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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
FORM 10-K
 
     
(Mark One)    
þ
  ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2005
 
or
o
  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
Commission File No. 0-16741
 
COMSTOCK RESOURCES, INC.
(Exact name of registrant as specified in its charter)
 
     
NEVADA
  94-1667468
(State or other jurisdiction of
incorporation or organization)
  (I.R.S. Employer
Identification Number)
 
5300 Town and Country Blvd., Suite 500, Frisco, Texas 75034
(Address of principal executive offices including zip code)
 
(972) 668-8800
(Registrant’s telephone number and area code)
 
Securities registered pursuant to Section 12(b) of the Act:
 
     
Common Stock, $.50 Par Value
Preferred Stock Purchase Rights
(Title of class)
  New York Stock Exchange
New York Stock Exchange
(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, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):
 
Large accelerated filer þ Accelerated filer o Non-accelerated filer 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 March 15, 2006, there were 42,970,762 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 30, 2005 (the last business day of the registrant’s most recently completed second fiscal quarter), was $1.0 billion.
 
DOCUMENTS INCORPORATED BY REFERENCE
 
Portions of the Proxy Statement for the 2006 Annual Meeting of Stockholders to be held
May 10, 2006 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, 2005
 
CONTENTS
 
               
Item
      Page
 
    Cautionary Note Regarding Forwarding Looking Statements   2
    Definitions   3
  Business and Properties   5
1A.
  Risk Factors   23
1B.
  Unresolved Staff Comments   30
3.
  Legal Proceedings   30
4.
  Submission of Matters to a Vote of Security Holders   30
 
5.
  Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities   31
6.
  Selected Financial Data   32
7.
  Management’s Discussion and Analysis of Financial Condition and Results of Operations   33
7A.
  Quantitative and Qualitative Disclosures About Market Risks   42
8.
  Financial Statements and Supplementary Data   43
9.
  Changes in and Disagreements with Accountants on Accounting and Financial Disclosure   44
9A.
  Controls and Procedures   44
9B.
  Other Information   46
 
10.
  Directors and Executive Officers of the Registrant   46
11.
  Executive Compensation   46
12.
  Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters   46
13.
  Certain Relationships and Related Transactions   46
14.
  Principal Accountant Fees and Services   46
 
15.
  Exhibits and Financial Statement Schedules   47
 Amendment No. 3 to Amended and Restated Credit Agreement
 First Amendment to the Lease Agreement dated August 25, 2005
 Subsidiaries
 Consent of Ernst & Young LLP
 Consent of Independent Petroleum Engineers
 CEO Certification under Section 302
 CFO Certification under Section 302
 CEO Certification under Section 906
 CFO 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.
 
“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.
 
“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.


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“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.
 
“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
 
General
 
Comstock Resources, Inc. 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 natural gas operations are concentrated in the East Texas/North Louisiana, Southeast Texas, South Texas and Mississippi regions. In addition, we have properties in other regions in Arkansas, Kansas, Kentucky, New Mexico and Oklahoma. We also own 48% of Bois d’Arc Energy, Inc. (“Bois d’Arc Energy”), a publicly-held company which conducts exploration, development and production operations in state and federal waters of the Gulf of Mexico. Our onshore oil and natural gas properties are estimated to have proved reserves of 504.7 Bcfe with an estimated PV 10 Value of $1.6 billion as of December 31, 2005 and a standardized measure of discounted future net cash flows of $1.1 billion (see note 1 on page 13 for a discussion of our PV 10 Value and our standardized measure of discounted future net cash flows). Our proved oil and natural gas reserve base is 86% natural gas and 59% proved developed on a Bcfe basis as of December 31, 2005. The proved reserves attributable to our 48% ownership in Bois d’Arc Energy were 155.0 Bcfe with an estimated PV10 value of $0.9 billion as of December 31, 2005 and a standardized measure of discounted future net cash flows of $0.6 billion. Bois d’Arc Energy’s reserves are 64% natural gas and 83% proved developed on a Bcfe basis as of December 31, 2005.
 
Our proved reserves at December 31, 2005 and our 2005 average daily production are summarized below:
 
                                                                 
    Reserves at December 31, 2005     2005 Daily Production  
                      % of
                      % of
 
    Oil     Gas     Total     Total     Oil     Gas     Total     Total  
    (MMBbls)     (Bcf)     (Bcf)           (MBbls/d)     (MMcf/d)     (MMcfe/d)        
 
East Texas/North Louisiana
    1,107       251,983       258,623       51.2 %     0.3       38.7       40.3       44.4 %
Southeast Texas
    2,416       73,111       87,606       17.4 %     0.4       17.5       20.2       22.2 %
South Texas
    863       44,204       49,381       9.8 %     0.2       10.3       11.5       12.7 %
Mississippi
    7,428       849       45,420       9.0 %     1.0             5.8       6.4 %
Other Regions
    229       62,269       63,646       12.6 %     0.1       12.2       13.0       14.3 %
                                                                 
Total
    12,043       432,416       504,676       100.0 %     2.0       78.7       90.8       100.0 %
                                                                 
Share of Bois d’Arc Energy(1)
    9,365       98,770       154,958               1.7       21.5       31.6          
                                                                 
 
 
(1) Represents our proportionate ownership of reserves and production of Bois d’Arc Energy.
 
Strengths
 
High Quality Properties.  Our onshore operations are focused in four primary operating areas, the East Texas/North Louisiana, Southeast Texas, South Texas and Mississippi regions, which account for approximately 51%, 17%, 10% and 9% of our proved reserves, respectively. We have favorable operating costs which results in us having high cash margins. Finally, our properties have an average reserve life of approximately 15.2 years and have extensive development and exploration potential.
 
Successful Exploration and Development Program.  In 2005, we spent $122.2 million on the exploration and development of our onshore oil and natural gas properties for development drilling, recompletions, workovers, abandonment and production facilities. Overall, we drilled 72 development wells, 48.4 net to us, with a 100% success rate. We also drilled three exploratory wells, 1.4 net to us. Only one of the three wells was successful.
 
Successful Acquisitions.  We have had significant growth over the years as a result of acquisitions. Since 1991, we have added 888.5 Bcfe of proved oil and natural gas reserves from 33 acquisitions at an average cost of $0.98 per Mcfe. In 2005 we acquired 121.5 Bcfe of proved oil and natural gas reserves for $201.8 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 76% of our proved onshore oil and natural gas reserve base as of December 31, 2005 and Bois d’Arc Energy operates 98% of its proved oil and natural gas reserve base as of December 31, 2005. 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 888.5 Bcfe of proved oil and natural gas reserves from 33 acquisitions at a total cost of $867.6 million, or $0.98 per Mcfe. The acquisitions were acquired at an average of 61% of their PV 10 Value in the year the acquisitions were completed. In 2005 we acquired 121.5 Bcfe of proved oil and natural gas reserves for $201.8 million or $1.66 per Mcfe. The PV 10 Value of the acquired reserves in 2005 was $355.3 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, improved logging tools, and formation stimulation techniques. During 2005, we spent approximately $87.3 million to drill 72 onshore development wells, 48.4 net to us, all of which were successful. In addition, we spent approximately $17.7 million for leasehold costs and for recompletion and workover activities. Our business plan in 2006 will focus on developing our East Texas/North Louisiana and Mississippi properties. We have budgeted $179.0 million for development drilling and for recompletion and workover activities in 2006 in all of our regions.
 
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, Inc. In addition to Bois d’Arc Energy’s exploration program we have budgeted $21.0 million for exploration in 2006 primarily 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 $200.0 million on our onshore development and exploration projects in 2006. We intend to primarily use operating cash flow to fund our development and exploration expenditures in 2006. We may also make additional property acquisitions in 2006 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 fields as of December 31, 2005:
 
                                                 
    Net Oil     Net Gas     MMcfe     %     PV 10 Value(1)     %  
    (MBbls)     (MMcf)                          
 
East Texas/North Louisiana
                                               
Beckville
    110       75,585       76,247       15.1 %   $ 254,593       16.1 %
Gilmer
    170       35,130       36,147       7.2 %     103,110       6.5 %
Blocker
    104       35,241       35,865       7.1 %     96,174       6.1 %
Cadeville
    81       15,368       15,854       3.1 %     57,089       3.6 %
Darco
    52       14,321       14,630       2.9 %     35,561       2.2 %
Logansport
    39       14,060       14,292       2.8 %     65,358       4.1 %
Douglass
    5       10,468       10,497       2.1 %     15,795       1.0 %
Waskom
    180       7,729       8,806       1.7 %     24,206       1.5 %
Drew
    81       7,327       7,812       1.5 %     23,141       1.5 %
Longwood
    92       5,078       5,627       1.1 %     21,413       1.4 %
Lisbon
    51       4,666       4,971       1.0 %     18,776       1.2 %
Other
    142       27,010       27,875       5.5 %     89,515       5.6 %
                                                 
      1,107       251,983       258,623       51.2 %     804,731       50.8 %
                                                 
Southeast Texas
                                               
Double A Wells
    2,182       64,577       77,670       15.4 %     270,120       17.0 %
Sugar Creek
    82       7,748       8,241       1.6 %     21,307       1.3 %
Other
    152       786       1,695       0.3 %     8,752       0.6 %
                                                 
      2,416       73,111       87,606       17.4 %     300,179       18.9 %
                                                 
South Texas
                                               
J.C. Martin
          15,319       15,319       3.0 %     47,850       3.0 %
Markham
    156       11,639       12,573       2.5 %     54,877       3.5 %
Lopeno
    34       4,634       4,835       1.0 %     13,360       0.8 %
Other
    673       12,612       16,654       3.3 %     61,745       3.9 %
                                                 
      863       44,204       49,381       9.8 %     177,832       11.2 %
                                                 
Mississippi
                                               
Laurel
    7,290             43,740       8.7 %     124,237       7.8 %
Other
    138       849       1,680       0.3 %     5,782       0.4 %
                                                 
      7,428       849       45,420       9.0 %     130,019       8.2 %
                                                 
Mid-Continent
                                               
Southwest Morse
          7,533       7,533       1.5 %     20,669       1.3 %
Other
    62       19,840       20,209       4.0 %     60,754       3.8 %
                                                 
      62       27,373       27,742       5.5 %     81,423       5.1 %
                                                 
Other Areas
                                               
New Albany Shale Gas
          16,752       16,752       3.3 %     51,182       3.2 %
San Juan
    29       14,507       14,683       2.9 %     24,776       1.6 %
Other
    138       3,637       4,469       0.9 %     14,909       1.0 %
                                                 
      167       34,896       35,904       7.1 %     90,867       5.8 %
                                                 
Total
    12,043       432,416       504,676       100.0 %   $ 1,585,051       100.0 %
                                                 
Share of Bois d’Arc Energy(2)
    9,365       98,770       154,958             $ 924,492          
                                                 
 
 
(1) The PV10 Value excludes future income taxes related to the future net cash flows. The standardized measure of future net cash flows at December 31, 2005 was $1.1 billion.
(2) We own a 48% interest in Bois d’Arc Energy through our ownership of its common stock. Following Bois d’Arc Energy’s initial public offering in May 2005, we account for our ownership interest in Bois d’Arc Energy under the equity method.


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East Texas/North Louisiana
 
Approximately 51% or 258.6 Bcfe of our proved reserves are located in East Texas and North Louisiana where we own interests in 670 producing wells, 324.8 net to us, in 31 field areas. We operate 334 of these wells. The largest of our fields in this region are the Beckville, Gilmer, Blocker, Cadeville, Darco, Logansport, Douglass, Waskom, Drew, Longwood and Lisbon fields. Production from this region averaged 38.7 MMcf of natural gas per day and 266 barrels of oil per day during 2005. 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 2005, we spent $71.5 million drilling 52 wells, 40.2 net to us, and $8.6 million on workovers and recompletions in this region. We have budgeted approximately $134.0 million in 2006 for development activities in this region.
 
Beckville
 
Our properties in the Beckville field, located in Panola and Rusk Counties, Texas, have proved reserves of 76.2 Bcfe which represents approximately 15% of our total reserves. We operate 107 wells in this field and own interests in six additional wells for a total of 113 wells, 84.6 net to us. During December 2005, production attributable to our interest from this field averaged 20.2 MMcf of natural gas per day and 11 barrels of oil per day. The Beckville field produces from the Cotton Valley formation at depths ranging from 9,000 to 10,000 feet.
 
Gilmer
 
We own interests in 73 natural gas wells, 27.7 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 36.1 Bcfe which represents 7% of our total reserve base. During December 2005, production attributable to our interest from this field averaged 6.1 MMcf of natural gas per day and 75 barrels of oil per day.
 
Blocker
 
Our proved reserves of 35.9 Bcfe in the Blocker field located in Harrison County, Texas represent approximately 7% of our total reserves. We own interests in 41 wells, 39.8 net to us, and operate 40 of these wells. During December 2005, net daily production attributable to our interest from this field averaged 8.8 MMcf of natural gas and 85 barrels of oil. Most of this production is from the Cotton Valley formation between 8,500 and 10,100 feet.
 
Cadeville
 
Our proved reserves of 15.9 Bcfe in the Cadeville field located in Ouachita Parrish, Louisiana represent approximately 3% of our total reserves. We own interests in 5 wells, 2.0 net to us, and operate 2 of these wells. During December 2005, net daily production attributable to our interest from this field averaged 0.2 MMcf of natural gas. This production is primarily from the Cotton Valley formation between 9,800 and 10,700 feet. We have six proved undeveloped locations in this field.
 
Darco
 
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 14.6 Bcfe in the Darco Field represent approximately 3% of our total reserves. We own interests in 4 wells, 3.0 net to us, and operate all of these wells. During December 2005, net daily production attributable to our interest from this field averaged 0.7 MMcf of natural gas and 7 barrels of oil.
 
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 14.3 Bcfe in the Logansport field represent


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approximately 3% of our total reserves. We own interests in 88 wells, 42.2 net to us, and operate 46 of these wells. During December 2005, net daily production attributable to our interest from this field averaged 2.4 MMcf of natural gas and 7 barrels of oil.
 
Douglass
 
The Douglass field is located in Nacogdoches County, Texas and is productive from stratigraphically trapped reservoirs in the Pettet Lime and Travis Peak formations. These reservoirs are found at depths from 9,200 to 10,300 feet. Our proved reserves of 10.5 Bcfe in the Douglass field represent approximately 2% of our total reserves. We own interests in 15 wells, 8.5 net to us, and operate 9 of these wells. During December 2005, net daily production attributable to our interest from this field averaged 1.0 MMcf of natural gas.
 
Waskom
 
The Waskom field, located in Harrison and Panola Counties in Texas, represents approximately 2% (8.8 Bcfe) of our proved reserves as of December 31, 2005. We own interests in 54 wells in this field, 27.7 net to us, and operate 29 wells in this field. During December 2005, net daily production attributable to our interest averaged 0.9 MMcf of natural gas and 28 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.
 
Drew
 
Our proved reserves of 7.8 Bcfe in the South Drew field located in Ouachita Parrish, Louisiana represent approximately 2% of our total reserves. Production from this field is from the Cotton Valley formation between 9,000 and 9,600 feet. We own interests in 6 wells, 4.4 net to us, and operate 5 of these wells. During December 2005, net daily production attributable to our interest from this field averaged 0.8 MMcf of natural gas and 12 barrels of oil.
 
Longwood
 
The Longwood field, located in Harrison County, Texas primarily produces from stacked sandstone reservoirs of the Travis Peak and Cotton Valley formations at depths ranging from 6,000 to 10,000 feet. We own interests in 26 wells in this field, 20.8 net to us, and operate 22 wells in this field. Our proved reserves of 5.6 Bcfe in the Longwood field represent approximately 1% of our total reserves. During December 2005, net daily production attributable to our interest from this field averaged 0.9 MMcf of natural gas and 22 barrels of oil.
 
Lisbon
 
Our proved reserves of 5.0 Bcfe in the Lisbon field, located in Claiborne Parrish, Louisiana, represent approximately 1% of our total reserves. Production from this field is from the Cotton Valley formation between 8,500 and 9,400 feet. We own interests in 11 wells, 6.3 net to us, and operate 9 of these wells. During December 2005, net daily production attributable to our interest from this field averaged 0.2 MMcf of natural gas and 2 barrels of oil.
 
Southeast Texas
 
Approximately 17.4% or 87.6 Bcfe of our proved reserves are located in Southeast Texas, where we own interests in 87 producing wells, 49.7 net to us, and operate 63 of these wells. Net daily production rates from the area averaged 17.5 MMcf of natural gas and 449 barrels of oil during 2005. We spent $16.0 million in the Southeast Texas region in 2005, primarily for the “Big Sandy” exploration well which was unsuccessful. In 2006, we plan to spend $2.9 million for development activity in this region. Substantially all of the reserves in this region are in the Double A Wells field area in Polk County, Texas and the Sugar Creek field in Tyler County, Texas.


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Double A Wells
 
The Double A Wells field is our largest field area with total estimated proved reserves of 77.7 Bcfe, which is 15% of our total reserves. We own interests in and operate 61 producing wells, 30.9 net to us, in this field in Polk County, Texas. Net daily production from the Double A Wells area averaged 15.0 MMcf of natural gas and 369 barrels of oil during December 2005. These wells typically produce from the Woodbine formation at an average depth of 14,300 feet.
 
Sugar Creek
 
Our proved reserves of 8.2 Bcfe in the Sugar Creek field located in Tyler County, Texas represent approximately 2% of our total reserves. We own interests in 4 wells, 2.6 net to us, and operate 2 of these wells. During December 2005, net daily production attributable to our interest from this field averaged 0.5 MMcf of natural gas and 8 barrels of oil. Production is from the Woodbine formation between 11,000 to 11,200 feet.
 
South Texas
 
Approximately 10%, or 49.4 Bcfe, of our proved reserves are located in South Texas, where we own interests in 291 producing wells, 70.2 net to us. We own interests in ten fields in the region, the largest of which are the J.C. Martin, North Markham, and Lopeno fields. Net daily production rates from the area averaged 10.3 MMcf of natural gas and 205 barrels of oil during 2005. We spent $12.4 million in this region in 2005 to drill 10 wells, 3.5 net to us, and for other development activity. In 2006, we plan to spend approximately $28.0 million primarily for development and exploration activity in this region.
 
J.C. Martin
 
Our largest field in South Texas is the J.C. Martin field which is located in the structurally complex and highly prolific Wilcox Lobo trend in Zapata County, Texas on the Mexico border. We own interests in 90 wells in this field, 14.4 net to us, with proved reserves of 15.3 Bcfe or 3% of our total reserves. During December 2005, net daily production attributable to our interest from this field averaged 3.9 MMcf of natural gas. 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.
 
North Markham
 
The North Markham/North Bay City 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 12.6 Bcfe represent 3% of our total 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 2005, net daily production attributable to our interests from this field average 85 barrels of oil and 0.5 MMcf of gas per day.
 
Lopeno
 
Our proved reserves of 4.8 Bcfe in the Lopeno field represent approximately 1% of our total reserves. We own interests in 26 wells, 5.2 net to us, and operate 3 of these wells. During December 2005, net daily production attributable to our interest from this field averaged 0.5 MMcf of natural gas and 3 barrels of oil.
 
Mississippi
 
Our operations in the Mississippi region are mainly located within the Laurel field, located in Jones County, Mississippi near a structurally complex salt dome. We own interests in and operate 45 producing, wells, 42.3 net to us, in the Laurel field. This field’s estimated proved reserves of 43.7 Bcfe represent 9% of our total 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 high viscosity crude oil from this field is being enhanced through waterflood operations. During December 2005, net daily production attributable to our interests in this field


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averaged 1,385 barrels of oil per day. In 2006, we plan to drill and complete 16 wells, 12.0 net to us, and spend approximately $30.0 million for development and exploration activity in this region.
 
Other Regions
 
Southwest Morse
 
Located in Hutchinson County, Texas, the Southwest Morse field is situated on the edge of the greater Hugoton Field producing complex. Production is from the structurally trapped, underpressured Brown Dolomite formation. The Brown Dolomite reservoir is typically encountered at depths of 2,900 to 3,400 feet. Our proved reserves of 7.5 Bcfe in the Southwest Morse field represent approximately 2% of our total reserves. We own interests in 38 wells, 37.1 net to us, and operate 37 of these wells. During December 2005, net daily production attributable to our interest from this field averaged 1.3 MMcf of natural gas.
 
New Albany Shale Gas
 
The New Albany Shale Gas field is 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 16.8 Bcfe in this field represent approximately 3% of our total reserves. We own interests in and operate 95 wells, 85.5 net to us. During December 2005, net daily production attributable to our interest from this field averaged 0.9 MMcf of natural gas.
 
San Juan
 
Our San Juan Basin properties are located in the west-central portion of the basin in San Juan County, New Mexico. Historically, production has been from multiple sands of the Cretaceous Dakota formation and the prolific Fruitland Coal seams. The Dakota is generally found at about 6,000 feet with the shallower Fruitland seams generally encountered at 2,500 to 3,000 feet. Recent advances in drilling and stimulation procedures have resulted in additional tight gas zones in the intervening Mesaverde and Mancos Shale being targeted. Our proved reserves of 14.7 Bcfe in the San Juan field represent approximately 3% of our total reserves. We own interests in 87 wells, 12.8 net to us. During December 2005, net daily production attributable to our interest from this field averaged 1.2 MMcf of natural gas and 5 barrels of oil.
 
Gulf of Mexico and Bois d’Arc Energy
 
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 contributed interests in our offshore oil and natural gas properties and assigned $83.2 million of related debt in exchange for an approximately 60% ownership interest in Bois d’Arc Energy. Each of the Bois d’Arc Participants contributed its interest in commonly owned Gulf of Mexico properties as well as ownership of Bois d’Arc Offshore, Ltd., the operator of the properties, and assigned in the aggregate $28.2 million of related liabilities in exchange for an approximately 40% aggregate ownership interest in Bois d’Arc Energy. The Bois d’Arc Participants also received $27.6 million in cash to equalize the amount that our debt exceeded our proportional share of the liabilities assigned. We were also reimbursed $12.7 million for advances made under the joint exploration venture for undrilled prospects.


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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 the public offering, we own 48% of Bois d’Arc Energy and we changed our accounting method for our investment in Bois d’Arc Energy to the equity method. Accordingly, effective May 10, 2005 our consolidated financial results no longer include our proportionate interest in the Bois d’Arc Energy operating results.
 
Bois d’Arc Energy owns interests in 46 gross (27.8 net) oil wells and 65 gross (46.8 net) gas wells in the Gulf of Mexico. Bois d’Arc Energy operates 91 of these 111 wells. Thirty-four of these wells were shut-in on December 31, 2005 waiting on third party pipelines to return to service. Bois d’Arc Energy also owns 203,301 (143,519 net) developed acres and 148,438 undeveloped acres in which it owns a 100% interest. Forty-nine percent of the acreage is held by production and 83% of the undeveloped acreage expires between 2008 and 2010.
 
Major Property Acquisitions
 
As a result of our acquisitions, we have added 888.5 Bcfe of proved oil and natural gas reserves since 1991 including 121.5 Bcfe we acquired in 2005.
 
Our largest acquisitions are the following:
 
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 in the acquisition include the Cadeville, Darco, Douglass, Drew 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. Major fields acquired in the acquisition include Southwest Morse and San Juan fields. 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 in the acquisition include the Gilmer field in East Texas, the J.C. Martin and Lopeno fields in South Texas and the New Albany Shale Gas field in Kentucky. 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, we 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.
 
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 Southeast 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


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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, and Longwood 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, 2005:
 
                                 
    Oil
    Gas
    Total
    PV10 Value
 
    (MBbls)     (MMcf)     (MMcfe)     (000’s)  
 
Proved Developed:
                               
Producing
    6,018       211,601       247,707     $ 809,855  
Non-producing
    1,211       43,526       50,797       131,069  
Proved Undeveloped
    4,814       177,289       206,172       644,127  
                                 
Total Proved
    12,043       432,416       504,676       1,585,051  
                                 
Discounted Future Income Taxes
    (471,255 )
         
Standardized Measure of Discounted Future Net Cash Flows(1)
  $ 1,113,796  
         
 
 
(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 following table sets forth our 48% ownership interest in of Bois d’Arc Energy’s estimated proved oil and natural gas reserves and the PV 10 Value as of December 31, 2005:
 
                                 
    Oil
    Gas
    Total
    PV10 Value
 
    (MBbls)     (MMcf)     (MMcfe)     (000’s)  
 
Proved Developed:
                               
Producing
    2,114       20,767       33,453     $ 209,742  
Non-producing
    5,230       63,547       94,926       567,451  
Proved Undeveloped
    2,021       14,456       26,579       147,299  
                                 
Total Proved
    9,365       98,770       154,958       924,492  
                                 
Discounted Future Income Taxes
    (309,570 )
         
Standardized Measure of Discounted Future Net Cash Flows(1)
  $ 614,922  
         
 
 
(1) The PV 10 Value represents the discounted future net cash flows attributable to our proved oil and gas reserves before income tax, discounted at 10%. Although it is a non-GAAP measure, we believe that the presentation of the PV 10 Value is relevant and useful to our investors because it presents the discounted future net cash flows attributable to our proved reserves prior to taking into account corporate future income taxes and our current tax structure. We use this measure when assessing the potential return on investment related to our oil and gas properties. The standardized measure of discounted future net cash flows represents the present value of future cash flows attributable to our proved oil and natural gas reserves after income tax, discounted at 10%.


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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, 2005. The market price for our oil production on December 31, 2005, after basis adjustments, was $49.17 per barrel as compared to $42.17 per barrel on December 31, 2004. The market price received for our natural gas production on December 31, 2005, after basis adjustments, was $8.27 per Mcf as compared to $5.86 per Mcf on December 31, 2004.
 
We did not provide estimates of total proved oil and natural gas reserves during the years ended December 31, 2003, 2004 or 2005 to any federal authority or agency, other than the SEC.
 
Drilling Activity Summary
 
During the three-year period ended December 31, 2005, we drilled development and exploratory wells as set forth in the table below.
 
                                                 
    Year Ended December 31,  
    2003     2004     2005  
    Gross     Net     Gross     Net     Gross     Net  
 
Development Wells:
                                               
Oil
                1       0.6       2       1.9  
Gas
    31       19.2       44       20.0       70       46.5  
Dry
    4       2.8       1       0.3              
                                                 
      35       22.0       46       20.9       72       48.4  
                                                 
Exploratory Wells:
                                               
Oil
    1       .3       4       1.9              
Gas
    13       5.0       9       3.6       1       .2  
Dry
    4       2.1       11       4.5       2       1.2  
                                                 
      18       7.4       24       10.0       3       1.4  
                                                 
Total Wells
    53       29.4       70       30.9       75       49.8  
                                                 


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The wells drilled in 2005 exclude the 22 wells drilled by Bois d’Arc Energy. In 2005 Bois d’Arc Energy drilled the following wells:
 
                 
          Comstock’s
 
    Gross     Net Share  
 
Development Wells:
               
Oil
    3       1.4  
Gas
    6       2.5  
Dry
    2       1.0  
                 
      11       4.9  
                 
Exploratory Wells:
               
Oil
    2       .7  
Gas
    8       3.1  
Dry
    1       .3  
                 
      11       4.1  
                 
Total Wells
    22       9.0  
                 
 
In 2006 to the date of this report, we have drilled 23 development wells, 14.3 net to us. Twenty-two of the wells were successful and one (1.0 net to us) was a dry hole. As of the date of this report, we have seven development wells, 2.9 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, 2005:
 
                                 
    Oil     Gas  
    Gross     Net     Gross     Net  
 
Arkansas
                13       6.9  
Kansas
                12       4.5  
Kentucky
                95       85.5  
Louisiana
    7       2.5       229       96.1  
Mississippi
    54       44.0       2       1.1  
New Mexico
    1       0.2       88       12.8  
Oklahoma
    3       0.5       135       19.4  
Texas
    66       40.9       817       348.5  
Wyoming
                32       2.4  
                                 
Total Wells
    131       88.1       1,423       577.2  
                                 
Share of Bois d’Arc Energy(1)
    34       8.7       33       10.7  
                                 
 
 
(1) We own a 48% interest in Bois d’Arc Energy. At December 31, 2005, Bois d’Arc Energy had eight oil wells and 26 gas wells shut-in awaiting repairs to pipelines in the Gulf of Mexico and four oil wells and six gas wells shut-in awaiting new production facilities.
 
We operate 628 of the 1,554 producing wells presented in the above table. Bois d’Arc Energy operates 47 of its producing wells.


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Acreage
 
The following table summarizes our developed and undeveloped leasehold acreage at December 31, 2005. We have excluded acreage in which our interest is limited to a royalty or overriding royalty interest.
 
                                 
    Developed     Undeveloped  
    Gross     Net     Gross     Net  
 
Arkansas
    1,280       684              
Kansas
    6,400       4,064              
Kentucky
    10,316       8,883       3,320       3,320  
Louisiana
    100,031       63,799       10,132       4,442  
Mississippi
    4,273       1,747       529       305  
New Mexico
    8,400       1,260       144,079       63,394  
Oklahoma
    38,080       5,707              
Texas
    249,253       152,054       38,947       15,706  
Wyoming
    13,440       927              
                                 
Total
    431,473       239,125       197,007       87,167  
                                 
Share of Bois d’Arc Energy(1)
    203,301       68,817       148,438       71,176  
                                 
 
 
(1) We own a 48% interest in Bois d’Arc Energy.
 
Title to our oil and natural gas properties is subject to royalty, overriding royalty, carried and other similar interests and contractual arrangements customary in the oil and gas industry, liens incident to operating agreements and for current taxes not yet due and other minor encumbrances. All of our oil and natural gas properties are pledged as collateral under our bank credit facility. As is customary in the oil and gas industry, we are generally able to retain our ownership interest in undeveloped acreage by production of existing wells, by drilling activity which establishes commercial reserves sufficient to maintain the lease or by payment of delay rentals.
 
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 76% of our 2005 natural gas sales were priced utilizing index prices and approximately 24% were priced utilizing daily spot prices. Two subsidiaries of Shell Oil Company accounted for approximately 15% of our total 2005 sales. Sales to BP Energy Company comprised approximately 12% of our total 2005 sales. The loss of any of the foregoing 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.
 
Bois d’Arc Energy’s oil production is sold at prices tied to the spot oil markets. Bois d’Arc Energy’s natural gas production is sold under short-term contracts and priced based on first of the month index prices or on daily spot market prices. Approximately 43% of Bois d’Arc Energy’s 2005 natural gas sales were priced utilizing index prices and 57% were priced utilizing daily spot prices. Shell Trading (US) Company was Bois d’Arc Energy’s most significant oil purchaser in 2005, accounting for approximately 33% of its total 2005 oil and gas sales. BP Energy Company was Bois d’Arc Energy’s most significant natural gas purchaser in 2005, accounting for approximately 49% of Bois d’Arc Energy’s total 2005 oil and gas sales. The loss of any of the foregoing customers would not have a material adverse effect on Bois d’Arc Energy as there is an available market for its crude oil and natural gas production from other purchasers.


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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.
 
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 wellhead sales of natural gas, effective January 1, 1993. 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.
 
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 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.
 
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.
 
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


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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 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 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


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expenditures, earnings or competitive position, including the suspension or cessation of operations in affected areas. As such, there can be no assurance that material cost and liabilities will not be incurred in the future.
 
The Comprehensive Environmental Response, Compensation and Liability Act, or “CERCLA,” imposes liability, without regard to fault, on certain classes of persons that are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the current or former owner or operator of the disposal site or sites where the release occurred and companies that disposed or arranged for the disposal of hazardous substances. Under CERCLA, such persons may be subject to joint and several liability for the cost of investigating and cleaning up hazardous substances that have been released into the environment, for damages to natural resources and for the cost of certain health studies. In addition, companies that incur liability frequently also confront third party claims because it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment from a polluted site.
 
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.
 
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


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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 32,896 square feet at a monthly rate of $61,680. The lease expires on July 31, 2014. We also own production offices and pipe yard facilities near Marshall and Livingston, Texas, Logansport, Louisiana, Guston, Kentucky and Laurel, Mississippi.
 
Employees
 
As of December 31, 2005, we had 89 employees and utilized contract employees for certain of our field operations. We consider our employee relations to be satisfactory.


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Directors, Executive Officers and Other Management
 
The following table sets forth certain information concerning our executive officers and directors.
 
             
Name
 
Age
 
Position with Company
 
M. Jay Allison
  50   President, Chief Executive Officer and
Chairman of the Board of Directors
Roland O. Burns
  46   Senior Vice President, Chief Financial
Officer, Secretary, Treasurer and Director
Mack D. Good
  55   Chief Operating Officer
Stephen E. Neukom
  56   Vice President of Marketing
Richard G. Powers
  51   Vice President of Land
Daniel K. Presley
  45   Vice President of Accounting and Controller
Richard D. Singer
  51   Vice President of Financial Reporting
Michael W. Taylor
  52   Vice President of Corporate Development
David K. Lockett
  51   Director
Cecil E. Martin, Jr. 
  64   Director
David W. Sledge
  49   Director
Nancy E. Underwood
  54   Director
 
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 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 LLP. During his tenure with Arthur Andersen LLP, 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.
 
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.
 
Richard G. Powers joined us as Land Manager in October 1994 and has been our Vice President of Land since December 1997. Mr. Powers has over 20 years of experience as a petroleum landman. Prior to joining us, Mr. Powers


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was employed for 10 years as land manager for Bridge Oil (U.S.A.), Inc. and its predecessor Pinoak Petroleum, Inc. Mr. Powers received a B.B.A. degree from Texas Christian University in 1976.
 
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 25 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.
 
Michael W. Taylor has been our Vice President of Corporate Development since December 1997 and has served us in various capacities since September 1994. Mr. Taylor has 32 years of experience in the oil and gas business. For 15 years prior to joining us, he had been an independent oil and gas producer and petroleum consultant. Before that time, he worked in various engineering and executive capacities for a major oil company, a small independent producer and an international oil and gas consulting company. Mr. Taylor is a Registered Professional Engineer in the State of Texas and he received a B.S. degree in Petroleum Engineering from Texas A & M University in 1974.
 
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 13 years and has spent the past 25 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, Jr. 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 was recently appointed to 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 presently managing personal oil and gas investments. He served as an area operations manager for 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 1981. Ms. Underwood holds B.S. and J.D. degrees from Emory University and practiced law at an Atlanta, Georgia based law firm before joining Underwood Development Corporation in 1981. Ms. Underwood is involved civically in the Dallas community and currently serves on the boards of the Presbyterian Hospital of Dallas Foundation, the Dallas Historical Society and the Dallas County Advisory Board of the Salvation Army.
 
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 450 Fifth Street, N.W., Washington, D.C. 20549.


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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, that 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, continued hostilities in the Middle East and other sustained military campaigns, and acts of terrorism or sabotage;
 
  •  the actions of the Organization of Petroleum Exporting Countries, or OPEC;
 
  •  domestic government regulation, legislation and policies;
 
  •  the level of global oil and natural gas inventories;
 
  •  technological advances affecting energy consumption;
 
  •  the price and availability of alternative fuels; and
 
  •  overall economic conditions.
 
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.


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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 is beginning to experience 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 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, Southeast Texas, South Texas, Mississippi, the Mid-Continent and other regions, as well as the Gulf of Mexico through our 48% ownership interest in Bois d’Arc Energy we may pursue acquisitions or properties located in other geographic areas.
 
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


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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.
 
Our debt service requirements could adversely affect our operations and limit our growth.
 
We had $243.0 million in debt as of December 31, 2005, and our ratio of total debt to total capitalization was approximately 29%.
 
Our outstanding debt will have important consequences, including, without limitation:
 
  •  a portion of our cash flow from operations will be required to make debt service payments;
 
  •  our ability to borrow additional amounts for working capital, capital expenditures (including acquisitions) or other purposes will be limited; and
 
  •  our debt could limit our ability to capitalize on significant business opportunities, our flexibility in planning for or reacting to changes in market conditions and our ability to withstand competitive pressures and economic downturns.
 
In addition, future acquisition or development activities may require us to alter our capitalization significantly. These changes in capitalization may significantly increase our debt. Moreover, our ability to meet our debt service obligations and to reduce our total debt will be dependent upon our future performance, which will be subject to general economic conditions and financial, business and other factors affecting our operations, many of which are beyond our control. If we are unable to generate sufficient cash flow from operations in the future to service our indebtedness and to meet other commitments, we will be required to adopt one or more alternatives, such as refinancing or restructuring our indebtedness, selling material assets or seeking to raise additional debt or equity capital. We cannot assure you that any of these actions could be effected on a timely basis or on satisfactory terms or that these actions would enable us to continue to satisfy our capital requirements.
 
Our bank credit facility contains a number of significant covenants. These covenants will limit our ability to, among other things:
 
  •  borrow additional money;
 
  •  merge, consolidate or dispose of assets;
 
  •  make certain types of investments;
 
  •  enter into transactions with our affiliates; and
 
  •  pay dividends.
 
Our failure to comply with any of these covenants 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


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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 or pipeline failures;
 
  •  casing collapses;
 
  •  mechanical difficulties, such as lost or stuck oil field drilling and service tools;
 
  •  abnormally pressured formations; and
 
  •  environmental hazards, such as natural gas leaks, oil spills, pipeline ruptures and discharges of toxic gases.
 
If we experience any of these problems, well bores, gathering systems and processing facilities could be affected, which could adversely affect our ability to conduct operations.
 
We could also incur substantial losses as a result of:
 
  •  injury or loss of life;
 
  •  severe damage to and destruction of property, natural resources and equipment;
 
  •  pollution and other environmental damage;
 
  •  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.


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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.
 
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


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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, 2005, 41% of our total proved reserves are undeveloped and 10% 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.
 
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.


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Our insurance coverage may not be sufficient or may not be available to cover some liabilities or losses that we may incur.
 
If we suffer a significant accident or other loss, our insurance coverage will be net of our deductibles and may not be sufficient to pay the full current market value or current replacement value of our lost investment, which could result in a material adverse impact on our operations and financial condition. Our insurance does not protect us against all operational risks. We do not carry business interruption insurance. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. Because third party drilling contractors are used to drill our wells, we may not realize the full benefit of workers’ compensation laws in dealing with their employees. In addition, some risks, including pollution and environmental risks, generally are not fully insurable.
 
We are subject to extensive governmental laws and regulations that may adversely affect the cost, manner or feasibility of doing business.
 
Our operations and facilities are subject to extensive federal, state and local laws and regulations relating to the exploration for, and the development, production and transportation of, oil and natural gas, and operating safety. Future laws or regulations, any adverse changes in the interpretation of existing laws and regulations or our failure to comply with existing legal requirements may harm our business, results of operations and financial condition. We may be required to make large and unanticipated capital expenditures to comply with governmental laws and regulations, such as:
 
  •  lease permit restrictions;
 
  •  drilling bonds and other financial responsibility requirements, such as plug and abandonment bonds;
 
  •  spacing of wells;
 
  •  unitization and pooling of properties;
 
  •  safety precautions;
 
  •  regulatory requirements; and
 
  •  taxation.
 
Under these laws and regulations, we could be liable for:
 
  •  personal injuries;
 
  •  property and natural resource damages;
 
  •  well reclamation costs; and
 
  •  governmental sanctions, such as fines and penalties.
 
Our operations could be significantly delayed or curtailed and our cost of operations could significantly increase as a result of regulatory requirements or restrictions. We are unable to predict the ultimate cost of compliance with these requirements or their effect on our operations.
 
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;


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  •  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.
 
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 2005.


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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  
 
  2004 —      First Quarter   $ 20.88     $ 16.60  
        Second Quarter     24.45       17.84  
        Third Quarter     21.34       16.61  
        Fourth Quarter     23.34       19.63  
                         
  2005 —      First Quarter   $ 30.23     $ 19.90  
        Second Quarter     29.64       20.33  
        Third Quarter     33.60       25.23  
        Fourth Quarter     33.98       27.10  
 
As of March 15, 2006, we had 42,970,762 shares of common stock outstanding, which were held by 353 holders of record and approximately 18,000 beneficial owners who maintain their shares in “street name” accounts.
 
We have never paid cash dividends on our common stock. We presently intend to retain any earnings for the operation and expansion of our business and we do not anticipate paying cash dividends in the foreseeable future. Any future determination as to the payment of dividends will depend upon the results of our operations, capital requirements, our financial condition and such other factors as our board of directors may deem relevant. In addition, we are limited under our bank credit facility and by the terms of the indenture for our senior notes from paying or declaring cash dividends.
 
The following table summarizes certain information regarding our equity compensation plans as of December 31, 2005:
 
                         
    Number of securities
    Weighted average
    Number of securities
 
    to be issued upon
    exercise price of
    authorized for future
 
    exercise of
    outstanding
    issuance under equity
 
    outstanding options     options     compensation plans  
 
Equity compensation plans approved by stockholders
    1,733,970     $ 9.83       302,158 (1)
 
 
(1) Plus 1% of the outstanding shares of common stock each year beginning on each subsequent January 1.


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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, 2005 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.”
 
Statement of Operations Data:
 
                                         
    Year Ended December 31,  
    2001     2002     2003     2004     2005  
    (In thousands, except per share data)  
 
Oil and gas sales
  $ 166,118     $ 142,085     $ 235,102     $ 261,647     $ 303,336  
Operating expenses:
                                       
Oil and gas operating(1)
    31,855       33,499       45,746       52,068       50,966  
Exploration
    6,611       5,479       4,410       15,610       19,725  
Depreciation, depletion and amortization
    47,429       53,155       61,169       63,879       63,338  
Impairment
    1,400             4,255       1,648       3,400  
General and administrative, net
    4,351       5,113       7,006       14,569       16,533  
                                         
Total operating expenses
    91,646       97,246       122,586       147,774       153,962  
                                         
Income from operations
    74,472       44,839       112,516       113,873       149,374  
Other income (expenses):
                                       
Interest income
    196       62       73       1,207       1,603  
Other income
    272       8,027       223       166       209  
Interest expense
    (22,098 )     (31,252 )     (29,860 )     (21,182 )     (20,272 )
Formation costs of Bois d’Arc Energy
                      (1,101 )      
Equity in loss of Bois d’Arc Energy
                            (49,862 )
Gain on sale of stock by Bois d’Arc Energy
                            28,797  
Gain (loss) from derivatives
    243       (2,326 )     (3 )     (155 )     (13,556 )
Loss on early extinguishment of debt
                      (19,599 )      
                                         
      (21,387 )     (25,489 )     (29,567 )     (40,664 )     (53,081 )
                                         
Income from continuing operations before income taxes expense
    53,085       19,350       82,949       73,209       96,294  
Income tax expense
    (18,579 )     (6,773 )     (29,682 )     (26,342 )     (35,815 )
                                         
Net income from continuing operations
    34,506       12,577       53,267       46,867       60,479  
Discontinued operations including gain (loss) on disposal, net of income taxes
    396       (1,072 )                  
Cumulative effect of change in accounting principle
                675              
                                         
Net income
    34,902       11,505       53,942       46,867       60,479  
Preferred stock dividends
    (1,604 )     (1,604 )     (573 )            
                                         
Net income attributable to common stock
  $ 33,298     $ 9,901     $ 53,369     $ 46,867     $ 60,479  
                                         
Basic net income per share:
                                       
From continuing operations
  $ 1.13     $ 0.38     $ 1.65     $ 1.37     $ 1.54  
Discontinued operations
    0.02       (0.04 )                  
Cumulative effect of change in accounting principle
                0.02              
                                         
    $ 1.15       0.34     $ 1.67     $ 1.37     $ 1.54  
                                         
Diluted net income per share:
                                       
From continuing operations
  $ 1.00     $ 0.37     $ 1.51     $ 1.29     $ 1.47  
Discontinued operations
    0.01       (0.03 )                  
Cumulative effect of change in accounting principle
                0.02              
                                         
    $ 1.01     $ 0.34     $ 1.53     $ 1.29     $ 1.47  
                                         
Weighted average shares outstanding:
                                       
Basic
    29,030       28,764       31,964       34,187       39,216  
                                         
Diluted
    34,552       33,901       35,275       36,252       41,154  
                                         
 
 
(1) Includes lease operating costs and production and ad valorem taxes.


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Balance Sheet Data:
 
                                         
    As of December 31,  
    2001     2002     2003     2004     2005  
    (In thousands)  
 
Cash and cash equivalents
  $ 6,122     $ 1,682     $ 5,343     $ 2,703     $ 89  
Property and equipment, net
    636,274       664,208       698,686       827,761       706,928  
Investment in Bois d’Arc Energy
                            252,134  
Total assets
    680,769       711,053       746,356       941,476       1,016,663  
Total debt
    372,464       366,272       306,623       403,150       243,000  
Redeemable convertible preferred stock
    17,573       17,573                    
Stockholders’ equity
    195,668       208,427       289,656       355,853       582,859  
 
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 1,554 (665.3 net to us) producing onshore oil and natural gas wells and we operate 628 of these wells. We also own 48% of the common stock of Bois d’Arc Energy, Inc., an independent exploration company which owns interests in offshore producing oil and natural gas wells in the Gulf of Mexico. 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 $200.0 million in 2006 for development and exploration activities. We plan to drill approximately 137 development wells, 98.2 net to us and 12 exploratory wells, 4.3 net to us. However, the number of wells that we drill in 2006 will be subject to the availability of drilling rigs that we can hire. In addition, we could reduce the wells that we drill if oil and natural gas prices were to decline significantly. 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.
 
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 revenues for 2005 benefited from a general increase in oil and natural gas prices. We have entered into certain derivative instruments on approximately 15% of our anticipated natural gas sales in 2006 to reduce an exposure to natural gas price risk. We may in the future enter into additional arrangements in order to


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reduce our exposure to price risks. Such arrangements may also limit our ability to benefit from increases in oil and natural gas prices.
 
Our operating costs are generally comprised of several components, including costs of field personnel, 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 $3.2 million as of December 31, 2005.
 
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 now own 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 onshore data in the tables below contains the results of operations for our direct ownership in our onshore oil and gas properties. The offshore results for 2005 include our proportionate interest in the operations of Bois d’Arc Energy based upon our ownership interest throughout the periods 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. The results for offshore operations in 2003 and 2004 represent our direct ownership interests in offshore properties that were ultimately contributed to Bois d’Arc Energy upon its formation and our proportionate consolidation of the results of Bois d’Arc Energy from its inception through December 31, 2004.


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Results of Operations
 
Our operating data for the last three years is summarized below:
 
                                 
                Adjustments
       
                To Equity
       
    Onshore     Offshore     Method(1)     Total  
 
Year ended December 31, 2005
                               
Net Production Data:
                               
Oil (MBbls)
    735       615       (313 )     1,037  
Natural gas (MMcf)
    28,742       7,849       (4,342 )     32,249  
Natural gas equivalent (MMcfe)
    33,151       11,537       (6,219 )     38,469  
Average Sales Price:
                               
Oil ($/Bbl)
  $ 49.34     $ 52.42             $ 49.01  
Natural gas ($/Mcf)
  $ 7.95     $ 8.15             $ 7.83  
Average equivalent price ($/Mcfe)
  $ 7.99     $ 8.34             $ 7.89  
Expenses ($ per Mcfe):
                               
Oil and gas operating(2)
  $ 1.34     $ 1.66             $ 1.32  
Depreciation, depletion and amortization(3)
  $ 1.60     $ 1.95             $ 1.64  
Year ended December 31, 2004
                               
Net Production Data:
                               
Oil (MBbls)
    430       1,104             1,534  
Natural gas (MMcf)
    26,388       7,131             33,519  
Natural gas equivalent (MMcfe)
    28,967       13,755             42,722  
Average Sales Price:
                               
Oil ($/Bbl)
  $ 39.96     $ 39.81             $ 39.86  
Natural gas ($/Mcf)
  $ 5.88     $ 6.36             $ 5.98  
Average equivalent price ($/Mcfe)
  $ 5.95     $ 6.49             $ 6.12  
Expenses ($ per Mcfe):
                               
Oil and gas operating(2)
  $ 1.09     $ 1.48             $ 1.22  
Depreciation, depletion and amortization(3)
  $ 1.25     $ 1.94             $ 1.46  
Year ended December 31, 2003
                               
Net Production Data:
                               
Oil (MBbls)
    480       1,135             1,615  
Natural gas (MMcf)
    26,659       7,661             34,320  
Natural gas equivalent (MMcfe)
    29,541       14,468             44,009  
Average Sales Price:
                               
Oil ($/Bbl)
  $ 30.12     $ 30.94             $ 30.70  
Natural gas ($/Mcf)
  $ 5.28     $ 5.83             $ 5.41  
Average equivalent price ($/Mcfe)
  $ 5.26     $ 5.51             $ 5.34  
Expenses ($ per Mcfe):
                               
Oil and gas operating(2)
  $ 1.01     $ 1.11             $ 1.04  
Depreciation, depletion and amortization(3)
  $ 1.10     $ 1.92             $ 1.37  
 
 
(1) Adjustments to eliminate our proportionate share of Bois d’Arc Energy’s operations subsequent to adoption of the equity method of accounting.
(2) Includes lease operating costs and production and ad valorem taxes.
(3) Represents depreciation, depletion and amortization of oil and gas properties only.


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Year Ended December 31, 2005 Compared to Year Ended December 31, 2004
 
Oil and gas sales.  Our oil and gas sales increased $41.7 million (16%) in 2005 to $303.3 million from $261.6 million in 2004. Oil and gas sales from our onshore operations increased to $264.8 million, an increase of $92.4 million or 54%, from $172.4 million in 2004. This increase is attributable to the higher oil and gas prices we realized and increased production from our onshore properties. Our average onshore natural gas price increased by 35% and our average onshore crude oil price increased by 23% in 2005 as compared to prices in 2004. Our onshore production increased by 14% in 2005 over 2004 primarily due to new production from our successful drilling activity and the additional production attributable to the properties we acquired from EnSight in May 2005. Sales from our offshore operations of $96.2 million in 2005 were 8% higher than offshore revenues in 2004 of $89.3 million as higher oil and gas prices realized were offset by lower production. Our average offshore natural gas price increased by 28% and our average crude oil price increased by 32% in 2005 as compared to prices in 2004. Offshore production in 2005 decreased by 16% from production in 2004. The lower offshore production was primarily attributable to the hurricane activity in the Gulf of Mexico that occurred during the third and fourth quarters of 2005 and partially to our lower ownership interest in Bois d’Arc Energy subsequent to the completion of its initial public offering on May 11, 2005.
 
Oil and gas operating expenses.  Our oil and gas operating expenses, including production taxes, decreased $1.1 million (2%) to $51.0 million in 2005 from $52.1 million in 2004. Oil and gas operating expenses per equivalent Mcf produced increased $0.10 to $1.32 in 2005 as compared with $1.22 in 2004. Onshore operating expenses for 2005 of $44.3 million increased by $12.6 million compared to 2004 due to the acquisition of the EnSight properties, the start up of new wells and higher production taxes due to increased oil and gas prices. Offshore oil and gas operating costs for 2005 of $19.1 million decreased $1.2 million (6%) due to our lower ownership interest in certain high lifting cost fields that were contributed to Bois d’Arc Energy.
 
Exploration expense.  In 2005, we incurred $19.7 million in exploration expense as compared to $15.6 million in 2004. Exploration expense in 2005 primarily relates to the exploratory dry hole drilled to test the “Big Sandy” prospect and the acquisition of 3-D seismic data.
 
DD&A.  Depreciation, depletion and amortization (“DD&A”) decreased $0.6 million (1%) to $63.3 million in 2005 from $63.9 million in 2004. DD&A associated with our onshore properties increased by $16.7 million to $52.9 million primarily due to our increased production and an increase in our amortization rate. Our DD&A rate per Mcfe produced for our onshore properties averaged $1.60 in 2005 as compared to $1.25 for 2004. The increase relates to higher costs of properties acquired in late 2004 and in 2005 together with an increase in capitalized costs on our existing properties. DD&A attributable to our offshore properties for 2005 declined primarily due to lower produced volumes. Our DD&A rate per Mcfe produced for offshore properties was essentially unchanged in 2005 from 2004.
 
Impairment.  We recorded impairments to our oil and gas properties of $3.4 million in 2005 and $1.6 million in 2004. These impairments 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.
 
General and administrative expenses.  General and administrative expenses, which are reported net of overhead reimbursements, of $16.5 million for 2005 were 14% higher than general and administrative expenses of $14.6 million for 2004. The increase primarily reflects higher personnel costs in 2005 and additional staffing that was necessitated by the EnSight acquisition.
 
Interest income.  Interest income in 2005 was $1.6 million as compared to $1.2 million in 2004. Included in interest income was $1.2 million in 2005 and $1.1 million in 2004 related to interest received from the other owners of Bois d’Arc Energy.
 
Interest expense.  Interest expense decreased $0.9 million (4%) to $20.3 million in 2005 from $21.2 million in 2004. The decrease was primarily the result of lower borrowings in 2005. Average borrowings under our bank credit facility decreased to $151.9 million in 2005 as compared to $176.7 million for 2004. The average interest rate on the outstanding borrowings under our credit facility increased to 4.6% in 2005 as compared to 3.2% in 2004.


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Equity in earnings.  Commencing May 10, 2005 we began accounting for our share of the earnings from Bois d’Arc Energy under the equity method on an after-tax basis. Accordingly, our results for 2005 include a loss of $49.9 million with respect to our ownership interest in Bois d’Arc Energy. This loss includes a one time provision of $64.6 million associated with recognizing, under the equity method of accounting, our proportionate share of the cumulative deferred tax liabilities recorded by Bois d’Arc Energy when it converted from a limited liability company to a corporation. We also recognized a gain of $28.8 million on our investment in Bois d’Arc Energy based on our share of the amount that Bois d’Arc Energy’s equity increased as a result of the sale of shares in Bois d’Arc Energy’s initial public offering.
 
Derivative losses.  The fair value of the liability for the derivatives we utilize as part of our natural gas price risk management program increased substantially during 2005 due to the increase in natural gas prices that occurred in the last four months of 2005. Since we did not designate these derivative positions as hedges, an unrealized loss of $11.1 million associated with the increase in fair value of these derivative positions was recorded as an expense during 2005. We realized losses of $2.5 million in 2005 to settle derivative positions.
 
Net income.  We reported net income of $60.5 million in 2005, as compared to net income of $46.9 million in 2004. Net income per share for 2005 was $1.47 on 41.2 million weighted average diluted shares outstanding as compared to $1.29 for 2004 on 36.3 million weighted average diluted shares outstanding. Excluding the effect of the one time adjustments for Bois d’Arc Energy’s conversion to a corporation and its initial public offering and the unrealized loss on derivatives, our net income for 2005 would have been $91.0 million or $2.21 per share. The 2004 results include a charge of $19.6 million ($12.5 million after income taxes or $0.35 per diluted share) relating to the early retirement of our 111/4% senior notes.
 
Year Ended December 31, 2004 Compared to Year Ended December 31, 2003
 
Oil and gas sales.  Our oil and gas sales increased $26.5 million or 11% in 2004 to $261.6 million from $235.1 million in 2003. The increase in sales was mostly due to higher natural gas and crude oil prices, which was partially offset by a decrease in our oil and natural gas production in 2004. Our average natural gas price increased by 11% and our average oil price increased by 30%. On an equivalent unit basis, our average price received for our production in 2004 was $6.12 per Mcfe, which was 15% higher than our average price in 2003 of $5.34 per Mcfe. Our natural gas production decreased by 2% and our oil production decreased by 5%. The decrease in production primarily due to the disruption to Bois d’Arc Energy’s production operations caused by Hurricane Ivan. Approximately 1.3 Bcfe of production was deferred in 2004 because of shut-ins due to the hurricane.
 
Oil and gas operating expenses.  Our oil and gas operating expenses, including production taxes, increased $6.3 million (14%) to $52.1 million in 2004 from $45.7 million in 2003. Oil and gas operating expenses per equivalent Mcf produced increased $0.18 (17%) to $1.22 in 2004 from $1.04 in 2003. The increase in operating expenses is due primarily to higher production and ad valorem taxes resulting from the higher oil and gas prices in 2004 and the lower production volumes due to the deferred production during September 2004 in the Gulf of Mexico, which was shut-in due to hurricane activity. In addition, operating expenses in 2004 include $0.7 million for repairs resulting from damage caused by the hurricane activity in the Gulf of Mexico.
 
Exploration expense.  In 2004, we incurred $15.6 million in exploration expense as compared to $4.4 million in 2003. The 2004 expense primarily relates to five exploratory dry holes drilled by Bois d’Arc Energy in the Gulf of Mexico together with six exploratory dry holes drilled in our South Texas region.
 
DD&A.  DD&A increased $2.7 million (4%) to $63.9 million in 2004 from $61.2 million in 2003. DD&A per equivalent Mcf produced for 2004 was $1.46, as compared to $1.37 for 2003. The higher DD&A rates are attributable to increased capitalized costs of our properties.
 
Impairment.  We recorded impairments to our oil and gas properties of $1.6 million in 2004 and $4.3 million in 2003. These impairments relate to some 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.
 
General and administrative expenses.  General and administrative expenses, which are reported net of overhead reimbursements, of $14.6 million for 2004 were $7.6 million higher than general and administrative expenses of $7.0 million for 2003. The increase is primarily related to stock-based compensation expense that we


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recorded in 2004 of $6.2 million, resulting from our adoption of a fair value-based method of accounting for employee stock-based compensation including our employee stock options on January 1, 2004. The remaining increase is a result of higher personnel costs in 2004 and higher professional fees related to the increased compliance costs.
 
Interest income.  Our interest income in 2004 was $1.2 million as compared to $0.1 million in 2003. Included in interest income in 2004 was $1.1 million related to interest paid by the other owners of Bois d’Arc Energy to us.
 
Interest expense.  Interest expense decreased $8.7 million (29%) to $21.2 million in 2004 from $29.9 million in 2003. The decrease is related to the early retirement of $220.0 million of principal amount of our 111/4% senior notes which were refinanced with $175.0 million new 67/8% senior notes along with the borrowings under a new bank credit facility. The refinancing of our 111/4% senior notes reduced our interest expense by $10.8 million on an annual basis. Our average borrowings outstanding under our bank credit facility increased to $176.7 million in 2004 as compared to $119.7 million in 2003. The average interest rate on the outstanding borrowings under the bank credit facility also increased to 3.2% in 2004 as compared to 3.0% in 2003.
 
Net income.  We reported net income of $46.9 million in 2004 as compared to net income of $53.9 million in 2003. Net income per share for 2004 was $1.29 on weighted average diluted shares outstanding of 36.3 million as compared to $1.53 for 2003 on weighted average diluted shares outstanding of 35.3 million. The 2004 results include a charge of $19.6 million ($0.35 per diluted share) relating to the early retirement of our 111/4% senior notes. The 2004 results also include a charge of $1.1 million related to the formation of Bois d’Arc Energy. Net income for 2003 included $0.7 million in income ($0.02 per share) related to the cumulative effect of a change in our accounting for future abandonment cost for our oil and gas properties.
 
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 2005, our net cash flow provided by operating activities totaled $218.0 million. Our other primary sources of funds in 2005 were the proceeds from a public offering of our common stock of $121.2 million and borrowings of $179.0 million under our bank credit facility. In 2004, our net cash flow provided by operating activities totaled $171.4 million and we received proceeds of $175.0 million from a sale of new eight-year 67/8% senior notes. In 2004 we also increased the debt outstanding under our bank credit facility by $142.0 million.
 
Our primary needs for capital, in addition to funding our ongoing operations, relate to the acquisition, development and exploration of our oil and gas properties and the repayment of our debt. In 2005, we incurred capital expenditures of $356.3 million for our acquisition, development and exploration activities. We also repaid $339.2 million of our debt, made advances to Bois d’Arc Energy in the aggregate amount of $6.4 million and received repayment of $158.1 million for outstanding indebtedness owed to us by Bois d’Arc Energy. In 2004, we incurred capital expenditures of $209.8 million primarily for our development and exploration activities. In 2004 we also retired our 111/4% senior notes and we loaned Bois d’Arc Energy $48.3 million.


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Our annual capital expenditure activity is summarized in the following table:
 
                         
    Year Ended December 31,  
    2003     2004     2005  
    (In thousands)  
 
Onshore:
                       
Acquisitions of proved oil and gas properties
  $ 192     $ 61,996     $ 201,788  
Acquisitions of unproved oil and gas properties
    3,129       2,726       1,967  
Developmental leasehold costs
    463       879       3,102  
Workovers and recompletions
    4,529       9,114       14,586  
Development drilling
    14,103       30,819       87,300  
Exploratory drilling
    9,073       11,442       15,210  
                         
      31,489       116,976       323,953  
Offshore(1)
    59,390       92,755       31,881  
Other
    2,051       59       428  
                         
Total
  $  92,930     $ 209,790     $ 356,262  
                         
 
 
(1) Includes all capital expenditures for offshore operations, including our proportionate share of Bois d’Arc Energy’s capital expenditures from July 16, 2004 through December 31, 2004 and from January 1, 2005 through May 9, 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 spent $86.1 million, $146.7 million and $154.0 million on development and exploration activities in 2003, 2004 and 2005, respectively. We have budgeted approximately $200.0 million for development and exploration projects in 2006. We expect to use internally generated cash flow to fund development and exploration activity. Our operating cash flow is highly dependent on oil and natural gas prices, and in particular natural gas prices.
 
In 2005 we acquired producing oil and gas properties in Texas, Louisiana and Mississippi in two acquisitions for an aggregate amount of $201.8 million. We spent $4.8 million and $62.7 million on acquisition activities in 2003 and 2004, respectively. We do not have a specific acquisition budget for 2006 since the timing and size of acquisitions are unpredictable. Smaller acquisitions will generally be funded from operating cash flows. With respect to significant acquisitions, we intend to use borrowings under our bank credit facility, or other debt or equity financings to the extent available, to finance such acquisitions. The availability and attractiveness of these sources of financing will depend upon a number of factors, some of which will relate to our financial condition and performance and some of which will be beyond our control, such as prevailing interest rates, oil and natural gas prices and other market conditions.
 
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 subsidiaries.
 
We also have a $400.0 million bank credit facility with Bank of Montreal, as the administrative agent. The bank credit facility is a four-year revolving credit commitment that matures on February 25, 2008. Indebtedness under the bank credit facility is secured by substantially all of our and our subsidiaries’ assets and is guaranteed by all of our 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, 2005 the borrowing base was $350.0 million. 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 1.25% to 1.75% or the base rate (which is the higher of the prime rate or the federal funds rate) plus 0% to 0.5%. A commitment fee of 0.375% 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, limit the amount of consolidated debt


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that we may incur and limit our ability to make certain loans and investments. The only financial covenants are the maintenance of a current ratio and maintenance of a minimum tangible net worth. We were in compliance with these covenants as of December 31, 2005.
 
In connection with the formation of Bois d’Arc Energy, we made available to Bois d’Arc Energy a revolving line of credit in a maximum outstanding amount of $200.0 million. This line of credit was paid off in full and terminated in connection with Bois d’Arc Energy’s initial public offering.
 
We believe that our cash flow from operations and available borrowings under our bank credit facility will be sufficient to fund our operations and future growth as contemplated under our current business plan. However, if our plans or assumptions change or if our assumptions prove to be inaccurate, we may be required to seek additional capital. We cannot provide any assurance that we will be able to obtain such capital, or if such capital is available, that we will be able to obtain it on acceptable terms.
 
The following table summarizes our aggregate liabilities and commitments by year of maturity:
 
                                                         
    2006     2007     2008     2009     2010     Thereafter     Total  
    (In thousands)  
 
Bank credit facility
  $     $     $ 68,000     $     $     $     $ 68,000  
67/8% senior notes
                                  175,000       175,000  
Interest on debt
    15,867       15,867       12,671       12,031       12,031       14,035       82,502  
Operating leases
    740       740       740       740       740       2,653       6,353  
Contracted drilling services
    44,169       35,710       6,256                         86,135  
                                                         
    $ 60,776     $ 52,317     $ 87,667     $ 12,771     $ 12,771     $ 191,688     $ 417,990  
                                                         
 
Federal Taxation
 
At December 31, 2005, we had federal income tax net operating loss carryforwards of approximately $43.5 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 value 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.
 
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


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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.  The determination of impairment of our oil and gas reserves is based on the oil and gas reserve estimates using projected future oil and natural gas prices that we have determined to be reasonable. The projected prices that we employ represent our long-term oil and natural gas price forecast and may be higher or lower than the December 31, 2005 market prices for crude oil and natural gas. For the impairment review of our oil and gas properties that we conducted as of December 31, 2005, we used oil and natural gas prices that were based on the current futures market. We used oil prices of $63.10, $64.01 and $62.80 per barrel for 2006, 2007 and 2008, respectively, and escalated prices by 3% each year thereafter to a maximum price of $66.60 per barrel. For natural gas we used prices of $10.58, $10.04 and $9.11 per Mcf for 2006, 2007 and 2008, respectively, and escalated prices by 3% each year thereafter to a maximum price of $11.50 per Mcf. To the extent we had used lower prices in our impairment review, an impairment could have been indicated on certain of our oil and gas properties.
 
Accounting for asset retirement obligations.  We adopted Statement of Financial Accounting Standards No. 143 (“SFAS 143”) “Accounting for Asset Retirement Obligations,” on January 1, 2003. This statement requires us to record 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, each quarter, this liability is accreted up to the final retirement cost. The adoption of SFAS 143 on January 1, 2003 resulted in a cumulative effect adjustment to record (i) a $3.7 million decrease in the carrying value of our oil and gas properties, (ii) a $3.3 million decrease in accumulated depreciation, depletion and amortization, (iii) a $1.5 million decrease in reserve for future abandonment, and (iv) a loss of $675,000 which was reflected as the cumulative effect of a change in accounting principle. The determination of our asset retirement obligations is based on our estimate of the future cost to plug and abandon our oil and gas wells and to dismantle and dispose of our offshore production facilities. The actual costs could be higher or lower than our current estimates.
 
Stock-based compensation.  Prior to January 1, 2004, we accounted for employee stock-based compensation using the intrinsic value method prescribed in Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees” (“APB 25”). Under the intrinsic method, compensation cost for stock options is measured as the excess, if any, of the fair value of our common stock at the date of the grant over the amount an employee must pay to acquire the common stock. Effective January 1, 2004, we changed our method of accounting for employee stock-based compensation to the preferable fair value based method prescribed in Statement of Financial Accounting Standards No. 123, “Accounting for Stock-Based Compensation” (“SFAS 123”). 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. We determine the fair value of each stock option at the date of grant using the Black-Scholes options pricing model. Under the modified prospective transition method selected by us as described in Statement of Financial Accounting Standards No. 148, “Accounting for Stock-Based Compensation — Transition and Disclosure,” stock-based compensation expense recognized for 2004, is the same as that which would have been recognized had the fair value method of SFAS 123 been applied from its original effective date. Accordingly, our general and administrative expenses included $6.2 million and $5.4 million in stock-based compensation in 2004 and 2005, respectively. In accordance with the modified prospective transition method, results for years prior to 2004 were not restated. For years prior to 2004, no compensation cost was recognized for our employee stock options. If compensation costs had been determined in accordance with SFAS 123, we would have recorded an additional compensation expense of $3.0 million in 2003.


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Included in our 2004 and 2005 stock-based compensation expense was $1.5 million and $1.2 million, respectively, attributable to our ownership in Bois d’Arc Energy. In connection with its formation, Bois d’Arc Energy established a long-term incentive plan to provide for equity-based compensation for its executive officers, employees and consultants. The awards made under this plan were comprised of either options to purchase class B LLC units or restricted class C LLC units, representing solely a profits interest. All of the awards made under the Bois d’Arc Energy incentive plan vest over a five year period. At the time of its formation, Bois d’Arc Energy granted options to purchase a total of 2,800,000 class B units at an exercise price of $6.00 per unit and 4,290,000 restricted class C units. In determining the fair value of the class B units and class C units underlying the equity awards granted, Bois d’Arc Energy used a valuation methodology that it believes is consistent with the practices recommended by the AICPA Audit and Accounting Practice Aid Series, Valuation of Privately-Held-Company Equity Securities Issued as Compensation (the “Practice Aid”). Bois d’Arc Energy reviewed the guidance set forth in the Practice Aid and performed a retrospective valuation on a “top down” basis, using an enterprise valuation model. Bois d’Arc Energy determined the fair value of the entity and then allocated the enterprise value to the various classes of member units. Bois d’Arc Energy also consulted with an independent valuation specialist regarding the methods and procedures used to determine, on a retrospective basis, the fair value of the class B units and the class C units at the time of issuance. The valuation conducted determined that the fair value of a class B unit at the date of the issuance was $8.42 per unit. The fair value of a class C unit was determined to be $3.40 per unit. The fair value of each option awarded under the incentive plan was estimated using the Black-Scholes option-pricing model and determined to be $4.55 per option.
 
New accounting standards.  On December 16, 2004, the FASB issued Statement 123 (revised 2004), “Share-Based Payment” (“SFAS 123 R”) that requires compensation costs related to share-based payment transactions (issuance of stock options and restricted stock) to be recognized in the financial statements. With limited exceptions, the amount of compensation cost is to be measured based on the grant date fair value of the equity or liability instruments issued. Compensation cost is recognized over the period that an employee provides service in exchange for the award. Statement 123 R replaces SFAS 123, “Accounting for Stock-Based Compensation,” and supersedes APB 25. SFAS 123 R is effective for the first reporting period after June 15, 2005. Entities that use the fair value-based method for either recognition or disclosure under SFAS 123 are required to apply SFAS 123 R using a modified version of prospective application whereby the entity is required to record compensation expense for all awards it grants after the date of adoption and the unvested portion of previously granted awards that remain outstanding at the date of adoption. Effective January 1, 2004, we adopted the fair value-based measure as proscribed in SFAS 123 using the modified prospective application. Therefore, SFAS 123 R will not have a significant impact on us.
 
Related Party Transactions
 
In recent years, we have not entered into any material transactions with our officers or directors apart from the compensation they are provided for their services. We also have not entered into any business transactions with our significant stockholders or any other related parties.
 
ITEM 7A.   QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET 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


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on our financial condition, results of operations and capital resources. Based on our oil and natural gas production in 2005, 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 $1.0 million and a $1.00 change in the price per Mcf of natural gas would have changed our cash flow by approximately $31.0 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. We realized $2.5 million in losses in 2005 related to our derivatives held for natural gas price risk management. 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.
 
The following table sets forth the derivative financial instruments which relate to our 2006 natural gas production:
 
                                     
        Volume
        Type of
  Floor
    Ceiling
 
Period Beginning
 
Period Ending
  MMBtu    
Delivery Location
  Instrument   Price     Price  
 
January 1, 2006
  December 31, 2006     3,072,000     Henry Hub   Collar   $ 4.50     $ 9.02  
January 1, 2006
  December 31, 2006     2,400,000     Houston Ship Channel   Collar   $ 4.50     $ 8.25  
 
The fair market value of these derivative financial instruments at December 31, 2005 was a liability of $11.2 million. We did not designate these instruments as cash flow hedges and, accordingly, recognized unrealized losses on derivatives of $11.1 million in 2005 to reflect the change in these liabilities.
 
Interest Rates
 
At December 31, 2005, we had long-term debt of $243.0 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, 2005 was $171.3 million based on the market price of 98% of the face amount. At December 31, 2005, we had $68.0 million outstanding under our bank credit facility, which was subject to floating market rates of interest. Borrowings under the bank credit facility bear interest at a fluctuating rate that is tied to LIBOR or the corporate base rate, at our option. Any 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, 2005, a 100 basis point change in interest rates would change our interest expense on our variable rate debt by approximately $0.7 million. We had no interest rate derivatives outstanding during 2005 or at December 31, 2005.
 
ITEM 8.   FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
 
Our consolidated financial statements are included on pages F-1 to F-29 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


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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 DISCLOSURE
 
None.
 
ITEM 9A.   CONTROLS AND PROCEDURES
 
Evaluation of disclosure controls and procedures.  Our chief executive officer and our 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 2005 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
 
Management’s Report on Internal Control Over Financial Reporting
 
The management of Comstock Resources, Inc. (the “Company”) is responsible for establishing and maintaining adequate internal control over financial reporting. The Company’s internal control over financial reporting is a process designed under the supervision of the Company’s Chief Executive Officer and Chief Financial Officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the Company’s financial statements for external purposes in accordance with generally accepted accounting principles.
 
As of December 31, 2005, 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, 2005, 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 audit report on management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2005. The report, which expresses unqualified opinions on management’s assessment and on the effectiveness of the Company’s internal control over financial reporting as of December 31, 2005 is included below.


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Report of Independent Registered Public Accounting Firm
on Internal Control over Financial Reporting
 
The Board of Directors and Stockholders
Comstock Resources, Inc.
 
We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control Over Financial Reporting, that Comstock Resources, Inc. maintained effective internal control over financial reporting as of December 31, 2005, 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. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of 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, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, 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, management’s assessment that Comstock Resources, Inc. maintained effective internal control over financial reporting as of December 31, 2005, is fairly stated, in all material respects, based on the COSO criteria. Also, in our opinion, Comstock Resources, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, 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, 2005 and 2004, and the related consolidated statements of operations, stockholders’ equity and comprehensive income, and cash flows for the years in the period ended December 31, 2005 of Comstock Resources, Inc. and our report dated March 13, 2006 expressed an unqualified opinion thereon.
 
/s/  ERNST & YOUNG LLP
 
Dallas, Texas
March 13, 2006


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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 our definitive proxy statement which will be filed with the Securities and Exchange Commission within 120 days after December 31, 2005.
 
Code of Ethics.  We have 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 also have 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 2006 annual meeting, which will be filed with the SEC within 120 days of December 31, 2005, 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, 2005.
 
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, 2005.
 
ITEM 13.   CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
 
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, 2005.
 
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, 2005.


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PART IV
 
ITEM 15.   EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
 
(a) Financial Statements:
 
1. The following consolidated financial statements and notes are included on Pages F-2 to F-51 of this report.
 
                 
    COMSTOCK RESOURCES, INC. AND SUBSIDIARIES:    
    Report of Independent Registered Public Accounting Firm   F-2
    Consolidated Balance Sheets as of December 31, 2004 and 2005   F-3
    Consolidated Statements of Operations for the Years Ended December 31, 2003, 2004 and 2005   F-4
    Consolidated Statements of Stockholders’ Equity and Comprehensive Income for the Years Ended December 31, 2003, 2004 and 2005   F-5
    Consolidated Statements of Cash Flows for the Years Ended December 31, 2003, 2004 and 2005   F-6
    Notes to Consolidated Financial Statements   F-7
 
         
BOIS d’ARC ENERGY, INC. AND SUBSIDIARIES:
   
Report of Independent Registered Public Accounting Firm   F-30
Consolidated Balance Sheets as of December 31, 2004 and 2005   F-31
Combined Statements of Operations for the Year Ended December 31, 2003 and the period from January 1, 2004 to July 15, 2004 and Consolidated Statements of Operations for the period from Inception (July 16, 2004) to December 31, 2004 and the Year Ended December 31, 2005   F-32
Combined Statement of Changes in Equity for the Year Ended December 31, 2003, Consolidated Statement of Changes in Members’ Equity for the Year Ended December 31, 2004 and Consolidated Statement of Changes in Members’ and Stockholders’ Equity for the Year Ended December 31, 2005   F-33
Combined Statements of Cash Flows for the Year Ended December 31, 2003 and the period from January 1, 2004 to July 15, 2004 and Consolidated Statements of Cash Flows for the period from Inception (July 16, 2004) to December 31, 2004 and the Year Ended December 31, 2005   F-34
Notes to Combined and Consolidated Financial Statements   F-35
 
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).


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Exhibit No.
 
Description
 
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).
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
  Amended and Restated Credit Agreement, dated February 25, 2004, 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 10.7 to our Annual Report on Form 10-K for the year ended December 31, 2003).
10.2
  Amendment No. 1 dated March 31, 2004 to the Amended and Restated Credit Agreement, among Comstock, the lenders named therein, Bank of Montreal, as administrative agent and issuing bank (incorporated by reference to Exhibit 10.1 to our Quarterly Report on Form 10-Q the quarter ended June 30, 2004).
10.3
  Amendment No. 2 dated July 16, 2004 to the Amended and Restated Credit Agreement among Comstock, the lenders named therein, and the Bank of Montreal, as administrative agent and issuing bank (incorporated by reference to Exhibit 10.2 to our Quarterly Report on Form 10-Q the quarter ended March 31, 2004).
10.4*
  Amendment No. 3 dated December 30, 2005 to the Amended and Restated Credit Agreement among Comstock, the lenders names therein, and the Bank of Montreal, as administrative agent and issuing bank.
10.5#
  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).
10.6#
  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).
10.7#
  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).
10.8#
  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).
10.9#
  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).
10.10#
  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).

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Exhibit No.
 
Description
 
10.11#   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).
10.12#   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).
10.13   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).
10.15   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. Blackie, 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).
10.16   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. 33-119511)).
10.17   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).
10.18   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).
10.19*   First Amendment to the Lease Agreement dated August 25, 2005 between Stonebriar I Office Partners, Ltd. and Comstock Resources, Inc.
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: March 15, 2006
 
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)   March 15, 2006
         
/s/  ROLAND O. BURNS

Roland O. Burns
  Senior Vice President, Chief Financial Officer, Secretary, Treasurer and Director (Principal Financial and Accounting Officer)   March 15, 2006
         
/s/  DAVID K. LOCKETT

David K. Lockett
  Director   March 15, 2006
         
/s/  CECIL E. MARTIN, JR.

Cecil E. Martin, Jr.
  Director   March 15, 2006
         
/s/  DAVID W. SLEDGE

David W. Sledge
  Director   March 15, 2006
         
/s/  NANCY E. UNDERWOOD

Nancy E. Underwood
  Director   March 15, 2006


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Table of Contents

INDEX
 
         
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES:
   
  F-2
  F-3
  F-4
  F-5
  F-6
  F-7
       
BOIS d’ARC ENERGY, INC. AND SUBSIDIARIES:
   
  F-30
  F-31
Combined Statements of Operations for the Year Ended December 31, 2003 and the period from January 1, 2004 to July 15, 2004 and Consolidated Statements of Operations for the period from Inception (July 16, 2004) to December 31, 2004 and the Year Ended December 31, 2005
  F-32
Combined Statement of Changes in Equity for the Year Ended December 31, 2003, Consolidated Statement of Changes in Members’ Equity for the Year Ended December 31, 2004 and Consolidated Statement of Changes in Members’ and Stockholders’ Equity for the Year Ended December 31, 2005
  F-33
Combined Statements of Cash Flows for the Year Ended December 31, 2003 and the period from January 1, 2004 to July 15, 2004 and Consolidated Statements of Cash Flows for the period from Inception (July 16, 2004) to December 31, 2004 and the Year Ended December 31, 2005
  F-34
  F-35


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, 2005 and 2004, and the related consolidated statements of operations, stockholders’ equity and comprehensive income, and cash flows for each of the three years in the period ended December 31, 2005. 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 audit provides 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, 2005 and 2004, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2005, in conformity with accounting principles generally accepted in the United States.
 
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Comstock Resources, Inc.’s internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 13, 2006 expressed an unqualified opinion thereon.
 
As discussed in Note 1 to the consolidated financial statements, on January 1, 2003, the Company adopted Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations and on January 1, 2004 the Company changed its method of accounting for employee stock based compensation to the fair value based method.
 
/s/  ERNST & YOUNG LLP
 
Dallas, Texas
March 13, 2006


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Table of Contents

COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
 
CONSOLIDATED BALANCE SHEETS
As of December 31, 2004 and 2005
 
                 
    December 31,  
    2004     2005  
    (In thousands)  
 
ASSETS
Cash and Cash Equivalents
  $ 2,703     $ 89  
Accounts Receivable:
               
Oil and gas sales
    29,822       37,646  
Joint interest operations
    9,146       5,553  
Other Current Assets
    6,544       9,482  
                 
Total current assets
    48,215       52,770  
Property and Equipment:
               
Unevaluated oil and gas properties
    14,811       10,723  
Oil and gas properties, successful efforts method
    1,249,023       1,018,341  
Other
    4,273       3,342  
Accumulated depreciation, depletion and amortization
    (440,346 )     (325,478 )
                 
Net property and equipment
    827,761       706,928  
Investment in Bois d’Arc Energy
          252,134  
Receivable from Bois d’Arc Energy
    59,417        
Other Assets
    6,083       4,831  
                 
    $ 941,476     $ 1,016,663  
                 
 
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Portion of Long-Term Debt
  $ 150     $  
Accounts Payable
    44,512       44,216  
Accrued Expenses
    19,107       12,659  
Unrealized Loss on Derivatives
    155       11,242  
                 
Total current liabilities
    63,924       68,117  
Long-Term Debt, less current portion
    403,000       243,000  
Deferred Income Taxes Payable
    99,451       119,481  
Reserve for Future Abandonment Costs
    19,248       3,206  
Commitments and Contingencies
               
Stockholders’ Equity:
               
Common stock — $0.50 par, 50,000,000 shares authorized, 35,648,742 and 42,969,262 shares issued and outstanding at December 31, 2004 and 2005, respectively
    17,824       21,485  
Additional paid-in capital
    176,130       338,996  
Retained earnings
    161,899       222,378  
                 
Total stockholders’ equity
    355,853       582,859  
                 
    $ 941,476     $ 1,016,663  
                 
 
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 OPERATIONS
For the Years Ended December 31, 2003, 2004 and 2005
 
                         
    2003     2004     2005  
    (In thousands, except per
 
    share amounts)  
 
Oil and gas sales
  $ 235,102     $ 261,647     $ 303,336  
Operating expenses:
                       
Oil and gas operating
    45,746       52,068       50,966  
Exploration
    4,410       15,610       19,725  
Depreciation, depletion and amortization
    61,169       63,879       63,338  
Impairment
    4,255       1,648       3,400  
General and administrative, net
    7,006       14,569       16,533  
                         
Total operating expenses
    122,586       147,774       153,962  
                         
Income from operations
    112,516       113,873       149,374  
Other income (expenses):
                       
Interest income
    73       1,207       1,604  
Other income
    223       166       209  
Interest expense
    (29,860 )     (21,182 )     (20,272 )
Formation costs of Bois d’Arc Energy
          (1,101 )      
Equity in loss of Bois d’Arc Energy
                (49,862 )
Gain on sale of shares by Bois d’Arc Energy
                28,797  
Loss on derivatives
    (3 )     (155 )     (13,556 )
Loss on early extinguishment of debt
          (19,599 )      
                         
      (29,567 )     (40,664 )     (53,080 )
                         
Income before income taxes
    82,949       73,209       96,294  
Provision for income taxes
    (29,682 )     (26,342 )     (35,815 )
                         
Net income before cumulative effect of change in accounting principle
    53,267       46,867       60,479  
Cumulative effect of change in accounting principle, net of income taxes
    675              
                         
Net income
    53,942       46,867       60,479  
Preferred stock dividends
    (573 )            
                         
Net income attributable to common stock
  $ 53,369     $ 46,867     $ 60,479  
                         
Basic net income per share:
                       
Net income before cumulative effect of change in accounting principle
  $ 1.65     $ 1.37     $ 1.54  
Cumulative effect of change in accounting principle
    0.02              
                         
Net income
  $ 1.67     $ 1.37     $ 1.54  
                         
Diluted net income per share:
                       
Net income before cumulative effect of change in accounting principle
  $ 1.51     $ 1.29     $ 1.47  
Cumulative effect of change in accounting principle
    0.02              
                         
Net income
  $ 1.53     $ 1.29     $ 1.47  
                         
Weighted average shares outstanding:
                       
Basic
    31,964       34,187       39,216  
                         
Diluted
    35,275       36,252       41,154  
                         
 
The accompanying notes are an integral part of these statements.


F-4


Table of Contents

COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
 
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
AND COMPREHENSIVE INCOME
For the Years Ended December 31, 2003, 2004 and 2005
 
                                                 
                      Deferred
    Accumulated
       
          Additional
          Compensation
    Other
       
    Common
    Paid-In
    Retained
    Restricted
    Comprehensive
       
    Stock     Capital     Earnings     Stock Grants     Income     Total  
    (In thousands)  
 
Balance at December 31, 2002
  $ 14,460     $ 133,828     $ 61,663     $   (1,487 )   $      (37 )   $ 208,427  
Conversion of preferred stock
    2,197       15,376                         17,573  
Value of stock options issued for exploration prospects, net of deferred income taxes
          4,907                         4,907  
Exercise of stock options
    287       2,741                         3,028  
Tax benefit of stock option exercises
          1,956                         1,956  
Stock-based compensation
    210       7,434             (7,285 )           359  
Preferred stock dividends
                (573 )                 (573 )
Net income
                53,942                   53,942  
Unrealized hedge gains, net of income taxes
                            37       37  
                                                 
Balance at December 31, 2003
    17,154       166,242       115,032       (8,772 )           289,656  
                                                 
Adoption of SFAS 123
          (8,772 )           8,772              
Value of stock options issued for exploration prospects, net of deferred income taxes
          1,512                         1,512  
Exercise of stock options
    532       8,847                         9,379  
Tax benefit of stock option exercises
          3,732                         3,732  
Stock-based compensation
    138       4,569                         4,707  
Net income
                46,867                   46,867  
                                                 
Balance at December 31, 2004
    17,824       176,130       161,899                   355,853  
                                                 
Public offering of common stock
    2,273       118,977                         121,250  
Stock issuance costs
          (175 )                       (175 )
Exercise of stock options
    1,217       24,376                         25,593  
Tax benefit of stock option exercises
          15,609                         15,609  
Stock-based compensation
    171       4,079                         4,250  
Net income
                60,479                   60,479  
                                                 
Balance at December 31, 2005
  $  21,485     $ 338,996     $ 222,378     $     $       —     $ 582,859  
                                                 
 
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, 2003, 2004 and 2005
 
                         
    2003     2004     2005  
    (In thousands)  
 
CASH FLOWS FROM OPERATING ACTIVITIES:
                       
Net income
  $ 53,942     $ 46,867     $ 60,479  
Adjustments to reconcile net income to net cash provided by operating activities, net of acquisition effects:
                       
Cumulative effect of change in accounting principle, net of income taxes
    (675 )            
Stock-based compensation
    359       6,208       5,419  
Depreciation, depletion and amortization
    61,169       63,879       63,338  
Debt issuance costs amortization
    1,200       970       942  
Impairment of oil and gas properties
    4,255       1,648       3,400  
Deferred income taxes
    27,982       20,739       31,201  
Equity in loss of Bois d’Arc Energy
                49,862  
Gain on sale of shares by Bois d’Arc Energy
                (28,797 )
Dry hole costs and leasehold impairments
    3,723       16,151       16,889  
Loss on derivatives
          155       13,556  
Loss on early extinguishment of debt
          19,599        
Decrease (increase) in accounts receivable
    (10,450 )     5,584       (13,030 )
Decrease (increase) in other current assets
    (2,124 )     (1,735 )     616  
Increase (decrease) in accounts payable and accrued expenses
    14,404       (8,714 )     14,079  
                         
Net cash provided by operating activities
     153,785       171,351       217,954  
                         
CASH FLOWS FROM INVESTING ACTIVITIES:
                       
Capital expenditures and acquisitions
    (92,930 )     (209,790 )     (356,262 )
Formation of Bois d’Arc Energy, net of cash acquired
          (48,271 )      
Advances to Bois d’Arc Energy
                (6,421 )
Repayments from Bois d’Arc Energy
                158,066  
Payments to settle derivatives
                (2,469 )
                         
Net cash used for investing activities
    (92,930 )     (258,061 )     (207,086 )
                         
CASH FLOWS FROM FINANCING ACTIVITIES:
                       
Borrowings
    23,402       272,673       179,000  
Proceeds from senior notes offering
          175,000        
Debt issuance costs
          (5,963 )      
Principal payments on debt
    (83,051 )     (367,019 )     (339,150 )
Proceeds from common stock issuances
    3,028       9,379       146,843  
Stock issuance costs
                (175 )
Dividends paid on preferred stock
    (573 )            
                         
Net cash provided by (used for) financing activities
    (57,194 )     84,070       (13,482 )
                         
Net increase (decrease) in cash and cash equivalents
    3,661       (2,640 )     (2,614 )
Cash and cash equivalents, beginning of year
    1,682       5,343       2,703  
                         
Cash and cash equivalents, end of year
  $ 5,343     $ 2,703     $ 89  
                         
 
The accompanying notes are an integral part of these statements.


F-6


Table of Contents

 
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 
(1)   Summary of Significant Accounting Policies
 
Accounting policies used by Comstock Resources, Inc. (“Comstock” or 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
 
Comstock 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 and its wholly owned subsidiaries. All significant intercompany accounts and transactions have been eliminated in consolidation. We account for our undivided interest in properties using the proportionate consolidation method, whereby our share of assets, liabilities, revenues and expenses are included in our financial statements.
 
Formation of and Investment in Bois d’Arc Energy
 
In July 2004, Bois d’Arc Energy, LLC (“Bois d’Arc Energy”) was formed by Comstock Offshore, LLC (“Comstock Offshore”), an indirect wholly-owned subsidiary of the Company, and Bois d’Arc Resources, Ltd. (“Bois d’Arc Resources”), Bois d’Arc Offshore, Ltd. and certain participants in their exploration activities (collectively, the “Bois d’Arc Participants”) to replace a joint exploration venture established in 1997 by Comstock Offshore and Bois d’Arc Resources to explore for oil and natural gas in the Gulf of Mexico. Under the joint exploration venture, Bois d’Arc Resources was responsible for generating exploration prospects in the Gulf of Mexico utilizing 3-D seismic data and their extensive geological expertise in the region. Comstock Offshore advanced the funds for the acquisition of 3-D seismic data and leases. Comstock Offshore was reimbursed for all advanced costs and was entitled to a non-promoted working interest in each prospect generated. For each successful discovery well drilled pursuant to the joint exploration venture, Comstock issued to the two principals of Bois d’Arc Resources warrants exercisable for the purchase of shares of Comstock’s common stock.
 
In July 2004, each of the Bois d’Arc Participants and Comstock Offshore contributed to Bois d’Arc Energy substantially all of their Gulf of Mexico related assets and assigned their related liabilities, including certain debt, in exchange for equity interests in Bois d’Arc Energy. The equity interests issued in exchange for the contributions were determined by using a valuation of the properties contributed by the particular contributor relative to the value of the properties contributed by all contributors. Comstock Offshore contributed its interests in its Gulf of Mexico properties and assigned to Bois d’Arc Energy $83.2 million of related debt in exchange for an approximately 60% ownership interest in Bois d’Arc Energy. The Bois d’Arc Participants contributed their offshore oil and natural gas properties as well as ownership of Bois d’Arc Offshore, Ltd., the operator of the properties, and assigned to Bois d’Arc Energy $28.2 million of related liabilities in exchange for an approximately 40% aggregate ownership interest in Bois d’Arc Energy. The Bois d’Arc Participants also received $27.6 million in cash to equalize the amount that Comstock Offshore’s debt exceeded its proportional share of the liabilities assigned. Bois d’Arc Energy also reimbursed Comstock Offshore $12.7 million and Bois d’Arc $0.8 million for advances made under the exploration joint venture for undrilled prospects.


F-7


Table of Contents

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

 
The following table sets forth the assets contributed and the liabilities assumed on the date of the formation of Bois d’Arc Energy:
 
                         
    Comstock
    Bois d’Arc
       
    Offshore     Participants     Combined  
    (In thousands)  
 
Cash and cash equivalents
  $ 6     $ 17,024     $ 17,030  
Other current assets
          21,992       21,992  
Property and equipment, net
    362,959       119,738       482,697  
Current liabilities and bank loan
          (66,788 )     (66,788 )
Payable to Comstock Resources
    (83,177 )           (83,177 )
Reserve for future abandonment
    (18,458 )     (7,985 )     (26,443 )
Cash distributed
    (12,742 )     (28,342 )     (41,084 )
                         
Net contribution
  $ 248,588     $ 55,639     $ 304,227  
                         
 
Under the terms of Bois d’Arc Energy’s operating agreement, management of Bois d’Arc Energy was shared jointly by Comstock and the principals of Bois d’Arc Resources. Management and operating decisions were made based on unanimous agreement between the parties. Because the Company had the ability to exercise significant influence over Bois d’Arc Energy, but not control it, the Company accounted for its interest in Bois d’Arc Energy’s assets, liabilities and operations under the proportionate consolidation method in accordance with Emerging Issues Task Force (“EITF”) 00-1, “Investor Balance Sheet and Income Statement Display Under the Equity Method for Investments in Partnerships and Certain other Ventures” and EITF 03-16 “Accounting for Investments in Limited Liability Companies,” and because Bois d’Arc Energy was similar to a partnership in that it maintained a specific ownership percentage for each member.
 
On May 10, 2005 Bois d’Arc Energy, LLC was converted to a corporation and changed its name to Bois d’Arc Energy, Inc. 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 $158.1 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 one-time tax provision of $108.2 million to record a deferred tax liability. Comstock recognized its proportionate share of this one time 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 has not previously owned interests in a subsidiary which has sold shares. The Company has no present plans for any future sale of Bois d’Arc Energy common stock and has elected to adopt a policy of recognizing its proportional share of the gain when Bois d’Arc Energy sells shares to third parties as permitted under Securities and Exchange Commission Staff Accounting Bulletin No. 51.
 
Comstock’s investment in Bois d’Arc Energy represents the value of the assets contributed at the time of its formation, the Company’s 60% interest in the undistributed earnings of Bois d’Arc Energy, LLC from inception through May 10, 2005, the portion of Bois d’Arc Energy’s net income attributable to the Company’s interest in the outstanding common stock of Bois d’Arc Energy since the adoption of the equity method of accounting for this


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Table of Contents

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

investment, and the gain recognized based on the Company’s share of the amount that Bois d’Arc Energy’s equity increased as a result of the sale of shares in Bois d’Arc Energy’s initial public offering.
 
Bois d’Arc Energy’s common stock is traded on the New York Stock Exchange under the ticker symbol “BDE.” The fair value of the Company’s investment in Bois d’Arc Energy as of December 31, 2005 was $474.8 million based upon the closing price for Bois d’Arc Energy shares on that date of $15.86 per share.
 
At December 31, 2005 the difference between the Company’s carrying value of its equity investment and its underlying basis in the net assets of Bois d’Arc Energy was $51.1 million. The Company evaluates this difference on a quarterly basis.
 
Financial information reported by Bois d’Arc Energy is summarized below:
 
Balance Sheet:
 
                 
    December 31,  
    2004     2005  
    (In thousands)  
 
Current assets
  $ 18,590     $ 50,172  
Property and equipment, net
    511,477       661,931  
Other assets
    516       799  
                 
Total assets
  $ 530,583     $ 712,902  
                 
Current liabilities
  $ 34,779     $ 66,406  
Payable to Comstock Resources
    148,066        
Long term debt
          69,000  
Deferred taxes payable
          123,256  
Other liabilities
    28,253       35,034  
                 
Total liabilities
    211,098       293,696  
Stockholders’ equity
    319,485       419,206  
                 
Total liabilities and stockholders’ equity
  $ 530,583     $ 712,902  
                 
 
Income Statement:
 
                                 
    Combined Bois d’Arc Energy
    Bois d’Arc Energy  
    Predecessors     Period from
       
          Period from
    Inception
       
          January 1,
    (July 16,
    Year
 
          2004 to
    2004) to
    Ended
 
    December 31,
    July 15,
    December 31,
    December 31,
 
    2003     2004     2004     2005  
    (In thousands)  
 
Revenues
  $ 133,450     $ 70,341     $ 72,721     $ 184,436  
Operating Income
    62,094       28,151       19,677       77,778  
Net Income
    51,929       23,773       15,248       (51,672 )(1)
 
 
(1) Includes one time income tax provision of $108.2 million for the conversion from a limited liability company to a corporation.
 
Receivable from Bois d’Arc Energy
 
In connection with the formation of Bois d’Arc Energy, Comstock provided to Bois d’Arc Energy a revolving line of credit with a maximum outstanding amount of $200.0 million. Approximately $59.4 million of the outstanding balance was attributable to the Bois d’Arc Participants and is reflected in the consolidated balance sheet


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

as a receivable from Bois d’Arc Energy at December 31, 2004. Borrowings under the credit facility bore interest at Bois d’Arc Energy’s option at either LIBOR plus 2% or the base rate (which is the higher of the prime rate or the federal funds rate) plus 0.75%. Interest expense of $2.7 million was charged by the Company to Bois d’Arc Energy under the credit facility during the period from July 16, 2004 to December 31, 2004 and interest expense of $2.7 million was charged by the Company to Bois d’Arc Energy during the period from January 1, 2005 to May 10, 2005. Approximately $1.1 million and $1.2 million of interest was attributable to the Bois d’Arc Participants and is included in interest income in the consolidated statement of operations in 2004 and 2005, respectively.
 
In consideration for the credit facility, Bois d’Arc Energy agreed to become a guarantor with respect to Comstock’s $400.0 million bank credit facility and Comstock’s 67/8% senior notes due 2012. Bois d’Arc Energy repaid the indebtedness owing to Comstock from the net proceeds of its initial public offering and borrowings under its new bank credit facility, and this revolving line of credit was retired and Bois d’Arc Energy was released as a guarantor of the Company’s debt.
 
Formation Costs
 
The consolidated financial statements include $1.1 million of costs incurred during 2004 in connection with the formation of Bois d’Arc Energy, including a termination fee of $0.7 million for the cancellation of a service agreement for accounting and administrative services provided to Bois d’Arc Offshore, Ltd. The fee is payable in monthly installments over a two year period beginning October 2004.
 
Reclassifications
 
Certain reclassifications have been made to prior periods’ financial statements to conform to the current presentation.
 
Use of Estimates in the Preparation of Financial Statements
 
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual amounts could differ from those estimates. Changes in the future estimated oil and natural gas reserves or the estimated future cash flows attributable to the reserves that are utilized for impairment analysis could have a significant impact on the future results of operations.
 
Concentration of Credit Risk and Accounts Receivable
 
Financial instruments that potentially subject Comstock to a concentration of credit risk consist principally of cash and cash equivalents, accounts receivable and derivative financial instruments, Comstock 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. For a discussion of the credit risks associated with Comstock’s hedging activities, see Note 10. Substantially all of Comstock’s accounts receivable are due from either purchasers of oil and gas or participants in oil and gas wells for which Comstock 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.


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Table of Contents

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

 
Fair Value of Financial Instruments
 
The following table presents the carrying amounts and estimated fair value of the Company’s financial instruments as of December 31, 2004 and 2005:
 
                                 
    2004     2005  
    Carrying
    Fair
    Carrying
    Fair
 
    Value     Value     Value     Value  
    (In thousands)  
 
Long term debt, including current portion
  $ 403,150     $ 408,400     $ 243,000     $ 239,281  
 
The fair market value of the fixed rate debt was based on the market price as of December 31, 2004 and 2005.
 
Derivatives are presented at their estimated fair value. The carrying amounts of cash and cash equivalents, accounts receivable, other current assets, and accounts payable and accrued expenses approximate fair value due to the short maturity of these instruments.
 
Other Current Assets
 
Other current assets at December 31, 2004 and 2005 consist of the following:
 
                 
    As of December 31,  
    2004     2005  
    (In thousands)  
 
Prepaid expenses
  $ 1,689     $ 3,511  
Tax refund receivable
    2,100        
Pipe inventory
    2,755       1,408  
Deferred tax asset
          4,439  
Other
          124  
                 
    $ 6,544     $ 9,482  
                 
 
Property and Equipment
 
Comstock 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 are determined on a field area basis. Costs incurred to acquire oil and gas leasehold are capitalized. Unproved oil and gas properties are periodically assessed and any impairment in value is charged to exploration expense. The 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. In accordance with Statement of Financial Accounting Standards No. 19, exploratory drilling costs are evaluated within a one-year period after the completion of drilling.
 
In accordance with Statement of Financial Accounting Standards No. 143 “Accounting for Asset Retirement Obligations,” Comstock 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. Comstock’s ARO’s relate to future plugging and abandonment expenses of its oil and gas properties and related facilities disposal.


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

 
The following table summarizes the changes in Comstock’s total estimated liability:
 
                         
    For the Year Ended December 31,  
    2003     2004     2005  
 
Beginning asset retirement obligations
  $ 16,677     $ 19,174     $ 19,248  
Cumulative effect adjustment
    (1,476 )            
Bois d’Arc Energy abandonment liability(1)
                (16,915 )
New wells placed on production and changes in estimates
    (875 )     1,870       266  
Acquisition liabilities assumed
    4,787       88       455  
Liabilities settled
    (685 )     (3,030 )      
Accretion expense
    746       1,146       152  
                         
Ending asset retirement obligations
  $ 19,174     $ 19,248     $ 3,206  
                         
 
 
(1) Comstock’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.
 
The adoption of SFAS 143 on January 1, 2003 resulted in a cumulative effect adjustment to record (i) a $3.7 million decrease in the carrying value of oil and gas properties, (ii) a $3.3 million decrease in accumulated depletion, depreciation and amortization, (iii) a $1.5 million decrease in reserve for future abandonment, and (iv) a gain of $675,000, net of income taxes, which was reflected as the cumulative effect of a change in accounting principle. The following pro forma data summarizes the Company’s net income and net income per share for the year ended December 31, 2003 as if the Company had adopted the provisions of SFAS 143 on December 31, 2002, including aggregate pro forma asset retirement obligations on that date of $15.2 million.
 
         
    For the Year
 
    Ended
 
    December 31,
 
    2003  
    (In thousands,
 
    except per
 
    share amounts)  
 
Net income, as reported
  $ 53,942  
Pro forma adjustments to reflect retroactive adoption of SFAS 143
    (675 )
         
Pro forma net income
  $ 53,267  
         
Net income per share:
       
Basic — as reported
  $ 1.67  
         
Basic — pro forma
  $ 1.65  
         
Diluted — as reported
  $ 1.53  
         
Diluted — pro forma
  $ 1.51  
         
 
In accordance with the Statement of Financial Accounting Standards No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (“SFAS 144”), Comstock assesses the need for an impairment of the costs capitalized of its oil and gas properties on a property or cost center basis. If an impairment is indicated based on undiscounted expected future cash flows, then an impairment is recognized to the extent that net capitalized costs exceed discounted expected future cash flows based on escalated prices and including risk adjusted probable reserves, where appropriate. Comstock recognized impairment of its oil and gas properties of $4.3 million, $1.6 million and $3.4 million in 2003, 2004, and 2005, respectively, which primarily related to some minor valued


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Table of Contents

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

fields where an impairment was indicated based on estimated future cash flows attributable to the fields’ estimated proved oil and natural gas reserves.
 
Other property and equipment consists primarily of gas gathering systems, computer equipment, furniture and fixtures and interests in private airplanes which are depreciated over estimated useful lives ranging from 5 to 311/2 years on a straight-line basis.
 
Other Assets
 
Other assets primarily consist of deferred costs associated with issuance of Comstock’s senior notes and its bank credit facility. These costs are amortized over the eight year life of the senior notes and the four year 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 Options
 
Prior to January 1, 2004, Comstock accounted for employee stock-based compensation using the intrinsic value method prescribed in Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees” (“APB 25”). Under the intrinsic method, compensation cost for stock options is measured as the excess, if any, of the fair value of the Company’s common stock at the date of the grant over the amount an employee must pay to acquire the common stock. Effective January 1, 2004, the Company changed its method of accounting for employee stock-based compensation to the preferable fair value based method prescribed in Statement of Financial Accounting Standards No. 123, “Accounting for Stock-Based Compensation” (“SFAS 123”). 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. The fair value of each award is estimated as of the date of grant using the Black-Scholes options pricing model. Under the modified prospective transition method selected by Comstock as described in Statement of Financial Accounting Standards No. 148, “Accounting for Stock-Based Compensation — Transition and Disclosure,” stock-based compensation expense recognized for 2004, is the same as that which would have been recognized had the fair value method of SFAS 123 been applied from its original effective date. During 2004 and 2005, the Company recorded $6.2 million and $5.4 million, respectively, in stock-based compensation expense in general and administrative expenses. The 2004 stock-based compensation included $2.8 million for restricted stock grants, $1.9 million for employee stock options and $1.5 million attributable to the Company’s ownership in Bois d’Arc Energy related to its stock-based compensation. The 2005 stock-based compensation included $3.6 million for restricted stock grants, $0.6 million for employee stock options and $1.2 million attributable to the Company’s ownership in Bois d’Arc Energy related to its stock-based compensation.
 
In accordance with the modified prospective transition method, results for years prior to 2004 have not been restated. In 2003, the Company accounted for stock-based compensation for employees under APB 25 and related interpretations, under which no compensation cost was recognized for employee stock options. If compensation


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Table of Contents

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

costs had been determined in accordance with SFAS 123, the Company’s net income and earnings per share would approximate the following pro forma amounts:
 
         
    Year Ended
 
    December 31,
 
    2003  
    (In thousands,
 
    except per share
 
    amounts)  
 
Net income, as reported
  $ 53,369  
Add stock-based employee compensation expense included in reported net income, net of income taxes
    233  
Deduct total stock-based employee compensation expense determined under fair value based method for all rewards, net of income taxes
    (1,942 )
         
Pro forma net income
  $ 51,660  
         
Net income per share:
       
Basic — as reported
  $ 1.67  
         
Basic — pro forma
  $ 1.62  
         
Diluted — as reported
  $ 1.53  
         
Diluted — pro forma
  $ 1.48  
         
 
The fair value of each option grant is estimated on the date of grant using the Black-Scholes option pricing model with the following weighted average assumptions used for grants in 2003, 2004 and 2005, respectively: average risk-free interest rates of 3.0, 3.6 and 4.3%; average expected lives of 5.9, 4.1 and 8.2 years; average expected volatility factors of 32.8, 46.9 and 36.8; and 0% dividend yield for all years. The estimated weighted average fair value of options to purchase one share of common stock issued under the Company’s incentive plans was $6.38 in 2003, $7.75 in 2004 and $15.08 in 2005.
 
Segment Reporting
 
Comstock presently operates in one business segment, the exploration and production of oil and natural gas.
 
Derivative Instruments and Hedging Activities
 
Comstock 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. Comstock 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 2005, Comstock had two purchasers of its oil and natural gas production that individually accounted for 10% of total oil and gas sales. Such purchasers accounted for 15% and 12% of total 2005 oil and gas sales. In 2004,


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Table of Contents

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

Comstock had two purchasers that accounted for 21% and 16% of total oil and gas sales. In 2003, Comstock had three purchasers that accounted for 18%, 14% and 10% of total 2003 oil and gas sales.
 
Revenue Recognition and Gas Balancing
 
Comstock utilizes the sales method of accounting for oil and natural gas revenues whereby revenues are recognized 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. Comstock did not have any significant imbalance positions at December 31, 2003, 2004 or 2005.
 
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 Comstock.
 
Income Taxes
 
Comstock accounts for income taxes using the asset and liability method, whereby deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their respective tax basis, as well as the future tax consequences attributable to the future utilization of existing tax net operating loss and other types of carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.
 
Comprehensive Income
 
Comprehensive income is defined as the change in equity of a business enterprise during a period from transactions and other events and circumstances from non-owner sources. The Company’s other comprehensive income in 2003 consisted of unrealized gains and losses on cash flow hedges.


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Table of Contents

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

 
Earnings Per Share
 
Basic and diluted earnings per share for 2003, 2004 and 2005 were determined as follows:
 
                                                                         
    Year Ended December 31,  
    2003     2004     2005  
                Per
                Per
                Per
 
    Income     Shares     Share     Income     Shares     Share     Income     Shares     Share  
    (In thousands except per share data)  
 
Basic Earnings Per Share: