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.

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 during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

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 the definitions of "large accelerated filer," "accelerated filer", "smaller reporting company" and "emerging growth company" in Rule 12b-2 of the Exchange Act. (Check one):

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).

The number of shares outstanding of the registrant's common stock, par value $0.50, as of August ~~7, 2017~~9, 2018 was ~~15,478,775.~~

	June 30, 2017			December 31, 2016			June 30, 2018			December 31, 2017
	(In thousands)						(In thousands)
ASSETS

Cash and Cash Equivalents	$	35,321		$	65,904		$	158,378		$	61,255
Accounts Receivable:
Oil and gas sales		22,547			19,339			21,518			26,700
Joint interest operations		9,554			3,105			17,771			11,872
Derivative Financial Instruments		5,229			—			—			1,318
Assets Held For Sale								—			198,615
Other Current Assets		2,732			1,824			4,482			2,745
Total current assets		75,383			90,172			202,149			302,505
Property and Equipment:
Oil and gas properties, successful efforts method		3,883,681			3,797,101			2,776,179			2,631,750
Other		19,598			19,590			18,921			18,918
Accumulated depreciation, depletion and amortization		(3,077,800	)		(3,018,029	)		(2,096,410	)		(2,042,739	)
Net property and equipment		825,479			798,662			698,690			607,929
Income Taxes Receivable								19,086			19,086
Other Assets		969			1,040			1,408			899

	$	901,831		$	889,874		$	921,333		$	930,419

LIABILITIES AND STOCKHOLDERS' DEFICIT

Accounts Payable	$	72,455		$	45,311		$	153,387		$	126,034
Accrued Expenses								35,456			42,455
Derivative Financial Instruments		—			6,030			230			—
Accrued Expenses		38,163			40,366
Total current liabilities		110,618			91,707			189,073			168,489
Long-term Debt		1,070,240			1,044,506			1,153,333			1,110,529
Deferred Income Taxes		10,077			9,126			10,726			10,266
Reserve for Future Abandonment Costs		16,203			15,804			10,622			10,407
Total liabilities		1,207,138			1,161,143			1,363,754			1,299,691
Commitments and Contingencies
Stockholders' Deficit:
Common stock — $0.50 par, 75,000,000 shares authorized, 15,478,775 and 13,937,627 shares outstanding at June 30, 2017 and December 31, 2016, respectively		7,739			6,969
Common stock — $0.50 par, 75,000,000 shares authorized, 16,261,017 and 15,427,561 shares outstanding at June 30, 2018 and December 31, 2017, respectively								8,131			7,714
Common stock warrants		3,557			5,672			441			3,557
Additional paid-in capital		543,604			531,924			552,135			546,696
Accumulated deficit		(860,207	)		(815,834	)		(1,003,128	)		(927,239	)
Total stockholders' deficit		(305,307	)		(271,269	)		(442,421	)		(369,272	)

	$	901,831		$	889,874		$	921,333		$	930,419

													Three Months Ended June 30,						Six Months Ended June 30,
	Three Months Ended June 30,						Six Months Ended June 30,						2018			2017			2018			2017
	2017			2016			2017			2016			(In thousands, except per share amounts)
Revenues:	(In thousands, except per share amounts)
Natural gas sales	$	50,437		$	25,727		$	91,377		$	50,874		$	56,265		$	50,437		$	115,808		$	91,377
Oil sales		11,034			14,988			23,895			26,004			5,184			11,034			18,234			23,895
Total oil and gas sales		61,471			40,715			115,272			76,878			61,449			61,471			134,042			115,272

Operating expenses:
Production taxes		1,143			1,327			2,240			2,513			1,112			1,143			2,952			2,240
Gathering and transportation		3,545			4,025			7,673			8,390			4,398			3,545			8,732			7,673
Lease operating		9,433			12,988			19,322			25,948			7,948			9,433			17,721			19,322
Exploration		—			—			—			7,753
Depreciation, depletion and amortization		30,321			36,029			60,226			74,865			26,798			30,321			53,950			60,226
General and administrative		6,559			5,663			12,960			11,238			6,956			6,559			12,972			12,960
Impairment of oil and gas properties		—			1,742			—			24,460
Net loss on sale of oil and gas properties		—			1,647			—			907
Loss on sale of oil and gas properties														6,838			—			35,438			—
Total operating expenses		51,001			63,421			102,421			156,074			54,050			51,001			131,765			102,421

Operating income (loss)		10,470			(22,706	)		12,851			(79,196	)
Operating income														7,399			10,470			2,277			12,851

Other income (expenses):
Gain on extinguishment of debt		—			56,196			—			89,576
Gain from derivative financial instruments		5,295			18			13,155			674
Gain (loss) from derivative financial instruments														(1,638	)		5,295			964			13,155
Other income		65			314			228			595			327			65			393			228
Interest expense		(36,755	)		(28,882	)		(69,655	)		(58,826	)		(40,213	)		(36,755	)		(79,063	)		(69,655	)
Total other income (expenses)		(31,395	)		27,646			(56,272	)		32,019			(41,524	)		(31,395	)		(77,706	)		(56,272	)

Income (loss) before income taxes		(20,925	)		4,940			(43,421	)		(47,177	)
Provision for income taxes		(517	)		(88	)		(952	)		(4,548	)
Net income (loss)	$	(21,442	)	$	4,852		$	(44,373	)	$	(51,725	)
Loss before income taxes														(34,125	)		(20,925	)		(75,429	)		(43,421	)
Benefit from (provision for) income taxes														122			(517	)		(460	)		(952	)
Net loss													$	(34,003	)	$	(21,442	)	$	(75,889	)	$	(44,373	)

Net income (loss) per share – basic and diluted	$	(1.45	)	$	0.41		$	(3.06	)	$	(4.82	)
Net loss per share – basic and diluted													$	(2.22	)	$	(1.45	)	$	(4.99	)	$	(3.06	)

Weighted average shares outstanding – basic and diluted		14,749			11,557			14,488			10,729			15,340			14,749			15,212			14,488

Common
Stock
(Shares)


Common
Stock –
Par Value

Common
Stock
Warrants


Additional
Paid-in
Capital


Accumulated Deficit


Total

(In thousands)

Balance at January 1, 2017

13,938

$
6,969

$
5,672

$
531,924

$
(815,834
)

$
(271,269
)
Stock-based compensation

495

248

—

2,567

—

2,815

Tax withholdings related to  equity awards

(27
)

(13
)

—

(258
)

—

(271
)
Common stock issued for debt conversions

826

412

—

7,377

—

7,789

Common stock warrants
exercised

247

123

(2,115
)

1,994

—

2

Net loss

—

—

—

—

(44,373
)

(44,373
)

Balance at June 30, 2017

15,479

$
7,739

$
3,557

$
543,604

$
(860,207
)

$
(305,307
)

		Common Stock (Shares)		Common Stock – Par Value			Common Stock Warrants			Additional Paid-in Capital			Accumulated Deficit			Total
	(In thousands)

Balance at January 1, 2018		15,428		$	7,714		$	3,557		$	546,696		$	(927,239	)	$	(369,272	)
Stock-based compensation		523			261			—			2,848			—			3,109
Income tax withholdings related to equity awards		(53	)		(26	)		—			(343	)		—			(369	)
Common stock warrants exercised		363			182			(3,116	)		2,934			—			—
Net loss		—			—			—			—			(75,889	)		(75,889	)

Balance at June 30, 2018		16,261		$	8,131		$	441		$	552,135		$	(1,003,128	)	$	(442,421	)

Six Months Ended
June 30,

2017


2016

(In thousands)

Cash Flows from Operating Activities:



Net loss

$
(44,373
)

$
(51,725
)
Adjustments to reconcile net loss to net cash provided by (used for) operating activities:



Deferred income taxes

855

4,519

Net loss on sale of oil and gas properties

—

907

Exploratory lease impairments

—



7,753

Impairment of oil and gas properties

—



24,460

Depreciation, depletion and amortization

60,226



74,865

Gain on derivative financial instruments

(13,155
)


(674
)
Cash settlements of derivative financial instruments

1,896



2,120

Gain on extinguishment of debt

—



(89,576
)
Amortization of debt discount, premium and issuance costs

15,000



2,533

Interest paid in-kind

18,594

—

Stock-based compensation

2,815



2,493

Decrease (increase) in accounts receivable

(9,657
)


331

Increase in other current assets

(908
)


(346
)
Increase (decrease) in accounts payable and accrued expenses

24,222



(8,864
)

Net cash provided by (used for) operating activities

55,515



(31,204
)

Cash Flows From Investing Activities:



Capital expenditures

(85,829
)


(33,654
)
Proceeds from sales of oil and gas properties

—

2,067

Net cash used for investing activities

(85,829
)


(31,587
)

Cash Flows from Financing Activities:



Payments to retire debt

—



(3,397
)
Common stock warrants exercised

2



—

Debt and equity issuance costs

—



(93
)
Tax withholdings related to equity awards

(271
)


(313
)

Net cash used for financing activities

(269
)


(3,803
)

Net decrease in cash and cash equivalents

(30,583
)


(66,594
)
Cash and cash equivalents, beginning of period

65,904



134,006

Cash and cash equivalents, end of period

$
35,321


$
67,412

	Six Months Ended June 30,
	2018			2017
	(In thousands)
Cash Flows from Operating Activities:
Net loss	$	(75,889	)	$	(44,373	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Deferred income taxes		426			855
Loss on sale of oil and gas properties		35,438			—
Depreciation, depletion and amortization		53,950			60,226
Gain on derivative financial instruments		(964	)		(13,155	)
Cash settlements of derivative financial instruments		2,512			1,896
Amortization of debt discount, premium and issuance costs		23,267			15,000
Interest paid in-kind		20,014			18,594
Stock-based compensation		3,109			2,815
Increase in accounts receivable		(717	)		(9,657	)
Decrease (increase) in other current assets		641			(908	)
Increase in accounts payable and accrued expenses		25,211			24,222

Net cash provided by operating activities		86,998			55,515
Cash Flows From Investing Activities:
Capital expenditures		(90,555	)		(85,829	)
Deposits on property acquisitions		(2,139	)		—
Proceeds from sale of oil and gas properties		103,593			—

Net cash provided by (used for) investing activities		10,899			(85,829	)
Cash Flows from Financing Activities:
Borrowings under bank credit facility		49,679			—
Repayments under bank credit facility		(49,679	)		—
Common stock warrants exercised		—			2
Debt issuance costs		(405	)		—
Income taxes related to equity awards		(369	)		(271	)

Net cash used for financing activities		(774	)		(269	)

Net increase (decrease) in cash and cash equivalents		97,123			(30,583	)
Cash and cash equivalents, beginning of period		61,255			65,904
Cash and cash equivalents, end of period	$	158,378		$	35,321

In management's opinion, the accompanying unaudited consolidated financial statements contain all adjustments necessary to present fairly the financial position of Comstock Resources, Inc. and its subsidiaries ~~("Comstock"~~(collectively, "Comstock" or the "Company") as of June 30, ~~2017,~~2018, and the related results of operations and cash flows for the three months and six months ended June 30, ~~2017~~2018 and ~~2016, and cash flows for the six months ended June 30, 2017 and 2016.~~2017. Net loss and comprehensive loss are the same in all periods presented. All adjustments are of a normal recurring nature unless otherwise disclosed. Included in the operating results for the six months ended June 30, 2017 is an adjustment reducing interest expense by $2.9 million recorded in the first quarter of 2017 related to the amortization of the discount on long-term debt to correct the calculation of interest expense under the effective interest method. This amount, which is being accounted for as correction of an accounting error, relates to the period from September 6, 2016 through December 31, 2016. The Company believes the error is immaterial to the consolidated financial statements for the year ended December 31, 2016, the three months ended September 30, 2016 and the three months ended December 31, 2016.

The accompanying unaudited consolidated financial statements have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission. Certain information and disclosures normally included in annual financial statements prepared in accordance with accounting principles generally accepted in the United States have been omitted pursuant to those rules and regulations, although Comstock believes that the disclosures made are adequate to make the information presented not misleading. These unaudited consolidated financial statements should be read in conjunction with the financial statements and notes thereto included in Comstock's Annual Report on Form 10-K for the year ended December 31, ~~2016.~~2017.

The results of operations for the three months and six months ended June 30, ~~2017~~2018 are not necessarily an indication of the results expected for the full year.

These unaudited consolidated financial statements include the accounts of Comstock and its wholly-owned subsidiaries.

On July 29, 2016, the Company effected a one-for-five (1:5) reverse split of its outstanding shares of common stock. All amounts disclosed in these financial statements have been adjusted to give effect to this reverse stock split in all periods.

The Company follows the successful efforts method of accounting for its oil and gas properties. Costs incurred to acquire oil and gas leasehold are capitalized.

~~In January~~On April 27 2018, Comstock completed the sale of its producing Eagle Ford shale oil and gas properties in McMullen, LaSalle, Frio, Atascosa, Wilson, and Karnes counties, Texas for $125.0 million. The sale was effective November 1, 2017 and the ~~Company entered an agreement~~estimated net cash flow from the properties from November 2017 to ~~jointly develop certain acreage~~April 2018 was paid to the buyer at closing. After the sale, Comstock has approximately 8,400 net undeveloped acres that are prospective for Eagle Ford shale development. During the ~~Haynesville shale in Louisiana~~three months and Texas with USG Properties Haynesville, LLC ("USG"). As of June 30, 2017, USG has acquired 6,382 net acres prospective for Haynesville shale development for the joint development program. The Company operates wells drilled on USG's acreage and has the right to acquire a 25% working interest in the acreage by reimbursing USG for the attributable acreage costs of the wells being drilled. Comstock received $80,000 for each well drilled as consideration for the Company's services managing the drilling program in addition to customary operating fees. Comstock and USG plan to continue to acquire additional acreage for the joint development venture.

~~In January 2016, the Company designated certain of its natural gas properties located in South Texas as held for sale and recognized an impairment charge of $20.8 million in the~~ six months ended June 30, ~~2016~~2018, the Company recognized a loss on sale of oil and gas properties of $4.1 million and $32.7 million, respectively, to reduce the carrying value of its assets held for sale to their fair value less costs to sell and to adjust the carrying value of ~~these assets~~the undeveloped acreage retained to their ~~estimated net realizable value.~~fair value of $55.0 million which has been included in proved oil and gas properties. The ~~sale~~fair value of ~~these properties was completed in December 2016.~~

~~In January 2016,~~ the ~~Company exchanged certain~~ oil and gas properties ~~with another operator in~~retained, a ~~non-monetary exchange. Under~~Level 3 measurement, was determined using the ~~exchange,~~discounted cash flow valuation methodology applied by the Company ~~received acreage~~ in ~~DeSoto Parish, Louisiana, prospective~~assessing oil and gas properties for impairment. Key inputs to the ~~Haynesville shale, including four producing wells (3.5 net)~~valuation included average oil prices of $72.03 per barrel, average natural gas prices of $4.31 per thousand cubic feet and discount factors of 20% - 25%. The Company exchanged acreage in Atascosa County, Texas, including seven producing wells (5.3 net) for the Haynesville shale properties. The Company recognized a gain of $0.7 million on this transaction which isAlso included in ~~the~~ loss on sale of oil and gas properties for the three and six months ended June 30, ~~2016. The Company also sold certain other oil and gas properties during the first six months of 2016 for total proceeds of $2.1 million. The Company recognized~~2018 is a loss of ~~$1.6~~$2.7 million ~~on these divestitures.~~ resulting from a final settlement for a property sale completed in 2012.

Results of operations for ~~the~~ properties that were sold ~~or held for sale~~ were as follows:

							Three Months Ended June 30,						Six Months Ended June 30,
	Three Months Ended June 30, 2016			Six Months Ended June 30, 2016			2018			2017			2018			2017
	(In thousands)						(In thousands)
Total oil and gas sales		1,728			3,528		$	4,535		$	11,881		$	17,747		$	25,416
Total operating expenses⁽¹⁾		(1,712	)		(3,399	)		(1,743	)		(12,293	)		(6,134	)		(26,598	)
Operating income	$	16		$	129
Operating income (loss)							$	2,792		$	(412	)	$	11,613		$	(1,182	)

Unproved oil and gas properties are periodically assessed and any impairment in value is charged to exploration expense. The costs of unproved properties which are determined to be productive are transferred to oil and gas properties and amortized on an equivalent unit-of-production basis. The Company ~~recognized an impairment included in exploration expense of $7.8 million in the six months ended June 30, 2016 related to leases that were expiring on certain of its unproved oil and gas properties.~~

~~The Company~~ also assesses the need for an impairment of the capitalized costs for its proved oil and gas properties on a property basis. ~~Accordingly,~~No impairments were recognized to adjust the ~~Company recognized additional impairments~~carrying value of ~~its~~the Company’s proved oil and gas properties ~~of $1.7 million and $3.7 million for~~during the three months and six months ended June 30, ~~2016, respectively, to reduce the carrying value of certain properties to their estimated fair value.~~ 2018 and 2017.

The Company determines the fair values of its oil and gas properties using a discounted cash flow model and proved and ~~risk adjusted~~risk-adjusted probable oil and natural gas reserves. Undrilled acreage can also be valued based on sales transactions in comparable areas. Significant Level 3 assumptions associated with the calculation of discounted future cash flows included in the cash flow model include management's outlook for oil and natural gas prices, production costs, capital expenditures, and future production as well as estimated proved oil and gas reserves and risk-adjusted probable oil and natural gas reserves. Management's oil and natural gas price outlook is developed based on third-party longer-term price forecasts as of each measurement date. The expected future net cash flows are discounted using an appropriate discount rate in determining a property's fair value.

It is reasonably possible that the Company's estimates of undiscounted future net cash flows attributable to its oil and gas properties may change in the future. The primary factors that may affect estimates of future cash flows include future adjustments, both positive and negative, to proved and appropriate risk-adjusted probable oil and gas reserves, results of future drilling activities, future prices for oil and natural gas, and increases or decreases in production and capital costs. As a result of these changes, there may be ~~further~~future impairments in the carrying values of these or other properties.

Accrued expenses at June 30, ~~2017~~2018 and December 31, ~~2016~~2017 consist of the following:

	As of June 30, 2017		As of December 31, 2016		As of June 30, 2018		As of December 31, 2017
	(In thousands)				(In thousands)
Accrued drilling costs	$	8,313	$	7,498	$	6,028	$	5,874
Accrued interest payable		20,938		22,721		20,937		21,277
Accrued transportation costs		2,785		2,227		2,882		3,269
Accrued employee compensation		2,561		6,292		2,561		6,449
Asset retirement obligation – assets held for sale						—		4,557
Accrued ad valorem taxes		1,800		—		1,200		—
Other		1,766		1,628		1,848		1,029
	$	38,163	$	40,366	$	35,456	$	42,455

Comstock's asset retirement obligations relate to future plugging and abandonment expenses on its oil and gas properties and related facilities disposal. The following table summarizes the changes in Comstock's total estimated liability for such obligations during the six months ended June 30, ~~2017~~2018 and ~~2016:~~2017:

	Six Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2018			2017
	(In thousands)						(In thousands)
Future abandonment costs — beginning of period	$	15,804		$	20,093		$	10,407		$	15,804
Accretion expense		431			496			280			431
New wells placed on production		4			2			4			4
Assets held for sale		—			(3,442	)
Liabilities settled and assets disposed of		(36	)		(1,177	)		(69	)		(36	)
Future abandonment costs — end of period	$	16,203		$	15,972		$	10,622		$	16,203

Comstock periodically uses swaps, floors and collars to hedge oil and natural gas prices and interest rates. Swaps are settled monthly based on differences between the prices specified in the instruments and the settlement prices of futures contracts. Generally, when the applicable settlement price is less than the price specified in the contract, Comstock receives a settlement from the counterparty based on the difference multiplied by the volume or amounts hedged. Similarly, when the applicable settlement price exceeds the price specified in the contract, Comstock pays the counterparty based on the difference. Comstock generally receives a settlement from the counterparty for floors when the applicable settlement price is less than the price specified in the contract, which is based on the difference multiplied by the volumes hedged. For collars, generally Comstock receives a settlement from the counterparty when the settlement price is below the floor and pays a settlement to the counterparty when the settlement price exceeds the cap. No settlement occurs when the settlement price falls between the floor and cap. All of the Company's derivative financial instruments are used for risk management purposes and, by policy, none are held for trading or speculative purposes. Comstock minimizes credit risk to counterparties of its derivative financial instruments through formal credit policies, monitoring procedures, and diversification. The Company is not required to provide any credit support to its counterparties other than cross collateralization with the assets securing its bank credit facility. None of the Company's derivative

financial instruments involve payment or receipt of premiums. The Company classifies the fair value amounts of derivative financial instruments as net current or noncurrent assets or liabilities, whichever the case may be, by commodity and counterparty.

All of Comstock's natural gas derivative financial instruments are tied to the Henry Hub-NYMEX price index. The Company had the following outstanding derivative financial instruments used for ~~oil and~~ natural gas price risk management at June 30, ~~2017:~~2018:

~~Commodity and Derivative Type~~


	Future Production Period
	Three Months Ending September 30, 2018		Three Months Ending December 31, 2018		Six Months Ending December 31, 2018		Year Ending December 31, 2019		Total
Swap contracts:
Volume (MMbtu)		5,400,000		5,400,000		10,800,000		4,200,000		15,000,000
Price per MMbtu	$	3.00	$	3.00	$	3.00	$	3.00	$	3.00
Collar contracts:
Volume (MMbtu)		2,700,000		2,700,000		5,400,000		5,400,000		10,800,000
Price per MMbtu
Ceiling	$	3.30	$	3.30	$	3.30	$	3.30	$	3.30
Floor	$	2.50	$	2.50	$	2.50	$	2.50	$	2.50

Volume (MMbtu)		2,700,000		2,700,000		5,400,000		5,400,000		10,800,000
Price per MMbtu
Ceiling	$	3.50	$	3.50	$	3.50	$	3.50	$	3.50
Floor	$	2.50	$	2.50	$	2.50	$	2.50	$	2.50

Weighted-Average
Contract Price

Contract Volume
(MMBtu)

~~Contract Period~~

~~Natural Gas Swap Agreements~~

~~$3.38 per MMBtu~~

~~20,745,000~~

~~July 2017 – March 2018~~

None of the Company's derivative contracts were designated as cash flow hedges. The aggregate fair value of the Company's derivative instruments reported in the accompanying consolidated balance sheets by type, including the classification between assets and liabilities, consists of the following:

Type	Consolidated Balance Sheet Location	Fair Value		Gross Amounts Offset in the Consolidated Balance Sheet			Net Fair Value Presented in the Consolidated Balance Sheet
				(in thousands)
Fair Value of Derivative Instruments as of June 30, 2018
Asset Derivatives:
Natural gas price derivatives	Derivative Financial Instruments – current	$	79	$	(79	)	$	—
Liability Derivatives:
Natural gas price derivatives	Derivative Financial Instruments – current	$	309	$	(79	)	$	230

Fair Value of Derivative Instruments as of December 31, 2017
Asset Derivatives:
Natural gas price derivatives	Derivative Financial Instruments – current	$	1,318	$	—		$	1,318

The Company recognized cash settlements and changes in the fair value of its derivative financial instruments as a single component of other income (expenses). ~~The Company recognized gains of $5.3 million~~Gains and ~~$18 thousand in the three months ended June 30, 2017 and 2016, respectively, and $13.2 million and $0.7 million in the six months ended June 30, 2017 and 2016, respectively,~~losses related to the change in the fair value recognized on the Company's derivative contracts recognized in the consolidated statement of ~~its natural gas swap agreements.~~operations were as follows:

Comstock accounts for employee stock-based compensation under the fair value method. Compensation cost is measured at the grant date based on the fair value of the award and is recognized over the award vesting period. The Company recognized $1.5 million ~~and $1.2 million~~ of stock-based compensation expense within general and administrative expenses related to awards of restricted stock and

performance stock units ("PSUs") to its employees and directors in each of the three months ended June 30, ~~2017~~2018 and ~~2016,~~2017, respectively. For the six months ended June 30, ~~2017~~2018 and ~~2016,~~2017, the Company recognized ~~$2.8~~$3.1 million and ~~$2.5~~$2.8 million, respectively, of stock-based compensation expense within general and administrative expenses.

During the six months ended June 30, ~~2017,~~2018, the Company granted ~~500,002~~445,801 shares of restricted stock with a grant date fair value of ~~$5.6~~$3.8 million, or ~~$11.11~~$8.46 per share, to its ~~employees and directors.~~employees. The fair value of each restricted share on the date of grant was equal to its market price. As of June 30, ~~2017,~~2018, Comstock had ~~688,998~~803,955 shares of unvested restricted stock outstanding at a weighted average grant date fair value of ~~$11.50~~$8.43 per share. Total unrecognized compensation cost related to unvested restricted stock grants of ~~$6.5~~$5.7 million as of June 30, ~~2017~~2018 is expected to be recognized over a period of ~~2.0~~2.2 years.

During the six months ended June 30, ~~2017,~~2018, the Company granted ~~241,814~~360,801 PSUs with a grant date fair value of ~~$4.4~~$4.5 million, or ~~$18.17~~$12.52 per unit, to its employees. As of June 30, ~~2017,~~2018, Comstock had ~~313,248~~514,336 PSUs outstanding at a weighted average grant date fair value of ~~$17.12~~$13.83 per unit. The number of shares of common stock to be issued related to the PSUs is based on the Company's stock price performance as compared to its peers which could result in the issuance of anywhere from zero to ~~626,496~~1,028,672 shares of common stock. Total unrecognized compensation cost related to these grants of ~~$4.6~~$6.2 million as of June 30, ~~2017~~2018 is expected to be recognized over a period of ~~2.4~~2.3 years.

On January 1, 2018, the Company adopted Financial Accounting Standards Board ("FASB") Accounting Standards Update ("ASU") 2014-09, Revenue from Contracts with Customers (Topic 606) ("ASU 2014-09"). Comstock adopted this standard using the modified retrospective method of adoption, and it applied the ASU only to contracts that were not completed as of January 1, 2018. Upon adoption, there were no adjustments to the opening balance of equity.

Comstock produces oil and natural gas and reports revenues separately for each of these two primary products in its statements of operations. Revenues are recognized upon the transfer of produced volumes to the Company's customers, who take control of the volumes and receive all the benefits of ownership upon delivery at designated sales points. Payment is reasonably assured upon delivery of production. All sales are subject to contracts that have commercial substance, contain specific pricing terms, and define the enforceable rights and obligations of both parties. These contracts typically provide for cash settlement within 25 days following each production month and are cancellable upon 30 days' notice by either party. Prices for sales of oil and natural gas are generally based upon terms that are common in the oil and gas industry, including index or spot prices, location and quality differentials, as well as market supply and demand conditions. As a result, prices for oil and natural gas routinely fluctuate based on changes in these factors. Each unit of production (barrel of crude oil and thousand cubic feet of natural gas) represents a separate performance obligation under the Company's contracts since each unit has economic benefit on its own and each is priced separately according to the terms of the contracts.

Comstock has elected to exclude all taxes from the measurement of transaction prices, and its revenues are reported net of royalties and exclude revenue interests owned by others because the Company acts as an agent when selling crude oil and natural gas, on behalf of royalty owners and working interest owners. Revenue is recorded in the month of production based on an estimate of the Company's share of volumes produced and prices realized. The Company recognizes any differences between estimates and actual amounts received in the month when payment is received. Historically differences between estimated revenues and actual revenue received have not been significant. The amount of oil or natural gas sold may differ from the amount to which the Company is entitled based on its revenue interests in the properties. The Company did not have any significant imbalance positions at December 31, 2017 or June 30, 2018. Sales of oil and natural gas generally occur at or near the wellhead. When sales of oil and gas occur at locations other than the wellhead, the Company accounts for costs incurred to transport the production to the delivery point as gathering and transportation expenses. The Company has recognized accounts receivable of $21.5 million as of June 30, 2018 from customers for contracts where performance obligations have been satisfied and an unconditional right to consideration exists.

Deferred income taxes are provided to reflect the future tax consequences or benefits of differences between the tax basis of assets and liabilities and their reported amounts in the financial statements using enacted tax rates. The deferred tax provision in the first three months and six months ofended June 30, 2018 and 2017 related to adjustments to the valuation allowances on federal and state net operating loss carryforwards. The deferred income tax provision for the first three months and six months of 2016 related to an increase in the Company's deferred income tax liability resulting from certain state tax law changes enacted during the period. In recording deferred income tax assets, the Company considers whether it is more likely than not that some portion or all of its deferred income tax assets will be realized in the future. The ultimate realization of deferred income tax assets is dependent upon the generation of future taxable income during the periods in which those deferred income tax assets would be deductible. The Company believes that, after considering all the available objective evidence, historical and prospective, with greater weight given to historical evidence, management is not able to determine that it is more likely than not that all of its deferred tax assets will be realized. As a result, the Company established valuation allowances for its deferred tax assets and U.S. federal and state net operating loss carryforwards that are not expected to be utilized due to the uncertainty of generating taxable income prior to the expiration of the carryforward periods.

The following is an analysis of consolidated income tax ~~expense:~~provision (benefit):

		Three Months Ended June 30,				Six Months Ended June 30,				Three Months Ended June 30,					Six Months Ended June 30,
		2017		2016		2017		2016		2018			2017		2018			2017
		(In thousands)								(In thousands)
Current - State	Current - State	$	21	$	15	$	97	$	29	$	24		$	21	$	34		$	97
- Federal	- Federal		—		—		—		—		—			—		—			—

Deferred - State	Deferred - State		496		73		855		4,519		(597	)		496		(1,051	)		855
- Federal	- Federal		—		—		—		—		451			—		1,477			—
		$	517	$	88	$	952	$	4,548	$	(122	)	$	517	$	460		$	952

The difference between the Company's effective tax rate and the ~~35%~~21% federal statutory rate in effect in 2018 and the 35% rate in effect in 2017 is caused by valuation allowances on deferred taxes and state taxes. The impact of these items varies based upon the Company's projected full year loss and the jurisdictions that are expected to generate the projected losses.

The difference between the federal statutory rate ~~of 35%~~ and the effective tax rate ~~on the income (loss) before income taxes~~ is due to the following:

The Tax Cuts and Jobs Act, which was enacted on December 22, 2017, reduced the corporate income tax rate effective January 1, 2018 from 35% to 21%. Among the other significant tax law changes that potentially affect the Company are the elimination of the corporate alternative minimum tax ("AMT"), changes that require operating losses incurred in 2018 and beyond be carried forward indefinitely with no carryback up to 80% of taxable income in a given year, and limitations on the deduction for interest expense incurred in 2018 or later for amounts in excess of 30% of its adjusted taxable income (defined as taxable income before interest and net operating losses). For tax years beginning before January 1, 2022, the adjusted taxable income for these purposes is also adjusted to exclude the impact of depreciation, depletion and amortization. The Tax Cuts and Jobs Act preserved deductibility of intangible drilling costs for federal income tax purposes, which allows the Company to deduct a portion of drilling costs in the year incurred and minimizes current taxes payable in periods of taxable income. At June 30, 2018, the Company has not completed its accounting for the tax effects of enactment of the Tax Cuts and Jobs Act; however, it has made reasonable estimates of the effects on its existing deferred tax balances. The Company has remeasured certain deferred federal tax assets and liabilities based on the rates at which they are expected to reverse in the future, which is generally 21%. The provisional amount recognized at December 31, 2017 related to the remeasurement of its deferred federal tax balance was $140.4 million, which was subject to a valuation allowance. The Tax Cuts and Jobs Act also repealed the AMT for tax years beginning on or after January 1, 2018 and provides that existing AMT credit carryforwards can be utilized to offset federal taxes for any taxable year. In addition, 50% of any unused AMT credit carryforwards can be refunded during tax years 2018 through 2020. The Company reclassified $19.1 million to a non-current receivable at December 31, 2017 representing the amount of AMT that is now refundable through 2021. The Company is still analyzing certain aspects of the Tax Cuts and Jobs Act, and refining its calculations, which could potentially affect the measurement of those balances or potentially give rise to new deferred tax amounts. Comstock's estimates may also be affected in the future as the Company gains a more thorough understanding of the Tax Cuts and Jobs Act, and how the individual states are implementing this new law.

The Company's federal income tax returns for the years subsequent to December 31, 2012, remain subject to examination. The Company's income tax returns in major state income tax jurisdictions remain subject to examination for various periods subsequent to December 31, 2011. The Company currently believes that all other significant filing positions are highly certain and that all of its other significant income tax positions and deductions would be sustained under audit or the final resolution would not have a material effect on the consolidated financial statements. Therefore, the Company has not established any significant reserves for uncertain tax positions.

Future use of the Company's federal and state net operating loss carryforwards may be limited in the event that a cumulative change in the ownership of Comstock's common stock by more than 50% occurs within a three-year period. Such a change in ownership could result in a substantial portion of the Company's net operating loss carryforwards being eliminated or becoming restricted. It is highly likely that a change in ownership ~~that would result from the~~due to future conversion of the Company's convertible notes would result in limits on the future use of its net operating loss carryforwards. In addition, the Company expects that the transaction discussed in Footnote (5) – Jones Contribution and Refinancing Plans involving the contribution of oil and gas properties for common stock will result in a change of control which will result in limits on the future use of its net operating loss carryforwards.

The Company's federal income tax returns for the years subsequent to December 31, 2013 remain subject to examination. The Company's income tax returns in major state income tax jurisdictions remain subject to examination for various periods subsequent to December 31, 2012. The Company currently believes that all other significant filing positions are highly certain and that all of its other significant income tax positions and deductions would be sustained under audit or the final resolution would not have a material effect on the consolidated financial statements. Therefore, the Company has not established any significant reserves for uncertain tax positions.

The Company holds or has held certain ~~items~~financial assets and liabilities that are required to be measured at fair value. These include cash and cash equivalents held in bank accounts and derivative financial instruments in the form of oil and natural gas price swap agreements. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. A three-level hierarchy is followed for disclosure to show the extent and level of judgment used to estimate fair value measurements:

Level 1 — Inputs used to measure fair value are unadjusted quoted prices that are available in active markets for the identical assets or liabilities as of the reporting date.

Level 2 — Inputs used to measure fair value, other than quoted prices included in Level 1, are either directly or indirectly observable as of the reporting date through correlation with market data, including quoted prices for similar assets and liabilities in active markets and quoted prices in markets that are not active. Level 2 also includes assets and liabilities that are valued using models or other pricing methodologies that do not require significant judgment since the input assumptions used in the models, such as interest rates and volatility factors, are corroborated by readily observable data from actively quoted markets for substantially the full term of the financial instrument.

Level 3 — Inputs used to measure fair value are unobservable inputs that are supported by little or no market activity and reflect the use of significant management judgment. These values are generally determined using pricing models for which the assumptions utilize management's estimates of market participant assumptions.

The Company's ~~valuation of~~ cash and cash equivalents valuation is abased on Level 1 ~~measurement.~~measurements. The Company's oil and natural gas price swap agreements ~~are~~and its natural gas price collars were not traded on a public ~~exchange. Their~~exchange, and their value is determined utilizing a discounted cash flow model based on inputs that are readily available in public markets and, accordingly, the valuation of these swap agreements, is categorized as a Level 2 measurement.

~~The following table summarizes~~ There are no financial assets or liabilities accounted for at fair value as of June 30, ~~2017:~~2018 that are a Level 3 measurement.

At June 30, 2018 the Company had a liability of $0.2 million recorded for the fair value of its natural gas swaps and collars. At December 31, 2017, the Company had assets recorded for the fair value of its natural gas price swap agreements of $1.3 million. There were no offsetting swap positions in 2018 or 2017. The change in fair value of these natural gas swaps and collars was recognized as a gain or loss and included as a component of other income (expense).

As of June 30, ~~2017,~~2018, the Company's other financial instruments, comprised solely of its fixed rate debt, had a carrying value of ~~$1.1~~$1.2 billion and a fair value of ~~$1.1~~$1.2 billion. The fair market value of the Company's fixed rate debt was based on quoted prices as of June 30, ~~2017,~~2018, a Level 2 measurement.

Basic earnings per share is determined without the effect of any outstanding potentially dilutive securities and diluted earnings per share is determined with the effect of any outstanding securities that are potentially dilutive. Unvested share-based payment awards containing nonforfeitable rights to dividends are considered to be participating securities and included in the computation of basic and diluted earnings per share pursuant to the two-class method. PSUs represent the right to receive a number of shares of the Company's common stock that may range from zero to up to two times the number of PSUs granted on the award date based on the achievement of certain performance measures during a performance period. The number of potentially dilutive shares related to PSUs is based on the number of shares, if any, which would be issuable at the end of the respective period, assuming that date was the end of the contingency period. ~~Common~~The treasury stock method is used to measure the dilutive effect of PSUs. Unexercised common stock warrants represent the right to convert the warrants into common stock at an exercise price of $0.01 per

share. The treasury stock method is used to measure the dilutive effect of ~~outstanding PSUs and~~unexercised common stock warrants. The shares that would be issuable upon exercise of the conversion rights ~~contained~~contains in the Company's convertible debt for each period are based on the if-converted method for computing potentially dilutive shares of common stock that could be issued upon conversion. None of the Company's participating securities participate in losses and as such are excluded from the computation of basic earnings per share during periods of net losses.

Basic and diluted loss per share for the three months and six months ended June 30, ~~2017~~2018 and ~~2016~~2017 were determined as follows:

Basic and diluted per share amounts are the same for the three months and six months ended June 30, 2018 and 2017 due to the net loss reported during each of those periods.

At June 30, ~~2017~~2018 and December 31, ~~2016, 688,998~~2017, 803,955 and ~~354,986~~619,867 shares of restricted stock, respectively, are included in common stock outstanding as such shares have a nonforfeitable right to participate in any dividends that might be declared and have the right to vote on matters submitted to the Company's stockholders.

Weighted average shares of unvested restricted stock outstanding during the three months and six months ended June 30, 2018 and 2017 ~~and 2016~~which were excluded from the computation of the loss per share were as follows:

~~For the three months ended June 30, 2017 and 2016, all~~All stock options, unvested PSUs, warrants exercisable into common stock ~~warrants~~ and contingently issuable shares related to the convertible debt that were anti-dilutive to earnings and excluded from weighted average shares used in the computation of earnings per share ~~in all periods presented~~ due to the net loss in ~~those periods. Options to purchase common stock, warrants exercisable into common stock, PSUs that~~each period were ~~outstanding and contingently issuable shares related to the convertible debt that were excluded as anti-dilutive from the determination of diluted earnings per share are~~ as follows:

Three Months Ended
June 30,


Six Months Ended
June 30,

2017


2016


2017


2016

(In thousands except per share/unit data)

Weighted average stock options

—

12



—

12

Weighted average exercise price per share

$
—

$
166.10

$
—

$
166.10

Weighted average warrants for common stock

433

—

511

—

Weighted average exercise price per share

$
0.01

$
—

$
0.01

$
—

Weighted average PSUs

313

135

273

138

Weighted average grant date fair value per unit

$
17.12

$
22.10

$
17.12

$
22.10

Weighted average contingently convertible shares

36,181

—

36,331

—

Weighted average conversion price per share

$
12.32

$
—

$
12.32

$
—

Supplementary Information With Respect to the Consolidated Statements of Cash Flows

For the purpose of the consolidated statements of cash flows, the Company considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents.

Cash payments made for interest and income taxes for the six months ended June 30, ~~2017~~2018 and ~~2016,~~2017, respectively, were as follows:

	Six Months Ended June 30				Six Months Ended June 30,
	2017		2016		2018		2017
	(In thousands)				(In thousands)
Interest payments	$	37,846	$	58,476	$	36,122	$	37,846
Income tax payments	$	3	$	—	$	2	$	3

Interest ~~of $18.6 million~~paid in-kind related to the Company's convertible notes was ~~paid in-kind~~$20.0 million and $18.6 million during the six months ended June 30, ~~2017.~~2018 and 2017, respectively.

~~In May 2014,~~On January 1, 2018, the ~~Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU")~~Company adopted ASU 2014-09,~~Revenue from Contracts with Customers (Topic 606)~~ ~~("ASU 2014-09"),~~ which supersedes nearly all existing revenue recognition guidance under existing generally accepted accounting principles. This new standard is based upon the principal that revenue is recognized to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from ~~customer contracts. ASU 2014-09 is effective for annual and interim periods beginning after December 15, 2017. Early adoption is permitted beginning~~contracts with periods after December 15, 2016 and entities have the option of using either a full retrospective or modified approach to adopt ASU 2014-09. The Company is currently reviewing its primary oil and natural gas marketing agreements in order to assess the impact of adoption. At this time, adoptingcustomers. Comstock adopted this standard isusing the modified retrospective method of adoption and it applied the ASU only to contracts that were not ~~expected~~completed as of January 1, 2018. Upon adoption, there were no adjustments to the opening balance of equity and the Company does not expect the standard to have a ~~material impact~~significant effect on the Company's financial statements because recognition of revenue is not expected to materially change under the new standard, since most of the Company's revenue will continue to be recognized as production is delivered. However, the Company is still evaluating the ultimate impact of this accounting standard on its ~~consolidated~~ results of operations, liquidity or financial position, cash flows and financial disclosures. This evaluation will continue throughout 2017, and the Company is currently planning to adopt this new standard in the first quarter of 2018. The Company has not yet determined which method of adoption it will apply for this new standard.position.

In February 2016, the FASB issued ASU No. 2016-02, Leases ("ASU 2016-02"). ASU 2016-02 requires lessees to include most leases on their balance sheets, but recognize lease costs in their financial statements in a manner similar to accounting for leases prior to ASC 2016-02. ASU 2016-02 is effective for annual periods ending after December 15, 2018 and interim ~~period~~periods thereafter. Early adoption is permitted. The Company is currently evaluating the new guidance and anticipates that certain operating leases that it has in place will be reflected as an asset and a liability in its consolidated balance sheet. The Company has not yet determined which method of adoption it will apply for this new standard.

	(In thousands)				(In thousands)

10% Senior Secured Toggle Notes due 2020:				10% Senior Secured Toggle Notes due 2020:
Principal	$	697,195		Principal	$	697,195
Discount, net of amortization		(10,673	)	Discount, net of amortization		(7,070	)
7¾% Convertible Second Lien PIK Notes due 2019:
7¾% Convertible Second Lien PIK Notes due 2019⁽¹⁾:				7¾% Convertible Second Lien PIK Notes due 2019⁽¹⁾:
Principal		273,832		Principal		295,465
Accrued interest payable in kind		5,276		Accrued interest payable in kind		5,693
Discount, net of amortization		(50,999	)	Discount, net of amortization		(24,821	)
9½% Convertible Second Lien PIK Notes due 2020:				9½% Convertible Second Lien PIK Notes due 2020:
Principal		178,580		Principal		195,948
Accrued interest payable in kind		728		Accrued interest payable in kind		801
Discount, net of amortization		(35,963	)	Discount, net of amortization		(27,077	)
10% Senior Notes due 2020:				10% Senior Notes due 2020:
Principal		2,805		Principal		2,805
7¾% Senior Notes due 2019:
7¾% Senior Notes due 2019⁽¹⁾:				7¾% Senior Notes due 2019⁽¹⁾:
Principal		17,959		Principal		17,959
Premium, net of amortization		92		Premium, net of amortization		39
9½% Senior Notes due 2020:				9½% Senior Notes due 2020:
Principal		4,860		Principal		4,860
Discount, net of amortization		(84	)	Discount, net of amortization		(56	)
Debt issuance costs, net of amortization		(13,368	)	Debt issuance costs, net of amortization		(8,408	)
	$	1,070,240			$	1,153,333

(1) Classified as long-term debt as the Company intends to refinance this debt with new long-term debt - See Footnote 5-Jones Contribution and Financing Plans.				(1) Classified as long-term debt as the Company intends to refinance this debt with new long-term debt - See Footnote 5-Jones Contribution and Financing Plans.

Interest on the 10% Senior Secured Toggle Notes and 10% Senior Notes due 2020 is payable on March 15 and September 15 and the notes mature on March 15, 2020. The Company has the option to pay up to $75.0 million of accrued interest on the Senior Secured Toggle Notes by issuing additional notes. To the extent that interest is paid in kind, the interest rate increases to 12¼% only for that interest payment and would result in up to an additional $91.9 million of notes outstanding.

Interest on the 7¾% Convertible Second Lien PIK Notes and the 7¾% Senior Notes due 2019 is payable on April 1 and October 1 and these notes mature on April 1, 2019. Interest on the 9½% Convertible Second Lien PIK Notes and the 9½% Senior Notes due 2020 is payable on June 15 and December 15 and these notes mature on June 15, 2020. Interest on the convertible notes is only payable in kind. Each series of the convertible notes is convertible, at the option of the holder, into 81.2 shares of the Company's common stock for each $1,000 of principal amount of notes. The convertible notes will mandatorily convert into shares of common stock following a 15 consecutive trading day period during which the daily volume weighted average price of the Company's common stock is equal to or greater than $12.32 per share. The mandatory conversion provisions of the convertible notes have been temporarily suspended pending the completion of the Jones Contribution and the tender offer. $9.9 million of principal amount of the convertible notes plus related accrued interest ~~thereon~~ were converted into 826,327 shares of common stock during the six months ended June 30, 2017.

During the six months ended June 30, 2016, the Company retired $87.5 million in principal amount of the 2019 Notes and $19.8 million of the 2020 Notes in exchange in the aggregate for the issuance of 2,748,403 shares of common stock and $3.5 million in cash. A gain of $89.6 million was recognized on the exchanges and purchases of the 2019 Notes and the 2020 Notes during the six months ended June 30, 2016. The gain is included in the net gain on extinguishment of debt for the difference between the market value of the stock on the closing date of the exchange and the net carrying value of the debt and the related net premium and net debt issuance costs.

Comstock has a $50.0 million revolving credit facility with Bank of Montreal and Bank of America, N.A. that matures on March 4, 2019. As of June 30, ~~2017, the Company did not have any~~2018, there were no borrowings outstanding under the revolving credit facility. Indebtedness under the revolving credit facility is guaranteed by all of the Company's subsidiaries and is secured by substantially all of Comstock's and its subsidiaries' assets. Borrowings under the revolving credit facility bear interest, at Comstock's option, at either (1) LIBOR plus 2.5% or (2) the base rate (which is the higher of the administrative agent's prime rate, the federal funds rate plus 0.5% or 30 day LIBOR plus 1.0%) plus 1.5%. A commitment fee of 0.5% per annum is payable quarterly on the unused credit line. The revolving credit facility contains covenants that, among other things, restrict the payment of cash dividends and repurchases of common stock, limit the amount of additional debt that Comstock may incur and limit the Company's ability to make certain loans, investments and divestitures. The only financial covenants are the maintenance of a current ratio, including availability under the revolving credit facility, of at least 1.0 to 1.0 and the maintenance of an asset coverage ratio of proved developed reserves to amounts outstanding under the ~~revolving~~ credit facility of at least 2.5 to 1.0. The Company was in compliance with these covenants as of June 30, ~~2017.~~2018.

All of the Company's subsidiaries guarantee the bank credit facility, the 10% Senior Secured Toggle Notes, the 7¾% Convertible Second Lien PIK Notes, the 9½% Convertible Second Lien PIK Notes, and the other outstanding senior notes. The bank credit facility, the 10% Senior Secured Toggle Notes and the convertible notes are secured by liens on substantially all of the assets of the Company and its subsidiaries. The allocation of proceeds related to the liens on the Company's assets are governed by intercreditor agreements granting priority to the bank credit facility. Proceeds from liens on the convertible notes are also subject to the priority of the 10% Senior Secured Toggle Notes.

At June 30, ~~2017~~2018, the Company had warrants outstanding to purchase ~~415,087~~51,449 shares of common stock at an exercise price of $0.01 per share. Warrants for 363,638 and 246,793 shares of common stock were exercised during the six months ended June 30, 2018 and 2017, respectively.

From time to time, Comstock is involved in certain litigation that arises in the normal course of its operations. The Company records a loss contingency for these matters when it is probable that a liability has been incurred and the amount of the loss can be reasonably estimated. The Company does not believe the resolution of any of these matters will have a material effect on the Company's financial position or results of operations.

The Company has entered into natural gas transportation and treating agreements through July 2019. Maximum commitments under these transportation agreements as of June 30, ~~2017~~2018 totaled ~~$3.3~~$1.3 million. As of June 30, ~~2017,~~2018, the Company had commitments for contracted drilling services through September 2019 of $19.3 million.

On May 9, 2018, Arkoma Drilling, L.P. ("Arkoma") and Williston Drilling, L.P. ("Williston") entered into a Contribution Agreement with the Company to contribute certain oil and gas properties in North Dakota and Montana (the "Bakken Shale Properties") with an estimated fair value of approximately $620.0 million in exchange for approximately 88.6 million newly issued shares of the Company's common stock (the "Jones Contribution"). The effective date of the acquisition of the properties is April 1, 2018. Comstock estimated that the properties have proved reserves of 22.8 million barrels of oil and 49.3 Bcf of natural gas on the effective date. Upon completion of this transaction, Arkoma and Williston will collectively own approximately 84.5% of the Company's pro forma outstanding shares. The transaction is subject to a number of closing conditions, including the approval of the

issuance of the common stock by the Company's stockholders at the Company's Annual Meeting of Stockholders on August 10, 2018 and satisfaction of ~~$9.9~~certain other closing conditions.

In connection with the Jones Contribution, the Company commenced a tender offer on July 13, 2018 to repurchase all of its outstanding debt. The Company expects to close the tender offer concurrent with the closing of the Jones Contribution and refinance all of the Company's debt using funds from the sale of 9¾% Senior Notes due 2026 and borrowings under a new Bank Credit Facility with an initial borrowing base of $700.0 million.

In connection with the refinancing plan, the Company sold $850.0 million of 9¾% Senior Notes due 2026 at 95.988% of the principal amount on August 3, 2018. Interest on the new senior notes is payable on February 15 and August 15. Proceeds from the offering are being held in escrow pending the closing of the Jones Contribution which is expected to occur on August 14, 2018.

On July 31, 2018 the Company acquired oil and gas properties in North Louisiana for $37.0 million. These properties, consist of approximately 21,000 gross acres (9,900 net) primarily in Caddo and DeSoto Parishes in Louisiana and include 120 (26.2 net) producing natural gas wells, 49 (14.7 net) of which produce from the Haynesville shale. All of the acreage acquired is held by production. Comstock has identified 112 (31.0 net) potential drilling locations on this acreage of which 21 (17.9 net) would be operated by Comstock.

ITEM 2: MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

This report contains forward-looking statements that involve risks and uncertainties that are made pursuant to the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. Actual results may differ materially from those anticipated in our forward-looking statements due to many factors. The following discussion should be read in conjunction with the consolidated financial statements and notes thereto included in this report and in our annual report filed on Form 10-K for the year ended December 31, ~~2016.~~2017.

	Three Months Ended June 30,				Six Months Ended June 30,				Three Months Ended June 30,				Six Months Ended June 30,
	2017		2016		2017		2016		2018		2017		2018		2017
	(In thousands, except per unit amounts)								(In thousands, except per unit amounts)
Net Production Data:
Natural gas (Mmcf)		17,321		13,519		31,320		27,344		21,718		17,321		43,364		31,320
Oil (Mbbls)		243		355		508		772		90		243		280		508
Natural gas equivalent (Mmcfe)		18,781		15,649		34,368		31,974		22,258		18,781		45,044		34,368
Revenues:
Natural gas sales	$	50,437	$	25,727	$	91,377	$	50,874	$	56,265	$	50,437	$	115,808	$	91,377
Oil sales		11,034		14,988		23,895		26,004		5,184		11,034		18,234		23,895
Total oil and gas sales	$	61,471	$	40,715	$	115,272	$	76,878	$	61,449	$	61,471	$	134,042	$	115,272
Expenses:
Production taxes	$	1,143	$	1,327	$	2,240	$	2,513	$	1,112	$	1,143	$	2,952	$	2,240
Gathering and transportation		3,545		4,025		7,673		8,390		4,398		3,545		8,732		7,673
Lease operating⁽¹⁾		9,433		12,988		19,322		25,948		7,948		9,433		17,721		19,322
Exploration expense		—		—		—		7,753
Depreciation, depletion and amortization		30,321		36,029		60,226		74,865		26,798		30,321		53,950		60,226
Average Sales Price:
Natural gas (per Mcf)	$	2.91	$	1.90	$	2.92	$	1.86	$	2.59	$	2.91	$	2.67	$	2.92
Oil (per Bbl)	$	45.34	$	42.21	$	47.04	$	33.69	$	57.56	$	45.34	$	65.12	$	47.04
Average equivalent (Mcfe)	$	3.27	$	2.60	$	3.35	$	2.40	$	2.76	$	3.27	$	2.98	$	3.35
Expenses ($ per Mcfe):
Production taxes	$	0.06	$	0.08	$	0.07	$	0.08	$	0.05	$	0.06	$	0.07	$	0.07
Gathering and transportation	$	0.19	$	0.26	$	0.22	$	0.26	$	0.20	$	0.19	$	0.19	$	0.22
Lease operating⁽¹⁾	$	0.50	$	0.83	$	0.56	$	0.81	$	0.35	$	0.50	$	0.39	$	0.56
Depreciation, depletion and amortization⁽²⁾	$	1.60	$	2.28	$	1.74	$	2.32	$	1.19	$	1.60	$	1.19	$	1.74

Our oil and natural gas sales ~~grew 51%~~ in the second quarter of ~~2017~~2018 of $61.4 million were comparable to our oil and natural gas sales of $61.5 ~~million from $40.7~~ million in the second quarter of ~~2016, primarily due to the increase in our natural gas production driven by our Haynesville shale drilling program and higher oil and natural gas prices.~~2017. Natural gas sales in the second quarter increased ~~96%~~12% to ~~$50.4~~$56.3 million due to the higher production which was partially offset by lower realized natural gas ~~prices and production growth.~~prices. Our natural gas production increased by ~~28%~~25% and our realized natural gas price ~~increased~~decreased by ~~53%~~11% as compared to the second quarter of ~~2016.~~2017. Oil sales in the second quarter of ~~2017~~2018 decreased by ~~26%~~53% to ~~$11.0~~$5.2 million from the second quarter of

~~2016~~ 2017 due to a ~~32%~~63% decrease in our oil production ~~which was offset in part by a 7% increase in oil prices. The decline in oil production is attributable to~~resulting from the ~~lack~~sale on April 27, 2018 of ~~drilling activity in~~ our producing Eagle Ford shale properties in South Texas.

In the first six months of ~~2017,~~2018, our oil and natural gas sales increased by ~~$38.4~~$18.7 million ~~(50%~~(16%) to ~~$115.3~~$134.0 million from ~~$76.9~~$115.3 million in the first six months of ~~2016.~~2017. Natural gas sales in the first six months of ~~2017~~2018 increased by ~~$40.5~~$24.4 million ~~(80%~~(27%) from ~~2016~~2017 while oil sales decreased by ~~$2.1~~$5.7 million ~~(8%~~(24%) from ~~2016.~~2017. Our natural gas production increased by ~~15%~~38% from ~~2016~~2017 and our realized natural gas price ~~increased~~decreased by ~~57%~~9%. The decrease in oil sales is attributable to the ~~34% decline in~~sale of our ~~production which was partially offset by the 40% increase in realized oil prices.~~producing Eagle Ford shale properties.

We utilize ~~oil and~~ natural gas price swaps to manage our exposure to ~~oil and~~ natural gas prices and protect returns on investment from our drilling activities. ~~Gains~~We had a loss related to our natural gas derivative financial instruments ~~were~~of $1.6 million and a gain of $5.3 million ~~and $18,000~~ for the three months ended June 30, 2018 and 2017, ~~and 2016, respectively,~~respectively. We had gains of $1.0 million and $13.2 ~~million and $0.7~~ million for the six months ended June 30, ~~2017~~2018 and ~~2016,~~2017, respectively. The following table presents our natural gas prices before and after the effect of cash settlements of our derivative financial instruments:

	Three Months Ended June 30,				Six Months Ended June 30,				Three Months Ended June 30,				Six Months Ended June 30,
	2017		2016		2017		2016		2018		2017		2018		2017
Average Realized Natural Gas Price:
Natural gas, per Mcf	$	2.91	$	1.90	$	2.92	$	1.86	$	2.59	$	2.91	$	2.67	$	2.92
Cash settlements of derivative financial instruments, per Mcf		0.08		0.09		0.06		0.08		0.05		0.08		0.06		0.06
Price per Mcf, including cash settlements of derivative financial instruments	$	2.99	$	1.99	$	2.98	$	1.94	$	2.64	$	2.99	$	2.73	$	2.98

Our production taxes ~~decreased $0.2~~were $1.1 million ~~to $1.1~~for each of the three months ended June 30, 2018 and 2017. Production taxes of $3.0 million for the first ~~quarter~~six months of ~~2017 from $1.3~~2018 increased $0.8 million ~~in the second quarter of 2016 despite the increase in sales. Production~~as compared with production taxes of $2.2 million for the first six months of ~~2017 decreased $0.3 million as compared with production taxes of $2.5 million for the first six months of 2016.~~2017. The ~~decrease~~increase is mainly due to our ~~lower oil sales. Much of the increase in~~higher natural gas ~~sales is attributable to new wells drilled which are initially exempt from~~ production ~~taxes.~~in 2018.

Gathering and transportation costs for the ~~first~~second quarter of ~~2017 decreased $0.5~~2018 increased $0.9 million to ~~$3.5~~$4.4 million as compared to ~~$4.0~~$3.5 million in the second quarter of ~~2016.~~2017. Gathering and transportation costs for the first six months of ~~2017 decreased $0.7~~2018 increased $1.0 million to ~~$7.7~~$8.7 million as compared to ~~$8.4~~$7.7 million for the first six months of ~~2016.~~2017. Our gathering and transportation costs have ~~decreased due to lower transportation rates we have negotiated for our~~increased primarily as a result of the increase in natural gas production.

Our lease operating expense of ~~$9.4~~$7.9 million for the ~~first~~second quarter of ~~2017~~2018 decreased ~~$3.6~~$1.5 million ~~(27%~~(16%) from lease operating expense of ~~$13.0~~$9.4 million for the ~~first~~second quarter of ~~2016~~2017 despite the increase in production. ~~This decrease primarily reflects lower costs associated with our Haynesville shale properties as well as the divestiture of certain high lifting cost properties in 2016.~~ Our lease operating expense for the first six months of ~~2017~~2018 of ~~$19.3~~$17.7 million decreased ~~$6.6~~$1.6 million or ~~26%~~8% from our lease operating expense of ~~$25.9~~$19.3 million for the first six months of ~~2016.~~2017. Our lease operating expense of ~~$0.56~~$0.39 per Mcfe produced for the six months ended June 30, ~~2017~~2018 was ~~$0.25~~$0.17 per Mcfe lower than the lease operating expense of ~~$0.81~~$0.56 per Mcfe for the same period in ~~2016.~~

~~Exploration~~2017. The decreases primarily reflect lower costs associated with our Haynesville shale properties and the sale of ~~$7.8 million~~our producing Eagle Ford shale oil properties in ~~the three months ended March 31, 2016, related to the impairments of certain unevaluated leases.~~April 2018.

Depreciation, depletion and amortization (“DD&A”) decreased ~~$5.7~~$3.5 million ~~(16%~~(12%) to $26.8 million in the second quarter of 2018 from $30.3 million in the second quarter of ~~2017 from $36.0 million in the second quarter of 2016.~~2017. Our DD&A per equivalent Mcf produced decreased ~~$0.68 (30%~~$0.41 (26%) to $1.19 for the three months ended June 30, 2018 from $1.60 for the three months ended June 30, ~~2017 from $2.28 for the three months ended June 30, 2016.~~2017. DD&A for the first six months of ~~2017~~2018 of ~~$60.2~~$54.0 million decreased by ~~$14.6~~$6.2 million ~~(20%~~(10%) from DD&A expense of ~~$74.9~~$60.2 million for the six months ended June 30, ~~2016.~~2017. For the first six months of ~~2017,~~2018, our per unit DD&A rate of ~~$1.74~~$1.19 decreased ~~$0.58 (25%~~$0.55 (32%) from our DD&A rate of ~~$2.32~~$1.74 for the first six months of ~~2016.~~2017. The lower rates in ~~2017~~2018 reflect the increase in production from our lower cost Haynesville shale properties.

General and administrative expenses, which are reported net of overhead reimbursements, increased to ~~$6.6~~$7.0 million for the ~~first~~second quarter of ~~2017~~2018 from ~~$5.7~~$6.6 million in the ~~first~~second quarter of ~~2016.~~2017. Included in general and administrative expenses are stock-based compensation of $1.5 million ~~and $1.2 million~~ for each of the three months ended June 30, 2018 and 2017, ~~and 2016,~~ respectively. ~~For~~Also included in the ~~first six~~three months ended June 30, 2018 were $0.4 million of ~~2017, general~~costs associated with an unsuccessful tender offer for our senior notes in April 2018. General and administrative expenses ofwere $13.0 million ~~increased $1.8 million (15%) from general and administrative expenses for~~in each of the six months ended June 30, ~~2016~~2018 and 2017.

We recognized a loss on sale of $11.2 million. Included in general and administrative expense is stock-based compensation of $2.8 million and $2.5 million for the six months ended June 30, 2017 and 2016, respectively. The increase in 2017 primarily relates to higher compensation costs for our employees.

~~We assess the need for impairment of the capitalized costs for our~~ oil and gas properties ~~on a property basis. We recognized impairment charges~~ of ~~$1.7~~$6.8 million and ~~$24.5~~$35.4 million ~~on our oil and gas properties~~ during the three months and six months ended June 30, ~~2016, respectively. Included in impairments for the six months ended June 30, 2016 is an impairment of $20.8 million which reduced~~2018 primarily to reduce the carrying value of our South Texas ~~natural gas~~oil properties classified as assets held for ~~sale. We also had~~sale to their fair value less costs to sell, and to adjust the carrying value of the South Texas acreage that we retained to fair value. $2.7 million of the loss results from a ~~net loss on~~final settlement for a property sale ~~of oil and gas properties of $1.6 million and $0.9 million for the three months and six months ended June 30, 2016, respectively.~~completed in 2012.

Interest expense increased ~~$7.9~~$3.4 million to ~~$36.8~~$40.2 million for the ~~first~~second quarter of ~~2017~~2018 from interest expense of ~~$28.9~~$36.8 million in the ~~first~~second quarter of ~~2016.~~2017. Interest expense increased ~~$10.9~~$9.4 million to ~~$69.7~~$79.1 million for the first six months of ~~2017~~2018 from interest expense of ~~$58.8~~$69.7 million in the first six months of ~~2016.~~2017. The increase in interest expense ~~mainly~~ reflects the amortization of the debt discounts ~~recognized as a result of~~and costs related to the ~~gain recognized on~~ debt exchange that we completed in September 2016 and the amortization of costs incurred on the exchange. These increases were partially offset by lower interest expense as a result of the reduction in the principal amount of our debt outstanding due to our debt reduction program in 2016.

During the six months ended June 30, 2016, we recognized a net gain on extinguishment of debt of $89.6 million due to the retirement of $87.5 million principal of the 2019 Notes and $19.8 million principal of the 2020 Notes as part of our debt reduction program.

Income taxes for the three months ended June 30, ~~2017~~2018 were a benefit of $0.1 million as compared to a provision of $0.5 million for the three months and ended June 30, 2017. Income taxes for the six months ended June 30, 2018 were a provision of $0.5 million as compared to a provision of ~~$88,000 for the three months ended June 30, 2016. Income taxes for the six months ended June 30, 2017 were a provision of~~ $1.0 ~~million as compared to a provision of $4.5~~ million for the six months ended June 30, ~~2016.~~2017. The ~~provisions~~benefit from or provision for income taxes are primarily related to adjustments of the valuation allowances against our federal and state net operating loss carryforwards. ~~During~~

We reported a net loss of $34.0 million, or $2.22 per share, for the ~~first quarter of 2016, Louisiana changed its tax laws with respect~~three months ended June 30, 2018 as compared to ~~the utilization of net operating losses. As a result of this tax law change we increased our deferred income tax liability related to state income taxes by $4.5 million.~~

~~We reported~~ a net loss of $21.4 million, or $1.45 per share, for the three months ended June 30, ~~2017 as compared to~~2017. We reported a net ~~income~~loss of ~~$4.9~~$75.9 million, or ~~$0.41~~$4.99 per ~~diluted~~ share, for the ~~three~~six months ended June 30, ~~2016. We reported~~2018, as compared to a net loss of $44.4 million, or $3.06 per share, for the six months ended June 30, ~~2017, as compared to a~~2017. The higher net ~~loss of $51.7 million, or $4.82 per share, for the six months ended June 30, 2016. The net loss for the six months ended June 30, 2017 was~~losses in 2018 are primarily due to our loss on sale of oil and gas properties and higher interest ~~expense, which includes the higher non-cash interest expense recognized in 2017 related to the amortization of discounts and costs recognized on our senior notes exchange.~~ expense.

Funding for our activities has historically been provided by our operating cash flow, debt or equity financings or proceeds from asset sales. For the six months ended June 30, ~~2017,~~2018, our primary source of funds was operating cash flow, ~~and~~ cash on ~~hand.~~hand and proceeds from asset sales. Cash provided from operating activities for the and six months ended June 30, ~~2017~~2018 was ~~$55.5~~$87.0 million as compared to cash ~~used for~~provided from operating activities of ~~$31.2~~$55.5 million for the first six months of ~~2016.~~2017. This increase in operating cash flow is mainly due to higher oil and gas ~~sales and the reduction in cash interest.~~sales.

Our primary needs for capital, in addition to funding our ongoing operations, relate to the acquisition, development and exploration of our oil and gas properties and the repayment of our debt. In the first six months of ~~2017,~~2018, we incurred capital expenditures of ~~$86.6~~$89.9 million to fund our development and exploration activities.

The following table summarizes our capital expenditure activity, on an accrual basis, for the six months ended June 30, ~~2017~~2018 and ~~2016:~~2017:

	Six Months Ended June 30,				Six Months ended June 30,
	2017		2016		2018		2017
	(In thousands)				(In thousands)
Exploration and development:
Development leasehold	$	1,064	$	1,089	$	2,344	$	1,064
Development drilling		81,544		26,798		76,629		81,544
Other development		4,028		2,455		10,913		4,028
Total capital expenditures	$	86,636	$	30,342	$	89,886	$	86,636

We drilled seventeen (5.1 net) wells and completed twenty-one (7.9 net) horizontal Haynesville and Bossier shale wells during the six months ended June 30, 2018. We expect to spend an additional $96.0 million in the second half of 2018 to drill 28 11.7 net) wells. In addition, we expect to spend $51.5 million on the Bakken Shale Properties We expect to fund our ~~ongoing~~future development and exploration activities with future operating cash flow including cash flow from the Bakken Shale Properties and from cash on hand. The timing of most of our future capital expenditures is discretionary because we have no material long-term capital expenditure commitments. Consequently, we have a significant degree of flexibility to adjust the level of our capital expenditures as circumstances warrant. As of June 30, ~~2017,~~2018, we have ~~three~~four drilling rigs under contract through ~~April 2018~~September 2019 at a cost of ~~$9.9~~$19.3 million and commitments of ~~$3.3~~$1.3 million to transport and treat natural gas through July 2019. We also have obligations to incur future payments for dismantlement, abandonment and restoration costs of oil and gas properties which are currently estimated to be incurred primarily after ~~2022.~~2023.

~~Through June 30,~~At December 31, 2017, we ~~drilled nine (8.1 net) and~~classified our South Texas oil properties in the Eagle Ford shale as assets held for sale. On April 27, 2018, we completed ~~ten (8.8 net) operated horizontal Haynesville~~the sale of these properties. After the sale, we retained approximately 8,400 undeveloped acres prospective for Eagle Ford shale ~~wells and one non-operated well. We are currently planning to drill 18 (9.0 net) additional wells in 2017. Capital expenditures for the remainder~~development with a fair value of ~~2017 are estimated at $81.0~~approximately $55.0 million. ~~We may reduce the number of wells we drill this year depending upon the natural gas prices that we realize.~~

At June 30, ~~2017~~2018, we had outstanding $697.2 million of 10% Senior Secured Toggle Notes due 2020, ~~$273.8~~$295.5 million of 7¾% Convertible Second Lien PIK Notes due 2019 and ~~$178.6~~$195.9 million of 9½% Convertible Second Lien PIK Notes due 2020. We also had $25.6 million of unsecured notes outstanding due in 2019 and 2020. Interest on the 10% Senior Secured Toggle Notes is payable on March 15 and September 15 and the notes mature on March 15, 2020. We have the option to pay up to $75.0 million of accrued interest on the Senior Secured Toggle Notes by issuing additional notes. To the extent that interest is paid in kind, the interest rate increases to 12¼% only for that interest payment and would result in up to an additional $91.9 million of notes outstanding. Interest on the 7¾% Convertible Second Lien PIK Notes is payable on April 1 and October 1 and these notes mature on April 1, 2019. Interest on the 9½% Convertible Second Lien PIK Notes is payable on June 15 and December 15 and these notes mature on June 15, 2020. Interest on the convertible notes is only payable in kind. Each series of the convertible notes is convertible, at the option of the holder, into 81.2 shares of our common stock for each $1,000 of principal amount of notes. The convertible notes ~~will~~ mandatorily convert into shares of common stock following a 15 consecutive trading day period during which the daily volume weighted average price of our common stock is equal to or greater than $12.32 per share. The mandatory conversion provisions of the convertible notes have been temporarily suspended pending the completion of the Jones Contribution and the tender offer. $9.9 million of principal amount of the convertible notes plus related accrued interest were converted into 826,327 shares of common stock during the six months ended June 30, 2017.

During the six months ended June 30, 2016, we retired $87.5 million in principal amount of the 2019 Notes and $19.8 million of the 2020 Notes in exchange in the aggregate for the issuance of 2,748,403 shares of common stock and $3.5 million in cash. A gain of $89.6 million was recognized on the exchanges and purchases of the 2019 Notes and the 2020 Notes during the six months ended June 30, 2016. The gain is included in the net gain on extinguishment of debt for the difference between the market value of the stock on the closing date of the exchange and the net carrying value of the debt and the related net premium and net debt issuance costs.

We have a $50.0 million revolving credit facility with Bank of Montreal and Bank of America, N.A. that matures on March 4, 2019. As of June 30, ~~2017,~~2018, there were no borrowings outstanding under the revolving credit facility.Indebtedness under the revolving credit facility is guaranteed by all of our subsidiaries and is secured by substantially all of our and ~~its~~our subsidiaries' assets. Borrowings under the revolving credit facility bear interest, at our option, at either (1) LIBOR plus 2.5% or (2) the base rate (which is the higher of the administrative agent's prime rate, the federal funds rate plus 0.5% or 30 day LIBOR plus 1.0%) plus 1.5%. A commitment fee of 0.5% per annum is payable quarterly on the unused credit line. The revolving credit facility contains covenants that, among other things, restrict the payment of cash dividends and repurchases of common stock, limit the amount of additional debt that we may incur and limit our ability to make certain loans, investments and divestitures. The only financial covenants are the maintenance of a current ratio, including availability under the ~~revolving~~ credit facility, of at least 1.0 to 1.0, and the maintenance of an asset coverage ratio of proved developed reserves to amounts outstanding under the revolving credit facility of at least 2.5 to 1.0. We were in compliance with these covenants as of June 30, ~~2017~~2018. The current maturities related to our debt are not included in the current ratio calculations.

All of our subsidiaries guarantee the bank credit facility, the 10% Senior Secured Toggle Notes, the 7¾% Convertible Second Lien PIK Notes, the 9½% Convertible Second Lien PIK Notes, and the other outstanding senior notes. The bank credit facility, the 10% Senior Secured Toggle Notes and the convertible notes are secured by liens on substantially all of our and our ~~subsidiaries~~subsidiaries' assets. The allocation of proceeds related to the liens on our assets are governed by intercreditor agreements granting priority to the bank credit facility. Proceeds from liens on the convertible notes are also subject to the priority of the 10% Senior Secured Toggle Notes.

On May 9, 2018, Arkoma and Williston entered into a Contribution Agreement with us to contribute certain oil and gas properties in North Dakota and Montana with an estimated fair value of approximately $620.0 million in exchange for approximately 88.6 million newly issued shares of our common stock. The effective date of the acquisition of the properties is April 1, 2018. We estimated that the properties have proved reserves of 22.8 million barrels of oil and 49.3 Bcf of natural gas on the effective date. Upon completion of the transaction, Arkoma and Williston will collectively own approximately 84.5% of our pro forma outstanding shares. The transaction is subject to a number of closing conditions, including the approval of the issuance of the common stock by our stockholders at our Annual Meeting of Stockholders scheduled for August 10, 2018 and satisfaction of certain other closing conditions.

In connection with the Jones Contribution, we commenced a tender offer on July 13, 2018 to repurchase all of our outstanding debt. We expect to close the tender offer concurrent with the closing of the Jones Contribution and refinance all of our debt using funds from the sale of 9¾% Senior Notes due 2026 and borrowings under a new Bank Credit Facility with an initial borrowing base of $700.0 million..

In connection with our refinancing plan, we sold $850.0 million of 9¾% Senior Notes due 2026 at 95.988% of the principal amount on August 3, 2018. Interest on the new senior notes is payable in cash each February 15 and August 15. Proceeds from the offering are being held in escrow pending the closing of the Jones Contribution which is expected to occur on August 14, 2018.

Future use of our net operating loss carryforwards ~~may~~are expected to be limited inupon completion of the ~~event that a cumulative change in the ownership of our common stock by more than 50% occurs within a three-year period. Such a change in ownership could~~Jones Contribution which will result in a substantial portion of our net operating loss carryforwards being eliminated or becoming restricted. It

The Tax Cuts and Jobs Act, which was enacted on December 22, 2017, reduced the corporate income tax rate effective January 1, 2018 from 35% to 21%. Among the other significant tax law changes that affect us are the elimination of the corporate alternative minimum tax ("AMT"), changes that require operating losses incurred in 2018 and beyond be carried forward indefinitely with no carryback up to 80% of taxable income in a given year, and limitations on the deduction for interest expense incurred in 2018 and later for amounts in excess of 30% of its adjusted taxable income (defined as taxable income before interest and net operating losses. For tax years beginning before January 1, 2022, the adjusted taxable income for these purposes is ~~highly likely that~~also adjusted to exclude the impact of depreciation, depletion and amortization. The Tax Cuts and Jobs Act preserved deductibility of intangible drilling costs for federal income tax purposes, which allows us to deduct a ~~change~~portion of drilling costs in ~~ownership that would result from~~the year incurred and minimizes current taxes payable in periods of taxable income. At June 30, 2018, we have not completed our accounting for the tax effects of enactment of the Tax Cuts and Jobs Act; however, we have made reasonable estimates of the effects on our existing deferred tax balances. We have remeasured certain deferred federal tax assets and liabilities based on the rates at which they are expected to reverse in the future, ~~conversion~~which is generally 21%. The provisional amount recognized related to the remeasurement of our ~~convertible notes would result~~deferred federal tax balance was $140.4 million, which was subject to a valuation allowance. The Tax Cuts and Jobs Act also repealed the AMT for tax years beginning on or after January 1, 2018 and provides that existing AMT credit carryforwards can be utilized to offset federal taxes for any taxable year. In addition, 50% of any unused AMT credit carryforwards can be refunded during tax years 2018 through 2020 with any remaining AMT credit carryforward being fully refunded in ~~limits on~~2021. We reclassified $19.1 million to a non-current receivable at December 31, 2017 representing the amount of AMT that is now refundable through 2021. We are still analyzing certain aspects of the Tax Cuts and Jobs Act, and refining our calculations, which could potentially affect the measurement of those balances or potentially give rise to

new deferred tax amounts. Our estimates may also be affected in the future ~~use~~as we gain a more thorough understanding of ~~our net operating loss carryforwards.~~the Tax Cuts and Jobs Act, and how the individual states are implementing this new law.

Our financial condition, results of operations and capital resources are highly dependent upon the prevailing market prices of natural gas and oil. These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors, some of which are beyond our control. Factors influencing oil and natural gas prices include the level of global demand for crude oil, the foreign supply of oil and natural gas, the establishment of and compliance with production quotas by oil exporting countries, weather conditions that determine the demand for natural gas, the price and availability of alternative fuels and overall economic conditions. It is impossible to predict future oil and natural gas prices with any degree of certainty. Sustained weakness in natural gas and oil prices may adversely affect our financial condition and results of operations, and may also reduce the amount of oil and natural gas reserves that we can produce economically. Any reduction in our natural gas and oil reserves, including reductions due to price fluctuations, can have an adverse effect on our ability to obtain capital for our exploration and development activities. Similarly, any improvements in natural gas and oil prices can have a favorable impact on our financial condition, results of operations and capital resources.

As of June 30, ~~2017,~~2018, we have entered into natural gas price swap agreements to hedge approximately ~~20.7~~15.0 billion cubic feet of our ~~2017~~2018 and ~~2018~~2019 production at an average price of ~~$3.38~~$3.00 per Mcf. We have also entered in natural gas collars to hedge approximately 10.8 Bcf of natural gas with a floor price of $2.50 and a ceiling price of $3.30 and approximately 10.8 Bcf of natural gas with a floor price of $2.50 and a ceiling price of $3.50. None of our derivative contracts have margin requirements or collateral provisions that could require funding prior to the scheduled cash settlement date. The change in the fair value of our natural gas swaps that would result from a 10% change in commodities prices at June 30, ~~2017~~2018 would be ~~$3.6~~$3.1 million. Such a change in fair value could be a gain or a loss depending on whether prices increase or decrease.

Based on our oil and natural gas production for the six months ended June 30, ~~2017~~2018 and our outstanding natural gas price swap agreements, a $0.10 change in the price per Mcf of natural gas would have changed our cash flow by approximately ~~$1.7~~$3.5 million and a $1.00 change in the price per barrel of oil would have resulted in a change in our cash flow ~~from continuing operations~~ for such period by approximately ~~$0.5~~$0.3 million. Our natural gas collars which cover the period July 1, 2018 through June 30, 2019 will result in natural gas prices on 10.8 Bcf of our future production to be subject to a floor price of $2.50 per MMbtu and a ceiling price of $3.30 per MMbtu and 10.8 Bcf of our future production to be subject to a floor price of $2.50 per MMbtu and a ceiling price of $3.50 per MMbtu. These collars may increase or decrease our cash flow depending upon whether future prices are below the floor or above the ceiling prices.

At June 30, ~~2017,~~2018, we had approximately $1.2 billion principal amount of long-term debt outstanding. All but $25.6 million of this debt is secured by substantially all of our assets. Of this amount, our first lien notes of $697.2 million bear interest at a fixed rate of 10%, our second lien notes of ~~$273.8~~$295.5 million bear interest at a fixed rate of 7¾% and our second lien notes of ~~$178.6~~$195.9 million bear interest at a fixed rate of 9½%. At our option, up to $75.0 million of the interest on the first lien debt is payable in-kind. All of the interest on the second lien debt is payable in kind. The $25.6 million of unsecured senior notes bear interest at rates of between 7¾% to 10% and mature in 2019 and 2020. The fair market value of our fixed rate debt as of June 30, ~~2017~~2018 was ~~$1.1~~$1.2 billion based on the market price of approximately ~~91%~~102% of the face amount of such debt. At June 30, 2017, we did not have any borrowings outstanding under our revolving credit facility, which is subject to variable rates of interest that are tied at our option to either LIBOR or the corporate base rate.

As of June 30, ~~2017,~~2018, we carried out an evaluation, under the supervision and with the participation of our chief executive officer and chief financial officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934). Based on this evaluation, our chief executive officer and chief financial officer concluded that our disclosure controls and procedures were effective as of June 30, ~~2017~~2018 to provide reasonable assurance that information required to be disclosed by us in the reports filed or submitted by us under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms, and to provide reasonable assurance that information required to be disclosed by us is accumulated and communicated to our management, including our chief executive officer and chief financial officer, as appropriate, to allow timely decisions regarding required disclosure. There were no changes in our internal controls over financial reporting (as such term is defined in Rule 13a-15(f) under the Securities Exchange Act of 1934) that occurred during the quarter ended June 30, ~~2017,~~2018, that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Large accelerated filer ☐	Accelerated filer ☐☒	Non-accelerated filer ☐	(Do not check if a smaller reporting company)
Smaller reporting company ☒☐	Emerging growth company ☐

	Page
PART I. Financial Information
Item 1. Financial Statements (Unaudited):
Consolidated Balance Sheets – June 30, ~~2017~~2018 and December 31, ~~2016~~2017	4
Consolidated Statements of Operations -– Three ~~Months~~ and ~~Six Months~~six months ended June 30, ~~2017~~2018 and ~~2016~~2017	5
Consolidated Statement of Stockholders' Deficit ~~- Six Months~~– Three and six months ended June 30, ~~2017~~2018	6
Consolidated Statements of Cash Flows ~~- Six Months~~– Three and six months ended June 30, ~~2017~~2018 and ~~2016~~2017	7
Notes to Consolidated Financial Statements	8
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations	1718
Item 3. Quantitative and Qualitative Disclosure About Market Risk	2122
Item 4. Controls and Procedures	2122
PART II. Other Information
Item 6. Exhibits	2223
Ex-2.1 Contribution Agreement dated May 9, 2018, by and among Arkoma Drilling, L.P., Williston Drilling, L.P. and Comstock Resources, Inc. previously filed on Form 8-K/A dated May 14, 2018.
EX-31.1 Section 302 Certification of the Chief Executive Officer.
EX-31.2 Section 302 Certification of the Chief Financial Officer.
EX-32.1 Certification for the Chief Executive Officer as required by Section 906 of the Sarbanes-Oxley Act of 2002.
EX-32.2 Certification for the Chief Financial Officer as required by Section 906 of the Sarbanes-Oxley Act of 2002.
EX-101 ~~INSTANCE DOCUMENT~~Instance Document
EX-101 ~~SCHEMA DOCUMENT~~Schema Document
EX-101 ~~CALCULATION LINKBASE DOCUMENT~~Calculation Linkbase Document
EX-101 ~~LABELS LINKBASE DOCUMENT~~Labels Linkbase Document
EX-101 ~~PRESENTATION LINKBASE DOCUMENT~~Presentation Linkbase Document
EX-101 ~~DEFINITION LINKBASE DOCUMENT~~Definition Linkbase Document

	Three Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2017			2016
	(In thousands)
Tax at statutory rate		35.0	%		35.0	%		35.0	%		35.0	%
Tax effect of:
Valuation allowance on deferred tax assets		(42.1	)		(22.1	)		(40.1	)		(48.5	)
State income taxes, net of federal benefit		5.0			(11.8	)		4.3			4.2
Other		(0.4	)		0.7			(1.4	)		(0.3	)
Effective tax rate		(2.5	)%		1.8	%		(2.2	)%		(9.6	)%

	Three Months Ended June 30,						Six Months Ended June 30,
	2018			2017			2018			2017
	(In thousands)
Tax at statutory rate		21.0	%		35.0	%		21.0	%		35.0	%
Tax effect of:
Valuation allowance on deferred tax assets		(24.1	)		(42.1	)		(24.3	)		(40.1	)
State income taxes, net of federal benefit		3.9			5.0			3.5			4.3
Nondeductible stock-based compensation		(0.4	)		(0.4	)		(0.7	)		(1.4	)
Effective tax rate		0.4	%		(2.5	)%		(0.5	)%		(2.2	)%

Exhibit No.		Description
2.1		Contribution Agreement dated May 9, 2018, by and among Arkoma Drilling, L.P., Williston Drilling, L.P. and Comstock Resources, Inc. previously filed on Form 8-K/A dated May 14, 2018.
31.1*		Section 302 Certification of the Chief Executive Officer.
31.2*		Section 302 Certification of the Chief Financial Officer.
32.1†		Certification for the Chief Executive Officer as required by Section 906 of the Sarbanes-Oxley Act of 2002.
32.2†		Certification for the Chief Financial Officer as required by Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS*		XBRL Instance Document
101.SCH*		XBRL Schema Document
101.CAL*		XBRL Calculation Linkbase Document
101.LAB*		XBRL Labels Linkbase Document
101.PRE*		XBRL Presentation Linkbase Document
101.DEF*		XBRL Definition Linkbase Document

Location of Gain/(Loss) Recognized in Earnings on Derivatives	Three Months Ended June 30,					Six Months Ended June 30,
	2018			2017		2018		2017
	(in thousands)
Gain (loss) from derivative financial instruments	$	(1,638	)	$	5,295	$	964	$	13,155

	Carrying Value Measured at Fair Value at June 30, 2017		Level 1		Level 2
	(In thousands)
Assets measured at fair value on a recurring basis:
Cash and cash equivalents held in bank accounts	$	35,321	$	35,321	$	—
Derivative financial instruments		5,229		—		5,229
Total assets	$	40,550	$	35,321	$	5,229

	COMSTOCK RESOURCES, INC.
Date: August ~~7, 2017~~9, 2018	/s/ M. JAY ALLISON
	M. Jay Allison, Chairman, Chief
	Executive Officer (Principal Executive Officer)
Date: August ~~7, 2017~~9, 2018	/s/ ROLAND O. BURNS
	Roland O. Burns, President, Chief Financial
	Officer and Secretary (Principal Financial and Accounting Officer)