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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, 2007    
    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   (I.R.S. Employer
incorporation or organization)   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
Preferred Stock Purchase Rights   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 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. 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
(Do not check if a smaller reporting company)
  Smaller reporting company o
 
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 28, 2008, there were 45,511,845 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 the Common Stock on the New York Stock Exchange on June 29, 2007 (the last business day of the registrant’s most recently completed second fiscal quarter), was $1.3 billion.
 
DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Proxy Statement for the 2008 Annual Meeting of Stockholders to be held
May 13, 2008 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, 2007
 
CONTENTS
 
             
Item
      Page
 
    Cautionary Note Regarding Forwarding Looking Statements     3  
    Definitions     4  
  Business and Properties     7  
1A.
  Risk Factors     28  
1B.
  Unresolved Staff Comments     37  
3.
  Legal Proceedings     37  
4.
  Submission of Matters to a Vote of Security Holders     37  
 
Part II
5.
  Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities     38  
6.
  Selected Financial Data     39  
7.
  Management’s Discussion and Analysis of Financial Condition and Results of Operations     40  
7A.
  Quantitative and Qualitative Disclosures About Market Risk     52  
8.
  Financial Statements and Supplementary Data     53  
9.
  Changes in and Disagreements with Accountants on Accounting and Financial Disclosure     53  
9A.
  Controls and Procedures     53  
9B.
  Other Information     56  
 
Part III
10.
  Directors and Executive Officers of the Registrant     56  
11.
  Executive Compensation     56  
12.
  Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters     56  
13.
  Certain Relationships, Related Transactions, and Director Independence     56  
14.
  Principal Accountant Fees and Services     56  
 
Part IV
15.
  Exhibits and Financial Statement Schedules     57  
 Waiver and Borrowing Base Redetermination Agreement
 Subsidiares of the Company
 Consent of Ernst & Young LLP
 Consent of Independent Petroleum Engineers
 Chief Executive Officer Certification under Section 302
 Chief Financial Officer Certification under Section 302
 Chief Executive Officer Certification under Section 906
 Chief Financial Officer Certification under Section 906


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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 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.
 
“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.
 
“Operator” means the individual or company responsible for the exploration, development, and production of an oil or gas well or lease.


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“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 should estimates for proved undeveloped reserves be 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.
 
“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.


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“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
 
Comstock Resources, Inc. (“Comstock”) is a Nevada corporation whose common stock is listed and traded on the New York Stock Exchange and is engaged in the acquisition, development, production and exploration of oil and natural gas.
 
Our oil and gas operations are concentrated onshore in the East Texas/North Louisiana and South Texas regions and offshore in state and federal waters of the Gulf of Mexico. Our offshore operations are conducted exclusively through Bois d’Arc Energy, Inc. (“Bois d’Arc Energy”), a separate publicly-held company. Combined with the ownership by members of our Board of Directors, we own a controlling interest in the common stock of Bois d’Arc Energy and are consolidating the results of Bois d’Arc Energy. Our oil and natural gas properties are estimated to have proved reserves of 1,048.7 Bcfe with an estimated PV 10 Value of $3.8 billion as of December 31, 2007 and a standardized measure of discounted future net cash flows of $2.9 billion. Our consolidated proved oil and natural gas reserve base is 80% natural gas and 68% proved developed on a Bcfe basis as of December 31, 2007.
 
Our proved reserves at December 31, 2007 and our 2007 average daily production are summarized below:
 
                                                                 
    Reserves at December 31, 2007     2007 Daily Production  
    Oil
    Gas
    Total
    % of
    Oil
    Gas
    Total
    % of
 
    (MMBbls)     (Bcf)     (Bcfe)     Total     (MBbls/d)     (MMcf/d)     (MMcfe/d)     Total  
 
East Texas / North Louisiana
      1.8       312.5       323.4        30.8         0.4        66.9        69.5        29.0  
South Texas
    2.9       227.3       244.9       23.4       0.6       32.3       35.8       14.9  
Other Regions
    5.8       48.0       82.5       7.9       1.7       8.3       18.7       7.8  
                                                                 
Total Onshore
    10.5       587.8       650.8       62.1       2.7       107.5       124.0       51.7  
Offshore (Bois d’Arc Energy)
    24.6       250.1       397.9       37.9       4.6       88.2       115.7       48.3  
                                                                 
Total
    35.1       837.9       1,048.7       100.0       7.3       195.7       239.7       100.0  
                                                                 
 
Strengths
 
High Quality Properties.  Our onshore operations, which comprise 62% of our total proved reserves, are focused in two primary operating areas, the East Texas/North Louisiana and South Texas regions. Our onshore properties have an average reserve life of approximately 14.4 years and have extensive development and exploration potential. Our offshore reserves, which represent approximately 38% of our total proved reserves, are located in the outer continental shelf of the Gulf of Mexico and include properties located in Louisiana state and federal waters. These offshore reserves have an average reserve life of 9.4 years.
 
Successful Exploration and Development Program.  In 2007 we spent $541.3 million on exploration and development of our oil and natural gas properties. We drilled 180 wells in 2007, 138.2 net to us, at a cost of $452.3 million. In 2007 we also spent $89.0 million for leasehold costs, recompletions, workovers, abandonment and production facilities. Our drilling activities in 2007 added 143 Bcfe to our proved reserves and accounted for substantially all of our production growth.
 
Successful Acquisitions.  We have had significant growth over the years as a result of acquisitions. Since 1991, we have added 991 Bcfe of proved oil and natural gas reserves from 37 acquisitions at an average cost of $1.15 per Mcfe. In 2007 we acquired 79 Bcfe of proved oil and natural gas reserves for $191.3 million. Our application of strict economic and reserve risk criteria have enabled us to successfully evaluate and integrate acquisitions.


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Efficient Operator.  We operate 84% of our proved oil and natural gas reserve base as of December 31, 2007. This allows us 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.
 
Business Strategy
 
Acquire High Quality Properties at Attractive Costs.  We have a successful track record of increasing our oil and natural gas reserves through opportunistic acquisitions. Since 1991, we have added 991 Bcfe of proved oil and natural gas reserves from 37 acquisitions at a total cost of $1.1 billion, or $1.15 per Mcfe. The acquisitions were acquired at an average of 67% of their PV 10 Value in the year the acquisitions were completed. In 2007 we acquired 79 Bcfe of proved oil and natural gas reserves for $191.3 million or $2.41 per Mcfe. The PV 10 Value of the acquired reserves in 2007 was $220.4 million. We apply strict economic and reserve risk criteria in evaluating acquisitions. 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.
 
Exploit Existing Reserves.  We seek to maximize the value of our oil and natural gas properties by increasing production and recoverable reserves through active 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 2007, we spent approximately $348.8 million to drill 168 development wells, 130.5 net to us, all but six of which were successful. In addition, we spent approximately $89.0 million for leasehold costs, recompletions, workover activities and facilities. We have budgeted $239.0 million for development drilling and for recompletion and workover activities in 2008 on our onshore properties. We also plan to spend approximately $82.0 million in 2008 for development drilling, recompletions, workover activities and production facilities on our offshore properties.
 
Pursue Exploration Opportunities.  We conduct exploration activities to grow our reserve base and to replace our production each year. Most of our exploration efforts are conducted through Bois d’Arc Energy. Bois d’Arc Energy’s 2008 budget includes $144.0 million to drill thirteen offshore exploratory wells. We have also budgeted $37.0 million for onshore exploration in 2008 in our South Texas region.
 
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. Consequently, we have a significant degree of flexibility to adjust the level of such expenditures according to market conditions. We anticipate spending approximately $526.0 million on our development and exploration projects in 2008. We intend to primarily use operating cash flow to fund our development and exploration expenditures in 2008 and to a lesser extent borrowings under our bank credit facilities. We may also make additional property acquisitions in 2008 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.


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Primary Operating Areas
 
The following table summarizes the estimated proved oil and natural gas reserves for our twenty largest onshore field areas and our five largest offshore operating areas as of December 31, 2007:
 
                                                 
    Net Oil
    Net Gas
                         
    (MBbls)     (MMcf)     MMcfe     %     PV 10 Value(1)     %  
 
East Texas / North Louisiana
                                               
Beckville
    109       67,510       68,165       10.5     $ 181,757       11.5  
Logansport
    130       54,908       55,688       8.6       87,680       5.6  
Waskom
    459       38,380       41,131       6.3       65,225       4.1  
Blocker
    95       30,392       30,961       4.8       58,439       3.7  
Gilmer
    93       28,446       29,002       4.5       52,564       3.3  
Hico-Knowles
    535       16,780       19,990       3.1       56,201       3.6  
Darco
    52       16,124       16,437       2.5       29,431       1.9  
Cadeville
    67       15,209       15,612       2.4       34,251       2.2  
Douglass
    6       15,508       15,542       2.4       27,791       1.8  
Other
    266       29,176       30,772       4.6       71,805       4.5  
                                                 
      1,812       312,433       323,300       49.7       665,144       42.2  
                                                 
South Texas
                                               
Double A Wells
    1,614       46,867       56,553       8.7       182,429       11.6  
Las Hermanitas
          35,464       35,464       5.4       83,672       5.3  
Fandango
          34,443       34,443       5.3       102,149       6.5  
Rosita
          32,589       32,589       5.0       70,445       4.5  
Javelina
    140       29,466       30,304       4.7       75,559       4.8  
J.C. Martin
          12,980       12,980       2.0       29,109       1.8  
Markham
    180       8,883       9,966       1.5       25,236       1.6  
Sugar Creek
    101       8,275       8,878       1.4       11,236       0.7  
Other
    900       18,353       23,754       3.6       83,389       5.2  
                                                 
      2,935       227,320       244,931       37.6       663,224       42.0  
                                                 
Other Onshore
                                               
Laurel
    5,386       23       32,338       5.0       143,388       9.1  
San Juan
    31       12,451       12,636       1.9       27,222       1.7  
Kentucky
          8,862       8,862       1.4       6,104       0.4  
Other
    346       26,629       28,708       4.4       72,724       4.6  
                                                 
      5,763       47,965       82,544       12.7       249,438       15.8  
                                                 
Total Onshore
    10,510       587,718       650,775       100.0       1,577,806       100.0  
                                                 
Offshore
                                               
Ship Shoal 111 and the Ship Shoal 113 Unit
    13,495       97,629       178,598       45.0       1,000,578       46.0  
South Pelto 5, South Timbalier 9, 11 and 16
    833       28,216       33,215       8.0       174,915       8.0  
South Pelto 22
    1,125       19,782       26,532       7.0       165,702       8.0  
Ship Shoal 66, 67, 68, 69 and South Pelto 1
    3,217       6,685       25,985       7.0       165,840       8.0  
Ship Shoal 97, 98, 99, 106, 107, 109, and 110
    389       23,447       25,779       6.0       112,296       5.0  
Other Offshore
    5,573       74,375       107,816       27.0       577,217       25.0  
                                                 
Total Offshore(2)
    24,632       250,134       397,925       100.0       2,196,548       100.0  
                                                 
Total Consolidated
    35,142       837,852       1,048,700               3,774,354          
                                                 
Discounted Future Income Taxes
    (830,517 )        
                 
Standardized Measure of Discounted Future Cash Flows
  $ 2,943,837          
                 
 
(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%.
(2) The reserves attributed to the minority interest ownership in Bois d’Arc Energy were 12,558 MBbls of oil and 127,522 MMcf of natural gas or 202,867 MMcfe of natural gas equivalent with a PV10 value of $1,119.8 million and a standardized measure of future net cash flows of $908.1 million.


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East Texas/North Louisiana
 
Approximately 50% or 323.3 Bcfe of our onshore proved reserves are located in East Texas and North Louisiana where we own interests in 881 producing wells, 503.6 net to us, in 31 field areas. We operate 539 of these wells. The largest of our fields in this region are the Beckville, Logansport, Waskom, Blocker, Gilmer, Hico-Knowles, Darco, Cadeville and Douglass fields. Production from this region averaged 66.9 MMcf of natural gas per day and 443 barrels of oil per day during 2007. Most of the reserves in this area produce from the Cretaceous aged Travis Peak/Hosston formation and the Jurassic aged Cotton Valley formation. The total thickness of these formations range from 2,000 to 4,000 feet of sand, shale and limestone sequences in the East Texas Basin and the North Louisiana Salt Basin, at depths ranging from 6,000 to 12,000 feet. In 2007, we spent $215.6 million drilling 128 wells, 100.2 net to us, and $6.0 million on leasehold costs, workovers and recompletions in this region. We plan to spend approximately $149.0 million in 2008 for development activities in this region.
 
Beckville
 
The Beckville field, located in Panola and Rusk Counties, Texas, is our largest field area in this region with total estimated proved reserves of 68.2 Bcfe which represents approximately 11% of our onshore reserves. We operate 191 wells in this field and own interests in 92 additional wells for a total of 283 wells, 160.0 net to us. During December 2007, production attributable to our interest from this field averaged 18 MMcf of natural gas per day and 100 barrels of oil per day. The Beckville field produces from the Cotton Valley formation at depths ranging from 9,000 to 10,000 feet.
 
Logansport
 
The Logansport field produces from multiple sands in the Hosston formation at an average depth of 8,000 feet and is located in DeSoto Parish, Louisiana. Our proved reserves of 55.7 Bcfe in the Logansport field represent approximately 9% of our onshore reserves. We own interests in 122 wells, 70.5 net to us, and operate 79 of these wells. During December 2007, net daily production attributable to our interest from this field averaged 13 MMcf of natural gas and 15 barrels of oil.
 
Waskom
 
The Waskom field, located in Harrison and Panola Counties in Texas, represents approximately 6% (41.1 Bcfe) of our onshore proved reserves as of December 31, 2007. We own interests in 75 wells in this field, 43.8 net to us, and operate 50 wells in this field. During December 2007, net daily production attributable to our interest averaged 7 MMcf of natural gas and 90 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. During the fourth quarter of 2007, we drilled our first successful horizontal Cotton Valley well in the Waskom field in East Texas. This well was drilled to a total vertical depth of 9,490 feet with a 2,548 foot horizontal leg drilled through the upper and lower Taylor Cotton Valley sands and was successfully completed with a seven stage frac.
 
Blocker
 
Our proved reserves of 31.0 Bcfe in the Blocker field located in Harrison County, Texas represent approximately 5% of our onshore reserves. We own interests in 69 wells, 65.9 net to us, and operate 64 of these wells. During December 2007, net daily production attributable to our interest from this field averaged 7 MMcf of natural gas and 45 barrels of oil. Most of this production is from the Cotton Valley formation between 8,500 and 10,100 feet.


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Gilmer
 
We own interests in 74 natural gas wells, 28.1 net to us, in the Gilmer field in Upshur County in East Texas. These wells produce primarily from the Cotton Valley Lime formation at a depth of approximately 11,500 to 12,000 feet. Proved reserves attributable to our interests in the Gilmer field are 29.0 Bcfe which represents 5% of our onshore reserve base. During December 2007, production attributable to our interest from this field averaged 5 MMcf of natural gas per day and 55 barrels of oil per day.
 
Hico-Knowles
 
Our proved reserves of 20.0 Bcfe in the Hico-Knowles field located in Lincoln County, Louisiana represent approximately 3% of our onshore reserves. We own interests in 24 wells, 11.7 net to us, and operate twelve of these wells. During December 2007, net daily production attributable to our interest from this field averaged 3 MMcf of natural gas and 10 barrels of oil. This production is primarily from the Hosston/Cotton Valley formations between 7,200 and 11,000 feet.
 
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 16.4 Bcfe in the Darco Field represent approximately 3% of our onshore reserves. We own interests in 22 wells, 17.3 net to us, and operate all of these wells. During December 2007, net daily production attributable to our interest from this field averaged 2 MMcf of natural gas and 15 barrels of oil.
 
Cadeville
 
Our proved reserves of 15.6 Bcfe in the Cadeville field located in Ouachita Parrish, Louisiana represent approximately 2% of our onshore reserves. We own interests in 7 wells, 3.8 net to us, and operate 5 of these wells. During December 2007, net daily production attributable to our interest from this field averaged 1 MMcf of natural gas and 4 barrels of oil. This production is primarily from the Cotton Valley formation between 9,800 and 10,700 feet.
 
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 15.5 Bcfe in the Douglass field represent approximately 2% of our onshore reserves. We own interests in 39 wells, 24.7 net to us, and operate 31 of these wells. During December 2007, net daily production attributable to our interest from this field averaged 4 MMcf of natural gas.
 
South Texas
 
Approximately 38%, or 245.0 Bcfe, of our onshore proved reserves are located in South Texas, where we own interests in 461 producing wells, 176.6 net to us. We own interests in fifteen field areas in the region, the largest of which are the Double A Wells, Las Hermanitas, Fandango, Rosita, Javelina, J.C. Martin, Markham and Sugar Creek fields. Net daily production rates from the area averaged 32.3 MMcf of natural gas and 588 barrels of oil during 2007, excluding the properties we acquired in this region in late December, 2007 which were producing 20.7 MMcf of natural gas per day in December 2007. We spent $79.7 million in this region in 2007 to drill 22 wells, 14.2 net to us, and for other development activity. During 2007 we also spent $31.2 million to acquire additional working interests in the Javelina field and $160.1 million to


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acquire producing properties in the Fandango, Rosita and Dinn Ranch fields. In 2008, we plan to spend approximately $122.0 million for development and exploration activity in this region.
 
Double A Wells
 
Our properties in the Double A Wells field have proved reserves of 56.6 Bcfe, which represent 9% of our onshore reserves. We own interests in 62 wells and operate 61 producing wells, 29.7 net to us, in this field in Polk County, Texas. Net daily production from the Double A Wells area averaged 8.4 MMcf of natural gas and 290 barrels of oil during December 2007. These wells produce from the Woodbine formation at an average depth of 14,300 feet.
 
Las Hermanitas
 
We own interests in twelve natural gas wells, 12.0 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 35.5 Bcfe in this field represent approximately 5% of our onshore reserves. During December 2007, net daily production attributable to our interest from this field averaged 11.2 MMcf of natural gas.
 
Fandango
 
We acquired interests in 18 natural gas wells, 18.0 net to us, in the Fandango field, located in Zapata County, Texas in December 2007. 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 34.4 Bcfe in this field represent approximately 5% of our onshore reserves. Production from this field averaged 13.5 MMcf of natural gas per day during December 2007.
 
Rosita
 
We acquired interests in 31 natural gas wells, 17.0 net to us, in the Rosita field, located in Duval County, Texas in December 2007. We operate three of these wells which produce from the Wilcox formation at depths from approximately 9,300 to 17,000 feet. Our proved reserves of 32.6 Bcfe in this field represent approximately 5% of our onshore reserves. Production from this field averaged 6.5 MMcf of natural gas per day during December 2007.
 
Javelina
 
We own interests in 11 natural gas wells and 1 oil well, 12 net to us, in the Javelina field in Hidalgo County in South Texas. During 2007 we acquired additional working interests in 9 wells (4.5 net) and drilled an additional 3 (3.0 net) wells in this field. 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 30.3 Bcfe, which represents 5% of our onshore reserve base. During December 2007, production attributable to our interest from this field averaged 10 MMcf of natural gas per day and 55 barrels of oil per day.
 
J.C. Martin
 
The J.C. Martin field is located in the Wilcox Lobo trend in Zapata County, Texas on the Mexico border. This field produces primarily from Eocene Wilcox Lobo sands at depths ranging from 7,000 to 9,000 feet. The Lobo section is characterized by geopressured, multiple pay sands occurring in a highly faulted area. We own interests in 90 wells in this field, 14.4 net to us, with proved reserves of 13.0 Bcfe or


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2% of our onshore reserves. During December 2007, net daily production attributable to our interest from this field averaged 2.5 MMcf of natural gas.
 
Markham
 
The Markham field is located in Matagorda County, Texas. We own interests in and operate 22 producing wells, 22.0 net to us, in the Ohio-Sun Unit. The field’s estimated proved reserves of 10.0 Bcfe represent 2% of our onshore reserves. The field’s active wells produce from more than twenty reservoirs of Oligocene Frio age at depths ranging from 6,500 to 9,000 feet. During December 2007, net daily production attributable to our interests from this field average 35 barrels of oil and 0.1 MMcf of natural gas per day.
 
Sugar Creek
 
Our proved reserves of 8.9 Bcfe in the Sugar Creek field located in Tyler County, Texas represent approximately 1% of our onshore reserves. We own interests in 4 wells, 2.6 net to us, and operate 2 of these wells. During December 2007, net daily production attributable to our interest from this field averaged 0.4 MMcf of natural gas and 6 barrels of oil.
 
Other Onshore
 
Approximately 13%, or 82.5 Bcfe, of our onshore proved reserves are in various other areas, primarily in Mississippi, New Mexico, Kentucky and the Mid-Continent region. Within these areas we own interests in 522 producing wells, 235.8 net to us in 24 fields. Fields with the largest proved reserves in these areas include the Laurel field in Laurel, Mississippi, our San Juan Basin properties in New Mexico and our New Albany Shale Gas properties in Kentucky. Net daily production from our other onshore fields totaled 8.3 MMcf of natural gas and 1,732 barrels of oil during 2007. We drilled fifteen wells, 11.8 net to us on these properties in 2007. In 2008, we plan to spend approximately $5.0 million for development and exploration activity on these properties.
 
Laurel
 
The Laurel field is located in Jones County, Mississippi near a structurally complex salt dome. We own interests in and operate 61 producing wells, 58.1 net to us, in the Laurel field. This field’s estimated proved reserves of 32.3 Bcfe represent 5% of our onshore reserves. The field produces from more than 42 horizons that range in depth from 6,600 feet in the Stanley Sand to 13,100 feet in the Middle Hosston formation. Recovery of low viscosity crude oil from this field is being enhanced through waterflood operations. During December 2007, net daily production attributable to our interests in this field averaged 1,439 barrels of oil 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 12.6 Bcfe in the San Juan field represent approximately 2% of our onshore reserves. We own interests in 95 wells, 13.9 net to us. During December 2007, net daily production attributable to our interest from this field averaged 1.2 MMcf of natural gas and 3 barrels of oil.


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Kentucky
 
Our New Albany Shale Gas properties are located in north-central Kentucky immediately north of the regionally extensive Rough Creek Fault Zone. Gas is produced from fractured Devonian New Albany Shale. The New Albany is generally about 100 feet in thickness and is found at approximately 850 feet from the surface. Our proved reserves of 8.9 Bcfe in the New Albany Shale Gas field represent approximately 1% of our onshore reserves. We own interests in and operate 92 wells, 82.5 net to us in this area. During December 2007, net daily production attributable to our interest from this field averaged 0.8 MMcf of natural gas.
 
Offshore Gulf of Mexico
 
Prior to July 2004, substantially all of our exploration activities in the Gulf of Mexico were conducted under a joint exploration venture with Bois d’Arc Offshore, Ltd. and its principals, which we collectively refer to as “Bois d’Arc.” Under the exploration venture, Bois d’Arc was responsible for generating exploration prospects in the Gulf of Mexico. From 1997 when the exploration venture was commenced until July 16, 2004 when it was terminated, we participated in drilling approximately 40 exploratory wells to test prospects generated under the exploration venture. Of these exploratory wells drilled, 34 or 85% were successful discoveries. In July 2004, we together with Bois d’Arc and certain participants in their exploration activities, which are collectively referred to as the “Bois d’Arc Participants,” formed Bois d’Arc Energy, LLC to replace the joint exploration venture. We and each of the Bois d’Arc Participants contributed to Bois d’Arc Energy substantially all of our respective Gulf of Mexico related assets and assigned our related liabilities, including certain debt, in exchange for equity interests in Bois d’Arc Energy.
 
We initially owned 60% of Bois d’Arc Energy, and we accounted for our share of the Bois d’Arc Energy financial and operating results using proportionate consolidation accounting until Bois d’Arc Energy converted into a corporation and completed its initial public offering in May 2005. Subsequent to the conversion of Bois d’Arc Energy into a corporation and its public offering, we owned 48% of Bois d’Arc Energy and we changed our accounting method for our investment in Bois d’Arc Energy to the equity method through December 31, 2005. During 2006, we acquired additional shares of common stock of Bois d’Arc Energy, which increased our direct ownership interest in Bois d’Arc Energy. As a result, we obtained voting control of Bois d’Arc Energy through our direct share ownership combined with the share ownership of members of our Board of Directors. Upon obtaining voting control of Bois d’Arc Energy, we began including Bois d’Arc Energy in our financial statements as a consolidated subsidiary.
 
Bois d’Arc Energy has total proved reserves in the outer continental shelf of the Gulf of Mexico of 397.9 Bcfe, which represents approximately 38% of our total reserves. Bois d’Arc Energy owns interests in 145 gross (108.3 net) and operates 122 of these wells. Production from Bois d’Arc Energy’s properties in 2007 averaged 88.2 MMcf per day of natural gas and 4,578 barrels per day of oil for a total of 115.7 MMcfe per day. During 2007, Bois d’Arc Energy spent $89.2 million drilling seven (4.6 net) exploratory wells and $46.5 million drilling eight (7.4 net) development wells. Bois d’Arc Energy also spent $62.2 million on production facilities, recompletions, abandonments and workovers, and $9.7 million on acquiring exploration acreage and seismic data during 2007. In 2008, Bois d’Arc Energy plans to spend $250.0 million for exploration and development activities.
 
Ship Shoal 111 and the Ship Shoal 113 Unit
 
The Ship Shoal 113 unit is located in federal waters having water depths from 20 to 50 feet, offshore of Terrebonne Parish, Louisiana and is comprised of 33,125 acres of federal leases covering portions of Ship Shoal blocks 93, 94, 112, 113, 114, 117, 118, 119 and 120. This unit was discovered in the late 1940s and has had cumulative production of 951 Bcfe of natural gas. These properties have 70 productive sands occurring at depths from 2,500 to 16,000 feet. We acquired a 50% working interest in these properties in December


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2002, acquired an additional 30% working interest in October 2003 and the remaining 20% interest during 2006. We acquired the adjacent Ship Shoal block 111 in 2005 together with an existing production platform. Since 2003 we have drilled 22 wells (20.7 net to us) in this area. We operate the four production platforms and the 36 producing wells (35.7 net to us) comprising these properties. Production from these properties net to our interest averaged 22.9 MMcf of natural gas per day and 1,856 barrels of oil per day during December 2007.
 
South Pelto 5 and South Timbalier 9, 11, 16
 
We own interests in 15 producing wells, 10.6 net to us, in South Pelto block 5 and South Timbalier blocks 9, 11 and 16. These blocks are located in Louisiana state waters and in federal waters, offshore of Terrebonne Parish, Louisiana in water depths from 30 to 50 feet. These wells share common production facilities comprised of a four-pile main production platform and a tripod satellite production platform. We acquired our lease position in South Pelto block 5 and South Timbalier block 11 through a farm-in in 1998. We leased adjacent acreage in South Timbalier blocks 9, 11 and 16 from the State of Louisiana from 1998 through 2002. We have drilled 19 wells, including redrills of existing wells (13.4 net to us), in these blocks. These wells have 18 productive sands occurring at depths from 8,000 to 17,000 feet. Production from these properties net to our interest averaged 8.3 MMcf of natural gas per day and 328 barrels of oil per day during December 2007.
 
South Pelto 22
 
South Pelto block 22 is located in federal waters with depths from 50 to 60 feet, offshore of Terrebonne Parish, Louisiana. We farmed-in this acreage from another offshore operator in 2003 and have subsequently drilled four wells (2.5 net to us). These wells have 14 productive sands occurring at depths from 13,400 to 17,000 feet. Production from these properties net to our interest averaged 15.8 MMcf of natural gas per day and 370 barrels of oil per day during December 2007.
 
Ship Shoal 66, 67, 68, 69 and South Pelto 1
 
Ship Shoal blocks 66, 67, 68, 69 and South Pelto block 1 are located in Louisiana state waters and in federal waters with depths from 20 to 35 feet, offshore of Terrebonne Parish, Louisiana. These properties produce from ten sands occurring at depths from 9,000 to 13,500 feet. We own interests in 21 wells (13.3 net to us) on Louisiana state leases partially covering Ship Shoal blocks 66 and 67 and South Pelto 1, and federal leases covering Ship Shoal blocks 68 and 69. We acquired these properties in December 1997 from Bois d’Arc Resources and other interest owners. These wells are connected to four production platforms and share common oil terminal facilities. Production from these properties net to our interest averaged 406 barrels of oil per day during December 2007.
 
Ship Shoal 97, 98, 99, 107, 109 and 110
 
Ship Shoal blocks 99, 107, 109 and 110 are located in federal waters with depths from 20 to 25 feet, offshore of Terrebonne Parish, Louisiana. We acquired these leases in federal lease sales in 2000 and 2001 and subsequently drilled eleven successful wells (8.4 net to us). These wells have 15 productive sands occurring at depths from 8,800 to 12,300 feet. Production from these properties net to our interest averaged 10.4 MMcf of natural gas per day, 121 barrels of oil per day during December 2007.
 
Major Property Acquisitions
 
As a result of our acquisitions, we have added 991 Bcfe of proved oil and natural gas reserves since 1991 including 79 Bcfe we acquired in 2007.


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Our largest acquisitions are 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 (“Shell”) 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. The acquisition was funded with borrowings under our bank credit facility.
 
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. The transaction was funded with borrowings under our bank credit facility.
 
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. The transaction was funded with borrowings under our bank credit facility.
 
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, Cadeville, Douglass, and Laurel fields. The acquisition was funded with proceeds from a public stock offering completed in April 2005 and borrowings under our bank credit facility.
 
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 include 165 active wells, of which 69 are operated by us. The acquisition was funded by borrowings under our bank credit facility.
 
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 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. Major fields acquired include the Gilmer field in East Texas and the J.C. Martin field in South Texas. 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.


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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 Beckville, Logansport, 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 PV10 Value as of December 31, 2007:
 
                                 
    Oil
    Gas
    Total
    PV10 Value
 
    (MBbls)     (MMcf)     (MMcfe)     (000’s)  
 
Proved Developed:
                               
Producing
    14,535       396,697       483,908     $ 1,839,988  
Non-producing
    10,304       162,891       224,714       1,065,362  
Proved Undeveloped
    10,303       278,264       340,078       869,004  
                                 
Total Proved
    35,142       837,852       1,048,700       3,774,354  
                                 
Discounted Future Income Taxes
    (830,517 )
         
Standardized Measure of Discounted Future Net Cash Flows(1)
  $ 2,943,837  
         
 
(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%.
 
The reserves attributed to the minority interest ownership in Bois d’Arc Energy as of December 31, 2007 were 12,558 MBbls of oil and 127,522 MMcf of natural gas or 202,867 MMcfe of natural gas equivalent with a PV10 Value of $1,119.8 million and a standardized measure of future net cash flows of $908.1 million.
 
Proved oil and gas reserves are 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). 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.
 
The PV 10 Value and standardized measure of discounted future net cash flows was determined based on the market prices for oil and natural gas on December 31, 2007. The market price for our oil production on December 31, 2007, after basis adjustments, was $90.67 per barrel as compared to $56.17 per barrel on December 31, 2006. The market price received for our natural gas production on December 31, 2007, after basis adjustments, was $6.87 per Mcf as compared to $5.70 per Mcf on December 31, 2006.


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We did not provide estimates of total proved oil and natural gas reserves during the years ended December 31, 2005, 2006 or 2007 to any federal authority or agency, other than the SEC.
 
Drilling Activity Summary
 
During the three-year period ended December 31, 2007, we drilled development and exploratory wells as set forth in the table below.
 
                                                                                                                                                 
    Onshore     Offshore     Total  
    2005     2006     2007     2005     2006     2007     2005     2006     2007  
    Gross     Net     Gross     Net     Gross     Net     Gross     Net     Gross     Net     Gross     Net     Gross     Net     Gross     Net     Gross     Net  
 
Development:
                                                                                                                                               
Oil
    2       1.9       8       7.6       5       4.8       3       3.0                   4       4.0       5       4.9       8       7.6       9       8.8  
Gas
    70       46.5       105       75.9       152       115.7       6       5.2       2       1.7       1       1.0       76       51.7       107       77.6       153       116.7  
Dry
                4       2.2       3       2.6       2       2.0                   3       2.4       2       2.0       4       2.2       6       5.0  
                                                                                                                                                 
      72       48.4       117       85.7       160       123.1       11       10.2       2       1.7       8       7.4       83       58.6       119       87.4       168       130.5  
                                                                                                                                                 
Exploratory:
                                                                                                                                               
Oil
                                        2       1.5                               2       1.5                          
Gas
    1       .2       3       2.0       1       0.6       8       6.4       8       7.0       2       1.6       9       6.6       11       9.0       3       2.2  
Dry
    2       1.2       2       2.0       4       2.5       1       0.6       3       2.5       5       3.0       3       1.8       5       4.5       9       5.5  
                                                                                                                                                 
      3       1.4       5       4.0       5       3.1       11       8.5       11       9.5       7       4.6       14       9.9       16       13.5       12       7.7  
                                                                                                                                                 
Total
    75       49.8       122       89.7       165       126.2       22       18.7       13       11.2       15       12.0       97       68.5       135       100.9       180       138.2  
                                                                                                                                                 
 
In 2008 to the date of this report, we have drilled twenty-three wells, 15.3 net to us, all of which have been successful. As of the date of this report, we have seven wells, 5.3 net to us, that are in the process of drilling.
 
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, 2007:
 
                                 
    Oil     Gas  
    Gross     Net     Gross     Net  
 
Onshore:
                               
Arkansas
                15       8.0  
Kansas
                12       4.5  
Kentucky
                92       82.5  
Louisiana
    5       2.4       274       137.2  
Mississippi
    71       60.9       3       1.1  
New Mexico
                95       13.9  
Oklahoma
    3       .4       137       19.7  
Texas
    63       39.5       1,062       543.6  
Wyoming
                32       2.2  
                                 
Total Onshore
    142       103.2       1,722       812.7  
                                 
Offshore Gulf of Mexico:
                               
Louisiana
    15       13.7       9       6.4  
Federal
    46       30.5       75       57.7  
                                 
Total Offshore
    61       44.2       84       64.1  
                                 
Total
    203       147.4       1,806       876.8  
                                 


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We operate 1,014 of the 2,009 producing wells presented in the above table. As of December 31, 2007 we owned interests in 42 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.
 
Acreage
 
The following table summarizes our developed and undeveloped leasehold acreage at December 31, 2007. We have excluded acreage in which our interest is limited to a royalty or overriding royalty interest.
 
                                 
    Developed     Undeveloped  
    Gross     Net     Gross     Net  
 
Onshore:
                               
Arkansas
    1,280       684              
Kansas
    6,400       4,064              
Kentucky
    7,206       5,773       785       785  
Louisiana
    100,960       64,590       5,541       2,456  
Mississippi
    4,304       1,777       7,485       5,101  
New Mexico
    7,120       697       4,803       2,113  
Oklahoma
    38,080       5,707              
Texas
    267,652       165,552       36,298       9,083  
Wyoming
    13,440       927              
                                 
Total Onshore
    446,442       249,771       54,912       19,538  
                                 
Offshore Gulf of Mexico:
                               
Louisiana
    6,660       5,574       1,399       1,399  
Federal
    231,271       170,920       150,202       149,152  
                                 
Total Offshore
    237,931       176,494       151,601       150,551  
                                 
Total
    684,373       426,265       206,513       170,089  
                                 
 
Our offshore undeveloped acreage, which represents 89% of our total net undeveloped acreage, expires as follows:
 
         
Expires in 2008
    24 %
Expires in 2009
    28 %
Expires in 2010
    11 %
Expires in 2011
    13 %
Expires in 2012
    7 %
Expires in 2013
    10 %
Expires in 2017
    7 %
         
      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 facilities. 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 or by payment of delay rentals.


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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 at prices tied to the spot oil markets. Our natural gas production is primarily sold under short-term contracts and priced on first of the month index prices or on daily spot market prices. Approximately 65% of our 2007 natural gas sales were priced utilizing index prices and approximately 35% were priced utilizing daily spot prices. Two subsidiaries of Shell Oil Company accounted for approximately 53% of our total 2007 sales. The loss of these customers 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.
 
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.
 
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. In recent years, the FERC has undertaken various initiatives to increase competition within the natural gas industry. As a result of initiatives like FERC Order No. 636, issued in April 1992, the interstate natural gas transportation and marketing system has been substantially restructured to remove various barriers and practices that historically limited non-pipeline natural gas sellers, including producers, from effectively competing with interstate pipelines for sales to local distribution companies and large industrial and commercial customers. The most significant provisions of Order No. 636 require that interstate pipelines provide firm and interruptible transportation service on an open access basis that is equal


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for all natural gas supplies. In many instances, the results of Order No. 636 and related initiatives have been to substantially reduce or eliminate the traditional role of interstate pipelines as wholesalers of natural gas in favor of providing storage and transportation services.
 
In 2000, the FERC issued Order No. 637 and subsequent orders, which imposed additional reforms designed to enhance competition in natural gas markets. Among other things, Order No. 637 revised the FERC’s pricing policy by waiving price ceilings for short-term released capacity for an experimental period, and effected changes in the FERC regulations relating to scheduling procedures, capacity segmentation, penalties, rights of first refusal and information reporting. While most major aspects of Order No. 637 have been upheld on judicial review, certain issues such as capacity segmentation and right of first refusal are pending further consideration by the FERC. We cannot predict what action the FERC will take on these matters in the future or whether the FERC’s actions will survive further judicial review.
 
Intrastate natural gas regulation 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 than other natural gas producers with which we compete by any action taken.
 
The Outer Continental Shelf Lands Act, or “OCSLA,” which the FERC implements as to transportation and pipeline issues, requires that all pipelines operating on or across the outer continental shelf, or “OCS,” provide open access, non-discriminatory transportation service. One of FERC’s principal goals in carrying out OCSLA’s mandate is to increase transparency in the market to provide producers and shippers on the OCS with greater assurance of open access service on pipelines located on the OCS and to help ensure non-discriminatory rates and conditions of service on such pipelines.
 
Although the FERC has historically imposed light-handed regulation on offshore facilities that meet its traditional test of gathering status, it has the authority under the OCSLA to exercise jurisdiction over gathering facilities, if necessary, to permit non-discriminatory access to service. In an effort to heighten its oversight of the OCS, the FERC recently attempted to promulgate reporting requirements for all OCS “service providers,” including gatherers, but the regulations were struck down as ultra vires by a federal district court, which decision was affirmed by the U.S. Court of Appeals in October 2003. The FERC withdrew those regulations in March 2004. Subsequently, in April 2004, the Minerals Management Service, or “MMS,” initiated an inquiry into whether it should amend its regulations to assure that pipelines provide open and non-discriminatory access over OCS pipeline facilities. For those facilities transporting natural gas across the OCS that are not considered to be gathering facilities, the rates, terms and conditions applicable to this transportation are generally regulated by the FERC under the NGA and NGPA, as well as the OCSLA.
 
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 recently pursued by the FERC, Congress and state regulatory authorities will continue.
 
Federal leases.  Substantially all of our offshore operations are located on federal oil and natural gas leases that are administered by the MMS pursuant to the OCSLA. These leases are issued through competitive bidding and contain relatively standardized terms. These leases require compliance with detailed Department of Interior and MMS regulations and orders that are subject to interpretation and change.
 
For offshore operations, lessees must obtain MMS approval for exploration, development and production plans prior to the commencement of such operations. In addition to permits required from


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other agencies such as the Coast Guard, the Army Corps of Engineers and the Environmental Protection Agency, lessees must obtain a permit from the MMS prior to the commencement of drilling. The MMS has promulgated regulations requiring offshore production facilities located on the OCS to meet stringent engineering and construction specifications. The MMS also has regulations restricting the flaring or venting of natural gas, and has proposed to amend such regulations to prohibit the flaring of liquid hydrocarbons and oil without prior authorization. Similarly, the MMS has promulgated other regulations governing the plug and abandonment of wells located offshore and the installation and removal of all production facilities.
 
To cover the various obligations of lessees on the OCS, the MMS generally requires that lessees have substantial net worth or post bonds or other acceptable assurances that such obligations will be satisfied. The cost of these bonds or assurances can be substantial, and there is no assurance that they can be obtained in all cases. We are currently exempt from supplemental bonding requirements by the MMS. Under some circumstances, the MMS may require any of our operations on federal leases to be suspended or terminated. Any such suspension or termination could materially adversely affect our financial condition and results of operations.
 
The MMS also administers the collection of royalties under the terms of the OCSLA and the oil and natural gas leases issued thereunder. The amount of royalties due is based upon the terms of the oil and natural gas leases as well as the regulations promulgated by the MMS. The MMS regulations governing the calculation of royalties and the valuation of crude oil produced from federal leases currently rely on arm’s-length sales prices and spot market prices as indicators of value. Although the method of calculating royalties on production from federal leases has been the subject of much public discussion in recent years, the basis for calculating royalty payments established or to be established by the MMS is generally applicable to all federal lessees. Accordingly, we believe that the impact of royalty regulation on our operations should generally be the same as the impact on our competitors.
 
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 regulation of pipelines that transport crude oil, condensate and natural gas liquids is generally more light-handed than the FERC’s regulation of natural gas pipelines under the NGA. 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 market-based rates or negotiated settlement rates are permitted in certain circumstances. Pursuant to FERC Order No. 561, issued in October 1993, the FERC implemented regulations generally grandfathering all previously unchallenged interstate pipeline rates and made these rates subject to an indexing methodology. Under this indexing methodology, pipeline rates are subject to changes in the Producer Price Index for Finished Goods, minus one percent. A pipeline can seek to increase its rates above index levels provided that the pipeline can establish that there is a substantial divergence between the actual costs experienced by the pipeline and the rate resulting from application of the index. A pipeline can seek to charge a market-based rate if it establishes that it lacks significant market power. In addition, a pipeline can establish rates pursuant to settlement if agreed upon by all current shippers. A pipeline can seek to establish initial rates for new services through a cost-of-service proceeding, a market-based rate proceeding, or through an agreement between the pipeline and at least one shipper not affiliated with the pipeline. As provided for in Order No. 561, in July 2000, the FERC issued a Notice of Inquiry seeking comment on whether to retain or to


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change the existing oil rate-indexing method. In December 2000, the FERC issued an order concluding that the rate index reasonably estimated the actual cost changes in the pipeline industry and should be continued for another five-year period, subject to review in July 2005. In February 2003, on remand of its December 2000 order from the D.C. Circuit, the FERC increased its index slightly. A challenge to FERC’s remand order was denied by the D.C. Circuit in April 2004.
 
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 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


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property damage allegedly caused by hazardous substances or other pollutants released into the environment from a polluted site.
 
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.


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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 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 National Environmental Policy Act, the Coastal Zone Management Act, 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.
 
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 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, plug 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 43,382 square


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feet at a monthly rate of $81,341 and in Houston, Texas covering 16,285 square feet at a monthly rate of $28,600. These leases expire on July 31, 2014 and April 30, 2012, respectively. We also own production offices and pipe yard facilities near Marshall, Livingston, and Zapata, Texas; Logansport, Louisiana; Guston, Kentucky and Laurel, Mississippi.
 
Employees
 
As of December 31, 2007, we had 138 employees and utilized contract employees for certain of our field operations. We consider our employee relations to be satisfactory.
 
Directors, Executive Officers and Other Management
 
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     52  
Roland O. Burns
  Senior Vice President, Chief Financial Officer, Secretary, Treasurer and Director     47  
D. Dale Gillette
  Vice President of Land and General Counsel     62  
Mack D. Good
  Chief Operating Officer     57  
Stephen E. Neukom
  Vice President of Marketing     58  
Daniel K. Presley
  Vice President of Accounting and Controller     47  
Richard D. Singer
  Vice President of Financial Reporting     53  
David K. Lockett
  Director     53  
Cecil E. Martin, Jr. 
  Director     66  
David W. Sledge
  Director     51  
Nancy E. Underwood
  Director     56  
 
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 June 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. He received B.B.A., M.S. and J.D. degrees from Baylor University in 1978, 1980 and 1981, respectively. Mr. Allison also serves as Chairman of the board of directors of Bois d’Arc Energy, Inc. and currently serves as a Director of Tidewater Marine, Inc., on the Board of Regents for Baylor University and on the Advisory Board of the Salvation Army in Dallas, Texas.
 
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. Mr. Burns also serves as Senior Vice President, Chief Financial Officer, Secretary and a director of Bois d’Arc Energy, Inc. 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 received B.A. and M.A. degrees from the University of Mississippi in 1982 and is a Certified Public Accountant.


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D. Dale Gillette joined us as Vice President of Land and General Counsel in September 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 August 1997 until February 1999, Mr. Good served as our district engineer for the East Texas/North Louisiana region. From 1983 until July 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 December 1997 and has served as our manager of crude oil and natural gas marketing since December 1996. From October 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 December 1997 and has been with us since December 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 joined us in June 2005 as Vice President of Financial Reporting. 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 March 2004 to May 2005 and as assistant controller for Santa Fe International Corporation from July 1988 to December 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 July 2001. Mr. Lockett has been a Vice President of Dell Inc. and has managed Dell’s Small and Medium Business Group since 1996. Mr. Lockett has been employed by Dell Inc. for the last 16 years and has spent the past 26 years in the technology industry. Mr. Lockett also serves as a director of Bois d’Arc Energy, Inc. Mr. Lockett received a B.B.A. degree from Texas A&M University in 1976.
 
Cecil E. Martin has served as a director since October 1989. Mr. Martin is an independent commercial real estate investor who has primarily been managing his personal real estate investments since 1991. From 1973 to 1991, he also served as chairman of a public accounting firm in Richmond, Virginia. Mr. Martin also serves as a director of Bois d’Arc Energy, Inc. and 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 May 1996. Mr. Sledge is currently a Vice President of Basic Energy Services, Inc. He was President and Chief Operating Officer of Sledge Drilling Company until it was acquired by Basic Energy Services in April 2007. He served as an area operations manager for


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Patterson-UTI Energy, Inc. from May 2004 until January 2006. From October 1996 until May 2004, Mr. Sledge managed his personal investments in oil and gas exploration activities. 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. Mr. Sledge also serves as a director of Bois d’Arc Energy, Inc. 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 is involved civically in the Dallas community and currently serves on the board of the Presbyterian Hospital of Dallas 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.
 
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 are 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;


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  •  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.
 
Any continued and extended decline in the price of crude oil or natural gas 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.
 
We have entered into certain natural gas price hedging arrangements on certain of our anticipated sales. In the future we may enter into additional 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.
 
We plan to 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, as well as the Gulf of Mexico through our ownership interest in Bois d’Arc Energy, we may pursue acquisitions or properties located in other geographic areas.


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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 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.
 
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.
 
With the increasing oil and natural gas prices, our industry has experienced a shortage of drilling rigs, equipment, supplies and qualified personnel. Costs and delivery times of rigs, equipment and supplies are substantially greater than they were several years ago. In addition, demand for, and wage rates of, qualified drilling rig crews rise with increases in the number of active rigs in service. 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.
 
We are vulnerable to operational, regulatory and other risks associated with the Gulf of Mexico, including the effects of adverse weather conditions such as hurricanes, because we currently explore and produce exclusively in that area.
 
Our offshore operations and revenues are significantly impacted by conditions in the Gulf of Mexico. Risks associated with the Gulf of Mexico include:
 
  •  adverse weather conditions, including hurricanes and tropical storms;
  •  delays or decreases in production, the availability of equipment, facilities or services;
  •  delays or decreases in the availability of capacity to transport, gather or process production; and
  •  changes in the regulatory environment.


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Offshore operations are also subject to a variety of operating risks peculiar to the marine environment, such as capsizing, collisions and damage or loss from hurricanes or other adverse weather conditions. These conditions can cause substantial damage to our facilities and interrupt our production. As a result, we could incur substantial liabilities that could reduce or eliminate the funds available for exploration and development or result in loss of equipment and property. For example, our offshore operations were impacted in 2005 by hurricane and tropical storm activity.
 
We plan to conduct exploration, development and production operations on the deep shelf and in the deepwater of the Gulf of Mexico, which presents greater operating and financial risks than conventional shelf operations.
 
The deep shelf of the Gulf of Mexico is an area that has had limited historical drilling activity. This is due, in part, to its geological complexity and depth. Deep shelf development can be more expensive than conventional shelf projects as deep shelf development requires more actual drilling days and higher drilling and services costs due to extreme pressure and temperatures associated with greater drilling depths. Moreover, drilling expense and the risk of mechanical failure are significantly higher because of the additional depth and adverse conditions such as high temperature and pressure. Also, seismic interpretation of deeper, geopressured formations is more difficult than at shallower, normally pressured conventional well depths. Our overall exploration success rate has been 70%. Of the 27 deep shelf wells that we have drilled, 17 successfully found hydrocarbons at geologic and drilling depths below 15,000 feet, for a success rate of 55%. This success rate is lower than our overall success rate, reflecting the fact that deep shelf drilling is inherently more risky than conventional shelf drilling. Deepwater development costs can also be significantly higher than shelf development costs because deepwater drilling requires bigger installation equipment; sophisticated sea floor production handling equipment; expensive, state-of-the-art platforms and/or investment in infrastructure. Accordingly, we cannot assure you that our oil and natural gas exploration activities, in the deep shelf, the deepwater and elsewhere, will be commercially successful.
 
Our debt service requirements could adversely affect our operations and limit our growth.
 
We had $760.0 million in debt as of December 31, 2007, and our ratio of total debt to total capitalization was approximately 50%.
 
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.


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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 would cause a default under our bank credit facility and the indenture governing our 67/8% senior notes due 2012. 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 to refinance it. 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.
 
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, sub-sea pipeline or onshore 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;


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  •  severe damage to and destruction of property, natural resources and equipment;
  •  pollution and other environmental damage;
  •  clean-up responsibilities;
  •  regulatory investigation and penalties;
  •  suspension of our operations; and
  •  repairs to resume operations.
 
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 for the acquisition, development and exploration of oil and natural gas properties and capital to finance such activities, 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.
 
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. 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.


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If oil and natural gas prices decrease, 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.
 
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, 2007, 32% of our total proved reserves are undeveloped and 21% are 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 gas at commercially acceptable prices, our profitability will decline.
 
Our ability to market oil and 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 effect our profitability.


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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 terminal 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 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.


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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.
 
Compliance with MMS regulations could significantly delay or curtail our operations or require us to make material expenditures, all of which could have a material adverse effect on our financial condition or results of operations.
 
Substantially all of Bois d’Arc Energy’s offshore operations are located on federal oil and natural gas leases that are administered by the MMS. As an offshore operator, Bois d’Arc Energy must obtain MMS approval for our exploration, development and production plans prior to commencing such operations. The MMS has promulgated regulations that, among other things, require Bois d’Arc Energy to meet stringent engineering and construction specifications, restrict the flaring or venting of natural gas, govern the plug and abandonment of wells located offshore and the installation and removal of all production facilities, and govern the calculation of royalties and the valuation of crude oil produced from federal leases.
 
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;
  •  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.
 
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.


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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.
 
We have in place a stockholders’ rights plan. The provisions of the stockholders’ rights plan and the above 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.
 
ITEM 4.   SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
 
No matters were submitted to a vote of our security holders during the fourth quarter of 2007.


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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  
 
  2006 —     First Quarter   $ 34.25     $ 25.43  
        Second Quarter   $ 33.53     $ 24.79  
        Third Quarter   $ 30.99     $ 24.84  
        Fourth Quarter   $ 33.80     $ 23.97  
                         
  2007 —     First Quarter   $ 32.49     $ 25.14  
        Second Quarter   $ 31.81     $ 27.03  
        Third Quarter   $ 32.89     $ 24.62  
        Fourth Quarter   $ 39.44     $ 30.85  
 
As of February 28, 2008, we had 45,511,845 shares of common stock outstanding, which were held by 319 holders of record and approximately 14,700 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 indenture for our senior notes from paying or declaring cash dividends in excess of $40.0 million.
 
During the fourth quarter of 2007, we did not repurchase any of our equity securities.
 
The following table summarizes certain information regarding our equity compensation plans as of December 31, 2007:
 
                         
            Number of securities
    Number of 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
    914,970     $ 16.68       350,306 (1)
 
(1) Plus 1% of the outstanding shares of common stock each year beginning on each subsequent January 1.
 
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, 2007 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.” Effective January 1, 2006, we began including Bois d’Arc Energy in our financial statements as a consolidated subsidiary. Our financial statements for data and periods prior to January 1, 2006 have not been adjusted. For comparative purposes, financial information for 2005 is also presented on a pro forma to reflect Bois d’Arc Energy as a consolidated subsidiary.
 
Statement of Operations Data:
 
                                                 
    Year Ended December 31,  
                      2005
             
    2003     2004     2005     Pro Forma     2006     2007  
    (In thousands, except per share data)  
 
Oil and gas sales
  $ 235,102     $ 261,647     $ 303,336     $ 449,242     $ 511,928     $ 687,073  
Operating expenses:
                                               
Oil and gas operating(1)
    45,746       52,068       50,966       81,356       107,303       123,632  
Exploration
    4,410       15,610       19,725       33,693       20,132       43,079  
Depreciation, depletion and amortization
    61,169       63,879       63,338       95,977       153,922       243,619  
Impairment
    4,255       1,648       3,400       3,990       10,444       826  
General and administrative, net
    7,006       14,569       16,533       24,017       31,769       42,682  
                                                 
Total operating expenses
    122,586       147,774       153,962       239,033       323,570       453,838  
                                                 
Income from operations
    112,516       113,873       149,374       210,209       188,358       233,235  
Other income (expenses):
                                               
Interest income
    73       1,207       1,604       610       1,012       1,389  
Other income
    223       166       209       209       781       685  
Interest expense
    (29,860 )     (21,182 )     (20,272 )     (21,365 )     (27,429 )     (41,326 )
Loss of disposal of assets
                      (89 )            
Formation costs of Bois d’Arc Energy
          (1,101 )                        
Gain on sale of stock by Bois d’Arc Energy
                28,797       28,797              
Gain (loss) from derivatives
    (3 )     (155 )     (13,556 )     (13,556 )     10,716        
Loss on early extinguishment of debt
          (19,599 )                        
                                                 
Total other income (expense)
    (29,567 )     (40,664 )     (3,218 )     (5,394 )     (14,920 )     (39,252 )
                                                 
Income before income taxes, equity in loss of Bois d’Arc Energy, and minority interest in earnings of Bois d’Arc Energy
    82,949       73,209       146,156       204,815       173,438       193,983  
Income tax expense
    (29,682 )     (26,342 )     (35,815 )     (161,623 )     (74,339 )     (85,177 )
Equity in loss of Bois d’Arc Energy
                (49,862 )                  
Minority interest in earnings of Bois d’Arc Energy
                      17,287       (28,434 )     (39,905 )
                                                 
Net income before cumulative effect of change in accounting principle
    53,267       46,867       60,479       60,479       70,665       68,901  
Cumulative effect of change in accounting principle
    675                                
                                                 
Net income
    53,942       46,867       60,479       60,479     $ 70,665       68,901  
Preferred stock dividends
    (573 )                              
                                                 
Net income attributable to common stock
  $ 53,369     $ 46,867     $ 60,479     $ 60,479     $ 70,665     $ 68,901  
                                                 
Basic net income per share:
                                               
Before cumulative effect of change in accounting principle
  $ 1.65     $ 1.37     $ 1.54     $ 1.54     $ 1.67     $ 1.59  
Cumulative effect of change in accounting principle
    0.02                                
                                                 
    $ 1.67     $ 1.37     $ 1.54     $ 1.54     $ 1.67     $ 1.59  
                                                 
Diluted net income per share:
                                               
Before cumulative effect of change in accounting principle
  $ 1.51     $ 1.29     $ 1.47     $ 1.47     $ 1.61     $ 1.54  
Cumulative effect of change in accounting principle
    0.02                                
                                                 
    $ 1.53     $ 1.29     $ 1.47     $ 1.47     $ 1.61     $ 1.54  
                                                 
Weighted average shares outstanding:
                                               
Basic
    31,964       34,187       39,216       39,216       42,220       43,415  
                                                 
Diluted
    35,275       36,252       41,154       41,154       43,556       44,405  
                                                 
 
(1) Includes lease operating costs and production and ad valorem taxes.


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Balance Sheet Data:
 
                                                 
    Year Ended December 31,  
                      2005
             
    2003     2004     2005     Pro Forma     2006     2007  
    (In thousands)  
 
Cash and cash equivalents
  $ 5,343     $ 2,703     $ 89     $ 12,132     $ 10,715     $ 24,406  
Property and equipment, net
    698,686       827,761       706,928       1,368,859       1,773,626       2,222,875  
Investment in Bois d’Arc Energy
                252,134                    
Total assets
    746,356       941,476       1,016,663       1,477,307       1,878,125       2,354,387  
Total debt
    306,623       403,150       243,000       312,000       458,250       762,588  
Stockholders’ equity
    289,656       355,853       582,859       582,859       682,563       771,644  
Cash flows provided by operating activities
    153,785       171,351       217,954       322,744       364,605       446,305  
Cash flows used for investing activities
    (92,930 )     (258,061 )     (207,086 )     (512,692 )     (529,751 )     (745,371 )
Cash flows provided by (used for) financing activities
    (57,194 )     84,070       (13,482 )     198,408       163,729       312,757  
 
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, discovery and production of oil and natural gas in the United States. We own interests in 2,009 (1,024.2 net to us) producing oil and natural gas wells and we operate 1,014 of these wells. We own a controlling interest in Bois d’Arc Energy, an independent exploration company that owns interests in offshore producing oil and natural gas wells in the Gulf of Mexico. The results of Bois d’Arc Energy have been included in our consolidated financial statements beginning January 1, 2006. 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 future growth will be driven primarily by acquisition, development and exploration activities. Under our current drilling budget, we plan to spend approximately $526.0 million in 2008 for development and exploration activities. We plan to drill approximately 108 development wells, 77.7 net to us, and 23 exploratory wells, 15.4 net to us in 2008. However, the number of wells that we drill in 2008 will be subject to the availability of drilling rigs that we can hire. In addition, we could increase or decrease the wells that we drill depending on oil and natural gas prices. We do not 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.


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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 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 offset production declines or maintain production at 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 harm 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 $52.6 million as of December 31, 2007.
 
Investment in Bois d’Arc Energy
 
Bois d’Arc Energy was organized in July 2004 as a limited liability company through the contribution of substantially all of our offshore properties together with the properties of Bois d’Arc Resources, Ltd. and its partners. We initially owned 60% of Bois d’Arc Energy, and we accounted for our share of Bois d’Arc Energy’s financial and operating results using proportionate consolidation accounting until Bois d’Arc Energy was converted into a corporation and completed its initial public offering in May 2005. Subsequent to the conversion into a corporation and as a result of the public offering, we owned 48% of the outstanding shares of Bois d’Arc Energy. Since proportionate consolidation is not a generally accepted accounting principle applicable to an investment in a corporation, we changed our accounting method for our investment in Bois d’Arc Energy to the equity method concurrent with Bois d’Arc Energy’s conversion to a corporation. The offshore results for 2005 include our proportionate interest in the operations of Bois d’Arc Energy based upon our ownership interest throughout the period presented. The equity method adjustments reflect the reductions to our share of Bois d’Arc Energy’s operating results that are necessary to apply the equity method of accounting for all periods subsequent to the conversion of Bois d’Arc Energy to corporation.
 
During 2006, we acquired additional shares of common stock of Bois d’Arc Energy, which increased our direct ownership interest in Bois d’Arc Energy. As a result, we obtained voting control of Bois d’Arc Energy through our direct share ownership combined with the share ownership of members of our Board of Directors. The results of Bois d’Arc Energy are included in our financial statements as a consolidated subsidiary, and as permitted by generally accepted accounting principles, consolidated revenues, expenses and cash flows for 2006 reflect Bois d’Arc Energy as a consolidated subsidiary as of January 1, 2006. Financial statements for dates and periods prior to January 1, 2006, have not been adjusted. Although the


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inclusion of Bois d’Arc Energy as a consolidated subsidiary had no impact on our net income, comparisons of the separate components of our results of operations are significantly impacted by this change. In order to provide more meaningful information regarding comparisons of our results for the year ended December 31, 2006, our discussion of our operating results and capital expenditures is presented based upon a comparison of actual 2006 results to pro forma results for 2005 adjusted to include Bois d’Arc Energy as a consolidated subsidiary.
 
The onshore data in the tables below contains the results of operations for our direct ownership in our onshore oil and gas properties. The offshore data contains the results of operations of Bois d’Arc Energy. The 2007 and 2006 data and the pro forma 2005 data reflect 100% of the operations of Bois d’Arc Energy. The historical 2005 results reflect only our proportionate share of Bois d’Arc Energy’s operations.
 
Results of Operations
 
Year Ended December 31, 2007 Compared to Year Ended December 31, 2006
 
Our operating data for 2007 and 2006 is summarized below:
 
                         
    Onshore     Offshore     Total  
 
Year Ended December 31, 2007
                       
Net Production Data:
                       
Oil (MBbls)
    1,008       1,671       2,679  
Natural gas (MMcf)
    39,231       32,186       71,417  
Natural gas equivalent (MMcfe)
    45,282       42,211       87,493  
Average Sales Price:
                       
Oil ($/Bbl)
  $ 60.96     $ 74.15     $ 69.18  
Natural gas ($/Mcf)
  $ 6.89     $ 7.19     $ 7.03  
Average equivalent price ($/Mcfe)
  $ 7.32     $ 8.42     $ 7.85  
Expenses ($ per Mcfe):
                       
Oil and gas operating(1)
  $ 1.43     $ 1.39     $ 1.41  
Depreciation, depletion and amortization(2)
  $ 2.76     $ 2.72     $ 2.77  
                         
Year Ended December 31, 2006
                       
Net Production Data:
                       
Oil (MBbls)
    921       1,383       2,304  
Natural gas (MMcf)
    30,271       23,183       53,454  
Natural gas equivalent (MMcfe)
    35,797       31,481       67,278  
Average Sales Price:
                       
Oil ($/Bbl)
  $ 55.32     $ 64.66     $ 60.93  
Natural gas ($/Mcf)
  $ 6.81     $ 7.13     $ 6.95  
Average equivalent price ($/Mcfe)
  $ 7.19     $ 8.09     $ 7.61  
Expenses ($ per Mcfe):
                       
Oil and gas operating(1)
  $ 1.51     $ 1.70     $ 1.59  
Depreciation, depletion and amortization(2)
  $ 2.10     $ 2.45     $ 2.28  
 
(1) Includes lease operating costs and production and 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 $175.1 million (34%) in 2007 to $687.1 million from $511.9 million in 2006. The increase in sales is primarily due to a 30% increase in our production combined with stronger oil prices in 2007. Our realized oil price increased by 14% and our realized natural gas price increased by 1% in 2007 as compared to 2006. Oil and gas sales from our onshore operations increased to $331.6 million, an increase of $74.4 million or 29%, from $257.2 million in 2006. This increase is attributable to the 27% increase in production driven primarily by our successful drilling activities and the higher oil and natural gas prices we realized. Our average onshore crude oil price increased by 10% and our average onshore natural gas price increased by 1% in 2007 as compared to prices in 2006. Sales from our


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offshore operations of $355.5 million in 2007 were 40% higher than offshore revenues in 2006 of $254.7 million mainly due to the 34% increase in production resulting from new wells drilled and the higher oil and natural gas prices realized. Our average offshore crude oil price realized increased 15% and our average offshore natural gas price realized increased by 1% in 2007 as compared to prices in 2006.
 
Oil and gas operating expenses.  Our oil and gas operating expenses, including production taxes, increased $16.3 million (15%) to $123.6 million in 2007 from $107.3 million in 2006. Oil and gas operating expenses per equivalent Mcf produced decreased $0.18 to $1.41 as compared to $1.59 in 2006. Onshore operating expenses for 2007 of $64.8 million increased by $10.9 million compared to 2006 due to the start-up of new wells and higher production taxes due to increased oil and gas prices. Offshore oil and gas operating costs for 2007 increased $5.4 million to $58.8 million mainly due to our 34% increase in production during 2007 as compared to production in 2006. Our average offshore operating cost per Mcfe produced decreased in 2007 as compared to 2006 due to our higher produced volumes and lower repair and maintenance costs. Operating costs in 2006 included $3.0 million of costs associated with repairs associated with hurricane damage in 2005.
 
Exploration expense.  In 2007, we incurred $43.1 million in exploration expense as compared to $20.1 million in 2006. The increase in exploration expense in 2007 primarily relates to nine dry holes drilled and the acquisition of 3-D seismic data. Exploration expense in 2006 included costs for five dry holes and costs incurred for seismic data acquisition.
 
DD&A.  Depreciation, depletion and amortization (“DD&A”) increased $89.7 million (58%) to $243.6 million in 2007 from $153.9 million in 2006. This increase resulted from our 30% increase in production in 2007 as compared to 2006 and an increase in our average DD&A rate per Mcfe produced. DD&A associated with our onshore properties increased by $52.0 million to $128.3 million in 2007. Onshore production increased 27% and the onshore DD&A rate per Mcfe produced increased to $2.76 in 2007 as compared to $2.10 in 2006. The increase in the DD&A rate results from the higher costs of properties acquired in late 2006 and 2007 and an increase in capitalized costs on our existing onshore properties. DD&A expense for our offshore properties increased by $37.7 million to $115.3 million in 2007. Offshore production increased 34% in 2007 as compared to 2006 and the offshore DD&A rate per Mcfe produced increased to $2.72 in 2007 from $2.45 in 2006. The increase in the offshore DD&A rate resulted from higher capitalized costs associated with our new wells drilled.
 
Impairment.  We recorded impairments to our oil and gas properties of $0.8 million in 2007 and $10.4 million in 2006. The impairments in 2007 relate to minor valued fields where an impairment was indicated based on estimated future cash flows attributable to the fields’ estimated proved oil and natural gas reserves. Impairments in 2006 included $7.9 million related to a property that was held for resale. Subsequently the plan to sell the property was cancelled. The impairment in 2006 reflected this property’s estimated fair market value at the time the plan to sell the property changed.
 
General and administrative expenses.  General and administrative expenses, which are reported net of overhead reimbursements, of $42.7 million for 2007 were 34% higher than general and administrative expenses of $31.8 million for 2006. The increase primarily reflects higher personnel costs resulting from increased hiring to support our operating activities and an increase of $5.9 million in stock based compensation in 2007 as compared to 2006, including $1.7 million in costs for accelerated vesting for Bois d’Arc Energy’s former chief executive officer, who retired in November 2007.
 
Interest expense.  Interest expense increased $13.9 million (51%) to $41.3 million in 2007 from $27.4 million in 2006. The increase was primarily due to higher outstanding borrowings and an increase in interest rates. Average borrowings under our bank credit facilities increased to $394.0 million in 2007 as


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compared to $188.6 million for 2006. The average interest rate on the outstanding borrowings under our credit facilities increased to 6.6% in 2007 as compared to 6.5% in 2006.
 
Minority Interest.  Minority interest in earnings of Bois d’Arc Energy of $39.9 million for 2007 increased $11.5 million from minority interest in earnings of $28.4 million for 2006 due to Bois d’Arc Energy’s higher net income in 2007.
 
Income taxes.  Income tax expense increased in 2007 to $85.2 million from $74.3 million in 2006 due to our higher pre-tax income in 2007. The increase in our effective tax rate to 43.9% in 2007 from 42.9% in 2006 is primarily due to higher deferred taxes associated with the increased earnings of Bois d’Arc Energy in 2007 as compared to 2006.
 
Net income.  We reported net income of $68.9 million in 2007, as compared to net income of $70.7 million in 2006. Net income per share for 2007 was $1.54 on 44.4 million weighted average diluted shares outstanding as compared to $1.61 for 2006 on 43.6 million weighted average diluted shares outstanding.
 
Year Ended December 31, 2006 Compared to Pro Forma Year Ended December 31, 2005
 
Our operating data for 2006 and 2005 on a pro forma basis is summarized below:
 
                         
    Onshore     Offshore     Total  
 
Year Ended December 31, 2006
                       
Net Production Data:
                       
Oil (MBbls)
    921       1,383       2,304  
Natural gas (MMcf)
    30,271       23,183       53,454  
Natural gas equivalent (MMcfe)
    35,797       31,481       67,278  
Average Sales Price:
                       
Oil ($/Bbl)
  $ 55.32     $ 64.66     $ 60.93  
Natural gas ($/Mcf)
  $ 6.81     $ 7.13     $ 6.95  
Average equivalent price ($/Mcfe)
  $ 7.19     $ 8.09     $ 7.61  
Expenses ($ per Mcfe):
                       
Oil and gas operating(1)
  $ 1.51     $ 1.70     $ 1.59  
Depreciation, depletion and amortization(2)
  $ 2.10     $ 2.45     $ 2.28  
                         
Pro Forma Year Ended December 31, 2005
                       
Net Production Data:
                       
Oil (MBbls)
    735       1,155       1,890  
Natural gas (MMcf)
    28,742       14,896       43,638  
Natural gas equivalent (MMcfe)
    33,151       21,825       54,976  
Average Sales Price:
                       
Oil ($/Bbl)
  $ 49.34     $ 52.88     $ 51.50  
Natural gas ($/Mcf)
  $ 7.95     $ 8.28     $ 8.06  
Average equivalent price ($/Mcfe)
  $ 7.99     $ 8.45     $ 8.17  
Expenses ($ per Mcfe):
                       
Oil and gas operating(1)
  $ 1.34     $ 1.70     $ 1.48  
Depreciation, depletion and amortization(2)
  $ 1.60     $ 1.95     $ 1.74  
 
(1) Includes lease operating costs and production and 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 $62.7 million (14%) in 2006 to $511.9 million from pro forma consolidated sales of $449.2 million in 2005. This increase primarily reflects a 22% increase in production and higher prices for crude oil which were partially offset by lower natural gas prices in 2006. Prices for crude oil increased by 18% in 2006 as compared to our prices for crude oil in 2005. Our average natural gas price decreased by 14% in 2006 as compared to our average gas price in 2005. The higher production was primarily due to new wells drilled and the restoration of certain of our offshore production with the return to service of pipelines and facilities in 2006 after being shut in due to hurricanes in 2005. Oil


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and gas sales from our onshore operations decreased to $257.2 million, a decrease of $7.6 million or 3%, from sales of $264.8 million in 2005. This decrease is attributable to the lower natural gas prices we realized in 2006 as compared to 2005, which was partially offset by an 8% increase in production. The increase in production was mainly due to production from the properties we acquired in 2005. Our average onshore crude oil price increased by 12% and our average onshore natural gas price decreased by 14% in 2006 as compared to prices in 2005. Sales from our offshore operations of $254.7 million in 2006 were 38% higher than offshore revenues in 2005 of $184.4 million mainly due to the 44% increase in production resulting from the restoration of pipelines and facilities offshore and production from new wells that we drilled. Our average offshore crude oil price realized increased 22% and our average offshore natural gas price realized decreased by 14% in 2006 as compared to prices in 2005.
 
Oil and gas operating expenses.  Our oil and gas operating expenses, including production taxes, increased $25.9 million (32%) to $107.3 million in 2006 from pro forma consolidated operating expenses of $81.4 million in 2005. Oil and gas operating expenses per equivalent Mcf produced increased $0.11 to $1.59 as compared to $1.48 in 2005. Onshore operating expenses for 2006 of $53.9 million increased by $9.6 million compared to 2005 due to costs associated with the properties we acquired in 2005 or drilled in 2006. Offshore oil and gas operating costs for 2006 increased $16.3 million to $53.4 million mainly due to our 44% increase in production during 2006 as compared to production in 2005. Our average offshore operating cost per Mcfe produced increased in 2006 as compared to 2005 due to our higher produced volumes and increased cost of services and materials for fuel, services and supplies, and higher insurance costs.
 
Exploration expense.  In 2006, we incurred $20.1 million in exploration expense as compared to pro forma consolidated exploration expense of $33.7 million in 2005. Exploration expense in 2006 primarily relates to dry hole expense for three offshore exploratory wells, two onshore exploratory wells, the acquisition and reprocessing of offshore 3-D seismic data, and impairment of unproved properties. Pro forma exploration expense in 2005 includes $16.7 million for a South Texas dry hole, the cost of one offshore exploratory dry hole and offshore seismic costs.
 
DD&A.  Depreciation, depletion and amortization (“DD&A”) increased $57.9 million (60%) to $153.9 million in 2006 from pro forma consolidated DDA expense of $96.0 million in 2005. Our DD&A rate per Mcfe produced averaged $2.28 in 2006 as compared to $1.74 for 2005. DD&A expense in 2006 for onshore operations increased $22.1 million or (42%) from 2005 due to higher production and an increase in the onshore amortization rate caused by higher capitalized costs of the development wells we drilled. Offshore DD&A expenses for 2006 increased $34.7 million or 81% from 2005 due to increased production and a higher the amortization rate. The offshore amortization rate results from higher capitalized costs associated with the wells we drilled and the installation of new production facilities
 
Impairment.  We recorded impairments to our oil and gas properties of $10.4 million in 2006 as compared to pro forma consolidated impairment expense of $4.0 million in 2005. Impairment of onshore properties of $8.8 million increased in 2006 over 2005 primarily due to impairment in 2006 of a property that was held for resale. Subsequently the plan to sell the property was cancelled. The impairment reflected this property’s estimated fair market value at the time the plan to sell the property changed. Offshore impairments of $1.6 million were related to several minor valued fields.
 
General and administrative expenses.  General and administrative expenses, which are reported net of overhead reimbursements, of $31.8 million for 2006 were 32% higher than pro forma consolidated general and administrative expenses of $24.0 million for 2005. The increase primarily reflects higher personnel costs in 2006 due to increased staffing necessary to support the higher activity levels in our exploration and development programs, an increase of $3.4 million in stock-based compensation in 2006 as compared to 2005, and the increased costs of compliance related to Bois d’Arc Energy which became a public company in May 2005.


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Interest expense.  Interest expense increased $6.0 million (28%) to $27.4 million in 2006 from pro forma consolidated interest expense of $21.4 million in 2005. The increase was primarily the result of higher borrowings and higher interest rates in 2006. Average borrowings under our bank credit facilities increased to $188.6 million in 2006 as compared to $166.4 million for 2005. The average interest rate on the outstanding borrowings under our credit facilities increased to 6.5% in 2006 as compared to 4.6% in 2005.
 
Derivative Gains and Losses.  We did not designate our derivatives we utilize as part of our price risk management program as cash flow hedges and accordingly, we recognize gains or losses for the changes in the fair value of these liabilities during each period. The fair value of our liability for these derivatives decreased during 2006 resulting in a net unrealized gain of $11.2 million. During 2005, the fair value of these liabilities increased due to the increase in natural gas prices and we accordingly recognized an unrealized loss of $11.1 million during 2005. We realized losses to settle derivative positions of $0.7 million and $2.5 million during 2006 and 2005, respectively.
 
Minority Interest.  Minority interest in earnings of Bois d’Arc Energy of $28.4 million for 2006 increased $45.7 million from the pro forma minority interest in losses of $17.3 million for 2005 primarily due to Bois d’Arc Energy’s higher net income in 2006. This increase is mainly due to the absence of Bois d’Arc Energy’s one time tax provision of $108.2 million in 2005 associated with recognizing cumulative deferred tax liabilities when it converted from a limited liability company to a corporation.
 
Income taxes.  Income tax expense decreased in 2006 to $74.3 million from $161.6 million in 2005. The 2005 tax provision included a $108.2 million provision for deferred taxes related to Bois d’Arc Energy’s conversion to a corporation during 2005. Subsequent to Bois d’Arc Energy’s conversion to a corporation, we are including a deferred tax provision on the change in our investment in Bois d’Arc Energy.
 
Net income.  We reported net income of $70.7 million in 2006, as compared to net income of $60.5 million in 2005. Net income per share for 2006 was $1.61 on 43.6 million weighted average diluted shares outstanding as compared to $1.47 for 2005 on 41.2 million weighted average diluted shares outstanding.
 
Liquidity and Capital Resources
 
Funding for our activities has historically been provided by our operating cash flow, debt or equity financings or asset dispositions. In 2007, our net cash flow provided by operating activities totaled $446.3 million. Our other primary source of funds in 2007 was net borrowings of $302.0 million under our bank credit facilities. In 2006, our net cash flow provided by operating activities totaled $364.6 million. Our other primary source of funds in 2006 was a net increase of $143.0 million under our bank credit facilities. In 2005, our net cash flow provided by operating activities totaled $218.0 million and we received proceeds of $121.2 million from a public offering of our common stock. In 2005 we also increased the debt outstanding under our bank credit facilities by $179.0 million.
 
Our cash flow from operating activities in 2007 increased by $81.7 million to $446.3 million as compared to $364.6 million in 2006 primarily due to higher revenues which were attributable to our increased production and improved oil and natural gas prices. Our cash flow from operating activities in 2006 increased by $146.6 million to $364.6 million as compared to $218.0 million in 2005 primarily due to higher revenues which were attributable to our increased production and the consolidation of Bois d’Arc Energy’s cash flows. Our cash flow from operating activities in 2006 increased from pro forma 2005 cash flow from operating activities of $322.7 million due to the higher oil and gas production in 2006.
 
Our primary need for capital, in addition to funding our ongoing operations, relate to the acquisition, development and exploration of our oil and gas properties, and the repayment of our debt. Our capital


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expenditures in 2007 of $733.9 million increased by $197.6 million over 2006 capital expenditures of $536.3 million mostly due to acquisitions and increased drilling activity. Capital expenditures in 2006 of $536.3 million increased by $22.1 million over pro forma 2005 capital expenditures of $514.2 million primarily due to increased drilling activity.
 
Our annual capital expenditure activity is summarized in the following table:
 
                                 
    Year Ended December 31,  
          Pro Forma
             
    2005     2005(1)     2006     2007  
    (In thousands)  
 
Exploration and development:
                               
Acquisitions of proved oil and gas properties
  $ 201,788     $ 201,788     $ 79,767     $ 191,290  
Acquisitions of unproved oil and gas properties
    2,027       6,935       10,010       15,115  
Developmental leasehold costs
    3,102       3,102       2,902       2,780  
Development drilling
    98,710       77,601       211,491       348,835  
Exploratory drilling
    26,106       78,228       136,759       103,521  
Workovers and recompletions
    21,100       34,561       41,646       44,771  
Other development
    2,580       109,300       50,764       26,266  
                                 
      355,413       511,515       533,339       732,578  
Other
    849       2,637       2,924       1,340  
                                 
Total
  $ 356,262     $ 514,152     $ 536,263     $ 733,918  
                                 
 
(1) Pro forma for consolidating the capital expenditures of Bois d’Arc Energy as of January 1, 2005.
 
The timing of most of our capital expenditures is discretionary because we have no material long-term capital expenditure commitments. Consequently, we have a significant degree of flexibility to adjust the level of our capital expenditures as circumstances warrant. We currently expect to spend approximately $526.0 million for development and exploration projects in 2008, which will be funded primarily by cash flows from operating activities and to a lesser extent borrowings under our bank credit facilities. 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 spent $201.8 million, $79.8 million and $191.3 million on acquisitions during 2005, 2006 and 2007, respectively. Our acquisitions of producing oil and gas properties in 2007 included 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 in December, 2007 and the acquisition of additional working interests in the Javelina field in Hidalgo County in South Texas for $31.2 million in June, 2007. These acquisitions were funded with borrowings under Comstock’s bank credit facility.
 
Concurrent with the December 2007 acquisition, we entered into a transaction structured as a reverse like-kind exchange in accordance with Section 1031 of the Internal Revenue Code. While we intend to obtain tax deferred treatment on gains from future sales of oil and gas properties, no assurance can be given that we will have future transactions that will qualify as a like-kind exchange or that we will achieve any tax-savings as a result of this structure. In connection with this reverse like-kind exchange, we assigned the right to acquire ownership in the oil and gas properties that were acquired from SWEPI LP to an exchange accommodation titleholder. We operate these properties pursuant to lease and management agreements. Because we are the primary beneficiary of these arrangements, the properties acquired are included in our consolidated balance sheet as of December 31, 2007, and we include all revenues earned and expenses incurred related to the properties in our results of operations during the term of the agreements. These agreements will terminate upon the transfer of the acquired properties from the exchange accommodation titleholder to us no later than June 25, 2008.


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We do not have a specific acquisition budget for 2008 since 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 facilities, 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.
 
We have $175.0 million of senior notes outstanding. The senior notes are due March 1, 2012 and bear interest at 67/8%, which is payable semiannually on each March 1 and September 1. The senior notes are unsecured obligations and are guaranteed by all of our wholly owned subsidiaries.
 
We have a $600.0 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 December 15, 2011. Indebtedness under the bank credit facility is secured by substantially 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, 2007 the borrowing base was $575.0 million, $70.0 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 LIBOR plus 1.0% to 1.75% or the base rate (which is the higher of the prime rate or the federal funds rate) plus 0% to 0.25%. A commitment fee of 0.25% to 0.375%, based on the utilization of the borrowing base, is payable on the unused portion of the borrowing base. The bank credit facility contains covenants that, among other things, restrict the payment of cash dividends in excess of $40.0 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, 2007.
 
Bois d’Arc Energy has a $350.0 million bank credit facility with The Bank of Nova Scotia and several other banks. Borrowings under the Bois d’Arc Energy credit facility are limited to a borrowing base that is re-determined semi-annually based on the banks’ estimates of the future net cash flows of our oil and natural gas properties. The borrowing base was $350.0 million, $270.0 million of which was available as of December 31, 2007. The determination of the borrowing base is at the sole discretion of the administrative agent and the bank group. The Bois d’Arc Energy credit facility matures on May 11, 2009. Borrowings under the credit facility bear interest at Bois d’Arc Energy’s option at either (1) LIBOR plus a margin that varies from 1.25% to 2.0% depending upon the ratio of the amounts outstanding to the borrowing base or (2) the base rate (which is the higher of the prime rate or the federal funds rate) plus a margin that varies from 0% to 0.75% depending upon the ratio of the amounts outstanding to the borrowing base. A commitment fee ranging from 0.375% to 0.50% (depending upon the ratio of the amounts outstanding to the borrowing base) is payable on the unused borrowing base. Indebtedness under the Bois d’Arc Energy credit facility is secured by substantially all of Bois d’Arc Energy’s and its subsidiaries’ assets, and all of Bois d’Arc Energy’s subsidiaries are guarantors of the indebtedness. The Bois d’Arc Energy credit facility contains covenants that restrict the payment of cash dividends in excess of $5.0 million, borrowings, sales of assets, loans to others, capital expenditures, investments, merger activity, hedging contracts, liens and certain other transactions without the prior consent of the lenders and requires Bois d’Arc Energy to maintain a ratio of current assets, including the availability under the bank credit facility, to current liabilities of at least one-to-one and a ratio of indebtedness to earnings before interest, taxes, depreciation, depletion, and


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amortization, exploration and impairment expense of no more than 2.5 to one. Bois d’Arc Energy was in compliance with these covenants as of December 31, 2007.
 
We believe that our cash flow from operations and available borrowings under our bank credit facilities 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.
 
The following table summarizes our aggregate liabilities and commitments by year of maturity:
 
                                                         
    2008     2009     2010     2011     2012     Thereafter     Total  
    (In thousands)  
 
Bank credit facilities
  $     $ 80,000     $     $ 505,000     $     $     $ 585,000  
67/8% senior notes
                            175,000             175,000  
Interest on debt
    48,818       45,700       43,954       42,553       1,998             183,023  
Operating leases
    1,354       1,394       1,412       1,429       1,112       1,545       8,246  
Acquisition of seismic data
    8,250                                     8,250  
Contracted drilling services
    23,781                                     23,781  
                                                         
    $ 82,203     $ 127,094     $ 45,366     $ 548,982     $ 178,110     $ 1,545     $ 983,300  
                                                         
 
Future interest costs are based upon the interest rate on our outstanding senior notes and on the December 31, 2007 rate for our bank credit facilities.
 
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 2012. We record a separate liability for the fair value of these asset retirement obligations which totaled $52.6 million as of December 31, 2007.
 
Federal Taxation
 
At December 31, 2007, we had federal income tax net operating loss carryforwards of approximately $41.3 million. We have established a $23.0 million valuation allowance against part of the net operating loss carryforwards that we acquired in an acquisition due to a “change in control” limitation which will prevent us from fully realizing these carryforwards. The carryforwards expire from 2017 through 2021. The realization of these carryforwards depends on our ability to generate future taxable income in order to utilize these carryforwards.
 
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.


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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 actual prices on the last day of the period.
 
Asset retirement obligations.  We have significant obligations to remove tangible equipment and facilities and to restore land or seafloor 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 offshore oil and gas platforms. 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 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 prescribed in Statement of Financial Accounting Standards No. 123 (revised 2004), “Share-Based Payment” (“SFAS 123R”) 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. We adopted SFAS 123R utilizing the modified prospective transition method and accordingly the financial results for periods prior to January 1, 2006 have not been adjusted. Prior to adopting SFAS 123R we followed the fair value based method prescribed in Statement of Financial Accounting Standards No. 123, “Accounting for Stock Based Compensation” for all periods beginning January 1, 2004. 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 over the award vesting period. Because we previously recorded stock-based compensation using the fair value method, adoption of SFAS 123R did not have a significant impact on our net income or earnings per share for the year ended December 31, 2006.


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New accounting standards.  In June 2006, the FASB issued FASB Interpretation (“FIN”) 48, “Accounting for Uncertainty in Income Taxes,” an interpretation of FASB Statement No. 109 (“FIN 48”). FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of tax positions taken or expected to be taken in a tax return. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. FIN 48 is effective for fiscal years beginning after December 15, 2006, and we adopted FIN 48 at the beginning of fiscal 2007. The impact of adoption was not material.
 
In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (“SFAS No. 157”). This statement establishes a framework for fair value measurements in the financial statements by providing a single definition of fair value, provides guidance on the methods used to estimate fair value and increases disclosures about estimates of fair value. SFAS 157 will be effective for financial assets and liabilities in financial statements issued for fiscal years beginning after November 15, 2007, and will be effective for non-financial assets and liabilities in financial statements issued for fiscal years beginning after November 15, 2008. The Company is currently evaluating the impact of the adoption of this statement on its consolidated financial statements.
 
In December 2007, the FASB concurrently issued SFAS No. 141R, “Business Combinations” and SFAS No. 160 (“SFAS 160”), “Noncontrolling Interests in Consolidated Financial Statements — An Amendment of ARB No. 51”. Both of these standards require measurements based on fair value as determined under the provisions of SFAS 157 and are effective for financial statements issued for fiscal years beginning after December 15, 2008. In addition, both of these standards also include expanded disclosure requirements.
 
SFAS 141R establishes accounting and reporting standards for how the acquirer of a business recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree. This statement also provides guidance for recognizing and measuring the goodwill acquired in the business combination and determines what information to disclose to enable users of the financial statement to evaluate the nature and financial effects of the business combination. SFAS 141R will impact the accounting and disclosures for any business combinations we engage in after January 1, 2009. However, the nature and magnitude of the specific effects will depend upon the nature, terms and size of the acquisitions we consummate after that date.
 
SFAS 160 amends Accounting Research Bulletin 51 to establish accounting and reporting standards for the noncontrolling or minority interest in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. It requires consolidated net income to be reported at amounts that include the amounts attributable to both the parent and the noncontrolling interest. It also requires disclosure, on the face of the consolidated statement of income, of the amounts of consolidated net income attributable to the parent and to the noncontrolling interest. This statement establishes a single method of accounting for changes in a parent’s ownership interest in a subsidiary that do not result in deconsolidation. SFAS 160 clarifies that all such transactions are equity transactions if the parent retains its controlling financial interest in the subsidiary. If there is a loss of control of the subsidiary, SFAS 160 requires the retained interest to be recorded at fair value. We are currently evaluating the impact of the adoption of this statement on our consolidated financial statements which is expected to have a significant impact on our financial statements due to our ownership of Bois d’Arc Energy.
 
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


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transactions with our significant stockholders or any other related parties except for the purchase of 2,250,000 shares of Bois d’Arc Energy’s common stock for $35.9 million in August 2006.
 
ITEM 7A.   QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISKS
 
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 2007, 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 $2.6 million and a $1.00 change in the price per Mcf of natural gas would have changed our cash flow by approximately $69.7 million.
 
We periodically use derivative transactions with respect to a portion of our oil and natural gas production to mitigate our exposure to price changes. While the use of these derivative arrangements limits the downside risk of price declines, such use may also limit any benefits which may be derived from price increases. We use swaps, floors and collars to hedge oil and natural gas prices. Swaps are settled monthly based on differences between the prices specified in the instruments and the settlement prices of futures contracts quoted on the New York Mercantile Exchange. Generally, when the applicable settlement price is less than the price specified in the contract, we receive a settlement from the counterparty based on the difference multiplied by the volume hedged. Similarly, when the applicable settlement price exceeds the price specified in the contract, we pay the counterparty based on the difference. We generally receive 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, we generally receive a settlement from the counterparty when the settlement price is below the floor and pay a settlement to the counterparty when the settlement price exceeds the cap. No settlement occurs when the settlement price falls between the floor and the cap. We had no derivative financial instrument outstanding as of December 31, 2007.
 
In January 2008, we entered into a natural gas price hedge for certain of our natural gas properties in South Texas. The hedge was structured as a natural gas price swap which fixed the price at $8.00 per Mmbtu for delivery at the Houston Ship Channel of 520,000 Mmbtus of natural gas per month for the period February 2008 to December 2009.
 
Interest Rates
 
At December 31, 2007, we had long-term debt of $760.0 million. Of this amount, $175.0 million bears interest at a fixed rate of 67/8%. The fair market value of the fixed rate debt as of December 31, 2007 was $165.8 million based on the market price of 95% of the face amount. At December 31, 2007, we had $585.0 million outstanding under our bank credit facilities, which were subject to floating market rates of


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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 increases in these interest rates can have an adverse impact on our results of operations and cash flow. Based on borrowings outstanding at December 31, 2007, a 100 basis point change in interest rates would change our annual interest expense on our variable rate debt by approximately $5.9 million. We had no interest rate derivatives outstanding during 2007 or at December 31, 2007.
 
ITEM 8.   FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
 
Our consolidated financial statements are included on pages F-1 to F-35 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 composed 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.
 
ITEM 9.   CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLSOURE
 
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 2007 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.


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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, 2007, 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, 2007, 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, 2007. The report, which expresses unqualified opinions on the effectiveness of the Company’s internal control over financial reporting as of December 31, 2007 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, 2007, 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, 2007, 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, 2006 and 2007, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2007 and our report dated February 28, 2008 expressed an unqualified opinion thereon.
 
/s/  ERNST & YOUNG LLP
 
Dallas, Texas
February 28, 2008


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ITEM 9B.   OTHER INFORMATION
 
None.
 
PART III
 
ITEM 10.   DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
 
The information required by this item is incorporated herein by reference to “Business — Directors, Executive Officers and Other Management” in this Form 10-K and to our definitive proxy statement which will be filed with the Securities and Exchange Commission within 120 days after December 31, 2007.
 
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 2008 annual meeting, which will be filed with the SEC within 120 days of December 31, 2007, 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 Securities and Exchange Commission within 120 days after December 31, 2007.
 
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 Securities and Exchange Commission within 120 days after December 31, 2007.
 
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 Securities and Exchange Commission within 120 days after December 31, 2007.
 
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 Securities and Exchange Commission within 120 days after December 31, 2007.


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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-35 of this report:
 
         
Report of Independent Registered Public Accounting Firm
    F-2  
Consolidated Balance Sheets as of December 31, 2006 and 2007
    F-3  
Consolidated Statements of Operations for the Years Ended December 31, 2005, 2006 and 2007
    F-4  
Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 2005, 2006 and 2007
    F-5  
Consolidated Statements of Cash Flows for the Years Ended December 31, 2005, 2006 and 2007
    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
  Bylaws (incorporated by reference to Exhibit 3.2 to our Registration Statement on Form S-3, dated October 25, 1996).
4.1
  Rights Agreement dated as of December 14, 2000, by and between Comstock and American Stock Transfer and Trust Company, as Rights Agent (incorporated herein by reference to Exhibit 1 to our Registration Statement on Form 8-A dated January 11, 2001).
4.2
  Certificate of Designation, Preferences and Rights of Series B Junior Participating Preferred Stock (incorporated by reference to Exhibit 2 to our Registration Statement on Form 8-A dated January 11, 2001).
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).


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Exhibit No.
 
Description
 
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).
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).
10.1#
  Employment Agreement dated June 1, 2002, by and between Comstock and M. Jay Allison (incorporated by reference to Exhibit 10.1 to our Quarterly Report on Form 10-Q for the quarter ended June 30, 2002).
10.2#
  First Amendment to Employment Agreement dated July 16, 2004, by and between Comstock and M. Jay Allison (incorporated by reference to Exhibit 10.8 to our Quarterly Report on Form 10-Q for the quarter ended June 30, 2004).
10.3#
  Employment Agreement dated June 1, 2002, by and between Comstock and Roland O. Burns (incorporated by reference to Exhibit 10.2 to our Quarterly Report on Form 10-Q for the quarter ended June 30, 2002).
10.4#
  First Amendment to Employment Agreement dated July 16, 2004, by and between Comstock and Roland O. Burns (incorporated by reference to Exhibit 10.8 to our Quarterly Report on Form 10-Q for the quarter ended June 30, 2004).
10.5#
  Comstock Resources, Inc. 1999 Long-term Incentive Plan (As restated on April 1, 2001) (incorporated by reference to Exhibit 10.8 to our Annual Report on Form 10-K for the year ended December 31, 2004).
10.6#
  Amendment No. 2 dated April 7, 2004 to the Comstock Resources, Inc. 1999 Long-term Incentive Plan (incorporated by reference to Exhibit 10.1 to our Quarterly Report on Form 10-Q for the quarter ended March 31, 2004).
10.7#
  Form of Nonqualified Stock Option Agreement between Comstock and certain officers and directors of Comstock (incorporated by reference to Exhibit 10.2 to our Quarterly Report on Form 10-Q for the year ended June 30, 1999).
10.8#
  Form of Restricted Stock Agreement between Comstock and certain officers of Comstock (incorporated by reference to Exhibit 10.3 to our Quarterly Report on Form 10-Q for the quarter ended June 30, 1999).
10.9
  Warrant Agreement dated July 31, 2001 by and between Comstock and Gary W. Blackie and Wayne L. Laufer (incorporated by reference to Exhibit 10.1 to our Quarterly Report on Form 10-Q for the quarter ended June 30, 2001).
10.10
  Contribution Agreement dated July 16, 2004, among Bois d’Arc Energy, LLC, Bois d’Arc Properties, LP, Bois d’Arc Resources, Ltd., Wayne L. Laufer, Gary W. Balckie, Haro Investments LLC, such other persons listed on the signature pages thereto, Comstock Offshore LLC, 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, 2004).
10.11
  Amended and Restated Operating Agreement, dated as of August 23, 2004, to be effective July 16, 2004, of Bois d’Arc Energy, LLC (incorporated by reference to Exhibit 3.2 to the Registration Statement on Form S-1 [File No. 33-119511] filed by Bois d’Arc Energy, LLC on October 4, 2004).
10.12
  Services Agreement dated July 16, 2004, between Comstock Resources, Inc. and Bois d’Arc Energy, LLC (incorporated by reference to Exhibit 10.3 to our Quarterly Report on Form 10-Q for the quarter ended June 30, 2004).


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Exhibit No.
 
Description
 
10.13
  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).
10.14
  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).
10.15
  Amended and Restated Operating Agreement dated as of August 23, 2004, to be effective July 16, 2004 of Bois d’Arc Energy, LLC (incorporated by reference to Exhibit 3.2 to Bois d’Arc Energy’s Registration Statement on Form S-1 (File No. 333-19511)).
10.16
  Stock Purchase Agreement dated August 25, 2006, between Bois d’Arc Energy, Inc. and Comstock Resources, Inc. (incorporated by reference to Exhibit 2.1 to our Current Report on Form 8-K dated August 25, 2006).
10.17
  Second Amended and Restated Credit Agreement, dated December 15, 2006, among Comstock, 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 Bank, Fortis Capital Corp., and Union Bank of California, N.A. as co-documentation agents (incorporated by reference to Exhibit 10.1 to our Annual Report on Form 10-K for the year ended December 31, 2006).
10.18*
  Waiver and Borrowing Base Redetermination Agreement, dated December 20, 2007, among Comstock, 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 Bank, Fortis Capital Corp., and Union Bank of California, N.A. as co-documentation agents.
10.19
  Purchase and Sale Agreement between SWEPI LP and Comstock Oil and Gas, LP dated November 26, 2007 (incorporated by reference to Exhibit 2.1 to our Current Report on Form 8-K dated November 26, 2007).
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.
 
* Filed herewith.
+ Furnished herewith.
# Management contract or compensatory plan document.


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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 28, 2008
 
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 28, 2008
         
/s/  ROLAND O. BURNS

Roland O. Burns
  Senior Vice President, Chief Financial Officer, Secretary, Treasurer and Director (Principal Financial and Accounting Officer)   February 28, 2008
         
/s/  DAVID K. LOCKETT

David K. Lockett
  Director   February 28, 2008
         
/s/  CECIL E. MARTIN, JR.

Cecil E. Martin, Jr.
  Director   February 28, 2008
         
/s/  DAVID W. SLEDGE

David W. Sledge
  Director   February 28, 2008
         
/s/  NANCY E. UNDERWOOD

Nancy E. Underwood
  Director   February 28, 2008


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COMSTOCK RESOURCES, INC.
 
FINANCIAL STATEMENTS
 
INDEX
 
         
    F-2  
    F-3  
    F-4  
    F-5  
    F-6  
    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, 2006 and 2007, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2007. 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, 2006 and 2007, and the consolidated results of their operations and cash flows for each of the three years in the period ended December 31, 2007, in conformity with accounting principles generally accepted in the United States.
 
As discussed in Note 1 to the consolidated financial statements, effective January 1, 2006, the Company adopted Statement of Financial Accounting Standards No. 123 (revised 2004), “Share Based Payment” in accounting for equity-based compensation.
 
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, 2007, 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 28, 2008 expressed an unqualified opinion thereon.
 
/s/  ERNST & YOUNG LLP
 
Dallas, Texas
February 28, 2008


F-2


Table of Contents

COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
 
CONSOLIDATED BALANCE SHEETS
As of December 31, 2006 and 2007
 
                 
    December 31,  
    2006     2007  
    (In thousands)  
 
ASSETS
Cash and Cash Equivalents
  $ 10,715     $ 24,406  
Accounts Receivable:
               
Oil and gas sales
    56,328       73,873  
Joint interest operations
    19,233       16,788  
Other Current Assets
    12,552       9,438  
                 
Total current assets
    98,828       124,505  
Property and Equipment:
               
Unevaluated oil and gas properties
    13,645       18,880  
Oil and gas properties, successful efforts method
    2,511,782       3,173,646  
Other
    8,483       9,777  
Accumulated depreciation, depletion and amortization
    (760,284 )     (979,428 )
                 
Net property and equipment
    1,773,626       2,222,875  
Other Assets
    5,671       7,007  
                 
    $ 1,878,125     $ 2,354,387  
                 
 
LIABILITIES AND STOCKHOLDERS’ EQUITY
Short-term Debt
  $ 3,250     $ 2,588  
Accounts Payable
    132,504       109,195  
Accrued Expenses
    16,107       19,017  
                 
Total current liabilities
    151,861       130,800  
Long-term Debt
    455,000       760,000  
Deferred Income Taxes Payable
    311,236       371,896  
Reserve for Future Abandonment Costs
    57,116       52,606  
Minority Interest in Bois d’Arc Energy
    220,349       267,441  
Commitments and Contingencies
               
Stockholders’ Equity:
               
Common stock — $0.50 par, 50,000,000 shares authorized, 44,395,495 and 45,428,095 shares issued and outstanding at December 31, 2006 and 2007, respectively
    22,197       22,714  
Additional paid-in capital
    367,323       386,986  
Retained earnings
    293,043       361,944  
                 
Total stockholders’ equity
    682,563       771,644  
                 
    $ 1,878,125     $ 2,354,387  
                 
 
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, 2005, 2006 and 2007
 
                         
    2005     2006     2007  
    (In thousands, except per share amounts)  
 
Oil and gas sales
  $ 303,336     $ 511,928     $ 687,073  
Operating expenses:
                       
Oil and gas operating
    50,966       107,303       123,632  
Exploration
    19,725       20,132       43,079  
Depreciation, depletion and amortization
    63,338       153,922       243,619  
Impairment
    3,400       10,444       826  
General and administrative, net
    16,533       31,769       42,682  
                         
Total operating expenses
    153,962       323,570       453,838  
                         
Income from operations
    149,374       188,358       233,235  
Other income (expenses):
                       
Interest income
    1,604       1,012       1,389  
Other income
    209       781       685  
Interest expense
    (20,272 )     (27,429 )     (41,326 )
Gain on sale of shares by Bois d’Arc Energy
    28,797              
Gain (loss) on derivatives
    (13,556 )     10,716        
                         
Total other income (expenses)
    (3,218 )     (14,920 )     (39,252 )
                         
Income before income taxes, minority interest and
                       
equity in earnings of Bois d’Arc Energy
    146,156       173,438       193,983  
Provision for income taxes
    (35,815 )     (74,339 )     (85,177 )
Equity in loss of Bois d’Arc Energy
    (49,862 )            
Minority interest in earnings of Bois d’Arc Energy
          (28,434 )     (39,905 )
                         
Net income
  $ 60,479     $ 70,665     $ 68,901  
                         
Net income per share:
                       
Basic
  $ 1.54     $ 1.67     $ 1.59  
                         
Diluted
  $ 1.47     $ 1.61     $ 1.54  
                         
Weighted average shares outstanding:
                       
Basic
    39,216       42,220       43,415  
                         
Diluted
    41,154       43,556       44,405  
                         
 
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
For the Years Ended December 31, 2005, 2006 and 2007
 
                                         
          Common
    Additional
             
    Common
    Stock
    Paid-In
    Retained
       
    Shares     Par Value     Capital     Earnings     Total  
    (In thousands)  
 
Balance at December 31, 2004
    35,649     $ 17,824     $ 176,130     $ 161,899     $ 355,853  
Public offering of common stock
    4,545       2,273       118,977             121,250  
Stock issuance costs
                (175 )           (175 )
Exercise of stock options and warrants
    2,433       1,217       24,376             25,593  
Tax benefit of stock option exercises
                15,609             15,609  
Stock-based compensation
    342       171       4,079             4,250  
Net income
                      60,479       60,479  
                                         
Balance at December 31, 2005
    42,969       21,485       338,996       222,378       582,859  
                                         
Exercise of stock options and warrants
    1,083       541       15,407             15,948  
Tax benefit of stock option exercises
                6,218             6,218  
Stock-based compensation
    343       171       6,702             6,873  
Net income
                      70,665       70,665  
                                         
Balance at December 31, 2006
    44,395       22,197       367,323       293,043       682,563  
                                         
Exercise of stock options and warrants
    596       298       2,571             2,869  
Tax benefit of stock option exercises
                6,522             6,522  
Stock-based compensation
    437       219       10,570             10,789  
Net income
                      68,901       68,901  
                                         
Balance at December 31, 2007
    45,428     $ 22,714     $ 386,986     $ 361,944     $ 771,644  
                                         
 
The accompanying notes are an integral part of these statements.


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Table of Contents

COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
 
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2005, 2006 and 2007
 
                         
    2005     2006     2007  
          (In thousands)        
 
CASH FLOWS FROM OPERATING ACTIVITIES:
                       
Net income
  $ 60,479     $ 70,665     $ 68,901  
Adjustments to reconcile net income to net cash provided by operating activities, net of acquisition effects:
                       
Stock-based compensation
    5,419       13,249       19,162  
Excess tax benefit from stock based compensation
          (6,218 )     (6,522 )
Depreciation, depletion and amortization
    63,338       153,922       243,619  
Debt issuance costs amortization
    942       1,649       1,158  
Impairment of oil and gas properties
    3,400       10,444       826  
Deferred income taxes
    31,201       66,550       67,780  
Equity in loss of Bois d’Arc Energy
    49,862              
Minority interest in earnings of Bois d’Arc Energy
          28,434       39,905  
Gain on sale of shares by Bois d’Arc Energy
    (28,797 )            
Dry hole costs and leasehold impairments
    16,889       14,351       35,899  
Loss (gain) on derivatives
    13,556       (10,716 )      
Increase in accounts receivable
    (13,030 )     (2,917 )     (15,100 )
Decrease in other current assets
    616       3,526       2,452  
Increase (decrease) in accounts payable and accrued expenses
    14,079       21,666       (11,775 )
                         
Net cash provided by operating activities
    217,954       364,605       446,305  
                         
CASH FLOWS FROM INVESTING ACTIVITIES:
                       
Capital expenditures and acquisitions
    (356,262 )     (529,225 )     (743,041 )
Advances to Bois d’Arc Energy
    (6,421 )            
Repayments from Bois d’Arc Energy
    158,066              
Payments to settle derivatives
    (2,469 )     (526 )      
Deposits paid for offshore leases
                (2,330 )
                         
Net cash used for investing activities
    (207,086 )     (529,751 )     (745,371 )
                         
CASH FLOWS FROM FINANCING ACTIVITIES:
                       
Borrowings
    179,000       190,000       357,000  
Debt issuance costs
          (1,563 )     (385 )
Principal payments on debt
    (339,150 )     (47,000 )     (52,000 )
Proceeds from common stock issuances
    146,843       15,948       2,869  
Proceeds from common stock issuances by Bois d’Arc Energy
          126       693  
Stock issuance costs
    (175 )            
Repurchase of common stock by Bois d’Arc Energy
                (1,942 )
Excess tax benefit from stock based compensation
          6,218       6,522  
                         
Net cash provided by (used for) financing activities
    (13,482 )     163,729       312,757  
                         
Net increase (decrease) in cash and cash equivalents
    (2,614 )     (1,417 )     13,691  
Cash and cash equivalents, beginning of year
    2,703       89       10,715  
Bois d’Arc Energy cash and equivalents as of January 1, 2006
          12,043        
                         
Cash and cash equivalents, end of year
  $ 89     $ 10,715     $ 24,406  
                         
 
The accompanying notes are an integral part of these statements.


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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. (the “Company”) 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
 
The Company is engaged in oil and natural gas exploration, development and production, and the acquisition of producing oil and natural gas properties. The consolidated financial statements include the accounts of Comstock Resources, Inc. and its wholly owned subsidiaries (“Comstock”) and, effective January 1, 2006, Bois d’Arc Energy, Inc. (collectively, “the Company”). The consolidated financial statements also include the accounts of a variable interest entity where the Company is the primary beneficiary of the arrangements. See Note 2. All significant intercompany accounts and transactions have been eliminated in consolidation. The Company accounts for its undivided interest in properties using the proportionate consolidation method, whereby its share of assets, liabilities, revenues and expenses are included in its financial statements.
 
Investment in Bois d’Arc Energy
 
In July 2004 the Company contributed its interests in its Gulf of Mexico properties and assigned to Bois d’Arc Energy, LLC $83.2 million of related debt in exchange for an approximate 60% ownership in Bois d’Arc Energy, LLC. On May 10, 2005 Bois d’Arc Energy, LLC was converted to a corporation and changed its name to Bois d’Arc Energy, Inc. (“Bois d’Arc Energy”). On May 11, 2005 Bois d’Arc Energy completed an initial public offering of 13.5 million shares of common stock at $13.00 per share to the public. Bois d’Arc Energy sold 12.0 million shares of common stock and received net proceeds of $145.1 million and a selling stockholder sold 1.5 million shares. Bois d’Arc Energy used the proceeds from its initial public offering together with borrowings under a new bank credit facility to repay $158.0 million in outstanding advances from Comstock. As a result of Bois d’Arc Energy’s conversion to a corporation and the offering, Comstock’s ownership in Bois d’Arc Energy decreased to 48% and Comstock discontinued accounting for its interest in Bois d’Arc Energy using the proportionate consolidation method and began using the equity method to account for its investment in Bois d’Arc Energy.
 
At the time that Bois d’Arc Energy converted to a corporation, it recorded a tax provision of $108.2 million to record a deferred tax liability. Comstock recognized its proportionate share of this provision for taxes of $64.6 million in its equity in loss of Bois d’Arc Energy in the consolidated statement of operations. In connection with the initial public offering completed by Bois d’Arc Energy, Comstock recognized a gain of $28.8 million on its investment in Bois d’Arc Energy based on Comstock’s share of the amount that Bois d’Arc Energy’s equity was increased as a result of the sale of shares in the offering. Comstock did not previously own interests in a subsidiary which had sold shares. The Company has no present plans for any future sale of Bois d’Arc Energy common stock and has adopted a policy of recognizing its proportional share of the gain when Bois d’Arc Energy sells shares to third parties.
 
During 2006 and 2007, Comstock acquired 2,288,900 additional shares of Bois d’Arc Energy for $36.5 million which increased its ownership of Bois d’Arc Energy’s common stock to 32,224,661 shares or 49%. Comstock also has voting agreements with each of its directors that own shares of Bois d’Arc Energy’s common stock pursuant to which Comstock has the right to vote such shares on behalf of the directors. As a result, the Company has voting control of Bois d’Arc Energy through the combined share ownership by Comstock and the members of its Board of Directors. Upon obtaining voting control of Bois d’Arc Energy,


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Table of Contents

 
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Comstock began including Bois d’Arc Energy in its financial statements as a consolidated subsidiary. The Company currently intends to maintain its controlling interest by acquiring additional shares of Bois d’Arc Energy common stock, through open market purchases and other negotiated transactions, as appropriate. Consolidated revenues, expenses and cash flows for 2006 reflect Bois d’Arc Energy as a consolidated subsidiary as of January 1, 2006. The Company’s financial statements for dates and periods prior to January 1, 2006, have not been adjusted. The inclusion of Bois d’Arc Energy as a consolidated subsidiary in the Company’s financial statements had no impact on the Company’s net income.
 
The following table summarizes the pro forma results as if Bois d’Arc Energy was consolidated in 2005:
 
                         
    Year Ended December 31, 2005  
          Consolidating
    Pro Forma
 
    As Reported     Adjustments     Consolidated  
          (In thousands)        
 
Statement of Operations -
                       
Total oil and gas sales
  $ 303,336     $ 145,906     $ 449,242  
Income from operations
    149,374       60,835       210,209  
Income before income taxes, minority interest and equity in earnings of Bois d’Arc Energy
    146,156       58,659       204,815  
Provision for income taxes
    (35,815 )     (125,808 )     (161,623 )
Minority interest in losses of Bois d’Arc Energy
          17,287       17,287  
Equity interest in losses of Bois d’Arc Energy
    (49,862 )     49,862        
                         
Net income
  $ 60,479     $     $ 60,479  
                         
 
In connection with its acquisitions of 2,288,900 additional common shares of Bois d’Arc Energy in 2006 and 2007, Comstock allocated the $36.5 million purchase price paid for the shares in excess of its underlying net book value in Bois d’Arc Energy of $19.0 million together with the related deferred income tax liability of $10.1 million to oil and gas properties in the accompanying consolidated balance sheet. This additional amount is being amortized over the productive lives of Bois d’Arc Energy’s oil and gas properties using the unit-of-production method. The pro forma impact of the acquisition of these shares was not material to the Company’s historical results of operations.
 
In December 2007, the board of directors of Bois d’Arc Energy approved a repurchase plan providing for repurchases of up to $100.0 million of Common Stock. During 2007, Bois d’Arc Energy repurchased 100,000 shares of outstanding common stock for $1.9 million.
 
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


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Table of Contents

 
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
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, accounts receivable and derivative financial instruments, the Company places its cash with high credit quality financial institutions and its derivative financial instruments with financial institutions and other firms that management believes have high credit rating. 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 collectable. Accordingly, no allowance for doubtful accounts has been provided. Schedule II, Valuation and Qualifying Accounts, was omitted because there were no allowances or other valuation or qualifying accounts.
 
Fair Value of Financial Instruments
 
The carrying amounts of cash and cash equivalents, accounts receivable, accounts payable and accrued expenses approximate fair value due to the short maturity of these instruments.
 
The following table presents the carrying amounts and estimated fair value of the Company’s financial instruments as of December 31, 2006 and 2007:
 
                                 
    2006     2007  
    Carrying
    Fair
    Carrying
    Fair
 
    Value     Value     Value     Value  
          (In thousands)        
 
Long-term debt, including current portion
  $ 455,000     $ 450,406     $ 760,000     $ 750,813  
 
The fair market value of the fixed rate debt was based on the market prices as of December 31, 2006 and 2007. The fair market value of the floating rate date approximates its carrying value.
 
The Company had no derivatives outstanding as of December 31, 2006 and 2007.
 
Other Current Assets
 
Other current assets at December 31, 2006 and 2007 consist of the following:
 
                 
    As of December 31,  
    2006     2007  
    (In thousands)  
 
Prepaid expenses
  $ 9,889     $ 5,873  
Pipe inventory
    1,251       1,520  
Income taxes receivable
    1,386       1,367  
Other
    26       678  
                 
    $ 12,552     $ 9,438  
                 

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Table of Contents

 
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
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 six barrels of oil for one thousand cubic feet of natural gas. Cost centers for amortization purposes for onshore properties are determined on a field area basis and for offshore properties are determined based on wells sharing common production platforms and facilities. 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.
 
The Company assesses the need for an impairment of the costs capitalized for its oil and gas properties costs 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 discounted expected future cash flows. 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. The Company recognized impairment charges related to its oil and gas properties of $3.4 million, $10.4 million and $0.8 million in 2005, 2006, and 2007, respectively. The impairment in 2006 includes $7.9 million related to a property that was held for resale. Subsequently, the plan to sell the property was cancelled. The impairment reflected the property’s estimated fair market value at the time the plan to sell the property changed.
 
Other property and equipment consists primarily of gas gathering systems, computer equipment, furniture and fixtures and interests in private aircraft which are depreciated over estimated useful lives ranging from five to 311/2 years on a straight-line basis.
 
Asset Retirement Obligation
 
The Company records a liability in the period in which an asset retirement obligation (“ARO”) 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 ARO’s relate to future plugging and abandonment costs of its oil and gas properties and related facilities disposal.


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Table of Contents

 
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
The following table summarizes the changes in the Company’s total estimated liability:
 
                         
    2005     2006     2007  
          (In thousands)        
 
Beginning asset retirement obligations
  $ 19,248     $ 3,206     $ 57,116  
Bois d’Arc Energy abandonment liability(1)
    (16,915 )     35,034        
New wells placed on production and changes in estimates
    266       18,134       (8,161 )
Acquisition liabilities assumed
    455       3,346       774  
Liabilities settled
          (5,145 )     (759 )
Accretion expense
    152       2,541       3,636  
                         
Ending asset retirement obligations
  $ 3,206     $ 57,116     $ 52,606  
                         
 
(1) The Company’s share of the asset retirement obligations of Bois d’Arc Energy was reclassified to the Investment in Bois d’Arc Energy upon the change to the equity accounting method in 2005. Concurrent with including Bois d’Arc Energy as a consolidated subsidiary as of January 1, 2006, the asset retirement obligations of Bois d’Arc Energy are included in the Company’s financial statements.
 
Other Assets
 
Other assets primarily consist of deferred costs associated with issuance of the senior notes and the bank credit facilities. These costs are amortized over the eight year 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 prescribed in Statement of Financial Accounting Standards No. 123 (revised 2004), “Share-Based Payment” (“SFAS 123R”) 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. The Company adopted SFAS 123R utilizing the modified prospective transition method and accordingly the financial results for periods prior to January 1, 2006 have not been adjusted. Prior to adopting SFAS 123R the Company followed the fair value based method prescribed in Statement of Financial Accounting Standards No. 123, “Accounting for Stock Based Compensation” for all periods beginning January 1, 2004. Because the Company previously recorded stock-based compensation using the fair value method, adoption of SFAS 123R did not have a significant impact on the Company’s net income or earnings per share for the year ended December 31, 2006.
 
Prior to adopting SFAS 123R, the Company presented all tax benefits of the deductions that resulted from stock-based compensation as cash flows from operating activities. SFAS 123R requires that excess tax benefits on stock-based compensation be recognized as a part of cash flows from financing activities. Comstock’s excess income tax benefit realized from tax deductions associated with stock-based compensation totaled $15.6 million, $6.2 million and $6.5 million for the years ended December 31, 2005, 2006 and 2007, respectively.


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Table of Contents

 
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
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 follows Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”), which requires that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded on the balance sheet as either an asset or liability measured at its fair value. SFAS 133 requires that changes in the derivative’s fair value be 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.
 
Major Purchasers
 
In 2007, the Company had one purchaser of its oil and natural gas production that accounted for 53% of total oil and gas sales. In 2006, the Company had two purchases that accounted for 42% and 13% of total 2006 oil and gas sales. In 2005, Comstock had two purchasers that accounted for 15% and 12% of total 2005 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. The amount of oil or natural gas sold may differ from the amount to which the Company is entitled based on its revenue interests in the properties. The Company did not have any significant imbalance positions at December 31, 2005, 2006 or 2007.
 
General and Administrative Expenses
 
General and administrative expenses are reported net of reimbursements of overhead costs that are allocated to working interest owners of the oil and gas properties operated by the Company.
 
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


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Table of Contents

 
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
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 includes the enactment date.
 
Earnings Per Share
 
Basic and diluted earnings per share for 2005, 2006 and 2007 were determined as follows:
 
                                                             
    2005     2006     2007  
    Income     Shares   Per Share     Income     Shares   Per Share     Income     Shares   Per Share  
    (In thousands except per share data)  
 
Basic Earnings Per Share:
                                                           
Net Income
  $ 60,479     39,216   $ 1.54     $ 70,665     42,220   $ 1.67     $ 68,901     43,415   $ 1.59  
                                                             
Diluted Earnings Per Share:
                                                           
Net Income
  $ 60,479     39,216   $ 1.54     $ 70,665     42,220   $ 1.67     $ 68,901     43,415   $ 1.59  
Effect of Dilutive Securities:
                                                           
Stock Grants and Stock Options
        1,938             (488 )   1,336             (697 )   990        
                                                             
Net Income
  $ 60,479     41,154   $ 1.47     $ 70,177     43,556   $ 1.61     $ 68,204     44,405   $ 1.54  
                                                             
 
Stock options and warrants to purchase common stock at exercise prices in excess of the average actual stock price for the period that were anti-dilutive and that were excluded from the determination of diluted earnings per share are as follows:
 
                         
    2005     2006     2007  
    (In thousands
 
    except per share data)  
 
Weighted average anti-dilutive stock options
    7       117       235  
Weighted average exercise price
  $ 32.50     $ 32.52     $ 32.60  
 
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, 2006 the Company’s cash investments consisted of overnight Eurodollar deposits with a bank and at December 31, 2007 the Company’s cash investments consisted of prime shares in an institutional preferred money market fund with a bank and overnight Eurodollar deposits with a bank.
 
                         
    2005     2006     2007  
    (In thousands)  
 
Cash Payments:
                       
Interest payments
  $ 19,848     $ 25,620     $ 40,530  
Income tax payments
  $ 2,578     $ 5,871     $ 15,817  
 
New Accounting Standards
 
In September 2006, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards No. 157, “Fair Value Measurements” (“SFAS 157”). This statement establishes a framework for fair value measurements in the financial statements by providing a single definition of fair value, provides guidance on the methods used to estimate fair value and increases disclosures about estimates of fair value. SFAS 157 will be effective for financial assets and liabilities in


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Table of Contents

 
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
financial statements issued for fiscal years beginning after November 15, 2007, and will be effective for non-financial assets and liabilities in financial statements issued for fiscal years beginning after November 15, 2008. The Company is currently evaluating the impact of the adoption of this statement on its consolidated financial statements.
 
In December 2007, the FASB concurrently issued Statement of Financial Accounting Standards No. 141(R), “Business Combinations” (“SFAS 141R”) and Statement of Financial Accounting Standards No. 160, “Noncontrolling Interests in Consolidated Financial Statements — An Amendment of ARB No. 51” (“SFAS 160”). Both of these standards require measurements based on fair value as determined under the provisions of SFAS 157 and are effective for financial statements issued for fiscal years beginning after December 15, 2008. In addition, both of these standards also include expanded disclosure requirements.
 
SFAS 141R establishes accounting and reporting standards for how the acquirer of a business recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree. This statement also provides guidance for recognizing and measuring the goodwill acquired in the business combination and determines what information to disclose to enable users of the financial statement to evaluate the nature and financial effects of the business combination. SFAS 141R will impact the accounting and disclosures for any business combinations the Company engages in after January 1, 2009. However, the nature and magnitude of the specific effects will depend upon the nature, terms and size of the acquisitions we consummate after that date.
 
SFAS 160 amends Accounting Research Bulletin 51 to establish accounting and reporting standards for the noncontrolling or minority interest in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. It requires consolidated net income to be reported at amounts that include the amounts attributable to both the parent and the noncontrolling interest. It also requires disclosure, on the face of the consolidated statement of income, of the amounts of consolidated net income attributable to the parent and to the noncontrolling interest. This statement establishes a single method of accounting for changes in a parent’s ownership interest in a subsidiary that do not result in deconsolidation. SFAS 160 clarifies that all such transactions are equity transactions if the parent retains its controlling financial interest in the subsidiary. If there is a loss of control of the subsidiary, SFAS 160 requires the retained interest to be recorded at fair value. The Company is currently evaluating the impact of the adoption of this statement on its consolidated financial statements which is expected to have a significant impact on the Company’s financial statements due to its ownership of Bois d’Arc Energy.
 
(2)   Acquisitions
 
In December 2007, the Company acquired certain oil and gas properties in South Texas for $160.1 million in cash. The Company acquired proved oil and gas reserves of 70.1 billion cubic feet (“Bcf”) of natural gas. The transaction was funded with borrowings under the Company’s bank credit facility and the pro forma effect of the transaction was not material to the Company’s historical results of operations. Concurrent with the December, 2007 acquisition, Comstock entered into a transaction structured as a reverse like-kind exchange in accordance with Section 1031 of the Internal Revenue Code. While the Company intends to obtain tax deferred treatment on gains from future sales of oil and gas properties, no assurance can be given that future sales transactions will qualify as a like-kind exchange or that the Company will achieve any tax-savings as a result of this structure. In connection with this reverse like-kind exchange, Comstock assigned the right to acquire ownership in the oil and gas properties that were acquired in December 2007 to an exchange accommodation titleholder. Comstock operates these properties pursuant


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Table of Contents

 
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
to lease and management agreements. Because the Company is the primary beneficiary of these arrangements, the properties acquired are included in its consolidated balance sheet as of December 31, 2007, and all revenues earned and expenses incurred related to the properties will be included in the Company’s consolidated results of operations during the term of the agreements. These agreements will terminate upon the transfer of the acquired properties from the exchange accommodation titleholder to Comstock no later than June 25, 2008.
 
In June 2007, the Company acquired additional working interests in the Javelina field in Hildalgo County in South Texas for $31.2 million. The additional interests acquired had proved reserves of approximately 9.1 Bcf of natural gas. The transaction was funded with borrowings under the Company’s bank credit facility, and the pro forma impact of this acquisition was not material to the Company’s historical results of operations.
 
In September 2006 the Company acquired oil and gas properties in South Texas for $67.2 million in cash. The Company acquired proved oil and gas reserves of 16.5 Bcfe as well as interest in unevaluated oil and gas reserves. The transaction was funded with borrowings under Comstock’s bank credit facility. The pro forma impact of this acquisition was not material to the Company’s historical results of operations.
 
On May 12, 2005, the Company completed an acquisition of certain oil and gas properties in East Texas, Louisiana and Mississippi and related assets for $190.9 million. The acquisition was funded with proceeds from a public offering of common stock completed in April 2005 and borrowings under Comstock’s bank credit facility. Set forth in the following table is certain unaudited pro forma financial information for the year ended December 31, 2005. This information has been prepared assuming the acquisition in May 2005 was consummated on January 1, 2005 and is based on estimates and assumptions deemed appropriate by the Company. The pro forma unaudited information is presented for illustrative purposes only. If the transaction had occurred in the past, the Company’s operat