10-K 1 d78717e10vk.htm FORM 10-K

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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K

(Mark One) |  |  |  |
þ |  | ANNUAL REPORT PURSUANT TO SECTIONS 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |  |
|  | For the fiscal year ended December 31, 2010 |  |
OR
o |  | TRANSITION REPORT PURSUANT TO SECTIONS 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |  |
|  | For the transition period from to |  |

Commission File No. 001-03262
COMSTOCK RESOURCES, INC.
(Exact name of registrant as specified in its charter)

NEVADA |  | 94-1667468
(State or other jurisdiction of incorporation or organization) |  | (I.R.S. Employer Identification Number)

5300 Town and Country Blvd., Suite 500, Frisco, Texas 75034
(Address of principal executive offices including zip code)
(972) 668-8800
(Registrant’s telephone number and area code)
Securities registered pursuant to Section 12(b) of the Act:

Common Stock, $.50 Par Value |  | New York Stock Exchange
(Title of class) |  | (Name of exchange on which registered)

Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes þ No o
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No þ
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer þ | Accelerated filer o | Non-accelerated filer o | Smaller reporting company o

(Do not check if smaller reporting company)
Indicate by check mark whether the registrant is a shell company (as defined in Exchange Act Rule 12b-2). Yes o No þ
As of February 22, 2011, there were 47,706,101 shares of common stock outstanding.
The aggregate market value of the common stock held by non-affiliates of the registrant, based on the closing price of common stock on the New York Stock Exchange on June 30, 2010 (the last business day of the registrant’s most recently completed second fiscal quarter), was $1.2 billion.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Definitive Proxy Statement for the 2011 Annual Meeting of Stockholders
are incorporated by reference into Part III of this report.

#####

COMSTOCK RESOURCES, INC.
ANNUAL REPORT ON FORM 10-K
For the Fiscal Year Ended December 31, 2010
CONTENTS

Item |  |  |  | Page
Part I
|  | Cautionary Note Regarding Forward-Looking Statements |  |  | 2 |
|  | Definitions |  |  | 3 |
1. and 2. |  | Business and Properties |  |  | 6 |
1A. |  | Risk Factors |  |  | 27 |
1B. |  | Unresolved Staff Comments |  |  | 36 |
3. |  | Legal Proceedings |  |  | 36 |
Part II
5. |  | Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities |  |  | 37 |
6. |  | Selected Financial Data |  |  | 38 |
7. |  | Management’s Discussion and Analysis of Financial Condition and Results of Operations |  |  | 39 |
7A. |  | Quantitative and Qualitative Disclosures About Market Risk |  |  | 48 |
8. |  | Financial Statements and Supplementary Data |  |  | 49 |
9. |  | Changes in and Disagreements with Accountants on Accounting and Financial Disclosure |  |  | 50 |
9A. |  | Controls and Procedures |  |  | 50 |
9B. |  | Other Information |  |  | 52 |
Part III
10. |  | Directors, Executive Officers and Corporate Governance |  |  | 52 |
11. |  | Executive Compensation |  |  | 52 |
12. |  | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters |  |  | 52 |
13. |  | Certain Relationships and Related Transactions, and Director Independence |  |  | 52 |
14. |  | Principal Accountant Fees and Services |  |  | 52 |
Part IV
15. |  | Exhibits and Financial Statement Schedules |  |  | 53 |
EX-4.8
EX-4.11
EX-10.10
EX-21
EX-23.1
EX-23.2
EX-31.1
EX-31.2
EX-32.1
EX-32.2
EX-99.1
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

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS
The information contained in this report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. These forward-looking statements are identified by their use of terms such as “expect,” “estimate,” “anticipate,” “project,” “plan,” “intend,” “believe” and similar terms. All statements, other than statements of historical facts, included in this report, are forward-looking statements, including statements mentioned under “Risk Factors” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” regarding:

| • | amount and timing of future production of oil and natural gas;
| • | the availability of exploration and development opportunities;
| • | amount, nature and timing of capital expenditures;
| • | the number of anticipated wells to be drilled after the date hereof;
| • | our financial or operating results;
| • | our cash flow and anticipated liquidity;
| • | operating costs including lease operating expenses, administrative costs and other expenses;
| • | finding and development costs;
| • | our business strategy; and
| • | other plans and objectives for future operations.

Any or all of our forward-looking statements in this report may turn out to be incorrect. They can be affected by a number of factors, including, among others:

| • | the risks described in “Risk Factors” and elsewhere in this report;
| • | the volatility of prices and supply of, and demand for, oil and natural gas;
| • | the timing and success of our drilling activities;
| • | the numerous uncertainties inherent in estimating quantities of oil and natural gas reserves and actual future production rates and associated costs;
| • | our ability to successfully identify, execute or effectively integrate future acquisitions;
| • | the usual hazards associated with the oil and natural gas industry, including fires, well blowouts, pipe failure, spills, explosions and other unforeseen hazards;
| • | our ability to effectively market our oil and natural gas;
| • | the availability of rigs, equipment, supplies and personnel;
| • | our ability to discover or acquire additional reserves;
| • | our ability to satisfy future capital requirements;
| • | changes in regulatory requirements;
| • | general economic conditions, status of the financial markets and competitive conditions;
| • | our ability to retain key members of our senior management and key employees; and
| • | hostilities in the Middle East and other sustained military campaigns and acts of terrorism or sabotage that impact the supply of crude oil and natural gas.

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DEFINITIONS
The following are abbreviations and definitions of terms commonly used in the oil and gas industry and this report. Natural gas equivalents and crude oil equivalents are determined using the ratio of six Mcf to one barrel. All references to “us,” “our,” “we” or “Comstock” mean the registrant, Comstock Resources, Inc. and where applicable, its consolidated subsidiaries.
“Bbl” means a barrel of U.S. 42 gallons of oil.
“Bcf” means one billion cubic feet of natural gas.
“Bcfe” means one billion cubic feet of natural gas equivalent.
“Btu” means British thermal unit, which is the quantity of heat required to raise the temperature of one pound of water from 58.5 to 59.5 degrees Fahrenheit.
“Completion” means the installation of permanent equipment for the production of oil or gas.
“Condensate” means a hydrocarbon mixture that becomes liquid and separates from natural gas when the gas is produced and is similar to crude oil.
“Development well” means a well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.
“Dry hole” means a well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.
“Exploratory well” means a well drilled to find and produce oil or natural gas reserves not classified as proved, to find a new productive reservoir in a field previously found to be productive of oil or natural gas in another reservoir or to extend a known reservoir.
“GAAP” means generally accepted accounting principles in the United States of America.
“Gross” when used with respect to acres or wells, production or reserves refers to the total acres or wells in which we or another specified person has a working interest.
“MBbls” means one thousand barrels of oil.
“MBbls/d” means one thousand barrels of oil per day.
“Mcf” means one thousand cubic feet of natural gas.
“Mcfe” means one thousand cubic feet of natural gas equivalent.
“MMBbls” means one million barrels of oil.
“MMBtu” means one million British thermal units.
“MMcf” means one million cubic feet of natural gas.
“MMcf/d” means one million cubic feet of natural gas per day.
“MMcfe/d” means one million cubic feet of natural gas equivalent per day.
“MMcfe” means one million cubic feet of natural gas equivalent.
“Net” when used with respect to acres or wells, refers to gross acres of wells multiplied, in each case, by the percentage working interest owned by us.
“Net production” means production we own less royalties and production due others.
“Oil” means crude oil or condensate.

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“Operator” means the individual or company responsible for the exploration, development, and production of an oil or gas well or lease.
“PV 10 Value” means the present value of estimated future revenues to be generated from the production of proved reserves calculated in accordance with the Securities and Exchange Commission guidelines, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation, without giving effect to non-property related expenses such as general and administrative expenses, debt service, future income tax expense and depreciation, depletion and amortization, and discounted using an annual discount rate of 10%. This amount is the same as the standardized measure of discounted future net cash flows related to proved oil and natural gas reserves except that it is determined without deducting future income taxes. Although PV 10 Value is not a financial measure calculated in accordance with GAAP, management believes that the presentation of PV 10 Value is relevant and useful to our investors because it presents the discounted future net cash flows attributable to our proved reserves prior to taking into account corporate future income taxes and our current tax structure. We use this measure when assessing the potential return on investment related to our oil and gas properties. Because many factors that are unique to any given company affect the amount of estimated future income taxes, the use of a pre-tax measure is helpful to investors when comparing companies in our industry.
“Proved developed reserves” means reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery will be included as “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.
“Proved developed non-producing” means reserves (i) expected to be recovered from zones capable of producing but which are shut-in because no market outlet exists at the present time or whose date of connection to a pipeline is uncertain or (ii) currently behind the pipe in existing wells, which are considered proved by virtue of successful testing or production of offsetting wells.
“Proved developed producing” means reserves expected to be recovered from currently producing zones under continuation of present operating methods. This category may also include recently completed shut-in gas wells scheduled for connection to a pipeline in the near future.
“Proved reserves” means the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.
“Proved undeveloped reserves” means reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances are estimates for proved undeveloped reserves attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

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“Recompletion” means the completion for production of an existing well bore in another formation from which the well has been previously completed.
“Reserve life” means the calculation derived by dividing year-end reserves by total production in that year.
“Reserve replacement” means the calculation derived by dividing additions to reserves from acquisitions, extensions, discoveries and revisions of previous estimates in a year by total production in that year.
“Royalty” means an interest in an oil and gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.
“3-D seismic” means an advanced technology method of detecting accumulations of hydrocarbons identified by the collection and measurement of the intensity and timing of sound waves transmitted into the earth as they reflect back to the surface.
“Working interest” means an interest in an oil and gas lease that gives the owner of the interest the right to drill for and produce oil and gas on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations. The share of production to which a working interest owner is entitled will always be smaller than the share of costs that the working interest owner is required to bear, with the balance of the production accruing to the owners of royalties. For example, the owner of a 100% working interest in a lease burdened only by a landowner’s royalty of 12.5% would be required to pay 100% of the costs of a well but would be entitled to retain 87.5% of the production.
“Workover” means operations on a producing well to restore or increase production.

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PART I
ITEMS 1. and 2. BUSINESS AND PROPERTIES
We are a Nevada corporation engaged in the acquisition, development, production and exploration of oil and natural gas. Our common stock is listed and traded on the New York Stock Exchange.
Our oil and gas operations are concentrated in East Texas/North Louisiana and South Texas. Our oil and natural gas properties are estimated to have proved reserves of 1,051.0 Bcfe with an estimated PV 10 Value of $797.6 million as of December 31, 2010 and a standardized measure of discounted future net cash flows of $606.1 million. Our consolidated proved oil and natural gas reserve base is 98% natural gas and 50% proved developed on a Bcfe basis as of December 31, 2010.
Our proved reserves at December 31, 2010 and our 2010 average daily production are summarized below:

|  | Reserves at December 31, 2010 |  |  | 2010 Average Daily Production |
|  |  |  |  | Natural |  |  |  |  |  |  |  |  |  |  |  | Natural |  |  |  |  |  |  |
|  | Oil |  |  | Gas |  |  | Total |  |  | % of |  |  | Oil |  |  | Gas |  |  | Total |  |  | % of |
|  | (MMBbls) |  |  | (Bcf) |  |  | (Bcfe) |  |  | Total |  |  | (MBbls/d) |  |  | (MMcf/d) |  |  | (MMcfe/d) |  |  | Total |
East Texas / North Louisiana |  |  | 1.2 |  |  |  | 862.9 |  |  |  | 870.4 |  |  |  | 82.8 | % |  |  | 0.4 |  |  |  | 142.6 |  |  |  | 145.0 |  |  |  | 72.2 | %
South Texas |  |  | 2.9 |  |  |  | 141.1 |  |  |  | 158.3 |  |  |  | 15.1 | % |  |  | 0.4 |  |  |  | 39.5 |  |  |  | 42.1 |  |  |  | 21.0 | %
Other Regions |  |  | 0.1 |  |  |  | 21.7 |  |  |  | 22.3 |  |  |  | 2.1 | % |  |  | 1.1 |  |  |  | 6.9 |  |  |  | 13.6 |  |  |  | 6.8 | %
Total |  |  | 4.2 |  |  |  | 1,025.7 |  |  |  | 1,051.0 |  |  |  | 100 | % |  |  | 1.9 |  |  |  | 189.0 |  |  |  | 200.7 |  |  |  | 100 | %

Strengths
High Quality Properties. Our operations are focused in two primary operating areas, the East Texas/North Louisiana and South Texas regions. Our properties have an average reserve life of approximately 14.3 years and have extensive development and exploration potential. We have a substantial acreage position in our East Texas/North Louisiana region in the Haynesville or Bossier shale resource play where we have identified 91,011 gross (79,457 net to us) acres prospective for Haynesville or Bossier shale development. During 2010 we also acquired 20,859 acres (18,320 net to us) in South Texas which are prospective for development of the Eagle Ford shale formation.
Successful Exploration and Development Program. In 2010 we spent $536.7 million on exploration and development activities. We drilled 78 wells in 2010, 49.3 net to us, at a cost of $390.6 million. We spent $134.7 million to acquire additional leases, $3.2 million on other leasehold costs and $2.6 million to acquire seismic data. We also spent $5.6 million for recompletions, workovers, abandonment and production facilities. Our drilling activities in 2010 added 431 Bcfe to our proved reserves and increased our production by 12% in 2010. Due to unavailability of completion services in 2010 we only completed 37 (21.6 net to us) of the 72 (45.0 net to us) Haynesville or Bossier shale wells that we drilled. We expect to complete all of the remaining wells drilled in 2010 during 2011.
Efficient Operator. We operate 92% of our proved oil and natural gas reserve base as of December 31, 2010. As operator we are better able to control operating costs, the timing and plans for future development, the level of drilling and lifting costs and the marketing of production. As an operator, we receive reimbursements for overhead from other working interest owners, which reduces our general and administrative expenses.
Successful Acquisitions. We have had significant growth over the years as a result of our acquisition activity. In recent years, however, we have not made any acquisitions; in 2010 we focused exclusively on

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drill bit growth. Since 1991, we have added 984 Bcfe of proved oil and natural gas reserves from 36 acquisitions at an average cost of $1.14 per Mcfe. Our application of strict economic and reserve risk criteria have enabled us to successfully evaluate and integrate acquisitions.
Business Strategy
Pursue Exploration Opportunities. We conduct exploration activities to grow our reserve base and to replace our production each year. In late 2007 we identified the potential in our largest operating region, East Texas/North Louisiana, to explore for natural gas in the Haynesville shale formation, which was below the Cotton Valley, Hosston and Travis Peak sand formations that we have been developing. We drilled eight pilot wells to evaluate the prospectivity of the Haynesville shale in 2007 and 2008. We undertook an active leasing program in 2008 through 2010 to acquire additional acreage where we believed the Haynesville shale formation would be prospective and spent $116.9 million in 2008, $26.9 million in 2009 and $55.8 million in 2010 to increase our leasehold with Haynesville or Bossier shale potential to 91,011 gross acres (79,457 net to us). We started the commercial development of the Haynesville shale in late 2008 and have drilled 118 (77.7 net to us) successful horizontal wells through the end of 2010. In 2010, our drilling program was primarily focused on exploring and developing our Haynesville and Bossier shale acreage and we drilled 72 (45.0 net to us) Haynesville and Bossier shale horizontal wells which added 402 Bcfe to our proved reserves in 2010. We plan to continue to develop our Haynesville and Bossier shale acreage in 2011 and have budgeted to spend $348.0 million to drill 45 (27.5 net to us) Haynesville and Bossier shale horizontal wells and to complete our wells that were in progress at the end of 2010.
During 2010 we spent approximately $81.4 million to acquire 20,859 acres (18,320 net to us) in South Texas which we believe to be prospective for the production of liquid hydrocarbons in the Eagle Ford shale formation. We spent approximately $25.6 million to drill three wells (3.0 net to us) in 2010 on our Eagle Ford shale properties. Our Eagle Ford shale drilling program added 10 Bcfe to our proved reserves in 2010. We plan to continue to evaluate our Eagle Ford shale properties during 2011 and have budgeted $169.3 million to drill 22 wells (22.0 net to us) during 2011.
Exploit Existing Reserves. We seek to maximize the value of our oil and natural gas properties by increasing production and recoverable reserves through development drilling and workover, recompletion and exploitation activities. We utilize advanced industry technology, including 3-D seismic data, horizontal drilling, improved logging tools, and formation stimulation techniques. During 2010, outside of our Haynesville shale and Eagle Ford shale drilling programs, we spent $4.6 million to drill three wells (1.3 net to us). We also spent $5.6 million for recompletion and workover activity in 2010.
Maintain Flexible Capital Expenditure Budget. The timing of most of our capital expenditures is discretionary because we have not made any significant long-term capital expenditure commitments except for contracted drilling and completion services. We operate most of the drilling projects in which we participate. Consequently, we have a significant degree of flexibility to adjust the level of such expenditures according to market conditions. We have budgeted to spend approximately $522.0 million on our development and exploration projects in 2011. We intend to primarily use operating cash flow, proceeds from the sale of non-core assets and borrowings under our bank credit facility to fund our development and exploration expenditures in 2011. We may also make additional property acquisitions in 2011 that would require additional sources of funding. Such sources may include borrowings under our bank credit facility or sales of our equity or debt securities.
Acquire High Quality Properties at Attractive Costs. In prior years we have had a successful track record of increasing our oil and natural gas reserves through opportunistic acquisitions. Since 1991, we have added 984 Bcfe of proved oil and natural gas reserves from 36 acquisitions at a total cost of $1.1 billion, or

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$1.14 per Mcfe. The acquisitions were acquired at an average of 67% of their PV 10 Value in the year the acquisitions were completed. We did not complete any acquisitions of producing oil and gas properties in 2009 or 2010 due to our focus on developing our Haynesville and Bossier shale and Eagle Ford shale properties. In evaluating acquisitions, we apply strict economic and reserve risk criteria. We target properties in our core operating areas with established production and low operating costs that also have potential opportunities to increase production and reserves through exploration and exploitation activities. We also evaluate our existing properties and consider divesting of non-strategic assets when market conditions are favorable.
Primary Operating Areas
The following table summarizes the estimated proved oil and natural gas reserves for our twenty largest field areas as of December 31, 2010:

|  |  |  |  | Natural |  |  |  |  |  |  |  |  |  |  |  |  |
|  | Oil |  |  | Gas |  |  | Total |  |  |  |  |  | PV 10 Value(1) |  |  |  |
|  | (MBbls) |  |  | (MMcf) |  |  | (MMcfe) |  |  | % |  |  | (000’s) |  |  | % |
East Texas / North Louisiana |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Logansport |  |  | 44 |  |  |  | 521,193 |  |  |  | 521,455 |  |  |  | 49.6 | % |  | $ | 351,416 |  |  |  | 44.1 | %
Toledo Bend |  |  | — |  |  |  | 134,310 |  |  |  | 134,310 |  |  |  | 12.8 | % |  |  | 15,492 |  |  |  | 1.9 | %
Beckville |  |  | 138 |  |  |  | 54,421 |  |  |  | 55,251 |  |  |  | 5.3 | % |  |  | 54,188 |  |  |  | 6.8 | %
Mansfield |  |  | — |  |  |  | 39,659 |  |  |  | 39,659 |  |  |  | 3.8 | % |  |  | 16,991 |  |  |  | 2.1 | %
Waskom |  |  | 417 |  |  |  | 31,758 |  |  |  | 34,259 |  |  |  | 3.3 | % |  |  | 22,737 |  |  |  | 2.9 | %
Blocker |  |  | 113 |  |  |  | 30,929 |  |  |  | 31,609 |  |  |  | 3.0 | % |  |  | 27,032 |  |  |  | 3.4 | %
Hico-Knowles/Terryville |  |  | 310 |  |  |  | 15,078 |  |  |  | 16,936 |  |  |  | 1.6 | % |  |  | 33,962 |  |  |  | 4.3 | %
Darco |  |  | 38 |  |  |  | 9,463 |  |  |  | 9,693 |  |  |  | 0.9 | % |  |  | 6,175 |  |  |  | 0.8 | %
Douglass |  |  | 3 |  |  |  | 7,171 |  |  |  | 7,191 |  |  |  | 0.7 | % |  |  | 6,513 |  |  |  | 0.8 | %
Drew |  |  | 34 |  |  |  | 3,387 |  |  |  | 3,588 |  |  |  | 0.3 | % |  |  | 4,736 |  |  |  | 0.6 | %
Vixen |  |  | — |  |  |  | 2,937 |  |  |  | 2,937 |  |  |  | 0.3 | % |  |  | 3,098 |  |  |  | 0.4 | %
Other |  |  | 145 |  |  |  | 12,569 |  |  |  | 13,444 |  |  |  | 1.2 | % |  |  | 16,696 |  |  |  | 2.0 | %
|  |  | 1,242 |  |  |  | 862,875 |  |  |  | 870,332 |  |  |  | 82.8 | % |  |  | 559,036 |  |  |  | 70.1 | %
South Texas |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Fandango |  |  | — |  |  |  | 53,375 |  |  |  | 53,375 |  |  |  | 5.1 | % |  |  | 57,320 |  |  |  | 7.2 | %
Double A Wells |  |  | 910 |  |  |  | 24,156 |  |  |  | 29,619 |  |  |  | 2.8 | % |  |  | 51,489 |  |  |  | 6.5 | %
Rosita |  |  | 1 |  |  |  | 27,327 |  |  |  | 27,335 |  |  |  | 2.6 | % |  |  | 25,696 |  |  |  | 3.2 | %
Javelina |  |  | 70 |  |  |  | 13,283 |  |  |  | 13,704 |  |  |  | 1.3 | % |  |  | 23,150 |  |  |  | 2.9 | %
Eagle Ford |  |  | 1,426 |  |  |  | 1,492 |  |  |  | 10,050 |  |  |  | 1.0 | % |  |  | 9,013 |  |  |  | 1.1 | %
Las Hermanitas |  |  | 3 |  |  |  | 9,745 |  |  |  | 9,762 |  |  |  | 0.9 | % |  |  | 10,413 |  |  |  | 1.3 | %
Segno |  |  | 373 |  |  |  | 1,147 |  |  |  | 3,382 |  |  |  | 0.3 | % |  |  | 15,146 |  |  |  | 1.9 | %
Lopeno |  |  | 46 |  |  |  | 2,640 |  |  |  | 2,916 |  |  |  | 0.3 | % |  |  | 4,450 |  |  |  | 0.6 | %
Other |  |  | 49 |  |  |  | 7,895 |  |  |  | 8,189 |  |  |  | 0.8 | % |  |  | 12,466 |  |  |  | 1.5 | %
|  |  | 2,878 |  |  |  | 141,060 |  |  |  | 158,332 |  |  |  | 15.1 | % |  |  | 209,143 |  |  |  | 26.2 | %
Other |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
San Juan Basin |  |  | 14 |  |  |  | 4,337 |  |  |  | 4,424 |  |  |  | 0.4 | % |  |  | 6,830 |  |  |  | 0.9 | %
Other |  |  | 85 |  |  |  | 17,361 |  |  |  | 17,862 |  |  |  | 1.7 | % |  |  | 22,617 |  |  |  | 2.8 | %
|  |  | 99 |  |  |  | 21,698 |  |  |  | 22,286 |  |  |  | 2.1 | % |  |  | 29,447 |  |  |  | 3.7 | %
Total |  |  | 4,219 |  |  |  | 1,025,633 |  |  |  | 1,050,950 |  |  |  | 100.00 | % |  |  | 797,626 |  |  |  | 100.00 | %
Discounted Future Income Taxes |  |  | (191,490 | ) |  |  |  |
Standardized Measure of Discounted Future Cash Flows |  | $ | 606,136 |  |  |  |  |

(1) |  | The PV 10 Value represents the discounted future net cash flows attributable to our proved oil and gas reserves before income tax, discounted at 10%. Although it is a non-GAAP measure, we believe that the presentation of the PV 10 Value is relevant and useful to our investors because it presents the discounted future net cash flows attributable to our proved reserves prior to taking into account corporate future income taxes and our current tax structure. We use this measure when assessing the potential return on investment related to our oil and gas properties. The standardized measure of discounted future net cash flows represents the present value of future cash flows attributable to our proved oil and natural gas reserves after income tax, discounted at 10%.

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East Texas/North Louisiana Region
Approximately 83% or 870.4 Bcfe of our proved reserves are located in East Texas and North Louisiana where we own interests in 936 producing wells (565.7 net to us) in 28 field areas. We operate 639 of these wells. The largest of our fields in this region are the Logansport, Toledo Bend, Beckville, Mansfield, Waskom, Blocker, Hico-Knowles/Terryville, Darco, Douglass, Drew and Vixen fields. Production from this region averaged 143 MMcf of natural gas per day and 403 barrels of oil per day during 2010 or 145 MMcfe per day. Most of the reserves in this area produce from the upper Jurassic aged Haynesville or Bossier shale or Cotton Valley formations and the Cretaceous aged Travis Peak/Hosston formation. In 2010, we spent $354.0 million drilling 73 wells (45.5 net to us) and $58.0 million on leasehold costs, workovers and recompletions in this region. 72 (45.0 net to us) of the 73 wells we drilled were horizontal wells that targeted the Haynesville or Bossier shale. As of December 31, 2010 we had 35 (23.4 net to us) Haynesville and Bossier shale wells that had been drilled but which were not yet completed. We plan to spend approximately $348.0 million in 2011 in this region to complete the wells that were in progress at the end of 2010 and for drilling activities which will focus primarily on the continued development of our Haynesville and Bossier shale properties.
Logansport
The Logansport field located in DeSoto Parish, Louisiana primarily produces from the Haynesville shale formation at a depth of 11,100 to 11,500 feet and from multiple sands in the Cotton Valley and Hosston formations at an average depth of 8,000 feet. Our proved reserves of 521.5 Bcfe in the Logansport field represent approximately 50% of our proved reserves. We own interests in 205 wells (129.6 net to us) and operate 143 of these wells in this field. At December 31, 2010 we had three wells (0.5 net to us) that were in the process of being completed and 19 drilled wells awaiting completion. During December 2010 net daily production attributable to our interest from this field averaged 80 MMcf of natural gas and 34 barrels of oil. In 2010 we drilled 42 (28.4 net to us) Haynesville or Bossier shale horizontal wells at Logansport. In 2011 we plan to drill 22 (15.4 net to us) horizontal Haynesville or Bossier shale wells.
Toledo Bend
The Toledo Bend field in Desoto and Sabine Parishes, Louisiana was discovered in 2008 with our first horizontal Haynesville shale well. In 2010, we drilled nine (4.7 net to us) Haynesville shale horizontal wells and ten (7.5 net to us) Bossier shale horizontal wells at Toledo Bend. Production from the Haynesville shale in the Toledo Bend ranges from 11,400 to 11,800 feet and from 10,880 to 11,300 feet in the Bossier shale. Our proved reserves of 134 Bcfe in the Toledo Bend field represent approximately 13% of our reserves. We own interests in 28 producing wells (17.8 net to us) and operate twenty of these wells. At December 31, 2010 we had four wells (2.1 net to us) that were in the process of being drilled, one well in the process of being completed and six drilled wells awaiting completion. During December 2010, net daily production attributable to our interest from this field averaged 29 MMcf of natural gas. In 2011, we plan to drill 18 (10.9 net to us) horizontal Haynesville or Bossier shale wells in this field.
Beckville
The Beckville field, located in Panola and Rusk Counties, Texas, has estimated proved reserves of 55 Bcfe which represents approximately 5% of our proved reserves. We operate 193 wells in this field and own interests in 83 additional wells for a total of 276 wells (161.5 net to us). During December 2010, production attributable to our interest from this field averaged 13 MMcf of natural gas per day and 52 barrels of oil per day. The Beckville field produces primarily from the Cotton Valley formation at depths ranging from 9,000 to 10,000 feet. The field is also prospective for future Haynesville shale development.

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Mansfield
The Mansfield field is located in DeSoto Parish Louisiana and produces from the Haynesville shale between 12,250 and 12,350 feet. During 2010 we drilled nine (2.3 net to us) Haynesville shale horizontal wells in this field. At December 31, 2010 in Mansfield we had two wells in the process of being drilled, three wells in the process of being completed and three drilled wells awaiting completion. Our proved reserves in this field of 40 Bcfe represent approximately 4% of our reserves. During December 2010, net daily production attributable to our interest for this field averaged 3 MMcf of natural gas.
Waskom
The Waskom field, located in Harrison and Panola Counties in Texas, represents approximately 3% (34 Bcfe) of our proved reserves as of December 31, 2010. We own interests in 67 wells in this field (43.5 net to us) and operate 51 wells in this field. During December 2010, net daily production attributable to our interest averaged 6 MMcf of natural gas and 30 barrels of oil from this field. The Waskom field produces from the Cotton Valley formation at depths ranging from 9,000 to 10,000 feet and from the Haynesville shale formation at depths of 10,800 to 10,900 feet. We drilled one Haynesville shale well in the Waskom field in 2010 and will drill one (1.0 net to us) horizontal Haynesville shale well in 2011.
Blocker
Our proved reserves of 32 Bcfe in the Blocker field located in Harrison County, Texas represent approximately 3% of our proved reserves. We own interests in 76 wells (70 net to us) and operate 70 of these wells. During December 2010, net daily production attributable to our interest from this field averaged 6 MMcf of natural gas and 35 barrels of oil. Most of this production is from the Cotton Valley formation between 8,600 and 10,150 feet and the Haynesville shale formation between 11,100 and 11,450 feet. During 2010 we drilled one successful Cotton Valley well at Blocker.
Hico-Knowles/Terryville
We have 17 Bcfe of proved reserves in the Hico-Knowles/Terryville field area located in Lincoln County, Louisiana which represent approximately 2% of our reserves. We own interests in 68 wells (25.3 net to us) and operate 22 of these wells. This field produces primarily from the Hosston/Cotton Valley formations between 7,200 and 11,000 feet. During December 2010, net daily production attributable to our interest from this field averaged 5 MMcf of natural gas and 95 barrels of oil.
Darco
The Darco field is located in Harrison County, Texas and produces from the Cotton Valley formation at depths from approximately 9,800 to 10,200 feet. Our proved reserves of 10 Bcfe in the Darco field represent approximately 1% of our reserves. We own interests in 24 wells (18.8 net to us) and operate all of these wells. During December 2010, net daily production attributable to our interest from this field averaged 1 MMcf of natural gas and 10 barrels of oil.
Douglass
The Douglass field is located in Nacogdoches County, Texas and is productive from stratigraphically trapped reservoirs in the Pettet Lime and Travis Peak formations. These reservoirs are found at depths from 9,200 to 10,300 feet. Our proved reserves of 7 Bcfe in the Douglass field represent approximately 1% of our

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reserves. We own interests in 40 wells (25.8 net to us) and operate 33 of these wells. During December 2010, net daily production attributable to our interest from this field averaged 1 MMcf of natural gas and 5 barrels of oil.
Drew
The Drew Field located in Ouachita Parish, Louisiana has an estimated proved reserves of 4 Bcfe which represents less than 1% of our total company proved reserves. Production is from the Cotton Valley formation between 9,000 feet and 9,600 feet. We own interest in eight wells (5.3 net to us) and operate six of these wells. During December 2010, net daily production attributable to our interest from this field averaged 1 MMcf of natural gas and 5 barrels of oil per day.
Vixen
The Vixen Field located in Caldwell Parish, Louisiana has an estimated proved reserves of 3 Bcfe which represents less than 1% of our total company proved reserves. Production is from various Hosston sands between 8,300 feet to 10,500 feet. We own interest in seven wells (6.0 net) and operate all of these wells. During December 2010, net daily production attributable to our interest from this field averaged 1 MMcf of natural gas.
South Texas Region
Approximately 15%, or 158 Bcfe, of our proved reserves are located in South Texas, where we own interests in 228 producing wells (124.7 net to us). We own interests in 15 field areas in the region, the largest of which are the Fandango, Double A Wells, Rosita, Javelina, Eagle Ford, Las Hermanitas, Segno and Lopeno fields. Net daily production rates from this region averaged 40 MMcf of natural gas and 429 barrels of oil during 2010 or 42 MMcfe per day. We spent $82.0 million in this region in 2010 to acquire acreage which is prospective for development of the Eagle Ford shale. We also spent $25.6 million to drill three Eagle Ford shale wells (3.0 net to us) and $12.0 million to drill one vertical well (0.5 net to us) and for other development activity. We plan to spend approximately $174.0 million in 2011 for development and exploration activity targeting the Eagle Ford shale formation in this region.
Fandango
We own interests in 21 wells (21 net to us) in the Fandango field, located in Zapata County, Texas. We operate all of these wells which produce from the Wilcox formation at depths from approximately 13,000 to 18,000 feet. Our proved reserves of 53 Bcfe in this field represent approximately 5% of our total reserves. Production from this field averaged 12 MMcf of natural gas per day during December 2010. We drilled one successful exploration well and two successful development wells since we acquired this field in 2007.
Double A Wells
Our properties in the Double A Wells field have proved reserves of 30 Bcfe, which represent 3% of our reserves. We own interests in and operate 57 producing wells (27.9 net to us) in this field in Polk County, Texas. Net daily production from the Double A Wells area averaged 5 MMcf of natural gas and 175 barrels of oil during December 2010. These wells produce from the Woodbine formation at an average depth of 14,300 feet.

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Rosita
We own interests in 31 wells (16.8 net to us) in the Rosita field, located in Duval County, Texas. We operate four of these wells which produce from the Wilcox formation at depths from approximately 9,300 to 17,000 feet. Our proved reserves of 27 Bcfe in this field represent approximately 3% of our total reserves. Production from this field averaged 4 MMcf of natural gas and two barrels of oil per day during December 2010.
Javelina
We own interests in and operate 18 wells, (18 net to us), in the Javelina field in Hidalgo County in South Texas. These wells produce primarily from the Vicksburg formation at a depth of approximately 10,900 to 12,500 feet. Proved reserves attributable to our interests in the Javelina field are 14 Bcfe, which represents 1% of our total proved reserves. During December 2010, production attributable to our interest from this field averaged 4 MMcf of natural gas per day and 38 barrels of oil per day.
Eagle Ford
We have 20,859 acres distributed across Atascosa, McMullen and Karnes Counties which is prospective for Eagle Ford shale development in South Texas. The Eagle Ford Shale is found between 7,500 feet and 11,500 feet across our acreage position. In 2010 we had two producing wells which we operate with a 100% working interest. In December 2010 both of these wells were producing a total of 525 barrels of oil per day and 352 Mcf per day of natural gas net to our interest. Our Eagle Ford proved reserves from this initial exploration activity during 2010 is estimated to be 10 Bcfe (85% oil) and represents 1% of our reserves.
Las Hermanitas
We own interests in and operate 15 natural gas wells (12.2 net to us) in the Las Hermanitas field, located in Duval County, Texas. These wells produce from the Wilcox formation at depths from approximately 11,400 to 11,800 feet. Our proved reserves of 10 Bcfe in this field represent approximately 1% of our proved reserves. During December 2010, net daily production attributable to our interest from this field averaged 3 MMcf of natural gas. We acquired interests in this field in 2006 and have subsequently drilled eleven successful wells in this field since the acquisition.
Segno
The Segno Field located in Polk County, Texas has an estimated proved reserves of 3 Bcfe which represents less than 1% of our total company proved reserves. Production is from shallow Yegua sands from 5,000 feet to 5,600 feet and deep Wilcox sands between 11,300 feet to 13,350 feet. We own interests in 10.5 net wells and do not operate any of the wells. During December 2010, net daily production attributable to our interest from this field averaged 1 MMcf of natural gas and 98 barrels of oil per day.
Lopeno
The Lopeno Field located in Zapata County, Texas has an estimated proved reserves of 3 Bcfe which represents less than 1% of our total company proved reserves. Production is from shallow Queen City sands between 2,200 feet and 2,600 feet and deeper Wilcox sands between 6,400 feet and 12,500 feet. We own interests in 18 wells (3.0 net to us) and operate one of these wells. During December 2010, net daily production attributable to our interest from this field averaged 0.2 MMcf of natural gas and 3 barrels of oil per day.

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Other Regions
Approximately 2%, or 22 Bcfe, of our proved reserves are in other regions, primarily in New Mexico, Kentucky and the Mid-Continent region. We own interests in 425 producing wells (163.6 net to us) in 15 fields within these regions. The field with the largest proved reserves is our San Juan Basin properties in New Mexico. Excluding production from the Mississippi properties we sold in 2010, net daily production from our other regions during 2010 totaled 6 MMcf of natural gas and 52 barrels of oil or 6 MMcfe per day.
San Juan
Our San Juan Basin properties are located in the west-central portion of the basin in San Juan County, New Mexico. These wells produce from multiple sands of the Cretaceous Dakota formation and the Fruitland Coal seams. The Dakota is generally found at about 6,000 feet with the shallower Fruitland seams encountered at 2,500 to 3,000 feet. Our proved reserves of 4 Bcfe in the San Juan field represent less than 1% of our reserves. We own interests in 97 wells (14.6 net to us) in this field. During December 2010, net daily production attributable to our interest from this field averaged 1 MMcf of natural gas and 3 barrels of oil.
Major Property Acquisitions
As a result of our acquisitions, we have added 984 Bcfe of proved oil and natural gas reserves since 1991. Our largest acquisitions include the following:
Shell Wilcox Acquisition. In December 2007, we completed the acquisition of certain oil and natural gas properties and related assets from SWEPI LP, an affiliate of Shell Oil Company for $160.1 million. The properties acquired had estimated proved reserves of approximately 70.1 Bcfe. Major fields acquired in the acquisition include the Fandango and Rosita fields.
Javelina Acquisition. In June 2007 we acquired additional working interests in oil and gas properties in the Javelina field in South Texas from Abaco Operating LLC for $31.2 million. The properties acquired had estimated proved reserves of approximately 9.1 Bcfe.
Denali Acquisition. In September 2006 we acquired proved and unproved oil and gas properties in the Las Hermanitas field in South Texas from Denali Oil & Gas Partners LP and other working interest owners for $67.2 million. The properties acquired had estimated proved reserves of approximately 16.5 Bcfe.
Ensight Acquisition. In May 2005, we completed the acquisition of certain oil and natural gas properties and related assets from Ensight Energy Partners, L.P., Laurel Production, LLC, Fairfield Midstream Services, LLC and Ensight Energy Management, LLC (collectively, “Ensight”) for $190.9 million. We also purchased additional interests in those properties from other owners for $10.9 million in July 2005. The properties acquired had estimated proved reserves of approximately 121.5 billion cubic feet of natural gas equivalent and included 312 active wells, of which 119 are operated by us. Major fields acquired include the Darco, Douglass, Cadeville, and Laurel fields.
Ovation Energy Acquisition. In October 2004, we acquired producing oil and gas properties in the East Texas, Arkoma, Anadarko and San Juan basins from Ovation Energy, L.P. for $62.0 million. The properties acquired had estimated proved reserves of approximately 41.0 billion cubic feet of gas equivalent and included 165 active wells, of which 69 were operated by us.
DevX Energy Acquisition. In December 2001, we completed the acquisition of DevX Energy, Inc. (“DevX”) by acquiring 100% of the common stock of DevX for $92.6 million. The total purchase price

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including debt and other liabilities assumed in the acquisition was $160.8 million. As a result of the acquisition of DevX, we acquired interests in 600 producing oil and natural gas wells located onshore primarily in East and South Texas, Kentucky, Oklahoma and Kansas. DevX’s properties had 1.2 MMBbls of oil reserves and 156.5 Bcf of natural gas reserves at the time of the acquisition.
Bois d’Arc Acquisition. In December 1997, Comstock acquired working interests in certain producing offshore Louisiana oil and gas properties as well as interests in undeveloped offshore oil and natural gas leases for approximately $200.9 million from Bois d’Arc Resources and certain of its affiliates and working interest partners. We acquired interests in 43 wells (29.6 net to us) and eight separate production complexes located in the Gulf of Mexico offshore of Plaquemines and Terrebonne Parishes, Louisiana. The acquisition included interests in the Louisiana state and federal offshore areas of Main Pass Block 21, Ship Shoal Blocks 66, 67, 68 and 69 and South Pelto Block 1. The net proved reserves acquired in this acquisition were estimated at 14.3 MMBbls of oil and 29.4 Bcf of natural gas. We divested of these offshore properties in 2008.
Black Stone Acquisition. In May 1996, we acquired 100% of the capital stock of Black Stone Oil Company and interests in producing and undeveloped oil and gas properties located in South Texas for $100.4 million. We acquired interests in 19 wells (7.7 net to us) that were located in the Double A Wells field in Polk County, Texas and we became the operator of most of the wells in the field. The net proved reserves acquired in this acquisition were estimated at 5.9 MMBbls of oil and 100.4 Bcf of natural gas.
Sonat Acquisition. In July 1995, we purchased interests in certain producing oil and gas properties located in East Texas and North Louisiana from Sonat Inc. for $48.1 million. We acquired interests in 319 producing wells (188.0 net to us). The acquisition included interests in the Logansport, Beckville, Waskom, Blocker and Hico-Knowles fields. The net proved reserves acquired in this acquisition were estimated at 0.8 MMBbls of oil and 104.7 Bcf of natural gas.
Oil and Natural Gas Reserves
The following table sets forth our estimated proved oil and natural gas reserves and the PV 10 Value as of December 31, 2010:

|  |  |  |  | Natural |  |  |  |  |  |  |
|  | Oil |  |  | Gas |  |  | Total |  |  | PV 10 Value |
|  | (MBbls) |  |  | (MMcf) |  |  | (MMcfe) |  |  | (000’s) |
Proved Developed: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Producing |  |  | 2,279 |  |  |  | 354,429 |  |  |  | 368,103 |  |  | $ | 608,902 |
Non-producing |  |  | 682 |  |  |  | 152,380 |  |  |  | 156,470 |  |  |  | 150,235 |
Total Proved Developed |  |  | 2,961 |  |  |  | 506,809 |  |  |  | 524,573 |  |  |  | 759,137 |
Proved Undeveloped |  |  | 1,258 |  |  |  | 518,824 |  |  |  | 526,377 |  |  |  | 38,489 |
Total Proved |  |  | 4,219 |  |  |  | 1,025,633 |  |  |  | 1,050,950 |  |  |  | 797,626 |
Discounted Future Income Taxes |  |  | (191,490 | )
Standardized Measure of Discounted Future Net Cash Flows(1) |  | $ | 606,136 |

(1) |  | The PV 10 Value represents the discounted future net cash flows attributable to our proved oil and natural gas reserves before income tax, discounted at 10%. Although it is a non-GAAP measure, we believe that the presentation of the PV 10 Value is relevant and useful to our investors because it presents the discounted future net cash flows attributable to our proved reserves prior to taking into account corporate future income taxes and our current tax structure. We use this measure when assessing the potential return on investment related to our oil and gas properties. The standardized measure of discounted future net cash flows represents the present value of future cash flows attributable to our proved oil and natural gas reserves after income tax, discounted at 10%.

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The following table sets forth our year end reserves as of December 31 for each of the last three fiscal years:

|  | 2008 |  |  | 2009 |  |  | 2010 |
|  | Oil |  |  | Natural Gas |  |  | Oil |  |  | Natural Gas |  |  | Oil |  |  | Natural Gas |
|  | (Mbbls) |  |  | (MMcf) |  |  | (Mbbls) |  |  | (MMcf) |  |  | (Mbbls) |  |  | (MMcf) |
Proved Developed |  |  | 5,446 |  |  |  | 354,934 |  |  |  | 4,894 |  |  |  | 367,102 |  |  |  | 2,961 |  |  |  | 506,809 |
Proved Undeveloped |  |  | 4,222 |  |  |  | 168,709 |  |  |  | 2,320 |  |  |  | 315,287 |  |  |  | 1,258 |  |  |  | 518,824 |
Total Proved Reserves |  |  | 9,668 |  |  |  | 523,643 |  |  |  | 7,214 |  |  |  | 682,389 |  |  |  | 4,219 |  |  |  | 1,025,633 |

Proved oil and natural gas reserves are the estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
There are numerous uncertainties inherent in estimating quantities of proved crude oil and natural gas reserves. Crude oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be precisely measured. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserves estimates are often different from the quantities of crude oil and natural gas that are ultimately recovered.
The average prices that we realized from sales of oil and natural gas, including the effect of hedging, and lifting costs including severance and ad valorem taxes and transportation costs, for each of the last three fiscal years were as follows:

|  | Year Ended December 31, |
|  | 2008 |  |  | 2009 |  |  | 2010 |
Oil Price — $/Bbl |  |  | $87.15 |  |  |  | $50.94 |  |  |  | $68.35 |
Natural Gas Price — $/Mcf |  |  | $8.83 |  |  |  | $4.16 |  |  |  | $4.35 |
Lifting costs — $/Mcfe |  |  | $1.45 |  |  |  | $1.08 |  |  |  | $1.10 |

The oil and natural gas prices used for reserves estimation were as follows:

|  |  |  |  |  | Natural
|  |  |  | Oil Price |  | Gas Price
Year |  |  |  | (per Bbl) |  | (per Mcf)
2008 |  | $ | 34.49 |  |  | $ | 5.33 |
2009 |  | $ | 49.60 |  |  | $ | 3.54 |
2010 |  | $ | 76.31 |  |  | $ | 4.16 |

Reserves may be classified as proved undeveloped if there is a high degree of confidence that the quantities will be recovered, and they are scheduled to be drilled within five years of their initial inclusion as proved reserves, unless specific circumstances justify a longer time. In addition, undeveloped reserves may be estimated through the use of reliable technology in addition to flow tests and production history. As of December 31, 2010, our proved reserves included 1.3 MMBbls of crude oil and 519 Bcf of natural gas, for a total of 526 Bcfe of undeveloped reserves. Approximately 83% of our proved undeveloped reserves at December 31, 2010 were associated with the future development of our Haynesville or Bossier shale

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##### Table of Contents

properties. The remaining proved undeveloped reserves are primarily associated with developing reserves in our Cotton Valley and Hosston sand reservoirs in East Texas/North Louisiana and our Eagle Ford shale, Wilcox and Vicksburg reservoirs in South Texas. Estimated future costs relating to the development of the undeveloped reserves are projected to be approximately $1.1 billion, of which $237.3 million, $380.9 million and $299.6 million are expected to be incurred in 2011, 2012 and 2013, respectively. Costs incurred relating to the development of our undeveloped reserves were approximately $104.4 million, $20.1 million and $16.9 million in 2008, 2009 and 2010, respectively. Following the initial success of our Haynesville shale evaluation wells, our 2010 drilling program was focused primarily to further evaluate and develop acreage that is prospective in the Haynesville shale formation. As a result, only three of the wells we drilled in 2010 resulted in conversions of proved undeveloped reserves to proved developed producing reserves at the end of 2010. All undeveloped drilling locations which comprise our undeveloped reserves at December 31, 2010 are scheduled to be drilled within five years of the year that such reserves were first included in our reported reserves.
We had proved reserve additions of 402 Bcfe in 2010 relating to discoveries resulting from our Haynesville and Bossier shale drilling program. These reserve additions related to 177 Bcfe assigned to 68 Haynesville and Bossier shale wells (41.5 net to us) that we drilled and 225 Bcfe assigned to 89 (55.5 net to us) proved undeveloped locations offsetting these wells. During 2010 we drilled the first wells in our acreage which is prospective for the Eagle Ford shale. Based on the drilling results from our first successful wells, we added 10.1 Bcfe to our proved reserves, most of which is crude oil or condensate. We also had an additional 19 Bcfe of reserve additions from our drilling activity in our non-shale oil and gas properties.
The estimates of our oil and natural gas reserves were determined by Lee Keeling and Associates, Inc. (“Lee Keeling”), an independent petroleum engineering firm. Lee Keeling has been providing consulting engineering and geological services for over fifty years. Lee Keeling’s professional staff is comprised of qualified petroleum engineers who are experienced in all productive areas of the United States.
Our policies regarding internal controls over the recording of reserves estimates requires that such estimates are in compliance with the SEC definitions and guidance. Inputs to our reserves estimation process, which we provide to Lee Keeling for use in their reserves evaluation, are based upon our historical results for production history, oil and natural gas prices, lifting and development costs, ownership interests and other required data. Our reservoir management group, comprised of qualified petroleum engineers, works with Lee Keeling to ensure that all data we provide is properly reflected in the final reserves estimates and consults with Lee Keeling throughout the reserves estimation process on technical questions regarding the reserve estimates.
We did not provide estimates of total proved oil and natural gas reserves during the years ended December 31, 2008, 2009 or 2010 to any federal authority or agency, other than the SEC.

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Drilling Activity Summary
During the three-year period ended December 31, 2010, we drilled development and exploratory wells as set forth in the table below:

|  | 2008 |  |  | 2009 |  |  | 2010 |
|  | Gross |  |  | Net |  |  | Gross |  |  | Net |  |  | Gross |  |  | Net |
Development: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Oil |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Gas |  |  | 127 |  |  |  | 71.5 |  |  |  | 37 |  |  |  | 27.2 |  |  |  | 65 |  |  |  | 41.1 |
Dry |  |  | 3 |  |  |  | 1.0 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
|  |  | 130 |  |  |  | 72.5 |  |  |  | 37 |  |  |  | 27.2 |  |  |  | 65 |  |  |  | 41.1 |
Exploratory: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Oil |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 3 |  |  |  | 3.0 |
Gas |  |  | 5 |  |  |  | 2.7 |  |  |  | 17 |  |  |  | 11.4 |  |  |  | 10 |  |  |  | 5.2 |
Dry |  |  | 1 |  |  |  | 0.5 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
|  |  | 6 |  |  |  | 3.2 |  |  |  | 17 |  |  |  | 11.4 |  |  |  | 13 |  |  |  | 8.2 |
Total |  |  | 136 |  |  |  | 75.7 |  |  |  | 54 |  |  |  | 38.6 |  |  |  | 78 |  |  |  | 49.3 |

In 2011 to the date of this report, we have drilled nine wells (4.6 net to us) and we have five wells (4.5 net to us) that are in the process of being drilled.
Producing Well Summary
The following table sets forth the gross and net producing oil and natural gas wells in which we owned an interest at December 31, 2010:

|  | Oil |  |  | Natural Gas |
|  | Gross |  |  | Net |  |  | Gross |  |  | Net |
Arkansas |  |  | — |  |  |  | — |  |  |  | 15 |  |  |  | 8.0 |
Kansas |  |  | — |  |  |  | — |  |  |  | 9 |  |  |  | 5.1 |
Kentucky |  |  | — |  |  |  | — |  |  |  | 86 |  |  |  | 76.1 |
Louisiana |  |  | 15 |  |  |  | 5.4 |  |  |  | 415 |  |  |  | 222.1 |
New Mexico |  |  | 1 |  |  |  | — |  |  |  | 96 |  |  |  | 14.6 |
Oklahoma |  |  | 10 |  |  |  | 1.2 |  |  |  | 127 |  |  |  | 17.9 |
Texas |  |  | 36 |  |  |  | 17.9 |  |  |  | 753 |  |  |  | 483.8 |
Wyoming |  |  | — |  |  |  | — |  |  |  | 26 |  |  |  | 1.9 |
Total |  |  | 62 |  |  |  | 24.5 |  |  |  | 1,527 |  |  |  | 829.5 |

We operate 899 of the 1,589 producing wells presented in the above table. As of December 31, 2010, we owned interests in 19 wells containing multiple completions, which means that a well is producing from more than one completed zone. Wells with more than one completion are reflected as one well in the table above.

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Acreage
The following table summarizes our developed and undeveloped leasehold acreage at December 31, 2010, all of which is onshore in the continental United States. We have excluded acreage in which our interest is limited to a royalty or overriding royalty interest.

|  | Developed |  |  | Undeveloped |
|  | Gross |  |  | Net |  |  | Gross |  |  | Net |
Arkansas |  |  | 1,280 |  |  |  | 684 |  |  |  | — |  |  |  | — |
Kansas |  |  | 6,400 |  |  |  | 4,064 |  |  |  | — |  |  |  | — |
Kentucky |  |  | 7,206 |  |  |  | 5,773 |  |  |  | — |  |  |  | — |
Louisiana |  |  | 88,816 |  |  |  | 52,534 |  |  |  | 33,511 |  |  |  | 28,107 |
New Mexico |  |  | 10,240 |  |  |  | 1,896 |  |  |  | — |  |  |  | — |
Oklahoma |  |  | 38,080 |  |  |  | 5,707 |  |  |  | — |  |  |  | — |
Texas |  |  | 123,833 |  |  |  | 68,796 |  |  |  | 30,561 |  |  |  | 26,243 |
Wyoming |  |  | 13,440 |  |  |  | 927 |  |  |  | — |  |  |  | — |
Total |  |  | 289,295 |  |  |  | 140,381 |  |  |  | 64,072 |  |  |  | 54,350 |

Our undeveloped acreage expires as follows:

Expires in 2011 |  |  | 55 | %
Expires in 2012 |  |  | 3 | %
Expires in 2013 |  |  | 42 | %
|  |  | 100 | %

Title to our oil and natural gas properties is subject to royalty, overriding royalty, carried and other similar interests and contractual arrangements customary in the oil and gas industry, liens incident to operating agreements and for current taxes not yet due and other minor encumbrances. All of our oil and natural gas properties are pledged as collateral under our bank credit facility. As is customary in the oil and gas industry, we are generally able to retain our ownership interest in undeveloped acreage by production of existing wells, by drilling activity which establishes commercial reserves sufficient to maintain the lease, by payment of delay rentals or by the exercise of contractual extension rights. The Company anticipates retaining ownership of a substantial amount of the acreage with primary terms expiring in 2011 through drilling activity or by extending the leases.
Markets and Customers
The market for oil and natural gas produced by us depends on factors beyond our control, including the extent of domestic production and imports of oil and natural gas, the proximity and capacity of natural gas pipelines and other transportation facilities, demand for oil and natural gas, the marketing of competitive fuels and the effects of state and federal regulation. The oil and gas industry also competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers.
Our oil production is sold under short-term contracts with a duration of six months or less. The contracts require the purchasers to purchase the amount of oil production that is available at prices tied to the spot oil markets. Our natural gas production is primarily sold under contracts with various terms and priced on first of the month index prices or on daily spot market prices. Approximately 82% of our 2010 natural gas sales were priced utilizing first of the month index prices and approximately 18% were priced utilizing daily spot prices. BP Energy Company and its subsidiaries accounted for 39% of our total 2010 sales. The loss of this customer would not have a material adverse effect on us as there is an available market for our crude oil and natural gas production from other purchasers.

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With the significant increase in our natural gas production in North Louisiana due to our Haynesville shale drilling program, we have entered into longer term marketing arrangements to ensure that we have adequate transportation to get our natural gas production to the markets. As an alternative to constructing our own gathering and treating facilities, we have entered into a variety of gathering and treating agreements with midstream companies to transport our natural gas to the long-haul natural gas pipelines. We have dedicated our production in our Logansport and Toledo Bend fields under such agreements for terms that expire from 2016 to 2018. We have a commitment to transport a minimum of 7.4 Bcf over 3.2 years under one of these agreements.
We have also entered into certain agreements with a major natural gas marketing company to provide us with firm transportation for our North Louisiana natural gas production on the long-haul pipelines. Under these agreements, we have priority access at certain delivery points for 80,000 MMBtus per day. These agreements expire from 2013 to 2019. To the extent we are not able to deliver the contracted natural gas volumes, we may be responsible for the transportation costs. Our production available to deliver under these agreements in North Louisiana is expected to exceed the firm transportation arrangements we have in place. In addition, the marketing company managing the firm transportation is required to use reasonable efforts to supplement our deliveries should we have a shortfall during the term of the agreements.
Competition
The oil and gas industry is highly competitive. Competitors include major oil companies, other independent energy companies and individual producers and operators, many of which have financial resources, personnel and facilities substantially greater than we do. We face intense competition for the acquisition of oil and natural gas properties and leases for oil and gas exploration.
Regulation
General. Various aspects of our oil and natural gas operations are subject to extensive and continually changing regulation, as legislation affecting the oil and natural gas industry is under constant review for amendment or expansion. Numerous departments and agencies, both federal and state, are authorized by statute to issue, and have issued, rules and regulations binding upon the oil and natural gas industry and its individual members. The Federal Energy Regulatory Commission, or “FERC,” regulates the transportation and sale for resale of natural gas in interstate commerce pursuant to the Natural Gas Act of 1938, or “NGA,” and the Natural Gas Policy Act of 1978, or “NGPA.” In 1989, however, Congress enacted the Natural Gas Wellhead Decontrol Act, which removed all remaining price and nonprice controls affecting all “first sales” of natural gas, effective January 1, 1993, subject to the terms of any private contracts that may be in effect. While sales by producers of natural gas and all sales of crude oil, condensate and natural gas liquids can currently be made at uncontrolled market prices, in the future Congress could reenact price controls or enact other legislation with detrimental impact on many aspects of our business. Under the provisions of the Energy Policy Act of 2005 (the “2005 Act”), the NGA has been amended to prohibit any form of market manipulation with the purchase or sale of natural gas, and the FERC has issued new regulations that are intended to increase natural gas pricing transparency. The 2005 Act has also significantly increased the penalties for violations of the NGA. The FERC has issued Order No. 704 et al. which requires a market participant to make an annual filing if it has sales or purchases equal to or greater than 2.2 million MMBtu in the reporting year to facilitate price transparency.
Regulation and transportation of natural gas. Our sales of natural gas are affected by the availability, terms and cost of transportation. The price and terms for access to pipeline transportation are subject to extensive regulation. The FERC requires interstate pipelines to provide open-access transportation on a not unduly discriminatory basis for similarly situated shippers. The FERC frequently reviews and modifies its

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regulations regarding the transportation of natural gas, with the stated goal of fostering competition within the natural gas industry.
Intrastate natural gas transportation is subject to regulation by state regulatory agencies. The Texas Railroad Commission has been changing its regulations governing transportation and gathering services provided by intrastate pipelines and gatherers. While the changes by these state regulators affect us only indirectly, they are intended to further enhance competition in natural gas markets. We cannot predict what further action the FERC or state regulators will take on these matters; however, we do not believe that we will be affected differently in any material respect than other natural gas producers with which we compete by any action taken.
Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, the FERC, state commissions and the courts. The natural gas industry historically has been very heavily regulated; therefore, there is no assurance that the less stringent regulatory approach pursued by the FERC, Congress and state regulatory authorities will continue.
Federal leases. Some of our operations are located on federal oil and natural gas leases that are administered by the Bureau of Land Management (“BLM”) of the United States Department of the Interior. These leases are issued through competitive bidding and contain relatively standardized terms. These leases require compliance with detailed Department of Interior and BLM regulations and orders that are subject to interpretation and change. These leases are also subject to certain regulations and orders promulgated by the Department of Interior’s Bureau of Ocean Energy Management, Regulation & Enforcement (“BOEMRE”), through its Minerals Revenue Management Program, which is responsible for the management of revenues from both onshore and offshore leases. Additionally, some of our federal leases are subject to the Indian Mineral Development Act of 1982, and are therefore subject to supplemental regulations and orders of the Department of Interior’s Bureau of Indian Affairs. While we cannot predict how various federal agencies may change their interpretations of existing regulations and orders or how regulations and orders issued in the future will impact our operations located on these federal leases, we do not believe we will be affected differently than other similarly situated oil and natural gas producers.
Oil and natural gas liquids transportation rates. Our sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at market prices. In a number of instances, however, the ability to transport and sell such products is dependent on pipelines whose rates, terms and conditions of service are subject to FERC jurisdiction under the Interstate Commerce Act. In other instances, the ability to transport and sell such products is dependent on pipelines whose rates, terms and conditions of service are subject to regulation by state regulatory bodies under state statutes. The price received from the sale of these products may be affected by the cost of transporting the products to market.
The FERC’s regulation of pipelines that transport crude oil, condensate and natural gas liquids under the Interstate Commerce Act is generally more light-handed than the FERC’s regulation of natural gas pipelines under the NGA. FERC-regulated pipelines that transport crude oil, condensate and natural gas liquids are subject to common carrier obligations that generally ensure non-discriminatory access. With respect to interstate pipeline transportation subject to regulation of the FERC under the Interstate Commerce Act, rates generally must be cost-based, although settlement rates agreed to by all shippers are permitted and market-based rates are permitted in certain circumstances. Effective January 1, 1995, the FERC implemented regulations establishing an indexing system (based on inflation) for transportation rates governed by the Interstate Commerce Act that allowed for an increase or decrease in the transportation rates. The FERC’s regulations include a methodology for such pipelines to change their rates through the use of an index system that establishes ceiling levels for such rates. The mandatory five year review in 2005 revised the methodology for this index to be based on Producer Price Index for Finished Goods (PPI-FG) plus 1.3 percent for the period July 1, 2006 through June 30, 2011. The mandatory five year review in 2010

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revised the methodology for this index to be based on PPI-FG plus 2.65 percent for the period July 1, 2011 through June 30, 2016. The regulations provide that each year the Commission will publish the oil pipeline index after the PPI-FG becomes available.
With respect to intrastate crude oil, condensate and natural gas liquids pipelines subject to the jurisdiction of state agencies, such state regulation is generally less rigorous than the regulation of interstate pipelines. State agencies have generally not investigated or challenged existing or proposed rates in the absence of shipper complaints or protests. Complaints or protests have been infrequent and are usually resolved informally.
We do not believe that the regulatory decisions or activities relating to interstate or intrastate crude oil, condensate or natural gas liquids pipelines will affect us in a way that materially differs from the way it affects other crude oil, condensate and natural gas liquids producers or marketers.
Environmental regulations. We are subject to stringent federal, state and local laws. These laws, among other things, govern the issuance of permits to conduct exploration, drilling and production operations, the amounts and types of materials that may be released into the environment, the discharge and disposition of waste materials, the remediation of contaminated sites and the reclamation and abandonment of wells, sites and facilities. Numerous governmental departments issue rules and regulations to implement and enforce such laws, which are often difficult and costly to comply with and which carry substantial civil and even criminal penalties for failure to comply. Some laws, rules and regulations relating to protection of the environment may, in certain circumstances, impose strict liability for environmental contamination, rendering a person liable for environmental damages and cleanup cost without regard to negligence or fault on the part of such person. Other laws, rules and regulations may restrict the rate of oil and natural gas production below the rate that would otherwise exist or even prohibit exploration and production activities in sensitive areas. In addition, state laws often require various forms of remedial action to prevent pollution, such as closure of inactive pits and plugging of abandoned wells. The regulatory burden on the oil and natural gas industry increases our cost of doing business and consequently affects our profitability. These costs are considered a normal, recurring cost of our on-going operations. Our domestic competitors are generally subject to the same laws and regulations.
We believe that we are in substantial compliance with current applicable environmental laws and regulations and that continued compliance with existing requirements will not have a material adverse impact on our operations. However, environmental laws and regulations have been subject to frequent changes over the years, and the imposition of more stringent requirements or new regulatory schemes such as carbon “cap and trade” programs could have a material adverse effect upon our capital expenditures, earnings or competitive position, including the suspension or cessation of operations in affected areas. As such, there can be no assurance that material cost and liabilities will not be incurred in the future.
The Comprehensive Environmental Response, Compensation and Liability Act, or “CERCLA,” imposes liability, without regard to fault, on certain classes of persons that are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the current or former owner or operator of the disposal site or sites where the release occurred and companies that disposed or arranged for the disposal of hazardous substances. Under CERCLA, such persons may be subject to joint and several liability for the cost of investigating and cleaning up hazardous substances that have been released into the environment, for damages to natural resources and for the cost of certain health studies. In addition, companies that incur liability frequently also confront third party claims because it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment from a polluted site.

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The Federal Solid Waste Disposal Act, as amended by the Resource Conservation and Recovery Act of 1976, or “RCRA,” regulates the generation, transportation, storage, treatment and disposal of hazardous wastes and can require cleanup of hazardous waste disposal sites. RCRA currently excludes drilling fluids, produced waters and other wastes associated with the exploration, development or production of oil and natural gas from regulation as “hazardous waste.” Disposal of such non-hazardous oil and natural gas exploration, development and production wastes usually are regulated by state law. Other wastes handled at exploration and production sites or used in the course of providing well services may not fall within this exclusion. Moreover, stricter standards for waste handling and disposal may be imposed on the oil and natural gas industry in the future. From time to time, legislation is proposed in Congress that would revoke or alter the current exclusion of exploration, development and production wastes from RCRA’s definition of “hazardous wastes,” thereby potentially subjecting such wastes to more stringent handling, disposal and cleanup requirements. If such legislation were enacted, it could have a significant impact on our operating cost, as well as the oil and natural gas industry in general. The impact of future revisions to environmental laws and regulations cannot be predicted.
Our operations are also subject to the Clean Air Act, or “CAA,” and comparable state and local requirements. Amendments to the CAA were adopted in 1990 and contain provisions that may result in the gradual imposition of certain pollution control requirements with respect to air emissions from our operations. We may be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions. However, we believe our operations will not be materially adversely affected by any such requirements, and the requirements are not expected to be any more burdensome to us than to other similarly situated companies involved in oil and natural gas exploration and production activities.
The Federal Water Pollution Control Act of 1972, as amended, or the “Clean Water Act,” imposes restrictions and controls on the discharge of produced waters and other wastes into navigable waters. Permits must be obtained to discharge pollutants into state and federal waters and to conduct construction activities in waters and wetlands. Certain state regulations and the general permits issued under the Federal National Pollutant Discharge Elimination System program prohibit the discharge of produced waters and sand, drilling fluids, drill cuttings and certain other substances related to the oil and natural gas industry into certain coastal and offshore waters, unless otherwise authorized. Further, the EPA has adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain permits for storm water discharges. Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans. The Clean Water Act and comparable state statutes provide for civil, criminal and administrative penalties for unauthorized discharges for oil and other pollutants and impose liability on parties responsible for those discharges for the cost of cleaning up any environmental damage caused by the release and for natural resource damages resulting from the release. We believe that our operations comply in all material respects with the requirements of the Clean Water Act and state statutes enacted to control water pollution.
Federal regulators require certain owners or operators of facilities that store or otherwise handle oil to prepare and implement spill prevention, control, countermeasure and response plans relating to the possible discharge of oil into surface waters. The Oil Pollution Act of 1990 (“OPA”) contains numerous requirements relating to the prevention and response to oil spills in the waters of the United States. The OPA subjects owners of facilities to strict joint and several liability for all containment and cleanup costs and certain other damages relating to a spill. Noncompliance with OPA may result in varying civil and criminal penalties and liabilities.
Executive Order 13158, issued on May 26, 2000, directs federal agencies to safeguard existing Marine Protected Areas, or “MPAs,” in the United States and establish new MPAs. The order requires federal agencies to avoid harm to MPAs to the extent permitted by law and to the maximum extent practicable. It

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also directs the EPA to propose new regulations under the Clean Water Act to ensure appropriate levels of protection for the marine environment. This order has the potential to adversely affect our operations by restricting areas in which we may carry out future exploration and development projects and/or causing us to incur increased operating expenses.
Certain flora and fauna that have officially been classified as “threatened” or “endangered” are protected by the Endangered Species Act. This law prohibits any activities that could “take” a protected plant or animal or reduce or degrade its habitat area. If endangered species are located in an area we wish to develop, the work could be prohibited or delayed and/or expensive mitigation might be required.
Other statutes that provide protection to animal and plant species and which may apply to our operations include, but are not necessarily limited to, the Oil Pollution Act, the Emergency Planning and Community Right-to-Know Act, the Marine Mammal Protection Act, the Marine Protection, Research and Sanctuaries Act, the Fish and Wildlife Coordination Act, the Fishery Conservation and Management Act, the Migratory Bird Treaty Act and the National Historic Preservation Act. These laws and regulations may require the acquisition of a permit or other authorization before construction or drilling commences and may limit or prohibit construction, drilling and other activities on certain lands lying within wilderness or wetlands and other protected areas and impose substantial liabilities for pollution resulting from our operations. The permits required for our various operations are subject to revocation, modification and renewal by issuing authorities. In addition, laws such as the National Environmental Policy Act and the Coastal Zone Management Act may make the process of obtaining certain permits more difficult or time consuming, resulting in increased costs and potential delays that could affect the viability or profitability of certain activities.
Certain statutes such as the Emergency Planning and Community Right to Know Act require the reporting of hazardous chemicals manufactured, processed, or otherwise used, which may lead to heightened scrutiny of the company’s operations by regulatory agencies or the public. In 2010, EPA adopted a new reporting requirement, the Petroleum and Natural Gas Systems Greenhouse Gas Reporting Rule (40 C.F.R. Part 98, Subpart W), which requires certain onshore petroleum and natural gas facilities to begin collecting data on their emissions of greenhouse gases (“GHGs”) in January 2011, with the first annual reports of those emissions due on March 31, 2012. GHGs include gases such as methane, a primary component of natural gas, and carbon dioxide, a byproduct of burning natural gas. Different GHGs have different global warming potentials with CO2 having the lowest global warming potential, so emissions of GHGs are typically expressed in terms of CO2 equivalents, or CO2e. The rule applies to facilities that emit 25,000 metric tons of CO2e or more per year, and requires onshore petroleum and natural gas operators to group all equipment under common ownership or control within a single hydrocarbon basin together when determining if the threshold is met. We have determined that these new reporting requirements apply to us and we are implementing procedures to collect the required information.
Such changes in environmental laws and regulations which result in more stringent and costly reporting, or waste handling, storage, transportation, disposal or cleanup activities, could materially affect companies operating in the energy industry. In addition, EPA is considering further regulation of climate change. Adoption of new regulations that regulate or restrict GHG emissions from oil and gas production could adversely affect our business, financial position, results of operations and prospects, as could the adoption of new laws or regulations which levy taxes or other costs on greenhouse gas emissions from other industries, which could result in changes to the consumption and demand for natural gas. We may also be assessed administrative, civil and/or criminal penalties if we fail to comply with any such new laws and regulations applicable to oil and natural gas production.
We maintain insurance against “sudden and accidental” occurrences, which may cover some, but not all, of the risks described above. Most significantly, the insurance we maintain will not cover the risks described above which occur over a sustained period of time. Further, there can be no assurance that such

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insurance will continue to be available to cover all such cost or that such insurance will be available at a cost that would justify its purchase. The occurrence of a significant event not fully insured or indemnified against could have a material adverse effect on our financial condition and results of operations.
Regulation of oil and natural gas exploration and production. Our exploration and production operations are subject to various types of regulation at the federal, state and local levels. Such regulations include requiring permits and drilling bonds for the drilling of wells, regulating the location of wells, the method of drilling and casing wells and the surface use and restoration of properties upon which wells are drilled. Many states also have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from oil and natural gas wells and the regulation of spacing, plugging and abandonment of such wells. Some state statutes limit the rate at which oil and natural gas can be produced from our properties.
State regulation. Most states regulate the production and sale of oil and natural gas, including requirements for obtaining drilling permits, the method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and gas resources. The rate of production may be regulated and the maximum daily production allowable from both oil and gas wells may be established on a market demand or conservation basis or both.
Office and Operations Facilities
Our executive offices are located at 5300 Town and Country Blvd., Suite 500 in Frisco, Texas 75034 and our telephone number is (972) 668-8800. We lease office space in Frisco, Texas covering 53,364 square feet at a monthly rate of $100,057. This lease expires on July 31, 2014. We also own production offices and pipe yard facilities near Marshall, Livingston, and Zapata, Texas; Logansport, Louisiana and Guston, Kentucky.
Employees
As of December 31, 2010, we had 127 employees and utilized contract employees for certain of our field operations. We consider our employee relations to be satisfactory.
Directors and Executive Officers
The following table sets forth certain information concerning our executive officers and directors.

Name |  | Position with Company |  | Age
M. Jay Allison |  | President, Chief Executive Officer and Chairman of the Board of Directors |  |  | 55 |
Roland O. Burns |  | Senior Vice President, Chief Financial Officer, Secretary, Treasurer and Director |  |  | 50 |
D. Dale Gillette |  | Vice President of Land and General Counsel |  |  | 65 |
Mack D. Good |  | Chief Operating Officer |  |  | 61 |
Stephen E. Neukom |  | Vice President of Marketing |  |  | 61 |
Daniel K. Presley |  | Vice President of Accounting and Controller |  |  | 50 |
Richard D. Singer |  | Vice President of Financial Reporting |  |  | 56 |
David K. Lockett |  | Director |  |  | 56 |
Cecil E. Martin |  | Director |  |  | 69 |
David W. Sledge |  | Director |  |  | 54 |
Nancy E. Underwood |  | Director |  |  | 59 |

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Executive Officers
A brief biography of each person who serves as a director or executive officer follows below.
M. Jay Allison has been a director since 1987, and our President and Chief Executive Officer since 1988. Mr. Allison was elected Chairman of the board of directors in 1997. From 1987 to 1988, Mr. Allison served as our Vice President and Secretary. From 1981 to 1987, he was a practicing oil and gas attorney with the firm of Lynch, Chappell & Alsup in Midland, Texas. Mr. Allison was Chairman of the Board of Directors of Bois d’Arc Energy, Inc. from the time of its formation in 2004 until its merger with Stone Energy Corporation in 2008. He received B.B.A., M.S. and J.D. degrees from Baylor University in 1978, 1980 and 1981, respectively. Mr. Allison also currently serves as a Director of Tidewater, Inc.
Roland O. Burns has been our Senior Vice President since 1994, Chief Financial Officer and Treasurer since 1990, our Secretary since 1991 and a director since 1999. From 1982 to 1990, Mr. Burns was employed by the public accounting firm, Arthur Andersen. During his tenure with Arthur Andersen, Mr. Burns worked primarily in the firm’s oil and gas audit practice. Mr. Burns was a director, Senior Vice President and the Chief Financial Officer of Bois d’Arc Energy, Inc. from the time of its formation in 2004 until its merger with Stone Energy Corporation in 2008. Mr. Burns received B.A. and M.A. degrees from the University of Mississippi in 1982 and is a Certified Public Accountant.
D. Dale Gillette has been our Vice President of Land and General Counsel since 2006. Prior to joining us, Mr. Gillette practiced law extensively in the energy sector for 32 years, most recently as a partner with Gardere Wynne Sewell LLP, and before that with Locke Liddell & Sapp LLP. During that time he represented independent exploration and production companies and large financial institutions in numerous oil and gas transactions. Mr. Gillette has also served as corporate counsel in the legal department of Mesa Petroleum Co. and in the legal department of Enserch Corp. Mr. Gillette holds B.A. and J.D. degrees from the University of Texas and is a member of the State Bar of Texas.
Mack D. Good was appointed our Chief Operating Officer in 2004. From 1999 to 2004, he served as Vice President of Operations. From 1997 until 1999, Mr. Good served as our district engineer for the East Texas/North Louisiana region. From 1983 until 1997, Mr. Good was with Enserch Exploration, Inc. serving in various operations management and engineering positions. Mr. Good received a B.S. of Biology/Chemistry from Oklahoma State University in 1975 and a B.S. of Petroleum Engineering from the University of Tulsa in 1983. He is a Registered Professional Engineer in the State of Texas.
Stephen E. Neukom has been our Vice President of Marketing since 1997 and has served as our manager of crude oil and natural gas marketing since 1996. From 1994 to 1996, Mr. Neukom served as vice president of Comstock Natural Gas, Inc., our former wholly owned gas marketing subsidiary. Prior to joining us, Mr. Neukom was senior vice president of Victoria Gas Corporation from 1987 to 1994. Mr. Neukom received a B.B.A. degree from the University of Texas in 1972.
Daniel K. Presley has been our Vice President of Accounting since 1997 and has been with us since 1989, serving as controller since 1991. Prior to joining us, Mr. Presley had six years of experience with several independent oil and gas companies including AmBrit Energy, Inc. Prior thereto, Mr. Presley spent two and one-half years with B.D.O. Seidman, a public accounting firm. Mr. Presley received a B.B.A. from Texas A & M University in 1983.
Richard D. Singer has been our Vice President of Financial Reporting since 2005. Mr. Singer has over 30 years of experience in financial accounting and reporting. Prior to joining us, Mr. Singer most recently served as an assistant controller for Holly Corporation from 2004 to 2005 and as assistant controller for

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Santa Fe International Corporation from 1988 to 2002. Mr. Singer received a B.S. degree from the Pennsylvania State University in 1976 and is a Certified Public Accountant.
Outside Directors
David K. Lockett has served as a director since 2001. Mr. Lockett is a Vice President with Dell Inc. and has held executive management positions in several divisions within Dell since 1991. Mr. Lockett has been employed by Dell Inc. for the past 19 years and has been in the technology industry for the past 34 years. Mr. Lockett was a director of Bois d’Arc Energy, Inc. from 2005 until its merger with Stone Energy Corporation in 2008. Mr. Lockett received a B.B.A. degree from Texas A&M University in 1976.
Cecil E. Martin has served as a director since 1988. Mr. Martin is an independent commercial real estate investor who has primarily been managing his personal real estate investments since 1991. From 1973 to1991, he also served as chairman of a public accounting firm in Richmond, Virginia. Mr. Martin was a director and chairman of the Audit Committee of Bois d’Arc Energy, Inc. from 2005 until its merger with Stone Energy Corporation in 2008. Mr. Martin also serves on the board of directors of Crosstex Energy, Inc. and Crosstex Energy, L.P. Mr. Martin holds a B.B.A. degree from Old Dominion University and is a Certified Public Accountant.
David W. Sledge has served as a director since 1996. Mr. Sledge was President and Chief Operating Officer of Sledge Drilling Company until it was acquired by Basic Energy Services, Inc. in 2007 and served as a Vice President of Basic Energy Services, Inc. from 2007 to 2009. He served as an area operations manager for Patterson-UTI Energy, Inc. from May 2004 until 2006. From 1996 until 2004, Mr. Sledge managed his personal investments in oil and gas exploration activities. Mr. Sledge was a Director of Bois d’Arc Energy, Inc. from 2005 until its merger with Stone Energy Corporation in 2008. Mr. Sledge is a past director of the International Association of Drilling Contractors and is a past chairman of the Permian Basin chapter of this association. He received a B.B.A. degree from Baylor University in 1979.
Nancy E. Underwood has served as a director since 2004. Ms. Underwood is owner and President of Underwood Financial Ltd., a position she has held since 1986. Ms. Underwood holds B.S. and J.D. degrees from Emory University and practiced law at an Atlanta, Georgia based law firm before joining River Hill Development Corporation in 1981. Ms. Underwood currently serves on the Executive Board and Campaign Steering Committee of the Southern Methodist University Dedman School of Law and on the board of the Texas Health Presbyterian Foundation.
Available Information
Our executive offices are located at 5300 Town and Country Blvd., Suite 500, Frisco, Texas 75034. Our telephone number is (972) 668-8800. We file annual, quarterly and current reports, proxy statements and other documents with the SEC under the Securities Exchange Act of 1934. The public may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street N.E., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. In addition, the SEC maintains a website that contains reports, proxy and information statements, and other information that is electronically filed with the SEC. The public can obtain any documents that we file with the SEC at www.sec.gov. We also make available free of charge on our website (www.comstockresources.com) our Annual Report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and, if applicable, amendments to those reports filed or furnished pursuant to Section 13(a) of the Exchange Act as soon as reasonably practicable after we file such material with, or furnish it to, the SEC.

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ITEM 1A. | RISK FACTORS

You should carefully consider the following risk factors as well as the other information contained or incorporated by reference in this report, as these important factors, among others, could cause our actual results to differ from our expected or historical results. It is not possible to predict or identify all such factors. Consequently, you should not consider any such list to be a complete statement of all of our potential risks or uncertainties.
A substantial or extended decline in oil and natural gas prices may adversely affect our business, financial condition, cash flow, liquidity or results of operations and our ability to meet our capital expenditure obligations and financial commitments and to implement our business strategy.
Our business is heavily dependent upon the prices of, and demand for, oil and natural gas. Historically, the prices for oil and natural gas have been volatile and are likely to remain volatile in the future. The prices we receive for our oil and natural gas production and the level of such production will be subject to wide fluctuations and depend on numerous factors beyond our control, including the following:

| • | the domestic and foreign supply of oil and natural gas;
| • | weather conditions;
| • | the price and quantity of imports of crude oil and natural gas;
| • | political conditions and events in other oil-producing and natural gas-producing countries, including embargoes, hostilities in the Middle East and other sustained military campaigns, and acts of terrorism or sabotage;
| • | the actions of the Organization of Petroleum Exporting Countries, or OPEC;
| • | domestic government regulation, legislation and policies;
| • | the level of global oil and natural gas inventories;
| • | technological advances affecting energy consumption;
| • | the price and availability of alternative fuels; and
| • | overall economic conditions.

If the decline in the price of natural gas that first started in 2008 continues through 2011, the lower prices will adversely affect:

| • | our revenues, profitability and cash flow from operations;
| • | the value of our proved oil and natural gas reserves;
| • | the economic viability of certain of our drilling prospects;
| • | our borrowing capacity; and
| • | our ability to obtain additional capital.

In the future we may enter into hedging arrangements in order to reduce our exposure to price risks. Such arrangements would limit our ability to benefit from increases in oil and natural gas prices.
The recent recession could have a material adverse impact on our financial position, results of operations and cash flows.
The oil and gas industry is cyclical and tends to reflect general economic conditions. The United States and other countries have been in a recession which could continue through 2011 and beyond, and the capital markets have experienced significant volatility. The recession has had an adverse impact on demand and pricing for crude oil and natural gas. A continuation of the recession could have a further negative impact on oil and natural gas prices. Our operating cash flows and profitability will be significantly affected by declining oil and natural gas prices. Further declines in oil and natural gas prices may also impact the value

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of our oil and gas reserves, which could result in future impairment charges to reduce the carrying value of our oil and gas properties and our marketable securities. Our future access to capital could be limited due to tightening credit markets and volatile capital markets. If our access to capital is limited, development of our assets may be delayed or limited, and we may not be able to execute our growth strategy.
Our future production and revenues depend on our ability to replace our reserves.
Our future production and revenues depend upon our ability to find, develop or acquire additional oil and natural gas reserves that are economically recoverable. Our proved reserves will generally decline as reserves are depleted, except to the extent that we conduct successful exploration or development activities or acquire properties containing proved reserves, or both. To increase reserves and production, we must continue our acquisition and drilling activities. We cannot assure you, however, that our acquisition and drilling activities will result in significant additional reserves or that we will have continuing success drilling productive wells at low finding and development costs. Furthermore, while our revenues may increase if prevailing oil and natural gas prices increase significantly, our finding costs for additional reserves could also increase.
Prospects that we decide to drill may not yield oil or natural gas in commercially viable quantities or quantities sufficient to meet our targeted rate of return.
A prospect is a property in which we own an interest or have operating rights and that has what our geoscientists believe, based on available seismic and geological information, to be an indication of potential oil or natural gas. Our prospects are in various stages of evaluation, ranging from a prospect that is ready to be drilled to a prospect that will require substantial additional evaluation and interpretation. There is no way to predict in advance of drilling and testing whether any particular prospect will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. The use of seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in commercial quantities. The analysis that we perform using data from other wells, more fully explored prospects and/or producing fields may not be useful in predicting the characteristics and potential reserves associated with our drilling prospects. If we drill additional unsuccessful wells, our drilling success rate may decline and we may not achieve our targeted rate of return.
Federal hydraulic fracturing legislation could increase our costs and restrict our access to our oil and gas reserves.
Several proposals are before the United States Congress that, if implemented, would subject the process of hydraulic fracturing to regulation under the Safe Drinking Water Act. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into rock formations to stimulate natural gas production. The use of hydraulic fracturing is necessary to produce commercial quantities of crude oil and natural gas from many reservoirs including the Haynesville shale, Bossier shale, Eagle Ford shale, Cotton Valley and other tight natural gas reservoirs. At the direction of Congress, EPA is currently conducting an extensive, multi-year study into the potential effects of hydraulic fracturing on underground sources of drinking water, and the results of that study have the potential to impact the likelihood or scope of future legislation or regulation.
Although it is not possible at this time to predict the final outcome of any legislation regarding hydraulic fracturing, several states, including some in which we operate such as Arkansas, have adopted or proposed rules that would limit or regulate hydraulic fracturing, and/or require disclosure of chemicals used in hydraulic fracturing. These new state rules and any new federal restrictions on hydraulic fracturing that may be imposed in areas in which we conduct business, could significantly increase our operating, capital and compliance costs as well as delay or inhibit our ability to develop our oil and natural gas reserves.

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Potential changes to US federal tax regulations, if passed, will have an adverse effect on us.
The United States Congress continues to consider imposing new taxes and repeal of many tax incentives and deductions that are currently used by independent oil and gas producers. Examples of changes being considered that would impact us are: elimination of the ability to fully deduct intangible drilling costs in the year incurred, repeal of the manufacturing tax deduction for oil and gas companies, increasing the geological and geophysical cost amortization period, and implementation of a fee on non-producing leases located on federal lands. If these proposals are enacted, our current income tax liability will increase, potentially significantly, which would have a negative impact on our cash flow from operating activities. A reduction in operating cash flow could require us to reduce our drilling activities. Since none of these proposals have yet to be included in new legislation, we do not know the ultimate impact they may have on our business.
Our debt service requirements could adversely affect our operations and limit our growth.
We had $513.4 million in debt as of December 31, 2010, and our ratio of total debt to total capitalization was approximately 32%.
Our outstanding debt will have important consequences, including, without limitation:

| • | a portion of our cash flow from operations will be required to make debt service payments;
| • | our ability to borrow additional amounts for working capital, capital expenditures (including acquisitions) or other purposes will be limited; and
| • | our debt could limit our ability to capitalize on significant business opportunities, our flexibility in planning for or reacting to changes in market conditions and our ability to withstand competitive pressures and economic downturns.

In addition, future acquisition or development activities may require us to alter our capitalization significantly. These changes in capitalization may significantly increase our debt. Moreover, our ability to meet our debt service obligations and to reduce our total debt will be dependent upon our future performance, which will be subject to general economic conditions and financial, business and other factors affecting our operations, many of which are beyond our control. If we are unable to generate sufficient cash flow from operations in the future to service our indebtedness and to meet other commitments, we will be required to adopt one or more alternatives, such as refinancing or restructuring our indebtedness, selling material assets or seeking to raise additional debt or equity capital. We cannot assure you that any of these actions could be effected on a timely basis or on satisfactory terms or that these actions would enable us to continue to satisfy our capital requirements.
Our bank credit facility contains a number of significant covenants. These covenants will limit our ability to, among other things:

| • | borrow additional money;
| • | merge, consolidate or dispose of assets;
| • | make certain types of investments;
| • | enter into transactions with our affiliates; and
| • | pay dividends.

Our failure to comply with any of these covenants could cause a default under our bank credit facility and the respective indentures governing our 67/8% senior notes due 2012 and 83/8% senior notes due 2017. A default, if not waived, could result in acceleration of our indebtedness, in which case the debt would become immediately due and payable. If this occurs, we may not be able to repay our debt or borrow sufficient funds

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to refinance it given the current status of the credit markets. Even if new financing is available, it may not be on terms that are acceptable to us. Complying with these covenants may cause us to take actions that we otherwise would not take or not take actions that we otherwise would take.
The unavailability or high cost of drilling rigs, equipment, supplies or qualified personnel and oilfield services could adversely affect our ability to execute our exploration and development plans on a timely basis and within our budget.
Our industry has experienced a shortage of drilling rigs, equipment, supplies and qualified personnel in recent years as the result of higher demand for these services. Costs and delivery times of rigs, equipment and supplies have been substantially greater than they were several years ago. In addition, demand for, and wage rates of, qualified drilling rig crews have escalated due to the higher activity levels. Shortages of drilling rigs, equipment or supplies or qualified personnel in the areas in which we operate could delay or restrict our exploration and development operations, which in turn could adversely affect our financial condition and results of operations because of our concentration in those areas.
Our business involves many uncertainties and operating risks that can prevent us from realizing profits and can cause substantial losses.
Our future success will depend on the success of our exploration and development activities. Exploration activities involve numerous risks, including the risk that no commercially productive natural gas or oil reserves will be discovered. In addition, these activities may be unsuccessful for many reasons, including weather, cost overruns, equipment shortages and mechanical difficulties. Moreover, the successful drilling of a natural gas or oil well does not ensure we will realize a profit on our investment. A variety of factors, both geological and market-related, can cause a well to become uneconomical or only marginally economical. In addition to their costs, unsuccessful wells can hurt our efforts to replace production and reserves.
Our business involves a variety of operating risks, including:

| • | unusual or unexpected geological formations;
| • | fires;
| • | explosions;
| • | blow-outs and surface cratering;
| • | uncontrollable flows of natural gas, oil and formation water;
| • | natural disasters, such as hurricanes, tropical storms and other adverse weather conditions;
| • | pipe, cement, or pipeline failures;
| • | casing collapses;
| • | mechanical difficulties, such as lost or stuck oil field drilling and service tools;
| • | abnormally pressured formations; and
| • | environmental hazards, such as natural gas leaks, oil spills, pipeline ruptures and discharges of toxic gases.

If we experience any of these problems, well bores, gathering systems and processing facilities could be affected, which could adversely affect our ability to conduct operations.
We could also incur substantial losses as a result of:

| • | injury or loss of life;
| • | severe damage to and destruction of property, natural resources and equipment;
| • | pollution and other environmental damage;

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| • | clean-up responsibilities;
| • | regulatory investigation and penalties;
| • | suspension of our operations; and
| • | repairs to resume operations.

We pursue acquisitions as part of our growth strategy and there are risks in connection with acquisitions.
Our growth has been attributable in part to acquisitions of producing properties and companies. We expect to continue to evaluate and, where appropriate, pursue acquisition opportunities on terms we consider favorable. However, we cannot assure you that suitable acquisition candidates will be identified in the future, or that we will be able to finance such acquisitions on favorable terms. In addition, we compete against other companies for acquisitions, and we cannot assure you that we will successfully acquire any material property interests. Further, we cannot assure you that future acquisitions by us will be integrated successfully into our operations or will increase our profits.
The successful acquisition of producing properties requires an assessment of numerous factors beyond our control, including, without limitation:

| • | recoverable reserves;
| • | exploration potential;
| • | future oil and natural gas prices;
| • | operating costs; and
| • | potential environmental and other liabilities.

In connection with such an assessment, we perform a review of the subject properties that we believe to be generally consistent with industry practices. The resulting assessments are inexact and their accuracy uncertain, and such a review may not reveal all existing or potential problems, nor will it necessarily permit us to become sufficiently familiar with the properties to fully assess their merits and deficiencies. Inspections may not always be performed on every well, and structural and environmental problems are not necessarily observable even when an inspection is made.
Additionally, significant acquisitions can change the nature of our operations and business depending upon the character of the acquired properties, which may be substantially different in operating and geologic characteristics or geographic location than our existing properties. While our current operations are focused in the East Texas/North Louisiana and South Texas regions, we may pursue acquisitions or properties located in other geographic areas.
We operate in a highly competitive industry, and our failure to remain competitive with our competitors, many of which have greater resources than we do, could adversely affect our results of operations.
The oil and natural gas industry is highly competitive in the search for and development and acquisition of reserves. Our competitors often include companies that have greater financial and personnel resources than we do. These resources could allow those competitors to price their products and services more aggressively than we can, which could hurt our profitability. Moreover, our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to close transactions in a highly competitive environment.

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Our competitors may use superior technology that we may be unable to afford or which would require costly investment by us in order to compete.
If our competitors use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement new technologies at a substantial cost. In addition, our competitors may have greater financial, technical and personnel resources that allow them to enjoy technological advances and may in the future allow them to implement new technologies before we can. We cannot be certain that we will be able to implement technologies on a timely basis or at a cost that is acceptable to us. One or more of the technologies that we currently use or that we may implement in the future may become obsolete. All of these factors may inhibit our ability to acquire additional prospects and compete successfully in the future.
Substantial exploration and development activities could require significant outside capital, which could dilute the value of our common shares and restrict our activities. Also, we may not be able to obtain needed capital or financing on satisfactory terms, which could lead to a limitation of our future business opportunities and a decline in our oil and natural gas reserves.
We expect to expend substantial capital in the acquisition of, exploration for and development of oil and natural gas reserves. In order to finance these activities, we may need to alter or increase our capitalization substantially through the issuance of debt or equity securities, the sale of non-strategic assets or other means. The issuance of additional equity securities could have a dilutive effect on the value of our common shares, and may not be possible on terms acceptable to us given the current volatility in the financial markets. The issuance of additional debt would require that a portion of our cash flow from operations be used for the payment of interest on our debt, thereby reducing our ability to use our cash flow to fund working capital, capital expenditures, acquisitions, dividends and general corporate requirements, which could place us at a competitive disadvantage relative to other competitors. Additionally, if our revenues decrease as a result of lower oil or natural gas prices, operating difficulties or declines in reserves, our ability to obtain the capital necessary to undertake or complete future exploration and development programs and to pursue other opportunities may be limited, which could result in a curtailment of our operations relating to exploration and development of our prospects, which in turn could result in a decline in our oil and natural gas reserves.
If oil and natural gas prices remain low or continue to decline, we may be required to write-down the carrying values and/or the estimates of total reserves of our oil and natural gas properties, which would constitute a non-cash charge to earnings and adversely affect our results of operations.
Accounting rules applicable to us require that we review periodically the carrying value of our oil and natural gas properties for possible impairment. Based on specific market factors and circumstances at the time of prospective impairment reviews and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying value of our oil and natural gas properties. A write-down constitutes a non-cash charge to earnings. We may incur non-cash charges in the future, which could have a material adverse effect on our results of operations in the period taken. We may also reduce our estimates of the reserves that may be economically recovered, which could have the effect of reducing the total value of our reserves. Such a reduction in carrying value could impact our borrowing ability and may result in accelerating the repayment date of any outstanding debt.

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Our reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in our reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.
Reserve engineering is a subjective process of estimating the recovery from 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 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 is only estimated and should not be construed as the current market value of the 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 borrowing ability, our future prospects and the value of our common stock.
As of December 31, 2010, 50% of our total proved reserves were undeveloped and 15% were developed non-producing. These reserves may not ultimately be developed or produced. Furthermore, not all of our undeveloped or developed non-producing reserves may be ultimately produced at the time periods we have planned, at the costs we have budgeted, or at all. As a result, we may not find commercially viable quantities of oil and natural gas, which in turn may result in a material adverse effect on our results of operations.
If we are unsuccessful at marketing our oil and natural gas at commercially acceptable prices, our profitability will decline.
Our ability to market oil and natural gas at commercially acceptable prices depends on, among other factors, the following:

| • | the availability and capacity of gathering systems and pipelines;
| • | federal and state regulation of production and transportation;
| • | changes in supply and demand; and
| • | general economic conditions.

Our inability to respond appropriately to changes in these factors could negatively affect our profitability.
Market conditions or operational impediments may hinder our access to oil and natural gas markets or delay our production.
Market conditions or the unavailability of satisfactory oil and natural gas transportation arrangements may hinder our access to oil and natural gas markets or delay our production. The availability of a ready market for our oil and natural gas production depends on a number of factors, including the demand for and supply of oil and natural gas and the proximity of reserves to pipelines and processing facilities. Our ability to market our production depends in a substantial part on the availability and capacity of gathering systems, pipelines and processing facilities, in some cases owned and operated by third parties. Our failure to obtain such services on acceptable terms could materially harm our business. We may be required to shut in wells for a lack of a market or because of the inadequacy or unavailability of pipelines or gathering system

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capacity. If that were to occur, then we would be unable to realize revenue from those wells until arrangements were made to deliver our production to market.
We depend on our key personnel and the loss of any of these individuals could have a material adverse effect on our operations.
We believe that the success of our business strategy and our ability to operate profitably depend on the continued employment of M. Jay Allison, our President and Chief Executive Officer, and a limited number of other senior management personnel. Loss of the services of Mr. Allison or any of those other individuals could have a material adverse effect on our operations.
Our insurance coverage may not be sufficient or may not be available to cover some liabilities or losses that we may incur.
If we suffer a significant accident or other loss, our insurance coverage will be net of our deductibles and may not be sufficient to pay the full current market value or current replacement value of our lost investment, which could result in a material adverse impact on our operations and financial condition. Our insurance does not protect us against all operational risks. We do not carry business interruption insurance. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. Because third party drilling contractors are used to drill our wells, we may not realize the full benefit of workers’ compensation laws in dealing with their employees. In addition, some risks, including pollution and environmental risks, generally are not fully insurable.
We are subject to extensive governmental laws and regulations that may adversely affect the cost, manner or feasibility of doing business.
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 harm our business, results of operations and financial condition. We may be required to make large and unanticipated capital expenditures to comply with governmental laws and regulations, such as:

| • | lease permit restrictions;
| • | drilling bonds and other financial responsibility requirements, such as plug and abandonment bonds;
| • | spacing of wells;
| • | unitization and pooling of properties;
| • | safety precautions;
| • | regulatory requirements; and
| • | taxation.

Under these laws and regulations, we could be liable for:

| • | personal injuries;
| • | property and natural resource damages;
| • | well reclamation costs; and
| • | governmental sanctions, such as fines and penalties.

Our operations could be significantly delayed or curtailed and our cost of operations could significantly increase as a result of regulatory requirements or restrictions. We are unable to predict the ultimate cost of compliance with these requirements or their effect on our operations.

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Our operations may incur substantial liabilities to comply with environmental laws and regulations.
Our oil and natural gas operations are subject to stringent federal, state and local laws and regulations relating to the release or disposal of materials into the environment and otherwise relating to environmental protection. These laws and regulations:

| • | require the acquisition of a permit before drilling commences;
| • | restrict the types, quantities and concentration of substances that can be released into the environment in connection with drilling and production activities;
| • | require reporting of significant releases, and annual reporting of the nature and quantity of emissions, discharges and other releases into the environment;
| • | limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; and
| • | impose substantial liabilities for pollution resulting from our operations.

Failure to comply with these laws and regulations may result in:

| • | the assessment of administrative, civil and criminal penalties;
| • | the incurrence of investigatory or remedial obligations; and
| • | the imposition of injunctive relief.

In June 2009 the United States House of Representatives passed the American Clean Energy and Security Act of 2009. A similar bill, the Clean Energy Jobs and American Power Act, introduced in the Senate, has not passed. Both bills contain the basic feature of establishing a “cap and trade” system for restricting greenhouse gas emissions in the United States. Under such a system, certain sources of greenhouse gas emissions would be required to obtain greenhouse gas emission “allowances” corresponding to their annual emissions of greenhouse gases. The number of emission allowances issued each year would decline as necessary over time to meet overall emission reduction goals. As the number of greenhouse gas emission allowances declines each year, the cost or value of allowances is expected to escalate significantly. It appears that the prospects for a cap and trade system such as that proposed in these bills have dimmed significantly since the 2010 midterm elections; however, some form of GHG legislation remains possible, and the EPA is moving ahead with its efforts to regulate GHG emissions from certain sources by rule. The EPA has issued Subpart W of the Final Mandatory Reporting of Greenhouse Gases Rule, which required petroleum and natural gas systems that emit 25,000 metric tons of CO2e or more per year to begin collecting GHG emissions data under a new reporting system beginning on January 1, 2011 with the first annual report due March 31, 2012. We are required to report under these new regulations, and are implementing the required procedures to collect the required information. Beyond measuring and reporting, the EPA issued an “Endangerment Finding” under section 202(a) of the Clean Air Act, concluding greenhouse gas pollution threatens the public health and welfare of current and future generations. The EPA has adopted regulations that would require permits for and reductions in greenhouse gas emissions for certain facilities. Since all of our crude oil and natural gas production is in the United States, these laws or regulations that have been or may be adopted to restrict or reduce emissions of greenhouse gases could require us to incur substantial increased operating costs, and could have an adverse effect on demand for the crude oil and natural gas we produce.
In June 2010 the Bureau of Land Management issued a proposed oil and gas leasing reform. The proposal would require, among other things, a more detailed environmental review prior to leasing oil and natural gas resources on federal lands, increased public engagement in the development of Master Leasing Plans prior to leasing areas where intensive new oil and gas development is anticipated, and a comprehensive parcel review process with greater public involvement in the identification of key environmental

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resource values before a parcel is leased. New leases would incorporate adaptive management stipulations, requiring lessees to monitor and respond to observed environmental impacts, possibly through the implementation of expensive new control measures or curtailment of operations, potentially reducing profitability. The proposed policy could have the effect of reducing the amount of new federal lands made available for lease, increasing the competition for and cost of available parcels.
Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly waste handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to reach and maintain compliance and may otherwise have a material adverse effect on our industry in general and on our own results of operations, competitive position or financial condition. Under these environmental laws and regulations, we could be held strictly liable for the removal or remediation of previously released materials or property contamination regardless of whether we were responsible for the release or contamination or if our operations met previous standards in the industry at the time they were performed. Future environmental laws and regulations, including proposed legislation regulating climate change, may negatively impact our industry. The costs of compliance with these requirements may have an adverse impact on our financial condition, results of operations and cash flows.
Provisions of our articles of incorporation, bylaws and Nevada law will make it more difficult to effect a change in control of us, which could adversely affect the price of our common stock.
Nevada corporate law and our articles of incorporation and bylaws contain provisions that could delay, defer or prevent a change in control of us. These provisions include:

| • | allowing for authorized but unissued shares of common and preferred stock;
| • | a classified board of directors;
| • | requiring special stockholder meetings to be called only by our chairman of the board, our chief executive officer, a majority of the board or the holders of at least 10% of our outstanding stock entitled to vote at a special meeting;
| • | requiring removal of directors by a supermajority stockholder vote;
| • | prohibiting cumulative voting in the election of directors; and
| • | Nevada control share laws that may limit voting rights in shares representing a controlling interest in us.

These provisions could make an acquisition of us by means of a tender offer or proxy contest or removal of our incumbent directors more difficult. As a result, these provisions could make it more difficult for a third party to acquire us, even if doing so would benefit our stockholders, which may limit the price that investors are willing to pay in the future for shares of our common stock.

ITEM 1B. | UNRESOLVED STAFF COMMENTS

None.

ITEM 3. | LEGAL PROCEEDINGS

We are not a party to any legal proceedings which management believes will have a material adverse effect on our consolidated results of operations or financial condition.

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PART II

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.

|  |  |  |  | High |  |  | Low |
| 2009 — |  |  | First Quarter |  | $ | 52.70 |  |  | $ | 26.62 |
|  |  |  | Second Quarter |  | $ | 43.93 |  |  | $ | 28.13 |
|  |  |  | Third Quarter |  | $ | 42.65 |  |  | $ | 27.88 |
|  |  |  | Fourth Quarter |  | $ | 49.14 |  |  | $ | 35.47 |
| 2010 — |  |  | First Quarter |  | $ | 44.52 |  |  | $ | 29.63 |
|  |  |  | Second Quarter |  | $ | 36.19 |  |  | $ | 26.67 |
|  |  |  | Third Quarter |  | $ | 28.02 |  |  | $ | 19.54 |
|  |  |  | Fourth Quarter |  | $ | 26.88 |  |  | $ | 20.82 |

As of February 22, 2011, we had 47,706,101 shares of common stock outstanding, which were held by 249 holders of record and approximately 18,000 beneficial owners who maintain their shares in “street name” accounts.
We have never paid cash dividends on our common stock. We presently intend to retain any earnings for the operation and expansion of our business and we do not anticipate paying cash dividends in the foreseeable future. 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. In addition, we are limited under our bank credit facility and by the terms of the indentures for our senior notes from paying or declaring cash dividends.
During the fourth quarter of 2010, we did not repurchase any of our equity securities.
The following table summarizes certain information regarding our equity compensation plans as of December 31, 2010:

|  | Number of |  |  |  | Number of securities
|  | securities |  |  |  | authorized for future
|  | to be issued upon |  | Weighted average |  | issuance under equity
|  | exercise of |  | exercise price of |  | compensation plans
|  | outstanding options, |  | outstanding options, |  | (excluding outstanding
|  | warrants and rights |  | warrants and rights |  | options, warrants and rights)
Equity compensation plans approved by stockholders |  | 237,150 |  | $36.05 |  | 3,030,900

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

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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, 2010 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.” During 2008, we divested our interests in offshore operations which were conducted through our subsidiary Bois d’Arc Energy, Inc. (“Bois d’Arc”). Accordingly, we have adjusted the presentation of selected financial data to reflect the offshore operations on a discontinued basis.
Statement of Operations Data:

|  | Year Ended December 31, |
|  | 2006 |  |  | 2007 |  |  | 2008 |  |  | 2009 |  |  | 2010 |
|  | (In thousands, except per share data) |
Revenues: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Oil and gas sales |  | $ | 257,218 |  |  | $ | 331,613 |  |  | $ | 563,749 |  |  | $ | 292,583 |  |  | $ | 349,141 |
Gain on sale of properties |  |  | — |  |  |  | — |  |  |  | 26,560 |  |  |  | 213 |  |  |  | — |
Total revenues |  |  | 257,218 |  |  |  | 331,613 |  |  |  | 590,309 |  |  |  | 292,796 |  |  |  | 349,141 |
Operating expenses: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Production taxes |  |  | 11,344 |  |  |  | 13,830 |  |  |  | 20,648 |  |  |  | 8,643 |  |  |  | 9,894 |
Gathering and transportation |  |  | 2,604 |  |  |  | 2,282 |  |  |  | 3,910 |  |  |  | 8,696 |  |  |  | 17,256 |
Lease operating(1) |  |  | 39,955 |  |  |  | 48,679 |  |  |  | 62,172 |  |  |  | 53,560 |  |  |  | 53,525 |
Exploration |  |  | 1,424 |  |  |  | 7,039 |  |  |  | 5,032 |  |  |  | 907 |  |  |  | 2,605 |
Depreciation, depletion and amortization |  |  | 75,278 |  |  |  | 125,349 |  |  |  | 182,179 |  |  |  | 213,238 |  |  |  | 213,809 |
Impairment of oil and gas properties |  |  | 8,812 |  |  |  | 482 |  |  |  | 922 |  |  |  | 115 |  |  |  | 224 |
Loss on sale of properties |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 26,632 |
General and administrative, net |  |  | 20,395 |  |  |  | 27,813 |  |  |  | 32,266 |  |  |  | 39,172 |  |  |  | 37,200 |
Total operating expenses |  |  | 159,812 |  |  |  | 225,474 |  |  |  | 307,129 |  |  |  | 324,331 |  |  |  | 361,145 |
Income (loss) from operations |  |  | 97,406 |  |  |  | 106,139 |  |  |  | 283,180 |  |  |  | (31,535 | ) |  |  | (12,004 | )
Other income (expenses): |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Interest income |  |  | 682 |  |  |  | 877 |  |  |  | 1,537 |  |  |  | 245 |  |  |  | 263 |
Other income |  |  | 184 |  |  |  | 144 |  |  |  | 119 |  |  |  | 133 |  |  |  | 236 |
Interest expense |  |  | (20,733 | ) |  |  | (32,293 | ) |  |  | (25,336 | ) |  |  | (16,086 | ) |  |  | (29,456 | )
Marketable securities impairment |  |  | — |  |  |  | — |  |  |  | (162,672 | ) |  |  | — |  |  |  | — |
Gain on sale of marketable securities |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 16,529 |
Gain (loss) from derivatives |  |  | 10,716 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Total other income (expenses) |  |  | (9,151 | ) |  |  | (31,272 | ) |  |  | (186,352 | ) |  |  | (15,708 | ) |  |  | (12,428 | )
Income (loss) from continuing operations before income taxes |  |  | 88,255 |  |  |  | 74,867 |  |  |  | 96,828 |  |  |  | (47,243 | ) |  |  | (24,432 | )
Benefit from (provision for) income taxes |  |  | (34,190 | ) |  |  | (29,223 | ) |  |  | (38,611 | ) |  |  | 10,772 |  |  |  | 4,846 |
Income (loss) from continuing operations |  |  | 54,065 |  |  |  | 45,644 |  |  |  | 58,217 |  |  |  | (36,471 | ) |  |  | (19,586 | )
Income (loss) from discontinued operations |  |  | 16,600 |  |  |  | 23,257 |  |  |  | 193,745 | (2) |  |  | — |  |  |  | — |
Net income (loss) |  | $ | 70,665 |  |  | $ | 68,901 |  |  | $ | 251,962 |  |  | $ | (36,471 | ) |  | $ | (19,586 | )
Basic net income (loss) per share: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Continuing operations |  | $ | 1.25 |  |  | $ | 1.03 |  |  | $ | 1.27 |  |  | $ | (0.81 | ) |  | $ | (0.43 | )
Discontinued operations |  |  | 0.38 |  |  |  | 0.52 |  |  |  | 4.23 |  |  |  | — |  |  |  | — |
|  | $ | 1.63 |  |  | $ | 1.55 |  |  | $ | 5.50 |  |  | $ | (0.81 | ) |  | $ | (0.43 | )
Diluted net income (loss) per share: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Continuing operations |  | $ | 1.22 |  |  | $ | 1.01 |  |  | $ | 1.26 |  |  | $ | (0.81 | ) |  | $ | (0.43 | )
Discontinued operations |  |  | 0.38 |  |  |  | 0.52 |  |  |  | 4.20 |  |  |  | — |  |  |  | — |
|  | $ | 1.60 |  |  | $ | 1.53 |  |  | $ | 5.46 |  |  | $ | (0.81 | ) |  | $ | (0.43 | )
Weighted average shares outstanding: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Basic |  |  | 42,220 |  |  |  | 43,415 |  |  |  | 44,524 |  |  |  | 45,004 |  |  |  | 45,561 |
Diluted |  |  | 43,252 |  |  |  | 44,080 |  |  |  | 44,813 |  |  |  | 45,004 | (3) |  |  | 45,561 | (3)

(1) |  | Includes ad valorem taxes.
(2) |  | Includes gain of $158.1 million, net of income taxes of $85.3 million, from the sale of our offshore operations.
(3) |  | Basic and diluted weighted average shares are the same due to the net loss.

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Balance Sheet Data:

|  | As of December 31,
|  | 2006 |  | 2007 |  | 2008 |  | 2009 |  | 2010
|  | (In thousands)
Cash and cash equivalents |  | $ | 1,228 |  |  | $ | 5,565 |  |  | $ | 6,281 |  |  | $ | 90,472 |  |  | $ | 1,732 |
Property and equipment, net |  |  | 917,854 |  |  |  | 1,310,559 |  |  |  | 1,444,715 |  |  |  | 1,576,287 |  |  |  | 1,816,248 |
Net assets of discontinued operations |  |  | 913,478 |  |  |  | 981,682 |  |  |  | — |  |  |  | — |  |  |  | — |
Total assets |  |  | 1,878,125 |  |  |  | 2,354,387 |  |  |  | 1,577,890 |  |  |  | 1,858,961 |  |  |  | 1,964,214 |
Total debt |  |  | 355,000 |  |  |  | 680,000 |  |  |  | 210,000 |  |  |  | 470,836 |  |  |  | 513,372 |
Stockholders’ equity |  |  | 902,912 |  |  |  | 1,039,085 |  |  |  | 1,062,085 |  |  |  | 1,066,111 |  |  |  | 1,068,531 |

Cash Flow Data:

|  | Year Ended December 31,
|  | 2006 |  | 2007 |  | 2008 |  | 2009 |  | 2010
|  | (In thousands)
Cash flows provided by operating activities from continuing operations |  | $ | 186,169 |  |  | $ | 201,539 |  |  | $ | 450,533 |  |  | $ | 176,257 |  |  | $ | 311,662 |
Cash flows used for investing activities from continuing operations |  |  | (281,505 | ) |  |  | (531,493 | ) |  |  | (289,194 | ) |  |  | (348,777 | ) |  |  | (440,473 | )
Cash flows provided by (used for) financing activities from continuing operations |  |  | 132,882 |  |  |  | 334,357 |  |  |  | (452,883 | ) |  |  | 256,711 |  |  |  | 40,071 |
Cash flows provided by (used for) discontinued operations |  |  | (36,407 | ) |  |  | (66 | ) |  |  | 292,260 |  |  |  | — |  |  |  | — |

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 1,589 (854.0 net to us) producing oil and natural gas wells and we operate 899 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.
Our offshore operations were historically conducted through our subsidiary, Bois d’Arc. Bois d’Arc was acquired by Stone Energy Corporation (“Stone”) in exchange for a combination of cash and shares of Stone common stock on August 28, 2008. Our offshore operations are presented 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 onshore operations. In 2008, we recorded an impairment of $162.7 million ($105.8 million after income taxes) to reduce our carrying value for our investment in Stone common stock to fair market value.

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Our future growth will be driven primarily by acquisition, development and exploration activities. In 2010 our growth in production and proved reserves was primarily driven by our successful drilling activities in the Haynesville shale formation. Under our current drilling budget, we plan to spend approximately $522.0 million in 2011 for development and exploration activities which will primarily be focused on developing our Haynesville and Bossier shale properties in East Texas/North Louisiana and our Eagle Ford shale properties located in South Texas. We plan to drill approximately 67 wells (49.5 net to us) in 2011. Forty-five of these wells will be horizontal Haynesville or Bossier shale wells and 22 will be horizontal Eagle Ford shale wells. However, we could increase or decrease the number of wells that we drill depending on oil and natural gas prices. We do not specifically budget for acquisitions as the timing and size of acquisitions are not predictable.
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. 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.
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 $6.7 million as of December 31, 2010.

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Results of Operations
Year Ended December 31, 2010 Compared to Year Ended December 31, 2009
Our operating data for 2009 and 2010 is summarized below:

|  | Year Ended December 31,
|  | 2009 |  | 2010
Net Production Data: |  |  |  |  |  |  |  |
Natural gas (MMcf) |  |  | 60,820 |  |  |  | 68,973 |
Oil (MBbls) |  |  | 775 |  |  |  | 715 |
Natural gas equivalent (MMcfe) |  |  | 65,468 |  |  |  | 73,262 |
Average Sales Price: |  |  |  |  |  |  |  |
Oil ($/Bbl) |  |  | $50.94 |  |  |  | $68.35 |
Natural gas ($/Mcf) |  |  | $3.73 |  |  |  | $4.35 |
Natural gas including hedging ($/Mcf) |  |  | $4.16 |  |  |  | $4.35 |
Average equivalent price ($/Mcfe) |  |  | $4.07 |  |  |  | $4.77 |
Average equivalent price including hedging ($/Mcfe) |  |  | $4.47 |  |  |  | $4.77 |
Expenses ($ per Mcfe): |  |  |  |  |  |  |  |
Production taxes |  |  | $0.13 |  |  |  | $0.14 |
Gathering and transportation |  |  | $0.13 |  |  |  | $0.24 |
Lease operating(1) |  |  | $0.82 |  |  |  | $0.72 |
Depreciation, depletion and amortization(2) |  |  | $3.25 |  |  |  | $2.91 |

(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 $56.5 million (19%) in 2010 to $349.1 million from sales of $292.6 million in 2009. This increase resulted from higher natural gas production and higher prices realized for natural gas and crude oil in 2010. Our production in 2010 increased by 12% over 2009’s production as our successful drilling in the Haynesville shale exceeded declines from our existing producing properties. The average price for natural gas we realized increased by 5% in 2010 as compared to 2009. Prices for crude oil increased by 34% in 2010 as compared to 2009. During 2010 we drilled 72 (45.0 net to us) Haynesville or Bossier shale horizontal wells. At December 31, 2010 we had 35 (23.4 net to us) of these wells awaiting completion. These wells were not completed in 2010 due to the unavailability of pressure pumping completion services. We have contracted for adequate completion services and expect to complete these wells in 2011.
Production taxes. Production taxes increased $1.3 million (14%) to $9.9 million in 2010 from $8.6 million in 2009. The increase was due to higher oil and natural gas prices and from higher production in 2010.
Gathering and transportation. Gathering and transportation costs in 2010 increased $8.6 million (98%) to $17.3 million as compared to $8.7 million in 2009 due to the transportation costs related to production from our Haynesville shale properties in North Louisiana.
Lease operating expenses. Our lease operating expenses, including ad valorem taxes, of $53.5 million in 2010 were comparable to our operating expenses of $53.6 million in 2009. Oil and gas operating expenses per equivalent Mcf produced decreased to $0.72 as compared to $0.82 in 2009. The decrease in our per unit rate reflects our higher production level in 2010.
Exploration expense. We had $2.6 million in exploration expense in 2010 as compared to $0.9 million in 2009. Exploration expense in 2010 and 2009 primarily related to costs incurred for the acquisition of seismic data.

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Depreciation, depletion and amortization expense (“DD&A”). DD&A of $213.8 million was comparable to DD&A of $213.2 million in 2009. Our DD&A rate per Mcfe produced averaged $2.91 in 2010 as compared to $3.25 for 2009. The increase in DD&A resulting from our 12% growth in production was mostly offset by the decrease in our amortization rate which resulted from our reserve growth and lower finding and development costs in 2010.
Impairment of oil and gas properties. We recorded minor impairments to our oil and gas properties of $0.2 million and $0.1 million in 2010 and 2009, respectively. These impairments relate to fields where an impairment was indicated based on estimated future cash flows attributable to the fields’ estimated proved oil and natural gas reserves.
General and administrative expenses. General and administrative expense of $37.2 million for 2010 was 5% lower than general and administrative expense of $39.2 million for 2009. The decrease primarily reflects our lower personnel costs in 2010 and $1.0 million in acquisition evaluation costs incurred in 2009.
Interest expense. Interest expense increased $13.4 million (83%) to $29.5 million in 2010 from interest expense of $16.1 million in 2009. The increase was primarily the result of interest on our senior notes issued in October 2009 which was partially offset by lower outstanding borrowings under our bank credit facility and an increase in capitalized interest related to our unevaluated properties. Average borrowings under our bank credit facility decreased to $70.0 million in 2010 as compared to $116.8 million for 2009. The average interest rate on the outstanding borrowings under our credit facility increased to 2.2% in 2010 as compared to 2.1% in 2009. We capitalized interest of $13.0 million and $6.6 million in 2010 and 2009, respectively, which reduced interest expense.
Income taxes. Income tax expense decreased in 2010 to a benefit of $4.8 million from a benefit of $10.8 million in 2009. Our effective tax rate of 19.8% in 2010 and 22.8% in 2009 differed from the federal income tax rate of 35% primarily due to the effect of nondeductible compensation and state income taxes.
Net loss. We reported a loss of $19.6 million for 2010 as compared to a loss of $36.5 million for 2009. The loss per share for 2010 was $0.43 on weighted average shares outstanding of 45.6 million as compared to a loss per share of $0.81 for 2009 on weighted average diluted shares outstanding of 45.0 million. The loss in 2010 was primarily related to the loss on our divestiture of oil and gas properties in Mississippi of $25.8 million ($16.8 million after income taxes).
Year Ended December 31, 2009 Compared to Year Ended December 31, 2008
Our operating data for 2008 and 2009 is summarized below:

|  | Year Ended December 31,
|  | 2008 |  | 2009
Net Production Data: |  |  |  |  |  |  |  |
Natural gas (MMcf) |  |  | 53,867 |  |  |  | 60,820 |
Oil (MBbls) |  |  | 1,009 |  |  |  | 775 |
Natural gas equivalent (MMcfe) |  |  | 59,923 |  |  |  | 65,468 |
Average Sales Price: |  |  |  |  |  |  |  |
Oil ($/Bbl) |  |  | $87.15 |  |  |  | $50.94 |
Natural gas ($/Mcf) |  |  | $8.92 |  |  |  | $3.73 |
Natural gas including hedging ($/Mcf) |  |  | $8.83 |  |  |  | $4.16 |
Average equivalent price ($/Mcfe) |  |  | $9.49 |  |  |  | $4.07 |
Average equivalent price including hedging ($/Mcfe) |  |  | $9.41 |  |  |  | $4.47 |
Expenses ($ per Mcfe): |  |  |  |  |  |  |  |
Production taxes |  |  | $0.34 |  |  |  | $0.13 |
Gathering and transportation |  |  | $0.07 |  |  |  | $0.13 |
Lease operating(1) |  |  | $1.04 |  |  |  | $0.82 |
Depreciation, depletion and amortization(2) |  |  | $3.03 |  |  |  | $3.25 |

(1) |  | Includes ad valorem taxes.
(2) |  | Represents depreciation, depletion and amortization of oil and gas properties only.

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Oil and gas sales. Our oil and gas sales decreased $271.1 million (48%) in 2009 to $292.6 million from sales of $563.7 million in 2008. This decrease primarily reflects lower prices realized by us for natural gas and crude oil in 2009. The average price for natural gas realized by us decreased by 53% in 2009 as compared to 2008. Prices for crude oil decreased by 42% in 2009 as compared to 2008. Our production in 2009 increased by 9% over 2008’s production as our successful drilling in the Haynesville shale more than replaced the declines from our existing producing properties.
Production taxes. Production taxes decreased $12.0 million (58%) to $8.6 million in 2009 from $20.6 million in 2008 primarily due to the decline in crude oil and natural gas prices in 2009.
Gathering and transportation. Gathering and transportation costs increased by $4.8 million to $8.7 million in 2009 as compared to $3.9 million in 2008 as a result of the increased production in our Haynesville shale natural gas production during 2009.
Lease operating expenses. Lease operating expenses, including ad valorem taxes, decreased $8.6 million (14%) to $53.6 million in 2009 from operating expenses of $62.2 million in 2008. Lease operating expenses per equivalent Mcf produced decreased to $0.82 as compared to $1.04 in 2008. The decrease in operating costs per Mcfe mainly reflects higher production in 2009 and lower ad valorem taxes.
Exploration expense. We had $0.9 million in exploration expense in 2009 as compared to $5.0 million in 2008. Exploration expense in 2009 primarily related to costs incurred for the acquisition of seismic data. Exploration expense in 2008 includes the cost of one exploratory dry hole, leasehold impairments and cost incurred for seismic data acquisition.
Depreciation, depletion and amortization expense. DD&A increased $31.0 million (17%) to $213.2 million in 2009 from DD&A of $182.2 million in 2008. Our DD&A rate per Mcfe produced averaged $3.25 in 2009 as compared to $3.03 for 2008. DD&A increased due to our higher production level and an increase in the amortization rate.
Impairment of oil and gas properties. We recorded impairments to our oil and gas properties of $0.1 million in 2009 as compared to impairment expense of $0.9 million in 2008. The impairments in 2009 and 2008 relate to fields where an impairment was indicated based on estimated future cash flows attributable to the fields’ estimated proved oil and natural gas reserves.
General and administrative expenses. General and administrative expense of $39.2 million for 2009 were 21% higher than general and administrative expense of $32.3 million for 2008. The increase primarily reflects our higher personnel costs in 2009 due to increased staffing necessary to support our exploration and development activities and an increase of $3.5 million in our stock-based compensation in 2009 as compared to 2008.
Interest expense. Interest expense decreased $9.2 million (37%) to $16.1 million in 2009 from interest expense of $25.3 million in 2008. The decrease was primarily the result of our lower outstanding borrowings and our lower average interest rates in 2009 as well as an increase in capitalized interest related to our unevaluated properties during 2009. Average borrowings under our bank credit facility decreased to $116.8 million in 2009 as compared to $301.5 million for 2008. The average interest rate on the outstanding borrowings under our credit facility decreased to 2.1% in 2009 as compared to 4.5% in 2008. Interest expense in 2009 also includes $6.1 million related to the issuance of $300.0 million of 83/8% senior notes in October 2009. We capitalized interest of $6.6 million and $2.3 million in 2009 and 2008, respectively, which reduced interest expense.

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Income taxes. Income tax expense from continuing operations decreased in 2009 to a benefit of $10.8 million from a provision of $38.6 million in 2008. Our effective tax rate of 22.8% in 2009 and our effective tax rate of 39.9% in 2008 differed from federal income tax rate of 35% primarily due to the effect of nondeductible compensation and state income taxes.
Income (loss). We reported a loss of $36.5 million for 2009 as compared to income from continuing operations of $58.2 million for 2008. The loss per diluted share for 2009 was $0.81 on weighted average shares outstanding of 45.0 million as compared to income per share $1.26 for 2008 on weighted average diluted shares outstanding of 44.8 million. The loss in 2009 was primarily attributable to the declines in oil and natural gas prices that we realized.
Liquidity and Capital Resources
Funding for our activities has historically been provided by our operating cash flow, debt or equity financings and asset dispositions. Our net cash provided by operating activities in 2010 totaled $311.7 million. Our other primary sources of funds in 2010 was $96.9 million of proceeds from sales of oil and gas properties and marketable securities, $45.0 million of borrowings under our bank credit facility and cash on hand. In 2009, our net cash flow provided by operating activities totaled $176.3 million. Our other primary source of funds in 2009 was $289.2 million of net proceeds from the issuance of senior notes and $135.0 million of borrowings under our bank credit facility. In 2008, our net cash flow provided by operating activities from continuing operations totaled $450.5 million. Our other primary source of funds in 2008 was the after tax proceeds of $421.8 million from the disposition of assets, including the sale of our offshore operations.
Our cash flow from operating activities in 2010 increased by $135.4 million to $311.7 million as compared to $176.3 million in 2009 primarily due to higher revenues resulting from higher production and the higher natural gas and crude oil prices we realized in 2010. Our cash flow from operating activities from continuing operations in 2009 decreased by $274.2 million to $176.3 million as compared to $450.5 million in 2008 primarily due to lower revenues which were mainly due to the lower oil and natural gas prices we realized in 2009.
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 the repayment of our debt. During 2010 our capital expenditures of $545.7 million increased by $200.9 million as compared to 2009 capital expenditures of $344.8 million. In 2009, our capital expenditures of $344.8 million decreased by $81.6 million as compared to 2008 capital expenditures of $426.4 million. In 2008, we reduced the amount outstanding under our bank credit facility by $470.0 million, primarily by using the proceeds from our asset sales.
Our annual capital expenditure activity is summarized in the following table:

|  | Year Ended December 31, |
|  | 2008 |  |  | 2009 |  |  | 2010 |
|  | (In thousands) |
Exploration and development: |  |  |  |  |  |  |  |  |  |  |  |
Acquisitions of unproved oil and gas properties |  | $ | 113,023 |  |  | $ | 26,040 |  |  | $ | 134,728 |
Developmental leasehold costs |  |  | 6,242 |  |  |  | 1,898 |  |  |  | 3,208 |
Development drilling |  |  | 230,604 |  |  |  | 205,901 |  |  |  | 305,410 |
Exploratory drilling |  |  | 61,113 |  |  |  | 101,049 |  |  |  | 85,140 |
Workovers and recompletions |  |  | 14,248 |  |  |  | 9,579 |  |  |  | 5,648 |
|  |  | 425,230 |  |  |  | 344,467 |  |  |  | 534,134 |
Other |  |  | 1,171 |  |  |  | 374 |  |  |  | 11,516 |
Total |  | $ | 426,401 |  |  | $ | 344,841 |  |  | $ | 545,650 |

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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 $522.0 million for development and exploration projects in 2011, which will be funded primarily by cash flows from operating activities and borrowings under our credit facility. Our operating cash flow and, therefore, our capital expenditures are highly dependent on oil and natural gas prices and, in particular, natural gas prices.
We do not have a specific acquisition budget for 2011 because the timing and size of acquisitions are unpredictable. Smaller acquisitions will generally be funded from operating cash flow. With respect to significant acquisitions, 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.
We have a $850.0 million bank credit facility with Bank of Montreal, as the administrative agent. The bank credit facility is a five-year revolving credit commitment that matures on November 30, 2015. Indebtedness under the bank credit facility is secured by all of our and our wholly owned subsidiaries’ assets and is guaranteed by all of our wholly owned subsidiaries. The bank credit facility is subject to borrowing base availability, which is redetermined semiannually based on the banks’ estimates of the future net cash flows of our oil and natural gas properties. As of December 31, 2010 the borrowing base was $500.0 million, $455.0 million of which was available. The borrowing base may be affected by the performance of our properties and changes in oil and natural gas prices. The determination of the borrowing base is at the sole discretion of the administrative agent and the bank group. Borrowings under the bank credit facility bear interest, based on the utilization of the borrowing base, at our option at either (1) LIBOR plus 1.75% to 2.75% 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 0.75% to 1.75%. A commitment fee of 0.5% is payable on the unused borrowing base. The bank credit facility contains covenants that, among other things, restrict the payment of cash dividends in excess of $50.0 million, limit the amount of consolidated debt that we may incur and limit our ability to make certain loans and investments. The only financial covenants are the maintenance of a ratio of current assets, including the availability under the bank credit facility, to current liabilities of at least one-to-one and maintenance of a minimum tangible net worth. We were in compliance with these covenants as of December 31, 2010.
We have $172.0 million of 67/8% senior notes outstanding which are due March 1, 2012. Interest is payable semiannually on each March 1 and September 1. During 2010 we repurchased $3.0 million of the 67/8% senior notes. We also have $300.0 million of 83/8% senior notes outstanding which are due October 15, 2017. Interest is payable semiannually on each October 15 and April 15. The senior notes are unsecured obligations and are guaranteed by all of our material subsidiaries. We intend to refinance the 67/8% senior notes due March 1, 2012 concurrent with or in advance of the maturity date of such notes based upon the credit markets and the then prevailing market interest rates.
We believe that our cash flow from operations and available borrowings under our bank credit facility will be sufficient to fund our operations and future growth as contemplated under our current business plan. However, if our plans or assumptions change or if our assumptions prove to be inaccurate, we may be required to seek additional capital. 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.

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The following table summarizes our aggregate liabilities and commitments by year of maturity and on the December 31, 2010 rate for our bank credit facility:

|  | 2011 |  |  | 2012 |  |  | 2013 |  |  | 2014 |  |  | 2015 |  |  | Thereafter |  |  | Total |
|  | (In thousands) |
67/8% senior notes |  | $ | — |  |  | $ | 172,000 |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | 172,000 |
Bank credit facility |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 45,000 |  |  |  | — |  |  |  | 45,000 |
83/8% senior notes |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 300,000 |  |  |  | 300,000 |
Interest on debt |  |  | 37,859 |  |  |  | 28,010 |  |  |  | 26,034 |  |  |  | 26,034 |  |  |  | 25,957 |  |  |  | 45,016 |  |  |  | 188,910 |
Operating leases |  |  | 1,701 |  |  |  | 1,701 |  |  |  | 1,701 |  |  |  | 1,200 |  |  |  | 500 |  |  |  | 1,500 |  |  |  | 8,303 |
Natural gas transportation agreements |  |  | 11,029 |  |  |  | 11,029 |  |  |  | 9,752 |  |  |  | 6,520 |  |  |  | 3,618 |  |  |  | 4,576 |  |  |  | 46,524 |
Contracted drilling services |  |  | 36,138 |  |  |  | 14,317 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 50,455 |
Contracted well completion services |  |  | 98,600 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 98,600 |
|  | $ | 185,327 |  |  | $ | 227,057 |  |  | $ | 37,487 |  |  | $ | 33,754 |  |  | $ | 75,075 |  |  | $ | 351,092 |  |  | $ | 909,792 |

Future interest costs are based upon the effective interest rates of our outstanding senior notes and the December 31, 2010 rate for our bank credit facility.
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 2015. We record a separate liability for the fair value of these asset retirement obligations, which totaled $6.7 million as of December 31, 2010.
Federal Taxation
Our federal income tax returns for the years subsequent to December 31, 2007 remain subject to examination. Our income tax returns in major state income tax jurisdictions remain subject to examination for various periods subsequent to December 31, 2005. State tax returns in one state jurisdiction are currently under review. We currently believe that resolution of this matter will not have a material impact on our financial statements. We also 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.
At December 31, 2010 we had U.S. federal net operating loss carryforwards of approximately $41.2 million and Louisiana state net operating loss carryforwards of approximately $416.2 million. The utilization of our 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, 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. Realization of the U.S. federal net operating loss carryforwards requires us to generate taxable income within the carryforward period. A valuation allowance with a tax effect of $19.1 million has been established against our Louisiana state net operating loss carryforwards due to the uncertainty of generating taxable income in the state of Louisiana prior to the expiration of the carryforward period.

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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 as well as impairments that are recognized on our oil and gas properties are highly dependent on the estimates of the proved oil and natural gas reserves attributable to our properties. 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 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 borrowing ability, 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 reserve estimates at the end of the period. 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.
Asset retirement obligations. We have obligations to remove tangible equipment and facilities and to restore land at the end of oil and gas production operations. Our removal and restoration obligations are primarily associated with plugging and abandoning wells and removing and disposing of any surface equipment used in production operations. Estimating the future restoration and removal costs is difficult and requires management to make estimates and judgments because most of the removal obligations are many

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years in the future. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations.
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.
Related Party Transactions
In recent years, we have not entered into any material transactions with our officers or directors apart from the compensation they are provided for their services. We also have not entered into any business transactions with our significant stockholders or any other related parties.

ITEM 7A. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Oil and Natural Gas Prices
Our financial condition, results of operations and capital resources are highly dependent upon the prevailing market prices of oil and natural gas. These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond our control. Factors influencing oil and natural gas prices include the level of global demand for crude oil, the foreign supply of oil and natural gas, the establishment of and compliance with production quotas by oil exporting countries, weather conditions which determine the demand for natural gas, the price and availability of alternative fuels and overall economic conditions. It is impossible to predict future oil and natural gas prices with any degree of certainty. Sustained weakness in oil and natural gas prices may adversely affect our financial condition and results of operations, and may also reduce the amount of oil and natural gas reserves that we can produce economically. Any reduction in our oil and natural gas reserves, including reductions due to price fluctuations, can have an adverse affect on our ability to obtain capital for our exploration and development activities. Similarly, any improvements in oil and natural gas prices can have a favorable impact on our financial condition, results of operations and capital resources. Based on our oil and natural gas production in 2010, a $1.00 change in the price per barrel of oil would have resulted in a change in our cash flow for such period by approximately $0.7 million and a $1.00 change in the price per Mcf of natural gas would have changed our cash flow by approximately $67.0 million.
We hedged approximately 10% of our price risks associated with our natural gas sales during 2009. We had no crude oil or natural gas derivative financial instruments outstanding during 2010 or at December 31, 2010 and none of our oil or gas production is hedged in 2011 or thereafter.
Interest Rates
At December 31, 2010, we had $513.4 million of long-term debt. Of this amount, $172.0 million bears interest at a fixed rate of 67/8% and $296.4 million bears interest at 83/8% (with an effective interest rate of 85/8%). The fair market value of our fixed rate debt as of December 31, 2010 was $473.9 million based on the market price of approximately 101% of the face amount. At December 31, 2010, we had $45.0 million outstanding under our bank credit facility, which is subject to variable rates of interest. Borrowings under the bank credit facility bear interest at a fluctuating rate that is tied to LIBOR or the corporate base rate, at our option. Any increase in these interest rates would have an adverse impact on our results of operations and cash flow. Based on borrowings outstanding at December 31, 2010, a 100 basis point change in interest rates

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would change our annual interest expense on our variable rate debt by approximately $0.5 million. We had no interest rate derivatives outstanding during 2010 or at December 31, 2010.

ITEM 8. | FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Our consolidated financial statements are included on pages F-1 to F-25 of this report.
We have prepared these financial statements in conformity with generally accepted accounting principles. We are responsible for the fairness and reliability of the financial statements and other financial data included in this report. In the preparation of the financial statements, it is necessary for us to make informed estimates and judgments based on currently available information on the effects of certain events and transactions.
Our independent public accountants, Ernst & Young LLP, are engaged to audit our financial statements and to express an opinion thereon. Their audit is conducted in accordance with auditing standards generally accepted in the United States to enable them to report whether the financial statements present fairly, in all material respects, our financial position and results of operations in accordance with accounting principles generally accepted in the United States.
The audit committee of our board of directors is comprised of three directors who are not our employees. This committee meets periodically with our independent public accountants and management. Our independent public accountants have full and free access to the audit committee to meet, with and without management being present, to discuss the results of their audits and the quality of our financial reporting.

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ITEM 9. | CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. | CONTROLS AND PROCEDURES

Evaluation of disclosure controls and procedures. Our Chief Executive Officer and Chief Financial Officer have evaluated, as required by Rule 13a-15(b) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), our disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)) as of the end of the period covered by this Annual Report on Form 10-K. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that the design and operation of our disclosure controls and procedures are adequate and effective in ensuring that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms.
Changes in internal control over financial reporting. There were no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that occurred during the fourth quarter of 2010 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
Management’s Report on Internal Control Over Financial Reporting
The management of Comstock Resources, Inc. (the “Company”) is responsible for establishing and maintaining adequate internal control over financial reporting. The Company’s internal control over financial reporting is a process designed under the supervision of the Company’s Chief Executive Officer and Chief Financial Officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the Company’s financial statements for external purposes in accordance with generally accepted accounting principles.
As of December 31, 2010, management assessed the effectiveness of the Company’s internal control over financial reporting based on the criteria for effective internal control over financial reporting established in “Internal Control — Integrated Framework,” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the assessment, management determined that the Company maintained effective internal control over financial reporting as of December 31, 2010, based on those criteria.
Ernst & Young LLP, the independent registered public accounting firm that audited the consolidated financial statements of the Company included in this Annual Report on Form 10-K, has issued an attestation report on the effectiveness of the Company’s internal control over financial reporting as of December 31, 2010. The report, which expresses unqualified opinions on the effectiveness of the Company’s internal control over financial reporting as of December 31, 2010 is included below.

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Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
Comstock Resources, Inc.
We have audited Comstock Resources, Inc.’s internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Comstock Resources, Inc.’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit.
We conducted our audit 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 effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, Comstock Resources, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Comstock Resources, Inc. and subsidiaries as of December 31, 2009 and 2010, and the related consolidated statements of operations, stockholders’ equity and comprehensive income (loss), and cash flows for each of the three years in the period ended December 31, 2010 and our report dated February 22, 2011 expressed an unqualified opinion thereon.
/s/ ERNST & YOUNG LLP
Dallas, Texas
February 22, 2011

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ITEM 9B. | OTHER INFORMATION

None.
PART III

ITEM 10. | DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

The information required by this item is incorporated herein by reference to “Business — Directors and Executive Officers” in this Form 10-K and to our definitive proxy statement which will be filed with the SEC within 120 days after December 31, 2010.
Code of Ethics. We have adopted a Code of Business Conduct and Ethics that is applicable to all of our directors, officers and employees as required by New York Stock Exchange rules. We have also adopted a Code of Ethics for Senior Financial Officers that is applicable to our Chief Executive Officer and Senior Financial Officers. Both the Code of Business Conduct and Ethics and Code of Ethics for Senior Financial Officers may be found on our website at www.comstockresources.com. Both of these documents are also available, without charge, to any stockholder upon request to: Comstock Resources, Inc., Attn: Investor Relations, 5300 Town and Country Blvd., Suite 500, Frisco, Texas 75034, (972) 668-8800. We intend to disclose any amendments or waivers to these codes that apply to our Chief Executive Officer and senior financial officers on our website in accordance with applicable SEC rules. Please see the definitive proxy statement for our 2011 annual meeting, which will be filed with the SEC within 120 days of December 31, 2010, for additional information regarding our corporate governance policies.

ITEM 11. | EXECUTIVE COMPENSATION

The information required by this item is incorporated herein by reference to our definitive proxy statement which will be filed with the SEC within 120 days after December 31, 2010.

ITEM 12. | SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

The information required by this item is incorporated herein by reference to our definitive proxy statement which will be filed with the SEC within 120 days after December 31, 2010.

ITEM 13. | CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTORS INDEPENDENCE

The information required by this item is incorporated herein by reference to our definitive proxy statement which will be filed with the SEC within 120 days after December 31, 2010.

ITEM 14. | PRINCIPAL ACCOUNTANT FEES AND SERVICES

The information required by this item is incorporated herein by reference to our definitive proxy statement which will be filed with the SEC within 120 days after December 31, 2010.

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PART IV

ITEM 15. | EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a) Financial Statements:
1. The following consolidated financial statements and notes of Comstock Resources, Inc. are included on Pages F-2 to F-25 of this report:

Report of Independent Registered Public Accounting Firm |  |  | F-2 |
Consolidated Balance Sheets as of December 31, 2009 and 2010 |  |  | F-3 |
Consolidated Statements of Operations for the Years Ended December 31, 2008, 2009 and 2010 |  |  | F-4 |
Consolidated Statements of Stockholders’ Equity and Comprehensive Income (Loss) for the Years Ended December 31, 2008, 2009 and 2010 |  |  | F-5 |
Consolidated Statements of Cash Flows for the Years Ended December 31, 2008, 2009 and 2010 |  |  | F-6 |
Notes to Consolidated Financial Statements |  |  | F-7 |

2. All financial statement schedules are omitted because they are not applicable, or are immaterial or the required information is presented in the consolidated financial statements or the related notes.
(b) Exhibits:
The exhibits to this report required to be filed pursuant to Item 15 (c) are listed below.

Exhibit No. |  | Description
3.1(a) |  | Restated Articles of Incorporation (incorporated by reference to Exhibit 3.1 to our Annual Report on Form 10-K for the year ended December 31, 1995).
3.1(b) |  | Certificate of Amendment to the Restated Articles of Incorporation dated July 1, 1997 (incorporated by reference to Exhibit 3.1 to our Quarterly Report on Form 10-Q for the quarter ended June 30, 1997).
3.2 |  | Certificate of Amendment to the Restated Articles of Incorporation dated May 19, 2009 (incorporated by reference to Exhibit 3.1 to our Registration Statement on Form S-3 dated October 5, 2009).
3.3 |  | Bylaws (incorporated by reference to Exhibit 3.2 to our Registration Statement on Form S-3, dated October 25, 1996).
4.3 |  | Indenture dated February 25, 2004 between Comstock, the guarantors and The Bank of New York Trust Company, N.A., Trustee for debt securities issued by Comstock Resources, Inc. (incorporated by reference to Exhibit 4.6 to our Annual Report on Form 10-K for the year ended December 31, 2003).
4.4 |  | First Supplemental Indenture, dated February 25, 2004 between Comstock, the guarantors and The Bank of New York Trust Company, N.A., Trustee for the 67/8% Senior Notes due 2012 (incorporated by reference to Exhibit 4.7 to our Annual Report on Form 10-K for the year ended December 31, 2003).
4.5 |  | Second Supplemental Indenture, dated March 11, 2004 between Comstock, the guarantors and The Bank of New York Trust Company, N.A. for the 67/8% Senior Notes due 2012 (incorporated by reference to Exhibit 4.1 to our Quarterly Report on Form 10-Q for the quarter ended March 31, 2004).

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Exhibit No. |  | Description
4.6 |  | Third Supplemental Indenture dated July 16, 2004 between Comstock, the guarantors and The Bank of New York Trust Company, N.A., Trustee (incorporated by reference to Exhibit 4.1 to our Quarterly Report on Form 10-Q for the quarter ended March 31, 2004).
4.7 |  | Fourth Supplemental Indenture dated May 20, 2005 between Comstock, the guarantors and The Bank of New York Trust Company, N.A., Trustee (incorporated by reference to Exhibit 4.1 to our Quarterly Report on Form 10-Q for the quarter ended June 30, 2005).
4.8* |  | Fifth Supplemental Indenture dated April 30, 2010 between Comstock, the guarantors and The Bank of New York Mellon Trust Company, N.A., Trustee, for the 67/8 Senior Notes due 2012.
4.9 |  | Indenture dated October 9, 2009 between Comstock, the guarantors and The Bank of New York Mellon Trust Company, N.A., Trustee for debt securities (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K dated October 9, 2009).
4.10 |  | First Supplemental Indenture, dated October 9, 2009 between Comstock, the guarantors and The Bank of New York Mellon Trust Company, N.A., Trustee for the 83/8% Senior Notes due 2017 (incorporated by reference to Exhibit 4.2 to our Current Report on Form 8-K dated October 9, 2009).
4.11* |  | Second Supplemental Indenture dated April 30, 2010 between Comstock, the guarantors and The Bank of New York Mellon Trust Company, N.A., Trustee for the 83/8 Senior Notes Due 2017.
10.1# |  | Employment Agreement dated December 22, 2008 by and between Comstock and M. Jay Allison (incorporated by reference to Exhibit 99.1 to our Current Report on Form 8-K dated December 22, 2008).
10.2# |  | Employment Agreement dated December 22, 2008 by and between Comstock and Roland O. Burns (incorporated by reference to Exhibit 99.2 to our Current Report on Form 8-K dated December 22, 2008).
10.3# |  | Comstock Resources, Inc. 2009 Long-term Incentive Plan (incorporated by reference to Exhibit 99 to our Registration Statement on Form S-8 dated May 19, 2009).
10.4# |  | Form of Restricted Stock Agreement under the Comstock Resources, Inc. 2009 Long-term Incentive Plan (incorporated by reference to Exhibit 10.4 to our Annual Report on Form 10-K for the year ended December 31, 2009).
10.5 |  | Lease between Stonebriar I Office Partners, Ltd. and Comstock Resources, Inc. dated May 6, 2004 (incorporated by reference to Exhibit 10.24 to our Annual Report on Form 10-K for the year ended December 31, 2004).
10.6 |  | First Amendment to the Lease Agreement dated August 25, 2005, between Stonebriar I Office Partners, Ltd. and Comstock Resources, Inc. (incorporated by reference to Exhibit 10.20 to our Annual Report on Form 10-K for the year ended December 31, 2005).
10.7 |  | Second Amendment to the Lease Agreement dated October 15, 2007 between Stonebriar I Office Partners, Ltd. and Comstock Resources, Inc. (incorporated by reference to Exhibit 10.10 to our Annual Report on Form 10-K for the year ended December 31, 2008).
10.8 |  | Third Amendment to the Lease Agreement dated September 30, 2008 between Stonebriar I Office Partners, Ltd. and Comstock Resources, Inc. (incorporated by reference to Exhibit 10.11 to our Annual Report on Form 10-K for the year ended December 31, 2008).
10.9 |  | Fourth Amendment to the Lease Agreement dated September 30, 2008 between Stonebriar I Office Partners, Ltd. and Comstock Resources, Inc. (incorporated by reference to Exhibit 10.2 to our Quarterly Report on Form 10-Q for the quarter ended June 30, 2009).
10.10* |  | Third Amended and Restated Credit Agreement, dated November 30, 2010, among Comstock Resources, Inc., as the borrower, the lenders from time to time thereto, Bank of Montreal, as administrative agent and issuing bank, Bank of America, N.A., as syndication agent and Comerica, JP Morgan Chase Bank, N.A., and Union Bank of California, N.A., as co-documentation agents.

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Exhibit No. |  | Description
10.11 |  | Base Contract for Sale and Purchase of Natural Gas between Comstock Oil & Gas-Louisiana, LLC and BP Energy Company dated November 7, 2008, as amended by Third Amended and Restated Special Provisions dated January 5, 2010 (incorporated by reference to Exhibit 10.14 to our Annual Report on Form 10-K for the year ended December 31, 2009).
21* |  | Subsidiaries of the Company.
23.1* |  | Consent of Ernst & Young LLP.
23.2* |  | Consent of Independent Petroleum Engineers.
31.1* |  | Chief Executive Officer certification under Section 302 of the Sarbanes-Oxley Act of 2002.
31.2* |  | Chief Financial Officer certification under Section 302 of the Sarbanes-Oxley Act of 2002.
32.1+ |  | Chief Executive Officer certification under Section 906 of the Sarbanes-Oxley Act of 2002.
32.2+ |  | Chief Financial Officer certification under Section 906 of the Sarbanes-Oxley Act of 2002.
99.1* |  | Report of Independent Petroleum Engineers on Proved Reserves as of December 31, 2010.
101** |  | The following materials from the Comstock Resources, Inc. Form 10-K for the year ended December 31, 2010, formatted in XBRL (Extensible Business Reporting Language): (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Operations, (iii) Consolidated Statement of Stockholders’ Equity and Comprehensive Income (Loss), (iv) Consolidated Statements of Cash Flows, and (v) Notes to Consolidated Financial Statements.

* |  | Filed herewith.
+ |  | Furnished herewith.
# |  | Management contract or compensatory plan document.
** |  | Submitted electronically herewith.

In accordance with Rule 406T of Regulation S-T, the XBRL information in Exhibit 101 to this Annual Report on Form 10-K shall not be deemed to be “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended (Exchange Act), or otherwise subject to the liability of that section, and shall not be incorporated by reference into any registration statement or other document filed under the Securities Act of 1933, as amended, or the Exchange Act, except as shall be expressly set forth by specific reference in such filing.

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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
COMSTOCK RESOURCES, INC.

| By: | /s/ M. JAY ALLISON

M. Jay Allison
President and Chief Executive Officer
(Principal Executive Officer)
Date: February 22, 2011
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

/s/ M. JAY ALLISON M. Jay Allison |  | President, Chief Executive Officer and Chairman of the Board of Directors (Principal Executive Officer) |  | February 22, 2011
/s/ ROLAND O. BURNS Roland O. Burns |  | Senior Vice President, Chief Financial Officer, Secretary, Treasurer and Director (Principal Financial and Accounting Officer) |  | February 22, 2011
/s/ DAVID K. LOCKETT David K. Lockett |  | Director |  | February 22, 2011
/s/ CECIL E. MARTIN, JR. Cecil E. Martin, Jr. |  | Director |  | February 22, 2011
/s/ DAVID W. SLEDGE David W. Sledge |  | Director |  | February 22, 2011
/s/ NANCY E. UNDERWOOD Nancy E. Underwood |  | Director |  | February 22, 2011

56

##### Table of Contents

COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
FINANCIAL STATEMENTS
INDEX

Report of Independent Registered Public Accounting Firm |  |  | F-2 |
Consolidated Balance Sheets as of December 31, 2009 and 2010 |  |  | F-3 |
Consolidated Statements of Operations for the Years Ended December 31, 2008, 2009 and 2010 |  |  | F-4 |
Consolidated Statements of Stockholders’ Equity and Comprehensive Income (Loss) for the Years Ended December 31, 2008, 2009 and 2010 |  |  | F-5 |
Consolidated Statements of Cash Flows for the Years Ended December 31, 2008, 2009 and 2010 |  |  | F-6 |
Notes to Consolidated Financial Statements |  |  | F-7 |

F-1

##### Table of Contents

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, 2009 and 2010, and the related consolidated statements of operations, stockholders’ equity and comprehensive income (loss), and cash flows for each of the three years in the period ended December 31, 2010. 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, 2009 and 2010, and the consolidated results of their operations and cash flows for each of the three years in the period ended December 31, 2010, in conformity with accounting principles generally accepted in the United States.
As discussed in Note 1 to the consolidated financial statements, during the year ended December 31, 2009 the Company changed its oil and gas reserves and related disclosures as a result of adopting new oil and gas reserve estimation and disclosure requirements.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Comstock Resources, Inc.’s internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 22, 2011 expressed an unqualified opinion thereon.
/s/ ERNST & YOUNG LLP
Dallas, Texas
February 22, 2011

F-2

##### Table of Contents

COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
As of December 31, 2009 and 2010

|  | December 31, |
|  | 2009 |  |  | 2010 |
|  | (In thousands) |
ASSETS
Cash and Cash Equivalents |  | $ | 90,472 |  |  | $ | 1,732 |
Accounts Receivable: |  |  |  |  |  |  |  |
Oil and gas sales |  |  | 31,435 |  |  |  | 28,705 |
Joint interest operations |  |  | 8,845 |  |  |  | 15,982 |
Marketable Securities |  |  | 95,973 |  |  |  | 84,637 |
Current Income Taxes Receivable |  |  | 42,402 |  |  |  | — |
Other Current Assets |  |  | 4,259 |  |  |  | 4,675 |
Total current assets |  |  | 273,386 |  |  |  | 135,731 |
Property and Equipment: |  |  |  |  |  |  |  |
Unevaluated oil and gas properties |  |  | 130,364 |  |  |  | 225,884 |
Oil and gas properties, successful efforts method |  |  | 2,289,571 |  |  |  | 2,574,717 |
Other |  |  | 6,477 |  |  |  | 18,156 |
Accumulated depreciation, depletion and amortization |  |  | (850,125 | ) |  |  | (1,002,509 | )
Net property and equipment |  |  | 1,576,287 |  |  |  | 1,816,248 |
Other Assets |  |  | 9,288 |  |  |  | 12,235 |
|  | $ | 1,858,961 |  |  | $ | 1,964,214 |
LIABILITIES AND STOCKHOLDERS’ EQUITY
Accounts Payable |  | $ | 67,488 |  |  | $ | 123,275 |
Deferred Income Taxes Payable |  |  | 6,588 |  |  |  | 10,339 |
Accrued Expenses |  |  | 20,695 |  |  |  | 21,450 |
Total current liabilities |  |  | 94,771 |  |  |  | 155,064 |
Long-term Debt |  |  | 470,836 |  |  |  | 513,372 |
Deferred Income Taxes Payable |  |  | 220,682 |  |  |  | 217,993 |
Reserve for Future Abandonment Costs |  |  | 6,561 |  |  |  | 6,674 |
Other Non-Current Liabilities |  |  | — |  |  |  | 2,580 |
Total liabilities |  |  | 792,850 |  |  |  | 895,683 |
Commitments and Contingencies |  |  |  |  |  |  |  |
Stockholders’ Equity: |  |  |  |  |  |  |  |
Common stock — $0.50 par, 75,000,000 shares authorized, 47,103,770 and 47,706,101 shares issued and outstanding at December 31, 2009 and 2010, respectively |  |  | 23,552 |  |  |  | 23,853 |
Additional paid-in capital |  |  | 434,505 |  |  |  | 454,499 |
Accumulated other comprehensive income |  |  | 30,619 |  |  |  | 32,330 |
Retained earnings |  |  | 577,435 |  |  |  | 557,849 |
Total stockholders’ equity |  |  | 1,066,111 |  |  |  | 1,068,531 |
|  | $ | 1,858,961 |  |  | $ | 1,964,214 |

The accompanying notes are an integral part of these statements.

F-3

##### Table of Contents

COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
For the Years Ended December 31, 2008, 2009 and 2010

|  | 2008 |  |  | 2009 |  |  | 2010 |
|  | (In thousands, except per share amounts) |
Revenues: |  |  |  |  |  |  |  |  |  |  |  |
Oil and gas sales |  | $ | 563,749 |  |  | $ | 292,583 |  |  | $ | 349,141 |
Gain on sale of properties |  |  | 26,560 |  |  |  | 213 |  |  |  | — |
Total revenues |  |  | 590,309 |  |  |  | 292,796 |  |  |  | 349,141 |
Operating expenses: |  |  |  |  |  |  |  |  |  |  |  |
Production taxes |  |  | 20,648 |  |  |  | 8,643 |  |  |  | 9,894 |
Gathering and transportation |  |  | 3,910 |  |  |  | 8,696 |  |  |  | 17,256 |
Lease operating |  |  | 62,172 |  |  |  | 53,560 |  |  |  | 53,525 |
Exploration |  |  | 5,032 |  |  |  | 907 |  |  |  | 2,605 |
Depreciation, depletion and amortization |  |  | 182,179 |  |  |  | 213,238 |  |  |  | 213,809 |
Impairment of oil and gas properties |  |  | 922 |  |  |  | 115 |  |  |  | 224 |
Loss on sale of properties |  |  | — |  |  |  | — |  |  |  | 26,632 |
General and administrative, net |  |  | 32,266 |  |  |  | 39,172 |  |  |  | 37,200 |
Total operating expenses |  |  | 307,129 |  |  |  | 324,331 |  |  |  | 361,145 |
Operating income (loss) from continuing operations |  |  | 283,180 |  |  |  | (31,535 | ) |  |  | (12,004 | )
Other income (expenses): |  |  |  |  |  |  |  |  |  |  |  |
Interest income |  |  | 1,537 |  |  |  | 245 |  |  |  | 263 |
Other income |  |  | 119 |  |  |  | 133 |  |  |  | 236 |
Interest expense |  |  | (25,336 | ) |  |  | (16,086 | ) |  |  | (29,456 | )
Gain on sale of marketable securities |  |  | — |  |  |  | — |  |  |  | 16,529 |
Marketable securities impairment |  |  | (162,672 | ) |  |  | — |  |  |  | — |
Total other income (expenses) |  |  | (186,352 | ) |  |  | (15,708 | ) |  |  | (12,428 | )
Income (loss) from continuing operations before income taxes |  |  | 96,828 |  |  |  | (47,243 | ) |  |  | (24,432 | )
Benefit from (provision for) income taxes |  |  | (38,611 | ) |  |  | 10,772 |  |  |  | 4,846 |
Income (loss) from continuing operations |  |  | 58,217 |  |  |  | (36,471 | ) |  |  | (19,586 | )
Income from discontinued operations |  |  | 193,745 |  |  |  | — |  |  |  | — |
Net income (loss) |  | $ | 251,962 |  |  | $ | (36,471 | ) |  | $ | (19,586 | )
Basic net income (loss) per share: |  |  |  |  |  |  |  |  |  |  |  |
Continuing operations |  | $ | 1.27 |  |  | $ | (0.81 | ) |  | $ | (0.43 | )
Discontinued operations |  |  | 4.23 |  |  |  | — |  |  |  | — |
|  | $ | 5.50 |  |  | $ | (0.81 | ) |  | $ | (0.43 | )
Diluted net income (loss) per share: |  |  |  |  |  |  |  |  |  |  |  |
Continuing operations |  | $ | 1.26 |  |  | $ | (0.81 | ) |  | $ | (0.43 | )
Discontinued operations |  |  | 4.20 |  |  |  | — |  |  |  | — |
|  | $ | 5.46 |  |  | $ | (0.81 | ) |  | $ | (0.43 | )
Weighted average shares outstanding: |  |  |  |  |  |  |  |  |  |  |  |
Basic |  |  | 44,524 |  |  |  | 45,004 |  |  |  | 45,561 |
Diluted |  |  | 44,813 |  |  |  | 45,004 |  |  |  | 45,561 |

The accompanying notes are an integral part of these statements.

F-4

##### Table of Contents

COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
AND COMPREHENSIVE INCOME (LOSS)
For the Years Ended December 31, 2008, 2009 and 2010

|  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | Non- |  |  |  |
|  |  |  |  |  |  |  |  |  |  |  |  |  | Accumulated |  |  | Controlling |  |  |  |
|  |  |  |  | Common |  |  | Additional |  |  |  |  |  | Other |  |  | Interest in |  |  |  |
|  | Common |  |  | Stock- |  |  | Paid-in |  |  | Retained |  |  | Comprehensive |  |  | Discontinued |  |  |  |
|  | Shares |  |  | Par Value |  |  | Capital |  |  | Earnings |  |  | Income |  |  | Operations |  |  | Total |
|  | (In thousands) |
Balance at December 31, 2007 |  |  | 45,428 |  |  | $ | 22,714 |  |  | $ | 386,986 |  |  | $ | 361,944 |  |  | $ | — |  |  | $ | 267,441 |  |  | $ | 1,039,085 |
Exercise of stock options and warrants |  |  | 591 |  |  |  | 295 |  |  |  | 8,033 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 8,328 |
Stock-based compensation |  |  | 423 |  |  |  | 212 |  |  |  | 12,051 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 12,263 |
Tax benefit of stock-based compensation |  |  | — |  |  |  | — |  |  |  | 8,805 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 8,805 |
Net income |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 251,962 |  |  |  | — |  |  |  | — |  |  |  | 251,962 |
Unrealized hedging gain, net of income taxes |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 9,083 |  |  |  | — |  |  |  | 9,083 |
Total comprehensive income |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 261,045 |
Minority interest in earnings of Bois d’Arc |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 46,883 |  |  |  | 46,883 |
Stock issuances by Bois d’Arc |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 4,612 |  |  |  | 4,612 |
Stock repurchases by Bois d’Arc |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | (3,009 | ) |  |  | (3,009 | )
Stock-based compensation of Bois d’Arc |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 19,294 |  |  |  | 19,294 |
Sale of shares of Bois d’Arc |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | (335,221 | ) |  |  | (335,221 | )
Balance at December 31, 2008 |  |  | 46,442 |  |  |  | 23,221 |  |  |  | 415,875 |  |  |  | 613,906 |  |  |  | 9,083 |  |  |  | — |  |  |  | 1,062,085 |
Exercise of stock options and warrants |  |  | 113 |  |  |  | 57 |  |  |  | 2,024 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 2,081 |
Stock-based compensation |  |  | 549 |  |  |  | 274 |  |  |  | 15,509 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 15,783 |
Tax benefit of stock-based compensation |  |  | — |  |  |  | — |  |  |  | 1,097 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 1,097 |
Net loss |  |  | — |  |  |  | — |  |  |  | — |  |  |  | (36,471 | ) |  |  | — |  |  |  | — |  |  |  | (36,471 | )
Unrealized hedging loss, net of income taxes |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | (9,083 | ) |  |  | — |  |  |  | (9,083 | )
Unrealized gain on marketable securities, net of income taxes |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 30,619 |  |  |  | — |  |  |  | 30,619 |
Total comprehensive loss |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | (14,935 | )
Balance at December 31, 2009 |  |  | 47,104 |  |  |  | 23,552 |  |  |  | 434,505 |  |  |  | 577,435 |  |  |  | 30,619 |  |  |  | — |  |  |  | 1,066,111 |
Exercise of stock options |  |  | 184 |  |  |  | 92 |  |  |  | 1,335 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 1,427 |
Stock-based compensation |  |  | 418 |  |  |  | 209 |  |  |  | 17,168 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 17,377 |
Tax benefit of stock-based compensation |  |  | — |  |  |  | — |  |  |  | 1,491 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 1,491 |
Net loss |  |  | — |  |  |  | — |  |  |  | — |  |  |  | (19,586 | ) |  |  | — |  |  |  | — |  |  |  | (19,586 | )
Net change in unrealized gains and losses on marketable securities, net of income taxes |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 1,711 |  |  |  | — |  |  |  | 1,711 |
Total comprehensive loss |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | (17,875 | )
Balance at December 31, 2010 |  |  | 47,706 |  |  | $ | 23,853 |  |  | $ | 454,499 |  |  | $ | 557,849 |  |  | $ | 32,330 |  |  | $ | — |  |  | $ | 1,068,531 |

The accompanying notes are an integral part of these statements.

F-5

##### Table of Contents

COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2008, 2009 and 2010

|  | 2008 |  |  | 2009 |  |  | 2010 |
|  | (In thousands) |
CASH FLOWS FROM CONTINUING OPERATIONS — |  |  |  |  |  |  |  |  |  |  |  |
Cash Flows From Operating Activities: |  |  |  |  |  |  |  |  |  |  |  |
Net income (loss) |  | $ | 251,962 |  |  | $ | (36,471 | ) |  | $ | (19,586 | )
Adjustments to reconcile net income (loss) to net cash provided by operating activities: |  |  |  |  |  |  |  |  |  |  |  |
Income from discontinued operations |  |  | (193,745 | ) |  |  | — |  |  |  | — |
(Gain) loss on sale of assets |  |  | (26,560 | ) |  |  | (213 | ) |  |  | 10,103 |
Deferred income taxes |  |  | 43,620 |  |  |  | 30,796 |  |  |  | (4,617 | )
Dry hole costs and leasehold impairments |  |  | 4,113 |  |  |  | — |  |  |  | — |
Impairment of marketable securities |  |  | 162,672 |  |  |  | — |  |  |  | — |
Impairment of oil and gas properties |  |  | 922 |  |  |  | 115 |  |  |  | 224 |
Depreciation, depletion and amortization |  |  | 182,179 |  |  |  | 213,238 |  |  |  | 213,809 |
Debt issuance costs and discount amortization |  |  | 810 |  |  |  | 1,162 |  |  |  | 2,436 |
Stock-based compensation |  |  | 12,263 |  |  |  | 15,783 |  |  |  | 17,377 |
Excess tax benefit from stock-based compensation |  |  | (8,805 | ) |  |  | (1,097 | ) |  |  | (1,491 | )
Decrease (increase) in accounts receivable |  |  | 6,418 |  |  |  | 1,997 |  |  |  | (4,432 | )
Decrease (increase) in other current assets |  |  | (9,646 | ) |  |  | (27,927 | ) |  |  | 48,070 |
Increase (decrease) in accounts payable and accrued expenses |  |  | 24,330 |  |  |  | (21,126 | ) |  |  | 49,769 |
Net cash provided by operating activities from continuing operations |  |  | 450,533 |  |  |  | 176,257 |  |  |  | 311,662 |
Cash Flows From Investing Activities: |  |  |  |  |  |  |  |  |  |  |  |
Capital expenditures and acquisitions |  |  | (418,730 | ) |  |  | (349,987 | ) |  |  | (537,400 | )
Proceeds from sales of properties |  |  | 129,536 |  |  |  | 1,210 |  |  |  | 66,428 |
Proceeds from sales of marketable securities |  |  | — |  |  |  | — |  |  |  | 30,499 |
Net cash used for investing activities from continuing operations |  |  | (289,194 | ) |  |  | (348,777 | ) |  |  | (440,473 | )
Cash Flows From Financing Activities: |  |  |  |  |  |  |  |  |  |  |  |
Borrowings |  |  | 85,000 |  |  |  | 430,713 |  |  |  | 110,000 |
Principal payments on debt |  |  | (555,000 | ) |  |  | (170,000 | ) |  |  | (68,000 | )
Debt issuance costs |  |  | (16 | ) |  |  | (7,180 | ) |  |  | (4,847 | )
Proceeds from common stock issuances |  |  | 8,328 |  |  |  | 2,081 |  |  |  | 1,427 |
Excess tax benefit from stock-based compensation |  |  | 8,805 |  |  |  | 1,097 |  |  |  | 1,491 |
Net cash provided by (used for) financing activities from continuing operations |  |  | (452,883 | ) |  |  | 256,711 |  |  |  | 40,071 |
Net cash provided by (used for) continuing operations |  |  | (291,544 | ) |  |  | 84,191 |  |  |  | (88,740 | )
CASH FLOWS FROM DISCONTINUED OPERATIONS — |  |  |  |  |  |  |  |  |  |  |  |
Net Cash Provided by Operating Activities |  |  | 240,332 |  |  |  | — |  |  |  | — |
Cash Flows From Investing Activities: |  |  |  |  |  |  |  |  |  |  |  |
Proceeds from sale of Bois d’Arc Energy, net of income taxes |  |  | 292,260 |  |  |  | — |  |  |  | — |
Capital expenditures |  |  | (159,368 | ) |  |  | — |  |  |  | — |
Net cash provided by investing activities |  |  | 132,892 |  |  |  | — |  |  |  | — |
Net Cash Used for Financing Activities |  |  | (80,964 | ) |  |  | — |  |  |  | — |
Net cash provided by discontinued operations |  |  | 292,260 |  |  |  | — |  |  |  | — |
Net increase in cash and cash equivalents |  |  | 716 |  |  |  | 84,191 |  |  |  | (88,740 | )
Cash and cash equivalents, beginning of year |  |  | 5,565 |  |  |  | 6,281 |  |  |  | 90,472 |
Cash and cash equivalents, end of year |  | $ | 6,281 |  |  | $ | 90,472 |  |  | $ | 1,732 |

The accompanying notes are an integral part of these statements.

F-6

##### Table of Contents

COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1) | Summary of Significant Accounting Policies

Accounting policies used by Comstock Resources, Inc. 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. is 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 and Louisiana. 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.
Discontinued Offshore Operations
In August 2008, the Company’s subsidiary, Bois d’Arc Energy, Inc. (“Bois d’Arc”) completed a merger with Stone Energy Corporation (“Stone”) pursuant to which each outstanding share of the common stock of Bois d’Arc was exchanged for cash in the amount of $13.65 per share and 0.165 shares of Stone common stock. Prior to the merger, Comstock conducted all of its offshore operations through Bois d’Arc. As a result of the merger, Comstock received net proceeds of $439.0 million in cash and 5,317,069 shares of Stone common stock in exchange for its interest in Bois d’Arc. As a result of the merger of Bois d’Arc and Stone, the consolidated financial statements and the related notes thereto present the Company’s offshore operations as a discontinued operation. No general and administrative or interest costs incurred by Comstock have been allocated to the 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.
The merger of Bois d’Arc with Stone resulted in Comstock recognizing a gain on the disposal of the discontinued operations in 2008 of $158.1 million, after income taxes of $85.3 million and the Company’s share of transaction related costs incurred by Bois d’Arc of $11.7 million. Transaction-related costs incurred by Bois d’Arc included accounting, legal and investment banking fees, change-in-control and other compensation costs that became obligations as a result of the merger.
Income from discontinued operations is comprised of the following:

|  | For the Year Ended |  |  |  |  |  |  |
|  | December 31, |  |  |  |  |  |  |
|  | 2008 |  |  |  |  |  |  |
|  | (In thousands) |  |  |  |  |  |  |
Oil and gas sales |  | $ | 360,719 |  |  |  |  |  |  |  |  |
Total operating expenses |  |  | (198,894 | ) |  |  |  |  |  |  |  |
Operating income from discontinued operations |  |  | 161,825 |  |  |  |  |  |  |  |  |
Other income (expenses) |  |  | (2,630 | ) |  |  |  |  |  |  |  |
Provision for income taxes |  |  | (76,626 | ) |  |  |  |  |  |  |  |
Minority interest in earnings |  |  | (46,883 | ) |  |  |  |  |  |  |  |
Income from discontinued operations, excluding gain on sale |  |  | 35,686 |  |  |  |  |  |  |  |  |
Gain on sale of discontinued operations, net of income taxes of $85,327 |  |  | 158,059 |  |  |  |  |  |  |  |  |
Income from discontinued operations |  | $ | 193,745 |  |  |  |  |  |  |  |  |

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##### Table of Contents

COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Reclassifications
Certain reclassifications have been made to prior periods’ financial statements to conform to the current presentation.
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 analysis 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 and accounts receivable. The Company places its cash with high credit quality financial institutions. 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 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.
Marketable Securities
Marketable securities are recorded at fair value, and temporary unrealized holding gains and losses are recorded, net of income tax, as a separate component of accumulated other comprehensive income. Unrealized losses are charged against net earnings when a decline in fair value is determined to be other than temporary. Comstock considers several factors to determine whether a loss is other than temporary. These factors include but are not limited to: (i) the length of time a security is in an unrealized loss position, (ii) the extent to which fair value is less than cost, (iii) the financial condition and near term prospects of the issuer and (iv) the ability to hold the security for a period of time sufficient to allow for any anticipated recovery in fair value. Realized gains and losses are accounted for using the specific identification method.
As of December 31, 2009 and 2010 the Company owned 5,317,069 and 3,797,069 shares, respectively, of Stone common stock. The Company does not exert influence over the operating and financial policies of Stone, and has classified its investment in these shares as an available-for-sale security in the consolidated balance sheets. Available-for-sale securities are accounted for at fair value, with any unrealized gains and unrealized losses not determined to be other than temporary reported in the consolidated balance sheet within accumulated other comprehensive income as a separate component of stockholders’ equity. The Company utilizes the specific identification method to determine the cost of any securities sold. During 2010 the Company sold 1,520,000 shares of Stone common stock and received proceeds of $30.5 million. Comstock realized a gain before income taxes of $16.5 million on the sales during 2010 which is included in other income (expenses) in the consolidated statements of operations.

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##### Table of Contents

COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The Company reviews its available-for-sale securities to determine whether a decline in fair value below the respective cost basis is other than temporary. If the decline in fair value is judged to be other than temporary, the cost basis of the security is written down to fair value and the amount of the write-down is included in the consolidated statement of operations. When the Stone shares were acquired in August 2008, the value was determined to be $211.4 million by an independent valuation specialist. As of December 31, 2008 the estimated value of the Stone shares had declined to $48.9 million, and the Company recognized an impairment charge of $162.7 million before income taxes in 2008 based on its determination that this decline in fair value was other than temporary. As of December 31, 2009 and 2010 the cost basis of the Stone shares was $48.9 million and $34.9 million, respectively. As of December 31, 2009 and 2010, the estimated fair value of the Stone shares, based on the market price for the shares, was $96.0 million and $84.6 million after recognizing unrealized gains after income taxes of $30.6 million and $32.3 million, respectively.
Other Current Assets
Other current assets at December 31, 2009 and 2010 consist of the following:

|  | As of December 31, |
|  | 2009 |  |  | 2010 |
|  | (In thousands) |
Drilling advances |  | $ | 195 |  |  | $ | 194 |
Prepaid expenses |  |  | 523 |  |  |  | 381 |
Pipe inventory |  |  | 2,060 |  |  |  | 1,552 |
Production tax refunds receivable |  |  | 1,480 |  |  |  | 2,500 |
Other |  |  | 1 |  |  |  | 48 |
|  | $ | 4,259 |  |  | $ | 4,675 |

Property and Equipment
The Company follows the successful efforts method of accounting for its oil and natural gas properties. Acquisition costs for proved oil and natural 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. Cost centers for amortization purposes are determined on a field area basis. Costs incurred to acquire oil and gas leasehold are capitalized. Unproved oil and gas properties are periodically assessed and any impairment in value is charged to exploration expense. 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 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. Exploratory drilling costs are initially capitalized as unproved property but charged to expense if and when the well is determined not to have found proved oil and gas reserves. Exploratory drilling costs are evaluated within a one-year period after the completion of drilling.

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##### Table of Contents

COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The Company assesses the need for an impairment of the costs capitalized for its 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. 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 reserve estimates at the end of the period. 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 actual prices on the last day of the period, for periods prior to December 31, 2009, and an average price based on the first day of each month of the years commencing with December 31, 2009, and is limited to proved reserves. The Company recognized impairment charges related to its oil and gas properties of $0.9 million, $0.1 million and $0.2 million in 2008, 2009, and 2010, respectively.
Effective December 31, 2009, the Company adopted the changes contained in the Securities and Exchange Final Rule “Modernization of Oil and Gas Reporting,” the related changes contained in Securities and Exchange Staff Accounting Bulletin 113 which modified Topic 12, Oil and Gas Producing Activities, and the Financial Accounting Standards Board accounting guidance issued to align the reserve estimation and disclosure requirements within generally accepted accounting principles to guidance issued by the Securities and Exchange Commission.
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.
Reserve for Future Abandonment Costs
The Company records a liability in the period in which an asset retirement obligation is incurred, in an amount equal to the discounted 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 financial statements. The Company’s asset retirement obligations relate to future plugging and abandonment costs of its oil and gas properties and related facilities disposal.
The following table summarizes the changes in the Company’s total estimated liability:

|  | 2008 |  |  | 2009 |  |  | 2010 |
|  | (In thousands) |
Reserve for Future Abandonment Costs at beginning of the year |  | $ | 7,512 |  |  | $ | 5,480 |  |  | $ | 6,561 |
New wells placed on production and changes in estimates |  |  | (1,537 | ) |  |  | 853 |  |  |  | 934 |
Liabilities settled and assets disposed of |  |  | (939 | ) |  |  | (86 | ) |  |  | (1,212 | )
Accretion expense |  |  | 444 |  |  |  | 314 |  |  |  | 391 |
Reserve for Future Abandonment Costs at end of the year |  | $ | 5,480 |  |  | $ | 6,561 |  |  | $ | 6,674 |

F-10

##### Table of Contents

COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Other Assets
Other assets primarily consist of deferred costs associated with issuance of the Company’s senior notes and bank credit facility. These costs are amortized over the life of the senior notes and 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.
Stock-based Compensation
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 tax benefits on stock-based compensation are recognized as an increase 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 Instruments and Hedging Activities
The Company accounts for derivative 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 quotes obtained from the counterparties to the derivative contract. 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. Derivative financial instruments that are not accounted for as hedges are adjusted to fair value through income. 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. The Company held no derivative financial instruments at December 31, 2009 or 2010.
Major Purchasers
In 2010 the Company had one purchaser of its oil and natural gas production that accounted for 39% of total oil and gas sales. In 2009 the Company had two purchasers of its oil and natural gas production that accounted for 22% and 11%, respectively, of total oil and gas sales. In 2008 the Company had three purchasers of its oil and natural gas production that accounted for 14%, 12% and 11%, respectively, of total oil and gas sales. The loss of any of these customers would not have a material adverse effect on the Company as there is an available market for its crude 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. Revisions to such estimates are recorded as actual results are known. The

F-11

##### Table of Contents

COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
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, 2009 or 2010. Sales of crude 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 $10.1 million, $10.2 million and $10.6 million in 2008, 2009 and 2010, 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 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.
Basic and diluted earnings per share for 2008, 2009 and 2010 were determined as follows:

|  | 2008 |  |  | 2009 |  |  | 2010 |
|  | Income |  |  | Shares |  |  | Per Share |  |  | Income |  |  | Shares |  |  | Per Share |  |  | Income |  |  | Shares |  |  | Per Share |
|  | (In thousands except per share data) |
Income (Loss) From Continuing Operations |  | $ | 58,217 |  |  |  |  |  |  |  |  |  |  | $ | (36,471 | ) |  |  |  |  |  |  |  |  |  | $ | (19,586 | ) |  |  |  |  |  |  |  |
Income Allocable to Unvested Stock Grants |  |  | (1,648 | ) |  |  |  |  |  |  |  |  |  |  | — |  |  |  |  |  |  |  |  |  |  |  | — |  |  |  |  |  |  |  |  |
Basic Income (Loss) From Continuing Operations Attributable to Common Stock |  | $ | 56,569 |  |  |  | 44,524 |  |  | $ | 1.27 |  |  | $ | (36,471 | ) |  |  | 45,004 |  |  | $ | (0.81 | ) |  | $ | (19,586 | ) |  |  | 45,561 |  |  | $ | (0.43 | )
Effect of Dilutive Securities: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Stock Options |  |  | — |  |  |  | 289 |  |  |  |  |  |  |  | — |  |  |  | — |  |  |  |  |  |  |  | — |  |  |  | — |  |  |  |  |
Diluted Income (Loss) From Continuing Operations Attributable to Common Stock |  | $ | 56,569 |  |  |  | 44,813 |  |  | $ | 1.26 |  |  | $ | (36,471 | ) |  |  | 45,004 |  |  | $ | (0.81 | ) |  | $ | (19,586 | ) |  |  | 45,561 |  |  | $ | (0.43 | )
Income from Discontinued Operations |  | $ | 193,745 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Income Allocable to Unvested Stock Grants |  |  | (5,486 | ) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Basic Income from Discontinued Operations Attributable to Common Stock |  | $ | 188,259 |  |  |  | 44,524 |  |  | $ | 4.23 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Effect of Dilutive Securities: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Stock Options |  |  | — |  |  |  | 289 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Diluted Income from Discontinued Operations Attributable to Common Stock |  | $ | 188,259 |  |  |  | 44,813 |  |  | $ | 4.20 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

F-12

##### Table of Contents

COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
At December 31, 2009 and 2010, 2,036,450 and 2,069,275 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:

|  | 2008 |  |  | 2009 |  |  | 2010 |
|  | (In thousands) |
Unvested restricted stock |  |  | 1,297 |  |  |  | 1,583 |  |  |  | 1,715 |

Stock options that were excluded from the determination of diluted earnings per share are as follows:

|  | 2008 |  |  | 2009 |  |  | 2010 |
|  | (In thousands except per share data) |
Weighted average anti-dilutive stock options |  |  | 40 |  |  |  | 447 |  |  |  | 240 |
Weighted average exercise price |  | $ | 54.36 |  |  | $ | 24.93 |  |  | $ | 35.98 |

Stock options were excluded as anti-dilutive to earnings per share due to the net loss in 2009 and 2010. In 2008, the excluded options that were anti-dilutive were at exercise prices in excess of the average actual stock price for the period.
Fair Value Measurements
The Company holds or has held certain items that are required to be measured at fair value. These include cash equivalents held in money market funds and marketable securities comprised of shares of Stone common stock, and derivative financial instruments in the form of 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. All of the Company’s assets held at December 31, 2010 that are required to be measured at fair value are based on inputs where the 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.
The following table summarizes financial assets accounted for at fair value as of December 31, 2010:

|  | Carrying Value |
|  | Measured at Fair |
|  | Value at |
|  | December 31, 2010 |
|  | (In thousands) |
Items measured at fair value on a recurring basis: |  |  |  |
Cash equivalents — money market funds |  | $ | 1,732 |
Marketable securities — Stone common stock |  |  | 84,637 |
Total assets |  | $ | 86,369 |

The following table presents the carrying amounts and estimated fair value of the Company’s other financial instruments as of December 31, 2009 and 2010:

|  | 2009 |  |  | 2010 |
|  | Carrying |  |  | Fair |  |  | Carrying |  |  | Fair |
|  | Value |  |  | Value |  |  | Value |  |  | Value |
|  | (In thousands) |
Long-term debt, including current portion |  | $ | 470,836 |  |  | $ | 479,938 |  |  | $ | 513,372 |  |  | $ | 518,930 |

F-13

##### Table of Contents

COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The fair market value of the Company’s fixed rate debt was based on the market prices as of December 31, 2009 and 2010. The fair value of the floating rate debt outstanding at December 31, 2010 approximated its carrying value.
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. At December 31, 2009 and 2010, the Company’s cash investments consisted of prime shares in institutional preferred money market funds.
Cash payments made for interest and income taxes for the years ended December 31, 2008, 2009 and 2010, respectively, were as follows:

|  | 2008 |  |  | 2009 |  |  | 2010 |
|  | (In thousands) |
Cash Payments: |  |  |  |  |  |  |  |  |  |  |  |
Interest payments |  | $ | 27,022 |  |  | $ | 15,827 |  |  | $ | 40,467 |
Income tax payments (refunds) |  | $ | 140,198 |  |  | $ | (4,924 | ) |  | $ | (48,575 | )

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 $2.3 million, $6.6 million and $13.0 million in 2008, 2009 and 2010, respectively, which reduced interest expense and increased the carrying value of its unevaluated oil and gas properties.
Comprehensive Income (Loss)
Comprehensive income (loss) consists of the following:

|  | For the Year Ended December 31, |
|  | 2008 |  |  | 2009 |  |  | 2010 |
|  | (In thousands) |
Income (loss) from continuing operations |  | $ | 58,217 |  |  | $ | (36,471 | ) |  | $ | (19,586 | )
Other comprehensive income (loss): |  |  |  |  |  |  |  |  |  |  |  |
Realized gain on marketable securities, net of income taxes of $5,785 in 2010 |  |  | — |  |  |  | — |  |  |  | (10,744 | )
Unrealized hedging gains (losses), net of income tax expense (benefit) of $4,891 in 2008 and $(4,891) in 2009 |  |  | 9,083 |  |  |  | (9,083 | ) |  |  | — |
Unrealized gain on marketable securities, net of income tax expense of $16,487 in 2009 and $6,707 in 2010 |  |  | — |  |  |  | 30,619 |  |  |  | 12,455 |
Total from continuing operations |  |  | 67,300 |  |  |  | (14,935 | ) |  |  | (17,875 | )
Income from discontinued operations, net of income taxes and minority interest |  |  | 193,745 |  |  |  | — |  |  |  | — |
Total comprehensive income (loss) |  | $ | 261,045 |  |  | $ | (14,935 | ) |  | $ | (17,875 | )

F-14

##### Table of Contents

COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The following table provides a summary of the amounts included in accumulated other comprehensive income (loss), net of income taxes, which are solely attributable to the Company’s natural gas price swap financial instruments and marketable securities, for the years ended December 31, 2009 and 2010:

|  |  |  |  |  |  |  | Accumulated |
|  | Natural Gas |  |  |  |  |  | Other |
|  | Price Swap |  |  | Marketable |  |  | Comprehensive |
|  | Agreement |  |  | Securities |  |  | Income (Loss) |
|  | (In thousands) |
Balance as of December 31, 2008 |  | $ | 9,083 |  |  | $ | — |  |  | $ | 9,083 |
2009 changes in value |  |  | (35,405 | ) |  |  | 30,619 |  |  |  | (4,786 | )
Reclassification to earnings |  |  | 26,322 |  |  |  | — |  |  |  | 26,322 |
Balance as of December 31, 2009 |  |  | — |  |  |  | 30,619 |  |  |  | 30,619 |
2010 changes in value |  |  | — |  |  |  | 12,455 |  |  |  | 12,455 |
Reclassification to earnings |  |  | — |  |  |  | (10,744 | ) |  |  | (10,744 | )
Balance as of December 31, 2010 |  | $ | — |  |  | $ | 32,330 |  |  | $ | 32,330 |

Subsequent Events
Subsequent events were evaluated through the issuance date of these consolidated financial statements.

(2) | Dispositions of Oil and Gas Properties

In June and September 2008, the Company sold interests in certain producing properties in East and South Texas and received aggregate net proceeds of $129.6 million. Comstock recognized a gain of $26.6 million on these sales. In December 2010, the Company sold its oil and gas properties in Mississippi and received net proceeds of $65.3 million. Comstock recognized a loss of $25.8 million on this sale.

(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, |
|  | 2009 |  |  | 2010 |
|  | (In thousands) |
Unproved properties |  | $ | 130,364 |  |  | $ | 225,884 |
Proved properties: |  |  |  |  |  |  |  |
Leasehold costs |  |  | 864,380 |  |  |  | 821,085 |
Wells and related equipment and facilities |  |  | 1,425,191 |  |  |  | 1,753,632 |
Accumulated depreciation depletion and amortization |  |  | (847,568 | ) |  |  | (996,750 | )
|  | $ | 1,572,367 |  |  | $ | 1,803,851 |

F-15

##### Table of Contents

COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Costs Incurred

|  | 2008 |  |  | 2009 |  |  | 2010 |
|  | (In thousands) |
Unproved property acquisitions |  | $ | 113,023 |  |  | $ | 26,040 |  |  | $ | 134,728 |
Development costs |  |  | 249,527 |  |  |  | 218,191 |  |  |  | 315,041 |
Exploration costs |  |  | 62,031 |  |  |  | 101,956 |  |  |  | 87,823 |
|  | $ | 424,581 |  |  | $ | 346,187 |  |  | $ | 537,592 |

(4) | Long-term Debt

Long-term debt is comprised of the following:

|  | As of December 31, |
|  | 2009 |  |  | 2010 |
|  | (In thousands) |
67/8% senior notes due 2012 |  | $ | 175,000 |  |  | $ | 172,000 |
Bank credit facility |  |  | — |  |  |  | 45,000 |
83/8% senior notes due 2017 |  |  | 300,000 |  |  |  | 300,000 |
Discount related to 83/8% senior notes due 2017 |  |  | (4,164 | ) |  |  | (3,628 | )
|  | $ | 470,836 |  |  | $ | 513,372 |

The discount is being amortized over the life of the senior notes using the effective interest rate method.
The following table summarizes Comstock’s debt as of December 31, 2010 by year of maturity:

|  | 2011 |  |  | 2012 |  |  | 2013 |  |  | 2014 |  |  | 2015 |  |  | Thereafter |  |  | Total |
|  | (In thousands) |
67/8% senior notes |  | $ | — |  |  | $ | 172,000 |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | 172,000 |
Bank credit facility |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 45,000 |  |  |  | — |  |  |  | 45,000 |
83/8% senior notes |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 296,372 |  |  |  | 296,372 |
|  | $ | — |  |  | $ | 172,000 |  |  | $ | — |  |  | $ | — |  |  | $ | 45,000 |  |  | $ | 296,372 |  |  | $ | 513,372 |

Comstock has a $850.0 million bank credit facility with Bank of Montreal, as the administrative agent. The credit facility is a five year revolving credit commitment that matures on November 30, 2015. Indebtedness under the credit facility is secured by substantially all of Comstock’s assets and is guaranteed by all of its wholly owned subsidiaries. The credit facility is subject to borrowing base availability, which is redetermined semiannually based on the banks’ estimates of the Company’s future net cash flows of oil and natural gas properties. The borrowing base may be affected by the performance of Comstock’s properties and changes in oil and natural gas prices. The determination of the borrowing base is at the sole discretion of the administrative agent and the bank group. As of December 31, 2010, the borrowing base was $500.0 million, $455.0 million of which was available. Borrowings under the credit facility bear interest, based on the utilization of the borrowing base, at Comstock’s option at either (1) LIBOR plus 1.75% to 2.75% 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 0.75% to 1.75%. A commitment fee of 0.5% is payable annually on the unused borrowing base. The credit facility contains covenants that, among other things,

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COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
restrict the payment of cash dividends in excess of $50.0 million, limit the amount of consolidated debt that Comstock may incur and limit the Company’s ability to make certain loans and investments. The only financial covenants are the maintenance of a ratio of current assets, including availability under the bank credit facility, to current liabilities of at least one-to-one and maintenance of a minimum tangible net worth. The Company was in compliance with these covenants as of December 31, 2010.
Comstock has $172.0 million of 67/8% senior notes outstanding which mature on March 1, 2012. Interest is payable semiannually on each March 1 and September 1. During 2010 the Company purchased $3.0 million in principal amount of the 67/8% senior notes for $2.9 million. The Company also has $300.0 million of 83/8% senior notes outstanding which mature on October 15, 2017. Interest is payable semiannually on each April 15 and October 15. The senior notes are unsecured obligations of Comstock and are guaranteed by all of Comstock’s material subsidiaries. The subsidiary guarantors are 100% owned and all of the guarantees are full and conditional and joint and several. As of December 31, 2010, Comstock had no material assets or operations which are independent of its subsidiaries. There are no restrictions on the ability of Comstock to obtain funds from its subsidiaries through dividends or loans.

(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, 2008, 2009 and 2010 was $1.0 million, $1.2 million and $1.3 million, respectively. Minimum future payments under the leases are as follows:

|  | (In thousands) |
2011 |  | $ | 1,701 |
2012 |  |  | 1,701 |
2013 |  |  | 1,701 |
2014 |  |  | 1,200 |
2015 |  |  | 500 |
Thereafter |  |  | 1,500 |
|  | $ | 8,303 |

As of December 31, 2010, the Company had commitments for contracted drilling rigs of $50.5 million through September 2012. The Company has entered into natural gas transportation agreements through July 2019. Maximum commitments under these transportation agreements as of December 31, 2010 totaled $46.5 million. The Company has also entered into agreements for well completion services through December 31, 2011 with minimum future payments of $98.6 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 resolution of these matters will have a material effect on the Company’s financial position or results of operations.

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COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(6) | Stockholders’ Equity

The authorized capital stock of Comstock consists of 75 million shares of common stock, $.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, 2009 or 2010.

(7) | Stock-based Compensation

The Company grants restricted shares of common stock and stock options to key employees and directors as part of their compensation. On May 19, 2009, the Company’s stockholders approved the 2009 Long-term Incentive Plan for management including officers, directors and managerial employees which replaced the 1999 Long-term Incentive Plan. As of December 31, 2010, the 2009 Long-term Incentive Plan provides for future awards of stock options, restricted stock grants or other equity awards of up to 3,030,900 shares of common stock.
During 2008, 2009 and 2010, the Company recorded $12.3 million, $15.8 million and $17.4 million, respectively, in stock-based compensation expense in general and administrative expenses. The excess income tax benefit realized from tax deductions associated with stock-based compensation totaled $8.8 million, $1.1 million and $1.5 million for the years ended December 31, 2008, 2009 and 2010, respectively.
Stock Options
The Company amortizes the fair value of stock options granted over the vesting period using the straight-line method. Total compensation expense recognized for all outstanding stock options for the years ended December 31, 2008, 2009 and 2010 was $1.5 million, $0.8 million and $0.4 million, respectively.
The Company did not issue any stock options during 2009 or 2010. Options granted in 2008 were granted with exercise prices equal to the closing price of the Company’s common stock on the grant date. The following table summarizes the assumptions used to value stock options granted in the year ended December 31, 2008:

Weighted average grant date fair value |  |  | $19.76 |
Weighted average assumptions used: |  |  |  |
Expected volatility |  |  | 38.9% |
Expected lives |  |  | 4.3 yrs. |
Risk-free interest rates |  |  | 3.3% |
Expected dividend yield |  |  | — |

The fair value of each award is estimated as of the date of grant using the Black-Scholes options pricing model. The expected volatility for grants is calculated using an analysis of the common stock’s historical volatility. Risk-free interest rates are determined using the implied yield currently available for zero-coupon U.S. government issues with a remaining term equal to the expected life of the options.

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##### Table of Contents

COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The following table summarizes information related to stock options outstanding at December 31, 2010:

|  | Weighted Average |  | Number of |  | Number of
Exercise |  | Remaining Life |  | Options |  | Options
Price |  | (in years) |  | Outstanding |  | Exercisable
$29.49 |  |  | 1.3 |  |  |  | 30,000 |  |  |  | 30,000 |
$32.44 |  |  | 0.4 |  |  |  | 30,000 |  |  |  | 30,000 |
$32.50 |  |  | 4.9 |  |  |  | 54,500 |  |  |  | 54,500 |
$33.22 |  |  | 6.0 |  |  |  | 82,650 |  |  |  | 82,650 |
$54.36 |  |  | 2.4 |  |  |  | 40,000 |  |  |  | 40,000 |
|  |  |  |  |  |  | 237,150 |  |  |  | 237,150 |

The following table summarizes information related to stock option activity under the Company’s incentive plans for the year ended December 31, 2010:

|  | 2010
|  |  |  |  | Weighted
|  | Number of |  |  | Average
|  | Options |  |  | Exercise Price
Outstanding at January 1, 2010 |  |  | 424,620 |  |  | $23.73
Exercised |  |  | (184,470 | ) |  | $7.74
Forfeited |  |  | (3,000 | ) |  | $32.98
Outstanding at December 31, 2010 |  |  | 237,150 |  |  | $36.05
Vested and Exercisable at December 31, 2010 |  |  | 237,150 |  |  | $36.05

|  | 2008 |  |  | 2009 |  |  | 2010 |
|  | (In thousands) |
Cash received for options exercised |  | $ | 6,483 |  |  | $ | 689 |  |  | $ | 1,427 |
Actual tax benefit realized |  | $ | 24,341 |  |  | $ | 646 |  |  | $ | 4,221 |

As of December 31, 2010, all compensation cost related to stock options has been recognized. Stock options outstanding at December 31, 2010 had no intrinsic value based on the closing price for the Company’s common stock on December 31, 2010. The total intrinsic value of options exercised was $24.4 million, $0.6 million and $4.2 million for the years ended December 31, 2008, 2009 and 2010, respectively.

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COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Restricted Stock
The fair value of restricted stock grants is amortized over the vesting period using the straight-line method. Initial grants of restricted stock generally vest 25% per annum over a period of four years from the grate date; subsequent grants, if any, generally vest four years from the date of the award. Total compensation expense recognized for restricted stock grants was $10.8 million, $15.0 million and $17.0 million for the years ended December 31, 2008, 2009 and 2010, respectively. The fair value of each restricted share on the date of grant is equal to its fair market price. A summary of restricted stock activity for the year ended December 31, 2010 is presented below:

|  | Number of |  |  | Weighted
|  | Restricted |  |  | Average Grant
|  | Shares |  |  | Price
Outstanding at January 1, 2010 |  |  | 2,036,450 |  |  | $36.57
Granted |  |  | 418,775 |  |  | $25.61
Vested |  |  | (385,200 | ) |  | $33.13
Forfeitures |  |  | (750 | ) |  | $37.64
Outstanding at December 31, 2010 |  |  | 2,069,275 |  |  | $34.99

The per share weighted average fair value of restricted stock grants in 2008, 2009 and 2010 was $44.31, $36.80 and $25.61, respectively. Total unrecognized compensation cost related to unvested restricted stock of $37.2 million as of December 31, 2010 is expected to be recognized over a period of 2.7 years. The fair value of restricted stock which vested in 2008, 2009 and 2010 was $6.9 million, $9.4 million and $15.1 million, respectively.

(8) | Retirement Plan

The Company has a 401(k) profit sharing plan which covers all of its employees. At its discretion, Comstock may match a certain percentage of the employees’ contributions to the plan. Matching contributions to the plan were $302,000, $358,000 and $341,000 for the years ended December 31, 2008, 2009 and 2010, respectively.

(9) | Income Taxes

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

|  | 2008 |  |  | 2009 |  |  | 2010 |
|  | (In thousands) |
Current |  | $ | (5,009 | ) |  | $ | (41,568 | ) |  | $ | (229 | )
Deferred |  |  | 43,620 |  |  |  | 30,796 |  |  |  | (4,617 | )
|  | $ | 38,611 |  |  | $ | (10,772 | ) |  | $ | (4,846 | )

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

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COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
enacted tax rates. 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:

|  | 2008 |  |  | 2009 |  |  | 2010 |
|  | (In thousands) |
Tax expense (benefit) at statutory rate |  | $ | 33,890 |  |  | $ | (16,535 | ) |  | $ | (8,551 | )
Tax effect of: |  |  |  |  |  |  |  |  |  |  |  |
Nondeductible compensation |  |  | 3,536 |  |  |  | 4,339 |  |  |  | 4,253 |
State taxes, net of federal tax benefit |  |  | 1,639 |  |  |  | 441 |  |  |  | (343 | )
Net operating loss carryback adjustments |  |  | — |  |  |  | — |  |  |  | (369 | )
Other |  |  | (454 | ) |  |  | 983 |  |  |  | 164 |
Total |  | $ | 38,611 |  |  | $ | (10,772 | ) |  | $ | (4,846 | )

|  | 2008 |  |  | 2009 |  |  | 2010 |
Statutory rate |  |  | 35.0 | % |  |  | 35.0 | % |  |  | 35.0 | %
Tax effect of: |  |  |  |  |  |  |  |  |  |  |  |
Nondeductible compensation |  |  | 3.7 |  |  |  | (9.2 | ) |  |  | (17.4 | )
State taxes, net of federal tax benefit |  |  | 1.7 |  |  |  | (0.9 | ) |  |  | 1.4 |
Net operating loss carryback adjustments |  |  | — |  |  |  | — |  |  |  | 1.5 |
Other |  |  | (0.5 | ) |  |  | (2.1 | ) |  |  | (0.7 | )
Effective tax rate |  |  | 39.9 | % |  |  | 22.8 | % |  |  | 19.8 | %

The tax effects of significant temporary differences representing the net deferred tax asset and liability at December 31, 2009 and 2010 were as follows:

|  | 2009 |  |  | 2010 |
|  | (In thousands) |
Current deferred tax assets (liabilities): |  |  |  |  |  |  |  |
Marketable securities |  | $ | (6,588 | ) |  | $ | (10,339 | )
Net current deferred tax asset (liability) |  |  | (6,588 | ) |  |  | (10,339 | )
Noncurrent deferred tax assets (liabilities): |  |  |  |  |  |  |  |
Property and equipment |  |  | (295,089 | ) |  |  | (249,429 | )
Other assets |  |  | 6,417 |  |  |  | 7,910 |
Net operating loss carryforwards |  |  | 33,840 |  |  |  | 36,062 |
Alternative minimum tax carryforward |  |  | 58,032 |  |  |  | 18,916 |
Valuation allowance on net operating loss carryforwards |  |  | (19,767 | ) |  |  | (27,125 | )
Other |  |  | (4,115 | ) |  |  | (4,327 | )
Net noncurrent deferred tax liability |  |  | (220,682 | ) |  |  | (217,993 | )
Net deferred tax liability |  | $ | (227,270 | ) |  | $ | (228,332 | )

At December 31, 2010, Comstock had the following carryforwards available to reduce future income taxes:

|  | Years of |  |  |
|  | Expiration |  |  |
Types of Carryforward |  | Carryforward |  | Amounts |
|  |  |  | (In thousands) |
Net operating loss — U.S. federal |  | 2017 — 2030 |  | $ | 41,206 |
Net operating loss — Louisiana |  | 2010 — 2025 |  | $ | 416,156 |
Alternative minimum tax credits |  | Unlimited |  | $ | 18,916 |

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COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The utilization 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, 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. Realization of the U.S. federal net operating loss carryforwards requires Comstock to generate taxable income within the carryforward period. A valuation allowance with a tax effect of $19.1 million has been established against the Louisiana state net operating loss carryforwards due to the uncertainty of generating taxable income in the state of Louisiana prior to the expiration of the carryforward period.
The Company’s federal income tax returns for the years subsequent to December 31, 2007 remain subject to examination. The Company’s income tax returns in major state income tax jurisdictions remain subject to examination for various periods subsequent to December 31, 2005. State tax returns in one state jurisdiction are currently under review. The Company currently believes that resolution of this matter 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) | Derivatives 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.
In January 2008, Comstock entered into natural gas swaps to fix the price at $8.00 per Mmbtu (at the Houston Ship Channel) for 520,000 Mmbtu’s per month of production from certain properties in South Texas for the period February 2008 through December 2009. The Company designated these swaps at their inception as cash flow hedges. Realized gains and losses were included in oil and natural gas sales in the month of production. Changes in the fair value of derivative instruments designated as cash flow hedges to the extent they were effective in offsetting cash flows attributable to the hedged risk were recorded in other comprehensive income until the hedged item was recognized in earnings. Changes in fair value resulting from ineffectiveness was recognized currently in oil and natural gas sales as unrealized gains (losses). The Company realized losses of $4.8 million and gains of $26.3 million on the natural gas price swaps settled during 2008 and 2009, respectively, which are included in oil and gas sales in the accompanying consolidated statements of operations. As of December 31, 2009 and December 31, 2010, the Company had no derivative financial instruments outstanding.

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COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(11) | Supplementary Quarterly Financial Data (Unaudited)

|  | 2009 |
|  | First |  |  | Second |  |  | Third |  |  | Fourth |  |  | Total |
|  | (In thousands, except per share data) |
Total oil and gas sales |  | $ | 68,351 |  |  | $ | 64,875 |  |  | $ | 67,436 |  |  | $ | 91,921 |  |  | $ | 292,583 |
Loss from operations |  | $ | (5,712 | ) |  | $ | (12,588 | ) |  | $ | (11,547 | ) |  | $ | (1,688 | ) |  | $ | (31,535 | )
Net loss |  | $ | (5,657 | ) |  | $ | (11,475 | ) |  | $ | (12,572 | ) |  | $ | (6,767 | ) |  | $ | (36,471 | )
Net loss per share: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Basic |  | $ | (0.12 | ) |  | $ | (0.26 | ) |  | $ | (0.28 | ) |  | $ | (0.15 | ) |  | $ | (0.81 | )
Diluted |  | $ | (0.12 | ) |  | $ | (0.26 | ) |  | $ | (0.28 | ) |  | $ | (0.15 | ) |  | $ | (0.81 | )

|  | 2010 |
|  | First |  |  | Second |  |  | Third |  |  | Fourth |  |  | Total |
|  | (In thousands, except per share data) |
Total oil and gas sales |  | $ | 106,089 |  |  | $ | 90,682 |  |  | $ | 79,720 |  |  | $ | 72,650 |  |  | $ | 349,141 |
Income (loss) from operations |  | $ | 15,188 |  |  | $ | 123 |  |  | $ | 2,095 |  |  | $ | (29,410 | ) |  | $ | (12,004 | )
Net income (loss) |  | $ | 7,342 |  |  | $ | (1,619 | ) |  | $ | (4,700 | ) |  | $ | (20,609 | ) |  | $ | (19,586 | )
Net income (loss) per share: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Basic |  | $ | 0.16 |  |  | $ | (0.04 | ) |  | $ | (0.10 | ) |  | $ | (0.45 | ) |  | $ | (0.43 | )
Diluted |  | $ | 0.16 |  |  | $ | (0.04 | ) |  | $ | (0.10 | ) |  | $ | (0.45 | ) |  | $ | (0.43 | )

Results of operations for the second and fourth quarters of 2010 included gains on sales of marketable securities of $5.7 million and $10.8 million, respectively. Results for the fourth quarter of 2010 included a loss on sale of oil and gas properties of $25.8 million.
With the exception of the first quarter of 2010, basic and diluted per share amounts are the same for all periods presented due to the net loss reported during each of these periods.

(12) | Oil and Gas Reserves Information (Unaudited)

Set forth below is a summary of the changes in Comstock’s net quantities of crude oil and natural gas reserves for each of the three years ended December 31, 2010:

|  | 2008 |  |  | 2009 |  |  | 2010 |
|  |  |  |  | Natural |  |  |  |  |  | Natural |  |  |  |  |  | Natural |
|  | Oil |  |  | Gas |  |  | Oil |  |  | Gas |  |  | Oil |  |  | Gas |
|  | (MBbls) |  |  | (MMcf) |  |  | (MBbls) |  |  | (MMcf) |  |  | (MBbls) |  |  | (MMcf) |
Proved Reserves: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Beginning of year |  |  | 10,510 |  |  |  | 587,718 |  |  |  | 9,668 |  |  |  | 523,643 |  |  |  | 7,214 |  |  |  | 682,389 |
Revisions of previous estimates |  |  | 551 |  |  |  | (56,153 | ) |  |  | (1,590 | ) |  |  | (130,224 | ) |  |  | 351 |  |  |  | (6,137 | )
Extensions and discoveries |  |  | 528 |  |  |  | 99,232 |  |  |  | 19 |  |  |  | 349,920 |  |  |  | 1,484 |  |  |  | 421,657 |
Sales of minerals in place |  |  | (912 | ) |  |  | (53,287 | ) |  |  | (108 | ) |  |  | (130 | ) |  |  | (4,115 | ) |  |  | (3,303 | )
Production |  |  | (1,009 | ) |  |  | (53,867 | ) |  |  | (775 | ) |  |  | (60,820 | ) |  |  | (715 | ) |  |  | (68,973 | )
End of year |  |  | 9,668 |  |  |  | 523,643 |  |  |  | 7,214 |  |  |  | 682,389 |  |  |  | 4,219 |  |  |  | 1,025,633 |
Proved Developed Reserves: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Beginning of year |  |  | 7,449 |  |  |  | 370,339 |  |  |  | 5,446 |  |  |  | 354,934 |  |  |  | 4,894 |  |  |  | 367,102 |
End of year |  |  | 5,446 |  |  |  | 354,934 |  |  |  | 4,894 |  |  |  | 367,102 |  |  |  | 2,961 |  |  |  | 506,809 |

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COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The proved oil and gas reserves utilized in the preparation of the financial statements were estimated by independent petroleum consultants of Lee Keeling and Associates in accordance with guidelines established by the Securities and Exchange Commission and the FASB, 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, 2009 and 2010:

|  | 2009 |  |  | 2010 |
|  | (In thousands) |
Cash Flows Relating to Proved Reserves: |  |  |  |  |  |  |  |
Future Cash Flows |  | $ | 2,774,542 |  |  | $ | 4,584,382 |
Future Costs: |  |  |  |  |  |  |  |
Production |  |  | (1,091,305 | ) |  |  | (1,625,133 | )
Development and Abandonment |  |  | (725,795 | ) |  |  | (1,350,391 | )
Future Income Taxes |  |  | (99,572 | ) |  |  | (386,919 | )
Future Net Cash Flows |  |  | 857,870 |  |  |  | 1,221,939 |
10% Discount Factor |  |  | (431,280 | ) |  |  | (615,803 | )
Standardized Measure of Discounted Future Net Cash Flows |  | $ | 426,590 |  |  | $ | 606,136 |

New rules issued by the Securities and Exchange Commission relating to the estimation and disclosure of oil and natural gas reserves were adopted in 2009. The standardized measure of discounted future net cash flows at the end of 2009 and 2010 was determined based on the simple average of the first of month market prices for oil and natural gas for each year. Prices were $49.60 per barrel of oil and $3.54 per Mcf of natural gas for 2009 and $76.31 per barrel of oil and $4.16 per Mcf of natural gas for 2010.
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.

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##### Table of Contents

COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
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, 2008, 2009 and 2010:

|  | 2008 |  |  | 2009 |  |  | 2010 |
|  |  |  |  | (In thousands) |  |  |  |
Standardized Measure, Beginning of Year |  | $ | 1,162,548 |  |  | $ | 636,291 |  |  | $ | 426,590 |
Net Change in Sales Price, Net of Production Costs |  |  | (594,456 | ) |  |  | (436,544 | ) |  |  | 141,570 |
Development Costs Incurred During the Year Which Were Previously Estimated |  |  | 165,036 |  |  |  | 49,029 |  |  |  | 69,216 |
Revisions of Quantity Estimates |  |  | (90,587 | ) |  |  | (176,742 | ) |  |  | (5,433 | )
Accretion of Discount |  |  | 157,781 |  |  |  | 82,011 |  |  |  | 48,911 |
Changes in Future Development and Abandonment Costs |  |  | (32,538 | ) |  |  | 144,388 |  |  |  | (15,201 | )
Changes in Timing |  |  | 83,223 |  |  |  | 52,762 |  |  |  | 66,657 |
Extensions and Discoveries |  |  | 157,529 |  |  |  | 177,264 |  |  |  | 321,909 |
Sales of Reserves in Place |  |  | (126,666 | ) |  |  | (1,480 | ) |  |  | (50,651 | )
Sales, Net of Production Costs |  |  | (477,019 | ) |  |  | (221,684 | ) |  |  | (268,466 | )
Net Changes in Income Taxes |  |  | 231,440 |  |  |  | 121,295 |  |  |  | (128,966 | )
Standardized Measure, End of Year |  | $ | 636,291 |  |  | $ | 426,590 |  |  | $ | 606,136 |

F-25