~~2019. In addition, we currently expect to spend ~~approximately $130.0~~$40.0 to $50.0 million in ~~2017~~2019 for non-drilling and completion expenditures, which includes acreage expenses, primarily lease extensions in the Utica Shale, of which ~~$98.0~~$23.2 million was spent as of ~~September~~June 30, 2017, and approximately $45.0 million to fund our investment in Strike Force, of which $39.4 million was spent as of September 30, 2017. Approximately 75% and 22% of our 2017 estimated drilling and completion capital expenditures are currently expected to be spent in the Utica Shale and in the SCOOP play in Oklahoma, respectively.2019. The ~~2017~~2019 range of capital expenditures is ~~higher~~lower than the ~~$549.5~~$814.7 million spent in ~~2016,~~2018, primarily due to the ~~increase~~decrease in current commodity prices, specifically natural gas prices, and our ~~expansion into~~desire to fund our capital development program within cash flow, as well as to generate free cash flow.

In January 2019, our board of directors approved a new stock repurchase program to acquire up to $400 million of our outstanding common stock within a 24 month period. We intend to purchase shares under the repurchase program opportunistically with available funds primarily from cash flow from operations and ~~exploratory activities in the SCOOP play in Oklahoma.~~sale of non-core assets while maintaining sufficient liquidity to fund our capital development programs.

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~~revolving credit facility will be sufficient to meet our normal recurring operating needs and capital requirements for the next twelve months. We believe that

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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 ~~our~~the Utica ~~Basin~~Shale and ~~Mid-Continent operating areas, or to scale back our activity,~~the 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 method 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

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environment worsens, our revenues, cash flows, results of operations, liquidity and reserves may be materially and adversely affected.

Commodity Price Risk

See Item 3. “Quantitative and Qualitative Disclosures about Market Risk” for information regarding our open fixed price swaps at ~~September~~June 30, ~~2017.~~

~~Commitments~~

In connection with our acquisition in 1997 of the remaining 50% interest in the WCBB properties, we assumed the seller’s (Chevron) obligation to contribute approximately $18,000 per month through March 2004, to a plugging and abandonment trust and the obligation to plug a minimum of 20 wells per year for 20 years commencing March 11, 1997. Chevron retained a security interest in production from these properties until our abandonment obligations to Chevron have been fulfilled. Beginning in 2009, we can access the trust for use in plugging and abandonment charges associated with the property. As of September 30, 2017, the plugging and abandonment trust totaled approximately $3.1 million. At September 30, 2017, we have plugged 551 wells at WCBB since we began our plugging program in 1997, which management believes fulfills our minimum plugging obligation.2019.

Contractual and Commercial Obligations

We have various contractual obligations in the normal course of our operations and financing activities. There have been no material changes to our contractual obligations from those disclosed in our Annual Report on Form 10-K for the year ended December 31, ~~2016.~~2018.

Off-balance Sheet Arrangements

We ~~had no~~may enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. As of June 30, 2019, our material off-balance sheet arrangements and transactions include $251.5 million in letters of credit outstanding against our 2019 revolving credit facility and $73.9 million in surety bonds issued as financial assurance on midstream firm transportation agreements. Management believes these items will expire without being funded. There are no other transactions, arrangements or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect our liquidity or availability of ~~September~~our capital resources. See Note 7 to our consolidated financial statements for further discussion of the various financial guarantees we have issued.

Critical Accounting Policies and Estimates

As of June 30, ~~2017.~~2019, there have been no significant changes in our critical accounting policies from those disclosed in our 2018 Annual Report on Form 10-K.

New Accounting Pronouncements

~~In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2014-09,~~ ~~Revenue from Contracts with Customers, which supersedes the revenue recognition requirements in Topic 605,~~ ~~Revenue Recognition~~, and most industry-specific guidance. The core principle of the new standard is for the recognition of revenue to depict the transfer of goods or services to customers in amounts that reflect the payment to which we expect to be entitled in exchange for those goods or services. The new standard will also result in enhanced revenue disclosures, provide guidance for transactions that were not previously addressed comprehensively and improve guidance for multiple-element arrangements. The ASU is effective for annual periods beginning after December 15, 2016, and interim periods within those years. The new standard permits retrospective application using either of the following methodologies: (i) restatement of each prior reporting period presented (full retrospective method) or (ii) recognition of a cumulative-effect adjustment as of the date of initial application (modified retrospective method). In July 2015, the FASB decided to defer the effective date by one year (until 2018). We are evaluating the impact of this ASU on our consolidated financial statements and working to identify any potential differences that would result from applying the requirements of the ASU to existing contracts and current accounting policies and practices. This evaluation requires, among other things, a review of the contracts we have with customers within each of three revenue streams identified within our business. including natural gas sales, oil and condensate sales and natural gas liquid sales. We do not believe further disaggregation of revenue will be required under the new standard. Substantially all of our revenue is earned pursuant to agreements under which we have currently interpreted one performance obligation, which is satisfied at a point-in-time. As part of the evaluation work to-date, we have substantially completed our contract reviews and documentation. Due to industry-wide ongoing discussions on certain application issues, we cannot reasonably estimate the expected financial statement impact; however, we do not expect the impact of the application of the new standard to be material on net income or cash flows based on the reviews performed to-date. We are currently assessing the requirements of additional disclosures and documentation of new policies, procedures, system, control and data requirements. Our expectation is to adopt the standard on January 1, 2018, using the modified retrospective method. Based on the analysis to-date, we have not identified any material impact on our consolidated financial statements other than additional disclosures requirements.

In February 2016, the FASB issued ~~ASU~~Accounting Standards Update ("ASU") No. 2016-02, Leases (Topic 842). The standard supersedes the previous lease guidance ~~requires the lessee~~by requiring lessees to recognize ~~most leases~~a right-to-use asset and lease liability on the balance sheet ~~thereby resulting in the recognition~~for all leases with lease terms of ~~lease assets~~greater than one year while maintaining substantially similar classifications for financing and ~~liability for those leases currently classified as~~ operating leases. ~~The accounting for lessors is largely unchanged. The guidance is effective for periods after December 15,~~

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2018, with early adoption permitted. We are in the process of evaluating the impact of this guidance on our consolidated financial statements and related disclosures; however, based on our current operating leases, it is not expectedSubsequent to ~~have a material impact.~~

~~In March 2016,~~ASU 2016-02, the FASB issued ~~ASU No. 2016-05,~~ ~~Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships.~~ ~~The guidance was issued~~several related ASU’s to clarify ~~that change in~~ the ~~counterparty to a derivative instrument that had been designated as~~application of the ~~hedging instrument under Topic 815, does not require designation of that hedging relationship provided that all other hedge accounting criteria continue to be met.~~lease standard. We adopted the new standard as of January 1, ~~2017. There was no impact~~2019 on a prospective basis using the simplified transition method permitted by ASU 2018-11, Leases (Topic 842): Targeted Improvements. The comparative information has not been restated and continues to be reported under the historic accounting standards in effect for those periods. See Note 12 to our consolidated financial statements ~~because all current derivative instruments are not designated~~ for ~~hedge accounting.~~further discussion of the lease standard.

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

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

In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments-Credit Losses: Measurement of Credit Losses on Financial Instruments. This ASU amends guidance on reporting credit losses for assets held at amortized cost basis and available for sale debt securities. For assets held at amortized cost basis, this ASU eliminates the probable initial recognition threshold in current GAAP and instead, requires an entity to reflect its current estimate of all expected credit losses. The amendments affect loans, debt securities, trade receivables, net investments in leases, off balance sheet credit exposure, reinsurance receivables and any other financial assets not excluded from the scope that have the contractual right to receive cash. Additionally, in May 2019, the FASB issued ASU No. 2019-05, Financial Instruments—Credit Losses (Topic 326): Targeted Transition Relief. The amendments in this update allow preparers to irrevocably elect the fair value option, on an instrument-by-instrument basis, for eligible financial assets measured at amortized cost basis upon adoption of 2016-13. The guidance is effective for periods after December 15, 2019, with early adoption permitted. We are currently evaluating the

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impact this standard will have on our financial statements and related disclosures and do not anticipate it to have a material ~~affect.~~effect.

In ~~August 2016,~~February 2018, the FASB issued ASU No. ~~2016-15,~~ ~~Statement of Cash Flows: Classification~~2018-02, Income statement - Reporting Comprehensive Income (Topic 220) - Reclassification of Certain ~~Cash Receipts~~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 ~~Cash Payments.~~ ~~This ASU provides guidance~~Jobs Act of ~~eight specific cash flow issues. This ASU is~~2017. The amendment will be effective for reporting periods beginning after December 15, ~~2017, with~~2018, and early adoption is permitted. We ~~are in the process of evaluating~~assessed the impact of ~~this guidance~~the ASU on our consolidated financial ~~statements.~~statements and related disclosures, and determined there was no material impact.

In ~~December 2016,~~August 2018, the FASB issued ASU No. ~~2016-20,~~ ~~Technical Corrections~~2018-13, Fair Value Measurement (Topic 820): Disclosure Framework—Changes to the Disclosure Requirements for Fair Value Measurement which removes, modifies, and ~~Improvements to Topic 606, Revenue from Contracts with Customers. This guidance updates narrow aspects of the guidance issued in Update 2014-09. This~~adds certain disclosure requirements on fair value measurements. The amendment iswill be effective for reporting periods beginning after December 15, ~~2017, with~~2019, and early adoption is permitted. We ~~in the process of evaluating~~are currently assessing the impact of ~~this~~the ASU on our consolidated financial ~~statements.~~statements and related disclosures.

In ~~January 2017,~~August 2018, the FASB also 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~~2018-15 , Intangibles—Goodwill 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~~Other—Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a ~~single asset~~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 ~~group of similar assets. If that screen is met, the set of assets is not a business.~~obtain internal-use software. The ~~new framework also specifies the minimum required inputs and processes necessary to~~amendment will be ~~a business. This amendment is~~ effective for reporting periods beginning after December 15, ~~2017, with~~2019, and early adoption is permitted. We are ~~in the process of evaluating~~currently assessing the impact of ~~this~~the ASU on our consolidated financial ~~statements.~~statements and related disclosures.

In November 2018, the FASB also issued ASU No. 2018-18, Collaborative Arrangements (Topic 808): Clarifying the Interaction Between Topic 808 and Topic 606, which provides guidance on how to assess whether certain transactions between participants in a collaborative arrangement should be accounted for within the ASU No. 2014-09 revenue recognition standard discussed above. 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.



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

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operations over a wide area; the level of consumer demand; the price and availability of alternative fuels; technical advances affecting energy consumption; risks associated with operating drilling rigs; the availability of pipeline capacity; the price and level of foreign imports; domestic and foreign governmental regulations and taxes; the ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls; political instability or armed conflict in oil and natural gas producing regions; and the overall economic environment.

These factors and the volatility of the energy markets make it extremely difficult to predict future oil and natural gas price movements with any certainty. During ~~the past seven years, the posted price for WTI, has~~2018, West Texas Intermediate ("WTI") prices ranged from ~~a low of $26.05~~$44.48 to $77.41 per barrel or Bbl, in February 2016 to a high of $113.39 per Bbl in April 2011. The Henry Hub spot market price of natural gas has ranged from a low of $1.61 per MMBtu in March 2016 to a high of $7.51 per MMBtu in January 2010. On October 27, 2017, the WTI posted price for crude oil was $53.90 per Bbl and the Henry Hub spot market price of natural gas ranged from $2.49 to $6.24 per MMBtu. On July 26, 2019, the WTI posted price for crude oil was ~~$2.78~~$56.20 per Bbl and the Henry Hub spot market price for natural gas was $2.23 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.

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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~~June 30, ~~2017:~~2019:

Location Daily Volume (MMBtu/day) Weighted
Average Price
Remaining 2017 NYMEX Henry Hub 765,000
$ 3.19
2018 NYMEX Henry Hub 898,000
$ 3.06
2019 NYMEX Henry Hub 112,000
$ 3.01



	Location	Daily Volume (MMBtu/day)	Weighted Average Price
Remaining 2019	NYMEX Henry Hub	1,380,000	$	2.81
2020	NYMEX Henry Hub	204,000	$	2.77

Location Daily Volume
(Bbls/day) Weighted
Average Price
Remaining 2017 ARGUS LLS 1,500
$ 53.12
2018 ARGUS LLS 1,000
$ 53.91
Remaining 2017 NYMEX WTI 4,500
$ 54.89
2018 NYMEX WTI 3,000
$ 52.24



	Location	Daily Volume (Bbls/day)	Weighted Average Price
Remaining 2019	NYMEX WTI	6,000	$	60.81
2020	NYMEX WTI	6,000	$	59.82



	Location	Daily Volume (Bbls/day)	Weighted Average Price
Remaining 2019	Mont Belvieu C2	1,000	$	18.48
Remaining 2019	Mont Belvieu C3	4,000	$	29.02
Remaining 2019	Mont Belvieu C5	1,000	$	53.71

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.~~

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volumes.

Location Daily Volume (MMBtu/day) Weighted Average Price
Remaining 2017 NYMEX Henry Hub 65,000
$ 3.11
2018 NYMEX Henry Hub 103,000
$ 3.25
2019 NYMEX Henry Hub 135,000
$ 3.07

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



	Location	Daily Volume (MMBtu/day)	Weighted Average Price
Remaining 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~~In December 2018, the counterparties chose to ~~extend the terms expires in December 2018. If executed, we would have additional~~exercise all natural gas fixed price swaps, ~~for~~resulting in an additional 100,000 MMBtu per day at a weighted average price of $3.05 per ~~MMBtu.~~MMBtu, which is included in the natural gas fixed price swaps listed above.

In addition, we have entered into natural gas basis swap ~~positions, which settle on the pricing index to basis differential of NGPL Mid-Continent to NYMEX Henry Hub natural gas price.~~positions. As of ~~September~~June 30, ~~2017,~~2019, we had the following natural gas basis swap positions ~~for NGPL Mid-Continent.~~

open:

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



	Gulfport Pays	Gulfport Receives	Daily Volume (MMBtu/day)	Weighted Average Fixed Spread
Remaining 2019	Transco Zone 4	NYMEX Plus Fixed Spread	60,000	$	(0.05	)
2020	Transco Zone 4	NYMEX Plus Fixed Spread	60,000	$	(0.05	)
2020	Fixed Spread	ONEOK Minus NYMEX	10,000	$	(0.54	)

Under our ~~2017~~2019 contracts, we have hedged approximately ~~62%~~94% to ~~64%~~96% of our estimated ~~2017~~2019 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~~June 30, ~~2017,~~2019, we had a net ~~liability~~asset derivative position of ~~$7.1~~$139.5 million as compared to a net liability derivative position of ~~$2.5~~$50.2 million as of ~~September~~June 30, ~~2016,~~2018, 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 ~~$147.9~~$99.8 million, while a 10% decrease in underlying commodity prices would have increased the fair value of these instruments by approximately ~~$147.9~~$99.7 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.

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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~~June 30, ~~2017,~~2019, we had ~~$365.0~~$155.0 million in borrowings outstanding under our revolving credit facility which bore interest at ~~the eurodollar~~a weighted average rate of ~~3.74%~~3.93%. A 1.0% increase in the average interest rate for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2019 would have resulted in an estimated ~~$0.8~~$0.4 million increase in interest expense. As of ~~September~~June 30, ~~2017,~~2019, we did not have any interest rate swaps to hedge our interest risks.



ITEM 4.	CONTROLS AND PROCEDURES

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

As of ~~September~~June 30, ~~2017,~~2019, an evaluation was performed under the supervision and with the participation of management, including our Chief Executive Officer and President and our Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Exchange Act. Based upon our

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evaluation, our Chief Executive Officer and President and our Chief Financial Officer have concluded that, as of ~~September~~June 30, ~~2017,~~2019, our disclosure controls and procedures are effective.

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

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PART II



ITEM 1.	LEGAL PROCEEDINGS

InLitigation and Regulatory Proceedings

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

We, along with a number of other oil and gas companies, have been named as a defendant in two separate complaints, one filed by the State of Louisiana and the Parish of Cameron in the 38th Judicial District Court for the Parish of Cameron on February 9, 2016 and the other filed by the State of Louisiana and the District Attorney for the 15^th Judicial District of the State of Louisiana in the 15^th Judicial District Court for the Parish of ~~Vermillion~~Vermilion on July 29, 2016 ~~we were named as a defendant, among 26 oil and gas companies, in~~(together, the ~~Cameron Parish complaint and among more than 40 oil and gas companies in the Vermillion Parish complaint, or the Complaints.~~"Complaints"). The Complaints ~~were filed under~~allege that certain of the defendants’ operations violated the State and Local Coastal Resources Management Act of 1978, as amended, and the rules, regulations, orders and ordinances adopted thereunder 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 Vermillion Parish complaint, were conducted in violation of the CZM Laws. The Complaints allege that such activities caused(the "CZM Laws") by causing 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.Parish. The Complaints also allege that the defendants’ oil and gas activities have resulted in the dredging of numerous canals, which had a direct and significant impact on the state coastal waters within the relevant Parish and that the defendants, among other things, failed to design, construct and maintain these canals using the best practical techniques to prevent bank slumping, erosion and saltwater intrusion and to minimize the potential for inland movement of storm-generated surges, which activities allegedly have resulted in the erosion of marshes and the degradation of terrestrial and aquatic life therein. The Complaints also allege that the defendants failed to re-vegetate, refill, clean, detoxify and otherwise restore these canals to their original condition. In these two petitions, the plaintiffs seek damages and other appropriate relief under the CZM Laws, including the payment of costs necessary to clear, re-vegetate, detoxify and otherwise restore the affected coastal zone of the relevant Parish to its original condition, actual restoration of such coastal zone to its original condition, and the payment of reasonable attorney fees and legal expenses and ~~pre-judgment and post judgment~~ interest.

~~We were served with the Cameron complaint in early May 2016 and with the Vermillion complaint in early September 2016.~~ The Louisiana Attorney General and the Louisiana Department of Natural Resources intervened in both the Cameron Parish suit and the Vermillion Parish suit. Shortly after the Complaints were filed, certain defendantscases have been removed ~~the cases to the lawsuit~~ to the United States District Court for the Western District of ~~Louisiana. In both cases, the plaintiffs filed a motion~~Louisiana, and motions to remand and the plaintiffs agreed to an extension of time for all defendants to file responsive pleadings until the District Courts ruled on the motions to remand. In the Vermilion Parish case, the District Court entered an order on September 26, 2017 remanding the lawsuit to the 15th Judicial District Court, State of Louisiana, Parish of Vermilion. Pursuant to an agreement with plaintiffs’ counsel, all defendants have an extension of time through November 27, 2017 to file responsive pleadings to plaintiffs’ petitionsare pending.

The cases are still in the Vermilion Parish lawsuit. In the Cameron Parish lawsuit, the District Court has not ruled on plaintiffs’ motion to remand. Briefing on the motion to remand has been completed; however, no hearing has been set for the motion to remand,their early stages and the District Court has not given the parties any indication regarding when a ruling should be expected. Due the procedural posture of lawsuits, the fact that responsive pleadings have not been filed and the fact that the parties have ~~not begun discovery,~~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~~SEC Investigation

The SEC has commenced an investigation with respect to certain actions by former Company management, including alleged improper personal use of Company assets, and potential violations by former management and the ~~nature~~Company of the Sarbanes-Oxley Act of 2002 in connection with such actions. We have fully cooperated and intend to continue to cooperate fully with the SEC’s investigation. Although it is not possible to predict the ultimate resolution or financial liability with respect to this matter, we believe that the outcome of this matter will not have a material effect on our business, wefinancial condition or results of operations.

Business Operations

We are ~~from time to time,~~ involved in ~~routine litigation or subject to~~various lawsuits and disputes ~~or claims related~~incidental to our business ~~activities,~~operations, including ~~workers’ compensation~~commercial disputes, personal injury claims, royalty claims, property damage claims and ~~employment related disputes. In~~contract actions.

Environmental Contingencies

The nature of the oil and gas business carries with it certain environmental risks for us and our subsidiaries. We have implemented various policies, programs, procedures, training and audits to reduce and mitigate such environmental risks. We conduct periodic reviews, on a company-wide basis, to assess changes in our environmental risk profile. Environmental reserves are established for environmental liabilities for which economic losses are probable and reasonably estimable. We manage our exposure to environmental liabilities in acquisitions by using an evaluation process that seeks to identify pre-existing contamination or compliance concerns and address the potential liability. Depending on the extent of an identified environmental concern, we may, among other things, exclude a property from the transaction, require the seller to remediate the property to our satisfaction in an acquisition or agree to assume liability for the remediation of the property.

We received several Findings of Violation (“FOV”) from the United States Environmental Protection Agency ("USEPA") alleging violations of the Clean Air Act at less than 20 locations in Ohio. The first FOV for one site was dated December 11,

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2013. Two subsequent FOVs incorporated and expanded the scope on January 4, 2017 and April 15, 2019. We have exchanged information with the USEPA and are engaged in discussions aimed at resolving the allegations. Resolution of the matter may result in monetary sanctions of more than $100,000.

Other Matters

Based on management’s current assessment, we are of the opinion ofthat no pending or threatened lawsuit or dispute relating to our ~~management, none of the pending litigation, disputes or claims against us, if decided adversely, will~~business operations are likely to have a material adverse effect on our future consolidated financial ~~condition, cash flows or~~position, results of ~~operations.~~operations or cash flows. The final resolution of such matters could exceed amounts accrued, however, and actual results could differ materially from management’s estimates.



ITEM 1A.	RISK FACTORS

See risk factors previously disclosed in our Annual Report on Form 10-K for the year ended December 31, ~~2016.~~2018.



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

Unregistered Sales of Equity Securities

None.

Issuer Repurchases of Equity Securities

Our common stock repurchase activity for the three months ended June 30, 2019 was as follows:



Period	Total number of shares purchased ⁽²⁾	Average price paid per share		Total number of shares purchased as part of publicly announced plans or programs ⁽²⁾	Approximate maximum dollar value of shares that may yet be purchased under the plans or programs ⁽¹⁾
April 2019	296,587	$	7.65	224,563	$	370,000,000
May 2019	—	$	—	—	$	370,000,000
June 2019	—	$	—	—	$	370,000,000
Total	296,587	$	7.65	224,563



(1)	In January 2019, our board of directors approved a new stock repurchase program to acquire up to $400 million of our outstanding common stock within a 24 month period. This repurchase program may be suspended from time to time, modified, extended or discontinued by our board of directors at any time.
(2)	In April 2019, we repurchased and canceled 224,563 shares under the repurchase program at a weighted average price of $7.96 per share. Additionally, in April 2019, we repurchased and canceled 72,024 shares of our common stock at a weighted average price of $6.69 to satisfy tax withholding requirements incurred upon the vesting of restricted stock unit awards.

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ITEM 3.	DEFAULTS UPON SENIOR SECURITIES

Not applicable.



ITEM 4.	MINE SAFETY DISCLOSURES

Not applicable.



ITEM 5.	OTHER INFORMATION

~~None.~~

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2019 Amended and Restated Stock Incentive Plan

On June 6, 2019, at the 2019 Annual Meeting of Stockholders of Gulfport Energy Corporation, our stockholders approved the 2019 Amended and Restated Stock Incentive Plan (as amended and restated, the “Plan”), which amended and restated our 2013 Restated Stock Incentive Plan. The Plan had previously been unanimously adopted, subject to stockholder approval, by the Compensation Committee (the “Compensation Committee”) of our board of directors (our “Board”), acting upon authority delegated to it by our Board. The Plan, among other things, increases the share reserve by an additional 5,000,000 shares and extends the expiration date from April 18, 2023 to April 28, 2029. A detailed summary of the Plan is set forth in our definitive proxy statement filed with the SEC on April 30, 2019. The description of the Plan herein and the summary of the Plan in the proxy statement are qualified in their entirety by reference to the full text of the Plan, which is attached to hereto as Exhibit 10.1 and incorporated by reference herein.

Indemnification Agreements

On August 1, 2019, the Company entered into indemnification agreements with each of its directors and David M. Wood, the Company’s Chief Executive Officer and President, Donnie Moore, the Company’s Chief Operating Officer, and Patrick K. Craine, the Company’s General Counsel and Corporate Secretary. The indemnification agreements require the Company to indemnify those individuals to the fullest extent permitted under Delaware law against liabilities that may arise by reason of their service to the Company, and to advance expenses incurred as a result of any proceeding against them as to which they could be indemnified. The indemnification agreements superseded any existing indemnification agreements between the Company and those individuals. The description of the indemnification agreements herein is qualified in its entirety by reference to the full text of the form of indemnification agreement, which is attached to hereto as Exhibit 10.2 and incorporated by reference herein.

Employment Agreements

Effective August 1, 2019, the Company entered into employment agreements (the “Employment Agreements”) with David M. Wood, the Company’s Chief Executive Officer and President, Donnie Moore, the Company’s Chief Operating Officer, and Patrick K. Craine, the Company’s General Counsel and Corporate Secretary (each, an “Executive”).

Each Employment Agreement provides for an initial term that extends through December 31, 2023; provided that the agreement will automatically renew for successive one-year terms unless the Company or the Executive gives written notice not to renew at least 90 days before the end of the initial term or any renewal term. If a change in control (as defined in the Employment Agreement) occurs during the term of the Employment Agreement, the term will be extended to the later of the original expiration date of the term or the date that is 24 months after the effective date of the change of control.

The Employment Agreements provide the respective Executive with, among other things: (i) an annual base salary of $834,000, $505,000 and $435,000, for Messrs. Wood, Moore and Craine, respectively, (ii) eligibility to earn a target annual bonus under the Company’s annual incentive plan equal to 125%, 100% and 90% of base salary for Messrs. Wood, Moore and Craine, respectively, (iii) eligibility for annual grants of equity awards as determined in the sole discretion of the Compensation Committee pursuant to the Company's equity compensation plans; provided that, with respect to the calendar year ending December 31, 2020, each of Messrs. Wood, Moore and Craine will receive awards that have a target aggregate fair value of 500%, 350% and 200% of base pay, respectively, and (iv) benefits that are customarily provided to similarly situated executives of the Company.

The Employment Agreements further provide that (i) if the Executive’s employment is terminated without cause by the Company or by the Executive for good reason (as such terms are defined in the Employment Agreements), such Executive is entitled to severance compensation equal to (a) 100% of annual base salary and target annual bonus, (b) pro rata target annual bonus, (c) pro rata vesting of the Executive’s unvested awards (with performance awards vested based on performance through the termination date), (d) immediate vesting of any Company matching or other contributions to the Company’s non-qualified deferred compensation plans, if any (“Company Non-Qualified Contributions”), and (e) a lump sum payment equal to the Executive’s monthly COBRA premium for a 12 month period, and (ii) if the Executive’s employment is terminated without cause by the Company or by the Executive for good reason, in each case, within 24 months following a change in control, such Executive is entitled to severance compensation equal to (v) 200% of annual base salary and target annual bonus, (w) pro rata target annual bonus, (x) immediate vesting of the Executive’s unvested awards (with performance awards vested based on performance through the termination date), (y) immediate vesting of any Company Non-Qualified Contributions, and (z) a lump sum payment equal to the Executive’s monthly COBRA premium for an 18 month period. Any severance benefits

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payable under the Employment Agreement is conditioned on timely execution of a waiver and release of claims. Each Employment Agreement also contains a one-year post-employment non-solicitation clause and standard confidentiality, trade secrets and cooperation provisions.

The description of the Employment Agreements herein is qualified in its entirety by reference to the full text of the Employment Agreements, which are attached to hereto as Exhibits 10.3, 10.4 and 10.5 and incorporated by reference herein.



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 October 11, 2017, among Gulfport Energy Corporation, the subsidiary guarantors party and J.P. Morgan Securities LLC, as representative of the several initial purchasers (incorporated by reference to Exhibit 4.2 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on October 11, 2017).

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

~~10.1~~10.1+		~~Tenth Amendment to~~2019 Amended and Restated ~~Credit Agreement, dated as of October 4, 2017, among Gulfport Energy Corporation, as borrower, The Bank of Nova Scotia, as administrative agent, and the lenders party thereto~~Stock Incentive Plan (incorporated by reference to ~~Exhibit 10.1~~Appendix A to the ~~Form 8-K,~~Company’s Definitive Proxy Statement on Schedule 14A, File No. 000-19514, filed by the Company with the SEC on ~~October 5, 2017)~~April 30, 2019).

10.2*+		Form of Indemnification Agreement.

10.3*+		Employment Agreement, entered into and effective as of August 1, 2019, by and between Gulfport Energy Corporation and David M. Wood.

10.4*+		Employment Agreement, entered into and effective as of August 1, 2019, by and between Gulfport Energy Corporation and Donnie Moore.

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10.5*+		Employment Agreement, entered into and effective as of August 1, 2019, by and between Gulfport Energy Corporation and Patrick K. Craine.

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

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

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

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

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

101.SCH*		XBRL Taxonomy Extension Schema Document.

101.CAL*		XBRL Taxonomy Extension Calculation Linkbase Document.

101.DEF*		XBRL Taxonomy Extension Definition Linkbase Document.

101.LAB*		XBRL Taxonomy Extension Labels Linkbase Document.

101.PRE*		XBRL Taxonomy Extension Presentation Linkbase Document.

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



*	Filed herewith.
+	Management contract, compensation plan or arrangement.

6057

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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~~August 2, ~~2017~~2019



GULFPORT ENERGY CORPORATION

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

6158



				Paid-in Capital			Accumulated Other Comprehensive Income (loss)			Retained Deficit			Total Stockholders’ Equity
	Common Stock
	Shares	Amount
	(In thousands, except share data)
Balance at January 1, 2017	158,829,816	$	1,588	$	3,946,442		$	(53,058	)	$	(1,711,080	)	$	2,183,892
Net income	—	—		—			—			278,626			278,626
Other Comprehensive Income							12,719			—			12,719
Stock 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

Balance at January 1, 2016	108,322,250	$	1,082	$	2,824,303		$	(55,177	)	$	(731,371	)	$	2,038,837
Net loss	—	—		—			—			(739,339		)	(739,339		)
Other Comprehensive Income	—	—		—			4,361			—			4,361
Stock Compensation	—	—		9,550			—			—			9,550
Issuance of Common Stock in public offerings, net of related expenses	16,905,000	169		411,542			—			—			411,711
Issuance of Restricted Stock	226,283	2		(2		)	—			—			—
Balance at September 30, 2016	125,453,533	$	1,253	$	3,245,393		$	(50,816	)	$	(1,470,710	)	$	1,725,120



	(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



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



	September 30, 2017			September 30, 2016
	(In thousands)
Asset retirement obligation, beginning of period	$	34,276		$	26,437
Liabilities incurred	11,557			6,726
Liabilities settled	(2,520		)	(955		)
Accretion expense	1,148			777
Asset retirement obligation as of end of period	44,461			32,985
Less current portion	195			75
Asset retirement obligation, long-term	$	44,266		$	32,910



	Number of Unvested Restricted Shares		Weighted Average Grant Date Fair Value
Unvested shares as of January 1, 2017	613,056		$	32.90
Granted	870,358		15.15
Vested	(399,843	)	28.77
Forfeited	(74,024	)	30.45
Unvested shares as of September 30, 2017	1,009,547		$	19.42



		(MMBtu per day)
Remaining 2017		710,000
2018		561,000
2019		659,000
2020		526,000
2021		372,000
Thereafter		249,000
Total		3,077,000



	(In thousands)
Remaining 2017	$	49,052
2018	238,767
2019	243,389
2020	240,746
2021	239,786
Thereafter	2,715,005
Total	$	3,726,745



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



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



	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



	Three months ended September 30, 2016
	Parent			Guarantors			Non-Guarantor			Eliminations			Consolidated

Total revenues	$	193,227		$	465		$	—		$	—		$	193,692

Costs and expenses:
Lease operating expenses	17,283			188			—			—			17,471
Production taxes	3,495			30			—			—			3,525
Midstream gathering and processing	45,385			90			—			—			45,475
Depreciation, depletion, and amortization	62,284			1			—			—			62,285
Impairment of oil and natural gas properties	212,194			—			—			—			212,194
General and administrative	10,772			(305		)	—			—			10,467
Accretion expense	269			—			—			—			269
	351,682			4			—			—			351,686

(LOSS) INCOME FROM OPERATIONS	(158,455		)	461			—			—			(157,994		)

OTHER (INCOME) EXPENSE:
Interest expense	12,787			—			—			—			12,787
Interest income	(337		)	—			—			—			(337		)
Insurance Proceeds	(3,750		)	—			—			—			(3,750		)
(Income) loss from equity method investments and investments in subsidiaries	(6,457		)	(99		)	364			195			(5,997		)
Other income	5			1									6
	2,248			(98		)	364			195			2,709

(LOSS) INCOME BEFORE INCOME TAXES	(160,703		)	559			(364		)	(195		)	(160,703		)
INCOME TAX BENEFIT	(3,407		)	—			—			—			(3,407		)

NET (LOSS) INCOME	$	(157,296	)	$	559		$	(364	)	$	(195	)	$	(157,296	)



	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		)
(Income) loss from equity method investments and investments in subsidiaries	(136,969		)	2,586			869			154,459			20,945
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



	Nine months ended September 30, 2016
	Parent			Guarantors			Non-Guarantor			Eliminations			Consolidated

Total revenues	$	321,404		$	1,090		$	—		$	—		$	322,494

Costs and expenses:
Lease operating expenses	48,246			543			—			—			48,789
Production taxes	9,410			82			—			—			9,492
Midstream gathering and processing	122,250			226			—			—			122,476
Depreciation, depletion, and amortization	183,411			3									183,414
Impairment of oil and natural gas properties	601,806			—			—			—			601,806
General and administrative	33,230			(291		)	2			—			32,941
Accretion expense	777			—			—			—			777
	999,130			563			2			—			999,695

(LOSS) INCOME FROM OPERATIONS	(677,726		)	527			(2		)	—			(677,201		)

OTHER (INCOME) EXPENSE:
Interest expense	44,891			1			—			—			44,892
Interest income	(822		)	—			—			—			(822		)
Insurance Proceeds	(3,750		)	—			—			—			(3,750		)
Loss (income) from equity method investments and investments in subsidiaries	25,044			(40		)	24,812			(24,240		)	25,576
Other income	5			(8		)	—			—			(3		)
	65,368			(47		)	24,812			(24,240		)	65,893

(LOSS) INCOME BEFORE INCOME TAXES	(743,094		)	574			(24,814		)	24,240			(743,094		)
INCOME TAX BENEFIT	(3,755		)	—			—			—			(3,755		)

NET (LOSS) INCOME	$	(739,339	)	$	574		$	(24,814	)	$	24,240		$	(739,339	)