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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Form 10-K

Commission file no. 0-16741

Comstock Resources, Inc.

5300 Town and Country Blvd., Suite 500, Frisco, Texas 75034

(972) 668-8800

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

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

      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

      As of March 12, 2004, there were 34,678,862 shares of common stock outstanding.

      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 $449,953,613.

DOCUMENTS INCORPORATED BY REFERENCE

Proxy statement for the 2004 annual meeting of stockholders — Part III

COMSTOCK RESOURCES, INC.

ANNUAL REPORT ON FORM 10-K

CONTENTS

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FORWARD-LOOKING STATEMENTS

      This report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements other than statements of historical facts included in this report, including without limitation, statements under “Business and Properties” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations‘ regarding budgeted capital expenditures, increases in oil and natural gas production, our financial position, oil and natural gas reserve estimates, business strategy and other plans and objectives for future operations, are forward-looking statements. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we can give no assurance that such expectations will prove to have been correct. There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond our control. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be precisely measured. Furthermore, the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates made by different engineers often vary from one another. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revisions of such estimate and such revision, if significant, would change the schedule of any further production and development drilling. Accordingly, reserve estimates are generally different from the quantities of oil and gas that are ultimately recovered. Should one or more of these risks or uncertainties occur, or should underlying assumptions prove incorrect, our actual results and plans for 2004 and beyond could differ materially from those expressed in forward-looking statements. All subsequent written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by such factors.

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.

      “Cash Margin per Mcfe” means the equivalent price per Mcfe less oil and gas operating expenses per Mcfe and general and administrative expenses per Mcfe.

      “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.

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      “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.

      “Present Value of Proved Reserves” 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%.

      “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 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.

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

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

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

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

      “Working interest” means an interest in an oil and gas lease that gives the owner of the interest the right to drill for and produce oil and gas on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations. The share of production to which a working interest owner is entitled will always be smaller than the share of costs that the working interest owner is required to bear, with the balance of the production accruing to the owners of royalties. For example, the owner of a 100% working interest in a lease burdened only by a landowner’s royalty of 12.5% would be required to pay 100% of the costs of a well but would be entitled to retain 87.5% of the production.

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

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PART I

      We are an independent energy company engaged in the acquisition, development, production and exploration of oil and natural gas properties. 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 Illinois Basin region in Kentucky and in the Mid-Continent regions located in the Texas panhandle, Oklahoma and Kansas. Our oil and natural gas properties are estimated to have proved reserves of 616.9 Bcfe with an estimated Present Value of Proved Reserves of $1.7 billion as of December 31, 2003. Our proved oil and natural gas reserve base is 81% natural gas and 67% proved developed on a Bcfe basis as of December 31, 2003. We replaced 108% of our production of 44.0 Bcfe in 2003 through our exploration, development and acquisition activities. We were also able to reduce our long-term debt by $60.0 million from $366.0 million as of December 31, 2002 to $306.0 million as of December 31, 2003.

      Our proved reserves at December 31, 2003 and our 2003 average daily production are summarized below:

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 35%, 28%, 21% 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 results in us having high cash margins. Finally, our properties have an average reserve life of approximately 14 years and have extensive development and exploration potential.

      Successful Exploration and Development Program. In 2003, we spent $46.8 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 35 development wells, 22.0 net to us, with a 89% success rate. We also had a successful exploratory drilling program in 2003, spending a total of $34.8 million to drill 18 wells, 7.4 net to us, with a 78% success rate. We spent an additional $5.1 million in acquiring new acreage and seismic data in 2003 to support our exploration program.

      Successful Acquisitions. We have had significant growth over the years as a result of acquisitions. Since 1991, we have added 725.9 Bcfe of proved oil and natural gas reserves from 30 acquisitions at an average cost of $0.83 per Mcfe. Our application of strict economic and reserve risk criteria have enabled us to successfully evaluate and integrate acquisitions.

      Efficient Operator. We operate 61% of our proved oil and natural gas reserve base as of December 31, 2003. 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 which can access attractive natural gas and crude oil markets. In addition, our natural gas production has a relatively high Btu content of approximately 1.07 Btu. Our crude oil production has a favorable API gravity of approximately 40 degrees.

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      High Cash Margins. As a result of our quality properties, higher price realizations and efficient operations, we have higher cash margins than most 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 utilize advanced industry technology, including 3-D seismic data, improved logging tools, and formation stimulation techniques. During 2003, we spent approximately $28.3 million to drill 35 development wells, 22.0 net to us, of which 31 wells, 19.2 net to us, were successful, representing a success rate of 89 %. In addition, we spent approximately $18.5 million for new production facilities, leasehold costs and for recompletion, abandonment and workover activities. For 2004, we have budgeted $37.0 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 2003, we spent approximately $34.8 million to drill 18 exploratory wells, 7.4 net to us, of which 14 wells, 5.3 net to us, were successful, representing a success rate of 78%. We also spent $5.1 million in acquiring new acreage and seismic data in 2003 to support our exploration program. We have budgeted $73.0 million in 2004 for exploration activities which will be focused primarily in the 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 $1.04 in 2003 and our general and administrative expenses per Mcfe averaged only $0.16 in 2003.

      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 725.9 Bcfe of proved oil and natural gas reserves from 30 acquisitions at a total cost of $603.1 million, or $0.83 per Mcfe. The acquisitions were acquired at an average of 60% of their Present Value of Proved Reserves in the year the acquisitions were completed. 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 $110.0 million on development and exploration projects in 2004. We intend to primarily use operating cash flow to fund our drilling expenditures in 2004. We may also make additional property acquisitions in 2004 that would require additional sources of funding. Such sources may include borrowings under our bank credit facility or sales of our equity or debt securities.

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Primary Operating Areas

      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 20 largest fields as of December 31, 2003:

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      Our Gulf of Mexico operating region includes properties located offshore of Louisiana and Texas, in state and federal waters of the Gulf of Mexico. We own interests in 98 producing wells, 50.1 net to us, in ten field areas, the largest of which are the Ship Shoal area (Ship Shoal Blocks 66, 67, 68, 69, 92, 93, 99, 107, 109, 110, 112, 113, 114, 117, 118, 119, 120, 135 and 146 and South Pelto Block 1), the South Timbalier/South Pelto area (South Timbalier Blocks 9, 11, 15, 16, 30, 34, 50, 52 and South Pelto Blocks 5, 15, 22 and 25) and the Main Pass Area (Main Pass Blocks 21,41,43, 55 and 58). In addition, we have 13 wells, 5.3 net to us, that have been drilled and are awaiting connection to production facilities in the Gulf of Mexico. We have 216.1 Bcfe of oil and natural gas reserves in the Gulf of Mexico region which represents 35% of our reserve base. We operate 40 of the wells that we own in this region. Production from the region averaged 21.8 MMcf of natural gas per day and 3,151 barrels of oil per day during 2003. We spent $14.2 million in this region in 2003 drilling seven development wells, 3.4 net to us, and $25.8 million drilling eleven exploratory wells, 4.0 net to us. We also spent $14.0 million for production facilities, recompletions, abandonment and workovers and $1.7 million on acquiring exploration acreage and seismic data. In 2004, we plan to spend $67.0 million for development and exploration activities in this region.

      Ship Shoal. The Ship Shoal area is located in Louisiana state waters and in federal waters, offshore of Terrebonne Parish. In this area, oil and natural gas are produced from numerous Miocene sands occurring at depths from 5,800 to 13,500 feet, and in water depths from 10 to 60 feet. We own interests in 46 wells in this area, 31.2 net to us, in Ship Shoal Blocks 66, 67, 68, 69, 92, 93, 99, 107, 109, 110, 112, 113, 114, 117, 118, 119, 120, 135 and 146 and in South Pelto Block 1. We operate 32 of these wells. Our properties in the Ship Shoal area have estimated proved reserves of 104.9 Bcfe, which is 17% of our total reserves. Production from the Ship Shoal area net to our interest averaged 8.4 MMcf of natural gas per day and 2,145 barrels of oil per day during 2003. In 2003, we drilled eight wells, 3.9 net to us, at Ship Shoal.

      South Timbalier/South Pelto. We own interests in 22 producing wells, 6.7 net to us, in Louisiana state waters and in federal waters in the South Timbalier/South Pelto area located offshore of Terrebonne and Lafourche Parishes in water depths ranging from 20 to 60 feet. We have estimated proved reserves totaling 79.9 Bcfe attributable to this area which is 13% of our total reserves. Production attributable to our interest averaged 11.1 MMcf of natural gas per day and 472 barrels of oil per day in 2003. These wells produce from numerous sands of Pliocene to Upper Miocene age, at depths ranging from 2,000 to 12,000 feet as well as the geopressured Miocene section at depths below 18,000 feet. We drilled six wells, 1.8 net to us, in the South Timbalier/South Pelto area in 2003.

      Main Pass. Main Pass Block 21 is located in Louisiana state waters, offshore of Plaquemines Parish in water with a depth of approximately 12 feet. Our wells in this area produce from multiple Miocene sands at depths that range from 4,400 to 7,700 feet. We are the operator and own interests in six wells, 5.6 net to us, at Main Pass Block 21. We also own nonoperated interests in eight producing wells, 1.2 net to us, at Main Pass Blocks 41, 43, 55 and 58 in federal waters with an average depth of 50 feet. Proved reserves for the total Main Pass area were 10.7 Bcfe, which is 2% of our total reserves at December 31, 2003. Production attributable to our interest from the Main Pass Area was approximately 1.0 Mmcf of natural gas per day and 468 barrels of oil per day in 2003.

      Approximately 28% or 174.7 Bcfe of our proved reserves are located in East Texas and North Louisiana where we own interests in 422 producing wells, 232.3 net to us, in 21 field areas. We operate 243 of these wells. The largest of our fields in this region are the Gilmer, Beckville, Logansport and Waskom fields. Production from this region averaged 29.2 MMcf of natural gas per day and 237 barrels of oil per day during 2003. Most of the reserves in this area produce from the Cretaceous aged Travis Peak/Hosston formation and the Jurassic aged Cotton Valley formation. The total thickness of these formations range from 2,000 to 4,000 feet of sand, shale and limestone sequences in the East Texas Basin and the North Louisiana Salt Basin, at depths ranging from 6,000 to 12,000 feet. In 2003, we spent $3.6 million drilling five wells, 2.4 net to us, and $1.9 million on workovers and recompletions in this region. We have budgeted approximately $7.0 million in 2004 for development activities in this region.

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      Gilmer. We own interests in 72 natural gas wells, 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 55.1 Bcfe which represents 9% of our total reserve base. During 2003, production attributable to our interest from this field averaged 9.6 MMcf of natural gas per day and 110 barrels of oil per day.

      Beckville. Our properties in the Beckville field, located in Panola and Rusk Counties, Texas, have proved reserves of 45.0 Bcfe which represents approximately 7% of our total reserves. We operate 72 wells in this field and own interests in thee additional wells for a total of 75 wells, 55.3 net to us. During 2003, production attributable to our interest from this field averaged 6.3 MMcf of natural gas per day and eight barrels of oil per day. The Beckville field produces from the Cotton Valley formation at depths ranging from 9,000 to 10,000 feet.

      Logansport. The Logansport field produces from multiple sands in the Hosston formation at an average depth of 8,000 feet and is located in DeSoto Parish, Louisiana. Our proved reserves of 17.1 Bcfe in the Logansport field represent approximately 3% of our total reserves. We own interests in 81 wells, 40.2 net to us, and operate 50 of these wells. During 2003, net daily production attributable to our interest from this field averaged 3.1 MMcf of natural gas and twelve barrels of oil.

      Waskom. The Waskom field, located in Harrison and Panola Counties in Texas, represents approximately 2% (13.4 Bcfe) of our proved reserves as of December 31, 2003. We own interests in 52 wells in this field, 26.0 net to us, and operate 28 wells in this field. During 2003, net daily production attributable to our interest averaged 0.9 MMcf of natural gas and 16 barrels of oil. The Waskom field produces from the Cotton Valley formation at depths ranging from 9,000 to 10,000 feet.

      Approximately 21% or 127.0 Bcfe of our proved reserves are located in Southeast Texas, where we own interests in 88 producing wells, 50.9 net to us, and operate 61 of these wells. Net daily production rates from the area averaged 28.4 MMcf of natural gas and 738 barrels of oil during 2003. We spent $8.0 million in the Southeast Texas region in 2003 drilling three wells, 1.7 net to us, and for other development activity. In 2004, we plan to spend $20.0 million for development and exploration activities in this region. Substantially all of the reserves in this region are in the Double A Wells field area in Polk County, Texas.

      Double A Wells. The Double A Wells field is our largest field area with total estimated proved reserves of 116.9 Bcfe, which is 19% of our total reserves. We own interests in and operate 59 producing wells, 29.7 net to us, in this field in Polk County, Texas. Net daily production from Double A Wells area averaged 27.3 MMcf of natural gas and 701 barrels of oil during 2003. 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, we drilled two additional delineation wells to further extend the discovery made in 2002. We are currently in the process of acquiring new 3-D seismic data to continue our exploration efforts.

South Texas

      Approximately 8%, or 47.1 Bcfe, of our proved reserves are located in South Texas, where we own interests in 263 producing wells, 59.6 net to us. We own interests in eleven fields in the region, the largest of which are the J.C. Martin and the North Markham fields. Net daily production rates from the area averaged 9.0 MMcf of natural gas and 149 barrels of oil during 2003. We spent $13.1 million in this region in 2003 to drill 13 wells, 4.5 net to us, and for other development activity. In 2004, we plan to spend approximately $15.0 million primarily for development and exploration activity in this region.

      J.C. Martin. Our largest field in South Texas is the J.C. Martin field which is located in the structurally complex and highly prolific Wilcox Lobo trend in Zapata County, Texas on the Mexico border. We own interests in 81 wells in this field, 13.0 net to us, with proved reserves of 16.1 Bcfe or 3% of our total reserves.

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      North Markham. The North Markham/North Bay City field is located in Matagorda County, Texas. We own interests in and operate 19 producing wells, 19.0 net to us, in the Ohio-Sun Unit. We purchased these interests in December 2002 and are in the process of redeveloping this field. The field’s estimated proved reserves of 13.6 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 2003, net daily production attributable to our interests from this field averaged 67 barrels of oil per day.

Acquisition Activities

      Acquisition Strategy. We have concentrated our acquisition activity in the Gulf of Mexico, East Texas/North Louisiana, Southeast Texas and South Texas regions. Using a strategy that capitalizes on our knowledge of and experience in these 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.

      Major Property Acquisitions. As a result of our acquisitions, we have added 725.9 Bcfe of proved oil and natural gas reserves since 1991.

      Our largest acquisitions are the following:

      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 in this transaction. 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.

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Oil and Natural Gas Reserves

      The following table sets forth our estimated proved oil and natural gas reserves and the Present Value of Proved Reserves as of December 31, 2003:

(1)	The standardized measure of discounted future net cash flows represents the present value of future cash flows attributable to our proved oil and natural gas reserves after income tax discounted at 10%.

     There are numerous uncertainties inherent in estimating oil and natural gas reserves and their values, including many factors beyond the control of the producer. The reserve data set forth above represents estimates only. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates of different engineers may vary. In addition, estimates of reserves are subject to revision based on the results of drilling, testing and production subsequent to the date of such estimates. Accordingly, reserve estimates are often different from the quantities of oil and gas reserves that are ultimately recovered.

      In general, the volume of production from oil and natural gas properties decline as reserves are depleted. Except to the extent we acquire properties containing proved reserves or conduct successful exploration and development activities, our proved reserves will decline as reserves are produced. Our future oil and natural gas production is highly dependent upon the level of success in acquiring or finding additional reserves.

      The Present Value of Proved Reserves was determined based on the market prices for oil and natural gas on December 31, 2003. The market price for our oil production on December 31, 2003, after basis adjustments, was $31.19 per barrel as compared to $30.07 per barrel on December 31, 2002. The market price received for our natural gas production on December 31, 2003, after basis adjustments, was $6.44 per Mcf as compared to $5.04 per Mcf on December 31, 2002.

      Comstock did not provide estimates of total proved oil and natural gas reserves during the years ended December 31, 2001, 2002 or 2003 to any federal authority or agency, other than the SEC.

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Drilling Activity Summary

      During the three-year period ended December 31, 2003, we drilled development and exploratory wells as set forth in the table below.

      Wells drilled in 2003 that are presented above exclude four pilot wells, 1.8 net to us, drilled in New Mexico to test a potential coalbed methane project. These wells are still being evaluated.

      In 2004 to the date of this report, we have drilled seven development wells, 3.5 net to us, and two exploratory wells, 0.8 net to us. All of the development wells were successful. Both of the exploratory wells were dry holes. As of the date of this report, we have three development wells, 1.4 net to us, and one exploratory well, 0.2 net to us, that are in the process of drilling.

Producing Well Summary

      The following table sets forth the gross and net producing oil and natural gas wells in which we owned an interest at December 31, 2003:

      We operate 463 of the 1,166 producing wells presented in the above table. As of December 31, 2003, we owned interests in 12 gross wells containing multiple completions.

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Acreage

      The following table summarizes our developed and undeveloped leasehold acreage at December 31, 2003. 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. 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.

      All of our oil production is sold at the well site at prices tied to the spot oil markets. Substantially all of our natural gas production is sold either on the spot natural gas market under short-term contracts at prevailing spot market prices, or under long-term contracts based on current spot market prices. Our most significant purchaser in 2003 was Shell Trading Company. Substantially all of our Gulf of Mexico and Double A Wells field oil production in 2003 was sold to Shell. Oil sales in 2003 to Shell accounted for approximately 18% of our total 2003 oil and gas sales. BP Energy Company is our most significant natural gas purchaser. Total natural gas sales in 2003 to BP Energy Company accounted for approximately 14% of our total 2003 oil and gas sales. Our natural gas sales to Houston Pipe Line Company, a subsidiary of American Electric Power Company, Inc., accounted for approximately 10% of our total 2003 oil and gas sales.

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.

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Regulation

      Our operations are regulated by certain federal and state agencies. In particular, oil and natural gas production and related operations are or have been subject to price controls, taxes and other laws relating to the oil and natural gas industry. We cannot predict how existing laws and regulations may be interpreted by enforcement agencies or court rulings, whether additional laws and regulations will be adopted, or the effect such changes may have on our business or financial condition.

      Our sales of natural gas are not regulated and are made at market prices. However, the Federal Energy Regulatory Commission regulates interstate and certain intrastate natural gas transportation rates and service conditions, which affect the marketing of natural gas produced by us, as well as the revenues received by us for sales of such production. Since the mid-1980s, the Federal Energy Regulatory Commission has issued a series of orders, culminating in Order Nos. 636, 636-A and 636-B, that have significantly altered the marketing and transportation of natural gas. These regulations mandated a fundamental restructuring of interstate pipeline sales and transportation service, including the unbundling by interstate pipelines of the sales, transportation, storage and other components of the city-gate sales services such pipelines previously performed. One of the Federal Energy Regulatory Commission purposes in issuing these regulations was to increase competition within all phases of the natural gas industry. Generally, these regulatory orders have eliminated or substantially reduced the interstate pipelines’ traditional role as wholesalers of natural gas and have substantially increased competition and volatility in natural gas markets.

      Our sales of oil and natural gas liquids are not regulated and are made at market prices. The price we receive from the sale of these products is affected by the cost of transporting the products to market.

      Our oil and natural gas exploration, production and related operations are subject to extensive rules and regulations promulgated by federal, state and local agencies. Failure to comply with such rules and regulations can result in substantial penalties. The regulatory burden on the oil and gas industry increases our cost of doing business and affects our profitability. Because such rules and regulations are frequently amended or reinterpreted, we are unable to predict the future cost or impact of complying with such laws.

      Most of the states in which we operate require permits for drilling operations, drilling bonds and the filing of reports concerning operations and impose other requirements relating to the exploration and production of oil and gas. These 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 gas wells and the regulation of spacing, plugging and abandonment of such wells. The statutes and regulations of certain states limit the rate at which oil and gas can be produced from our properties.

      We are required to comply with various federal and state regulations regarding plugging and abandonment of oil and natural gas wells. Our financial statements include a reserve for the estimated costs of plugging and abandoning our wells.

      Environmental Regulation. Various federal, state and local laws and regulations governing the discharge of materials into the environment, or otherwise relating to the protection of the environment, health and safety, affect our operations and costs. These laws and regulations sometimes require governmental authorization before conducting certain activities, limit or prohibit other activities because of protected areas or species, create the possibility of substantial liabilities for pollution related to our operations or properties and provide penalties for noncompliance. In particular, our drilling and production operations, our activities in connection with storage and transportation of crude oil and other liquid hydrocarbons and our use of facilities for treating, processing or otherwise handling hydrocarbons and related exploration and production wastes are subject to stringent environmental regulation. As with the industry in general, compliance with existing and anticipated regulations increases our overall cost of business. While these regulations affect our capital expenditures and earnings, we believe that such regulations do not affect our competitive position in the industry because our competitors are similarly affected by environmental regulatory programs. Environmental regulations have historically been subject to frequent change and, therefore, we cannot predict with certainty the future costs or other future impacts of environmental regulations on our future operations. A discharge of

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      The following are examples of some environmental laws that potentially impact us and our operations.

      Water. The Oil Pollution Act was enacted in 1990 and amends provisions of the Federal Water Pollution Control Act of 1972 and other statutes as they pertain to the prevention of and response to major oil spills. The Oil Pollution Act subjects owners of facilities to strict, joint and potentially unlimited liability for removal costs and certain other consequences of an oil spill along shorelines or that enters navigable waters. In the event of an oil spill into such waters, substantial liabilities could be imposed upon us. Recent regulations developed under the Oil Pollution Act require companies that own offshore facilities, including us, to demonstrate oil spill financial responsibility for removal costs and damage caused by oil discharge. States in which we operate have also enacted similar laws. Regulations are currently being developed under the Oil Pollution Act and similar state laws that may also impose additional regulatory burdens upon us.

      The Federal Water Pollution Control Act imposes restrictions and strict controls regarding the discharge of produced waters, other oil and gas wastes, any form of pollutant, and, in some instances, storm water runoff, into waters of the United States. The Federal Water Pollution Control Act provides for civil, criminal and administrative penalties for any unauthorized discharges and, along with the Oil Pollution Act, imposes substantial potential liability for the costs of removal, remediation or damages resulting from an unauthorized discharge. State laws for the control of water pollution also provide civil, criminal and administrative penalties and liabilities in the case of an unauthorized discharge into state waters. The cost of compliance with the Oil Pollution Act and the Federal Water Pollution Control Act have not historically been material to our operations, but there can be no assurance that changes in federal, state or local water pollution control programs will not materially adversely affect us in the future. Although no assurances can be given, we believe that compliance with existing permits and compliance with foreseeable new permit requirements will not have a material adverse effect on our financial condition or results of operations.

      Air Emissions. The Federal Clean Air Act and comparable state programs require many industrial operations in the United States to incur capital expenditures in order to meet air emissions control standards developed by the United States Environmental Protection Agency and state environmental agencies. Although no assurances can be given, we believe that compliance with the Clean Air Act and comparable state laws will not have a material adverse effect on our financial condition or results of operations.

      Solid Waste. We generate non-hazardous solid wastes that are subject to the requirements of the Federal Resource Conservation and Recovery Act and comparable state statutes. The EPA and the states in which we operate are considering the adoption of stricter disposal standards for the type of non-hazardous wastes generated by us. The Resource Conservation and Recovery Act also governs the generation, management, and disposal of hazardous wastes. At present, we are not required to comply with a substantial portion of the requirements under this law because our operations generate minimal quantities of hazardous wastes. However, it is possible that additional wastes, which could include wastes currently generated during our operations, could in the future be designated as “hazardous wastes.” Hazardous wastes are subject to more rigorous and costly disposal and management requirements than are non-hazardous wastes. Such changes in the regulations may result in additional capital expenditures or operating expenses by us.

      Superfund. The Comprehensive Environmental Response, Compensation, and Liability Act also known as “Superfund”, imposes liability, without regard to fault or the legality of the original act, on certain classes of persons in connection with the release of a “hazardous substance” into the environment. These persons include the current owner or operator of any site where a release historically occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Superfund also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. In the course of our ordinary operations, we may have managed substances that may fall within Superfund’s definition of a

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      We currently own or lease numerous properties that for many years have been used for the exploration and production of oil and gas. Although we believe we have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released by us on or under the properties owned or leased by us. In addition, many of these properties have been previously owned or operated by third parties who may have disposed of or released hydrocarbons or other wastes at these properties. Under Superfund and analogous state laws, we could be subject to certain liabilities and obligations, such as being required to remove or remediate previously disposed wastes, including wastes disposed of or released by prior owners or operators, to clean up contaminated property, including contaminated groundwater, or to perform remedial plugging operations to prevent future contamination.

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 make available free of charge on our website our annual report on Form 10-K, our quarterly reports on Form 10-Q, our current reports on Form 8-K, and amendments to these reports, as soon as reasonably practicable after we file such material with, or furnish it to, the SEC. The Internet address of our website is www.comstockresources.com, and such website contains additional information about us; however, such information does not constitute part of this Annual Report on Form 10-K.

      We lease office space in Frisco, Texas covering 20,046 square feet at a monthly rate of $34,706, which increases to $39,717 beginning June 2004. The lease expires on May 31, 2006. In addition to our leased office space in Frisco, Texas, we lease 2,329 square feet of office space in Houston, Texas at a monthly rate of $3,299. This lease expires on March 31, 2007. We also own production offices and pipe yard facilities near Marshall and Livingston, Texas, Logansport, Louisiana and Guston, Kentucky.

Employees

      As of December 31, 2003, we had 68 employees and utilized contract employees for certain of our field operations. We consider our employee relations to be satisfactory.

Directors, Executive Officers and Other Management

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

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Executive Officers.

      M. Jay Allison has been one of our directors since 1987, and our President and Chief Executive Officer since 1988. Mr. Allison was elected chairman of the board of directors in 1997. From 1987 to 1988, Mr. Allison served as our vice president and secretary. From 1981 to 1987, he was a practicing oil and gas attorney with the firm of Lynch, Chappell & Alsup in Midland, Texas. In 1983, Mr. Allison co-founded a private independent oil and gas company, Midwood Petroleum, Inc., which was active in the acquisition and development of oil and gas properties from 1983 to 1987. 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.

      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 vice president of operations in March 1999. From August 1997 until his promotion, 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.

      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 28 years of experience in the oil and gas business. For 15 years prior to joining us, he had been an independent oil and gas producer and petroleum consultant. Before that time, he worked in various engineering and executive capacities for a major oil company, a small independent producer and an international oil and gas consulting company. Mr. Taylor is a Registered Professional Engineer in the State of Texas and he received a B.S. degree in Petroleum Engineering from Texas A & M University in 1974.

Outside Directors.

      David K. Lockett was appointed to our board of directors in 2001. Mr. Lockett is currently a vice president of Dell Computer Corp. and heads up Dell’s Small and Medium Business group. Mr. Lockett has been employed by Dell Computer Corp. for the last ten years and has spent the past twenty five years in the technology industry. Mr. Lockett received a B.B.A. degree from Texas A&M University in 1976.

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      Cecil E. Martin, Jr. has been one of our directors since 1988. Mr. Martin 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.

      David W. Sledge was elected to our board of directors in 1996. Since 1996, he has been investing in oil and gas exploration activities. Mr. Sledge served as President of Gene Sledge Drilling Corporation, a privately held contract drilling company based in Midland, Texas until its sale in October 1996. Mr. Sledge served Gene Sledge Drilling Corporation in various capacities from 1979 to 1996. 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.

      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 2003.

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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 12, 2004, we had 34,678,862 shares of common stock outstanding, which were held by 414 holders of record and approximately 9,300 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 securities issuable and authorized by the stockholders under certain equity compensation plans: