SEC Filing | Comstock Resources, Inc.

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Form 8-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

Date of Report (Date of Earliest Event Reported): August 1, 2016

COMSTOCK RESOURCES, INC.

(Exact Name of Registrant as Specified in Charter)

STATE OF NEVADA

001-03262

94-1667468

(State or other jurisdiction

incorporation)

(Commission

File Number)

(I.R.S. Employer

Identification Number)

5300 Town and Country Boulevard

Suite 500

Frisco, Texas 75034

(Address of principal executive offices)

(972) 668-8800

(Registrant’s Telephone No.)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

¨	Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

¨	Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

¨	Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

¨	Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Item 8.01

Other Events

We are filing this Current Report on Form 8-K (this “Form 8-K”) to update certain financial information in our Annual Report on Form 10-K for the fiscal year ended December 31, 2015 that we filed on February 26, 2016 (the “Form 10-K”), to reflect the one-for-five (1:5) reverse split of our issued and outstanding common stock which has been approved by our Board of Directors and became effective on July 29, 2016.

This Form 8-K presents disclosures updated from our Form 10-K, as originally filed, to reflect the application of the reverse stock split on a comparable basis for all years presented. All other information is presented as set forth in the Form 10-K and has not been updated in this Form 8-K. The updates to the Form 10-K, as set forth in this Form 8-K, for the retrospective application of the reverse stock split are consistent with the presentation in our quarterly report on Form 10-Q for the period ended June 30, 2016 which we are also filing with the Securities and Exchange Commission today. The sections of the Form 10-K affected by these changes are: Items 5, 6, 7, 12 and 15.

All such updated and enhanced items of the Form 10-K are set forth in their entirety in Exhibits 99.1 through 99.5 hereto, and are incorporated by reference herein.

We have not updated or enhanced any other disclosures presented in the Form 10-K. More current information is included in our other filings with the Securities and Exchange Commission. This Form 8-K, including the exhibits hereto, should be read in conjunction with the Form 10-K and our other filings. Other filings may contain important information regarding uncertainties, trends, risks, events, transactions, developments and updates to certain expectations that may have been reported since the filing of the Form 10-K.

Item 9.01

Financial Statements and Exhibits


Exhibit 23.1		Consent of Independent Registered Public Accounting Firm

Exhibit 99.1		Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Exhibit 99.2		Selected Financial Data

Exhibit 99.3		Management’s Discussion and Analysis of Financial Condition and Results of Operations

Exhibit 99.4		Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Exhibit 99.5		Financial Statements

Ex-101		Instance Document

Ex-101		Schema Document

Ex-101		Calculation Linkbase Document

Ex-101		Labels Linkbase Document

Ex-101		Presentation Linkbase Document

Ex-101		Definition Linkbase Document

SIGNATURES

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


		COMSTOCK RESOURCES, INC.

Dated: August 1, 2016	By:	/s/ ROLAND O. BURNS
		Roland O. Burns
		President and Chief Financial Officer

EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in the Registration Statements (Form S-8 Nos. 333-36854, 033-88962, 333-159332 and 333-207180) pertaining to the Comstock Resources, Inc. 2009 Long-term Incentive Plan Amended and Restated Effective as of May 7, 2015 of our report dated February 26, 2016 (except for Notes 1, 6, 7 and 11 as to the effect of the reverse stock split, as to which the date is August 1, 2016), with respect to the consolidated financial statements of Comstock Resources, Inc., included in this Current Report (Form 8-K) dated August 1, 2016.

/s/ Ernst & Young LLP

Dallas, Texas

August 1, 2016

EX-99.1

Exhibit 99.1

ITEM 5.

MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Our common stock is listed for trading on the New York Stock Exchange under the symbol “CRK”. The following table sets forth, on a per share basis for the periods indicated, the high and low sales prices by calendar quarter for the periods indicated as reported by the New York Stock Exchange. All share and per share amounts below have been adjusted to give effect to the Company’s one-for-five (1:5) reverse stock split that became effective on July 29, 2016.


		High		Low
2014 –	First Quarter	$	115.75	$	81.10
	Second Quarter	$	145.75	$	112.10
	Third Quarter	$	147.45	$	91.50
	Fourth Quarter	$	94.00	$	25.05

2015 –	First Quarter	$	36.10	$	16.15
	Second Quarter	$	27.20	$	16.45
	Third Quarter	$	20.35	$	4.95
	Fourth Quarter	$	16.90	$	8.00

As of February 26, 2016, we had 10,635,664 shares of common stock outstanding, which were held by 196 holders of record and approximately 15,000 beneficial owners who maintain their shares in “street name” accounts.

We paid a quarterly cash dividend on our common stock in 2014, resulting in total dividends paid of $23.8 million. On February 13, 2015, we announced that the dividend was being suspended until oil and natural gas prices improve. Any future determination as to the payment of dividends will depend upon the results of our operations, capital requirements, our financial condition and such other factors as our board of directors may deem relevant.

Stockholder Return Performance

A peer group of companies is used by our compensation committee to benchmark our executives’ compensation and to determine total stockholder return performance for purposes of vesting of performance share units granted to executives under our 2009 Long-term Incentive Plan. For 2015, the compensation committee utilized a peer group, which consisted of Approach Resources. Inc., Bill Barrett Corporation, Carrizo Oil & Gas Inc., Cimarex Energy Co., Laredo Petroleum Holdings Inc., Oasis Petroleum Inc., PDC Energy Inc., SM Energy, Inc., Stone Energy Corporation, Swift Energy Co., and Ultra Petroleum Corp.

The following graph compares the yearly percentage change in the cumulative total stockholder return on our common stock during the five years ended December 31, 2015 with the cumulative return on the New York Stock Exchange Index and the cumulative return for our peer group. The graph assumes that $100.00 was invested on the last trading day of 2010, and that dividends, if any, were reinvested.

COMPARISON OF 5 YEAR CUMULATIVE TOTAL RETURN⁽¹⁾⁽²⁾

Among Comstock Resources, the NYSE Composite Index, and Our Peer Group

LOGO

(1)	$100 invested on December 31, 2010 in stock or index, including reinvestment of dividends, fiscal year ending December 31.

(2)	The data contained in the above graph is deemed to be furnished and not filed pursuant to Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liabilities of that section.


	As of December 31,
Total Return Analysis	2010		2011		2012		2013		2014		2015
Comstock Resources	$	100.00	$	62.30	$	61.56	$	76.23	$	29.33	$	8.05
NYSE Composite	$	100.00	$	96.16	$	111.53	$	140.85	$	150.35	$	144.21
Peer Group	$	100.00	$	82.59	$	65.44	$	100.02	$	62.82	$	42.43

EX-99.2

Exhibit 99.2

The selected financial data below has been adjusted to give effect to a one for five (1:5) reverse stock split which became effective on July 29, 2016. Basic and diluted earnings per share have been adjusted in all periods to include the effect of this reverse stock split. The effect of on each year is presented in the table below:


	Year Ended December 31,
	2011			2012			2013			2014			2015
	Increase (decrease) from previously reported amounts
Basic and diluted net income (loss) per share:
Loss from continuing operations	$	(2.91	)	$	(8.88	)	$	(8.88	)	$	(4.96	)	$	(90.82	)
Income from discontinued operations		—			0.26			12.29			—			—

	$	(2.91	)	$	(8.62	)	$	3.41		$	(4.96	)	$	(90.82	)

Dividends per common share	$	—		$	—		$	1.50		$	2.00			—

Basic and diluted weighted average shares outstanding (In thousands)		(36,798	)		(37,138	)		(37,242	)		(37,238	)		(36,890	)

ITEM 6.

SELECTED FINANCIAL DATA

The historical financial data presented in the table below as of and for each of the years in the five-year period ended December 31, 2015 are derived from our consolidated financial statements. The financial results are not necessarily indicative of our future operations or future financial results. The data presented below should be read in conjunction with our consolidated financial statements and the notes thereto and “Management’s Discussion and Analysis of Financial Condition and Results of Operations”. All share and per share data presented below has been adjusted to give effect to the Company’s reverse stock split which became effective on July 29, 2016.

Statement of Operations Data:


	Year Ended December 31,
	2011			2012			2013			2014			2015
	(In thousands, except per share data)
Revenues:
Natural gas sales	$	354,123		$	203,651		$	188,453		$	165,461		$	109,753
Oil sales		80,244			181,163			231,837			389,770			142,669

Total oil and gas sales		434,367			384,814			420,290			555,231			252,422
Gain on sales of oil and gas properties		—			24,271			—			—			—

Total revenues		434,367			409,085			420,290			555,231			252,422
Operating expenses:
Production taxes		3,670			11,727			14,524			23,797			10,286
Gathering and transportation		28,491			26,265			17,245			12,897			14,298
Lease operating⁽¹⁾		46,552			51,248			52,844			60,283			64,502
Exploration		10,148			61,449			33,423			19,403			70,694
Depreciation, depletion and amortization		290,776			343,858			337,134			378,275			321,323
General and administrative, net		35,172			33,798			34,767			32,379			23,541
Impairment of oil and gas properties		60,817			25,368			652			60,268			801,347
Loss on sales of oil and gas properties		57			—			2,033			—			112,085

Total operating expenses		475,683			553,713			492,622			587,302			1,418,076

Operating loss		(41,316	)		(144,628	)		(72,332	)		(32,071	)		(1,165,654	)
Other income (expenses):
Gain on sale of marketable securities		35,118			26,621			7,877			—			—
Gain (loss) from derivative financial instruments		—			21,256			(8,388	)		8,175			2,676
Net gain (loss) on extinguishment of debt		(1,096	)		—			(17,854	)		—			78,741
Other income		790			944			1,059			727			1,275
Interest expense		(41,592	)		(57,906	)		(73,242	)		(58,631	)		(118,592	)

Total other income (expenses)		(6,780	)		(9,085	)		(90,548	)		(49,729	)		(35,900	)

Loss from continuing operations before income taxes		(48,096	)		(153,713	)		(162,880	)		(81,800	)		(1,201,554	)
Benefit from income taxes		14,624			50,634			56,157			24,689			154,445

Loss from continuing operations		(33,472	)		(103,079	)		(106,723	)		(57,111	)		(1,047,109	)
Income from discontinued operations, net of income taxes		—			3,019			147,752			—			—

Net income (loss)	$	(33,472	)	$	(100,060	)	$	41,029		$	(57,111	)	$	(1,047,109	)

Basic and diluted net income (loss) per share:
Loss from continuing operations	$	(3.64	)	$	(11.10	)	$	(11.09	)	$	(6.20	)	$	(113.53	)
Income from discontinued operations		—			0.32			15.36			—			—

Net Income (loss)	$	(3.64	)	$	(10.78	)	$	4.27		$	(6.20	)	$	(113.53	)

Dividends per common share	$	—		$	—		$	1.88		$	2.50		$	—

Basic and diluted weighted average shares outstanding		9,199			9,284			9,311			9,309			9,223

(1)	Includes ad valorem taxes.

Balance Sheet Data:


	As of December 31,
	2011		2012		2013		2014		2015
	(In thousands)
Cash and cash equivalents	$	8,460	$	4,471	$	2,967	$	2,071	$	134,006
Property and equipment, net		2,155,568		1,958,687		2,066,735		2,198,169		1,038,420
Total assets⁽¹⁾		2,632,009		2,554,930		2,130,112		2,264,546		1,195,850
Total debt⁽¹⁾		1,186,319		1,309,416		789,414		1,060,654		1,249,330
Stockholders’ equity (deficit)		1,037,625		933,534		952,005		870,272		(171,258	)

(1)	Restated to reclassify debt issuance costs from total assets to total debt in the amount of $10,589, $14,967, $9,286 and $9,791 as of December 31, 2011, 2012, 2013, and 2014, respectively.

Cash Flow Data:


	Year Ended December 31,
	2011			2012			2013			2014			2015
	(In thousands)
Cash flows provided by operating activities from continuing operations	$	275,433		$	219,721		$	268,994		$	400,984		$	30,086
Cash flows used for investing activities from continuing operations		(597,809	)		(205,393	)		(408,678	)		(634,787	)		(161,725	)
Cash flows provided by (used for) financing activities from continuing operations		673,381			117,502			(576,140	)		232,907			263,574
Cash flows provided by (used for) operating activities of discontinued operations		—			42,508			(7,715	)		—			—
Cash flows provided by (used for) investing activities of discontinued operations		(344,277	)		(178,327	)		722,035			—			—

EX-99.3

Exhibit 99.3

ITEM 7.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis should be read in conjunction with our selected historical consolidated financial data and our accompanying consolidated financial statements and the notes to those financial statements included elsewhere in this report. The following discussion includes forward-looking statements that reflect our plans, estimates and beliefs. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, those discussed below and elsewhere in this report, particularly in “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements.”

Overview

We are an independent energy company engaged in the acquisition, exploration, development and production of oil and natural gas in the United States. We own interests in 1,575 producing oil and natural gas wells (859.7 net to us) and we operate 952 of these wells. In managing our business, we are concerned primarily with maximizing return on our stockholders’ equity. To accomplish this goal, we focus on profitably increasing our oil and natural gas reserves and production.

In 2011, we acquired an undeveloped acreage position and some producing oil wells in Gaines and Reeves Counties in West Texas. We operated these properties, which we designated as our West Texas region, through May 2013 when we sold all of these properties for total proceeds of $823.1 million. Accordingly, we are presenting our West Texas operations as discontinued operations in our financial statements for all periods presented. Unless indicated otherwise, the amounts in the accompanying tables and discussion relate to our continuing operations.

Our growth is driven primarily by acquisition, development and exploration activities. In 2015 our growth in natural gas production and proved reserves was primarily driven by our successful drilling activities. Under our current drilling budget, we plan to spend approximately $98.0 million in 2016 for development and exploration activities, which will primarily be focused on natural gas projects. We are currently planning to drill nine horizontal natural gas wells (7.5 net to us) in 2016, targeting the Haynesville/Bossier shales. The actual number of wells that we drill will depend on oil and natural gas prices.

We use the successful efforts method of accounting, which allows only for the capitalization of costs associated with developing proven oil and natural gas properties as well as exploration costs associated with successful exploration activities. Accordingly, our exploration costs consist of costs we incur to acquire and reprocess 3-D seismic data, impairments of our unevaluated leasehold where we were not successful in discovering reserves and the costs of unsuccessful exploratory wells that we drill.

We generally sell our oil and natural gas at current market prices at the point our wells connect to third party purchaser pipelines or terminals. We have entered into certain transportation and treating agreements with midstream and pipeline companies to transport a substantial portion of our natural gas production in North Louisiana to long-haul gas pipelines. We market our products several different ways depending upon a number of factors, including the availability of purchasers for the product, the availability and cost of pipelines near our wells, market prices, pipeline constraints and operational flexibility. Accordingly, our revenues are heavily dependent upon the prices of, and demand for, oil and natural gas. Oil and natural gas prices have historically been volatile and are likely to remain volatile in the future. Oil and natural gas prices have declined substantially since June 2014 and have continued to decline into early 2016.

Our operating costs are generally comprised of several components, including costs of field personnel, insurance, repair and maintenance costs, production supplies, fuel used in operations, transportation costs, workover expenses and state production and ad valorem taxes.

Like all oil and natural gas exploration and production companies, we face the constant challenge of replacing our reserves. Although in the past we have offset the effect of declining production rates from existing properties through successful acquisition and drilling efforts, there can be no assurance that we will be able to continue to offset production declines or maintain production at current rates through future acquisitions or drilling activity. Our future growth will depend on our ability to continue to add new reserves in excess of production.

Our operations and facilities are subject to extensive federal, state and local laws and regulations relating to the exploration for, and the development, production and transportation of, oil and natural gas, and operating safety. Future laws or regulations, any adverse changes in the interpretation of existing laws and regulations or our failure to comply with existing legal requirements may have an adverse effect on our business, results of operations and financial condition. Applicable environmental regulations require us to remove our equipment after production has ceased, to plug and abandon our wells and to remediate any environmental damage our operations may have caused. The present value of the estimated future costs to plug and abandon our oil and gas wells and to dismantle and remove our production facilities is included in our reserve for future abandonment costs, which was $20.1 million as of December 31, 2015.

Prices for crude oil and natural gas have been highly volatile, and we are currently experiencing a period of extraordinarily low prices primarily due to an oversupply of crude oil and natural gas. As prices remain low, we will continue to experience low revenues and cash flows. We expect our oil production to decline in the future until we resume drilling on these properties. We expect our natural gas production to decline in the future to the extent that we do not offset this decline from production from the new wells we plan to drill in 2016 and future periods. Depending upon future prices and our production volumes, our cash flows from our operating activities may not be sufficient to fund our capital expenditures, and we will need to either curtail drilling activity or we may seek additional borrowings which would increase our interest expense in 2016 and in future periods.

We recognized significant impairments of our proved oil and gas properties in 2015. We may need to recognize further impairments if oil and natural gas prices remain low, and as a result, the expected future cash flows from these properties becomes insufficient to recover their carrying value. Specifically, as part of the impairment review performed at December 31, 2015, we observed that a decline in excess of 30% for our future cash flow estimates for our Eagleville field in South Texas could result in an additional impairment being recorded in an amount that could be at least $130.0 million. In addition, we may recognize additional impairments of our unevaluated oil and gas properties should we determine that we no longer intend to retain these properties for future oil and natural gas development.

Results of Operations

Year Ended December 31, 2015 Compared to Year Ended December 31, 2014

Our operating data for 2014 and 2015 is summarized below:


	Year Ended December 31,
	2014		2015
Oil and Gas Sales (in thousands):
Natural gas sales	$	165,461	$	109,753
Oil sales		389,770		142,669

Total oil and gas sales	$	555,231	$	252,422


Net Production Data:
Natural gas (MMcf)		39,768		47,646
Oil (MBbls)		4,313		3,089
Natural gas equivalent (MMcfe)		65,645		66,207

Average Sales Price:
Natural gas ($/Mcf)	$	4.16	$	2.30
Oil ($/Bbl)	$	90.37	$	46.19
Average equivalent price ($/Mcfe)	$	8.46	$	3.81

Expenses ($ per Mcfe):
Production taxes	$	0.36	$	0.16
Gathering and transportation	$	0.20	$	0.22
Lease operating⁽¹⁾	$	0.92	$	0.97
Depreciation, depletion and amortization⁽²⁾	$	5.74	$	4.84

(1)	Includes ad valorem taxes.

(2)	Represents depreciation, depletion and amortization of oil and gas properties only.

Oil and gas sales. Our oil and gas sales decreased $302.8 million (55%) in 2015 to $252.4 million from $555.2 million in 2014. Oil sales decreased by $247.1 million (63%) from 2014 while our natural gas sales decreased by $55.7 million (34%) from 2014. The decrease in oil sales was attributable to the 28% decline in oil production and a 49% decrease in our realized oil price in 2015. Our natural gas production increased by 20% from 2014 while our realized natural gas price decreased by 45%. Our drilling activity in the Haynesville and Bossier shale fields in East Texas and North Louisiana generated the natural gas production growth.

Production taxes. Production taxes decreased $13.5 million or 57% to $10.3 million in 2015 from $23.8 million in 2014. The decrease in 2015 is due to the 63% decline in our oil sales during the year. Much of our natural gas sales in 2014 and 2015 qualified for temporary exemption from state production taxes.

Gathering and transportation. Gathering and transportation costs in 2015 increased $1.4 million (11%) to $14.3 million as compared to $12.9 million in 2014 due to the 20% increase in natural gas we produced during 2015. Gathering and transportation per Mcf produced improved from 2014 as the additional volumes produced in the Haynesville shale properties allowed us to lower our unit transportation costs.

Lease operating expenses. Our lease operating expenses, including ad valorem taxes, of $64.5 million in 2015 were $4.2 million or 7% higher than our operating expenses of $60.3 million in 2014. Our lease operating expense per Mcfe produced rose by 6% to $0.97 per Mcfe in 2015 as compared to $0.92 per Mcfe in 2014. The increase in operating costs mainly reflects the higher lifting costs associated with our oil wells including additional costs incurred related to adding artificial lift to many of our producing oil wells.

Exploration expense. We incurred $70.7 million in exploration expense in 2015 as compared to $19.4 million in 2014. Exploration expense in 2015 consisted of $69.0 million in impairments of unevaluated leasehold costs and $1.7 million in rig termination fees. Our 2014 exploration cost consisted of $11.8 million in dry hole costs, $6.7 million in rig termination fees, $0.5 million of impairments of unevaluated leasehold costs and $0.4 million for the acquisition of seismic data.

Depreciation, depletion and amortization expense (“DD&A”). DD&A of $321.3 million decreased by $57.0 million (15%) from DD&A of $378.3 million in 2014. Our DD&A rate per Mcfe produced averaged $4.84 in 2015 as compared to $5.74 for 2014. The decrease in DD&A expense and the DD&A rate primarily resulted from higher production from our lower cost natural gas properties.

General and administrative expenses. General and administrative expense of $23.5 million for 2015 was 27% lower than general and administrative expense of $32.4 million for 2014 primarily due to lower employee compensation in 2015 including stock based compensation which decreased to $8.1 million in 2015 as compared to $10.7 million in 2014.

Impairment of oil and gas properties. We assess the need for impairment of the capitalized costs for our oil and gas properties on a property basis. During 2015, with the substantial decline in management’s estimates of future oil and natural gas prices, we recognized an impairment charge of $801.3 million on our oil and gas properties. During 2014 we recognized an impairment charge of $60.3 million.

Derivative financial instruments. We utilized oil and natural gas price swaps to manage our exposure to commodity prices and protect returns on investment from our drilling activities. We had gains of $2.7 million and $8.2 million on derivative financial instruments in 2015 and 2014, respectively. Our total net cash received from derivative financial instruments was $1.2 million and $9.1 million in 2015 and 2014, respectively.

The following tables present our oil and natural gas prices before and after the effect of cash settlements of our derivative financial instruments:


Average Realized Natural Gas Price:	2014		2015
Natural gas, per Mcf	$	4.16	$	2.30
Cash settlements on derivative financial instruments, per Mcf		—		0.03

Price per Mcf, including cash settlements on derivative financial instruments	$	4.16	$	2.33


Average Realized Oil Price:	2014		2015
Oil, per barrel	$	90.37	$	46.19
Cash settlements on derivative financial instruments, per barrel		2.13		—

Price per barrel, including cash settlements on derivative financial instruments	$	92.50	$	46.19

Interest expense. Interest expense increased $60.0 million (102%) to $118.6 million in 2015 from interest expense of $58.6 million in 2014. The increase was primarily related to the refinancing of our bank credit facility with 10% secured senior notes in March 2015 and a reduction in the interest we capitalized in 2015. We issued $700.0 million of senior secured notes in March 2015. We capitalized interest of $0.9 million and $10.2 million in 2015 and 2014, respectively.

Income taxes. The benefit from income taxes from continuing operations increased in 2015 to $154.4 million from $24.7 million in 2014 due to the higher net loss in 2015. Our effective tax rate of 12.9% in 2015 differed from the federal income tax rate of 35% primarily due to a valuation allowance on deferred tax assets of $282.9 million.

Net loss. We reported a loss of $1.0 billion or $113.53 per share for 2015 as compared to a loss of $57.1 million or $6.20 per share for 2014. The loss in 2015 was primarily due to the oil and gas property impairment charges recognized, the loss on sale of oil and gas properties, lower oil and natural gas prices, higher exploration costs and higher interest expense. The net loss in 2014 was primarily due to impairments of proved and unproved properties, and other exploration costs.

Year Ended December 31, 2014 Compared to Year Ended December 31, 2013

Our operating data for 2013 and 2014 is summarized below:


	Year Ended December 31,
	2013		2014
Oil and Gas Sales (in thousands):
Natural gas sales	$	188,453	$	165,461
Oil sales		231,837		389,770

Total oil and gas sales	$	420,290	$	555,231


Net Production Data:
Natural gas (MMcf)		55,694		39,768
Oil (MBbls)		2,314		4,313
Natural gas equivalent (MMcfe)		69,577		65,645

Average Sales Price:
Natural gas ($/Mcf)	$	3.38	$	4.16
Oil ($/Bbl)	$	100.20	$	90.37
Average equivalent price ($/Mcfe)	$	6.04	$	8.46

Expenses ($ per Mcfe):
Production taxes	$	0.21	$	0.36
Gathering and transportation	$	0.25	$	0.20
Lease operating⁽¹⁾	$	0.76	$	0.92
Depreciation, depletion and amortization⁽²⁾	$	4.83	$	5.74

(1)	Includes ad valorem taxes.

(2)	Represents depreciation, depletion and amortization of oil and gas properties only.

Oil and gas sales. Our oil and gas sales increased $134.9 million (32%) in 2014 to $555.2 million from $420.3 million in 2013. Oil sales in 2014 increased by $157.9 million (68%) from 2013 while our natural gas sales decreased by $23.0 million (12%) from 2013. The increase in oil sales was attributable to the 86% growth in oil production offset by a 10% decrease in our realized oil prices in 2014. Our drilling activity in the Eagleville and Giddings fields in South Texas principally generated the growth in the oil production. With limited drilling in our natural gas properties in 2014, our natural gas production fell by 29% from 2013 while our realized natural gas prices increased by 23%.

Production taxes. Production taxes increased $9.3 million or 64% to $23.8 million in 2014 from $14.5 million in 2013. The increase in 2014 was due to the 68% growth in our oil sales during the year. Much of our natural gas sales in 2013 and 2014 qualified for a temporary exemption from state production taxes.

Gathering and transportation. Gathering and transportation costs in 2014 decreased $4.3 million (25%) to $12.9 million as compared to $17.2 million in 2013 due to the lower natural gas volumes that we produced in North Louisiana in 2014.

Lease operating expenses. Our lease operating expenses, including ad valorem taxes, of $60.3 million in 2014 were $7.5 million or 14% higher than our operating expenses of $52.8 million in 2013. Our lease operating expense per Mcfe produced increased by 21% to $0.92 per Mcfe in 2014 as compared to $0.76 per Mcfe in 2013. The increase in operating costs mainly reflects our growing oil production. Our oil wells are typically more costly to operate on a per Mcfe basis than our natural gas wells. The increase in our per unit costs is also partially attributable to the lower production on a Mcfe basis. Oil production comprised 39% of our total production in 2014 as compared to 20% in 2013.

Exploration expense. We incurred $19.4 million in exploration expense in 2014 as compared to $33.4 million in 2013. Exploration expense in 2014 consisted of $11.8 million in dry hole costs, $6.7 million in rig termination fees, $0.5 million of impairments of unevaluated leasehold costs and $0.4 million for the acquisition of seismic data. Our 2013 exploration cost consisted of $33.0 million of impairments of unevaluated leasehold costs and $0.4 million for the acquisition of seismic data.

Depreciation, depletion and amortization expense. DD&A of $378.3 million increased by $41.2 million (12%) from DD&A of $337.1 million in 2013. Our DD&A rate per Mcfe produced averaged $5.74 in 2014 as compared to $4.83 for 2013. The increase in DD&A primarily resulted from the increased development costs per Mcfe associated with the oil wells drilled in 2014 and 2013.

General and administrative expenses. General and administrative expense of $32.4 million for 2014 was 7% lower than general and administrative expense of $34.8 million for 2013. The decrease is primarily related to stock-based compensation which decreased by $2.1 million to $10.7 million in 2014 as compared to $12.8 million in 2013.

Impairment of oil and gas properties. We recorded impairments to our oil and gas properties of $60.3 million and $0.7 million in 2014 and 2013, respectively. These impairments relate to older, conventional oil and gas properties with declining production and limited potential for future investments.

Derivative financial instruments. We utilized oil price swaps to manage our exposure to oil prices and protect returns on investment from our drilling activities in 2013 and 2014. We had a gain of $8.2 million and a loss of $8.4 million on derivative financial instruments in 2014 and 2013, respectively. Our total net cash received from derivative financial instruments was $9.1 million in 2014 and $2.3 million in 2013.

The following table presents our crude oil equivalent prices before and after the effect of cash settlements of our derivative financial instruments:


Average Realized Oil Price:	2013		2014
Oil, per barrel	$	100.20	$	90.37
Cash settlements on derivative financial instruments, per barrel		0.99		2.13

Price per barrel, including cash settlements on derivative financial instruments	$	101.19	$	92.50

Interest expense. Interest expense decreased $14.6 million (20%) to $58.6 million in 2014 from interest expense of $73.2 million in 2013. The decrease was primarily related to lower interest expense due to the retirement in September 2013 of our 8³⁄₈% senior notes due in 2017. We capitalized interest of $10.2 million and $4.7 million in 2014 and 2013, respectively, which reduced interest expense. We had interest expense allocated to discontinued operations of $8.4 million in 2013 of which $2.0 million was capitalized. Average borrowings under our bank credit facility increased to $319.2 million in 2014 as compared to $201.5 million for 2013 and the average interest rate on the outstanding borrowings under our bank credit facility of 2.0% in 2014 was lower than the interest rate of 2.6% in 2013. Interest expense related to our outstanding senior notes decreased by 21% due to the retirement of our 8³⁄₈% senior notes offset partially by the issuance an additional $100.0 million of our 7³⁄₄% senior notes in 2014.

Income taxes. The benefit from income taxes from continuing operations decreased in 2014 to $24.7 million from $56.2 million in 2013 due to the lower net loss from continuing operations in 2014. Our effective tax rate of 30.2% in 2014 differed from the federal income tax rate of 35% primarily due to the effect of nondeductible compensation, state income taxes and an increase in the valuation allowance for state income tax net operating loss carry forwards.

Net loss. We reported a net loss from continuing operations of $57.1 million or $6.20 per share for 2014 as compared to a loss of $106.7 million or $11.09 per share for 2013. The net loss in 2014 was primarily due to impairments of proved and unproved properties and other exploration costs. The loss in 2013 was due to impairments of proved and unproved properties and a loss on early extinguishment of debt.

Net income from discontinued operations for 2013 of $147.8 million, or $15.36 per share, included a gain on the sale of our West Texas oil and gas properties of $230.0 million ($148.6 million after income taxes). Excluding the gain, the net loss from discontinued operations for the year ended December 31, 2013 was $0.8 million.

Liquidity and Capital Resources

Funding for our activities has historically been provided by our operating cash flow, debt or equity financings and asset dispositions. For 2015, our primary source of funds was operating cash flow, borrowings and net proceeds from asset sales. Cash provided by operating activities in 2015 of $30.1 million decreased $370.9 million from $401.0 million in 2014. Cash flow was lower than 2014 due to decreased revenues related to the decreased oil production and lower oil and gas prices along with higher interest expense from our senior notes issued in 2015. Our other primary source of funds in 2015 included net proceeds from our 10% senior secured notes offering of $683.8 million, $40.0 million of net borrowings under our bank credit facility and net proceeds from asset sales of $102.5 million.

In 2014, our primary source of funds was operating cash flow and borrowings. Cash provided by operating activities from continuing operations in 2014 of $401.0 million increased $132.0 million (49%) from $269.0 million in 2013 primarily due to the higher revenues related to increased oil production and higher natural gas prices in 2014. Our other primary source of funds during 2014 included $103.3 million of proceeds from an additional issuance of our 7³⁄₄% senior notes and $165.0 million of borrowings under our bank credit facility.

Our primary need for capital, in addition to funding our ongoing operations, relates to the acquisition, development and exploration of our oil and gas properties and servicing and retirement of our debt. In 2015, our capital expenditures of $243.2 million represented a decrease of $345.4 million as compared to 2014 capital expenditures of $588.6 million, mainly due to our significant reduction in drilling activity during 2015 in response to the low commodity price environment throughout the year. During 2014 our capital expenditures of $588.6 million represented an increase of $107.7 million as compared to 2013 capital expenditures of $480.9 million due primarily to our high level of drilling activity during 2014.

Our capital expenditure activity related to our continuing operations is summarized in the following table:


	Year Ended December 31,
	2013			2014			2015
	(In thousands)
Exploration and development:
Acquisitions of proved oil and gas properties	$	6,450		$	2,400		$	—
Acquisitions of unproved oil and gas properties		130,113			91,960			12,972
Developmental leasehold costs		461			3,386			767
Development drilling		317,241			398,604			184,393
Exploratory drilling		—			51,725			11,985
Other development costs		26,348			39,282			31,237

		480,613	⁽¹⁾		587,357	⁽¹⁾		241,354
Other		260			1,257			1,893

Total	$	480,873	⁽¹⁾	$	588,614	⁽¹⁾	$	243,247

(1)	Net of reimbursements received from joint venture partner of $51.5 million and $28.7 million in 2013 and 2014, respectively.

The timing of most of our capital expenditures is discretionary because we have no material long-term capital expenditure commitments except for contracted drilling and completion services. Consequently, we have a significant degree of flexibility to adjust the level of our capital expenditures as circumstances warrant. We currently expect to spend approximately $98.0 million in 2016 for development and exploration projects to drill nine wells. Our operating cash flow and, therefore, our capital expenditures are highly dependent on oil and natural gas prices that we realize in 2016. We operate most of our properties and have significant discretion over the amount and timing of our future capital expenditures.

We do not have a specific acquisition budget for 2016 because the timing and size of acquisitions are unpredictable. We intend to use borrowings under our bank credit facility, or other debt or equity financings to the extent available, to finance such acquisitions. The availability and attractiveness of these sources of financing will depend upon a number of factors, some of which will relate to our financial condition and performance and some of which will be beyond our control, such as prevailing interest rates, oil and natural gas prices and other market conditions. Lack of access to the debt or equity markets due to general economic conditions could impede our ability to complete acquisitions.

In March 2015, we issued $700.0 million of 10% senior secured notes (the “Secured Notes”) which are due on March 15, 2020. Interest on the Secured Notes is payable semi-annually on each March 15 and September 15. Net proceeds from the issuance of the Secured Notes of $683.8 million were used to retire our bank credit facility and for general corporate purposes. We also have outstanding (i) $376.1 million of 7³⁄₄% senior notes (the “2019 Notes”) which are due on April 1, 2019 and bear interest which is payable semi-annually on each April 1 and October 1 and (ii) $194.4 million of 9¹⁄₂% senior notes (the “2020 Notes”) which are due on June 15, 2020 and bear interest which is payable semi-annually on each June 15 and December 15. The Secured Notes are secured on a first priority basis equally and ratably with our revolving credit facility, subject to payment priorities in favor of the revolving credit facility by the collateral securing the revolving credit facility, which consists of, among other things, at least 80% of our and our subsidiaries’ oil and gas properties. The Secured Notes, the 2019 Notes and 2020 Notes are our general obligations and are guaranteed by all of our subsidiaries. Such subsidiary guarantors are 100% owned and all of the guarantees are full and unconditional and joint and several obligations. There are no restrictions on our ability to obtain funds from our subsidiaries through dividends or loans. As of December 31, 2015, we had no material assets or operations which are independent of our subsidiaries.

During 2015 we purchased $23.9 million in principal amount of the 2019 Notes and $105.6 million in principal amount of the 2020 Notes for an aggregate purchase price of $42.7 million. The gain of $82.4 million recognized on the purchase of the 2019 Notes and 2020 Notes and the loss resulting from the write-off of deferred loan costs associated with our prior bank credit facility of $3.7 million are included in the net gain on extinguishment of debt, which is reported as a component of other income (expense).

In connection with the issuance of the Secured Notes, we entered into a $50.0 million revolving credit facility with Bank of Montreal and Bank of America, N.A. The revolving credit facility is a four year commitment that matures on March 4, 2019. Indebtedness under the revolving credit facility is secured by substantially all of our and our subsidiaries’ assets and is guaranteed by all of our subsidiaries. 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 consolidated 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 of at least 1.0 to 1.0 and the maintenance of an asset coverage ratio of proved developed reserves to debt outstanding under the revolving credit facility of at least 2.5 to 1.0. We were in compliance with these covenants as of December 31, 2015.

We believe that our cash on hand and cash flow from operations and available borrowings under our bank credit facility is sufficient to fund our 2016 planned operating activities. If our plans or assumptions change or our assumptions prove to be inaccurate, we may be required to seek additional capital, including additional equity or debt financings to replace any liquidity that may be lost from low oil and natural gas prices. We cannot provide any assurance that we will be able to obtain such capital, or if such capital is available, that we will be able to obtain it on acceptable terms.

The following table summarizes our aggregate liabilities and commitments by year of maturity:


	2016		2017		2018		2019		2020		Thereafter		Total
	(In thousands)
10% senior secured notes	$	—	$	—	$	—	$	—	$	700,000	$	—	$	700,000
7³⁄₄% senior unsecured notes		—		—		—		376,090		—		—		376,090
9¹⁄₂% senior unsecured notes		—		—		—		—		194,367		—		194,367
Interest on debt		117,612		117,612		117,612		95,752		23,046		—		471,634
Operating leases		1,994		2,021		2,060		1,560		1,560		1,560		10,755
Natural gas transportation and treating agreements		2,199		1,780		1,696		690		—		—		6,365
Contracted drilling services		1,593		—		—		—		—		—		1,593

	$	123,398	$	121,413	$	121,368	$	474,092	$	918,973	$	1,560	$	1,760,804

Future interest costs are based upon the effective interest rates of our outstanding senior notes.

We have obligations to incur future payments for dismantlement, abandonment and restoration costs of oil and gas properties. These payments are currently estimated to be incurred primarily after 2020. We record a separate liability for the fair value of these asset retirement obligations, which totaled $20.1 million as of December 31, 2015.

Federal and State Taxation

We have $558.7 million in U.S. federal net operating loss carryforwards. The utilization of $34.7 million of the U.S. federal net operating loss carryforward is limited to approximately $1.1 million per year pursuant to a prior change of control of an acquired company. Accordingly, as of December 31, 2014, a valuation allowance of $23.0 million, with a tax effect of $8.0 million, has been established for the estimated U.S. federal net operating loss carryforwards that will not be utilized as a result of the change in control. As of December 31, 2015, we have also established a valuation allowance of $775.3 million, with a tax effect of $271.4 million, against our other U.S. federal net operating loss carryforwards that are not subject a change in control, due to the uncertainty of generating future taxable income prior to the expiration of the carry-over period. In addition, as of December 31, 2015, we have established a valuation allowance of $957.7 million, with a tax effect of $49.8 million, against our Louisiana state net deferred tax assets due to the uncertainty of generating taxable income in the state of Louisiana prior to the expiration of the carry-over period. As of December 31, 2014, we had a valuation allowance of $742.2 million, with a tax effect of $38.6 million, against our Louisiana state deferred tax assets.

Future use of our net operating loss carryforwards may be limited in 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 result in a substantial portion of our net operating loss carryforwards being eliminated or becoming restricted. We established a rights plan on October 1, 2015 to deter ownership changes that would trigger this limitation.

Our federal income tax returns for the years subsequent to December 31, 2011 remain subject to examination. Our income tax returns in one major state income tax jurisdiction remain subject to examination for the year ended December 31, 2008 and various periods subsequent to December 31, 2010. We currently believe that our significant filing positions are highly certain and that all of our other significant income tax filing positions and deductions would be sustained upon audit or the final resolution would not have a material effect on our consolidated financial statements. Therefore, we have not established any significant reserves for uncertain tax positions. Interest and penalties resulting from audits by tax authorities have been immaterial and are included in the provision for income taxes in the consolidated statements of operations.

Critical Accounting Policies

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires us to make estimates and use assumptions that can affect the reported amounts of assets, liabilities, revenues or expenses.

Successful efforts accounting. We are required to select among alternative acceptable accounting policies. There are two generally acceptable methods for accounting for oil and gas producing activities. The full cost method allows the capitalization of all costs associated with finding oil and natural gas reserves, including certain general and administrative expenses. The successful efforts method allows only for the capitalization of costs associated with developing proven oil and natural gas properties as well as exploration costs associated with successful exploration projects. Costs related to exploration that are not successful are expensed when it is determined that commercially productive oil and gas reserves were not found. We have elected to use the successful efforts method to account for our oil and gas activities and we do not capitalize any of our general and administrative expenses.

Oil and natural gas reserve quantities. The determination of depreciation, depletion and amortization expense is highly dependent on the estimates of the proved oil and natural gas reserves attributable to our properties. The determination of whether impairments should be recognized on our oil and gas properties is also dependent on these estimates, as well as estimates of probable reserves. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be precisely measured. The accuracy of any reserve estimate depends on the quality of available data, production history and engineering and geological interpretation and judgment. Because all reserve estimates are to some degree imprecise, the quantities and timing of oil and natural gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future oil and natural gas prices may all differ materially from those assumed in these estimates. The information regarding present value of the future net cash flows attributable to our proved oil and natural gas reserves are estimates only and should not be construed as the current market value of the estimated oil and natural gas reserves attributable to our properties. Thus, such information includes revisions of certain reserve estimates attributable to proved properties included in the preceding year’s estimates. Such revisions reflect additional information from subsequent activities, production history of the properties involved and any adjustments in the projected economic life of such properties resulting from changes in product prices. Any future downward revisions could adversely affect our financial condition, our future prospects and the value of our common stock.

Impairment of oil and gas properties. We evaluate our properties on a field area basis for potential impairment when circumstances indicate that the carrying value of an asset may not be recoverable. If impairment is indicated based on a comparison of the asset’s carrying value to its undiscounted expected future net cash flows, then it is recognized to the extent that the carrying value exceeds fair value. A significant amount of judgment is involved in performing these evaluations since the results are based on estimated future events. Expected future cash flows are determined using estimated future prices based on market based forward prices applied to projected future production volumes. The projected production volumes are based on the property’s proved and risk adjusted probable oil and natural gas reserves estimates at the end of the period. At December 31, 2015, we excluded probable undeveloped reserves from our impairment analysis given our limited capital resources available for future drilling activities. The estimated future cash flows that we use in our assessment of the need for an impairment are based on a corporate forecast which considers forecasts from multiple independent price forecasts. Prices are not escalated to levels that exceed observed historical market prices. Costs are also assumed to escalate at a rate that is based on our historical experience, currently estimated at 2% per annum. The oil and natural gas prices used for determining asset impairments will generally differ from those used in the standardized measure of discounted future net cash flows because the standardized measure requires the use of the average first day of the month historical price for the year. During 2015, our oil and natural gas price outlook declined significantly and our access to capital to develop our proved and probable undeveloped reserves was limited. Accordingly, we recognized impairment charges of $801.3 million to reduce the capitalized costs of our evaluated oil and natural gas properties. It is reasonably possible that our 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 impairments in the carrying values of our evaluated oil and gas properties. Specifically, as part of the impairment review performed at December 31, 2015, we observed that a decline in excess of 30% for our future cash flow estimates for our Eagleville field in South Texas could result in an additional impairment being recorded in an amount that could be at least $130.0 million. In addition, we may recognize additional impairments of our unevaluated oil and gas properties should we determine that we no longer intend to retain these propertied for future oil and natural gas development.

Income Taxes. The Company accounts for income taxes using the asset and liability method, whereby deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their respective tax basis, as well as the future tax consequences attributable to the future utilization of existing tax net operating loss and other types of carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that the change in rate is enacted.

In recording deferred income tax assets, we consider whether it is more likely than not that some portion or all of our 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. We believe that after considering all the available objective evidence, historical and prospective, with greater weight given to historical evidence, we are not able to determine that it is more likely than not that all of our deferred tax assets will be realized. As a result, in 2015 we established an additional valuation allowance of $775.3 million, with a tax effect of $271.4 million, for our estimated U.S. federal net operating loss carryforwards and other U.S. federal tax assets and an additional valuation allowance of $215.5 million, with a tax effect of $11.2 million, for our estimated Louisiana state net operating loss carryforwards that are not expected be utilized due to the uncertainty of generating taxable income prior to the expiration of the respective U.S. federal and Louisiana state carry-over periods. We will continue to assess the valuation allowance against deferred tax assets considering all available information obtained in future reporting periods.

Stock-based compensation. We follow the fair value based method in accounting for equity-based compensation. Under the fair value based method, compensation cost is measured at the grant date based on the fair value of the award and is recognized on a straight-line basis over the award vesting period.

Recent accounting pronouncements. In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“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 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. We are currently evaluating the new guidance and have not determined the impact this standard may have on our financial statements or decided upon the method of adoption.

In August 2014, the FASB issued ASU No. 2014-15, Presentation of Financial Statements—Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern (“ASU 2014-15”). ASU 2014-15 provides guidance about management’s responsibility to evaluate whether there is substantial doubt about an entity’s ability to continue as a going concern and sets rules for how this information should be disclosed in the financial statements. ASU 2014-15 is effective for annual periods ending after December 15, 2016 and interim periods thereafter. Early adoption is permitted. We have elected to not adopt ASU 2014-15 early and do not expect adoption of ASU 2014-15 to have any impact on our consolidated financial condition, results of operations or cash flows.

Related Party Transactions

Along with M. Jay Allison, our Chairman and CEO, and Roland O. Burns, our President, Chief Financial Officer and a director, we formed an entity in 2010 in which we jointly owned and operated a private airplane. The entity was owned 80% by us and 10% by each of Messrs. Allison and Burns. Each party funded their respective share of the acquisition costs of the airplane in exchange for their ownership interest. This arrangement was approved by our audit committee and board of directors. In January 2015, we acquired from Messrs. Allison and Burns their collective 20% interest in the entity for aggregate consideration of $1,680,000, which amount was based upon the then fair market value of the airplane (the only asset owned by the entity). The airplane is leased to and managed by a third party operator. The airplane, which is intended to be used primarily for company business, also provides charter services to third parties. The termination of this related party relationship was approved by our audit committee and the board of directors in accordance with our policy on related party transactions. We have not entered into any other business transactions with our significant stockholders or any other related parties.

EX-99.4

Exhibit 99.4

ITEM 12.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

The following table summarizes certain information regarding our equity compensation plans as of December 31, 2015. All share and per share amounts below have been adjusted to give effect to the Company’s one-for-five (1:5) reverse stock split that became effective after the market closed on July 29, 2016:


	Number of securities to be issued upon exercise of outstanding options, warrants and rights			Weighted average exercise price of outstanding options, warrants and rights		Number of securities authorized for future issuance under equity compensation plans (excluding outstanding options, warrants and rights)
Equity compensation plans approved by stockholders		291,765	⁽¹⁾	$	166.10		191,569

(1)	Includes performance share unit awards equivalent to 1,400,173 shares that would be issuable based upon achievement of the maximum awards under the terms of the performance share unit awards.

We do not have any equity compensation plans that were not approved by stockholders.

EX-99.5

Exhibit 99.5

ITEM 15 (a) FINANCIAL STATEMENTS

COMSTOCK RESOURCES, INC. AND SUBSIDIARIES

FINANCIAL STATEMENTS

INDEX


Report of Independent Registered Public Accounting Firm			F-2

Consolidated Balance Sheets as of December 31, 2014 and 2015			F-3

Consolidated Statements of Operations for the Years Ended December 31, 2013, 2014 and 2015			F-4

Consolidated Statements of Comprehensive Income (Loss) for the Years Ended December 31, 2013, 2014 and 2015			F-5

Consolidated Statements of Stockholders’ Equity (Deficit) for the Years Ended December 31, 2013, 2014 and 2015			F-6

Consolidated Statements of Cash Flows for the Years Ended December 31, 2013, 2014 and 2015			F-7

Notes to Consolidated Financial Statements			F-8

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders

Comstock Resources, Inc.

We have audited the accompanying consolidated balance sheets of Comstock Resources, Inc. and subsidiaries as of December 31, 2014 and 2015, and the related consolidated statements of operations, comprehensive income (loss), stockholders’ equity (deficit) and cash flows for each of the three years in the period ended December 31, 2015. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Comstock Resources, Inc. and subsidiaries at December 31, 2014 and 2015, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2015, in conformity with accounting principles generally accepted in the United States.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Comstock Resources, Inc.’s internal control over financial reporting as of December 31, 2015, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated February 26, 2016 expressed an unqualified opinion thereon.

/s/ ERNST & YOUNG LLP

Dallas, Texas

February 26, 2016,

except for Notes 1, 6, 7 and 11 as to the effect of

the reverse stock split, as to which the date is August 1, 2016.

F-2

COMSTOCK RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

As of December 31, 2014 and 2015


	December 31,
	2014			2015

	(In thousands)
ASSETS

Cash and Cash Equivalents	$	2,071		$	134,006
Accounts Receivable:
Oil and gas sales		32,849			15,241
Joint interest operations		16,192			3,552
Derivative Financial Instruments		—			1,446
Other Current Assets		10,105			1,993

Total current assets		61,217			156,238
Property and Equipment:
Unevaluated oil and gas properties		201,459			84,144
Oil and gas properties, successful efforts method		4,282,088			4,332,222
Other		19,630			19,521
Accumulated depreciation, depletion and amortization		(2,305,008	)		(3,397,467	)

Net property and equipment		2,198,169			1,038,420
Other Assets		5,160			1,192

	$	2,264,546		$	1,195,850


LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT)

Accounts Payable	$	117,329		$	57,276
Accrued Expenses		44,842			38,444

Total current liabilities		162,171			95,720
Long-term Debt		1,060,654			1,249,330
Deferred Income Taxes Payable		154,547			1,965
Reserve for Future Abandonment Costs		14,900			20,093
Other Non-Current Liabilities		2,002			—

Total liabilities		1,394,274			1,367,108
Commitments and Contingencies
Stockholders’ Equity (Deficit):
Common stock—$0.50 par, 15,000,000 shares authorized, 9,371,683 and 9,544,035 shares issued and outstanding at December 31, 2014 and 2015, respectively		4,686			4,772
Additional paid-in capital		499,177			504,670
Accumulated earnings (deficit)		366,409			(680,700	)

Total stockholders’ equity (deficit)		870,272			(171,258	)

	$	2,264,546		$	1,195,850

The accompanying notes are an integral part of these statements.

F-3

COMSTOCK RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

For the Years Ended December 31, 2013, 2014 and 2015


	2013			2014			2015

	(In thousands, except per share amounts)

Natural gas sales	$	188,453		$	165,461		$	109,753
Oil sales		231,837			389,770			142,669

Total oil and gas sales		420,290			555,231			252,422
Operating expenses:
Production taxes		14,524			23,797			10,286
Gathering and transportation		17,245			12,897			14,298
Lease operating		52,844			60,283			64,502
Exploration		33,423			19,403			70,694
Depreciation, depletion and amortization		337,134			378,275			321,323
General and administrative, net		34,767			32,379			23,541
Impairment of oil and gas properties		652			60,268			801,347
Loss on sale of oil and gas properties		2,033			—			112,085

Total operating expenses		492,622			587,302			1,418,076

Operating loss		(72,332	)		(32,071	)		(1,165,654	)
Other income (expenses):
Gain on sale of marketable securities		7,877			—			—
Gain (loss) from derivative financial instruments		(8,388	)		8,175			2,676
Net gain (loss) on extinguishment of debt		(17,854	)		—			78,741
Other income		1,059			727			1,275
Interest expense		(73,242	)		(58,631	)		(118,592	)

Total other income (expenses)		(90,548	)		(49,729	)		(35,900	)

Loss from continuing operations before income taxes		(162,880	)		(81,800	)		(1,201,554	)
Benefit from income taxes		56,157			24,689			154,445

Loss from continuing operations		(106,723	)		(57,111	)		(1,047,109	)
Income from discontinued operations, net of income taxes		147,752			—			—

Net income (loss)	$	41,029		$	(57,111	)	$	(1,047,109	)

Net income (loss) per share:
Basic and diluted —loss from continuing operations	$	(11.09	)	$	(6.20	)	$	(113.53	)
—income from discontinued operations		15.36			—			—

—net income (loss)	$	4.27		$	(6.20	)	$	(113.53	)

Dividends per common share	$	1.88		$	2.50		$	—

Basic and diluted weighted average shares outstanding		9,311			9,309			9,223

The accompanying notes are an integral part of these statements.

F-4

COMSTOCK RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

For the Years Ended December 31, 2013, 2014 and 2015


	2013			2014			2015

	(In thousands)

Net income (loss)	$	41,029		$	(57,111	)	$	(1,047,109	)
Other comprehensive income (loss):
Realized gains on marketable securities reclassified to gain on sale of marketable securities, net of a benefit from income taxes of $2,757 in 2013		(5,120	)		—			—
Unrealized gains on marketable securities, net of a provision for income taxes of $377 in 2013		702			—			—

Other comprehensive loss		(4,418	)		—			—

Total comprehensive income (loss)	$	36,611		$	(57,111	)	$	(1,047,109	)

The accompanying notes are an integral part of these statements.

F-5

COMSTOCK RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (DEFICIT)

For the Years Ended December 31, 2013, 2014 and 2015


	Common Shares			Common Stock- Par Value			Additional Paid-in Capital			Accumulated Earnings (Deficit)			Accumulated Other Comprehensive Income			Total

	(In thousands)

Balance at December 31, 2012		9,682		$	4,841		$	499,958		$	424,317		$	4,418		$	933,534
Stock-based compensation		3			2			12,783			—			—			12,785
Tax withholdings related to stock grants		(22	)		(11	)		(1,669	)		—			—			(1,680	)
Excess income taxes from stock-based compensation		—			—			(2,016	)		—			—			(2,016	)
Repurchases of common stock		(127	)		(64	)		(9,168	)		—			—			(9,232	)
Net income		—			—			—			41,029			—			41,029
Other comprehensive loss		—			—			—			—			(4,418	)		(4,418	)
Dividends paid		—			—			—			(17,997	)		—			(17,997	)

Balance at December 31, 2013		9,536			4,768			499,888			447,349			—			952,005
Stock-based compensation		62			31			10,666			—			—			10,697
Tax withholdings related to stock grants		(26	)		(13	)		(2,336	)		—			—			(2,349	)
Excess income taxes from stock-based compensation		—			—			(1,055	)		—			—			(1,055	)
Repurchases of common stock		(200	)		(100	)		(7,986	)		—			—			(8,086	)
Net loss		—			—			—			(57,111	)		—			(57,111	)
Dividends paid		—			—			—			(23,829	)		—			(23,829	)

Balance at December 31, 2014		9,372			4,686			499,177			366,409			—			870,272
Stock-based compensation		188			94			8,055			—			—			8,149
Tax withholdings related to stock grants		(16	)		(8	)		(518	)		—			—			(526	)
Excess income taxes from stock-based compensation		—			—			(2,044	)		—			—			(2,044	)
Net loss		—			—			—			(1,047,109	)		—			(1,047,109	)

Balance at December 31, 2015		9,544		$	4,772		$	504,670		$	(680,700	)	$	—		$	(171,258	)

The accompanying notes are an integral part of these statements.

F-6

COMSTOCK RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Years Ended December 31, 2013, 2014 and 2015


	2013			2014			2015

	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	41,029		$	(57,111	)	$	(1,047,109	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Income from discontinued operations		(147,752	)		—			—
Loss (gain) on sale of assets		(5,844	)		—			112,085
Deferred income taxes		(56,291	)		(24,677	)		(155,249	)
Dry hole costs, leasehold impairments and other exploration costs		32,984			19,003			70,694
Impairment of oil and gas properties		652			60,268			801,347
Depreciation, depletion and amortization		337,134			378,275			321,323
(Gain) loss on derivative financial instruments		8,388			(8,175	)		(2,676	)
Cash settlements of derivative financial instruments		2,293			9,145			1,230
Net loss (gain) on extinguishment of debt		17,854			—			(78,741	)
Amortization of debt discount, premium and issuance costs		6,074			4,097			5,144
Stock-based compensation		12,785			10,697			8,149
Excess income taxes from stock-based compensation		2,016			1,055			2,044
Decrease (increase) in accounts receivable		(12,674	)		2,221			30,248
Decrease (increase) in other current assets		3,459			(7,366	)		8,112
Increase (decrease) in accounts payable and accrued expenses		26,887			13,552			(46,515	)

Net cash provided by continuing operations		268,994			400,984			30,086
Net cash used for discontinued operations		(7,715	)		—			—

Net cash provided by operating activities		261,279			400,984			30,086

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(422,244	)		(634,787	)		(264,210	)
Proceeds from sales of oil and gas properties		174			—			102,485
Proceeds from sales of marketable securities		13,392			—			—

Net cash used for continuing operations		(408,678	)		(634,787	)		(161,725	)
Cash flow from investing activities of discontinued operations:
Capital expenditures		(101,037	)		—			—
Proceeds from sale of oil and gas properties		823,072			—			—

Net cash provided by discontinued operations		722,035			—			—

Net cash provided by (used for) investing activities		313,357			(634,787	)		(161,725	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings		305,000			370,750			790,000
Principal payments on debt		(835,000	)		(100,000	)		(507,655	)
Costs related to extinguishment of debt		(12,471	)		—			—
Debt issuance costs		(2,744	)		(2,524	)		(16,201	)
Tax withholding related to stock grants		(1,680	)		(2,349	)		(526	)
Repurchases of common stock		(9,232	)		(8,086	)		—
Excess income taxes from stock-based compensation		(2,016	)		(1,055	)		(2,044	)
Dividends paid		(17,997	)		(23,829	)		—

Net cash provided by (used for) financing activities		(576,140	)		232,907			263,574

Net increase (decrease) in cash and cash equivalents		(1,504	)		(896	)		131,935
Cash and cash equivalents, beginning of the year		4,471			2,967			2,071

Cash and cash equivalents, end of the year	$	2,967		$	2,071		$	134,006

The accompanying notes are an integral part of these statements.

F-7

COMSTOCK RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1) Summary of Significant Accounting Policies

Accounting policies used by Comstock Resources, Inc. and subsidiaries reflect oil and natural gas industry practices and conform to accounting principles generally accepted in the United States of America.

Basis of Presentation and Principles of Consolidation

Comstock Resources, Inc. and its subsidiaries are engaged in oil and natural gas exploration, development and production, and the acquisition of producing oil and natural gas properties. The Company’s operations are primarily focused in Texas, Louisiana and Mississippi. The consolidated financial statements include the accounts of Comstock Resources, Inc. and its wholly owned or controlled subsidiaries (collectively, “Comstock” or the “Company”). All significant intercompany accounts and transactions have been eliminated in consolidation. The Company accounts for its undivided interest in oil and gas properties using the proportionate consolidation method, whereby its share of assets, liabilities, revenues and expenses are included in its financial statements.

The Company’s Board of Directors has authorized a one-for-five (1:5) reverse split of its issued and outstanding common stock which became effective on July 29, 2016. All amounts disclosed in these financial statements have been adjusted to give effect to the effect of this reverse stock split in all periods.

Reclassifications

Certain reclassifications have been made to prior periods’ financial statements, consisting primarily of reclassifications of the presentation of debt issuance costs as a reduction in long term debt and presentation of current deferred income taxes as non-current due to the early adoption of new accounting standards.

Use of Estimates in the Preparation of Financial Statements

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual amounts could differ from those estimates. Changes in the future estimated oil and natural gas reserves or the estimated future cash flows attributable to the reserves that are utilized for impairment analyses could have a significant impact on the future results of operations.

Concentration of Credit Risk and Accounts Receivable

Financial instruments that potentially subject the Company to a concentration of credit risk consist principally of cash and cash equivalents, accounts receivable and derivative financial instruments. The Company places its cash with high credit quality financial institutions and its derivative financial instruments with financial institutions and other firms that management believes have high credit ratings. Substantially all of the Company’s accounts receivable are due from either purchasers of oil and gas or participants in oil and gas wells for which the Company serves as the operator. Generally, operators of oil and gas wells have the right to offset future revenues against unpaid charges related to operated wells. Oil and gas sales are generally unsecured. The Company’s policy is to assess the collectability of its receivables based upon their age, the credit quality of the purchaser or participant and the potential for revenue offset. The Company has not had any significant credit losses in the past and believes its accounts receivable are fully collectible. Accordingly, no allowance for doubtful accounts has been provided.

F-8

Marketable Securities

During 2013, the Company sold 600,000 shares of Stone Energy Corporation common stock for proceeds of $13.4 million. Realized gains before income taxes of $7.9 million on these sales during 2013 are included in gain on sale of marketable securities in the consolidated statements of operations.

Other Current Assets

Other current assets at December 31, 2014 and 2015 consist of the following:


	As of December 31,
	2014		2015
	(In thousands)
Settlements receivable on derivative financial instruments	$	7,890	$	—
Pipe and oil field equipment inventory		1,379		1,198
Other		836		795

	$	10,105	$	1,993

Fair Value Measurements

Certain accounts within the Company’s consolidated balance sheets are required to be measured at fair value on a recurring basis. These include 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 cash and cash equivalents valuation is based on Level 1 measurements. The Company’s oil and natural gas price swap agreements were not traded on a public 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.

F-9

The following table summarizes financial assets accounted for at fair value as of December 31, 2015:


	Carrying Value Measured at Fair Value at December 31, 2015		Level 1		Level 2
	(In thousands)
Assets measured at fair value on a recurring basis:
Cash and cash equivalents	$	134,006	$	134,006	$	—
Derivative financial instruments		1,446		—		1,446

Total assets	$	135,452	$	134,006	$	1,446

At December 31, 2015, the Company had natural gas price swap agreements covering approximately 1.8 Bcf of natural gas to be produced in 2016 with a fair value of $1.4 million. The Company has recognized an asset for this amount and has recognized a corresponding gain representing the change in fair value of its natural gas swaps as a component of other income (expense). The Company had no derivative financial instruments outstanding at December 31, 2014.

The following table presents the carrying amounts and estimated fair value of the Company’s long-term debt as of December 31, 2014 and 2015:


	2014			2015
	(In thousands)
Fixed rate debt:
Principal amount	$	700,000		$	1,270,457
Discount or premium		(4,555	)		(1,457	)

Carrying value	$	695,445		$	1,269,000

Fair Value	$	453,000		$	428,767

Variable rate debt:
Carrying value	$	375,000		$	—

Fair value	$	375,000		$	—

The fair market value of the Company’s fixed rate debt was based on quoted prices as of December 31, 2014 and 2015, a Level 2 measurement. The fair value of the floating rate debt outstanding at December 31, 2014 approximated its carrying value, a Level 2 measurement.

Property and Equipment

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. Acquisition costs for proved oil and gas properties, costs of drilling and equipping productive wells, and costs of unsuccessful development wells are capitalized and amortized on an equivalent unit-of-production basis over the life of the remaining related oil and gas reserves. Equivalent units are determined by converting oil to natural gas at the ratio of one barrel of oil for six thousand cubic feet of natural gas. This conversion ratio is not based on the price of oil or natural gas, and there may be a significant difference in price between an equivalent volume of oil versus natural gas. Amortization is calculated at the field level. The estimated future costs of dismantlement, restoration, plugging and abandonment of oil and gas properties and related facilities disposal are capitalized when asset retirement obligations are incurred and amortized as part of depreciation, depletion and amortization expense. The costs of unproved properties which are determined to be productive are transferred to proved oil and gas properties and amortized on an equivalent

F-10

unit-of-production basis. Exploratory expenses, including geological and geophysical expenses and delay rentals for unevaluated oil and gas properties, are charged to expense as incurred. Unproved oil and gas properties are periodically assessed for impairment on a property by property basis, and any impairment in value is charged to exploration expense. During 2013, 2014 and 2015, impairment charges of $33.0 million, $0.5 million and $68.9 million, respectively, were recognized in exploration expense related to certain leases that the Company no longer expects to drill on. Exploratory drilling costs are initially capitalized as unproved property but charged to expense if and when the well is determined not to have found commercial quantities of proved oil and gas reserves. Exploratory drilling costs are evaluated within a one-year period after the completion of drilling.

The Company periodically assesses the need for an impairment of the costs capitalized for its evaluated oil and gas properties on a property or cost center basis. If impairment is indicated based on undiscounted expected future cash flows attributable to the property, then a provision for impairment is recognized to the extent that net capitalized costs exceed the estimated fair value of the property. The Company determines the fair values of its oil and gas properties using a discounted cash flow model and proved and risk-adjusted probable reserves. Undrilled acreage is valued based on sales transactions in comparable areas. At December 31, 2015, the Company excluded probable undeveloped reserves from its impairment analysis given the Company’s limited capital resources available for future drilling activities. 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 reserves and risk-adjusted probable 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. The oil and natural gas prices used for determining asset impairments will generally differ from those used in the standardized measure of discounted future net cash flows because the standardized measure requires the use of an average price based on the first day of each month of the preceding year and is limited to proved reserves.

In 2015, reductions to management’s oil and natural gas price outlook resulted in indications of impairment of the Company’s oil properties in South Texas and Mississippi, and certain of its natural gas properties in Texas and Louisiana. The following table presents the fair value and impairments recorded by the Company in the third quarter and fourth quarter of 2015, as well as the average oil price per barrel and gas price per thousand cubic feet over the life of the properties and the applicable discount rates utilized in the Company’s assessments:


	Fair Value		Impairment		Management’s Price Outlook				Annual Discount Rate
	Fair Value		Impairment		Oil		Gas		Annual Discount Rate
	(In thousands)				(Per barrel)		(Per Mcf)
Impairments recorded at September 30, 2015:
Oil properties	$	330,257	$	405,308	$	73.70	$	4.04		10%-20%
Natural gas properties	$	61,625	$	139,406	$	75.91	$	3.91		10%-20%

Impairments recorded at December 31, 2015:
Oil properties	$	3,030	$	16,036	$	73.48				10%-20%
Natural gas properties	$	123,926	$	238,210	$	70.76	$	3.74		10%-20%

In the aggregate we recognized impairments of $801.3 million related to our evaluated oil and gas properties in 2015. In 2014, the Company recognized impairment charges of $60.3 million on certain of its oil and gas properties which had a fair value of $18.0 million.

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 and possible 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

F-11

impairments in the carrying values of these or other properties. Specifically, as part of the impairment review performed at December 31, 2015, the Company observed that a decline in excess of 30% in its future cash flow estimates for its Eagleville field in South Texas could result in an additional impairment being recorded in an amount that could be at least $130.0 million.

Other property and equipment consists primarily of gas gathering systems, computer equipment, furniture and fixtures and an airplane which are depreciated over estimated useful lives ranging from three to 31¹⁄₂ years on a straight-line basis. In January 2015, the Company purchased a 20% interest in an airplane that previously had been owned 80% by the Company and 20% by two executive officers of the Company. The purchase price for the 20% interest of $1.7 million was based on the then fair market value of the airplane determined by a third party. This related party transaction was approved by the Company’s audit committee and board of directors.

Other Assets

Other assets primarily consist of deferred costs associated with the Company’s bank credit facility. These costs are amortized over the life of the bank credit facility on a straight-line basis which approximates the amortization that would be calculated using an effective interest rate method.

Accrued Expenses

Accrued expenses at December 31, 2014 and 2015 consist of the following:


	As of December 31,
	2014		2015
	(In thousands)
Accrued drilling costs	$	26,269	$	5,306
Accrued interest payable		9,011		29,075
Accrued rig termination fees		2,600		—
Other		6,962		4,063

	$	44,842	$	38,444

Reserve for Future Abandonment Costs

The Company’s asset retirement obligations relate to future plugging and abandonment costs of its oil and gas properties and related facilities disposal. The Company records a liability in the period in which an asset retirement obligation is incurred, in an amount equal to the estimated fair value of the obligation that is capitalized. Thereafter, this liability is accreted up to the final retirement cost. Accretion of the discount is included as part of depreciation, depletion and amortization in the accompanying consolidated statements of operations.

The following table summarizes the changes in the Company’s total estimated liability:


	2014			2015
	(In thousands)
Reserve for Future Abandonment Costs at beginning of the year	$	14,534		$	14,900
New wells placed on production		1,480			310
Changes in estimates and timing		(1,796	)		4,927
Liabilities settled and assets disposed of		(153	)		(717	)
Accretion expense		835			673

Reserve for Future Abandonment Costs at end of the year	$	14,900		$	20,093

F-12

Stock-based Compensation

The Company has stock-based employee compensation plans under which stock awards, comprised of restricted stock and performance share units, are issued to employees and non-employee directors. The Company follows the fair value based method in accounting for equity-based compensation. Under the fair value based method, compensation cost is measured at the grant date based on the fair value of the award and is recognized on a straight-line basis over the award vesting period. Excess taxes on stock-based compensation are recognized as an adjustment to additional paid-in capital and as a part of cash flows from financing activities.

Segment Reporting

The Company presently operates in one business segment, the exploration and production of oil and natural gas.

Derivative Financial Instruments and Hedging Activities

The Company accounts for derivative financial instruments (including certain derivative instruments embedded in other contracts) as either an asset or liability measured at its fair value. Changes in the fair value of derivatives are recognized currently in earnings unless specific hedge accounting criteria are met. The Company estimates fair value based on a discounted cash flow model. The fair value of derivative contracts that expire in less than one year are recognized as current assets or liabilities. Those that expire in more than one year are recognized as long-term assets or liabilities. If the derivative is designated as a cash flow hedge, changes in fair value are recognized in other comprehensive income until the hedged item is recognized in earnings.

Major Purchasers

The Company has one major purchaser of its oil production that represented 36%, 35% and 25% of its total oil and gas sales in 2013, 2014 and 2015, respectively. The Company also has one major purchaser of its natural gas production that represented 51%, 53% and 52% of its total oil and gas sales in 2013, 2014 and 2015, respectively. The loss of any of these purchasers would not have a material adverse effect on the Company as there is an available market for its oil and natural gas production from other purchasers.

Revenue Recognition and Gas Balancing

Comstock utilizes the sales method of accounting for oil and natural gas revenues whereby revenues are recognized at the time of delivery based on the amount of oil or natural gas sold to purchasers. Revenue is typically recorded in the month of production based on an estimate of the Company’s share of volumes produced and prices realized. 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, 2014 or 2015. Sales of oil and natural gas generally occur at 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 operating expenses.

General and Administrative Expenses

General and administrative expenses are reported net of reimbursements of overhead costs that are received from working interest owners of the oil and gas properties operated by the Company of $11.9 million, $13.2 million and $13.9 million in 2013, 2014 and 2015, respectively.

Income Taxes

The Company accounts for income taxes using the asset and liability method, whereby deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial

F-13

statement carrying amounts of assets and liabilities and their respective tax basis, as well as the future tax consequences attributable to the future utilization of existing tax net operating loss and other types of carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that the change in rate is enacted.

Earnings Per Share

Basic earnings per share is determined without the effect of any outstanding potentially dilutive stock options and diluted earnings per share is determined with the effect of outstanding stock options that are potentially dilutive. Unvested share-based payment awards containing nonforfeitable rights to dividends are considered to be participatory securities and included in the computation of basic and diluted earnings per share pursuant to the two-class method. Performance share units (“PSUs”) represent the right to receive a number of shares of the Company’s common stock that may range from zero to up to three 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. The treasury stock method is used to measure the dilutive effect of PSUs.

Basic and diluted earnings per share for 2013, 2014 and 2015 were determined as follows:


	2013								2014								2015
	Income (Loss)			Shares		Per Share			Loss			Shares		Per Share			Loss			Shares		Per Share
	(In thousands except per share data)
Net Loss From Continuing Operations	$	(106,723	)						$	(57,111	)						$	(1,047,109	)
Loss (Income) Allocable to Unvested Stock Grants		3,424								(595	)							—

Basic and Diluted Net Loss From Continuing Operations Attributable to Common Stock	$	(103,299	)		9,311	$	(11.09	)	$	(57,706	)		9,309	$	(6.20	)	$	(1,047,109	)		9,223	$	(113.53	)

Net Income From Discontinued Operations	$	147,752
Income Allocable to Unvested Stock Grants		(4,742	)

Basic and Diluted Net Income From Discontinued Operations Attributable to Common Stock	$	143,010			9,311	$	15.36

Basic and diluted per share amounts are the same for each of the years ended December 31, 2013, 2014, and 2015 due to the net loss from continuing operations reported during each of those years.

F-14

At December 31, 2013, 2014 and 2015, 303,178, 241,505 and 314,060 shares of unvested 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. Weighted average shares of unvested restricted stock included in common stock outstanding were as follows:

2013

2014

2015

(In thousands)

Unvested restricted stock

309

238

293

All stock options and PSUs were anti-dilutive to earnings and excluded from weighted average shares used in the computation of earnings per share due to the net loss from continuing operations in each period.

Options to purchase common stock and PSUs that were outstanding and that were excluded as anti-dilutive from determination of diluted earnings per share were as follows:


	2013	2014	2015
	(In thousands except per share data)
Weighted average anti-dilutive stock options	26	23	20
Weighted average exercise price	$164.50	$164.50	$164.75
Weighted average performance share units	51	100	136
Weighted average grant date fair value per unit	$104.60	$99.40	$35.35

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 years ended December 31, 2013, 2014 and 2015, respectively, were as follows:


	2013		2014		2015
	(In thousands)
Cash Payments:
Interest payments	$	83,560	$	62,812	$	94,177
Income tax payments	$	769	$	682	$	77

The Company capitalizes interest on its unevaluated oil and gas property costs during periods when it is conducting exploration activity on this acreage. The Company capitalized interest of $4.7 million, $10.2 million and $0.9 million in 2013, 2014 and 2015, respectively, which reduced interest expense and increased the carrying value of its unevaluated oil and gas properties.

Discontinued West Texas Operations

In May 2013, the Company sold its oil and gas properties in the Delaware Basin located in Reeves County in West Texas which it acquired in December 2011 and certain other undeveloped leases in West Texas (the “West Texas Properties”) to a third party. The Company received proceeds of $823.1 million and realized a gain of $230.0 million which is reflected as a component of income from discontinued operations in 2013. As a result of this divestiture, the consolidated financial statements and the related notes thereto present the results of the Company’s West Texas Properties as discontinued operations. No general and administrative cost incurred by Comstock was allocated to discontinued operations during the periods presented. Unless indicated otherwise, the amounts presented in the accompanying notes to the consolidated financial statements relate to the Company’s continuing operations.

F-15

Income from discontinued operations is comprised of the following:


	Year Ended December 31, 2013
	(In thousands)
Revenues:
Oil and gas sales	$	25,125

Costs and expenses:
Production taxes		1,120
Gathering and transportation		501
Lease operating		9,853
Depletion, depreciation and amortization		8,649
Interest expense⁽¹⁾		6,346

Total costs and expenses		26,469

Gain on sale		230,008

Income from discontinued operations before income taxes		228,664

Income tax expense:
Current		(2,218	)
Deferred		(78,694	)

Total income tax expense		(80,912	)

Net income from discontinued operations	$	147,752

(1)	Interest expense was allocated to discontinued operations based on the ratio of the net assets of discontinued operations to our consolidated net assets plus long-term debt. Interest expense is net of capitalized interest of $2,010 for the year ended December 31, 2013.

Recent accounting pronouncements

In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“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 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 evaluating the new guidance and has not determined the impact this standard may have on its financial statements or decided upon the method of adoption.

In August 2014, the FASB issued ASU No. 2014-15, Presentation of Financial Statements—Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern (“ASU 2014-15”). ASU 2014-15 provides guidance about management’s responsibility to evaluate whether there is substantial doubt about an entity’s ability to continue as a going concern and sets rules for how this information should be disclosed in the financial statements. ASU 2014-15 is effective for annual periods ending after December 15, 2016 and interim periods thereafter. Early adoption is permitted. The Company does not expect adoption of ASU 2014-15 to have any impact on its consolidated financial condition, results of operations or cash flows.

F-16

In April 2015, the FASB issued ASU No. 2015-03, Interest-Imputation of Interest, Simplifying the Presentation of Debt Issuance Costs (“ASU 2015-03”). ASU 2015-03 requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability. ASU 2015-03 is effective for annual periods beginning after December 15, 2015 and interim periods thereafter. Early adoption is permitted. The Company has elected to early adopt ASU 2015-03 and accordingly $9.8 million of debt issuance costs have been reclassified from long term assets to long term debt in our consolidated balance sheet as of December 31, 2014.

In November 2015, the FASB issued ASU No. 2015-17, Balance Sheet Classification of Deferred Taxes (“ASU 2015-17”). ASU 2015-17 requires that all deferred tax assets and liabilities be classified as non-current. ASU 2015-17 also discontinues allocation of valuation allowances between current and noncurrent tax assets. ASU 2015-17 is effective for annual periods beginning after December 15, 2016 and interim periods thereafter. Early adoption is permitted. The Company has elected to retrospectively early adopt ASU 2015-17. The effect of this change did not have a material impact on the Company’s consolidated financial condition.

Subsequent Events

In January 2016, the Company completed an acreage swap with another operator which increased its Haynesville shale acreage by 3,637 net acres in DeSoto Parish, Louisiana including four producing wells (3.5 net). The Company exchanged 2,547 net acres in Atascosa County, Texas including seven producing wells (5.3 net) for the Haynesville shale properties. The swap was an equal value exchange that required no cash outlays.

In February 2016, the Company issued approximately 0.9 million shares of common stock in exchange for $40.0 million in principal amount of the Company’s 7³⁄₄% Senior Notes due 2019.

(2) Acquisitions and Dispositions of Oil and Gas Properties

During 2013, the Company acquired oil and gas leases in Burleson County, Texas for $67.4 million. The Burleson County, Texas acquisition included one producing well and approximately 21,000 net acres which are prospective for oil in the Eagle Ford shale formation. During 2014, the Company commenced drilling operations on these properties and acquired additional interests in certain leases in Burleson County, Texas for approximately $33.9 million. The acquisition included approximately 9,000 net undeveloped acres and an additional 30% working interest in one producing well. Prior to the sale, during 2015, the Company acquired additional acreage, drilled an additional four wells and completed a total of 8 wells on this acreage at a cost of $77.0 million. In 2015, the Company completed the sale of these properties for net proceeds of $102.5 million and recognized a net loss on sale of $112.1 million. Results of operations for these properties were as follows:


	Year Ended December 31,
	2014			2015
	(In thousands)
Total oil and gas sales	$	10,542		$	18,036
Total operating expenses⁽¹⁾		(23,260	)		(66,251	)

Operating loss	$	(12,718	)	$	(48,215	)

(1)	Includes direct operating expenses, depreciation, depletion and amortization and exploration expense. Excludes interest expense and general and administrative expenses.

During 2013, the Company acquired oil and gas leases in Mississippi and Louisiana for $53.3 million. The Mississippi and Louisiana acquisition included approximately 51,000 net acres that are prospective for oil in the Tuscaloosa Marine shale formation.

In 2012, the Company entered into a participation agreement with Kohlberg Kravis Roberts & Co L.P. (together with its affiliates, “KKR”) providing for the participation of KKR in Comstock’s future development of

F-17

certain of its Eagle Ford shale properties in South Texas. Under the terms of the participation agreement, KKR has the right to participate for one-third of Comstock’s working interest in wells drilled on the Company’s acreage comprising its Eagleville field in exchange for KKR paying $25,000 per acre for the net acreage being acquired and one-third of the wells costs. Each well that KKR participates in is intended to earn KKR approximately one-third of the Company’s working interest in approximately 80 acres. The Company received $51.5 million and $28.7 million for acreage and facility costs for new wells drilled subsequent to the closing in 2013 and 2014, respectively. There were no wells drilled under the joint venture in 2015.

In connection with acquisitions of producing oil and gas properties, the Company estimates the value of proved properties based on estimated future net cash flows and discounts them using a market-based rate that the Company determined appropriate at the acquisition date for the various proved reserve categories. Due to the unobservable nature of the inputs, the fair values of the proved oil and gas properties are considered Level 3 fair value measurements.

(3) Oil and Gas Producing Activities

Set forth below is certain information regarding the aggregate capitalized costs of oil and gas properties and costs incurred by the Company for its oil and gas property acquisition, development and exploration activities:

Capitalized Costs


	As of December 31,
	2014			2015
	(In thousands)
Unproved properties	$	201,459		$	84,144
Proved properties:
Leasehold costs		1,006,839			982,915
Wells and related equipment and facilities		3,275,249			3,349,307
Accumulated depreciation depletion and amortization		(2,298,450	)		(3,389,786	)

	$	2,185,097		$	1,026,580

Costs Incurred


	For the Years Ended December 31,
	2013		2014		2015
	(In thousands)
Property Acquisitions:
Unproved property acquisitions	$	130,113	$	91,960	$	12,972
Proved property acquisitions		6,471		2,400		—
Development costs		341,970		440,848		221,265
Exploration costs		439		52,080		12,265

	$	478,993	$	587,288	$	246,502

F-18

(4) Long-term Debt

Long-term debt is comprised of the following:


	As of December 31,
	2014			2015
	(In thousands)

Bank credit facility	$	375,000		$	—
7³⁄₄% senior notes due 2019:
Principal		400,000			376,090
Premium, net of amortization		4,984			3,583
Debt issuance costs, net of amortization		(5,266	)		(3,787	)
9¹⁄₂% senior notes due 2020:
Principal		300,000			194,367
Discount, net of amortization		(9,539	)		(5,040	)
Debt issuance costs, net of amortization		(4,525	)		(2,396	)
10% senior secured notes due 2020:
Principal		—			700,000
Debt issuance costs, net of amortization		—			(13,487	)

	$	1,060,654		$	1,249,330

The premium and discount on the senior notes are being amortized over the life of the senior notes using the effective interest rate method. Issuance costs are amortized over the life of the senior notes on a straight-line basis which approximates the amortization that would be calculated using an effective interest rate method.

The following table summarizes Comstock’s principal amount of debt as of December 31, 2015 by year of maturity:


	2016		2017		2018		2019		2020		Thereafter		Total
	(In thousands)
Bank credit facility	$	—	$	—	$	—	$	—	$	—	$	—	$	—
7³⁄₄% senior notes		—		—		—		376,090		—		—		376,090
9¹⁄₂% senior notes		—		—		—		—		194,367		—		194,367
10% senior secured notes		—		—		—		—		700,000		—		700,000

	$	—	$	—	$	—	$	376,090	$	894,367	$	—	$	1,270,457

In March 2015, Comstock issued $700.0 million of 10% senior secured notes (the “Secured Notes”) which are due on March 15, 2020. Interest on the Secured Notes is payable semi-annually on each March 15 and September 15. Net proceeds from the issuance of the Secured Notes of $683.8 million were used to retire the Company’s bank credit facility and for general corporate purposes. Comstock also has outstanding (i) $376.1 million of 7³⁄₄% senior notes (the “2019 Notes”) which are due on April 1, 2019 and bear interest which is payable semi-annually on each April 1 and October 1 and (ii) $194.4 million of 9¹⁄₂% senior notes (the “2020 Notes”) which are due on June 15, 2020 and bear interest which is payable semi-annually on each June 15 and December 15. The Secured Notes are secured on a first priority basis equally and ratably with the Company’s revolving credit facility described below, subject to payment priorities in favor of the revolving credit facility by the collateral securing the revolving credit facility, which consists of, among other things, at least 80% of the Company’s and its subsidiaries’ oil and gas properties. The Secured Notes, the 2019 Notes and 2020 Notes are general obligations of Comstock and are guaranteed by all of Comstock’s subsidiaries. Such subsidiary guarantors are 100% owned and all of the guarantees are full and unconditional and joint and several obligations.

F-19

There are no restrictions on the Company’s ability to obtain funds from its subsidiaries through dividends or loans. As of December 31, 2015, the Company had no material assets or operations which are independent of its subsidiaries.

During 2015, Comstock purchased $23.9 million in principal amount of the 2019 Notes and $105.6 million in principal amount of the 2020 Notes for an aggregate purchase price of $42.7 million. The gain of $82.4 million recognized on the purchase of the 2019 Notes and 2020 Notes and the loss resulting from the write-off of deferred loan costs associated with Comstock’s prior bank credit facility of $3.7 million are included in the net gain on extinguishment of debt, which is reported as a component of other income (expense).

In connection with the issuance of the Secured Notes, Comstock entered into a $50.0 million revolving credit facility with Bank of Montreal and Bank of America, N.A. The revolving credit facility is a four year commitment that matures on March 4, 2019. Indebtedness under the revolving credit facility is secured by substantially all of the Company’s and its subsidiaries’ assets and is guaranteed by all of its subsidiaries. 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 consolidated debt that we 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 of at least 1.0 to 1.0 and the maintenance of an asset coverage ratio of proved developed reserves to debt outstanding under the revolving credit facility of at least 2.5 to 1.0. The Company was in compliance with these covenants as of December 31, 2015.

(5) Commitments and Contingencies

Commitments

The Company rents office space and other facilities under noncancelable operating leases. Rent expense for the years ended December 31, 2013, 2014 and 2015 was $1.4 million, $1.5 million and $1.5 million, respectively. Minimum future payments under the leases at December 31, 2015 are as follows:


	(In thousands)
2016		1,994
2017		2,021
2018		2,060
2019		1,560
2020		1,560
Thereafter		1,560

	$	10,755

As of December 31, 2015, the Company had commitments for contracted drilling rigs of $1.6 million through May 2016.

The Company has entered into natural gas transportation and treating agreements through July 2019. Maximum commitments under these transportation agreements as of December 31, 2015 totaled $6.4 million.

Contingencies

From time to time, the Company 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

F-20

resolution of these matters will have a material effect on the Company’s financial position, results of operations or cash flows and no material amounts are accrued relative to these matters at December 31, 2014 or 2015.

(6) Stockholders’ Equity

The authorized capital stock of Comstock consists of 15 million shares of common stock, $0.50 par value per share, and 5 million shares of preferred stock, $10.00 par value per share. The preferred stock may be issued in one or more series, and the terms and rights of such stock will be determined by the Board of Directors. There were no shares of preferred stock outstanding at December 31, 2014 or 2015.

The Company paid dividends to its common stockholders of $18.0 million and $23.8 million in 2013 and 2014, respectively. During 2013, the Board of Directors also approved an open market share repurchase plan to repurchase up to $100.0 million of its common stock on the open market. The Company made open market purchases of 126,219 shares and 200,000 shares with an aggregate cost of $9.2 million and $8.1 million in 2013 and 2014, respectively. The Company did not purchase any shares of its common stock in 2015.

On October 1, 2015, the Company entered into a net operating loss carryforwards (“NOLs”) rights plan (the “Rights Plan”) with American Stock Transfer & Trust Company, LLC, as rights agent. In connection with the adoption of the Rights Plan, the board of directors of the Company declared a dividend of one preferred share purchase right (“Right”) for each outstanding share of the Company’s common stock. The dividend was payable on October 16, 2015 to stockholders of record as of the close of business on October 12, 2015. In addition, one Right automatically attached to each share of common stock issued between the record date and the date when the Rights become exercisable.

The Rights Plan was adopted in an effort to prevent potential significant limitations under Section 382 of the Internal Revenue Code of 1986, as amended (the “Code”), on Comstock’s ability to utilize its current NOLs to reduce its future tax liabilities. If Comstock experiences an “ownership change,” as defined in Section 382 of the Code, the Company’s ability to fully utilize its NOLs on an annual basis will be substantially limited, and the timing of the usage of the NOLs could be substantially delayed, which could accordingly significantly impair the value of those benefits. The Rights Plan works by imposing a significant penalty upon any person or group that acquires 4.9% or more of the Company’s outstanding common stock without the approval of the board of directors (an “Acquiring Person”). The Rights Plan also gives discretion to the Board to determine that someone is an Acquiring Person even if they do not own 4.9% or more of the outstanding common stock but do own 4.9% or more in value of the Company’s outstanding stock, as determined pursuant to Section 382 of the Code and the regulations promulgated thereunder. Stockholders who currently own 4.9% or more of the Company’s common stock will not trigger the Rights unless they acquire additional shares, subject to certain exceptions set forth in the Rights Plan. In addition, the Board has established procedures to consider requests to exempt certain acquisitions of the Company’s securities from the Rights Plan if the board of directors determines that doing so would not limit or impair the availability of the NOLs or is otherwise in the best interests of the Company.

(7) Stock-based Compensation

The Company grants restricted shares of common stock and performance share units to key employees and directors as part of their compensation under the 2009 Long-term Incentive Plan. Future awards of stock options, restricted stock grants or other equity awards under the 2009 Long-term Incentive Plan are available with up to 191,569 shares of common stock.

During 2013, 2014 and 2015, the Company had $12.8 million, $10.7 million and $8.1 million, respectively, in stock-based compensation expense which is included in general and administrative expenses. The excess income taxes associated with stock-based compensation recognized in additional paid in capital were $2.0 million, $1.1 million and $2.0 million for the years ended December 31, 2013, 2014 and 2015, respectively.

F-21

Stock Options

At December 31, 2015, the Company had options outstanding to purchase 11,730 shares of common stock at $166.10 per share. The stock options have a weighted average life of 1 year.

The following table summarizes information related to stock option activity under the Company’s incentive plans for the year ended December 31, 2015:


	Number of Options			Weighted Average Exercise Price
Outstanding at January 1, 2015		23,030		$	164.50
Expired or forfeited		(11,300	)	$	162.90

Outstanding at December 31, 2015		11,730		$	166.10

Exercisable at December 31, 2015		11,730		$	166.10

There were no stock option exercises in 2013, 2014 or 2015. No stock option has been granted since 2008 and all compensation cost related to stock options has been recognized. Stock options outstanding at December 31, 2014 and 2015 had no intrinsic value based on the closing price for the Company’s common stock at those dates.

Restricted Stock

The fair value of restricted stock grants is amortized over the vesting period, generally one to four years, using the straight-line method. Total compensation expense recognized for restricted stock grants was $9.8 million, $7.3 million and $6.0 million for the years ended December 31, 2013, 2014 and 2015, respectively. The fair value of each restricted share on the date of grant is equal to the fair market price of a share of the Company’s stock.

A summary of restricted stock activity for the year ended December 31, 2015 is presented below:


	Number of Restricted Shares			Weighted Average Grant Price
Outstanding at January 1, 2015		241,505		$	99.55
Granted		202,074		$	26.70
Vested		(115,349	)	$	111.15
Forfeitures		(14,170	)	$	74.25

Outstanding at December 31, 2015		314,060		$	49.55

The per share weighted average fair value of restricted stock grants in 2013, 2014 and 2015 was $82.20, $101.20 and $26.70, respectively. Total unrecognized compensation cost related to unvested restricted stock of $5.1 million as of December 31, 2015 is expected to be recognized over a period of 1.8 years. The fair value of restricted stock which vested in 2013, 2014 and 2015 was $7.0 million, $10.0 million and $3.7 million, respectively.

Performance Share Units

The Company issues PSUs as part of its long-term equity incentive compensation. PSU awards can result in the issuance of common stock to the holder if certain performance criteria is met during a performance period. The performance periods consist of one year, two years and three years, respectively. The performance criteria

F-22

for the PSUs are based on the Company’s annualized total stockholder return (“TSR”) for the performance period as compared with the TSR of certain peer companies for the performance period. The costs associated with PSUs are recognized as general and administrative expense over the performance periods of the awards.

The fair value of PSUs was measured at the grant date using a stochastic process method utilizing the Geometric Brownian Motion Model (“GBM Model”). A stochastic process is a mathematically defined equation that can create a series of outcomes over time. These outcomes are not deterministic in nature, which means that by iterating the equations multiple times, different results will be obtained for those iterations. In the case of the Company’s PSUs, the Company cannot predict with certainty the path its stock price or the stock prices of its peers will take over the future performance periods. By using a stochastic simulation, the Company can create multiple prospective total return pathways, statistically analyze these simulations, and ultimately make inferences to the most likely path the total return will take. As such, because future stock returns are stochastic, or probabilistic with some direction in nature, the stochastic method, specifically the GBM Model, is deemed an appropriate method by which to determine the fair value of the PSUs. Significant assumptions used in this simulation include the Company’s expected volatility and a risk-free interest rate based on U.S. Treasury yield curve rates with maturities consistent with the vesting periods, as well as the volatilities for each of the Company’s peers. Assumptions regarding volatility included the historical volatility of each company’s stock and the implied volatilities of publicly traded stock options. For the PSUs granted in 2014, the valuation inputs included a risk free interest rate of 0.6% and a range of volatilities of 38% to 70%. For the PSUs granted in 2015, the valuation inputs included a risk free rate of 1.1% and a range of volatilities of 37% to 65%.

In 2014, the Company granted 37,792 PSUs with a grant date fair value of $3.7 million, or $99.05 per unit. In 2015, the Company granted 94,250 PSUs with a grant date fair value of $0.7 million, or $7.30 per unit. No PSUs were awarded in 2013. The fair value of PSUs is amortized over the vesting period of one to three years, using the straight-line method. Total compensation expense recognized for PSUs was $3.0 million, $3.4 million and $2.1 million for the years ended December 31, 2013, 2014 and 2015, respectively.

A summary of PSU activity for the year ended December 31, 2015 is presented below:


	Number of PSUs			Weighted Average Grant Price
Outstanding at January 1, 2015		74,614		$	99.40
Granted		94,250		$	7.30
Unearned or forfeited		(34,943	)	$	96.35

Outstanding at December 31, 2015		133,921		$	35.35

The number of awards assumes a one multiplier. The final number of shares of common stock issued may vary depending upon the performance multiplier, and can result in the issuance of zero to 280,035 shares of common stock based on the achieved performance ranges from zero to two. As of December 31, 2015, there was $2.0 million of total unrecognized expense related to PSUs, which is being amortized through December 31, 2017.

(8) Retirement Plan

The Company has a 401(k) profit sharing plan which covers all of its employees. At its discretion, Comstock may match the employees’ contributions to the plan. Matching contributions to the plan were $702,000, $834,000 and $888,000 for the years ended December 31, 2013, 2014 and 2015, respectively.

F-23

(9) Income Taxes

The following is an analysis of the consolidated income tax benefit from continuing operations:


	2013			2014			2015
	(In thousands)
Current	$	134		$	(12	)	$	804
Deferred		(56,291	)		(24,677	)		(155,249	)

	$	(56,157	)	$	(24,689	)	$	(154,445	)

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 difference between the Company’s effective tax rate and the 35% federal statutory rate is caused by non-deductible stock compensation, state taxes and the establishment of a valuation allowance on deferred taxes. The impact of these items varies based upon the Company’s full year loss and the jurisdictions that are expected to generate the projected losses.

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, in 2015 the Company established an additional valuation allowance of $775.3 million, with a tax effect of $271.4 million for its estimated U.S. federal net operating loss carryforwards and other U.S. federal tax assets and an additional valuation allowance of $215.5 million, with a tax effect of $11.2 million, for its estimated Louisiana state net operating loss carryforwards that are not expected be utilized due to uncertainty of generating taxable income prior to the expiration of the respective U.S. federal and Louisiana state carry-over periods.

The difference between the Company’s customary rate of 35% and the effective tax rate on income from continuing operations is due to the following:


	2013			2014			2015
	(In thousands)
Tax benefit at statutory rate	$	(57,008	)	$	(28,630	)	$	(420,544	)
Tax effect of:
Nondeductible compensation		1,545			756			539
State taxes, net of federal tax benefit		(10,902	)		(5,108	)		(17,502	)
Valuation allowance on deferred tax assets		10,103			8,086			282,869
Other		105			207			193

Total	$	(56,157	)	$	(24,689	)	$	(154,445	)


	2013			2014			2015
Statutory rate		35.0	%		35.0	%		35.0	%
Tax effect of:
Nondeductible compensation		(0.9	)		(0.9	)		—
State taxes, net of federal tax benefit		6.7			6.2			1.4
Valuation allowance on deferred tax assets		(6.2	)		(9.9	)		(23.5	)
Other		(0.1	)		(0.2	)		—

Effective tax rate		34.5	%		30.2	%		12.9	%

F-24

The tax effects of significant temporary differences representing the net deferred tax liability at December 31, 2014 and 2015 were as follows:


	2014			2015
	(In thousands)
Deferred tax assets:
Property and equipment	$	—		$	49,116
Net operating loss carryforwards		126,026			255,231
Alternative minimum tax carryforward		20,435			20,435
Other		7,854			8,201

		154,315			332,983
Valuation allowance on deferred tax assets		(46,639	)		(329,508	)

Deferred tax assets		107,676			3,475

Deferred tax liabilities:
Property and equipment		(259,222	)		—
Unrealized hedging income		—			(506	)
Other		(3,001	)		(4,934	)

Deferred tax liabilities		(262,223	)		(5,440	)

Net deferred tax liability	$	(154,547	)	$	(1,965	)

At December 31, 2015, Comstock had the following carryforwards available to reduce future income taxes:


Types of Carryforward	Years of Expiration Carryforward		Amount
			(In thousands)
Net operating loss—U.S. federal		2017 – 2035	$	558,718
Net operating loss—Louisiana		2020 – 2035	$	1,147,689
Alternative minimum tax credits		Unlimited	$	20,435

As of December 31, 2015, the Company had $558.7 million in U.S. federal net operating loss carryforwards. The utilization of $34.7 million of the U.S. federal net operating loss carryforward is limited to approximately $1.1 million per year pursuant to a prior change of control of an acquired company. Accordingly, as of December 31, 2014, a valuation allowance of $23.0 million, with a tax effect of $8.0 million, has been established for the estimated U.S. federal net operating loss carryforwards that will not be utilized as a result of the change in control. As of December 31, 2015, the Company had also established a valuation allowance of $775.3 million, with a tax effect of $271.4 million, against its other U.S. federal net operating loss carryforwards that are not subject to a change in control and other U.S. federal tax assets due to the uncertainty of generating future taxable income prior to the expiration of the carry-over period. In addition, as of December 31, 2015, the Company established a valuation allowance of $957.7 million, with a tax effect of $49.8 million, against its Louisiana state net deferred tax assets due to the uncertainty of generating taxable income in the state of Louisiana prior to the expiration of the carry-over period. As of December 31, 2014, the Company had a valuation allowance of $742.2 million, with a tax effect of $38.6 million, against its Louisiana state deferred tax assets.

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 Comstock’s net operating loss carryforwards being eliminated or becoming restricted, and the Company may need to recognize an additional valuation allowance reflecting the restricted use of the net operating loss carryforwards in the period when such an ownership change occurred. The Company established a rights plan on October 1, 2015 to deter ownership changes that would trigger this limitation.

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The Company’s federal income tax returns for the years subsequent to December 31, 2011 remain subject to examination. The Company’s income tax returns in major state income tax jurisdictions remain subject to examination for the year ended December 31, 2008 and various periods subsequent to December 31, 2010. State tax returns in one state jurisdiction are currently under review. The Company currently believes that resolution of these matters will not have a material impact on its financial statements. The Company currently believes that its significant filing positions are highly certain and that all of its other significant income tax filing positions and deductions would be sustained upon 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. Interest and penalties resulting from audits by tax authorities have been immaterial and are included in the provision for income taxes in the consolidated statements of operations.

(10) Derivative Financial Instruments and Hedging Activities

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. All of Comstock’s derivative financial instruments are with parties that are lenders under its bank credit facility. 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.

During 2013 and 2014, the Company hedged 2,160,000 barrels and 2,438,000 barrels, respectively, of its oil production at an average NYMEX West Texas Intermediate oil price of $98.67 per barrel and $96.56 per barrel, respectively. During 2015, the Company hedged 1,800,000 Mmbtu of its gas production at an average NYMEX Henry Hub natural gas price of $3.20 per Mmbtu.

As of December 31, 2015, the Company had the following outstanding commodity derivatives:

Commodity and Derivative Type

Weighted-Average
Contract Price

Contract Volume
(Mmbtu)

Contract Period

Natural Gas Swap Agreements

3.20 per Mmbtu

1,800,000

Jan. 2016 – June 2016

None of the derivative contracts were designated as cash flow hedges. The Company recognizes cash settlements and changes in the fair value of its derivative financial instruments as a single component of other income (expenses).

The gain (loss) on derivative financial instruments was a loss of $8.4 million, a gain of $8.2 million and a gain of $2.7 million for the years ended December 31, 2013, 2014 and 2015, respectively. Cash settlements received on derivative financial instruments were $2.3 million, $9.1 million and $1.2 million for the years ended

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December 31, 2013, 2014 and 2015, respectively. The estimated fair value of the Company’s derivative financial instruments, which equaled their carrying value, was an asset of $1.4 million as of December 31, 2015 which was reflected as a current asset based on estimated settlement dates.

(11) Supplementary Quarterly Financial Data (Unaudited)


	2014
	First			Second			Third			Fourth			Total
	(In thousands, except per share data)
Total oil and gas sales	$	141,909		$	155,723		$	144,983		$	112,616		$	555,231
Operating income (loss)	$	20,228		$	27,729		$	263		$	(80,291	)	$	(32,071	)
Net income (loss)	$	1,165		$	1,898		$	(1,903	)	$	(58,271	)	$	(57,111	)

Income (loss) per share:
Basic and diluted	$	0.11		$	0.19		$	(0.22	)	$	(6.31	)	$	(6.20	)

	2015
	First			Second			Third			Fourth			Total
	(In thousands, except per share data)
Total oil and gas sales	$	66,522		$	77,312		$	61,360		$	47,228		$	252,422
Operating loss	$	(96,928	)	$	(182,185	)	$	(596,026	)	$	(290,515	)	$	(1,165,654	)
Net income (loss)	$	(78,502	)	$	(135,068	)	$	(544,996	)	$	(288,543	)	$	(1,047,109	)

Income (loss) per share:
Basic and diluted	$	(8.53	)	$	(14.64	)	$	(59.05	)	$	(31.26	)	$	(113.53	)

Basic and diluted per share amounts are the same for each of the quarters and for the years ended where a net loss was reported.

Results of operations include the following non-routine items of income (expense), which are presented before the effect of income taxes:


	2014
	First			Second			Third			Fourth			Total
	(In thousands)
Impairments of unproved oil and gas properties	$	—		$	—		$	—		$	(487	)	$	(487	)
Impairments of proved oil and gas properties	$	—		$	(256	)	$	(15	)	$	(59,997	)	$	(60,268	)

	2015
	First			Second			Third			Fourth			Total
	(In thousands)
Gain (loss) on sale of oil and gas properties	$	—		$	(111,830	)	$	52		$	(307	)	$	(112,085	)
Net gain (loss) on extinguishment of debt	$	(2,735	)	$	7,267		$	51,054		$	23,155		$	78,741
Impairments of unproved oil and gas properties	$	(40,432	)	$	(23,040	)	$	(5,090	)	$	(385	)	$	(68,947	)
Impairments of proved oil and gas properties	$	(403	)	$	(1,984	)	$	(544,714	)	$	(254,246	)	$	(801,347	)

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(12) Oil and Gas Reserves Information (Unaudited)

Set forth below is a summary of the changes in Comstock’s net quantities of oil and natural gas reserves for its continuing operations for each of the three years in the period ended December 31, 2015:


	2013						2014						2015
	Oil (MBbls)			Natural Gas (MMcf)			Oil (MBbls)			Natural Gas (MMcf)			Oil (MBbls)			Natural Gas (MMcf)
Proved Reserves:
Beginning of year		18,899			437,445			21,976			452,653			20,854			495,266
Revisions of previous estimates		28			23,321			(2,182	)		3,998			(5,096	)		(41,437	)
Extensions and discoveries		5,363			47,581			5,373			78,383			231			168,539
Sales of minerals in place		—			—			—			—			(3,671	)		(5,096	)
Production		(2,314	)		(55,694	)		(4,313	)		(39,768	)		(3,089	)		(47,676	)

End of year		21,976			452,653			20,854			495,266			9,229			569,596

Proved Developed Reserves:
Beginning of year		8,389			362,426			13,914			344,278			16,247			324,598

End of year		13,914			344,278			16,247			324,598			9,229			311,130

The downward revisions in 2015 were primarily related to the decline in oil and natural gas prices. In 2015 price-related revisions were downward revisions of 4,958 MBbls of oil and 77,659 MMcf of natural gas.

The proved oil and gas reserves utilized in the preparation of the financial statements were estimated by Lee Keeling and Associates, independent petroleum consultants, in accordance with guidelines established by the Securities and Exchange Commission and the Financial Accounting Standards Board, which require that reserve reports be prepared under existing economic and operating conditions with no provision for price and cost escalation except by contractual agreement. All of the Company’s reserves are located onshore in the continental United States of America.

The following table sets forth the standardized measure of discounted future net cash flows relating to proved reserves at December 31, 2014 and 2015:


	2014			2015
	(In thousands)
Cash Flows Relating to Proved Reserves:
Future Cash Flows	$	3,891,953		$	1,763,146
Future Costs:
Production		(1,260,580	)		(705,146	)
Development and Abandonment		(571,200	)		(362,874	)
Future Income Taxes		(192,600	)		(1,231	)

Future Net Cash Flows		1,867,573			693,895
10% Discount Factor		(776,913	)		(321,756	)

Standardized Measure of Discounted Future Net Cash Flows	$	1,090,660		$	372,139

The standardized measure of discounted future net cash flows at the end of 2014 and 2015 was determined based on the simple average of the first of month market prices for oil and natural gas for each year. Prices were $92.55 per barrel of oil and $3.96 per Mcf of natural gas for 2014 and $46.88 per barrel of oil and $2.34 per Mcf of natural gas for 2015. Prices used in determining quantities of oil and natural gas reserves and future cash inflows from oil and natural gas reserves represent prices received at the Company’s sales point. These prices

F-28

have been adjusted from posted or index prices for both location and quality differences. Future development and production costs are computed by estimating the expenditures to be incurred in developing and producing proved oil and gas reserves at the end of the year, based on year end costs and assuming continuation of existing economic conditions. Future income tax expenses are computed by applying the appropriate statutory tax rates to the future pre-tax net cash flows relating to proved reserves, net of the tax basis of the properties involved. The future income tax expenses give effect to permanent differences and tax credits, but do not reflect the impact of future operations.

The following table sets forth the changes in the standardized measure of discounted future net cash flows relating to proved reserves for the years ended December 31, 2013, 2014 and 2015:


	2013			2014			2015
	(In thousands)
Standardized Measure, Beginning of Year	$	641,325		$	807,217		$	1,090,660
Net change in sales price, net of production costs		43,117			5,911			(751,774	)
Development costs incurred during the year which were previously estimated		187,643			344,590			157,390
Revisions of quantity estimates		48,411			(40,993	)		(111,454	)
Accretion of discount		81,434			105,400			114,427
Changes in future development and abandonment costs		(157,207	)		(10,909	)		14,901
Changes in timing and other		80,348			(19,028	)		(44,439	)
Extensions and discoveries		291,582			163,559			56,216
Sales of minerals in place		—			—			(43,694	)
Sales, net of production costs		(335,677	)		(458,254	)		(163,336	)
Net changes in income taxes		(73,759	)		193,167			53,242

Standardized Measure, End of Year	$	807,217		$	1,090,660		$	372,139

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