10-K 1 d43050e10vk.htm FORM 10-K e10vk
Table of Contents

 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
FORM 10-K
         
(Mark One)                 
þ
  ANNUAL REPORT PURSUANT TO SECTIONS 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
   
    For the fiscal year ended December 31, 2006    
    OR    
o
  TRANSITION REPORT PURSUANT TO SECTIONS 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
   
    For the transition period from          to              
 
Commission file no. 0-16741
COMSTOCK RESOURCES, INC.
(Exact name of registrant as specified in its charter)
 
     
NEVADA   94-1667468
(State or other jurisdiction of   (I.R.S. Employer
incorporation or organization)   Identification Number)
 
5300 Town and Country Blvd., Suite 500, Frisco, Texas 75034
(Address of principal executive offices including zip code)
 
(972) 668-8800
(Registrant’s telephone number and area code)
 
Securities registered pursuant to Section 12(b) of the Act:
 
     
Common Stock, $.50 Par Value   New York Stock Exchange
Preferred Stock Purchase Rights   New York Stock Exchange
(Title of class)   (Name of exchange on which registered)
 
Securities registered pursuant to Section 12(g) of the Act: None
 
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes þ     No o
 
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.  Yes o     No þ
 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes þ     No o
 
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K. þ
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, 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 February 28, 2007, there were 44,396,995 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, 2006 (the last business day of the registrant’s most recently completed second fiscal quarter), was $1.2 billion.
 
DOCUMENTS INCORPORATED BY REFERENCE
 
Portions of the Proxy Statement for the 2007 Annual Meeting of Stockholders to be held
May 3, 2007 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, 2006
 
CONTENTS
 
             
Item
      Page
 
    Cautionary Note Regarding Forwarding-Looking Statements   3
    Definitions   4
  Business and Properties   7
1A.
  Risk Factors   28
1B.
  Unresolved Staff Comments   37
3.
  Legal Proceedings   37
4.
  Submission of Matters to a Vote of Security Holders   37
 
5.
  Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities   38
6.
  Selected Financial Data   39
7.
  Management’s Discussion and Analysis of Financial Condition and Results of Operations   40
7A.
  Quantitative and Qualitative Disclosures About Market Risks   52
8.
  Financial Statements and Supplementary Data   53
9.
  Changes in and Disagreements with Accountants on Accounting and Financial Disclosure   53
9A.
  Controls and Procedures   54
9B.
  Other Information   56
 
10.
  Directors and Executive Officers of the Registrant   56
11.
  Executive Compensation   56
12.
  Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters   56
13.
  Certain Relationships and Related Transactions, and Director Independence   56
14.
  Principal Accountant Fees and Services   57
 
15.
  Exhibits and Financial Statement Schedules   57
 Second Amended and Restated Credit Agreement
 Subsidiaries
 Consent of Ernst & Young LLP
 Consent of Independent Petroleum Engineers
 Certification of CEO Pursuant to Section 302
 Certification of CFO Pursuant to Section 302
 Certification of CEO Pursuant to Section 906
 Certification of CFO Pursuant to Section 906


2


Table of Contents

 
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.


3


Table of Contents

 
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


4


Table of Contents

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.
 
“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.


5


Table of Contents

 
“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.


6


Table of Contents

 
PART I
 
ITEMS 1. and 2.  BUSINESS AND PROPERTIES
 
Comstock Resources, Inc. (“Comstock”) is a Nevada corporation whose common stock is listed and traded on the New York Stock Exchange and is engaged in the acquisition, development, production and exploration of oil and natural gas.
 
Our oil and gas operations are concentrated onshore in the East Texas/North Louisiana and South Texas regions as well as in Mississippi, and offshore in state and federal waters of the Gulf of Mexico. Our offshore operations are conducted exclusively through Bois d’Arc Energy, Inc. (“Bois d’Arc Energy”), a separate publicly-held company. Combined with the ownership by members of our Board of Directors, we own a controlling interest in the common stock of Bois d’Arc Energy and are consolidating the results of Bois d’Arc Energy effective from January 1, 2006. Our oil and natural gas properties are estimated to have proved reserves of 851 Bcfe with an estimated PV 10 Value of $2.3 billion as of December 31, 2006 and a standardized measure of discounted future net cash flows of $1.8 billion. Our consolidated proved oil and natural gas reserve base is 77% natural gas and 23% proved developed on a Bcfe basis as of December 31, 2006.
 
Our proved reserves at December 31, 2006 and our 2006 average daily production are summarized below:
 
                                                                 
    Reserves at December 31, 2006     2006 Daily Production  
    Oil
    Gas
    Total
    % of
    Oil
    Gas
    Total
    % of
 
    (MMBbls)     (Bcf)     (Bcfe)     Total     (MBbls/d)     (MMcf/d)     (MMcfe/d)     Total  
 
East Texas/North Louisiana
    1.7       247.1       257.6       30%         0.3       48.9       50.8       28%  
South Texas
    3.4       139.7       159.9       19%       0.6       24.9       28.3       15%  
Mississippi
    6.7       0.7       40.8       5%       1.5       0.2       9.4       5%  
Other Regions
    0.2       48.0       49.1       6%       0.1       8.9       9.5       5%  
                                                                 
Total Onshore
    12.0       435.5       507.4       60%       2.5       82.9       98.0       53%  
Offshore (Bois d’Arc Energy)
    20.4       221.5       344.0       40%       3.8       63.5       86.2       47%  
                                                                 
Total
     32.4       657.0       851.4       100%       6.3       146.4       184.2       100%  
                                                                 
 
Strengths
 
High Quality Properties.  Our onshore operations, which comprise 60% of our total proved reserves, are focused in three primary operating areas, the East Texas/North Louisiana and South Texas regions and in Mississippi. Our onshore properties have an average reserve life of approximately 14.2 years and have extensive development and exploration potential. Our offshore reserves, which represent approximately 40% of our total proved reserves, are located in the outer continental shelf of the Gulf of Mexico and include properties located in Louisiana state and federal waters. These offshore reserves have an average reserve life of 10.9 years.
 
Successful Exploration and Development Program.  In 2006 we spent $453.6 million on exploration and development of our oil and natural gas properties. We drilled 16 exploratory wells in 2006, 13.5 net to us, at a cost of $136.8 million. Eleven of these 16 wells were successful. We spent $211.5 million on our 2006 development drilling program, which included drilling 119 development wells, 87.4 net to us, with a 97% success rate. In 2006 we also incurred $105.3 million on recompletions, workovers, abandonment and production facilities.
 
Successful Acquisitions.  We have had significant growth over the years as a result of acquisitions. Since 1991, we have added 912 Bcfe of proved oil and natural gas reserves from 35 acquisitions at an


7


Table of Contents

average cost of $1.04 per Mcfe. In 2006 we acquired 23 Bcfe of proved oil and natural gas reserves for $79.8 million. Our application of strict economic and reserve risk criteria have enabled us to successfully evaluate and integrate acquisitions.
 
Efficient Operator.  We operate 86% of our proved oil and natural gas reserve base as of December 31, 2006. 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 912 Bcfe of proved oil and natural gas reserves from 35 acquisitions at a total cost of $947.3 million, or $1.04 per Mcfe. The acquisitions were acquired at an average of 64% of their PV 10 Value in the year the acquisitions were completed. In 2006 we acquired 23 Bcfe of proved oil and natural gas reserves for $79.8 million or $3.43 per Mcfe. The PV 10 Value of the acquired reserves in 2006 was $53.2 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 2006, we spent approximately $211.5 million to drill 119 development wells, 87.4 net to us, all but four of which were successful. In addition, we spent approximately $105.4 million for leasehold costs, recompletions, workover activities and facilities. Our onshore business plan in 2007 will focus on developing our East Texas/North Louisiana, South Texas and Mississippi properties. We have budgeted $250.0 million for development drilling and for recompletion and workover activities in 2007 in all of our onshore regions. We also plan to spend $88.3 million in 2007 for development drilling, recompletions, workover activities and production facilities on our offshore properties.
 
Pursue Exploration Opportunities.  We conduct exploration activities to grow our reserve base and to replace our production each year. Most of our exploration efforts are conducted through Bois d’Arc Energy. Bois d’Arc Energy’s 2007 budget includes $91.7 million to drill 11 offshore exploratory wells. We have also budgeted $28.0 million for onshore exploration in 2007, primarily in our South Texas and Mississippi regions.
 
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 $478.0 million on our development and exploration projects in 2007. We intend to primarily use operating cash flow to fund our development and exploration expenditures in 2007 and to a lesser extent borrowings under our bank credit facilities. We may also make additional property acquisitions in 2007 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.


8


Table of Contents

 
Primary Operating Areas
 
The following table summarizes the estimated proved oil and natural gas reserves for our twenty largest onshore field areas and our five largest offshore operating areas as of December 31, 2006:
 
                                                 
    Net Oil
    Net Gas
                         
    (MBbls)     (MMcf)     MMcfe     %     PV 10 Value(1)     %  
 
East Texas/North Louisiana
                                               
Beckville
    133       80,326       81,122       16%     $ 127,944       13%  
Gilmer
    115       30,607       31,299       6%       57,298       6%  
Blocker
    99       29,898       30,495       6%       44,866       5%  
Waskom
    968       10,151       15,959       3%       42,773       4%  
Logansport
    31       13,199       13,385       3%       26,766       3%  
Darco
    68       19,152       19,558       4%       24,503       3%  
Cadeville
    72       15,079       15,510       3%       23,048       2%  
Douglass
    4       14,942       14,968       3%       14,537       1%  
Longwood
    63       4,897       5,273       1%       10,679       1%  
Other
    185       28,899       30,007       6%       48,720       5%  
                                                 
      1,738       247,150       257,576       51%       421,134       43%  
                                                 
South Texas
                                               
Double A Wells
    2,220       59,651       72,971       14%       179,522       18%  
Las Hermanitas
          25,190       25,190       5%       47,707       5%  
Javelina
    51       11,074       11,380       2%       28,779       3%  
Markham
    194       9,647       10,808       2%       27,512       3%  
J.C. Martin
          13,756       13,756       3%       26,641       3%  
Sugar Creek
    77       7,707       8,169       2%       15,030       2%  
East White Point
    499       1,797       4,790       1%       14,612       1%  
Ball Ranch
    40       4,005       4,247       1%       9,929       1%  
Other
    292       6,871       8,625       1%       21,069       2%  
                                                 
      3,373       139,698       159,936       31%       370,801       38%  
                                                 
Mississippi
                                               
Laurel
    6,557             39,342       8%       112,439       12%  
Other
    122       700       1,433       —%       4,077       —%  
                                                 
      6,679       700       40,775       8%       116,516       12%  
                                                 
Other Onshore
                                               
San Juan
    36       12,234       12,452       3%       18,031       1%  
Southwest Morse
          5,914       5,914       1%       10,223       1%  
Other
    158       29,812       30,760       6%       44,576       5%  
                                                 
      194       47,960       49,126       10%       72,830       7%  
                                                 
Total Onshore
    11,984       435,508       507,413       100%       981,281       100%  
                                                 
Offshore
                                               
Ship Shoal 111 and the Ship Shoal 113 Unit
    8,261       71,854       121,417       35%       438,315       33%  
South Pelto 5, South Timbalier 9, 11 and 16
    1,406       25,204       33,643       10%       145,955       11%  
Ship Shoal 66, 67, 68, 69 and South Pelto 1
    3,603       9,818       31,436       9%       124,364       9%  
Ship Shoal 97, 98, 99, 106, 107, 109, and 110
    500       25,872       28,873       9%       95,415       7%  
South Pelto 22
    1,336       13,428       21,445       6%       91,283       7%  
Other Offshore
    5,319       75,287       107,196       31%       421,788       33%  
                                                 
Total Offshore(2)
    20,425       221,463       344,010       100%       1,317,120       100%  
                                                 
Total Consolidated
    32,409       656,971       851,423             $ 2,298,401          
                                                 
 
(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, 2006 was $1.8 billion.
(2) The reserves attributed to the minority interest ownership in Bois d’Arc Energy were 10,320 MBbls of oil and 111,898 MMcf of natural gas or 173,817 MMcfe of natural gas equivalent with a PV10 value of $665.5 million and a standardized measure of future net cash flows of $546.2 million.


9


Table of Contents

 
East Texas/North Louisiana
 
Approximately 51% or 257.6 Bcfe of our onshore proved reserves are located in East Texas and North Louisiana where we own interests in 752 producing wells, 392.4 net to us, in 31 field areas. We operate 412 of these wells. The largest of our fields in this region are the Beckville, Gilmer, Blocker,Waskom, Logansport, Darco, Cadeville, Logansport, Douglass and Longwood fields. Production from this region averaged 48.9 MMcf of natural gas per day and 321 barrels of oil per day during 2006. 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 2006, we spent $145.0 million drilling 88 wells, 69.3 net to us, and $13.3 million on workovers and recompletions in this region. We plan to spend approximately $175.0 million in 2007 for development activities in this region.
 
Beckville
 
The Beckville field, located in Panola and Rusk Counties, Texas, is our largest field area in this region with total estimated proved reserves of 81.1 Bcfe which represents approximately 16% of our onshore reserves. We operate 130 wells in this field and own interests in six additional wells for a total of 136 wells, 104.6 net to us. During December 2006, production attributable to our interest from this field averaged 19.9 MMcf of natural gas per day and 45 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 31.3 Bcfe which represents 6% of our onshore reserve base. During December 2006, production attributable to our interest from this field averaged 5.7 MMcf of natural gas per day and 58 barrels of oil per day.
 
Blocker
 
Our proved reserves of 30.5 Bcfe in the Blocker field located in Harrison County, Texas represent approximately 6% of our onshore reserves. We own interests in 60 wells, 57.8 net to us, and operate 57 of these wells. During December 2006, net daily production attributable to our interest from this field averaged 9.8 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.
 
Waskom
 
The Waskom field, located in Harrison and Panola Counties in Texas, represents approximately 3% (16 Bcfe) of our onshore proved reserves as of December 31, 2006. We own interests in 60 wells in this field, 31.6 net to us, and operate 35 wells in this field. During December 2006, net daily production attributable to our interest averaged 1.8 MMcf of natural gas and 16 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.
 
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 13.4 Bcfe in the Logansport


10


Table of Contents

field represent approximately 3% of our onshore reserves. We own interests in 94 wells, 46.4 net to us, and operate 52 of these wells. During December 2006, net daily production attributable to our interest from this field averaged 3.7 MMcf of natural gas and 22 barrels of oil.
 
Darco
 
The Darco field is located in Harrison County, Texas and produces from the Cotton Valley formation at depths from approximately 9,800 to 10,200 feet. Our proved reserves of 19.6 Bcfe in the Darco Field represent approximately 4% of our onshore reserves. We own interests in 11 wells, 8.4 net to us, and operate all of these wells. During December 2006, net daily production attributable to our interest from this field averaged 2.3 MMcf of natural gas and 8 barrels of oil.
 
Cadeville
 
Our proved reserves of 15.5 Bcfe in the Cadeville field located in Ouachita Parrish, Louisiana represent approximately 3% of our onshore reserves. We own interests in 5 wells, 2.0 net to us, and operate 2 of these wells. During December 2006, net daily production attributable to our interest from this field averaged 1.4 MMcf of natural gas and 5 barrels of oil. This production is primarily from the Cotton Valley formation between 9,800 and 10,700 feet.
 
Douglass
 
The Douglass field is located in Nacogdoches County, Texas and is productive from stratigraphically trapped reservoirs in the Pettet Lime and Travis Peak formations. These reservoirs are found at depths from 9,200 to 10,300 feet. Our proved reserves of 15.0 Bcfe in the Douglass field represent approximately 3% of our onshore reserves. We own interests in 21 wells, 13.4 net to us, and operate 15 of these wells. During December 2006, net daily production attributable to our interest from this field averaged 2.4 MMcf of natural gas.
 
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 27 wells in this field, 21.8 net to us, and operate 23 wells in this field. Our proved reserves of 5.3 Bcfe in the Longwood field represent approximately 1% of our onshore reserves. During December 2006, net daily production attributable to our interest from this field averaged 1.1 MMcf of natural gas and 15 barrels of oil.
 
South Texas
 
Approximately 32%, or 159.9 Bcfe, of our onshore proved reserves are located in South Texas, where we own interests in 387 producing wells, 124.4 net to us. We own interests in fifteen field areas in the region, the largest of which are the Double A, Las Hermanitas, Javelina, Markham, J.C. Martin, Sugar Creek, East White Point and Ball Ranch fields. Net daily production rates from the area averaged 24.9 MMcf of natural gas and 573 barrels of oil during 2006. We spent $29.3 million in this region in 2006 to drill ten wells, 4.3 net to us, and for other development activity. In 2007, we plan to spend approximately $56.0 million for development and exploration activity in this region.


11


Table of Contents

 
Double A Wells
 
Our properties in the Double A Wells field have proved reserves of 73.0 Bcfe, which represent 14% of our onshore reserves. We own interests in and operate 61 producing wells, 30.7 net to us, in this field in Polk County, Texas. Net daily production from the Double A Wells area averaged 7.3 MMcf of natural gas and 260 barrels of oil during December 2006. These wells typically produce from the Woodbine formation at an average depth of 14,300 feet.
 
Las Hermanitas
 
We acquired interests in three natural gas wells, 3.0 net to us, in the Las Hermanitas field, located in Duval County, Texas in September 2006. We also drilled three (3.0 net to us) wells in this field in 2006. These wells produce from the Wilcox formation at depths from approximately 11,400 to 11,800 feet. Our proved reserves of 25.2 Bcfe in this field represent approximately 5% of our onshore reserves. During December 2006, net daily production attributable to our interest from this field averaged 3.2 MMcf of natural gas.
 
Javelina
 
We own interests in five natural gas wells and one oil well, 3.1 net to us, in the Javelina field in Hidalgo County in South Texas. These wells produce primarily from the Vicksburg formation at a depth of approximately 10,900 to 12,500 feet. Proved reserves attributable to our interests in the Javelina field are 11.4 Bcfe which represents 2% of our onshore reserve base. During December 2006, production attributable to our interest from this field averaged 3.2 MMcf of natural gas per day and 28 barrels of oil per day.
 
Markham
 
The Markham field is located in Matagorda County, Texas. We own interests in and operate 22 producing wells, 22.0 net to us, in the Ohio-Sun Unit. The field’s estimated proved reserves of 10.8 Bcfe represent 2% of our onshore reserves. The field’s active wells produce from more than twenty reservoirs of Oligocene Frio age at depths ranging from 6,500 to 9,000 feet. During December 2006, net daily production attributable to our interests from this field average 70 barrels of oil and 0.3 MMcf of gas per day.
 
J.C. Martin
 
The J.C. Martin field 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 13.8 Bcfe or 3% of our onshore reserves. During December 2006, net daily production attributable to our interest from this field averaged 3.5 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.
 
Sugar Creek
 
Our proved reserves of 8.2 Bcfe in the Sugar Creek field located in Tyler County, Texas represent approximately 2% of our onshore reserves. We own interests in 4 wells, 2.6 net to us, and operate 2 of these wells. During December 2006, net daily production attributable to our interest from this field averaged 0.5 MMcf of natural gas and 7 barrels of oil.


12


Table of Contents

 
East White Point
 
We own interests in four producing natural gas and three producing oil wells for at total of seven wells, 3.2 net to us, at East White Point in Nueces Bay off of the Texas Gulf Coast. We operate two of these wells. The wells produce from the Miocene and Frio formations from 1,800 to 11,000 feet. We have proved reserves of 4.8 Bcfe at East White Point which represent approximately 1% of our onshore reserves. During December 2006, net daily production attributable to our interest from this field averaged 0.5 MMcf of natural gas and 18 barrels of oil.
 
Ball Ranch
 
Our proved reserves of 4.2 Bcfe in the Ball Ranch field located in Kenedy County, Texas represent approximately 1% of our onshore reserves. Production is from the Vicksburg formation in sands that range in depth from 13,000 feet to 14,300 feet. We own interests in 21 wells, 4.0 net to us in this field. During December 2006, net daily production attributable to our interest from this field averaged 2.8 MMcf of natural gas and 20 barrels of oil.
 
Mississippi
 
Approximately 8% or 40.8 Bcfe of our onshore proved reserves are located in Mississippi, where we own interests in three fields, the largest of which is the Laurel field. Our Mississippi properties contain 55 producing wells, 51.2 net to us, which averaged net daily production rates of 1,529 barrels of oil and 0.5 MMcf of natural gas during 2006. We drilled eleven wells, 10.5 net to us, in Mississippi during 2006 and we plan to spend approximately $45.0 million for development and exploration activity.
 
Laurel
 
Our properties in Mississippi are mainly located within the Laurel field, located in Jones County, Mississippi near a structurally complex salt dome. We own interests in and operate 53 producing wells, 50.2 net to us, in the Laurel field. This field’s estimated proved reserves of 39.3 Bcfe represent 8% of our onshore reserves. The field produces from more than 42 horizons that range in depth from 6,600 feet in the Stanley Sand to 13,100 feet in the Middle Hosston formation. Recovery of low viscosity crude oil from this field is being enhanced through waterflood operations. During December 2006, net daily production attributable to our interests in this field averaged 1,683 barrels of oil per day.
 
Other Onshore
 
Approximately 10%, or 49.1 Bcfe, of our onshore proved reserves are in various other areas, primarily in the Mid-Continent region and in Kentucky and New Mexico. Within these areas we own interests in 461 producing wells, 176.2 net to us in 21 fields. Fields with the largest proved reserves in these areas include the San Juan Basin properties in New Mexico and our Southwest Morse field in the Texas panhandle. Net daily production from our other onshore fields totaled 9.0 MMcf of natural gas and 100 barrels of oil during 2006. We drilled thirteen wells, 5.5 net to us on these properties in 2006. In 2007, we plan to spend approximately $2.0 million for development and exploration activity on these properties.
 
San Juan
 
Our San Juan Basin properties are located in the west-central portion of the basin in San Juan County, New Mexico. These wells produce from multiple sands of the Cretaceous Dakota formation and the 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. Our proved reserves of 12.5 Bcfe in the San Juan field


13


Table of Contents

represent approximately 3% of our onshore reserves. We own interests in 93 wells, 13.6 net to us. During December 2006, net daily production attributable to our interest from this field averaged 1.3 MMcf of natural gas and 5 barrels of oil.
 
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 5.9 Bcfe in the Southwest Morse field represent approximately 1% of our onshore reserves. We own interests in 40 wells, 39.1 net to us, and operate 39 of these wells. During December 2006, net daily production attributable to our interest from this field averaged 0.7 MMcf of natural gas.
 
Offshore Gulf of Mexico
 
Prior to July 2004, substantially all of our exploration activities in the Gulf of Mexico were conducted under a joint exploration venture with Bois d’Arc Offshore, Ltd. and its principals, which we collectively refer to as “Bois d’Arc.” Under the exploration venture, Bois d’Arc was responsible for generating exploration prospects in the Gulf of Mexico. From 1997 when the exploration venture was commenced until July 16, 2004 when it was terminated, we participated in drilling approximately 40 exploratory wells to test prospects generated under the exploration venture. Of these exploratory wells drilled, 34 or 85% were successful discoveries. In July 2004, we together with Bois d’Arc and certain participants in their exploration activities, which are collectively referred to as the “Bois d’Arc Participants,” formed Bois d’Arc Energy, LLC to replace the joint exploration venture. We and each of the Bois d’Arc Participants contributed to Bois d’Arc Energy substantially all of our respective Gulf of Mexico related assets and assigned our related liabilities, including certain debt, in exchange for equity interests in Bois d’Arc Energy.
 
We initially owned 60% of Bois d’Arc Energy, and we accounted for our share of the Bois d’Arc Energy financial and operating results using proportionate consolidation accounting until Bois d’Arc Energy converted into a corporation and completed its initial public offering in May 2005. Subsequent to the conversion of Bois d’Arc Energy into a corporation and the public offering, we owned 48% of Bois d’Arc Energy and we changed our accounting method for our investment in Bois d’Arc Energy to the equity method through December 31, 2005. Beginning in September 2006, we own a controlling interest in Bois d’Arc Energy and are consolidating the results of Bois d’Arc Energy effective January 1, 2006.
 
Bois d’Arc Energy has total proved reserves in the outer continental shelf of the Gulf of Mexico of 344 Bcfe, which represents approximately 40% of our total reserves. Bois d’Arc Energy owns interests in 111 gross (76.6 net) and operates 89 of these wells. Production from Bois d’Arc Energy’s properties in 2006 averaged 63.5MMcf per day of natural gas and 3,789 barrels per day of oil for a total of 86.2 MMcfe per day. During 2006, Bois d’Arc Energy spent $129.0 million drilling 11 (9.5 net) exploratory wells and $23.4 million drilling two (1.7 net) development wells. Bois d’Arc Energy also spent $71.1 million on production facilities, recompletions, abandonments and workovers, $18.1 million on acquisition of proved reserves, and $7.6 million acquiring exploration acreage and seismic data during 2006. In 2007, Bois d’Arc Energy plans to spend $200.0 million for exploration and development activities.
 
Ship Shoal 111 and the Ship Shoal 113 Unit
 
The Ship Shoal 113 unit is located in federal waters having water depths from 20 to 50 feet, offshore of Terrebonne Parish, Louisiana and is comprised of 33,125 acres of federal leases covering portions of Ship Shoal blocks 93, 94, 112, 113, 114, 117, 118, 119 and 120. This unit was discovered in the late 1940s and has had cumulative production of 951 Bcfe of natural gas. These properties have 70 productive sands occurring


14


Table of Contents

at depths from 2,500 to 16,000 feet. We acquired a 50% working interest in these properties in December 2002, acquired an additional 30% working interest in October 2003 and the remaining 20% interest during 2006. We acquired the adjacent Ship Shoal block 111 in 2005 together with an existing production platform. Since 2003 we have drilled 17 wells (15.7 net to us) in this area. We operate the four production platforms and the 22 producing wells (20.2 net to us) comprising these properties. Production from these properties net to our interest averaged 23.3 MMcf of natural gas per day and 1,343 barrels of oil per day during December 2006.
 
South Pelto 5 and South Timbalier 9, 11, 16
 
We own interests in 15 producing wells, 10.6 net to us, in South Pelto block 5 and South Timbalier blocks 9, 11 and 16. These blocks are located in Louisiana state waters and in federal waters, offshore of Terrebonne Parish, Louisiana in water depths from 30 to 50 feet. These wells share common production facilities comprised of a four-pile main production platform and a tripod satellite production platform. We acquired our lease position in South Pelto block 5 and South Timbalier block 11 through a farm-in in 1998. We leased adjacent acreage in South Timbalier blocks 9, 11 and 16 from the State of Louisiana from 1998 through 2002. We have drilled 19 wells, including redrills of existing wells (13.4 net to us), in these blocks. These wells have 18 productive sands occurring at depths from 8,000 to 17,000 feet. Production from these properties net to our interest averaged 7.6 MMcf of natural gas per day and 287 barrels of oil per day during December 2006.
 
Ship Shoal 66, 67, 68, 69 and South Pelto 1
 
Ship Shoal blocks 66, 67, 68, 69 and South Pelto block 1 are located in Louisiana state waters and in federal waters with depths from 20 to 35 feet, offshore of Terrebonne Parish, Louisiana. These properties produce from ten sands occurring at depths from 9,000 to 13,500 feet. We own interests in eight wells (7.8 net to us) on Louisiana state leases partially covering Ship Shoal blocks 66 and 67 and South Pelto 1, and federal leases covering Ship Shoal blocks 68 and 69. We acquired these properties in December 1997 from Bois d’Arc Resources and other interest owners. We have drilled 8 wells (7.1 net to us) subsequent to the acquisition. These wells are connected to four production platforms and share common oil terminal facilities. Production from these properties net to our interest averaged 255 barrels of oil per day during December 2006.
 
Ship Shoal 99, 107, 109 and 110
 
Ship Shoal blocks 99, 107, 109 and 110 are located in federal waters with depths from 20 to 25 feet, offshore of Terrebonne Parish, Louisiana. We acquired these leases in federal lease sales in 2000 and 2001 and subsequently drilled 11 successful wells (8.4 net to us). These wells have 15 productive sands occurring at depths from 8,800 to 12,300 feet. Production from these properties net to our interest averaged 7.5 MMcf of natural gas per day, 111 barrels of oil per day during December 2006.
 
South Pelto 22
 
South Pelto block 22 is located in federal waters with depths from 50 to 60 feet, offshore of Terrebonne Parish, Louisiana. We farmed-in this acreage from another offshore operator in 2003 and have subsequently drilled four wells (2.5 net to us). These wells have 14 productive sands occurring at depths from 13,400 to 17,000 feet. Production from these properties net to our interest averaged 16.5 MMcf of natural gas per day and 436 barrels of oil per day during December 2006.


15


Table of Contents

 
Major Property Acquisitions
 
As a result of our acquisitions, we have added 912 Bcfe of proved oil and natural gas reserves since 1991 including 23.2 Bcfe we acquired in 2006.
 
Our largest acquisitions are the following:
 
Denali Acquisition.  In September 2006 we acquired proved and unproved oil and gas properties in the Las Hermanitas field in South Texas from Denali Oil & Gas Partners LP and other working interest owners for $67.2 million in cash. The properties acquired have estimated proved reserves of approximately 16.5 Bcfe. The transaction was funded with borrowings under our bank credit facility.
 
EnSight Acquisition.  In May 2005, we completed the acquisition of certain oil and natural gas properties and related assets from EnSight Energy Partners, L.P., Laurel Production, LLC, Fairfield Midstream Services, LLC and EnSight Energy Management, LLC (collectively, “EnSight”) for $190.9 million. We also purchased additional interests in those properties from other owners for $10.9 million in July 2005. The properties acquired had estimated proved reserves of approximately 121.5 billion cubic feet of natural gas equivalent and included 312 active wells, of which 119 are operated by us. Major fields acquired in the acquisition include the Darco, Cadeville, Douglass, and Laurel fields. The acquisition was funded with proceeds from a public stock offering completed in April 2005 and borrowings under our bank credit facility.
 
Ovation Energy Acquisition.  In October 2004, we acquired producing oil and gas properties in the East Texas, Arkoma, Anadarko and San Juan basins from Ovation Energy, L.P. for $62.0 million. The properties acquired had estimated proved reserves of approximately 41.0 billion cubic feet of gas equivalent and include 165 active wells, of which 69 are operated by us. 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 and the J.C. Martin and the Ball Ranch fields in South Texas. DevX’s properties had 1.2 MMBbls of oil reserves and 156.5 Bcf of natural gas reserves at the time of the acquisition.
 
Bois d’Arc Acquisition.  In December 1997, Comstock acquired working interests in certain producing offshore Louisiana oil and gas properties as well as interests in undeveloped offshore oil and natural gas leases for approximately $200.9 million from Bois d’Arc Resources and certain of its affiliates and working interest partners. We acquired interests in 43 wells, 29.6 net to us, and eight separate production complexes located in the Gulf of Mexico offshore of Plaquemines and Terrebonne Parishes, Louisiana. The acquisition included interests in the Louisiana state and federal offshore areas of Main Pass Block 21, Ship Shoal Blocks 66, 67, 68 and 69 and South Pelto Block 1. The net proved reserves acquired in this acquisition were estimated at 14.3 MMBbls of oil and 29.4 Bcf of natural gas.
 
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


16


Table of Contents

in Polk County, Texas and we became the operator of most of the wells in the field. The net proved reserves acquired in this acquisition were estimated at 5.9 MMBbls of oil and 100.4 Bcf of natural gas.
 
Sonat Acquisition.  In July 1995, we purchased interests in certain producing oil and gas properties located in East Texas and North Louisiana from Sonat Inc. for $48.1 million. We acquired interests in 319 producing wells, 188.0 net to us. The acquisition included interests in the Beckville, Blocker, Waskom, Logansport 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, 2006:
 
                                 
    Oil
    Gas
    Total
    PV10 Value
 
    (MBbls)     (MMcf)     (MMcfe)     (000’s)  
 
Proved Developed:
                               
Producing
    10,591       247,906       311,454     $ 853,686  
Non-producing
    12,957       176,339       254,082       900,241  
Proved Undeveloped
    8,860       232,725       285,888       544,474  
                                 
Total Proved
    32,408       656,970       851,424       2,298,401  
                                 
Discounted Future Income Taxes
    (469,896 )
         
Standardized Measure of Discounted Future Net Cash Flows(1)
  $ 1,828,505  
         
 
(1) The PV 10 Value represents the discounted future net cash flows attributable to our proved oil and gas reserves before income tax, discounted at 10%. Although it is a non-GAAP measure, we believe that the presentation of the PV 10 Value is relevant and useful to our investors because it presents the discounted future net cash flows attributable to our proved reserves prior to taking into account corporate future income taxes and our current tax structure. We use this measure when assessing the potential return on investment related to our oil and gas properties. The standardized measure of discounted future net cash flows represents the present value of future cash flows attributable to our proved oil and natural gas reserves after income tax, discounted at 10%.
 
The reserves attributed to the minority interest ownership in Bois d’Arc Energy as of December 31, 2006 were 10,320 MBbls of oil and 111,898 MMcf of natural gas or 173,817 MMcfe of natural gas equivalent with a PV10 Value of $665.5 million and a standardized measure of future net cash flows of $546.2 million.
 
Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions (i.e., prices and costs as of the date the estimate is made). Proved developed reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
 
The PV 10 Value and standardized measure of discounted future net cash flows was determined based on the market prices for oil and natural gas on December 31, 2006. The market price for our oil production on December 31, 2006, after basis adjustments, was $56.17 per barrel as compared to $49.17 per barrel on December 31, 2005. The market price received for our natural gas production on December 31, 2006, after basis adjustments, was $5.70 per Mcf as compared to $8.27 per Mcf on December 31, 2005.
 
We did not provide estimates of total proved oil and natural gas reserves during the years ended December 31, 2004, 2005 or 2006 to any federal authority or agency, other than the SEC.


17


Table of Contents

 
Drilling Activity Summary
 
During the three-year period ended December 31, 2006, we drilled development and exploratory wells as set forth in the table below.
 
                                                                                                 
    Onshore     Offshore  
    2004     2005     2006     2004     2005     2006  
    Gross     Net     Gross     Net     Gross     Net     Gross     Net     Gross     Net     Gross     Net  
 
Development Wells:
                                                                                               
Oil
    1       0.6       2       1.9       8       7.6       4       3.2       2       1.5              
Gas
    44       20.0       70       46.5       105       75.9       5       3.8       8       6.4       2       1.7  
Dry
    1       0.3                   4       2.2       5       3.1       1       0.6              
                                                                                                 
      46       20.9       72       48.4       117       85.7       14       10.1       11       8.5       2       1.7  
                                                                                                 
Exploratory Wells:
                                                                                               
Oil
    4       1.9                               1       1.0       3       3.0              
Gas
    9       3.6       1       .2       3       2.0       9       7.1       6       5.2       8       7.0  
Dry
    11       4.5       2       1.2       2       2.0                   2       2.0       3       2.5  
                                                                                                 
      24       10.0       3       1.4       5       4.0       10       8.1       11       10.2       11       9.5  
                                                                                                 
Total
    70       30.9       75       49.8       122       89.7       24       18.2       22       18.7       13       11.2  
                                                                                                 
 
In 2007 to the date of this report, we have drilled twenty-five wells, 18.6 net to us. Twenty-four of the wells were successful and one (0.8 net to us) was a dry hole. As of the date of this report, we have eleven wells, 9.2 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, 2006:
 
                                 
    Oil     Gas  
    Gross     Net     Gross     Net  
 
Onshore:
                               
Arkansas
                15       8.0  
Kansas
                12       4.5  
Kentucky
                91       81.5  
Louisiana
    6       2.4       241       105.1  
Mississippi
    61       51.9       2       1.1  
New Mexico
                93       13.6  
Oklahoma
    3       0.5       137       19.7  
Texas
    64       39.9       898       413.5  
Wyoming
                32       2.4  
                                 
Total Onshore
    134       94.7       1,521       649.4  
                                 
Offshore Gulf of Mexico:
                               
Louisiana
    10       7.9       9       7.0  
Federal
    34       17.9       58       43.8  
                                 
Total Offshore
    44       25.8       67       50.8  
                                 
Total
    178       120.5       1,588       700.2  
                                 
 
We operate 805 of the 1,766 producing wells presented in the above table. As of December 31, 2006, we owned interests in 23 wells containing multiple completions, which means that a well is producing out of


18


Table of Contents

more than one completed zone. Wells with more than one completion are reflected as one well in the table above.
 
Acreage
 
The following table summarizes our developed and undeveloped leasehold acreage at December 31, 2006. We have excluded acreage in which our interest is limited to a royalty or overriding royalty interest.
 
                                 
    Developed     Undeveloped  
    Gross     Net     Gross     Net  
 
Onshore:
                               
Arkansas
    1,280       684              
Kansas
    6,400       4,064              
Kentucky
    7,271       5,838       1,513       1,513  
Louisiana
    100,689       64,467       9,329       3,670  
Mississippi
    4,273       1,747       7,515       4,938  
New Mexico
    8,400       1,260       84,131       37,017  
Oklahoma
    38,080       5,707              
Texas
    250,147       153,288       42,625       14,568  
Wyoming
    13,440       927              
                                 
Total Onshore
    429,980       237,982       145,113       61,706  
                                 
Offshore Gulf of Mexico:
                               
Louisiana
    5,484       4,929       1,304       1,304  
Federal
    213,771       156,623       171,208       171,208  
                                 
Total Offshore
    219,255       161,552       172,512       172,512  
                                 
Total
    649,235       399,534       317,625       234,218  
                                 
 
Title to our oil and natural gas properties is subject to royalty, overriding royalty, carried and other similar interests and contractual arrangements customary in the oil and gas industry, liens incident to operating agreements and for current taxes not yet due and other minor encumbrances. All of our oil and natural gas properties are pledged as collateral under our bank credit facilities. As is customary in the oil and gas industry, we are generally able to retain our ownership interest in undeveloped acreage by production of existing wells, by drilling activity which establishes commercial reserves sufficient to maintain the lease or by payment of delay rentals.
 
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 onshore 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 64% of our 2006 natural gas sales were priced utilizing index prices and approximately 36% were priced utilizing daily spot prices. Two subsidiaries of Shell Oil Company accounted for approximately 42% of our total 2006 sales. Sales to National Energy & Trading LP comprised approximately 13% of our total 2006 sales. The loss of any of the foregoing customers would


19


Table of Contents

not have a material adverse effect on us as there is an available market for our crude oil and natural gas production from other purchasers.
 
Competition
 
The oil and gas industry is highly competitive. Competitors include major oil companies, other independent energy companies and individual producers and operators, many of which have financial resources, personnel and facilities substantially greater than we do. We face intense competition for the acquisition of oil and natural gas properties.
 
Regulation
 
General.  Various aspects of our oil and natural gas operations are subject to extensive and continually changing regulation, as legislation affecting the oil and natural gas industry is under constant review for amendment or expansion. Numerous departments and agencies, both federal and state, are authorized by statute to issue, and have issued, rules and regulations binding upon the oil and natural gas industry and its individual members. The Federal Energy Regulatory Commission, or “FERC,” regulates the transportation and sale for resale of natural gas in interstate commerce pursuant to the Natural Gas Act of 1938, or “NGA,” and the Natural Gas Policy Act of 1978, or “NGPA.” In 1989, however, Congress enacted the Natural Gas Wellhead Decontrol Act, which removed all remaining price and nonprice controls affecting all “first sales” of natural gas, effective January 1, 1993, subject to the terms of any private contracts that may be in effect. While sales by producers of natural gas and all sales of crude oil, condensate and natural gas liquids can currently be made at uncontrolled market prices, in the future Congress could reenact price controls or enact other legislation with detrimental impact on many aspects of our business. Under the provisions of the Energy Policy Act of 2005 (the “2005 Act”), the NGA has been amended to prohibit any form of market manipulation with the purchase or sale of natural gas, and the FERC has issued new regulations that are intended to increase natural gas pricing transparency. The 2005 Act has also significantly increased the penalties for violations of the NGA.
 
Regulation and transportation of natural gas.  Our sales of natural gas are affected by the availability, terms and cost of transportation. The price and terms for access to pipeline transportation are subject to extensive regulation. In recent years, the FERC has undertaken various initiatives to increase competition within the natural gas industry. As a result of initiatives like FERC Order No. 636, issued in April 1992, the interstate natural gas transportation and marketing system has been substantially restructured to remove various barriers and practices that historically limited non-pipeline natural gas sellers, including producers, from effectively competing with interstate pipelines for sales to local distribution companies and large industrial and commercial customers. The most significant provisions of Order No. 636 require that interstate pipelines provide firm and interruptible transportation service on an open access basis that is equal 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.


20


Table of Contents

 
Intrastate natural gas regulation is subject to regulation by state regulatory agencies. The Texas Railroad Commission has been changing its regulations governing transportation and gathering services provided by intrastate pipelines and gatherers. While the changes by these state regulators affect us only indirectly, they are intended to further enhance competition in natural gas markets. We cannot predict what further action the FERC or state regulators will take on these matters; however, we do not believe that we will be affected differently than other natural gas producers with which we compete by any action taken.
 
The Outer Continental Shelf Lands Act, or “OCSLA,” which the FERC implements as to transportation and pipeline issues, requires that all pipelines operating on or across the outer continental shelf, or “OCS,” provide open access, non-discriminatory transportation service. One of FERC’s principal goals in carrying out OCSLA’s mandate is to increase transparency in the market to provide producers and shippers on the OCS with greater assurance of open access service on pipelines located on the OCS and to help ensure non-discriminatory rates and conditions of service on such pipelines.
 
Although the FERC has historically imposed light-handed regulation on offshore facilities that meet its traditional test of gathering status, it has the authority under the OCSLA to exercise jurisdiction over gathering facilities, if necessary, to permit non-discriminatory access to service. In an effort to heighten its oversight of the OCS, the FERC recently attempted to promulgate reporting requirements for all OCS “service providers,” including gatherers, but the regulations were struck down as ultra vires by a federal district court, which decision was affirmed by the U.S. Court of Appeals in October 2003. The FERC withdrew those regulations in March 2004. Subsequently, in April 2004, the Minerals Management Service, or “MMS,” initiated an inquiry into whether it should amend its regulations to assure that pipelines provide open and non-discriminatory access over OCS pipeline facilities. For those facilities transporting natural gas across the OCS that are not considered to be gathering facilities, the rates, terms and conditions applicable to this transportation are generally regulated by the FERC under the NGA and NGPA, as well as the OCSLA.
 
Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, the FERC, state commissions and the courts. The natural gas industry historically has been very heavily regulated; therefore, there is no assurance that the less stringent regulatory approach recently pursued by the FERC, Congress and state regulatory authorities will continue.
 
Federal leases.  Substantially all of our offshore operations are located on federal oil and natural gas leases that are administered by the MMS pursuant to the OCSLA. These leases are issued through competitive bidding and contain relatively standardized terms. These leases require compliance with detailed Department of Interior and MMS regulations and orders that are subject to interpretation and change.
 
For offshore operations, lessees must obtain MMS approval for exploration, development and production plans prior to the commencement of such operations. In addition to permits required from other agencies such as the Coast Guard, the Army Corps of Engineers and the Environmental Protection Agency, lessees must obtain a permit from the MMS prior to the commencement of drilling. The MMS has promulgated regulations requiring offshore production facilities located on the OCS to meet stringent engineering and construction specifications. The MMS also has regulations restricting the flaring or venting of natural gas, and has proposed to amend such regulations to prohibit the flaring of liquid hydrocarbons and oil without prior authorization. Similarly, the MMS has promulgated other regulations governing the plug and abandonment of wells located offshore and the installation and removal of all production facilities.
 
To cover the various obligations of lessees on the OCS, the MMS generally requires that lessees have substantial net worth or post bonds or other acceptable assurances that such obligations will be satisfied. The cost of these bonds or assurances can be substantial, and there is no assurance that they can be obtained in all


21


Table of Contents

cases. We are currently exempt from supplemental bonding requirements by the MMS. Under some circumstances, the MMS may require any of our operations on federal leases to be suspended or terminated. Any such suspension or termination could materially adversely affect our financial condition and results of operations.
 
The MMS also administers the collection of royalties under the terms of the OCSLA and the oil and natural gas leases issued thereunder. The amount of royalties due is based upon the terms of the oil and natural gas leases as well as the regulations promulgated by the MMS. The MMS regulations governing the calculation of royalties and the valuation of crude oil produced from federal leases currently rely on arm’s-length sales prices and spot market prices as indicators of value. Although the method of calculating royalties on production from federal leases has been the subject of much public discussion in recent years, the basis for calculating royalty payments established or to be established by the MMS is generally applicable to all federal lessees. Accordingly, we believe that the impact of royalty regulation on our operations should generally be the same as the impact on our competitors.
 
Oil and Natural Gas Liquids Transportation Rates.  Our sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at market prices. In a number of instances, however, the ability to transport and sell such products is dependent on pipelines whose rates, terms and conditions of service are subject to FERC jurisdiction under the Interstate Commerce Act. In other instances, the ability to transport and sell such products is dependent on pipelines whose rates, terms and conditions of service are subject to regulation by state regulatory bodies under state statutes. The price received from the sale of these products may be affected by the cost of transporting the products to market.
 
The regulation of pipelines that transport crude oil, condensate and natural gas liquids is generally more light-handed than the FERC’s regulation of natural gas pipelines under the NGA. Regulated pipelines that transport crude oil, condensate and natural gas liquids are subject to common carrier obligations that generally ensure non-discriminatory access. With respect to interstate pipeline transportation subject to regulation of the FERC under the Interstate Commerce Act, rates generally must be cost-based, although market-based rates or negotiated settlement rates are permitted in certain circumstances. Pursuant to FERC Order No. 561, issued in October 1993, the FERC implemented regulations generally grandfathering all previously unchallenged interstate pipeline rates and made these rates subject to an indexing methodology. Under this indexing methodology, pipeline rates are subject to changes in the Producer Price Index for Finished Goods, minus one percent. A pipeline can seek to increase its rates above index levels provided that the pipeline can establish that there is a substantial divergence between the actual costs experienced by the pipeline and the rate resulting from application of the index. A pipeline can seek to charge a market-based rate if it establishes that it lacks significant market power. In addition, a pipeline can establish rates pursuant to settlement if agreed upon by all current shippers. A pipeline can seek to establish initial rates for new services through a cost-of-service proceeding, a market-based rate proceeding, or through an agreement between the pipeline and at least one shipper not affiliated with the pipeline. As provided for in Order No. 561, in July 2000, the FERC issued a Notice of Inquiry seeking comment on whether to retain or to 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.


22


Table of Contents

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


23


Table of Contents

“hazardous wastes,” thereby potentially subjecting such wastes to more stringent handling, disposal and cleanup requirements. If such legislation were enacted, it could have a significant impact on our operating cost, as well as the oil and natural gas industry in general. The impact of future revisions to environmental laws and regulations cannot be predicted.
 
Our operations are also subject to the Clean Air Act, or “CAA,” and comparable state and local requirements. Amendments to the CAA were adopted in 1990 and contain provisions that may result in the gradual imposition of certain pollution control requirements with respect to air emissions from our operations. We may be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions. However, we believe our operations will not be materially adversely affected by any such requirements, and the requirements are not expected to be any more burdensome to us than to other similarly situated companies involved in oil and natural gas exploration and production activities.
 
The Federal Water Pollution Control Act of 1972, as amended, or the “Clean Water Act,” imposes restrictions and controls on the discharge of produced waters and other wastes into navigable waters. Permits must be obtained to discharge pollutants into state and federal waters and to conduct construction activities in waters and wetlands. Certain state regulations and the general permits issued under the Federal National Pollutant Discharge Elimination System program prohibit the discharge of produced waters and sand, drilling fluids, drill cuttings and certain other substances related to the oil and natural gas industry into certain coastal and offshore waters, unless otherwise authorized. Further, the EPA has adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain permits for storm water discharges. Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans. The Clean Water Act and comparable state statutes provide for civil, criminal and administrative penalties for unauthorized discharges for oil and other pollutants and impose liability on parties responsible for those discharges for the cost of cleaning up any environmental damage caused by the release and for natural resource damages resulting from the release. We believe that our operations comply in all material respects with the requirements of the Clean Water Act and state statutes enacted to control water pollution.
 
Federal regulators require certain owners or operators of facilities that store or otherwise handle oil to prepare and implement spill prevention, control, countermeasure and response plans relating to the possible discharge of oil into surface waters. The Oil Pollution Act of 1990 (“OPA”) contains numerous requirements relating to the prevention and response to oil spills in the waters of the United States. The OPA subjects owners of facilities to strict joint and several liability for all containment and cleanup costs and certain other damages relating to a spill. Noncompliance with OPA may result in varying civil and criminal penalties and liabilities.
 
Executive Order 13158, issued on May 26, 2000, directs federal agencies to safeguard existing Marine Protected Areas, or “MPAs,” in the United States and establish new MPAs. The order requires federal agencies to avoid harm to MPAs to the extent permitted by law and to the maximum extent practicable. It also directs the EPA to propose new regulations under the Clean Water Act to ensure appropriate levels of protection for the marine environment. This order has the potential to adversely affect our operations by restricting areas in which we may carry out future exploration and development projects and/or causing us to incur increased operating expenses.
 
Certain flora and fauna that have officially been classified as “threatened” or “endangered” are protected by the Endangered Species Act. This law prohibits any activities that could “take” a protected plant or animal or reduce or degrade its habitat area. If endangered species are located in an area we wish to develop, the work could be prohibited or delayed and/or expensive mitigation might be required.


24


Table of Contents

 
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 and in Houston, Texas covering 16,285 square feet at a monthly rate of $28,600. These leases expire on July 31, 2014 and April 30, 2012, respectively. We also own production offices and pipe yard facilities near Marshall and Livingston, Texas; Logansport, Louisiana; Guston, Kentucky and Laurel, Mississippi.
 
Employees
 
As of December 31, 2006, we had 130 employees and utilized contract employees for certain of our field operations. We consider our employee relations to be satisfactory.


25


Table of Contents

 
Directors, Executive Officers and Other Management
 
The following table sets forth certain information concerning our executive officers and directors.
 
             
Name
 
Position With Company
 
Age
 
M. Jay Allison
  President, Chief Executive Officer and Chairman of the Board of Directors   51
Roland O. Burns
  Senior Vice President, Chief Financial Officer, Secretary, Treasurer and Director   46
D. Dale Gillette
  Vice President of Land and General Counsel   61
Mack D. Good
  Chief Operating Officer   56
Stephen E. Neukom
  Vice President of Marketing   57
Daniel K. Presley
  Vice President of Accounting and Controller   46
Richard D. Singer
  Vice President of Financial Reporting   52
David K. Lockett
  Director   52
Cecil E. Martin, Jr. 
  Director   65
David W. Sledge
  Director   50
Nancy E. Underwood
  Director   55
 
Executive Officers
 
A brief biography of each person who serves as a director or executive officer follows below.
 
M. Jay Allison has been a director since June 1987, and our President and Chief Executive Officer since 1988. Mr. Allison was elected Chairman of the board of directors in 1997. From 1987 to 1988, Mr. Allison served as our Vice President and Secretary. From 1981 to 1987, he was a practicing oil and gas attorney with the firm of Lynch, Chappell & Alsup in Midland, Texas. He received B.B.A., M.S. and J.D. degrees from Baylor University in 1978, 1980 and 1981, respectively. Mr. Allison also serves as Chairman of the board of directors of Bois d’Arc Energy, Inc. and currently serves as a director of Tidewater Marine, Inc., on the Board of Regents for Baylor University and on the Advisory Board of the Salvation Army in Dallas, Texas.
 
Roland O. Burns has been our Senior Vice President since 1994, Chief Financial Officer and Treasurer since 1990, our Secretary since 1991 and a director since 1999. Mr. Burns also serves as Senior Vice President, Chief Financial Officer, Secretary and a director of Bois d’Arc Energy, Inc. From 1982 to 1990, Mr. Burns was employed by the public accounting firm, Arthur Andersen 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.
 
D. Dale Gillette joined us as Vice President of Land and General Counsel in September 2006. Prior to joining us, Mr. Gillette practiced law extensively in the energy sector for 32 years, most recently as a partner with Gardere Wynne Sewell LLP, and before that with Locke Liddell & Sapp LLP. During that time he represented independent exploration and production companies and large financial institutions in numerous oil and gas transactions. Mr. Gillette has also served as corporate counsel in the legal department of Mesa Petroleum Co. and in the legal department of Enserch Corp. Mr. Gillette holds B.A. and J.D. degrees from the University of Texas and is a member of the State Bar of Texas.


26


Table of Contents

 
Mack D. Good was appointed our Chief Operating Officer in 2004. From 1999 to 2004, he served as Vice President of Operations. From August 1997 until February 1999, Mr. Good served as our district engineer for the East Texas/North Louisiana region. From 1983 until July 1997, Mr. Good was with Enserch Exploration, Inc. serving in various operations management and engineering positions. Mr. Good received a B.S. of Biology/Chemistry from Oklahoma State University in 1975 and a B.S. of Petroleum Engineering from the University of Tulsa in 1983. He is a Registered Professional Engineer in the State of Texas.
 
Stephen E. Neukom has been our Vice President of Marketing since December 1997 and has served as our manager of crude oil and natural gas marketing since December 1996. From October 1994 to 1996, Mr. Neukom served as vice president of Comstock Natural Gas, Inc., our former wholly owned gas marketing subsidiary. Prior to joining us, Mr. Neukom was senior vice president of Victoria Gas Corporation from 1987 to 1994. Mr. Neukom received a B.B.A. degree from the University of Texas in 1972.
 
Daniel K. Presley has been our Vice President of Accounting since December 1997 and has been with us since December 1989, serving as controller since 1991. Prior to joining us, Mr. Presley had six years of experience with several independent oil and gas companies including AmBrit Energy, Inc. Prior thereto, Mr. Presley spent two and one-half years with B.D.O. Seidman, a public accounting firm. Mr. Presley received a B.B.A. from Texas A & M University in 1983.
 
Richard D. Singer joined us in June 2005 as Vice President of Financial Reporting. Mr. Singer has over 30 years of experience in financial accounting and reporting. Prior to joining us, Mr. Singer most recently served as an assistant controller for Holly Corporation from March 2004 to May 2005 and as assistant controller for Santa Fe International Corporation from July 1988 to December 2002. Mr. Singer received a B.S. degree from the Pennsylvania State University in 1976 and is a Certified Public Accountant.
 
Outside Directors
 
David K. Lockett has served as a director since July 2001. Mr. Lockett has been a Vice President of Dell Inc. and has managed Dell’s Small and Medium Business Group since 1996. Mr. Lockett has been employed by Dell Inc. for the last 15 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 on the board of directors of Crosstex Energy, Inc. and Crosstex Energy, L.P. Mr. Martin holds a B.B.A. degree from Old Dominion University and is a Certified Public Accountant.
 
David W. Sledge has served as a director since May 1996. Mr. Sledge is currently President and Chief Officer of Sledge Drilling Corporation. 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 1986. Ms. Underwood holds B.S. and J.D. degrees from Emory University and practiced law at an Atlanta, Georgia based law firm before joining River Hill


27


Table of Contents

Development Corporation in 1981. Ms. Underwood is involved civically in the Dallas community and currently serves on the board of the Presbyterian Hospital of Dallas Foundation.
 
Available Information
 
Our executive offices are located at 5300 Town and Country Blvd., Suite 500, Frisco, Texas 75034. Our telephone number is (972) 668-8800. We file annual, quarterly and current reports, proxy statements and other documents with the SEC under the Securities Exchange Act of 1934. The public may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 450 Fifth Street, N.W., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. In addition, the SEC maintains a website that contains reports, proxy and information statements, and other information that is electronically filed with the SEC. The public can obtain any documents that we file with the SEC at www.sec.gov. We also make available free of charge on our website (www.comstockresources.com) our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, current reports on Form 8-K and, if applicable, amendments to those reports filed or furnished pursuant to Section 13(a) of the Exchange Act as soon as reasonably practicable after we file such material with, or furnish it to, the SEC.
 
ITEM 1A.   RISK FACTORS
 
You should carefully consider the following risk factors as well as the other information contained or incorporated by reference in this report, as these are important factors, among others, 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;


28


Table of Contents

  •  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.
 
The unavailability or high cost of drilling rigs, equipment, supplies or qualified personnel and oilfield services could adversely affect our ability to execute our exploration and development plans on a timely basis and within our budget.
 
With the increasing oil and natural gas prices, our industry has experienced a shortage of drilling rigs, equipment, supplies and qualified personnel. Costs and delivery times of rigs, equipment and supplies are substantially greater than they were several years ago. In addition, demand for, and wage rates of, qualified drilling rig crews rise with increases in the number of active rigs in service. Shortages of drilling rigs, equipment or supplies or qualified personnel in the areas in which we operate could delay or restrict our exploration and development operations, which in turn could adversely affect our financial condition and results of operations because of our concentration in those areas.
 
We 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


29


Table of Contents

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 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 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.
 
We are vulnerable to operational, regulatory and other risks associated with the Gulf of Mexico, including the effects of adverse weather conditions such as hurricanes, because we currently explore and produce exclusively in that area.
 
Our offshore operations and revenues are significantly impacted by conditions in the Gulf of Mexico. Risks associated with the Gulf of Mexico include:
 
  •  adverse weather conditions, including hurricanes and tropical storms;
  •  delays or decreases in production, the availability of equipment, facilities or services;
  •  delays or decreases in the availability of capacity to transport, gather or process production; and
  •  changes in the regulatory environment.
 
Offshore operations are also subject to a variety of operating risks peculiar to the marine environment, such as capsizing, collisions and damage or loss from hurricanes or other adverse weather conditions. These conditions can cause substantial damage to our facilities and interrupt our production. As a result, we could incur substantial liabilities that could reduce or eliminate the funds available for exploration and development or result in loss of equipment and property. For example, our offshore operations were substantially impacted in 2004, 2005 and 2006 by hurricane and tropical storm activity. In both 2004 and 2005, we had


30


Table of Contents

production shut-in for six different hurricanes or tropical storms. In 2004, 2005 and 2006 we also had production shut-in awaiting repairs to third party pipelines that were damaged by the hurricanes.
 
We plan to conduct exploration, development and production operations on the deep shelf and in the deepwater of the Gulf of Mexico, which presents greater operating and financial risks than conventional shelf operations.
 
The deep shelf of the Gulf of Mexico is an area that has had limited historical drilling activity. This is due, in part, to its geological complexity and depth. Deep shelf development can be more expensive than conventional shelf projects as deep shelf development requires more actual drilling days and higher drilling and services costs due to extreme pressure and temperatures associated with greater drilling depths. Moreover, drilling expense and the risk of mechanical failure are significantly higher because of the additional depth and adverse conditions such as high temperature and pressure. Also, seismic interpretation of deeper, geopressured formations is more difficult than at shallower, normally pressured conventional well depths. Our overall exploration success rate has been 73%. Of the 25 deep shelf wells that we have drilled, 15 successfully found hydrocarbons at geologic and drilling depths below 15,000 feet, for a success rate of 54%. This success rate is lower than our overall success rate, reflecting the fact that deep shelf drilling is inherently more risky than conventional shelf drilling. Deepwater development costs can also be significantly higher than shelf development costs because deepwater drilling requires bigger installation equipment; sophisticated sea floor production handling equipment; expensive, state-of-the-art platforms and/or investment in infrastructure Accordingly, we cannot assure you that our oil and natural gas exploration activities, in the deep shelf, the deepwater and elsewhere, will be commercially successful.
 
Our debt service requirements could adversely affect our operations and limit our growth.
 
We had $455.0 million in debt as of December 31, 2006, and our ratio of total debt to total capitalization was approximately 40%.
 
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.


31


Table of Contents

 
Our bank credit facility contains a number of significant covenants. These covenants will limit our ability to, among other things:
 
  •  borrow additional money;
  •  merge, consolidate or dispose of assets;
  •  make certain types of investments;
  •  enter into transactions with our affiliates; and
  •  pay dividends.
 
Our failure to comply with any of these covenants would cause a default under our bank credit facility and the indenture governing our 67/8% senior notes due 2012. A default, if not waived, could result in acceleration of our indebtedness, in which case the debt would become immediately due and payable. If this occurs, we may not be able to repay our debt or borrow sufficient funds to refinance it. Even if new financing is available, it may not be on terms that are acceptable to us. Complying with these covenants may cause us to take actions that we otherwise would not take or not take actions that we otherwise would take.
 
Our business involves many uncertainties and operating risks that can prevent us from realizing profits and can cause substantial losses.
 
Our future success will depend on the success of our exploration and development activities. Exploration activities involve numerous risks, including the risk that no commercially productive natural gas or oil reserves will be discovered. In addition, these activities may be unsuccessful for many reasons, including weather, cost overruns, equipment shortages and mechanical difficulties. Moreover, the successful drilling of a natural gas or oil well does not ensure we will realize a profit on our investment. A variety of factors, both geological and market-related, can cause a well to become uneconomical or only marginally economical. In addition to their costs, unsuccessful wells can hurt our efforts to replace production and reserves.
 
Our business involves a variety of operating risks, including:
 
  •  unusual or unexpected geological formations;
  •  fires;
  •  explosions;
  •  blow-outs and surface cratering;
  •  uncontrollable flows of natural gas, oil and formation water;
  •  natural disasters, such as hurricanes, tropical storms and other adverse weather conditions;
  •  pipe, cement, sub-sea pipeline or onshore pipeline failures;
  •  casing collapses;
  •  mechanical difficulties, such as lost or stuck oil field drilling and service tools;
  •  abnormally pressured formations; and
  •  environmental hazards, such as natural gas leaks, oil spills, pipeline ruptures and discharges of toxic gases.
 
If we experience any of these problems, well bores, gathering systems and processing facilities could be affected, which could adversely affect our ability to conduct operations.
 
We could also incur substantial losses as a result of:
 
  •  injury or loss of life;
  •  severe damage to and destruction of property, natural resources and equipment;
  •  pollution and other environmental damage;


32


Table of Contents

  •  clean-up responsibilities;
  •  regulatory investigation and penalties;
  •  suspension of our operations; and
  •  repairs to resume operations.
 
We operate in a highly competitive industry, and our failure to remain competitive with our competitors, many of which have greater resources than we do, could adversely affect our results of operations.
 
The oil and natural gas industry is highly competitive in the search for and development and acquisition of reserves. Our competitors for the acquisition, development and exploration of oil and natural gas properties and capital to finance such activities, include companies that have greater financial and personnel resources than we do. These resources could allow those competitors to price their products and services more aggressively than we can, which could hurt our profitability. Moreover, our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to close transactions in a highly competitive environment.
 
Our competitors may use superior technology that we may be unable to afford or which would require costly investment by us in order to compete.
 
If our competitors use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement new technologies at a substantial cost. In addition, our competitors may have greater financial, technical and personnel resources that allow them to enjoy technological advances and may in the future allow them to implement new technologies before we can. We cannot be certain that we will be able to implement technologies on a timely basis or at a cost that is acceptable to us. One or more of the technologies that we currently use or that we may implement in the future may become obsolete. All of these factors may inhibit our ability to acquire additional prospects and compete successfully in the future.
 
Substantial exploration and development activities could require significant outside capital, which could dilute the value of our common shares and restrict our activities. Also, we may not be able to obtain needed capital or financing on satisfactory terms, which could lead to a limitation of our future business opportunities and a decline in our oil and natural gas reserves.
 
We expect to expend substantial capital in the acquisition of, exploration for and development of oil and natural gas reserves. In order to finance these activities, we may need to alter or increase our capitalization substantially through the issuance of debt or equity securities, the sale of non-strategic assets or other means. The issuance of additional equity securities could have a dilutive effect on the value of our common shares. The issuance of additional debt would require that a portion of our cash flow from operations be used for the payment of interest on our debt, thereby reducing our ability to use our cash flow to fund working capital, capital expenditures, acquisitions, dividends and general corporate requirements, which could place us at a competitive disadvantage relative to other competitors. Additionally, if our revenues decrease as a result of lower oil or natural gas prices, operating difficulties or declines in reserves, our ability to obtain the capital necessary to undertake or complete future exploration and development programs and to pursue other opportunities may be limited, which could result in a curtailment of our operations relating to exploration and development of our prospects, which in turn could result in a decline in our oil and natural gas reserves.


33


Table of Contents

 
If oil and natural gas prices decrease, we may be required to write-down the carrying values and/or the estimates of total reserves of our oil and natural gas properties, which would constitute a non-cash charge to earnings and adversely affect our results of operations.
 
Accounting rules applicable to us require that we review periodically the carrying value of our oil and natural gas properties for possible impairment. Based on specific market factors and circumstances at the time of prospective impairment reviews and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying value of our oil and natural gas properties. A write-down constitutes a non-cash charge to earnings. We may incur non-cash charges in the future, which could have a material adverse effect on our results of operations in the period taken. We may also reduce our estimates of the reserves that may be economically recovered, which could have the effect of reducing the total value of our reserves. Such a reduction in carrying value could impact our borrowing ability and may result in accelerating the repayment date of any outstanding debt.
 
Our reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in our reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.
 
Reserve engineering is a subjective process of estimating the recovery from underground accumulations of oil and natural gas that cannot be precisely measured. The accuracy of any reserve estimate depends on the quality of available data, production history and engineering and geological interpretation and judgment. Because all reserve estimates are to some degree imprecise, the quantities of oil and natural gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future oil and natural gas prices may all differ materially from those assumed in these estimates. The information regarding present value of the future net cash flows attributable to our proved oil and natural gas reserves is only estimated and should not be construed as the current market value of the oil and natural gas reserves attributable to our properties. Thus, such information includes revisions of certain reserve estimates attributable to proved properties included in the preceding year’s estimates. Such revisions reflect additional information from subsequent activities, production history of the properties involved and any adjustments in the projected economic life of such properties resulting from changes in product prices. Any future downward revisions could adversely affect our financial condition, our borrowing ability, our future prospects and the value of our common stock.
 
As of December 31, 2006, 34% of our total proved reserves are undeveloped and 30% 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.


34


Table of Contents

 
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.
 
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;


35


Table of Contents

  •  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.
 
Compliance with MMS regulations could significantly delay or curtail our operations or require us to make material expenditures, all of which could have a material adverse effect on our financial condition or results of operations.
 
Substantially all of Bois d’Arc Energy’s offshore operations are located on federal oil and natural gas leases that are administered by the MMS. As an offshore operator, Bois d’Arc Energy must obtain MMS approval for our exploration, development and production plans prior to commencing such operations. The MMS has promulgated regulations that, among other things, require Bois d’Arc Energy to meet stringent engineering and construction specifications, restrict the flaring or venting of natural gas, govern the plug and abandonment of wells located offshore and the installation and removal of all production facilities, and govern the calculation of royalties and the valuation of crude oil produced from federal leases.
 
Our operations may incur substantial liabilities to comply with environmental laws and regulations.
 
Our oil and natural gas operations are subject to stringent federal, state and local laws and regulations relating to the release or disposal of materials into the environment and otherwise relating to environmental protection. These laws and regulations:
 
  •  require the acquisition of a permit before drilling commences;
  •  restrict the types, quantities and concentration of substances that can be released into the environment in connection with drilling and production activities;
  •  limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; and
  •  impose substantial liabilities for pollution resulting from our operations.
 
Failure to comply with these laws and regulations may result in:
 
  •  the assessment of administrative, civil and criminal penalties;
  •  the incurrence of investigatory or remedial obligations; and
  •  the imposition of injunctive relief.
 
Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly waste handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to reach and maintain compliance and may otherwise have a material adverse effect on our industry in general and on our own results of operations, competitive position or financial


36


Table of Contents

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 2006.


37


Table of Contents

 
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  
 
  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  
                         
  2006 —     First Quarter   $ 34.25     $ 25.43  
        Second Quarter     33.53       24.79  
        Third Quarter     30.99       24.84  
        Fourth Quarter     33.80       23.97  
 
As of February 28, 2007, we had 44,396,995 shares of common stock outstanding, which were held by 340 holders of record and approximately 20,700 beneficial owners who maintain their shares in “street name” accounts.
 
We have never paid cash dividends on our common stock. We presently intend to retain any earnings for the operation and expansion of our business and we do not anticipate paying cash dividends in the foreseeable future. Any future determination as to the payment of dividends will depend upon the results of our operations, capital requirements, our financial condition and such other factors as our board of directors may deem relevant. In addition, we are limited under our bank credit facility and by the terms of the indenture for our senior notes from paying or declaring cash dividends in excess of $40.0 million.
 
During the fourth quarter of 2006, we did not repurchase any of our equity securities.
 
The following table summarizes certain information regarding our equity compensation plans as of December 31, 2006:
 
                         
                Number of Securities
 
    Number of Securities
          Authorized for Future
 
    to be Issued upon
    Weighted Average
    Issuance under Equity
 
    Exercise of
    Exercise Price of
    Compensation Plans
 
    Outstanding Options,
    Outstanding Options,
    (Excluding Outstanding
 
    Warrants and Rights     Warrants and Rights     Options, Warrants and Rights)  
 
Equity compensation plans approved by stockholders
    1,468,970     $ 11.59       328,351 (1)
 
(1) Plus 1% of the outstanding shares of common stock each year beginning on each subsequent January 1.
 
We do not have any equity compensation plans that were not approved by stockholders.


38


Table of Contents

 
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, 2006 are derived from our consolidated financial statements. The financial results are not necessarily indicative of our future operations or future financial results. The data presented below should be read in conjunction with our consolidated financial statements and the notes thereto and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” Effective January 1, 2006, we began including Bois d’Arc Energy in our financial statements as a consolidated subsidiary. Our financial statements for data and periods prior to January 1, 2006 have not been adjusted. For comparative purposes, financial information for 2005 are also presented pro forma to reflect Bois d’Arc Energy as a consolidated subsidiary.
 
Statement of Operations Data:
 
                                                 
    Year Ended December 31,  
                                  2005
 
    2002     2003     2004     2005     2006     Pro Forma  
    (In thousands, except per share data)  
 
Oil and gas sales
  $  142,085     $  235,102     $  261,647     $  303,336     $  511,928     $ 449,242  
Operating expenses:
                                               
Oil and gas operating(1)
    33,499       45,746       52,068       50,966       107,303       81,356  
Exploration
    5,479       4,410       15,610       19,725       20,132       33,693  
Depreciation, depletion and amortization
    53,155       61,169       63,879       63,338       153,922       95,977  
Impairment
          4,255       1,648       3,400       10,444       3,990  
General and administrative, net
    5,113       7,006       14,569       16,533       31,769       24,017  
                                                 
Total operating expenses
    97,246       122,586       147,774       153,962       323,570       239,033  
                                                 
Income from operations
    44,839       112,516       113,873       149,374       188,358       210,209  
Other income (expenses):
                                               
Interest income
    62       73       1,207       1,604       1,012       610  
Other income
    8,027       223       166       209       781       209  
Interest expense
    (31,252 )     (29,860 )     (21,182 )     (20,272 )     (27,429 )     (21,365 )
Loss of disposal of assets
                                  (89 )
Formation costs of Bois d’Arc Energy
                (1,101 )                  
Gain on sale of stock by Bois d’Arc Energy
                      28,797             28,797  
Gain (loss) from derivatives
    (2,326 )     (3 )     (155 )     (13,556 )     10,716       (13,556 )
Loss on early extinguishment of debt
                (19,599 )                  
                                                 
Total other income (expense)
    (25,489 )     (29,567 )     (40,664 )     (3,218 )     (14,920 )     (5,394 )
                                                 
Income from continuing operations before income taxes, equity in loss of Bois d’Arc Energy, and minority interest in earnings of Bois d’Arc Energy
    19,350       82,949       73,209       146,156       173,438       204,815  
Income tax expense
    (6,773 )     (29,682 )     (26,342 )     (35,815 )     (74,339 )     (161,623 )
Equity in loss of Bois d’Arc Energy
                      (49,862 )            
Minority interest in earnings of Bois d’Arc Energy
                            (28,434 )     17,287  
                                                 
Net income from continuing operations
    12,577       53,267       46,867       60,479       70,665       60,479  
Discontinued operations including gain (loss) on disposal, net of income taxes
    (1,072 )                              
Cumulative effect of change in accounting principle
          675                          
                                                 
Net income
    11,505       53,942       46,867       60,479       70,665       60,479  
Preferred stock dividends
    (1,604 )     (573 )                        
                                                 
Net income attributable to common stock
  $ 9,901     $ 53,369     $ 46,867     $ 60,479     $ 70,665     $ 60,479  
                                                 
Basic net income per share:
                                               
From continuing operations
  $ 0.38     $ 1.65     $ 1.37     $ 1.54     $ 1.67     $ 1.54  
Discontinued operations
    (0.04 )                              
Cumulative effect of change in accounting principle
          0.02                          
                                                 
      0.34     $ 1.67     $ 1.37     $ 1.54     $ 1.67     $ 1.54  
                                                 
Diluted net income per share:
                                               
From continuing operations
  $ 0.37     $ 1.51     $ 1.29     $ 1.47     $ 1.61     $ 1.47  
Discontinued operations
    (0.03 )                              
Cumulative effect of change in accounting principle
          0.02                          
                                                 
    $ 0.34     $ 1.53     $ 1.29     $ 1.47     $ 1.61     $ 1.47  
                                                 
Weighted average shares outstanding:
                                               
Basic
    28,764       31,964       34,187       39,216       42,220       39,216  
                                                 
Diluted
    33,901       35,275       36,252       41,154       43,556       41,154  
                                                 
 
(1) Includes lease operating costs and production and ad valorem taxes.


39


Table of Contents

 
Balance Sheet Data:
 
                                                 
    Year Ended December 31,  
                                  2005
 
    2002     2003     2004     2005     2006     Pro Forma  
    (In thousands)  
 
Cash and cash equivalents
  $     1,682     $     5,343     $     2,703     $        89     $    10,715     $    12,132  
Property and equipment, net
    664,208       698,686       827,761       706,928       1,773,626       1,368,859  
Investment in Bois d’Arc Energy
                      252,134              
Total assets
    711,053       746,356       941,476       1,016,663       1,878,125       1,477,307  
Total debt
    366,272       306,623       403,150       243,000       458,250       312,000  
Redeemable convertible preferred stock
    17,573                                
Stockholders’ equity
    208,427       289,656       355,853       582,859       682,563       582,859  
Cash flows provided by operating activities
    84,437       153,785       171,351       217,954       364,605       322,744  
Cash flows used for investing activities
    (79,903 )     (92,930 )     (258,061 )     (207,086 )     (529,751 )     (512,692 )
Cash flows provided by (used for) financing activities
    (8,974 )     (57,194 )     84,070       (13,482 )     163,729       198,408  
 
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 1,766 (820.7 net to us) producing oil and natural gas wells and we operate 805 of these wells. We own a controlling interest in Bois d’Arc Energy, an independent exploration company that owns interests in offshore producing oil and natural gas wells in the Gulf of Mexico. The results of Bois d’Arc Energy have been included in our consolidated financial statements as of January 1, 2006. In managing our business, we are concerned primarily with maximizing return on our stockholders’ equity. To accomplish this goal, we focus on profitably increasing our oil and natural gas reserves and production.
 
Our future growth will be driven primarily by acquisition, development and exploration activities. Under our current drilling budget, we plan to spend approximately $478.0 million in 2007 for development and exploration activities. We plan to drill approximately 160 development wells, 113 net to us, and 25 exploratory wells, 15.9 net to us in 2007. However, the number of wells that we drill in 2007 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


40


Table of Contents

consist of costs we incur to acquire and reprocess 3-D seismic data, impairments of our unevaluated leasehold where we were not successful in discovering reserves and the costs of unsuccessful exploratory wells that we drill.
 
We generally sell our oil and natural gas at current market prices at the point our wells connect to third party purchaser pipelines. We market our products several different ways depending upon a number of factors, including the availability of purchasers for the product, the availability and cost of pipelines near our wells, market prices, pipeline constraints and operational flexibility. Accordingly, our revenues are heavily dependent upon the prices of, and demand for, oil and natural gas. Oil and natural gas prices have historically been volatile and are likely to remain volatile in the future.
 
Our operating costs are generally comprised of several components, including costs of field personnel, 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 $57.1 million as of December 31, 2006.
 
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. The results for offshore operations in 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. Subsequent to the conversion into a corporation and as a result of the public offering, we owned 48% of the outstanding shares of Bois d’Arc Energy. Since proportionate consolidation is not a generally accepted accounting principle applicable to an investment in a corporation, we changed our accounting method for our investment in Bois d’Arc Energy to the equity method concurrent with Bois d’Arc Energy’s conversion to a corporation. The offshore results for 2005 include our proportionate interest in the operations of Bois d’Arc Energy based upon our ownership interest throughout the period presented. The equity method adjustments reflect the reductions to our share of Bois d’Arc Energy’s operating results that are necessary to apply the equity method of accounting for all periods subsequent to the conversion of Bois d’Arc Energy to a corporation.


41


Table of Contents

 
During 2006 we acquired additional shares of common stock of Bois d’Arc Energy, which increased our direct ownership interest in Bois d’Arc Energy. As a result, we have voting control of Bois d’Arc Energy through our direct share ownership combined with the share ownership of members of our Board of Directors. The results of Bois d’Arc Energy are included in our financial statements as a consolidated subsidiary, and as permitted by generally accepted accounting principles, consolidated revenues, expenses and cash flows for 2006 reflect Bois d’Arc Energy as a consolidated subsidiary as of January 1, 2006. Financial statements for dates and periods prior to January 1, 2006, have not been adjusted. The inclusion of Bois d’Arc Energy as a consolidated subsidiary in our financial statements had no impact on our net income, and although the adjustment to reflect Bois d’Arc Energy as a consolidated subsidiary had no impact on our net income, comparisons of the separate components of our results of operations are significantly impacted by this change. In order to provide more meaningful information regarding comparisons of our results for the year ended December 31, 2006, our discussion of our operating results and capital expenditures is presented based upon a comparison of actual 2006 results to pro forma results for 2005 adjusted to include Bois d’Arc Energy as a consolidated subsidiary.
 
The onshore data in the tables below contains the results of operations for our direct ownership in our onshore oil and gas properties. The offshore data contains the results of operations of Bois d’Arc Energy after its formation in July 2004 and our Gulf of Mexico production that we contributed to Bois d’Arc Energy prior to Bois d’Arc Energy’s formation. The 2006 data and the pro forma 2005 data reflect 100% of the operations of Bois d’Arc Energy. The 2004 and 2005 results reflect only our proportionate share of Bois d’Arc Energy’s operations.
 
Results of Operations
 
Year Ended December 31, 2006 Compared to Pro Forma Year Ended December 31, 2005
 
Our operating data for 2006 and 2005 on a pro forma basis is summarized below:
 
                         
    Onshore     Offshore     Total  
 
Year Ended December 31, 2006
                       
Net Production Data:
                       
Oil (MBbls)
    921       1,383       2,304  
Natural gas (MMcf)
    30,271       23,183       53,454  
Natural gas equivalent (MMcfe)
    35,797       31,481       67,278  
Average Sales Price:
                       
Oil ($/Bbl)
  $ 55.32     $ 64.66     $ 60.93  
Natural gas ($/Mcf)
  $ 6.81     $ 7.13     $ 6.95  
Average equivalent price ($/Mcfe)
  $ 7.19     $ 8.09     $ 7.61  
Expenses ($ per Mcfe):
                       
Oil and gas operating(1)
  $ 1.51     $ 1.70     $ 1.59  
Depreciation, depletion and amortization(2)
  $ 2.10     $ 2.45     $ 2.28  
                         
Pro Forma Year Ended December 31, 2005
                       
Net Production Data:
                       
Oil (MBbls)
    735       1,155       1,890  
Natural gas (MMcf)
    28,742       14,896       43,638  
Natural gas equivalent (MMcfe)
    33,151       21,825       54,976  
Average Sales Price:
                       
Oil ($/Bbl)
  $ 49.34     $ 52.88     $ 51.50  
Natural gas ($/Mcf)
  $ 7.95     $ 8.28     $ 8.06  
Average equivalent price ($/Mcfe)
  $ 7.99     $ 8.45     $ 8.17  
Expenses ($ per Mcfe):
                       
Oil and gas operating(1)
  $ 1.34     $ 1.70     $ 1.48  
Depreciation, depletion and amortization(2)
  $ 1.60     $ 1.95     $ 1.74  
 
(1) Includes lease operating costs and production and ad valorem taxes.
(2) Represents depreciation, depletion and amortization of oil and gas properties only.


42


Table of Contents

 
Oil and gas sales.  Our oil and gas sales increased $62.7 million (14%) in 2006 to $511.9 million from pro forma consolidated sales of $449.2 million in 2005. This increase primarily reflects a 22% increase in production which was partially offset by lower natural gas prices in 2006. Our average natural gas price decreased by 14% in 2006 as compared to our average gas price in 2005. Prices for crude oil increased by 18% in 2006 as compared to our prices for crude oil in 2005. Our natural gas production increased by 22% in 2006 over 2005. Higher offshore natural gas production was primarily due to production from new wells drilled and the restoration of certain of our offshore production with the return to service of pipelines and facilities in 2006 after being shut in due to hurricanes in 2005. Our onshore natural gas production increased by 5%, reflecting our active development drilling program and production attributable to the properties we acquired in 2005. Oil production increased 22% in 2006 over 2005. Higher oil production onshore in 2006 resulted mainly from additional production from the properties we acquired in 2005. The increase in offshore oil production resulted from the restoration of pipelines and facilities offshore and production from new wells that we drilled.
 
Oil and gas operating expenses.  Our oil and gas operating expenses, including production taxes, increased $25.9 million (32%) to $107.3 million in 2006 from pro forma consolidated operating expenses of $81.4 million in 2005. Oil and gas operating expenses per equivalent Mcf produced increased $0.11 to $1.59 in 2006 as compared with $1.48 in 2005. Onshore operating expenses in 2006 increased due to costs associated with the properties we acquired in 2005 or drilled in 2006. The increase in offshore operating expenses resulted primarily from increased cost of services and materials for fuel, services and supplies, and higher insurance costs.
 
Exploration expense.  In 2006, we incurred $20.1 million in exploration expense as compared to pro forma consolidated exploration expense of $33.7 million in 2005. Exploration expense in 2006 primarily relates to dry hole expense for three offshore exploratory wells, two onshore exploratory wells, the acquisition and reprocessing of offshore 3-D seismic data, and impairment of unproved properties. Pro forma exploration expense in 2005 includes $16.7 million for the Big Sandy dry hole onshore, and the cost of one offshore exploratory dry hole and offshore seismic costs.
 
DD&A.  Depreciation, depletion and amortization (“DD&A”) increased $57.9 million (60%) to $153.9 million in 2006 from pro forma consolidated DDA expense of $96.0 million in 2005. Our DD&A rate per Mcfe produced averaged $2.28 in 2006 as compared to $1.74 for 2005. DD&A expense in 2006 for onshore operations increased $22.1 million or (42%) from 2005 due to higher production and an increase in the onshore amortization rate caused by higher capitalized costs of the development wells we drilled. Offshore DD&A expenses for 2006 increased from 2005 due to increased production and a higher the amortization rate. The offshore amortization rate results from higher capitalized costs associated with the wells we drilled and the installation of new production facilities.
 
Impairment.  We recorded impairments to our oil and gas properties of $10.4 million in 2006 as compared to pro forma consolidated impairment expense of $4.0 million in 2005. Impairment of onshore properties of $8.8 million increased in 2006 over 2005 primarily due to impairment in 2006 of a property that was held for resale. Subsequently the plan to sell the property was cancelled. The impairment reflected this property’s estimated fair market value at the time the plan to sell the property changed. Offshore impairments of $1.6 million were related to several minor valued fields.
 
General and administrative expenses.  General and administrative expenses, which are reported net of overhead reimbursements, of $31.8 million for 2006 were 32% higher than pro forma consolidated general and administrative expenses of $24.0 million for 2005. The increase primarily reflects higher personnel costs in 2006 due to increased staffing necessary to support the higher activity levels in our exploration and development programs, an increase of $3.4 million in stock-based compensation in 2006 as


43


Table of Contents

compared to 2005, and the increased costs of compliance related to Bois d’Arc Energy which became a public company in May 2005.
 
Interest expense.  Interest expense increased $6.0 million (28%) to $27.4 million in 2006 from pro forma consolidated interest expense of $21.4 million in 2005. The increase was primarily the result of higher borrowings and higher interest rates in 2006. Average borrowings under our bank credit facilities increased to $188.6 million in 2006 as compared to $166.4 million for 2005. The average interest rate on the outstanding borrowings under our credit facilities increased to 6.5% in 2006 as compared to 4.6% in 2005.
 
Derivative Gains and Losses.  We did not designate our derivatives we utilize as part of our price risk management program as cash flow hedges and accordingly, we recognize gains or losses for the changes in the fair value of these liabilities during each period. The fair value of our liability for these derivatives decreased during 2006 resulting in a net unrealized gain of $11.2 million. During 2005, the fair value of these liabilities increased due to the increase in natural gas prices and we accordingly recognized an unrealized loss of $11.1 million during 2005. We realized losses to settle derivative positions of $0.7 million and $2.5 million during 2006 and 2005, respectively.
 
Minority Interest.  Minority interest in earnings of Bois d’Arc Energy of $28.4 million for 2006 increased $45.7 million from the pro forma minority interest in losses of $17.3 million for 2005 primarily due to Bois d’Arc Energy’s higher net income in 2006. This increase is mainly due to the absence of Bois d’Arc Energy’s one time tax provision of $108.2 million associated with recognizing cumulative deferred tax liabilities when it converted from a limited liability company to a corporation.
 
Income taxes.  Income tax expense decreased in 2006 to $74.3 million from pro forma income tax expense of $161.6 million in 2005. The pro forma tax expense in 2005 included a $108.2 million provision for deferred taxes related to Bois d’Arc Energy’s conversion from a nontaxable entity to a corporation during 2005. Income tax expense in 2006 also increased from pro forma 2005 tax expense due to our higher income before income taxes and deferred taxes provided on the undistributed earnings of Bois d’Arc Energy.
 
Net income.  We reported net income of $70.7 million in 2006, as compared to net income of $60.5 million in 2005. Net income per share for 2006 was $1.61 on 43.6 million weighted average diluted shares outstanding as compared to $1.47 for 2005 on 41.2 million weighted average diluted shares outstanding.


44


Table of Contents

 
Year Ended December 31, 2005 Compared to Year Ended December 31, 2004
 
Our operating data for 2005 and 2004 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  
 
(1) Adjustments to eliminate our proportionate share of Bois d’Arc Energy’s operations subsequent to adoption of the equity method of accounting effective May 10, 2005.
(2) Includes lease operating costs and production and ad valorem taxes.
(3) Represents depreciation, depletion and amortization of oil and gas properties only.
 
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


45


Table of Contents

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 13% 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.
 
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 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.


46


Table of Contents

 
Income taxes.  Income tax expense increased in 2005 to $35.8 million from $26.3 million in 2004 due to the higher pre-tax income in 2005.
 
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.
 
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 2006, our net cash flow provided by operating activities totaled $364.6 million. Our other primary source of funds in 2006 was a net increase of $143.0 million under our bank credit facilities and $15.9 million from the exercise of stock options and warrants. In 2005, our net cash flow provided by operating activities totaled $218.0 million and we received proceeds of $121.2 million from a public offering of our common stock. In 2005 we also increased the debt outstanding under our bank credit facilities by $179.0 million and we received $25.6 million from the exercise of stock options and warrants. 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 and received $9.4 million from the exercise of stock options and warrants.
 
Our cash flow from operating activities in 2006 increased by $146.6 million to $364.6 million as compared to $218.0 million in 2005 primarily due to higher revenues which were attributable to our increase in our production and the consolidation of Bois d’Arc Energy’s cash flows. Cash flows from operating activities in 2005 of $218.0 million increased by $46.6 million from the 2004 cash flows from operating activities of $171.4 million mainly due to higher revenues caused by increased natural gas prices. Our cash flow from operating activities in 2006 also increased from pro forma 2005 cash flow from operating activities of $322.7 million due to the increased oil and gas production in 2006.
 
Our primary need for capital, in addition to funding our ongoing operations, relate to the acquisition, development and exploration of our oil and gas properties, and the repayment of our debt. Capital expenditures for exploration, development and exploration activities were $209.8 million, $355.4 million and $533.3 million for the years ended December 31, 2004, 2005 and 2006, respectively.


47


Table of Contents

Our capital expenditure activity for the years ended December 31, 2005 and 2006, including 2005 pro forma data as if we had consolidated Bois d’Arc Energy’s capital expenditures for the full year of 2005 is summarized in the following table:
 
                         
    Year Ended December 31,  
                Pro Forma
 
    2005     2006     2005(1)  
    (In thousands)  
 
Exploration and development:
                       
Acquisitions of proved oil and gas properties
  $ 201,788     $ 79,767     $ 201,788  
Acquisitions of unproved oil and gas properties
    2,027       10,010       6,935  
Developmental leasehold costs
    3,102       2,902       3,102  
Workovers and recompletions
    21,100       41,646       34,561  
Other development
    2,580       50,764       109,300  
Development drilling
    98,710       211,491       77,601  
Exploratory drilling
    26,106       136,759       78,228  
                         
      355,413       533,339       511,515  
Other
    849       2,924       2,637  
                         
Total
  $ 356,262     $ 536,263     $ 514,152  
                         
 
(1) Pro forma for consolidating the capital expenditures of Bois d’Arc Energy as of January 1, 2005.
 
Our capital expenditures in 2006 of $536.3 million increased by $22.1 million over pro forma 2005 capital expenditures of $514.2 million mostly due to higher drilling and construction costs. Capital expenditures in 2005 increased above 2004 capital expenditures of $209.8 million primarily due to the acquisitions we made in 2005.
 
The timing of most of our capital expenditures is discretionary because we have no material long-term capital expenditure commitments. Consequently, we have a significant degree of flexibility to adjust the level of our capital expenditures as circumstances warrant. We currently expect to spend approximately $478.0 million for development and exploration projects in 2007, which will be funded primarily by cash flows from operating activities and to a lesser extent borrowings under our bank credit facilities. Our operating cash flow and therefore, our capital expenditures are highly dependent on oil and natural gas prices, and in particular natural gas prices.
 
In 2006 we acquired producing oil and gas properties for an aggregate amount of $79.8 million. We spent $201.8 million on acquisition activities in 2005. We do not have a specific acquisition budget for 2007 since the timing and size of acquisitions are unpredictable. Smaller acquisitions will generally be funded from operating cash flow. With respect to significant acquisitions, we intend to use borrowings under our bank credit facilities, or other debt or equity financings to the extent available, to finance such acquisitions. The availability and attractiveness of these sources of financing will depend upon a number of factors, some of which will relate to our financial condition and performance and some of which will be beyond our control, such as prevailing interest rates, oil and natural gas prices and other market conditions.
 
We have $175.0 million of senior notes outstanding. The senior notes are due March 1, 2012 and bear interest at 67/8%, which is payable semiannually on each March 1 and September 1. The senior notes are unsecured obligations and are guaranteed by all of our wholly owned subsidiaries.
 
We have a $600.0 million bank credit facility with Bank of Montreal, as the administrative agent. The bank credit facility is a five-year revolving credit commitment that matures on December 15, 2011. Indebtedness under the bank credit facility is secured by substantially all of our and our wholly-owned subsidiaries’ assets and is guaranteed by all of our wholly-owned subsidiaries. The bank credit facility is


48


Table of Contents

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, 2006 the borrowing base was $400.0 million, $220.0 million of which was available. The borrowing base may be affected by the performance of our properties and changes in oil and natural gas prices. The determination of the borrowing base is at the sole discretion of the administrative agent and the bank group. Borrowings under the bank credit facility bear interest, based on the utilization of the borrowing base, at our option at either LIBOR plus 1.0% to 1.75% or the base rate (which is the higher of the prime rate or the federal funds rate) plus 0% to 0.25%. A commitment fee of 0.25% to 0.375%, based on the utilization of the borrowing base, is payable on the unused portion of the borrowing base. The bank credit facility contains covenants that, among other things, restrict the payment of cash dividends in excess of $40.0 million, limit the amount of consolidated debt that we may incur and limit our ability to make certain loans and investments. The only financial covenants are the maintenance of a ratio of current assets, including the availability under the bank credit facility, to current liabilities of at least one-to-one and maintenance of a minimum tangible net worth. We were in compliance with these covenants as of December 31, 2006.
 
Bois d’Arc Energy has a $200.0 million bank credit facility with The Bank of Nova Scotia and several other banks. Borrowings under the Bois d’Arc Energy credit facility are limited to a borrowing base that is re-determined semi-annually based on the banks’ estimates of the future net cash flows of our oil and natural gas properties. The borrowing base was $200.0 million, $100.0 million of which was available as of December 31, 2006. The determination of the borrowing base is at the sole discretion of the administrative agent and the bank group. The Bois d’Arc Energy credit facility matures on May 11, 2009. Borrowings under the credit facility bear interest at Bois d’Arc Energy’s option at either (1) LIBOR plus a margin that varies from 1.25% to 2.0% depending upon the ratio of the amounts outstanding to the borrowing base or (2) the base rate (which is the higher of the prime rate or the federal funds rate) plus a margin that varies from 0% to 0.75% depending upon the ratio of the amounts outstanding to the borrowing base. A commitment fee ranging from 0.375% to 0.50% (depending upon the ratio of the amounts outstanding to the borrowing base) is payable on the unused borrowing base. Indebtedness under the Bois d’Arc Energy credit facility is secured by substantially all of Bois d’Arc Energy’s and its subsidiaries’ assets, and all of Bois d’Arc Energy’s subsidiaries are guarantors of the indebtedness. The Bois d’Arc Energy credit facility contains covenants that restrict the payment of cash dividends in excess of $5.0 million, borrowings, sales of assets, loans to others, capital expenditures, investments, merger activity, hedging contracts, liens and certain other transactions without the prior consent of the lenders and requires Bois d’Arc Energy to maintain a ratio of current assets, including the availability under the bank credit facility, to current liabilities of at least one-to-one and a ratio of indebtedness to earnings before interest, taxes, depreciation, depletion, and amortization, exploration and impairment expense of no more than 2.5 to one. Bois d’Arc Energy was in compliance with these covenants as of December 31, 2006.
 
We believe that our cash flow from operations and available borrowings under our bank credit facilities will be sufficient to fund our operations and future growth as contemplated under our current business plan. However, if our plans or assumptions change or if our assumptions prove to be inaccurate, we may be required to seek additional capital. We cannot provide any assurance that we will be able to obtain such capital, or if such capital is available, that we will be able to obtain it on acceptable terms.
 
The following table summarizes our aggregate liabilities and commitments by year of maturity:
 
                                                         
    2007     2008     2009     2010     2011     Thereafter     Total  
    (In thousands)  
 
Bank credit facilities
  $     $     $ 100,000     $     $ 180,000     $     $ 280,000  
67/8% senior notes
                                  175,000       175,000  
Interest on debt
    31,211       31,211       26,820       24,361       23,821       2,005       139,429  
Operating leases
    1,123       1,128       1,142       1,152       1,158       2,055       7,758  
Acquisition of seismic data
    5,250       8,250                               13,500  
Contracted drilling services
    80,257       13,594                                 93,851  
                                                         
    $ 117,841     $ 54,183     $ 127,962     $ 25,513     $ 204,979     $ 179,060     $ 709,538  
                                                         


49


Table of Contents

Future interest costs are based upon the interest rate on our outstanding senior notes and on the December 31, 2006 rate for our bank credit facilities.
 
Federal Taxation
 
At December 31, 2006, we had federal income tax net operating loss carryforwards of approximately $42.4 million. We have established a $23.0 million valuation allowance against part of the net operating loss carryforwards that we acquired in an acquisition due to a “change in control” limitation which will prevent us from fully realizing these carryforwards. The carryforwards expire from 2017 through 2021. The realization of these carryforwards depends on our ability to generate future taxable income in order to utilize these carryforwards.
 
Critical Accounting Policies
 
The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires us to make estimates and use assumptions that can affect the reported amounts of assets, liabilities, revenues or expenses.
 
Successful efforts accounting.  We are required to select among alternative acceptable accounting policies. There are two generally acceptable methods for accounting for oil and gas producing activities. The full-cost method allows the capitalization of all costs associated with finding oil and natural gas reserves, including certain general and administrative expenses. The successful efforts method allows only for the capitalization of costs associated with developing proven oil and natural gas properties as well as exploration costs associated with successful exploration projects. Costs related to exploration that are not successful are expensed when it is determined that commercially productive oil and gas reserves were not found. We have elected to use the successful efforts method to account for our oil and gas activities and we do not capitalize any of our general and administrative expenses.
 
Oil and natural gas reserve quantities.  The determination of depreciation, depletion and amortization expense as well as impairments that are recognized on our oil and gas properties are highly dependent on the estimates of the proved oil and natural gas reserves attributable to our properties. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be precisely measured. The accuracy of any reserve estimate depends on the quality of available data, production history and engineering and geological interpretation and judgment. Because all reserve estimates are to some degree imprecise, the quantities of oil and natural gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future oil and natural gas prices may all differ materially from those assumed in these estimates. The information regarding present value of the future net cash flows attributable to our proved oil and natural gas reserves are estimates only and should not be construed as the current market value of the estimated oil and natural gas reserves attributable to our properties. Thus, such information includes revisions of certain reserve estimates attributable to proved properties included in the preceding year’s estimates. Such revisions reflect additional information from subsequent activities, production history of the properties involved and any adjustments in the projected economic life of such properties resulting from changes in product prices. Any future downward revisions could adversely affect our financial condition, our borrowing ability, our future prospects and the value of our common stock.
 
Impairment of oil and gas properties.  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


50


Table of Contents

gas price forecast and may be higher or lower than the December 31, 2006 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, 2006, we used oil and natural gas prices that were based on the current futures market. We used an oil price of $53.50 for 2007 and escalated prices by 5% each year thereafter to a maximum price of $66.91 per barrel. For natural gas we used a price of $7.90 per Mcf for 2007 and escalated prices by 5% each year thereafter to a maximum price of $12.12 per Mcf. The initial prices we used were tied to the one-year market prices for oil and natural gas. 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.
 
Asset retirement obligations.  We have significant obligations to remove tangible equipment and facilities and to restore land or seafloor at the end of oil and gas production operations. Our removal and restoration obligations are primarily associated with plugging and abandoning wells and removing and disposing of offshore oil and gas platforms. Estimating the future restoration and removal costs is difficult and requires management to make estimates and judgments because most of the removal obligations are many years in the future. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations.
 
Stock-based compensation.  We follow the fair value based method prescribed in Statement of Financial Accounting Standards No. 123 (revised 2004), “Share-Based Payment” (“SFAS 123R”) in accounting for equity-based compensation. Under the fair value based method, compensation cost is measured at the grant date based on the fair value of the award and is recognized on a straight-line basis over the award vesting period. We adopted SFAS 123R utilizing the modified prospective transition method and accordingly the financial results for periods prior to January 1, 2006 have not been adjusted. Prior to adopting SFAS 123R we followed the fair value based method prescribed in Statement of Financial Accounting Standards No. 123, “Accounting for Stock Based Compensation” for all periods beginning January 1, 2004. Under the fair value based method, compensation cost is measured at the grant date based on the fair value of the award and is recognized over the award vesting period. Because we previously recorded stock-based compensation using the fair value method, adoption of SFAS 123R did not have a significant impact on our net income or earnings per share for the year ended December 31, 2006.
 
New accounting standards.  In June 2006, the FASB issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes,” an interpretation of FASB Statement No. 109 (“FIN 48”). FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of tax positions taken or expected to be taken in a tax return. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. FIN 48 is effective for fiscal years beginning after December 15, 2006, and we adopted FIN 48 at the beginning of fiscal 2007. The impact of adoption was not material.
 
In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (SFAS No. 157). This Statement establishes a framework for fair value measurements in the financial statements by providing a single definition of fair value, provides guidance on the methods used to estimate fair value and increases disclosures about estimates of fair value. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007 and is generally applied prospectively. We are currently evaluating the impact of this statement on our consolidated financial statements.
 
In September 2006, the FASB issued FSP AUG AIR-1, “Accounting for Planned Major Maintenance Activities” (FSP AUG AIR-1). This FSP addresses the planned major maintenance of assets and prohibits the use of the “accrue-in-advance” method of accounting for these activities. This FSP is effective for the first fiscal year beginning after December 15, 2006. We are currently evaluating the impact of this FSP, but do not expect it to have a material impact on our consolidated financial statements.


51


Table of Contents

 
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 except for the purchase of 2,250,000 shares of Bois d’Arc Energy’s common stock for $35.9 million in August 2006.
 
ITEM 7A.   QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISKS
 
Oil and Natural Gas Prices
 
Our financial condition, results of operations and capital resources are highly dependent upon the prevailing market prices of oil and natural gas. These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond our control. Factors influencing oil and natural gas prices include the level of global demand for crude oil, the foreign supply of oil and natural gas, the establishment of and compliance with production quotas by oil exporting countries, weather conditions which determine the demand for natural gas, the price and availability of alternative fuels and overall economic conditions. It is impossible to predict future oil and natural gas prices with any degree of certainty. Sustained weakness in oil and natural gas prices may adversely affect our financial condition and results of operations, and may also reduce the amount of oil and natural gas reserves that we can produce economically. Any reduction in our oil and natural gas reserves, including reductions due to price fluctuations, can have an adverse affect on our ability to obtain capital for our exploration and development activities. Similarly, any improvements in oil and natural gas prices can have a favorable impact on our financial condition, results of operations and capital resources. Based on our oil and natural gas production in 2006, a $1.00 change in the price per barrel of oil would have resulted in a change in our cash flow for such period by approximately $2.2 million and a $1.00 change in the price per Mcf of natural gas would have changed our cash flow by approximately $52.1 million.
 
We periodically use derivative transactions with respect to a portion of our oil and natural gas production to mitigate our exposure to price changes. While the use of these derivative arrangements limits the downside risk of price declines, such use may also limit any benefits which may be derived from price increases. We use swaps, floors and collars to hedge oil and natural gas prices. Swaps are settled monthly based on differences between the prices specified in the instruments and the settlement prices of futures contracts quoted on the New York Mercantile Exchange. Generally, when the applicable settlement price is less than the price specified in the contract, we receive a settlement from the counterparty based on the difference multiplied by the volume hedged. Similarly, when the applicable settlement price exceeds the price specified in the contract, we pay the counterparty based on the difference. We generally receive a settlement from the counterparty for floors when the applicable settlement price is less than the price specified in the contract, which is based on the difference multiplied by the volumes hedged. For collars, we generally receive a settlement from the counterparty when the settlement price is below the floor and pay a settlement to the counterparty when the settlement price exceeds the cap. No settlement occurs when the settlement price falls between the floor and the cap. We had no derivative financial instrument outstanding as of December 31, 2006. During 2006 we recognized unrealized gains on derivatives of $11.2 million to reflect the changes in these liabilities and we had realized losses of $0.7 million to settle derivative positions.
 
Interest Rates
 
At December 31, 2006, we had long-term debt of $455.0 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, 2006 was


52


Table of Contents

$170.4 million based on the market price of 97% of the face amount. At December 31, 2006, we had $280.0 million outstanding under our bank credit facilities, which were 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, 2006, a 100 basis point change in interest rates would change our annual interest expense on our variable rate debt by approximately $2.8 million. We had no interest rate derivatives outstanding during 2006 or at December 31, 2006.
 
ITEM 8.   FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
 
Our consolidated financial statements are included on pages F-1 to F-36 of this report.
 
We have prepared these financial statements in conformity with generally accepted accounting principles. We are responsible for the fairness and reliability of the financial statements and other financial data included in this report. In the preparation of the financial statements, it is necessary for us to make informed estimates and judgments based on currently available information on the effects of certain events and transactions.
 
Our independent public accountants, Ernst & Young LLP, are engaged to audit our financial statements and to express an opinion thereon. Their audit is conducted in accordance with auditing standards generally accepted in the United States to enable them to report whether the financial statements present fairly, in all material respects, our financial position and results of operations in accordance with accounting principles generally accepted in the United States.
 
The audit committee of our board of directors is composed of three directors who are not our employees. This committee meets periodically with our independent public accountants and management. Our independent public accountants have full and free access to the audit committee to meet, with and without management being present, to discuss the results of their audits and the quality of our financial reporting.
 
ITEM 9.   CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
 
None.


53


Table of Contents

 
ITEM 9A.   CONTROLS AND PROCEDURES
 
Evaluation of disclosure controls and procedures.  Our Chief Executive Officer and Chief Financial Officer have evaluated, as required by Rule 13a-15(b) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), our disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)) as of the end of the period covered by this Annual Report on Form 10-K. Based on that evaluation, our chief executive officer and chief financial officer concluded that the design and operation of our disclosure controls and procedures are adequate and effective in ensuring that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms.
 
Changes in internal control over financial reporting.  There were no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that occurred during the fourth quarter of 2006 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, 2006, 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, 2006, based on those criteria.
 
Ernst & Young LLP, the independent registered public accounting firm that audited the consolidated financial statements of the Company included in this Annual Report on Form 10-K, has issued an attestation report on management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2006. 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, 2006 is included below.


54


Table of Contents

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, 2006, 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, 2006, 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, 2006, based on the COSO criteria.
 
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Comstock Resources, Inc. and subsidiaries as of December 31, 2006 and 2005, and the related consolidated statements of operations, stockholders’ equity and comprehensive income, and cash flows for the years in the period ended December 31, 2006 of Comstock Resources, Inc. and our report dated February 28, 2007 expressed an unqualified opinion thereon.
 
/s/  ERNST & YOUNG LLP
 
Dallas, Texas
February 28, 2007


55


Table of Contents

 
ITEM 9B.   OTHER INFORMATION
 
None.
 
PART III
 
ITEM 10.   DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
 
The information required by this item is incorporated herein by reference to “Business — Directors, Executive Officers and Other Management” in this Form 10-K and to our definitive proxy statement which will be filed with the Securities and Exchange Commission within 120 days after December 31, 2006.
 
Code of Ethics.  We have adopted a Code of Business Conduct and Ethics that is applicable to all of our directors, officers and employees as required by New York Stock Exchange rules. We have also adopted a Code of Ethics for Senior Financial Officers that is applicable to our Chief Executive Officer and senior financial officers. Both the Code of Business Conduct and Ethics and Code of Ethics for Senior Financial Officers may be found on our website at www.comstockresources.com. Both of these documents are also available, without charge, to any stockholder upon request to: Comstock Resources, Inc., Attn: Investor Relations, 5300 Town and Country Blvd., Suite 500, Frisco, Texas 75034, (972) 668-8800. We intend to disclose any amendments or waivers to these codes that apply to our Chief Executive Officer and senior financial officers on our website in accordance with applicable SEC rules. Please see the definitive proxy statement for our 2007 annual meeting, which will be filed with the SEC within 120 days of December 31, 2006, 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, 2006.
 
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, 2006.
 
ITEM 13.   CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
 
The information required by this item is incorporated herein by reference to our definitive proxy statement which will be filed with the Securities and Exchange Commission within 120 days after December 31, 2006.


56


Table of Contents

 
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, 2006.
 
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-36 of this report.
 
         
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES:
   
  F-2
  F-3
  F-4
  F-5
  F-6
  F-7
 
2. All financial statement schedules are omitted because they are not applicable, or are immaterial or the required information is presented in the consolidated financial statements or the related notes.
 
(b) Exhibits:
 
The exhibits to this report required to be filed pursuant to Item 15 (c) are listed below.
 
     
Exhibit No.
 
Description
 
3.1(a)
  Restated Articles of Incorporation (incorporated by reference to Exhibit 3.1 to our Annual Report on Form 10-K for the year ended December 31, 1995).
3.1(b)
  Certificate of Amendment to the Restated Articles of Incorporation dated July 1, 1997 (incorporated by reference to Exhibit 3.1 to our Quarterly Report on Form 10-Q for the quarter ended June 30, 1997).
3.2
  Bylaws (incorporated by reference to Exhibit 3.2 to our Registration Statement on Form S-3, dated October 25, 1996).
4.1
  Rights Agreement dated as of December 14, 2000, by and between Comstock and American Stock Transfer and Trust Company, as Rights Agent (incorporated herein by reference to Exhibit 1 to our Registration Statement on Form 8-A dated January 11, 2001).
4.2
  Certificate of Designation, Preferences and Rights of Series B Junior Participating Preferred Stock (incorporated by reference to Exhibit 2 to our Registration Statement on Form 8-A dated January 11, 2001).


57


Table of Contents

     
Exhibit No.
 
Description
 
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*
  Second Amended and Restated Credit Agreement, dated December 15, 2006, among Comstock, as the borrower, the lenders from time to time thereto, Bank of Montreal, as administrative agent and issuing bank, Bank of America, N.A., as syndication agent and Comerica Bank, Fortis Capital Corp., and Union Bank of California, N.A. as co-documentation agents.
10.2#
  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).
10.3#
  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).
10.4#
  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).
10.5#
  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).
10.6#
  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).
10.7#
  Amendment No. 2 dated April 7, 2004 to the Comstock Resources, Inc. 1999 Long-term Incentive Plan (incorporated by reference to Exhibit 10.1 to our Quarterly Report on Form 10-Q for the quarter ended March 31, 2004).
10.8#
  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).
10.9#
  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).
10.10
  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).

58


Table of Contents

     
Exhibit No.
 
Description
 
10.11
  Contribution Agreement dated July 16, 2004, among Bois d’Arc Energy, LLC, Bois d’Arc Properties, LP, Bois d’Arc Resources, Ltd., Wayne L. Laufer, Gary W. Balckie, Haro Investments LLC, such other persons listed on the signature pages thereto, Comstock Offshore LLC, and Comstock Resources, Inc. (incorporated by reference to Exhibit 10.2 to our Quarterly Report on Form 10-Q for the quarter ended June 30, 2004).
10.12
  Amended and Restated Operating Agreement, dated as of August 23, 2004, to be effective July 16, 2004, of Bois d’Arc Energy, LLC (incorporated by reference to Exhibit 3.2 to the Registration Statement on Form S-1 [File No. 33-119511] filed by Bois d’Arc Energy, LLC on October 4, 2004).
10.13
  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).
10.14
  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).
10.15
  First Amendment to the Lease Agreement dated August 25, 2005, between Stonebriar I Office Partners, Ltd. and Comstock Resources, Inc.(incorporated by reference to Exhibit 10.20 to our Annual Report on Form 10-K for the year ended December 31, 2005).
10.16
  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. 333-19511)).
10.17
  Stock Purchase Agreement dated August 25, 2006, between Bois d’Arc Energy, Inc. and Comstock Resources, Inc. (incorporated by reference to Exhibit 2.1 to our Form 8-K dated August 25, 2006).
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.

59


Table of Contents

SIGNATURES
 
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
 
COMSTOCK RESOURCES, INC.
 
  By: 
/s/  M. JAY ALLISON
M. Jay Allison
President and Chief Executive Officer
(Principal Executive Officer)
Date: February 28, 2007
 
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
 
             
/s/  M. JAY ALLISON

M. Jay Allison
  President, Chief Executive Officer and Chairman of the Board of Directors (Principal Executive Officer)   February 28, 2007
         
/s/  ROLAND O. BURNS

Roland O. Burns
  Senior Vice President, Chief Financial Officer, Secretary, Treasurer and Director (Principal Financial and Accounting Officer)   February 28, 2007
         
/s/  DAVID K. LOCKETT

David K. Lockett
  Director   February 28, 2007
         
/s/  CECIL E. MARTIN, JR.

Cecil E. Martin, Jr.
  Director   February 28, 2007
         
/s/  DAVID W. SLEDGE

David W. Sledge
  Director   February 28, 2007
         
/s/  NANCY E. UNDERWOOD

Nancy E. Underwood
  Director   February 28, 2007


60


Table of Contents


Table of Contents

 
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
The Board of Directors and Stockholders
Comstock Resources, Inc.
 
We have audited the accompanying consolidated balance sheets of Comstock Resources, Inc. and subsidiaries as of December 31, 2006 and 2005, 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, 2006. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
 
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
 
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Comstock Resources, Inc. and subsidiaries at December 31, 2006 and 2005, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2006, in conformity with accounting principles generally accepted in the United States.
 
As discussed in Note 1 to the consolidated financial statements, effective January 1, 2006, the Company adopted Statement of Financial Accounting Standards No. 123 (revised 2004), “Share Based Payment” in accounting for equity-based compensation.
 
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Comstock Resources, Inc.’s internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 28, 2007 expressed an unqualified opinion thereon.
 
ERNST & YOUNG LLP
 
Dallas, Texas
February 28, 2007


F-2


Table of Contents

COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
 
As of December 31, 2005 and 2006
 
                 
    December 31,  
    2005     2006  
    (In thousands)  
 
ASSETS
Cash and Cash Equivalents
  $ 89     $ 10,715  
Accounts Receivable:
               
Oil and gas sales
    37,646       56,328  
Joint interest operations
    5,553       19,233  
Other Current Assets
    9,482       12,552  
                 
Total current assets
    52,770       98,828  
Property and Equipment:
               
Unevaluated oil and gas properties
    10,723       13,645  
Oil and gas properties, successful efforts method
    1,018,341       2,511,782  
Other
    3,342       8,483  
Accumulated depreciation, depletion and amortization
    (325,478 )     (760,284 )
                 
Net property and equipment
    706,928       1,773,626  
Investment in Bois d’Arc Energy
    252,134        
Other Assets
    4,831       5,671  
                 
    $ 1,016,663     $ 1,878,125  
                 
 
LIABILITIES AND STOCKHOLDERS’ EQUITY
Short-term Debt
  $     $ 3,250  
Accounts Payable
    48,955       132,504  
Accrued Expenses
    7,920       16,107  
Unrealized Loss on Derivatives
    11,242        
                 
Total current liabilities
    68,117       151,861  
Long-term Debt
    243,000       455,000  
Deferred Income Taxes Payable
    119,481       311,236  
Reserve for Future Abandonment Costs
    3,206       57,116  
Minority Interest in Bois d’Arc Energy
          220,349  
Commitments and Contingencies
               
Stockholders’ Equity:
               
Common stock — $0.50 par, 50,000,000 shares authorized, 42,969,262 and 44,395,495 shares issued and outstanding at December 31, 2005 and 2006, respectively
    21,485       22,197  
Additional paid-in capital
    338,996       367,323  
Retained earnings
    222,378       293,043  
                 
Total stockholders’ equity
    582,859       682,563  
                 
    $ 1,016,663     $ 1,878,125  
                 
 
The accompanying notes are an integral part of these statements.


F-3


Table of Contents

COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
 
For the Years Ended December 31, 2004, 2005 and 2006
 
                         
    2004     2005     2006  
    (In thousands, except per share amounts)  
 
Oil and gas sales
  $ 261,647     $ 303,336     $ 511,928  
Operating expenses:
                       
Oil and gas operating
    52,068       50,966       107,303  
Exploration
    15,610       19,725       20,132  
Depreciation, depletion and amortization
    63,879       63,338       153,922  
Impairment
    1,648       3,400       10,444  
General and administrative, net
    14,569       16,533       31,769  
                         
Total operating expenses
    147,774       153,962       323,570  
                         
Income from operations
    113,873       149,374       188,358  
Other income (expenses):
                       
Interest income
    1,207       1,604       1,012  
Other income
    166       209       781  
Interest expense
    (21,182 )     (20,272 )     (27,429 )
Formation costs of Bois d’Arc Energy
    (1,101 )            
Gain on sale of shares by Bois d’Arc Energy
          28,797        
Gain (loss) on derivatives
    (155 )     (13,556 )     10,716  
Loss on early extinguishment of debt
    (19,599 )            
                         
Total other income (expenses)
    (40,664 )     (3,218 )     (14,920 )
                         
Income before income taxes, minority interest and
equity in loss of Bois d’Arc Energy
    73,209       146,156       173,438  
Provision for income taxes
    (26,342 )     (35,815 )     (74,339 )
Equity in loss of Bois d’Arc Energy
          (49,862 )      
Minority interest in earnings of Bois d’Arc Energy
                (28,434 )
                         
Net income
  $ 46,867     $ 60,479     $ 70,665  
                         
Net income per share:
                       
Basic
  $ 1.37     $ 1.54     $ 1.67  
                         
Diluted
  $ 1.29     $ 1.47     $ 1.61  
                         
Weighted average shares outstanding:
                       
Basic
    34,187       39,216       42,220  
                         
Diluted
    36,252       41,154       43,556  
                         
 
The accompanying notes are an integral part of these statements.


F-4


Table of Contents

COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
 
AND COMPREHENSIVE INCOME
For the Years Ended December 31, 2004, 2005 and 2006
 
                                         
          Common
    Additional
             
    Common
    Stock
    Paid-In
    Retained
       
    Shares     Par Value     Capital     Earnings     Total  
                (In thousands)              
 
Balance at December 31, 2003
    34,309     $ 17,154     $ 157,470     $ 115,032     $ 289,656  
Stock purchase warrants issued for exploration prospects, net of
deferred income taxes
                1,512             1,512  
Exercise of stock options and warrants
    1,065       532       8,847             9,379  
Tax benefit of stock option and
warrant exercises
                3,732             3,732  
Stock-based compensation
    275       138       4,569             4,707  
Net income
                      46,867       46,867  
                                         
Balance at December 31, 2004
    35,649       17,824       176,130       161,899       355,853  
                                         
Public offering of common stock
    4,545       2,273       118,977             121,250  
Stock issuance costs
                (175 )           (175 )
Exercise of stock options and warrants
    2,433       1,217       24,376             25,593  
Tax benefit of stock option and
warrant exercises
                15,609             15,609  
Stock-based compensation
    342       171       4,079             4,250  
Net income
                        60,479       60,479  
                                         
Balance at December 31, 2005
    42,969       21,485       338,996       222,378       582,859  
                                         
Exercise of stock options and warrants
    1,083       541       15,407             15,948  
Tax benefit of stock option
and warrant exercises
                6,218             6,218  
Stock-based compensation
    343       171       6,702             6,873  
Net income
                      70,665       70,665  
                                         
Balance at December 31, 2006
    44,395     $ 22,197     $ 367,323     $ 293,043     $ 682,563  
                                         
 
The accompanying notes are an integral part of these statements.


F-5


Table of Contents

COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
 
For the Years Ended December 31, 2004, 2005 and 2006
 
                         
    2004     2005     2006  
          (In thousands)        
 
CASH FLOWS FROM OPERATING ACTIVITIES:
                       
Net income
  $ 46,867     $ 60,479     $ 70,665  
Adjustments to reconcile net income to net cash provided by operating activities, net of acquisition effects:
                       
Stock-based compensation
    6,208       5,419       13,249  
Excess tax benefit from stock based compensation
                (6,218 )
Depreciation, depletion and amortization
    63,879       63,338       153,922  
Debt issuance costs amortization
    970       942       1,649  
Impairment of oil and gas properties
    1,648       3,400       10,444  
Deferred income taxes
    20,739       31,201       66,550  
Equity in loss of Bois d’Arc Energy
          49,862        
Minority interest in earnings of Bois d’Arc Energy
                28,434  
Gain on sale of shares by Bois d’Arc Energy
          (28,797 )      
Dry hole costs and leasehold impairments
    16,151       16,889       14,351  
Loss (gain) on derivatives
    155       13,556       (10,716 )
Loss on early extinguishment of debt
    19,599              
Decrease (increase) in accounts receivable
    5,584       (13,030 )     (2,917 )
Decrease (increase) in other current assets
    (1,735 )     616       3,526  
Increase (decrease) in accounts payable and accrued expenses
    (8,714 )     14,079       21,666  
                         
Net cash provided by operating activities
    171,351       217,954       364,605  
                         
CASH FLOWS FROM INVESTING ACTIVITIES:
                       
Capital expenditures and acquisitions
    (209,790 )     (356,262 )     (529,225 )
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 )     (526 )
                         
Net cash used for investing activities
    (258,061 )     (207,086 )     (529,751 )
                         
CASH FLOWS FROM FINANCING ACTIVITIES:
                       
Borrowings
    272,673       179,000       190,000  
Proceeds from senior notes offering
    175,000              
Debt issuance costs
    (5,963 )           (1,437 )
Principal payments on debt
    (367,019 )     (339,150 )     (47,000 )
Proceeds from common stock issuances
    9,379       146,843       15,948  
Stock issuance costs
          (175 )      
Excess tax benefit from stock based compensation
                6,218  
                         
Net cash provided by (used for) financing activities
    84,070       (13,482 )     163,729  
                         
Net decrease in cash and cash equivalents
    (2,640 )     (2,614 )     (1,417 )
Cash and cash equivalents, beginning of year
    5,343       2,703       89  
Bois d’Arc Energy cash and equivalents as of
January 1, 2006
                12,043  
                         
Cash and cash equivalents, end of year
  $ 2,703     $ 89     $ 10,715  
                         
 
The accompanying notes are an integral part of these statements.


F-6


Table of Contents

COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
 
 
(1)  Summary of Significant Accounting Policies
 
Accounting policies used by Comstock Resources, Inc. and its consolidated subsidiaries (collectively, the “Company”) reflect oil and natural gas industry practices and conform to accounting principles generally accepted in the United States of America.
 
Basis of Presentation and Principles of Consolidation
 
The Company is engaged in oil and natural gas exploration, development and production, and the acquisition of producing oil and natural gas properties. The consolidated financial statements include the accounts of Comstock Resources, Inc. and its wholly owned subsidiaries (“Comstock”) and, effective January 1, 2006, Bois d’Arc Energy, Inc. and its wholly owned subsidiaries (“Bois d’Arc Energy”). All significant intercompany accounts and transactions have been eliminated in consolidation. The Company accounts for its undivided interest in properties using the proportionate consolidation method, whereby its share of assets, liabilities, revenues and expenses are included in its financial statements.
 
Formation of and Investment in Bois d’Arc Energy
 
In July 2004, Bois d’Arc Energy, LLC was formed by Comstock Offshore, LLC (“Comstock Offshore”), an indirect wholly-owned subsidiary of Comstock, 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, and because Bois d’Arc Energy was similar to a partnership in that it maintained a specific ownership percentage for each member, the Company accounted for its interest in Bois d’Arc Energy’s assets, liabilities and operations under the proportionate consolidation method.
 
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 was payable in monthly installments over a two year period beginning in October 2004.
 
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 as a receivable from Bois d’Arc Energy. 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.
 
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 $158.0 million in outstanding advances from Comstock. As a result of Bois d’Arc Energy’s conversion to a corporation and the offering, Comstock’s ownership in Bois d’Arc Energy


F-8


Table of Contents

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

decreased to 48% and Comstock discontinued accounting for its interest in Bois d’Arc Energy using the proportionate consolidation method and began using the equity method to account for its investment in Bois d’Arc Energy.
 
At the time that Bois d’Arc Energy converted to a corporation, it recorded a tax provision of $108.2 million to record a deferred tax liability. Comstock recognized its proportionate share of this provision for taxes of $64.6 million in its equity in loss of Bois d’Arc Energy in the consolidated statement of operations. In connection with the initial public offering completed by Bois d’Arc Energy, Comstock recognized a gain of $28.8 million on its investment in Bois d’Arc Energy based on Comstock’s share of the amount that Bois d’Arc Energy’s equity was increased as a result of the sale of shares in the offering.
 
Comstock did not previously own interests in a subsidiary which had sold shares. The Company has no present plans for any future sale of Bois d’Arc Energy common stock and has adopted a policy of recognizing its proportional share of the gain when Bois d’Arc Energy sells shares to third parties.
 
During 2006, Comstock acquired 2,285,000 additional shares of Bois d’Arc Energy for $36.4 million which increased its ownership of Bois d’Arc Energy’s common stock to 32,220,761 shares or 49.5%. As a result, the Company has voting control of Bois d’Arc Energy through the combined share ownership by Comstock and the members of its Board of Directors. Upon obtaining voting control of Bois d’Arc Energy, Comstock began including Bois d’Arc Energy in its financial statements as a consolidated subsidiary. Consolidated revenues, expenses and cash flows for 2006 reflect Bois d’Arc Energy as a consolidated subsidiary as of January 1, 2006. The Company’s financial statements for dates and periods prior to January 1, 2006, have not been adjusted. The inclusion of Bois d’Arc Energy as a consolidated subsidiary in the Company’s financial statements had no impact on the Company’s net income.
 
The following table summarizes the pro forma results as if Bois d’Arc Energy was consolidated in 2005:
 
                         
    Year Ended December 31, 2005  
          Consolidating
    Pro Forma
 
    As Reported     Adjustments     Consolidated  
          (In thousands)        
 
Balance Sheet -
                       
Current assets
  $ 52,770     $ 50,048     $ 102,818  
Property and equipment, net
    706,928       661,931       1,368,859  
Investment in Bois d’Arc Energy
    252,134       (252,134 )      
Other assets
    4,831       799       5,630  
                         
Total assets
  $ 1,016,663     $ 460,644     $ 1,477,307  
                         
Current liabilities
  $ 68,117     $ 66,282     $ 134,399  
Long-term debt
    243,000       69,000       312,000  
Deferred income taxes payable
    119,481       123,256       242,737  
Reserve for future abandonment costs
    3,206       35,034       38,240  
Minority interest in Bois d’Arc Energy
          167,072       167,072  
Stockholder’s equity
    582,859             582,859  
                         
Total liabilities and stockholder’s equity
  $ 1,016,663     $ 460,644     $ 1,477,307  
                         


F-9


Table of Contents

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

                         
    Year Ended December 31, 2005  
          Consolidating
    Pro Forma
 
    As Reported     Adjustments     Consolidated  
          (In thousands)        
 
Statement of Operations -
                       
Total oil and gas sales
  $ 303,336     $ 145,906     $ 449,242  
Income from operations
  $ 149,374     $ 60,835     $ 210,209  
Income before income taxes, minority interest and
equity in earnings of Bois d’Arc Energy
  $ 146,156     $ 58,659     $ 204,815  
Provision for income taxes
  $ (35,815 )   $ (125,808 )   $ (161,623 )
Minority interest in losses of Bois d’Arc Energy
        $ 17,287     $ 17,287  
Equity interest in losses of Bois d’Arc Energy
  $ (49,862 )   $ 49,862     $  
Net income
  $ 60,479     $     $ 60,479  

 
In connection with the acquisition of additional common shares of Bois d’Arc Energy, Comstock has allocated the purchase price paid for the shares in excess of its underlying net book value in Bois d’Arc Energy of $18.9 million together with the related deferred income tax liability of $10.1 million to oil and gas properties in the accompanying consolidated balance sheet. This additional amount is being amortized over the productive lives of Bois d’Arc Energy’s oil and gas properties using the unit-of-production method. The pro forma impact of the acquisition of these shares was not material to the Company’s historical results of operations.
 
Reclassifications
 
Certain reclassifications have been made to prior periods’ financial statements to conform to the current presentation.
 
Use of Estimates in the Preparation of Financial Statements
 
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual amounts could differ from those estimates. Changes in the future estimated oil and natural gas reserves or the estimated future cash flows attributable to the reserves that are utilized for impairment analysis could have a significant impact on the future results of operations.
 
Concentration of Credit Risk and Accounts Receivable
 
Financial instruments that potentially subject the Company to a concentration of credit risk consist principally of cash and cash equivalents, accounts receivable and derivative financial instruments, the Company places its cash with high credit quality financial institutions and its derivative financial instruments with financial institutions and other firms that management believes have high credit rating. Substantially all of the Company’s accounts receivable are due from either purchasers of oil and gas or participants in oil and gas wells for which the Company serves as the operator. Generally, operators of oil and gas wells have the right to offset future revenues against unpaid charges related to operated wells. Oil and gas sales are generally unsecured. The Company has not had any significant credit losses in the past and

F-10


Table of Contents

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

believes its accounts receivable are fully collectable. Accordingly, no allowance for doubtful accounts has been provided.
 
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, 2005 and 2006:
 
                                 
    2005     2006  
    Carrying
    Fair
    Carrying
    Fair
 
    Value     Value     Value     Value  
          (In thousands)        
 
Long-term debt, including current portion
  $ 243,000     $ 239,281     $ 455,000     $ 450,406  
 
The fair market value of the fixed rate debt was based on the market prices as of December 31, 2005 and 2006. The fair market value of the floating rate date approximates its carrying value.
 
Derivatives at December 31, 2005 are presented at their estimated fair value. The Company had no derivatives outstanding as of December 31, 2006. 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, 2005 and 2006 consist of the following:
 
                 
    As of December 31,  
    2005     2006  
    (In thousands)  
 
Prepaid expenses
  $  3,511     $ 9,889  
Pipe inventory
    1,408       1,251  
Deferred tax asset
    4,439        
Income taxes receivable
          1,386  
Other
    124       26  
                 
    $ 9,482     $ 12,552  
                 
 
Property and Equipment
 
The Company follows the successful efforts method of accounting for its oil and natural gas properties. Acquisition costs for proved oil and natural gas properties, costs of drilling and equipping productive wells, and costs of unsuccessful development wells are capitalized and amortized on an equivalent unit-of-production basis over the life of the remaining related oil and gas reserves. Equivalent units are determined by converting oil to natural gas at the ratio of six barrels of oil for one thousand cubic feet of natural gas. Cost centers for amortization purposes 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


F-11


Table of Contents

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

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.
 
The Company records a liability in the period in which an asset retirement obligation (“ARO”) is incurred, in an amount equal to the discounted estimated fair value of the obligation that is capitalized. Thereafter this liability is accreted up to the final retirement cost. The Company’s ARO’s relate to future plugging and abandonment expenses of its oil and gas properties and related facilities disposal.
 
The following table summarizes the changes in the Company’s total estimated liability:
 
                         
    For the Year Ended December 31,  
    2004     2005     2006  
          (In thousands)        
 
Beginning asset retirement obligations
  $ 19,174     $ 19,248     $ 3,206  
Bois d’Arc Energy abandonment liability(1)
          (16,915 )     35,034  
New wells placed on production and changes in estimates
    1,870       266       18,134  
Acquisition liabilities assumed
    88       455       3,346  
Liabilities settled
    (3,030 )           (5,145 )
Accretion expense
    1,146       152       2,541  
                         
Ending asset retirement obligations
  $ 19,248     $ 3,206     $ 57,116  
                         
 
(1) The Company’s share of the asset retirement obligations of Bois d’Arc Energy was reclassified to the Investment in Bois d’Arc Energy upon the change to the equity accounting method in 2005. Concurrent with including Bois d’Arc Energy as a consolidated subsidiary as of January 1, 2006, the asset retirement obligations of Bois d’Arc Energy are included in the Company’s financial statements.
 
The Company 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. The Company recognized impairment charges related to its oil and gas properties of $1.6 million, $3.4 million and $10.4 million in 2004, 2005, and 2006, respectively. The impairment in 2006 includes $7.9 million related to a property that was held for resale. Subsequently, the plan to sell the property was cancelled. The impairment reflected the property’s estimated fair market value at the time the plan to sell the property changed.
 
Other property and equipment consists primarily of gas gathering systems, computer equipment, furniture and fixtures and interests in private aircraft which are depreciated over estimated useful lives ranging from five to 311/2 years on a straight-line basis.
 
Other Assets
 
Other assets primarily consist of deferred costs associated with issuance of the senior notes and the bank credit facilities. These costs are amortized over the eight year life of the senior notes and the life of the bank credit facility on a straight-line basis which approximates the amortization that would be calculated using an effective interest rate method.


F-12


Table of Contents

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

 
Stock-based Compensation
 
Effective January 1, 2006, the Company follows the fair value based method prescribed in Statement of Financial Accounting Standards No. 123 (revised 2004), “Share-Based Payment” (“SFAS 123R”) in accounting for equity-based compensation. The Company adopted SFAS 123R utilizing the modified prospective transition method and accordingly the financial results for periods prior to January 1, 2006 have not been adjusted. Prior to adopting SFAS 123R the Company followed the fair value based method prescribed in Statement of Financial Accounting Standards No. 123, “Accounting for Stock Based Compensation” for all periods beginning January 1, 2004. Because the Company previously recorded stock-based compensation using the fair value method, adoption of SFAS 123R did not have a significant impact on the Company’s net income or earnings per share for the year ended December 31, 2006. Under the fair value based method, compensation cost is measured at the grant date based on the fair value of the award and is recognized on a straight-line basis over the award vesting period.
 
Prior to adopting SFAS 123R, the Company presented all tax benefits of the deductions that resulted from stock-based compensation as cash flows from operating activities. SFAS 123R requires that excess tax benefits on stock-based compensation be recognized as a part of cash flows from financing activities. Comstock’s excess income tax benefit realized from tax deductions associated with stock-based compensation totaled $3.7 million, $15.6 million and $6.2 million for the years ended December 31, 2004, 2005 and 2006, respectively. Upon adoption of SFAS 123R effective January 1, 2006, $6.2 million of tax benefits have been included in cash flows from financing activities.
 
Segment Reporting
 
The Company presently operates in one business segment, the exploration and production of oil and natural gas.
 
Derivative Instruments and Hedging Activities
 
The Company follows Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”), which requires that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded on the balance sheet as either an asset or liability measured at its fair value. SFAS 133 requires that changes in the derivative’s fair value be recognized currently in earnings unless specific hedge accounting criteria are met. The Company estimates fair value based on quotes obtained from the counterparties to the derivative contract. The fair value of derivative contracts that expire in less than one year are recognized as current assets or liabilities. Those that expire in more than one year are recognized as long-term assets or liabilities. Derivative financial instruments that are not accounted for as hedges are adjusted to fair value through income. If the derivative is designated as a cash flow hedge, changes in fair value are recognized in other comprehensive income until the hedged item is recognized in earnings. The Company had no derivative financial instruments outstanding at December 31, 2006.
 
Major Purchasers
 
In 2006, the Company had two purchasers of its oil and natural gas production that accounted for 10% of total oil and gas sales. Such purchasers accounted for 42% and 13% of total 2006 oil and gas sales. In 2005, Comstock had two purchasers that accounted for 15% and 12% of total 2005 oil and gas sales. In 2004, Comstock had two purchasers that accounted for 21% and 16% of total oil and gas sales. The loss of


F-13


Table of Contents

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

any of the foregoing customers would not have a material adverse effect on the Company as there is an available market for its crude oil and natural gas production from other purchasers.
 
Revenue Recognition and Gas Balancing
 
Comstock utilizes the sales method of accounting for oil and natural gas revenues whereby revenues are recognized based on the amount of oil or natural gas sold to purchasers. The amount of oil or natural gas sold may differ from the amount to which the Company is entitled based on its revenue interests in the properties. The Company did not have any significant imbalance positions at December 31, 2004, 2005 or 2006.
 
General and Administrative Expenses
 
General and administrative expenses are reported net of reimbursements of overhead costs that are allocated to working interest owners of the oil and gas properties operated by the Company.
 
Income Taxes
 
The Company accounts for income taxes using the asset and liability method, whereby deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their respective tax basis, as well as the future tax consequences attributable to the future utilization of existing tax net operating loss and other types of carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be 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. There were no differences between comprehensive income and reported income in the periods presented.
 
Earnings Per Share
 
Basic and diluted earnings per share for 2004, 2005 and 2006 were determined as follows:
 
<