UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

Commission File No. 0-16741

COMSTOCK RESOURCES, INC.

(Exact name of registrant as specified in its charter)

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:

Securities registered pursuant to Section 12(g) of the Act:

None

      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 an accelerated filer (as defined in Exchange Act Rule 12b-2).     Yes þ          No o

      The aggregate market value of the voting common equity held by non-affiliates of the Registrant computed by reference to the price at which the common equity was last sold as of the last business day of the Registrant’s most recently completed second fiscal quarter was $658.0 million.

      As of March 17, 2005, there were 36,037,868 shares of common stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

      Proxy statement for the 2005 annual meeting of stockholders — Part III

COMSTOCK RESOURCES, INC.

ANNUAL REPORT ON FORM 10-K

For the Fiscal Year Ended December 31, 2004

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 “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” regarding:

      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:

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 42 U.S. 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 thousand cubic feet of natural gas equivalent.

      MMBbls means one million barrels of oil.

      MMcf means one million cubic feet of natural gas.

      MMcf/d means one million cubic feet of natural gas per day.

      MMcfe/d means one million cubic feet of natural gas equivalent per day.

      MMcfe means one million cubic feet of natural gas equivalent.

      Net when used with respect to acres or wells, refers to gross acres of wells multiplied, in each case, by the percentage working interest owned by us.

      Net production means production we own less royalties and production due others.

      Oil means crude oil or condensate.

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

      PV 10 Value means the present value of estimated future revenues to be generated from the production of proved reserves calculated in accordance with the Securities and Exchange Commission guidelines, net of estimated production and future development costs, using prices and costs as of the date of estimation without

future escalation, without giving effect to non-property related expenses such as general and administrative expenses, debt service, future income tax expense and depreciation, depletion and amortization, and discounted using an annual discount rate of 10%. This amount is the same as the standardized measure of discounted future net cash flows related to proved oil and natural gas reserves except that it is determined without deducting future income taxes.

      Proved developed reserves means reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery will be included as “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

      Proved developed non-producing means reserves (i) expected to be recovered from zones capable of producing but which are shut-in because no market outlet exists at the present time or whose date of connection to a pipeline is uncertain or (ii) currently behind the pipe in existing wells, which are considered proved by virtue of successful testing or production of offsetting wells.

      Proved developed producing means reserves expected to be recovered from currently producing zones under continuation of present operating methods. This category may also include recently completed shut-in gas wells scheduled for connection to a pipeline in the near future.

      Proved reserves means the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.

      Proved undeveloped reserves means reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

      Recompletion means the completion for production of an existing well bore in another formation from which the well has been previously completed.

      Reserve life means the calculation derived by dividing year-end reserves by total production in that year.

      Reserve replacement means the calculation derived by dividing additions to reserves from acquisitions, extensions, discoveries and revisions of previous estimates in a year by total production in that year.

      Royalty means an interest in an oil and gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.

      3-D seismic means an advanced technology method of detecting accumulations of hydrocarbons identified by the collection and measurement of the intensity and timing of sound waves transmitted into the earth as they reflect back to the surface.

      Working interest means an interest in an oil and gas lease that gives the owner of the interest the right to drill for and produce oil and gas on the leased acreage and requires the owner to pay a share of the costs of

drilling and production operations. The share of production to which a working interest owner is entitled will always be smaller than the share of costs that the working interest owner is required to bear, with the balance of the production accruing to the owners of royalties. For example, the owner of a 100% working interest in a lease burdened only by a landowner’s royalty of 12.5% would be required to pay 100% of the costs of a well but would be entitled to retain 87.5% of the production.

      Workover means operations on a producing well to restore or increase production.

PART I

General

      Comstock Resources 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.

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. Also, the SEC maintains an internet website that contains reports, proxy and information statements, and other information regarding issuers, including us, that file electronically with the SEC. The public can obtain any documents that we file with the SEC at http://www.sec.gov. We also make available free of charge on our internet website (http://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 electronically file such material with, or furnish it to, the SEC.

Summary Reserve and Production Information

      Our oil and natural gas operations are concentrated in the Gulf of Mexico, East Texas/ North Louisiana, Southeast Texas and South Texas regions. In addition, we have properties in the Mid-Continent region located in the Texas panhandle, Oklahoma, Arkansas and Kansas and in other regions. Our oil and natural gas properties are estimated to have proved reserves of 628.8 Bcfe with an estimated PV 10 Value of $1.5 billion as of December 31, 2004 and a standardized measure of discounted future net cash flows of $1.1 billion (see note 1 on page 15 for a discussion of our PV 10 Value and our standardized measure of discounted future net cash flows). Our proved oil and natural gas reserve base is 85% natural gas and 67% proved developed on a Bcfe basis as of December 31, 2004.

      Our proved reserves at December 31, 2004 and our 2004 average daily production are summarized below by our operating regions:

Strengths

      High Quality Properties. Our operations are focused in four geographically concentrated areas, the Gulf of Mexico, East Texas/ North Louisiana, Southeast Texas and South Texas regions, which account for

approximately 29%, 32%, 18% and 8% of our proved reserves, respectively. We have high price realizations relative to benchmark prices for natural gas and crude oil production. We also have favorable operating costs, which result in us having high cash margins. Finally, our properties have an average reserve life of approximately 14.7 years and have extensive development and exploration potential.

      Successful Exploration and Development Program. In 2004, we spent $94.6 million on the exploitation and development of our oil and natural gas properties for development drilling, recompletions, workovers, abandonment and production facilities. Overall, we drilled 46 development wells, 20.9 net to us, with a 98% success rate. We also had a successful exploratory drilling program in 2004, spending a total of $47.0 million on exploration to drill 24 wells, 10.0 net to us, with a 54% success rate.

      Successful Acquisitions. We have had significant growth over the years as a result of acquisitions. Since 1991, we have added 766.9 Bcfe of proved oil and natural gas reserves from 31 acquisitions at an average cost of $0.87 per Mcfe. Our application of strict economic and reserve risk criteria have enabled us to successfully evaluate and integrate acquisitions.

      Efficient Operator. We operate 83% of our proved oil and natural gas reserve base as of December 31, 2004 based on the PV 10 Value of our proved reserves. 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.

      High Price Realizations. The majority of our wells are located in areas in which we can access attractive natural gas and crude oil markets. In addition, our natural gas production has a relatively high Btu content of approximately 1.08 Btu. Our crude oil production has a favorable gravity of approximately 40 degrees. Due to these factors, we have relatively high price realizations compared to benchmark prices. In 2004, the average natural gas price we realized was $5.98 per Mcf, which represented a $0.16 discount to the 2004 NYMEX average monthly settlement price. Also in 2004, the average price we realized for our crude oil was $39.86 per barrel, which represented a $1.75 barrel premium to the average monthly West Texas Intermediate crude oil price for 2004 posted by Koch Industries, Inc.

      High Cash Margins. As a result of our quality properties, higher price realizations and efficient operations, we have higher cash margins than many of our competitors. Consequently, our oil and natural gas reserves have a higher value per Mcfe than reserves that generate lower cash margins.

Business Strategy

      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 use advanced industry technology, including 3-D seismic data, improved logging tools, and formation stimulation techniques. During 2004, we spent approximately $68.6 million to drill 46 development wells, 20.9 net to us, of which 45 wells, 20.6 net to us, were successful, representing a 98% success rate. In addition, we spent approximately $26.0 million for new production facilities, leasehold costs and for recompletion, abandonment and workover activities. For 2005, we have budgeted $92.0 million for development drilling and for recompletion, abandonment and workover activities.

      Pursue Exploration Opportunities. We conduct exploration activities to grow our reserve base and to replace our production each year. In 2004, we spent approximately $47.0 million to drill 24 exploratory wells, 10.0 net to us, of which 13 wells, 5.5 net to us, were successful, representing a 54% success rate. We have budgeted $83.0 million for exploration activities in 2005, which will be focused primarily in our Gulf of Mexico, Southeast Texas and South Texas regions.

      Maintain Low Cost Structure. We seek to increase cash flow by carefully controlling operating costs and general and administrative expenses. Our average oil and gas operating costs per Mcfe were $1.22 in 2004 and our general and administrative expenses per Mcfe (excluding stock based compensation) averaged $0.20 in 2004.

      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 766.9 Bcfe of proved oil and natural gas reserves from 31 acquisitions at a total cost of $665.8 million, or $0.87 per Mcfe. The properties were acquired at an average of 63% of their PV 10 Value in the year the acquisitions were completed by us. 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.

      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 $175.0 million on development and exploration projects in 2005. We intend to primarily use operating cash flow to fund our drilling expenditures in 2005. We may also make additional property acquisitions 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.

      Reserve Replacement. We replaced 128% of our production of 42.7 Bcfe in 2004 with 54.6 Bcfe of net additions to our proved reserve base from extensions and discoveries (37.5 Bcfe), purchases (41.0 Bcfe), upward revisions to our previous reserve estimates (1.4 Bcfe), and the net decrease due to the formation of Bois d’Arc Energy, LLC to which we contributed certain of our offshore Gulf of Mexico properties (25.3 Bcfe). The proved reserves added in 2004 were 66% developed and 34% undeveloped. Unless we conduct successful exploration and development activities or acquire properties containing proven reserves, our proved reserves will decline as our reserves are depleted. Our historical reserve additions relate to successful wells drilled in our exploration and development program or acquisitions that we make. To the extent our drilling success rate declines or we are unable to complete acquisitions of productive oil and gas properties, we may not be able to replace all of our production in the future. The production of reserves we added in 2004 are expected to occur during the period from 2005 to 2079. The ultimate recovery of the reserves is subject to future declines in prices of oil and natural gas, which could impact the economic viability of the future operation of the properties and our access to future development capital that will be required to recover additional undeveloped reserves. The annual reserve replacement ratio is calculated by dividing our annual proved reserve additions by our annual production. We use the annual reserve replacement ratio in assessing whether our proved reserve base is expanding or declining. This ratio’s measurement of reserve growth is accurate only to the extent that the reserve additions reflected in a particular year are ultimately recovered and not adjusted upward or downward in the future based on changes to oil and natural gas prices or other factors that may impact the ultimate recovery of such reserves.

Primary Operating Areas

      Our activities are concentrated in four primary operating areas: Gulf of Mexico, East Texas/ North Louisiana, Southeast Texas and South Texas. The following table summarizes the estimated proved oil and natural gas reserves for our five largest offshore fields and our 15 largest onshore fields as of December 31, 2004:

Gulf of Mexico and the Formation of Bois d’Arc Energy

      Prior to July 2004, substantially all of our exploration activities in the Gulf of Mexico were conducted under a joint exploration venture with Bois d’Arc Offshore, Ltd. and its principals which we collectively refer to as “Bois d’Arc”. Under the joint exploration venture, Bois d’Arc was responsible for generating exploration prospects in the Gulf of Mexico. Since 1997 when the joint exploration venture commenced through 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 (“Bois d’Arc Energy”) 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 Gulf of Mexico related assets and assigned our related liabilities, including certain debt, in exchange for equity interests in Bois d’Arc Energy. We contributed interests in our offshore oil and natural gas properties and assigned $83.2 million of related debt in exchange for an approximately 59.9% ownership interest in Bois d’Arc Energy. Each of the Bois d’Arc Participants contributed its interest in commonly owned Gulf of Mexico properties as well as ownership of Bois d’Arc Offshore, Ltd., the operator of the properties, and assigned in the aggregate $28.2 million of related liabilities in exchange for an approximately 40.1% aggregate ownership interest in Bois d’Arc Energy. The Bois d’Arc Participants also received $27.6 million in cash to equalize the amount that our debt exceeded our proportional share of the liabilities assigned. We were also reimbursed $12.7 million for advances made under the joint exploration venture for undrilled prospects. The offshore Gulf of Mexico properties that we own at December 31, 2004 represent our 59.9% proportionate interest in Bois d’Arc Energy’s properties.

      Bois d’Arc Energy’s properties are located offshore of Louisiana and Texas, in state and federal waters of the Gulf of Mexico. Through Bois d’Arc Energy, we own interests in 104 producing wells, 41.3 net to us, in 17 field areas. Bois d’Arc Energy operates 82 of the wells that it owns in this region. We have 182.8 Bcfe of oil and natural gas reserves in the Gulf of Mexico region, which represents 29% of our reserve base. Production from the region averaged 19.6 MMcf of natural gas per day and 3,016 barrels of oil per day, or 37.7 MMcfe per day during 2004 net to our interest. We spent $37.8 million in this region in 2004 drilling 10 development wells, 5.4 net to us, and $33.2 million drilling 14 exploratory wells, 5.7 net to us. We also spent $16.6 million for production facilities, recompletions, abandonment and workovers and $2.4 million on acquiring exploration acreage. In 2005, we plan to spend $75.0 million for development and exploration activities in this region.

      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 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 over 50 Bcfe of natural gas. These properties have 70 productive sands occurring at depths from 2,500 to 16,000 feet. We acquired a 50% working interest in these properties in December 2002 and acquired an additional 30% working interest in October 2003. Bois d’Arc Energy operates the three main production platforms and the 23 producing wells (12.0 net to us) comprising this unit. Production from these properties net to our interest averaged 4.3 MMcf of natural gas per day and 1,376 barrels of oil per day, or 12.6 MMcfe per day, in 2004.

      We own interests in 11 producing wells, 4.6 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. 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 5.2 MMcf of natural gas per day and 306 barrels of oil per day, or 7.0 MMcfe per day, during 2004.

      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 22 wells (8.6 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 originally acquired these properties in December 1997 from Bois d’Arc Resources and other interest owners. These wells are connected to four production platforms and share common oil terminal facilities. Production form these properties net to our interest averaged 1.3 MMcf of natural gas per day and 443 barrels of oil per day, or 3.9 MMcfe per day, during 2004.

      Vermilion block 51 and the adjacent block at South Marsh Island 220 are located in federal waters with depths from 10 to 15 feet, offshore of Vermilion Parish, Louisiana. We drilled four successful wells in this field (1.7 net to us) in 2003 and 2004. These wells have six productive sands occurring at depths from 7,400 to 11,000 feet. A four-pile production platform was installed in January 2005. These wells began producing in January 2005 at a rate net to our interest of 10.4 MMcf of natural gas per day and 51 barrels of oil per day, or 10.7 MMcfe per day.

      Vermilion blocks 87 and 122 are located in federal waters with depths from 30 to 70 feet, offshore of Vermilion Parish, Louisiana. We have six producing wells (2.9 net to us) in Vermilion block 87 and 122. These wells have 11 productive sands occurring at depths from 6,000 to 12,000 feet and are connected to two production platforms. Production from these properties net to our interest averaged 1.9 MMcf of natural gas per day and 75 barrels of oil per day, or 2.3 MMcfe per day, during 2004.

East Texas/ North Louisiana

      Approximately 32% or 200.6 Bcfe of our total proved reserves are located in East Texas and North Louisiana where we own interests in 464 producing wells, 273.6 net to us, in 19 field areas. We operate 271 of these wells. The largest of our fields in this region are the Beckville, Gilmer, Blocker, Logansport, Longwood, Waskom and Lisbon fields. Production from this region averaged 26.7 MMcf of natural gas per day and 238 barrels of oil per day or 28.1 MMcfe per day during 2004. 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. We spent $16.9 million in 2004 drilling 16 development wells, 10.7 net to us, and $4.8 million on workovers and recompletions in this region. We have budgeted $62.0 million in 2005 to drill 69 development wells, 43.2 net to us, in this region.

      Our properties in the Beckville field, located in Panola and Rusk Counties, Texas, have proved reserves of 63.5 Bcfe which represents approximately 10% of our total reserves. We operate 82 wells in this field and own interests in three additional wells for a total of 85 wells, 63.6 net to us. During 2004, production attributable to our interest from this field averaged 6.9 MMcf of natural gas per day and six barrels of oil per day or 7.0 MMcfe per day. The Beckville field produces from the Cotton Valley formation at depths ranging from 9,000 to 10,000 feet. In 2005, we presently plan to drill 21 wells in this field.

      We own interests in 71 natural gas wells and one oil well, 27.4 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 42.8 Bcfe which represents 7% of our total reserve base. During 2004, production attributable to our interest from this field averaged 7.5 MMcf of natural gas per day and 84 barrels of oil per day or 8.0 MMcfe per day.

      The Blocker field in Harrison County, Texas produces primarily from the Cotton Valley formation from depths ranging from 8,600 feet to 10,000 feet. Wells also produce from the Pettit and Travis Peak formations from 6,000 feet to 7,800 feet in depth. We have 34.6 Bcfe of proved reserves in this field (6% of our total proved reserves). We own interests in 26 natural gas wells, 25.2 net to us and operate 25 of these wells. During 2004, net daily production attributable to our interest averaged 2.5 MMcf of natural gas and 12 barrels of oil or 2.5 MMcfe. We presently plan to drill 18 wells in this field in 2005.

      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 15.0 Bcfe in the Logansport field represent approximately 2% of our total reserves. We own interests in 81 natural gas wells and two oil wells for a total of 83 wells, 41.0 net to us, and operate 50 of these wells. During 2004, net daily production attributable to our interest from this field averaged 3.2 MMcf of natural gas and 12 barrels of oil or 3.2 MMcfe.

      We have 5.7 Bcfe of proved reserves in the Longwood field, in Caddo Parish, Louisiana and in Harrison County, Texas. We operate 26 wells in this field and have interests in three additional wells, 24.3 net to us. Production in Longwood Field is from the Travis Peak and Hosston formations. Our daily production net to our interest in 2004 averaged approximately 1.8 MMcf of natural gas and 39 barrels of oil or 2.0 MMcfe.

      The Waskom field, located in Harrison and Panola Counties in Texas, has 7.8 Bcfe of proved reserves as of December 31, 2004. We own interests in 45 natural gas and eight oil wells for a total of 53 wells in this field, 27.8 net to us, and operate 30 wells in this field. During 2004, net daily production attributable to our interest averaged 0.4 MMcf of natural gas and 26 barrels of oil or 1.1 MMcfe. The Waskom field produces from the Cotton Valley formation at depths ranging from 9,000 to 10,000 feet.

      The Lisbon field has 5.1 Bcfe of our proved reserves as of December 31, 2004. We operate 11 wells and own interests in two additional wells in this field for a total of 13 wells, 7.2 net to us, in Claiborne Parish, Louisiana. Our average net daily production from the field in 2004 was approximately 0.3 MMcf of natural gas and 4 barrels of oil per day or 0.3 MMcfe per day. The Lisbon field produces from the Cotton Valley formation at an average depth of 8,000 feet.

Southeast Texas

      Approximately 18% or 112.6 Bcfe of our proved reserves are located in Southeast Texas, where we own interests in 68 producing natural gas wells, 34.3 net to us, and operate 62 of these wells. Net daily production rates from the area averaged 26.9 MMcf of natural gas and 600 barrels of oil or 30.5 MMcfe per day during 2004. We spent $10.1 million in the Southeast Texas region in 2004 drilling two development wells, 1.1 net to us, and for other development and exploration activity. In 2005, we plan to spend $18.0 million for development and exploration activities in this region.

      The Double A Wells field is our largest field area with total estimated proved reserves of 102.6 Bcfe, which is 16% of our total reserves. We own interests in and operate 61 producing natural gas wells, 30.6 net to us, in this field in Polk County, Texas. Net daily production from Double A Wells area averaged 26.1 MMcf of natural gas and 573 barrels of oil or 29.6 MMcfe per day during 2004. These wells typically produce from the Woodbine formation at an average depth of 14,300 feet. In 1999, we began a redevelopment program in

this field based on our interpretation of 3-D seismic data and drilled 19 successful wells from 1999 to 2001. In 2002, we found additional productive Woodbine sands to the south with two successful exploratory wells. In 2003 and 2004, we drilled four additional delineation wells to further extend the discovery made in 2002. We are currently in the process of drilling an exploratory well to the south of the Double A Wells field to test our “Big Sandy” prospect which we identified with a 75 square mile 3-D seismic survey that we acquired in 2004.

      The Sugar Creek field, located in Polk and Tyler Counties, Texas, represents approximately 2% or 8.3 Bcfe of our proved reserves as of December 31, 2004. We own interests in three natural gas wells in this field, 1.9 net to us, and operate one of these wells in this field. During 2004, net daily production attributable to our interest averaged 0.5 MMcf of natural gas and 8 barrels of oil or 0.5 MMcfe. The Sugar Creek field produces from the Upper Woodbine formation at a depth of approximately 11,100 feet.

South Texas

      Approximately 8%, or 51.4 Bcfe, of our proved reserves are located in South Texas, where we own interests in 286 producing wells, 68.4 net to us. We own interests in ten fields in the region, the largest of which are the North Markham, J.C. Martin and the East White Point fields. Net daily production rates from the area averaged 11.5 MMcf of natural gas and 207 barrels of oil or 12.7 MMcfe during 2004. We spent $21.1 million in this region in 2004 to drill 26 wells, 7.7 net to us, and for other development and exploration activity. In 2005, we plan to spend $15.0 million for development and exploration projects in this region.

      The North Markham field is located in Matagorda County, Texas. We own interests in and operate 17 producing oil wells and 5 natural gas wells for a total of 22 wells in which we own a 100% working interest. We purchased these interests in December 2002 and are in the process of redeveloping this field. The field’s estimated proved reserves of 14.9 Bcfe represent 2% of our total reserves. The field’s active wells produce from more than twenty reservoirs of Oligocene Frio age at depths ranging from 6,500 to 9,000 feet. During 2004, net daily production attributable to our interests from this field averaged 89 barrels of oil and 0.4 MMcf of natural gas per day or 0.9 MMcfe per day.

      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 natural gas wells in this field, 14.4 net to us, with proved reserves of 16.5 Bcfe or 3% of our total reserves. During 2004, net daily production attributable to our interest from this field averaged 5.6 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.

      We own interest in three producing natural gas and three producing oil wells for a total of six wells, 3.1 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 Miocene and Frio formation from 1,800 to 11,000 feet. We have 5.5 Bcfe of proved reserves at East White Point which reproduces approximately 1% of our total reserves. Daily production net to our interest in 2004 was 0.1 MMcf of natural gas and 27 barrels of oil or 0.3 MMcfe.

Acquisition Activities

      Using a strategy that capitalizes on our knowledge of and experience in our primary operating regions, we seek to selectively pursue acquisition opportunities where we can evaluate the assets to be acquired in detail

prior to completion of the transaction. We evaluate a large number of prospective properties according to certain internal criteria, including established production and the properties’ future development and exploration potential, low operating costs and the ability for us to obtain operating control.

      As a result of our acquisitions, we have added 766.9 Bcfe of proved oil and natural gas reserves since 1991. Our largest acquisitions are the following:

      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 Bcfe and included 165 active wells of which we operate 69 such wells.

      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, Ball Ranch and Lopeno fields in South Texas. We also acquired interests in the New Albany Shale Gas field in Kentucky, the Glick field in Kansas and the N.E. Moorewood field in Oklahoma. DevX’s properties had 1.2 MMBbls of oil reserves and 156.5 Bcf of natural gas reserves at the time of the acquisition.

      Bois d’ Arc Acquisition. In December 1997, we acquired working interests in certain producing offshore Louisiana oil and gas properties as well as interests in undeveloped offshore oil and natural gas leases for approximately $200.9 million from Bois d’ Arc Resources and certain of its affiliates and working interest partners. We acquired interests in 43 wells, 29.6 net to us, and eight separate production complexes located in the Gulf of Mexico offshore of Plaquemines and Terrebonne Parishes, Louisiana. The acquisition included interests in the Louisiana state and federal offshore areas of Main Pass Block 21, Ship Shoal Blocks 66, 67, 68 and 69 and South Pelto Block 1. The net proved reserves acquired in this acquisition were estimated at 14.3 MMBbls of oil and 29.4 Bcf of natural gas.

      Black Stone Acquisition. In May 1996, we acquired 100% of the capital stock of Black Stone Oil Company and interests in producing and undeveloped oil and gas properties located in Southeast Texas for $100.4 million. We acquired interests in 19 wells, 7.7 net to us, that were located in the Double A Wells field in Polk County, Texas and became the operator of most of the wells in the field. The net proved reserves acquired in this acquisition were estimated at 5.9 MMBbls of oil and 100.4 Bcf of natural gas.

      Sonat Acquisition. In July 1995, we purchased interests in certain producing oil and gas properties located in East Texas and North Louisiana from Sonat Inc. for $48.1 million. We acquired interests in 319 producing wells, 188.0 net to us. The acquisition included interests in the Beckville, Logansport, Waskom, and Longwood fields. The net proved reserves acquired in this acquisition were estimated at 0.8 MMBbls of oil and 104.7 Bcf of natural gas.

Oil and Natural Gas Reserves

      The following table sets forth our estimated proved oil and natural gas reserves and the PV 10 Value as of December 31, 2004. The estimates are based on a reserve report prepared by Lee Keeling and Associates, Inc., our independent petroleum consultants.

     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 reserve data set forth above represents estimates only. 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 the PV 10 Value of 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.

      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, 2004. The market price for our oil production on December 31, 2004, after basis adjustments, was $42.17 per barrel as compared to $31.19 per barrel on December 31, 2003. The market price received for our natural gas production on December 31, 2004, after basis adjustments, was $5.86 per Mcf as compared to $6.44 per Mcf on December 31, 2003.

      We did not provide estimates of total proved oil and natural gas reserves during the years ended December 31, 2002, 2003 or 2004 to any federal authority or agency, other than the SEC.

Drilling Activity Summary

      During the three-year period ended December 31, 2004, we drilled development and exploratory wells as set forth in the table below.

      In 2005 to the date of this report, we have drilled 13 development wells, 8.4 net to us, and 2 exploratory wells, 1.0 net to us. All of the wells were successful. As of the date of this report, we have six development wells, 3.0 net to us, and three exploratory wells, 1.8 net to us, that we 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, 2004:

      We or Bois d’Arc Energy operate 595 of the 1,356 producing wells presented in the above table. As of December 31, 2004, we owned interests in 19 gross wells containing multiple completions which means that a well is producing out of more than one completed zone. Wells with more than one completion are reflected as one well in the table above. If at least one completion is an oil producing zone, then the well is counted as an oil well.

Acreage

      The following table summarizes our developed and undeveloped leasehold acreage at December 31, 2004. We have excluded acreage in which our interest is limited to a royalty or overriding royalty interest.

      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. Substantially all of our oil and natural gas properties are pledged as collateral under our bank credit facility. As is customary in the oil and gas industry, we are generally able to retain our ownership interest in undeveloped acreage by production of existing wells, by drilling activity which establishes commercial reserves sufficient to maintain the lease or by payment of delay rentals.

Markets and Customers

      The market for oil and natural gas produced by us depends on factors beyond our control, including the extent of domestic production and imports of oil and natural gas, the proximity and capacity of natural gas pipelines and other transportation facilities, demand for oil and natural gas, the marketing of competitive fuels and the effects of state and federal regulation. The oil and gas industry also competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers.

      Our oil production is sold at prices tied to the spot oil markets. Our natural gas production is sold under short-term contracts and priced based on first of the month index prices or on daily spot market prices. Approximately 82% of our 2004 natural gas sales were priced utilizing index prices and 18% were priced utilizing daily spot prices. Shell Trading (US) Company was our most significant oil purchaser in 2004, accounting for approximately 20% of our total 2004 sales. Shell Trading represented approximately 18% of our total 2003 sales. BP Energy Company was our most significant gas purchaser in 2004, accounting for approximately 16% of our total 2004 sales. Sales to BP Energy Company comprised approximately 14% of our 2003 sales. The loss of any of the foregoing customers would not have a material adverse effect on us as there is an available market for our crude oil and natural gas production from other purchasers.

Competition

      The oil and gas industry is highly competitive. Competitors include major oil companies, other independent energy companies and individual producers and operators, many of which have financial resources, personnel and facilities substantially greater than we do. We face intense competition for the acquisition of oil and natural gas properties.

Regulation

      General. Various aspects of our oil and natural gas operations are subject to extensive and continually changing regulation, as legislation affecting the oil and natural gas industry is under constant review for amendment or expansion. Numerous departments and agencies, both federal and state, are authorized by statute to issue, and have issued, rules and regulations binding upon the oil and natural gas industry and its individual members. The Federal Energy Regulatory Commission, or “FERC”, regulates the transportation and sale for resale of natural gas in interstate commerce pursuant to the Natural Gas Act of 1938, or “NGA”, and the Natural Gas Policy Act of 1978, or “NGPA”. In 1989, however, Congress enacted the Natural Gas Wellhead Decontrol Act, which removed all remaining price and nonprice controls affecting wellhead sales of natural gas, effective January 1, 1993. While sales by producers of natural gas and all sales of crude oil, condensate and natural gas liquids can currently be made at uncontrolled market prices, in the future Congress could reenact price controls or enact other legislation with detrimental impact on many aspects of our business.

      Regulation and transportation of natural gas. Our sales of natural gas are affected by the availability, terms and cost of transportation. The price and terms for access to pipeline transportation are subject to extensive regulation. In recent years, the FERC has undertaken various initiatives to increase competition within the natural gas industry. As a result of initiatives like FERC Order No. 636, issued in April 1992, the interstate natural gas transportation and marketing system has been substantially restructured to remove various barriers and practices that historically limited non-pipeline natural gas sellers, including producers, from effectively competing with interstate pipelines for sales to local distribution companies and large industrial and commercial customers. The most significant provisions of Order No. 636 require that interstate pipelines provide firm and interruptible transportation service on an open access basis that is equal for all natural gas supplies. In many instances, the results of Order No. 636 and related initiatives have been to substantially reduce or eliminate the traditional role of interstate pipelines as wholesalers of natural gas in favor of providing storage and transportation services.

      In 2000, the FERC issued Order No. 637 and subsequent orders, which imposed additional reforms designed to enhance competition in natural gas markets. Among other things, Order No. 637 revised the FERC’s pricing policy by waiving price ceilings for short-term released capacity for an experimental period, and effected changes in the FERC regulations relating to scheduling procedures, capacity segmentation, penalties, rights of first refusal and information reporting. While most major aspects of Order No. 637 have been upheld on judicial review, certain issues such as capacity segmentation and right of first refusal are pending further consideration by the FERC. We cannot predict what action the FERC will take on these matters in the future or whether the FERC’s actions will survive further judicial review.

      Intrastate natural gas regulation is subject to regulation by state regulatory agencies. The Texas Railroad Commission has been changing its regulations governing transportation and gathering services provided by intrastate pipelines and gatherers. While the changes by these state regulators affect us only indirectly, they are intended to further enhance competition in natural gas markets. We cannot predict what further action the FERC or state regulators will take on these matters; however, we do not believe that we will be affected differently than other natural gas producers with which we compete by any action taken.

      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 Bois d’Arc Energy’s 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 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 regulation of pipelines that transport crude oil, condensate and natural gas liquids is generally more light-handed than the FERC’s regulation of natural gas pipelines under the NGA. Regulated pipelines that transport crude oil, condensate and natural gas liquids are subject to common carrier obligations that generally ensure non-discriminatory access. With respect to interstate pipeline transportation subject to regulation of the

FERC under the Interstate Commerce Act, rates generally must be cost-based, although market-based rates or negotiated settlement rates are permitted in certain circumstances. Pursuant to FERC Order No. 561, issued in October 1993, the FERC implemented regulations generally grandfathering all previously unchallenged interstate pipeline rates and made these rates subject to an indexing methodology. Under this indexing methodology, pipeline rates are subject to changes in the Producer Price Index for Finished Goods, minus one percent. A pipeline can seek to increase its rates above index levels provided that the pipeline can establish that there is a substantial divergence between the actual costs experienced by the pipeline and the rate resulting from application of the index. A pipeline can seek to charge a market-based rate if it establishes that it lacks significant market power. In addition, a pipeline can establish rates pursuant to settlement if agreed upon by all current shippers. A pipeline can seek to establish initial rates for new services through a cost-of-service proceeding, a market-based rate proceeding, or through an agreement between the pipeline and at least one shipper not affiliated with the pipeline. As provided for in Order No. 561, in July 2000, the FERC issued a Notice of Inquiry seeking comment on whether to retain or to change the existing oil rate-indexing method. In December 2000, the FERC issued an order concluding that the rate index reasonably estimated the actual cost changes in the pipeline industry and should be continued for another five-year period, subject to review in July 2005. In February 2003, on remand of its December 2000 order from the D.C. Circuit, the FERC increased its index slightly. A challenge to FERC’s remand order was denied by the D.C. Circuit in April 2004.

      With respect to intrastate crude oil, condensate and natural gas liquids pipelines subject to the jurisdiction of state agencies, such state regulation is generally less rigorous than the regulation of interstate pipelines. State agencies have generally not investigated or challenged existing or proposed rates in the absence of shipper complaints or protests. Complaints or protests have been infrequent and are usually resolved informally.

      We do not believe that the regulatory decisions or activities relating to interstate or intrastate crude oil, condensate or natural gas liquids pipelines will affect us in a way that materially differs from the way it affects other crude oil, condensate and natural gas liquids producers or marketers.

      Environmental regulations. We are subject to stringent federal, state and local laws. These laws, among other things, govern the issuance of permits to conduct exploration, drilling and production operations, the amounts and types of materials that may be released into the environment, the discharge and disposition of waste materials, the remediation of contaminated sites and the reclamation and abandonment of wells, sites and facilities. Numerous governmental departments issue rules and regulations to implement and enforce such laws, which are often difficult and costly to comply with and which carry substantial civil and even criminal penalties for failure to comply. Some laws, rules and regulations relating to protection of the environment may, in certain circumstances, impose strict liability for environmental contamination, rendering a person liable for environmental damages and cleanup cost without regard to negligence or fault on the part of such person. Other laws, rules and regulations may restrict the rate of oil and natural gas production below the rate that would otherwise exist or even prohibit exploration and production activities in sensitive areas. In addition, state laws often require various forms of remedial action to prevent pollution, such as closure of inactive pits and plugging of abandoned wells. The regulatory burden on the oil and natural gas industry increases our cost of doing business and consequently affects our profitability. These costs are considered a normal, recurring cost of our on-going operations. Our domestic competitors are generally subject to the same laws and regulations.

      We believe that we are in substantial compliance with current applicable environmental laws and regulations and that continued compliance with existing requirements will not have a material adverse impact on our operations. However, environmental laws and regulations have been subject to frequent changes over the years, and the imposition of more stringent requirements could have a material adverse effect upon our capital expenditures, earnings or competitive position, including the suspension or cessation of operations in affected areas. As such, there can be no assurance that material cost and liabilities will not be incurred in the future.

      The Comprehensive Environmental Response, Compensation and Liability Act, or “CERCLA”, imposes liability, without regard to fault, on certain classes of persons that are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the current or former owner

or operator of the disposal site or sites where the release occurred and companies that disposed or arranged for the disposal of hazardous substances. Under CERCLA, such persons may be subject to joint and several liability for the cost of investigating and cleaning up hazardous substances that have been released into the environment, for damages to natural resources and for the cost of certain health studies. In addition, companies that incur liability frequently also confront third party claims because it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment from a polluted site.

      The Federal Solid Waste Disposal Act, as amended by the Resource Conservation and Recovery Act of 1976, or “RCRA”, regulates the generation, transportation, storage, treatment and disposal of hazardous wastes and can require cleanup of hazardous waste disposal sites. RCRA currently excludes drilling fluids, produced waters and other wastes associated with the exploration, development or production of oil and natural gas from regulation as “hazardous waste”. Disposal of such non-hazardous oil and natural gas exploration, development and production wastes usually are regulated by state law. Other wastes handled at exploration and production sites or used in the course of providing well services may not fall within this exclusion. Moreover, stricter standards for waste handling and disposal may be imposed on the oil and natural gas industry in the future. From time to time, legislation is proposed in Congress that would revoke or alter the current exclusion of exploration, development and production wastes from RCRA’s definition of “hazardous wastes,” thereby potentially subjecting such wastes to more stringent handling, disposal and cleanup requirements. If such legislation were enacted, it could have a significant impact on our operating cost, as well as the oil and natural gas industry in general. The impact of future revisions to environmental laws and regulations cannot be predicted.

      Our operations are also subject to the Clean Air Act, or “CAA”, and comparable state and local requirements. Amendments to the CAA were adopted in 1990 and contain provisions that may result in the gradual imposition of certain pollution control requirements with respect to air emissions from our operations. We may be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions. However, we believe our operations will not be materially adversely affected by any such requirements, and the requirements are not expected to be any more burdensome to us than to other similarly situated companies involved in oil and natural gas exploration and production activities.

      The Federal Water Pollution Control Act of 1972, as amended, or the “Clean Water Act”, imposes restrictions and controls on the discharge of produced waters and other wastes into navigable waters. Permits must be obtained to discharge pollutants into state and federal waters and to conduct construction activities in waters and wetlands. Certain state regulations and the general permits issued under the Federal National Pollutant Discharge Elimination System program prohibit the discharge of produced waters and sand, drilling fluids, drill cuttings and certain other substances related to the oil and natural gas industry into certain coastal and offshore waters, unless otherwise authorized. Further, the EPA has adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain permits for storm water discharges. Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans. The Clean Water Act and comparable state statutes provide for civil, criminal and administrative penalties for unauthorized discharges for oil and other pollutants and impose liability on parties responsible for those discharges for the cost of cleaning up any environmental damage caused by the release and for natural resource damages resulting from the release. We believe that our operations comply in all material respects with the requirements of the Clean Water Act and state statutes enacted to control water pollution.

      Executive Order 13158, issued on May 26, 2000, directs federal agencies to safeguard existing Marine Protected Areas, or “MPAs”, in the United States and establish new MPAs. The order requires federal agencies to avoid harm to MPAs to the extent permitted by law and to the maximum extent practicable. It also directs the EPA to 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.

      Federal Lease Stipulations address the protection of marine species (sea turtles, marine mammals, Gulf sturgeon and other listed marine species). MMS permit approvals will be conditioned on collection and removal of debris resulting from activities related to exploration, development and production of offshore leases. MMS has issued Notices to Lessees and Operators 2003-G06 advising of requirements for posting of signs in prominent places on all vessels and structures.

      Certain flora and fauna that have officially been classified as “threatened” or “endangered” are protected by the Endangered Species Act. This law prohibits any activities that could “take” a protected plant or animal or reduce or degrade its habitat area. If endangered species are located in an area we wish to develop, the work could be prohibited or delayed and/or expensive mitigation might be required.

      Other statutes that provide protection to animal and plant species and which may apply to our operations include, but are not necessarily limited to, the National Environmental Policy Act, the Coastal Zone Management Act, the Oil Pollution Act, the Emergency Planning and Community Right-to-Know Act, the Marine Mammal Protection Act, the Marine Protection, Research and Sanctuaries Act, the Fish and Wildlife Coordination Act, the Fishery Conservation and Management Act, the Migratory Bird Treaty Act and the National Historic Preservation Act. These laws and regulations may require the acquisition of a permit or other authorization before construction or drilling commences and may limit or prohibit construction, drilling and other activities on certain lands lying within wilderness or wetlands and other protected areas and impose substantial liabilities for pollution resulting from our operations. The permits required for our various operations are subject to revocation, modification and renewal by issuing authorities.

      We maintain insurance against “sudden and accidental” occurrences, which may cover some, but not all, of the risks described above. Most significantly, the insurance we maintain will not cover the risks described above which occur over a sustained period of time. Further, there can be no assurance that such insurance will continue to be available to cover all such cost or that such insurance will be available at a cost that would justify its purchase. The occurrence of a significant event not fully insured or indemnified against could have a material adverse effect on our financial condition and results of operations.

      Regulation of oil and natural gas exploration and production. Our exploration and production operations are subject to various types of regulation at the federal, state and local levels. Such regulations include requiring permits and drilling bonds for the drilling of wells, regulating the location of wells, the method of drilling and casing wells and the surface use and restoration of properties upon which wells are drilled. Many states also have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from oil and natural gas wells and the regulation of spacing, plug and abandonment of such wells. Some state statutes limit the rate at which oil and natural gas can be produced from our properties.

      State Regulation. Most states regulate the production and sale of oil and natural gas, including requirements for obtaining drilling permits, the method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and gas resources. The rate of production may be regulated and the maximum daily production allowable from both oil and gas wells may be established on a market demand or conservation basis or both.

Office and Operations Facilities

      Our executive offices are located at 5300 Town and Country Blvd., Suite 500 in Frisco, Texas 75034 and our telephone number is (972) 668-8800.

      We lease office space in Frisco, Texas covering 27,196 square feet at a monthly rate of $50,993. The lease expires on July 31, 2014. The executive offices of Bois d’Arc Energy are located at 600 Travis Street, Suite 6275, Houston, Texas 77002, and the telephone number at such office is (713) 228-0438. Beginning in May 2005, Bois d’Arc Energy will lease 16,285 square feet of office space in Houston, Texas at a monthly rate of $28,227. This lease expires on April 30, 2012. We also own production offices and pipe yard facilities near Marshall and Livingston, Texas, Logansport, Louisiana and Guston, Kentucky.

Employees

      As of December 31, 2004, we had 72 employees and utilized contract employees for certain of our field operations, and Bois d’Arc Energy had 14 employees and also uses contract employees. We consider our employee relations to be satisfactory.

Directors, Executive Officers and Other Management

      The following table sets forth certain information concerning our executive officers and directors.

      A brief biography of each person who serves as a director or executive officer follows.

      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 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 currently serves on the Board of Regents for Baylor University and on the Advisory Board of the Salvation Army in Dallas, Texas.

      Roland O. Burns has been our Senior Vice President since 1994, Chief Financial Officer and Treasurer since 1990 and our Secretary since 1991. Mr. Burns was elected one of our directors in June 1999. From 1982 to 1990, Mr. Burns was employed by the public accounting firm, Arthur Andersen LLP. During his tenure with Arthur Andersen LLP, Mr. Burns worked primarily in the firm’s oil and gas audit practice. Mr. Burns received B.A. and M.A. degrees from the University of Mississippi in 1982 and is a Certified Public Accountant.

      Mack D. Good was appointed our Chief Operating Officer in May 2004. From 1999 to 2004, he served as Vice President of Operations. From August 1997 until his promotion to Vice President of Operations, Mr. Good served as our district engineer for the East Texas/ North Louisiana region. From 1983 until July 1997, Mr. Good was with Enserch Exploration, Inc. serving in various operations management and engineering positions. Mr. Good received a B.S. of Biology/ Chemistry from Oklahoma State University in 1975 and a B.S. of Petroleum Engineering from the University of Tulsa in 1983. He is a Registered Professional Engineer in the State of Texas.

      Stephen E. Neukom has been our Vice President of Marketing since December 1997 and has served as our manager of crude oil and natural gas marketing since December 1996. From October 1994 to 1996, Mr. Neukom served as Vice President of Comstock Natural Gas, Inc., our former wholly owned gas

marketing subsidiary. Prior to joining us, Mr. Neukom was senior vice president of Victoria Gas Corporation from 1987 to 1994. Mr. Neukom received a B.B.A. degree from the University of Texas in 1972.

      Richard G. Powers joined us as Land Manager in October 1994 and has been our Vice President of Land since December 1997. Mr. Powers has over 20 years of experience as a petroleum landman. Prior to joining us, Mr. Powers was employed for 10 years as land manager for Bridge Oil (U.S.A.), Inc. and its predecessor Pinoak Petroleum, Inc. Mr. Powers received a B.B.A. degree in 1976 from Texas Christian University.

      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 has a B.B.A. from Texas A & M University in 1983.

      Michael W. Taylor has been our Vice President of Corporate Development since December 1997 and has served us in various capacities since September 1994. Mr. Taylor has 31 years of experience in the oil and gas business. For 15 years prior to joining us, he had been an independent oil and gas producer and petroleum consultant. Before that time, he worked in various engineering and executive capacities for a major oil company, a small independent producer and an international oil and gas consulting company. Mr. Taylor is a Registered Professional Engineer in the State of Texas and he received a B.S. degree in Petroleum Engineering from Texas A & M University in 1974.

      David K. Lockett has been a Vice President of Dell Inc. and has managed Dell’s Small and Medium Business Group since 1996. Mr. Lockett has been employed by Dell Inc. for the last 13 years and has spent the past 25 years in the technology industry. Mr. Lockett received a B.B.A. degree from Texas A&M University in 1976. Mr. Lockett has served as one of our directors since July 2001.

      Cecil E. Martin, Jr. has been an independent commercial real estate developer since 1991. From 1973 to 1991, he served as Chairman of a public accounting firm in Richmond, Virginia. Mr. Martin holds a B.B.A. degree from Old Dominion University and is a Certified Public Accountant. Mr. Martin has served as one of our directors since October 1989.

      David W. Sledge has served as an area operations manager for Patterson-UTI Energy, Inc. since May 2004. 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. He received a B.B.A. degree from Baylor University in 1979. Mr. Sledge has served as one of our directors since May 1996.

      Nancy E. Underwood was elected to our board of directors in 2004. Ms. Underwood is owner and President of Underwood Financial Ltd., a position she has held since 1981. Ms. Underwood holds B.S. and J.D. degrees from Emory University and practiced law at an Atlanta, Georgia based law firm before joining Underwood Development Corporation in 1981. Ms. Underwood is involved civically in the Dallas community and currently serves on the boards of the Presbyterian Hospital of Dallas Foundation, the Dallas Historical Society and the Dallas County Advisory Board of the Salvation Army.

      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.

      No matters were submitted to a vote of our security holders during the fourth quarter of 2004.

PART II

      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.

      As of March 17, 2005, we had 36,037,868 shares of common stock outstanding, which were held by 376 holders of record and approximately 10,000 beneficial owners who maintain their shares in “street name” accounts.

      We have never paid cash dividends on our common stock. We presently intend to retain any earnings for the operation and expansion of our business and we do not anticipate paying cash dividends in the foreseeable future. Any future determination as to the payment of dividends will depend upon the results of our operations, capital requirements, our financial condition and such other factors as our board of directors may deem relevant. In addition, we are limited under our bank credit facility and by the terms of the indenture for our senior notes from paying or declaring cash dividends.

      The following table summarizes certain information regarding our equity compensation plans as of December 31, 2004:

      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, 2004 are derived from our consolidated financial statements. The financial results are not necessarily indicative of our future operations or future financial results. The data presented below should be read in conjunction with our consolidated financial statements and the notes thereto and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Statement of Operations Data:

Balance Sheet Data:

      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 “Cautionary Note Regarding Forward-Looking Statements.”

Overview

      We are a growing independent exploration company engaged in the acquisition, discovery and production of oil and natural gas in the United States. We own interests in 1,356 (586.7 net to us) producing oil and natural gas wells and we or Bois d’Arc Energy operate 595 of these wells. In managing our business, we are concerned primarily with maximizing return on our stockholders’ equity. To accomplish this goal, we focus on profitably increasing our oil and natural gas reserves and production.

      Our future growth will be driven primarily by acquisition, development and exploration activities. Under our current drilling budget, we plan to spend approximately $175.0 million in 2005 for development and exploration activities. We plan to drill approximately 114 development wells, 58.9 net to us and 29 exploratory wells, 14.3 net to us. However, the number of wells that we drill in 2005 will be subject to the availability of drilling rigs that we can hire. In addition, we could reduce the wells that we drill if oil and natural gas prices were to decline significantly. We do not budget for acquisitions as the timing and size of acquisitions are not predictable. We use the successful efforts method of accounting which allows only for the capitalization of costs associated with developing proven oil and natural gas properties as well as exploration costs associated with successful exploration activities. Accordingly, our exploration costs consist of costs we incur to acquire and reprocess 3-D seismic data, impairments of our unevaluated leasehold where we were not successful in discovering reserves and the costs of unsuccessful exploratory wells that we drill.

      We generally sell our oil and natural gas at current market prices at the point our wells connect to third party purchaser pipelines. We market our products several different ways depending upon a number of factors, including the availability of purchasers for the product, the availability and cost of pipelines near our wells, market prices, pipeline constraints and operational flexibility. Accordingly, our revenues are heavily dependent upon the prices of, and demand for, oil and natural gas. Oil and natural gas prices have historically been volatile and are likely to remain volatile in the future. Our revenues for 2004 benefited from a general increase in oil and natural gas prices. We have entered into certain hedging arrangements on a small part of our anticipated natural gas sales in 2005 and 2006. We may in the future enter into additional arrangements in order to reduce our exposure to price risks. Such arrangements may also limit our ability to benefit from increases in oil and natural gas prices.

      Our operating costs include the expense of operating our wells and production facilities and transporting our products to the point of sale. Our operating costs are generally comprised of several components, including costs of field personnel, repair and maintenance cost, production supplies, fuel used in operations, transportation cost, state production taxes, workover cost and state 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 our existing properties from acquisitions and through successful drilling efforts, there can be no assurance that we will be able to offset future production declines or maintain our current production level. Our future growth will depend on our ability to continue to add new reserves in excess of our production.

      In December 1997, we established a joint exploration venture with Bois d’Arc to explore for oil and natural gas in the Gulf of Mexico. Under the joint exploration venture, Bois d’Arc was responsible for generating exploration prospects in the Gulf of Mexico utilizing 3-D seismic data and their extensive geological expertise in the region. We advanced the funds for the acquisition of 3-D seismic data and leases. We were reimbursed for all advanced costs and were entitled to a non-promoted working interest in each prospect generated. For each successful discovery well drilled pursuant to the joint exploration venture, we issued to the two principals of Bois d’Arc warrants exercisable for the purchase of shares of our common stock.

      In July 2004, we together with the Bois d’Arc Participants formed Bois d’Arc Energy to replace the joint exploration venture. We and each of the Bois d’Arc Participants contributed substantially all of our Gulf of Mexico related assets and assigned our related liabilities, including certain debt, in exchange for equity interests in Bois d’Arc Energy. We contributed interests in our offshore oil and natural gas properties and assigned $83.2 million of related debt in exchange for an approximately 59.9% ownership interest in Bois d’Arc Energy. Each of the Bois d’Arc Participants contributed its interest in commonly owned Gulf of Mexico properties as well as ownership of Bois d’Arc Offshore, Ltd., the operator of the properties, and assigned in the aggregate $28.2 million of related liabilities in exchange for an approximately 40.1% aggregate ownership interest in Bois d’Arc Energy. The Bois d’Arc Participants also received $27.6 million in cash to equalize the amount that our debt exceeded our proportional share of the liabilities assigned. We were also reimbursed $12.7 million for advances made under the joint exploration venture for undrilled prospects. Our 59.9% proportionate share of Bois d’Arc Energy’s operations are included in our consolidated financial statements beginning in July 2004.

      Bois d’Arc Energy’s exploration and production activities are conducted exclusively in the Gulf of Mexico. Consequently, its operations are significantly impacted by conditions in the Gulf of Mexico, such as adverse weather conditions; the availability of equipment, facilities or services; delays and decreases in the availability of capacity to transport, gather or process production; and changes in the regulatory environment. In September 2004, Bois d’Arc Energy shut in substantially all of its production for four days because of Hurricane Ivan and part of its production was also shut in during the fourth quarter of 2004 awaiting repairs to third party pipelines that were damaged by the hurricane. As a result of the shut-ins, Bois d’Arc Energy was forced to defer production of approximately 2.2 Bcfe, 1.3 net to us, in 2004. Bois d’Arc Energy also had three drilling rigs under contract standing idle for a combined total of 22 days and the start up of a new production facility planned for November 2004 was delayed until January 2005. Operating costs in 2004 included $0.7 million for repairs related to the hurricane.

      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 platforms after production has ceased, to plug and abandon our wells and to remediate any environmental damage our operations may have caused. The fair value of our liability 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 $19.2 million as of December 31, 2004.

Results of Operations

      Our operating data for the last three years is summarized below:

      Oil and gas sales. Our oil and gas sales increased $26.5 million or 11% in 2004 to $261.6 million from $235.1 million in 2003. The increase in sales was mostly due to higher natural gas and crude oil prices, which was partially offset by a decrease in our oil and natural gas production in 2004. Our average natural gas price increased by 11% and our average oil price increased by 30%. On an equivalent unit basis, our average price received for our production in 2004 was $6.12 per Mcfe, which was 15% higher than our average price in 2003 of $5.34 per Mcfe. Our natural gas production decreased by 2% and our oil production decreased by 5%. The decrease in production primarily due to the disruption to Bois d’Arc Energy’s production operations caused by Hurricane Ivan. Approximately 1.3 Bcfe of production was deferred in 2004 because of shut-ins due to the hurricane.

      Oil and gas operating expenses. Our oil and gas operating expenses, including production taxes, increased $6.3 million (14%) to $52.1 million in 2004 from $45.7 million in 2003. Oil and gas operating expenses per equivalent Mcf produced increased $0.18 (17%) to $1.22 in 2004 from $1.04 in 2003. The increase in operating expenses is due primarily to higher production and ad valorem taxes resulting from the higher oil and gas prices in 2004 and the lower production volumes due to the deferred production during September 2004 in the Gulf of Mexico, which was shut-in due to hurricane activity. In addition, operating expenses in 2004 include $0.7 million for repairs resulting from damage caused by the hurricane activity in the Gulf of Mexico.

      Exploration expense. In 2004, we incurred $15.6 million in exploration expense as compared to $4.4 million in 2003. The 2004 expense primarily relates to five exploratory dry holes drilled by Bois d’Arc Energy in the Gulf of Mexico together with six exploratory dry holes drilled in our South Texas region.

      DD&A. Depreciation, depletion and amortization (“DD&A”) increased $2.7 million (4%) to $63.9 million in 2004 from $61.2 million in 2003. DD&A per equivalent Mcf produced for 2004 was $1.46, as compared to $1.37 for 2003. The higher DD&A rates are attributable to increased capitalized costs of our properties.

      Impairment. We recorded impairments to our oil and gas properties of $1.6 million in 2004 and $4.3 million in 2003. These impairments relate to some minor valued fields where an impairment was indicated based on estimated future cash flows attributable to the fields’ estimated proved oil and natural gas reserves.

      General and administrative expenses. General and administrative expenses, which are reported net of overhead reimbursements, of $14.6 million for 2004 were $7.6 million higher than general and administrative expenses of $7.0 million for 2003. The increase is primarily related to stock-based compensation expense that we recorded in 2004 of $6.2 million, resulting from our adoption of a fair value-based method of accounting for employee stock-based compensation including our employee stock options on January 1, 2004. The remaining increase is a result of higher personnel costs in 2004 and higher professional fees related to the increased compliance costs.

      Interest income. Our interest income in 2004 was $1.2 million as compared to $0.1 million in 2003. Included in interest income in 2004 was $1.1 million related to interest paid by the other owners of Bois d’Arc Energy to us.

      Interest expense. Interest expense decreased $8.7 million (29%) to $21.2 million in 2004 from $29.9 million in 2003. The decrease is related to the early retirement of $220.0 million of principal amount of our 11¹/4% senior notes which were refinanced with $175.0 million new 6⁷/8% senior notes along with the borrowings under a new bank credit facility. The refinancing of our 11¹/4% senior notes reduced our interest expense by $10.8 million on an annual basis. Our average borrowings outstanding under our bank credit facility increased to $176.7 million in 2004 as compared to $119.7 million in 2003. The average interest rate on the outstanding borrowings under the bank credit facility also increased to 3.2% in 2004 as compared to 3.0% in 2003.

      Net income. We reported net income of $46.9 million in 2004 as compared to net income of $53.9 million in 2003. Net income per share for 2004 was $1.29 on weighted average diluted shares outstanding of 36.3 million as compared to $1.53 for 2003 on weighted average diluted shares outstanding of 35.3 million. The 2004 results include a charge of $19.6 million ($0.35 per diluted share) relating to the early retirement of our 11¹/4% senior notes. The 2004 results also include a charge of $1.1 million related to the formation of Bois d’Arc Energy. Net income for 2003 included $0.7 million in income ($0.02 per share) related to the cumulative effect of a change in our accounting for future abandonment cost for our oil and gas properties.

      Oil and gas sales. Our oil and gas sales increased $93.0 million or 65% in 2003 to $235.1 million from $142.1 million in 2002. The increase in sales was mostly due to higher natural gas and crude oil prices and increased oil and natural gas production in 2003. Our average natural gas price decreased by 64% and our average oil price increased by 23%. On an equivalent unit basis, our average price received for our production in 2003 was $5.34 per Mcfe, which was 54% higher than our average price in 2002 of $3.47 per Mcfe. The higher prices were accompanied by a 7% increase in our production. Our natural gas production increased by 3% while our oil production increased by 24%. The production increases are primarily related to new production resulting from wells drilled in our 2002 and 2003 drilling programs.

      Oil and gas operating expenses. Our oil and gas operating expenses, including production taxes, increased $12.2 million (37%) to $45.7 million in 2003 from $33.5 million in 2002. Oil and gas operating expenses per equivalent Mcf produced increased $0.22 (27%) to $1.04 in 2003 from $0.82 in 2002. The increase in operating expenses is primarily related to the 7% increase in production and higher ad valorem and production taxes resulting from the significantly higher oil and gas prices in 2003.

      Exploration expense. In 2003, we had $4.4 million in exploration expense, which primarily related to the write-off of exploratory dry holes, impairment of certain of our exploratory leasehold and the acquisition of seismic data. Exploration expense for 2002 was $5.5 million, which related to the write-off of exploratory dry holes.

      DD&A. Our DD&A increased $8.0 million (15%) to $61.2 million in 2003 from $53.2 million in 2002. The increase is attributable to our higher production in 2003. Our depreciation, depletion and amortization per equivalent Mcf produced also increased to $1.37 in 2003 from $1.29 in 2002.

      Impairment. In 2003, we had a $4.3 million impairment of our oil and gas properties which primarily relates to some minor valued fields where an impairment was indicated based on estimated future cash flows attributable to the fields’ estimated proved oil and natural gas reserves.

      General and administrative expenses. General and administrative expenses, which are reported net of overhead reimbursements, of $7.0 million for 2003 were 37% higher than general and administrative expenses of $5.1 million for 2002. The increase was due primarily to the opening of an offshore operations office in Houston, Texas as well as an increase in the number of employees and higher compensation paid to our employees in 2003.

      Other income. Our other income in 2003 was $0.2 million as compared to $8.0 million in 2002. Included in other income in 2002 was $7.7 million related to refunds of severance taxes paid in prior years.

      Interest expense. Interest expense decreased $1.4 million (4%) to $29.9 million for 2003 from $31.3 million in 2002. The decrease was due to a reduction in the average borrowings outstanding under our credit facility of $119.7 million during 2003 as compared to an average of $172.0 million outstanding in 2002. The average interest rate on the outstanding borrowings under the credit facility also decreased to 3.0% in 2003 as compared to 3.6% in 2002.

      Net income. For 2003, we reported net income of $53.4 million, after deducting preferred stock dividends of $0.6 million. These results compared to net income from continuing operations in 2002 of $11.0 million, after deducting preferred stock dividends of $1.6 million. Our income from continuing operations per share for 2003 was $1.53 on diluted weighted average shares outstanding of 35.3 million as compared to net income from continuing operations per share of $0.37 for 2002 on diluted weighted average shares outstanding of 33.9 million. Net income for 2003 included $0.7 million in income ($0.02 per share) related to the cumulative effect of a change in our accounting for future abandonment cost for our oil and gas properties. In 2002, we sold certain marginal oil and gas properties. The operating results of these properties in 2002 including the loss on disposal of $1.1 million ($0.03 per share) have been reflected as discontinued operations.

      Funding for our activities has historically been provided by our operating cash flow, debt or equity financings or asset dispositions. In 2004, our net cash flow provided by operating activities totaled $171.4 million and we received proceeds of $175.0 million from a public sale of new eight-year 6⁷/8% senior notes. We also increased the debt outstanding under our bank credit facility by $142.0 million.

      Our primary needs for capital, in addition to funding our ongoing operations, relate to our acquisition, development and exploration activities and the repayment of our debt. In 2004, we incurred capital expenditures of $209.8 million primarily for our development and exploration activities. We also retired our 11¹/4% senior notes and we loaned Bois d’Arc Energy $48.3 million.

      Our annual capital expenditure activity is summarized in the following table:

      The timing of most of our capital expenditures is discretionary because we have no material long-term capital expenditure commitments. Consequently, we have a significant degree of flexibility to adjust the level of our capital expenditures as circumstances warrant. We spent $70.6 million, $86.1 million and $146.7 million on development and exploration activities in 2002, 2003 and 2004, respectively. We have budgeted approximately $175.0 million for development and exploration projects in 2005. We expect to use internally generated cash flow to fund development and exploration activity. Our operating cash flow is highly dependent on oil and natural gas prices, especially natural gas prices.

      We spent $11.4 million, $4.8 million and $62.7 million on acquisition activities in 2002, 2003 and 2004, respectively. 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. We do not have a specific acquisition budget for 2005 since the timing and size of acquisitions are not predictable. We intend to use borrowings under our bank credit facility, or other debt or equity financings to the extent available, to finance significant 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.

      On January 1, 2004 we had $220.0 million in principal amount of our 11¹/4% senior notes due 2007 (the “1999 Notes”) outstanding. Pursuant to a tender offer, on February 25, 2004, we repurchased $197.7 million in principal amount of the 1999 Notes for $212.2 million plus accrued interest. On May 1, 2004, we redeemed the remaining $22.3 million in principal amount of the 1999 Notes outstanding for $23.6 million plus accrued interest. The early extinguishment of the 1999 Notes resulted in a loss of $19.6 million, which was comprised of the premium paid for the repurchase of the 1999 Notes together with the write-off of unamortized debt issuance costs related to the 1999 Notes.

      In connection with the repurchase of the 1999 Notes, we sold $175.0 million of senior notes in an underwritten public offering. The new senior notes are due March 1, 2012 and bear interest at 6⁷/8%, which is payable semiannually on March 1 and September 1. The 6⁷/8% senior notes are unsecured obligations and are currently guaranteed by all of our subsidiaries.

      On February 25, 2004, we also entered into a new $400.0 million bank credit facility with Bank of Montreal, as the administrative agent, which replaced our former credit facility. The bank credit facility is a four-year revolving credit commitment that matures on February 25, 2008. Borrowings under the bank credit facility were used to refinance amounts outstanding under our prior bank credit facility and to fund the repurchase of the 1999 Notes. Indebtedness under our bank credit facility is secured by substantially all of our and our subsidiaries’ assets and is guaranteed by all of our subsidiaries. The bank credit facility is subject to borrowing base availability, which is redetermined semiannually based on the banks’ estimates of the future net cash flows of our oil and natural gas properties. The borrowing base may be affected by the performance of our properties and changes in oil and natural gas prices. The determination of the borrowing base is at the sole

discretion of the administrative agent and the bank group. Borrowings under the bank credit facility bear interest, based on the utilization of the borrowing base, at our option at either LIBOR plus 1.25% to 1.75% or the base rate (which is the higher of the prime rate or the federal funds rate) plus 0% to 0.5%. A commitment fee of 0.375% is payable on the unused borrowing base. The bank credit facility contains covenants that, among other things, restrict the payment of cash dividends, 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 current ratio and maintenance of a minimum tangible net worth. We were in compliance with these covenants as of December 31, 2004.

      In connection with the formation of Bois d’Arc Energy, we have made available to Bois d’Arc Energy a revolving line of credit in a maximum outstanding amount of $200.0 million, of which approximately $148.0 million was outstanding on December 31, 2004. In consideration for the line of credit, Bois d’Arc Energy and its subsidiaries each became guarantors of our bank credit facility and our 6⁷/8% senior notes.

      On October 4, 2004, Bois d’Arc Energy filed a registration statement on Form S-1 with the SEC related to a proposed underwritten initial public offering of $150.0 million of its common stock. As of the date of this report, the Form S-1 is not yet effective. Such an offering will have the effect of diluting our current 59.9% interest in Bois d’Arc Energy. The net proceeds of the offering are expected to be used to refinance the amounts outstanding under the credit facility provided by us. If Bois d’Arc Energy does not complete a financing transaction that generates sufficient proceeds to repay all of the amounts outstanding under the credit facility by May 1, 2005 (or such later date as is determined by Bois d’Arc Energy’s board of managers), Bois d’Arc Energy will be dissolved and liquidated in a manner designed to put its members in a position as near as possible to the same economic position that the members would have been in if they had never formed Bois d’Arc Energy and instead had continued to own their respective properties individually.

      We believe that our cash flow from operations and available borrowings under the bank credit facility will be sufficient to fund our operations and future growth as contemplated under our current business plan. However, if our plans or assumptions change or if our assumptions prove to be inaccurate, we may be required to seek additional capital. We cannot provide any assurance that we will be able to obtain such capital, or if such capital is available, that we will be able to obtain it on acceptable terms.

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

Federal Taxation

      At December 31, 2004, we had federal income tax net operating loss carryforwards of approximately $53.4 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 2023. The value of these carryforwards depends on our ability to generate future taxable income in order to utilize these carryforwards.

Critical Accounting Policies

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

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

      Oil and natural gas reserve quantities. The determination of depreciation, depletion and amortization expense as well as impairments that are recognized on our oil and gas properties are highly dependent on the estimates of the proved oil and natural gas reserves attributable to our properties. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be precisely measured. The accuracy of any reserve estimate depends on the quality of available data, production history and engineering and 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.

      The estimates of our proved oil and gas reserves used in the preparation of our consolidated financial statements were determined by an independent petroleum engineering consulting firm and were prepared in accordance with the rules promulgated by the SEC and the Financial Accounting Standards Board (the “FASB”).

      Impairment of oil and gas properties. The determination of impairment of our oil and gas reserves is based on the oil and natural gas reserve estimates using projected future oil and natural gas prices that we have determined to be reasonable. The projected prices that we employ represent our long-term oil and natural gas price forecast and may be higher or lower than the December 31, 2004 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, 2004, we used oil and natural gas prices that were based on the current futures market. We used oil prices of $45.86, $42.86 and $40.93 per barrel for 2005, 2006 and 2007, respectively, and escalated prices by 3% each year thereafter to a maximum price of $48.60 per barrel. For natural gas we used prices of $6.20, $6.27 and $5.87 per Mcf for 2005, 2006 and 2007, respectively, and escalated prices by 3% each year thereafter to a maximum price of $6.75 per Mcf. To the extent we had used lower prices in our impairment review, an impairment could have been indicated on certain of our oil and gas properties.

      Accounting for asset retirement obligations. We adopted Statement of Financial Accounting Standards No. 143 (“SFAS 143”) “Accounting for Asset Retirement Obligations,” on January 1, 2003. This statement requires us to record a liability in the period in which an asset retirement obligation (“ARO”) is incurred, in an amount equal to the discounted estimated fair value of the obligation that is capitalized. Thereafter, each quarter this liability is accreted up to the final retirement cost. The adoption of SFAS 143 on January 1, 2003

resulted in a gain of $0.7 million which was reflected as a cumulative effect of a change in accounting principle. The determination of our asset retirement obligations is based on our estimate of the fair value to plug and abandon our oil and gas wells and to dismantle and dispose of our offshore production facilities. The actual costs could be higher or lower than our current estimates.

      Stock-based compensation. Prior to January 1, 2004, we accounted for employee stock-based compensation using the intrinsic value method prescribed in Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees” (“APB 25”). Under the intrinsic method, compensation cost for stock options is measured as the excess, if any, of the fair value of our common stock at the date of the grant over the amount an employee must pay to acquire the common stock. Effective January 1, 2004, we changed our method of accounting for employee stock-based compensation to the preferable fair value based method prescribed in Statement of Financial Accounting Standards No. 123, “Accounting for Stock-Based Compensation” (“SFAS 123”). Under the fair value based method, compensation cost is measured at the grant date based on the fair value of the award and is recognized over the award vesting period. We determine the fair value of each stock option at the date of grant using the Black-Scholes options pricing model. Under the modified prospective transition method selected by us as described in Statement of Financial Accounting Standards No. 148, “Accounting for Stock-Based Compensation — Transition and Disclosure,” stock-based compensation expense recognized for 2004, is the same as that which would have been recognized had the fair value method of SFAS 123 been applied from its original effective date. Accordingly, during 2004 our general and administrative expenses included $6.2 million in stock-based compensation. In accordance with the modified prospective transition method, results for years prior to 2004 were not restated. For years prior to 2004, no compensation cost was recognized for our employee stock options. If compensation costs had been determined in accordance with SFAS 123, we would have recorded an additional compensation expense of $1.6 million and $3.0 million in 2002 and 2003, respectively.

      Included in our 2004 stock-based compensation was $1.5 million attributable to our ownership in Bois d’Arc Energy. In connection with its formation, Bois d’Arc Energy established a long-term incentive plan to provide for equity-based compensation for its executive officers, employees and consultants. The awards made under this plan were comprised of either options to purchase class B LLC units or restricted class C LLC units, representing solely a profits interest. All of the awards made under the Bois d’Arc Energy incentive plan vest over a five year period. At the time of its formation, Bois d’Arc Energy granted options to purchase a total of 2,800,000 class B units at an exercise price of $6.00 per unit and 4,290,000 restricted class C units. In determining the fair value of the class B units and class C units underlying the equity awards granted, Bois d’Arc Energy used a valuation methodology that it believes is consistent with the practices recommended by the AICPA Audit and Accounting Practice Aid Series, Valuation of Privately-Held-Company Equity Securities Issued as Compensation (the “Practice Aid”). Bois d’Arc Energy reviewed the guidance set forth in the Practice Aid and performed a retrospective valuation on a “top down” basis, using an enterprise valuation model. Bois d’Arc Energy determined the fair value of the entity and then allocated the enterprise value to the various classes of member units. Bois d’Arc Energy also consulted with an independent valuation specialist regarding the methods and procedures used to determine, on a retrospective basis, the fair value of the class B units and the class C units at the time of issuance. The valuation conducted determined that the fair value of a class B unit at the date of the issuance was $8.42 per unit. The fair value of a class C unit was determined to be $3.40 per unit. The fair value of each option awarded under the incentive plan was estimated using the Black-Scholes option-pricing model and determined to be $4.55 per option.

      New accounting standards. On December 16, 2004, the FASB issued Statement 123 (revised 2004), “Share-Based Payment” (“SFAS 123 R”) that requires compensation costs related to share-based payment transactions (issuance of stock options and restricted stock) to be recognized in the financial statements. With limited exceptions, the amount of compensation cost is to be measured based on the grant date fair value of the equity or liability instruments issued. Compensation cost is recognized over the period that an employee provides service in exchange for the award. Statement 123 R replaces SFAS 123, “Accounting for Stock-Based Compensation”, and supersedes APB 25. SFAS 123 R is effective for the first reporting period after June 15, 2005. Entities that use the fair value-based method for either recognition or disclosure under SFAS 123 are required to apply SFAS 123 R using a modified version of prospective application whereby the

entity is required to record compensation expense for all awards it grants after the date of adoption and the unvested portion of previously granted awards that remain outstanding at the date of adoption. Effective January 1, 2004, we adopted the fair value-based measure as proscribed in SFAS 123 using the modified prospective application. Therefore, SFAS 123 R will not have a significant impact on us.

      On December 16, 2004, the FASB also issued Statement 153, “Exchanges of Nonmonetary Assets”, an amendment of APB Opinion No. 29, to clarify the accounting for nonmonetrary exchanges of similar productive assets. SFAS 153 provides a general exception from fair value measurement for exchanges of nonmonetary assets that do not have commercial substance. A nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. The Statement will be applied prospectively and is effective for nonmonetary asset exchanges occurring in fiscal periods beginning after June 15, 2005.

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.

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 2004, a $1.00 change in the price per barrel of oil would have resulted in a change in our cash flow for such period by approximately $1.4 million and a $1.00 change in the price per Mcf of natural gas would have changed our cash flow by approximately $32.1 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. We did not hedge any of our 2004 oil and natural gas production. While the use of these derivative arrangements limits the downside risk of price declines, such use may also limit any benefits which may be derived from price increases. We use swaps, floors and collars to hedge oil and natural gas prices. Swaps are settled monthly based on differences between the prices specified in the instruments and the settlement prices of futures contracts quoted on the New York Mercantile Exchange. Generally, when the applicable settlement price is less than the price specified in the contract, we receive a settlement from the counterparty based on the difference multiplied by the volume hedged. Similarly, when the applicable settlement price exceeds the price specified in the contract, we pay the counterparty based on the difference. We generally receive a settlement from the counterparty for floors when the applicable settlement price is less than the price specified in the contract, which is based on the difference multiplied by the volumes hedged. For collars, we generally receive a settlement from the counterparty when the settlement price is below the floor and pay a settlement to the counterparty when the settlement price exceeds the cap. No settlement occurs when the settlement price falls between the floor and the cap.

      The following table sets forth the derivative financial instruments that we entered into during 2004 which relate to our 2005 and 2006 natural gas production: