UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K (Mark One) ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF x THE SECURITIES EXCHANGE ACT OF 1934 --- For the fiscal year ended December 31, 2002 OR TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 Commission File No. 0-16741 COMSTOCK RESOURCES, INC. (Exact name of registrant as specified in its charter) NEVADA 94-1667468 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification Number) 5300 Town and Country Blvd., Suite 500, Frisco, Texas 75034 (Address of principal executive offices including zip code) (972) 668-8800 (Registrant's telephone number and area code) Securities registered pursuant to Section 12(b) of the Act: Common Stock, $.50 Par Value New York Stock Exchange Preferred Stock Purchase Rights New York Stock Exchange (Title of class) (Name of exchange on which registered) Securities registered pursuant to Section 12(g) of the Act: None Indicate by check mark 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 x No --- 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. [ x ] Indicate by check mark whether the registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2). Yes x No --- As of March 26, 2003, there were 28,919,561 shares of common stock outstanding. As of June 30, 2002, the aggregate market value of the voting stock held by non-affiliates of the registrant was approximately $215.0 million. DOCUMENTS INCORPORATED BY REFERENCE Proxy statement for the 2003 annual meeting of stockholders - Part IIICOMSTOCK RESOURCES, INC. ANNUAL REPORT ON FORM 10-K For the Fiscal Year Ended December 31, 2002 CONTENTS Item Page - ---------- Part I ----- Forwarding Looking Statements................................... 2 Definitions..................................................... 2 Introductory Note............................................... 5 1. and 2. Business and Properties......................................... 5 3. Legal Proceedings............................................... 21 4. Submission of Matters to a Vote of Security Holders............. 21 Part II 5. Market for Registrant's Common Equity and Related Stockholder Matters..................................... 22 6. Selected Financial Data......................................... 23 7. Management's Discussion and Analysis of Financial Condition and Results of Operations..................... 24 7 A. Operations Quantitative and Qualitative Disclosures About Market Risks...................................... 33 8. Financial Statements............................................ 35 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure..................... 35 Part III 10. Directors and Executive Officers of the Registrant.............. 36 11. Executive Compensation.......................................... 36 12. Security Ownership of Certain Beneficial Owners and Management.......................................... 36 13. Certain Relationships and Related Transactions.................. 36 14. Controls and Procedures......................................... 36 Part IV 15. Exhibits and Reports on Form 8-K................................ 37 1 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 2003 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. 2 "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. "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%. 3 "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. "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. 4 PART I INTRODUCTORY NOTE Subsequent to the issuance of our Annual Report for the year ended December 31, 2001, we determined that certain outstanding advances made by us to our partner under our joint exploration venture in the Gulf of Mexico for seismic data acquisition should have been charged to exploration expense rather than reflected on the balance sheet as an asset. As a result of changing our accounting treatment for the advances used for seismic data acquisition, we determined that our financial statements for 1998, 1999, 2000 and 2001 should be restated. The effect of the restatement is a reduction to previously reported net income by $0.4 million, $0.3 million, $0.2 million and $1.6 million for the years 1998, 1999, 2000 and 2001, respectively, as a result of the additional exploration expense in each year. These changes primarily affect the timing of our recognition of exploration expense. As reimbursements are received for the advances we have made, our future exploration expense will be reduced. In addition, we have reclassified our Series 1999 Preferred Stock from stockholders' equity at December 31, 2001 to temporary equity. Please see "Restatement of Previously Issued Financial Statements" in Item 7 of this Annual Report and Note 13 to our Consolidated Financial Statements filed as part of this Annual Report. ITEMS 1. AND 2. BUSINESS AND PROPERTIES 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 613.9 Bcfe with an estimated Present Value of Proved Reserves of $1.3 billion as of December 31, 2002. Our proved oil and natural gas reserve base is 80% natural gas and 66% proved developed on a Bcfe basis as of December 31, 2002. Our proved reserves at December 31, 2002 and our 2002 average daily production are summarized below: Reserves at December 31, 2002 2002 Daily Production --------------------------------- ---------------------------------------- % of % of Oil Gas Total Total Oil Gas Total Total -------- ------ ------- ----- -------- -------- -------- ------ (MMBbls) (Bcf) (Bcfe) (MBbls/d) (MMcf/d) (MMcfe/d) Gulf of Mexico........... 15.6 96.1 189.7 30.9 2.2 20.7 33.6 29.8 East Texas / North Louisiana 1.1 182.0 188.5 30.7 0.3 32.4 34.2 30.4 Southeast Texas.......... 3.1 107.1 125.5 20.4 0.9 24.3 29.5 26.2 South Texas.............. 0.7 47.0 51.3 8.4 0.1 6.5 7.0 6.2 Other Regions............ 0.3 56.6 58.9 9.6 0.1 7.2 8.3 7.4 ------ ------ ------ ----- ---- ----- ------ ------ Total.............. 20.8 488.8 613.9 100.0% 3.6 91.1 112.6 100.0% ====== ====== ====== ===== ==== ===== ====== ====== Strengths 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 31%, 31%, 20% 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 15.0 years and have extensive development and exploration potential. 5 Successful Exploration and Development Program. In 2002, we spent $35.3 million on the exploitation and development of our oil and natural gas properties for development drilling, recompletions, workovers and production facilities. Overall, we drilled 27 development wells, 11.7 net to us, with a 96% success rate. We also had a successful exploratory drilling program in 2002, spending a total of $31.1 million to drill 20 wells, 7.6 net to us, with a 75% success rate. We spent an additional $4.3 million in acquiring new acreage in 2002 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 711.7 Bcfe of proved oil and natural gas reserves from 29 acquisitions at an average cost of $0.84 per Mcfe. Our application of strict economic and reserve risk criteria have enabled us to successfully evaluate and integrate acquisitions. Efficient Operator. We operate 60% of our proved oil and natural gas reserve base as of December 31, 2002. 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 1,079 Btu. Our crude oil production has a favorable API gravity of approximately 40 degrees. Due to these factors, we have relatively high price realizations compared to benchmark prices. In 2002 our average natural gas price, before gains from hedging activities, was $3.26 per Mcf, which represented a $0.04 premium to the 2002 NYMEX average monthly settlement price. Also in 2002, our average crude oil price was $24.95 per barrel, which represented a $2.04 barrel premium to the average monthly West Texas Intermediate crude oil price for 2002 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. 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 2002, we spent approximately $22.9 million to drill 27 development wells, 11.7 net to us, of which 26 wells, 10.7 net to us, were successful, representing a success rate of 96%. In addition, we spent approximately $12.4 million for new production facilities, leasehold costs and for recompletion and workover activities. For 2003, we have budgeted $49.0 million for development drilling and for workover and recompletion activity. Pursue Exploration Opportunities. We conduct exploration activities to grow our reserve base and to replace our production each year. In 2002 we replaced 131% of our 2002 production from new discoveries. In 2002, we spent approximately $31.1 million to drill 20 exploratory wells, 7.6 net to us, of which 15 wells, 5.3 net to us, were successful, representing a success rate of 75%. We also spent $4.3 million in acquiring new acreage in 2002 to support our exploration program. We have budgeted $51.0 million in 2003 for exploration activities which will be focused primarily in the Gulf of Mexico, Southeast Texas and South Texas regions. 6 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 $0.82 in 2002 and our general and administrative expenses per Mcfe averaged only $0.12 in 2002. 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 711.7 Bcfe of proved oil and natural gas reserves from 29 acquisitions at a total cost of $598.3 million, or $0.84 per Mcfe. The acquisitions were acquired at an average of 63% 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 $100.0 million on development and exploration projects in 2003. We intend to primarily use operating cash flow to fund our drilling expenditures in 2003. We may also make additional property acquisitions in 2003 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. 7 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, 2002. Present Value of Net Oil Net Gas Proved (MBbls) (MMcf) MMcfe % Reserves % -------- --------- --------- ------- ---------- ------- Gulf of Mexico (in thousands) Ship Shoal.................... 8,696 36,448 88,626 $ 208,146 South Timbalier / South Pelto. 4,371 51,918 78,143 224,288 Main Pass..................... 1,359 1,991 10,148 24,017 East White Point.............. 750 2,107 6,605 8,517 Other......................... 410 3,685 6,144 17,565 -------- --------- --------- ---------- 15,586 96,149 189,666 30.9 482,533 37.7 -------- --------- --------- ---------- East Texas / North Louisiana Gilmer........................ 399 64,377 66,769 124,434 Beckville..................... 116 46,126 46,821 78,350 Logansport.................... 43 15,268 15,523 30,742 Waskom........................ 210 13,186 14,446 24,275 Blocker....................... 42 11,324 11,576 17,813 Box Church.................... 4 6,408 6,430 11,565 Ada........................... 5 6,003 6,033 14,955 Other......................... 257 19,319 20,869 42,582 -------- --------- --------- ---------- 1,076 182,011 188,467 30.7 344,716 26.9 -------- --------- --------- ---------- Southeast Texas Double A Wells................ 2,840 97,973 115,012 259,388 Sugar Creek................... 95 8,584 9,155 13,400 Other......................... 135 553 1,361 3,517 -------- --------- --------- ---------- 3,070 107,110 125,528 20.4 276,305 21.6 -------- --------- --------- ---------- South Texas J. C. Martin.................. -- 18,383 18,383 34,995 North Markham................. 474 13,432 16,277 35,825 Ball Ranch.................... 80 5,368 5,847 13,940 Lopeno........................ 39 4,748 4,981 6,859 Other......................... 131 5,045 5,835 10,975 -------- --------- --------- ---------- 724 46,976 51,323 8.4 102,594 8.0 -------- --------- --------- ---------- Illinois Basin New Albany Shale Gas.......... -- 35,486 35,486 5.8 32,578 2.5 -------- --------- --------- ---------- Mid-Continent Glick......................... 8 5,890 5,935 9,499 N. E. Moorewood............... 17 4,990 5,090 9,215 Other......................... 155 7,070 8,005 14,733 -------- --------- --------- ---------- 180 17,950 19,030 3.1 33,447 2.6 -------- --------- --------- ---------- Other Areas................... 213 3,102 4,379 0.7 8,120 0.7 -------- --------- --------- ------ ---------- ------ Total 20,849 488,784 613,879 100.0 $1,280,293 100.0 ======== ========= ========= ====== ========== ====== 8 Gulf of Mexico 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 108 producing wells, 47.5 net to us, in nine field areas, the largest of which are the Ship Shoal area (Ship Shoal Blocks 66, 67, 68, 69, 99, 107, 113 and 146 and South Pelto Block 1), and the South Timbalier / South Pelto area (South Timbalier Blocks 11, 16, 34, 50 and South Pelto Blocks 5 and 15). We have 189.7 Bcfe of oil and natural gas reserves in the Gulf of Mexico region which represents 31% of our reserve base. We operate 46 of the wells that we own in this region. Production from the region averaged 20.7 MMcf of natural gas per day and 2,158 barrels of oil per day during 2002. We spent $5.3 million in this region in 2002 drilling three development wells, 1.2 net to us, and $21.7 million drilling 8 exploratory wells, 3.0 net to us. We also spent $8.7 million for production facilities, recompletions and workovers. In 2003, we plan to spend $54.0 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 the 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 50 wells in this area, 27.1 net to us, in Ship Shoal Blocks 66, 67, 68, 69, 99, 107, 113 and 146 and in South Pelto Block 1. We operate 38 of these wells. Our properties in the Ship Shoal area have estimated proved reserves of 88.6 Bcfe, which is 14% of our total reserves. Production from the Ship Shoal area net to our interest averaged 2.1 MMcf of natural gas per day and 1,110 barrels of oil per day during 2002. We drilled two exploratory wells at Ship Shoal in 2002. One was successful and one was a dry hole. South Timbalier / South Pelto We own interests in 21 producing wells, 6.4 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 78.1 Bcfe attributable to this area which is 13% of our total reserves. Production attributable to our interest averaged 14.5 MMcf of natural gas per day and 506 barrels of oil per day in 2002. 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 a geopressured Miocene section at a depth below 16,000 feet. We drilled seven wells in the South Timbalier / South Pelto area in 2002. Six of these wells were successful with one exploratory dry hole. East Texas / North Louisiana Approximately 31% or 188.5 Bcfe of our proved reserves are located in East Texas and North Louisiana where we own interests in 415 producing wells, 229.7 net to us, in 21 field areas. We operate 241 of these wells. The largest of our fields in this region are the Gilmer, Beckville, Logansport, Waskom and Blocker fields. Production from this region averaged 32.4 MMcf of natural gas per day and 287 barrels of oil per day during 2002. 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 2002 we spent $16.7 million drilling 18 wells, 7.0 net to us, and $0.8 million on workovers and recompletions in this region. We have budgeted approximately $8.0 million in 2003 for development activities in this region. 9 Gilmer We own interests in 70 natural gas wells, 26.6 net to us, in the Gilmer field in Upshur County in East Texas. These wells produce from the Cotton Valley Lime formation at a depth of approximately 11,500 feet to 12,000 feet. Proved reserves attributable to our interests in the Gilmer field are 66.8 Bcfe which represents 11% of our total reserve base. During 2002 production attributable to our interest from this field averaged 11.9 MMcf of natural gas per day and 142 barrels of oil per day. In 2002, we drilled 15 sucessful development wells at Gilmer, 5.7 net to us. Beckville Our properties in the Beckville field, located in Panola and Rusk Counties, Texas, have proved reserves of 46.8 Bcfe which represents approximately 8% of our total reserves. We operate 72 wells in this field and own interests in four additional wells for a total of 76 wells, 55.6 net to us. During 2002, production attributable to our interest from this field averaged 7.9 MMcf of natural gas per day and 10 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 15.5 Bcfe in the Logansport field represents approximately 3% of our total reserves. We own interests in 82 wells, 38.6 net to us, and operate 48 of these wells. During 2002, net daily production attributable to our interest from this field averaged 3.1 MMcf of natural gas and 17 barrels of oil. Waskom The Waskom field, located in Harrison and Panola Counties in Texas, represented approximately 2% (14.4 Bcfe) of our proved reserves as of December 31, 2002. We own interests in 52 wells in this field, 26.7 net to us, and operate 29 wells in this field. During 2002, net daily production attributable to our interest averaged 1.0 MMcf of natural gas and 22 barrels of oil. The Waskom field produces from the Cotton Valley formation at depths ranging from 9,000 to 10,000 feet. Blocker We own interests in 26 wells, 25.2 net to us, in the Blocker field in Harrison County, Texas and we operate 25 of these wells. These wells produce primarily from the Cotton Valley formation from depths ranging from 8,600 feet to 10,000 feet and the Pettit and Travis Peak formations from depths of 6,000 feet to 7,800 feet. At December 31, 2002, we had 11.6 Bcfe of proved reserves in this field. Production from this field attributable to our interest averaged 2.9 MMcf of natural gas and 14 barrels of oil per day in 2002. Southeast Texas Approximately 20% or 125.5 Bcfe of our proved reserves are located in Southeast Texas, where we own interests in 86 producing wells, 49.8 net to us, and operate 59 of these wells. Net daily production rates from the area averaged 24.3 MMcf of natural gas and 871 barrels of oil during 2002. We spent $4.3 million in the Southeast Texas region in 2002 drilling three exploratory wells, 1.7 net to us. In 2003, we plan to spend $14.0 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. 10 Double A Wells The Double A Wells field is our largest field area with total estimated proved reserves of 115.0 Bcfe, which is 19% of our total reserves. We own interests in and operate 57 producing wells, 28.6 net to us, in this field in Polk County, Texas. Net daily production from Double A Wells area averaged 22.2 MMcf of natural gas and 791 barrels of oil during 2002. 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 extended the reserves to the south with two successful exploratory wells. The first discovery well is currently producing from a depth of about 14,700 feet. The other successful well also found productive pay in the Woodbine formation and is awaiting pipeline connection and completion. South Texas Approximately 8% or 51.3 Bcfe of our proved reserves are located in South Texas, where we own interests in 251 producing wells, 53.5 net to us. We own interests in seven 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 6.5 MMcf of natural gas and 78 barrels of oil during 2002. We spent $7.7 million in this region in 2002 primarily to drill eight exploration wells, 2.3 net to us. All but one of these wells were successful. In 2003, we plan to spend approximately $21.0 million primarily for 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 Mexican border. We own interests in 82 wells in this field, 13.1 net to us, with proved reserves of 18.4 Bcfe or 3% of our total reserves. During 2002, net daily production attributable to our interest from this field averaged 4.4 MMcf of natural gas. This field produces primarily from Eocene Wilcox Lobo sands at depths ranging from 7,000 to 9,000 feet. The Lobo section is characterized by geopressured, multiple pay sands occurring in a highly faulted area. North Markham The North Markham / North Bay City field is located in Matagorda County, Texas. We own interests in and operate 15 producing wells, 15.0 net to us, in the Ohio-Sun Unit. We purchased these interests from Marathon Oil Company in December 2002 and plan to redevelop this field beginning in 2003. The field's estimated proved reserves of 16.3 Bcfe represent 3% of our total reserves. The field's active wells produce from more than twenty reservoirs of Oligocene Frio age at depths ranging from 6,500 to 9,000 feet. 11 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 711.7 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. 12 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, 2002: Present Value of Proved Oil Gas Total Reserves (MBbls) (MMcf) (MMcfe) (000's) ------ ------- ------- ---------- Proved Developed Producing......... 7,030 244,909 287,087 $ 607,970 Proved Developed Non-producing..... 6,907 74,246 115,692 236,722 Proved Undeveloped................. 6,912 169,629 211,100 435,601 ------ ------- ------- ---------- Total Proved................. 20,849 488,784 613,879 $1,280,293 ====== ======= ======= ========== 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 estimate. 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 declines 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, 2002. The market price for our oil production on December 31, 2002, after basis adjustments, was $30.07 per barrel as compared to $18.73 per barrel on December 31, 2001. The market price received for our natural gas production on December 31, 2002, after basis adjustments, was $5.04 per Mcf as compared to $2.69 per Mcf on December 31, 2001. 13 Drilling Activity Summary During the three-year period ended December 31, 2002, we drilled development and exploratory wells as set forth in the table below. Year Ended December 31, ------------------------------------------------ 2000 2001 2002 -------------- ------------- ------------- Gross Net Gross Net Gross Net ----- ----- ----- ----- ----- ----- Development Wells: Oil................... -- -- 2 .7 -- -- Gas................... 37 19.7 29 16.3 26 10.7 Dry................... -- -- 4 1.8 1 1.0 ----- ----- ----- ----- ----- ----- 37 19.7 35 18.8 27 11.7 ----- ----- ----- ----- ----- ----- Exploratory Wells: Oil................... 2 1.1 1 .3 2 .8 Gas................... 5 2.2 13 4.5 13 4.5 Dry................... 5 1.5 3 1.1 5 2.3 ----- ----- ----- ----- ----- ----- 12 4.8 17 5.9 20 7.6 ----- ----- ----- ----- ----- ----- Total Wells........ 49 24.5 52 24.7 47 19.3 ====== ===== ===== ===== ===== ===== In 2003 to the date of this report, we have drilled seven development wells, 6.4 net to us, and four exploratory wells, 1.5 net to us. All development wells were either successful or are still being evaluated by us. Three of the exploratory wells were successful and one was a dry hole. As of the date of this report, we have three wells, 0.8 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, 2002. Oil Gas ------------- ------------- Gross Net Gross Net ----- ---- ----- ----- Colorado....................... -- -- 1 .3 Kansas......................... -- -- 12 4.5 Kentucky....................... -- -- 86 76.4 Louisiana...................... 6 2.3 171 76.3 Mississippi.................... 1 .1 1 .2 Offshore Gulf of Mexico........ 36 17.4 72 30.1 Oklahoma....................... 2 .3 134 16.0 Texas.......................... 109 40.5 497 218.3 Wyoming........................ -- -- 31 2.3 ----- ---- ----- ----- Total Wells............. 154 60.6 1,005 424.4 ===== ==== ===== ===== We operate 454 of the 1,159 producing wells presented in the above table. 14 Acreage The following table summarizes our developed and undeveloped leasehold acreage at December 31, 2002. We have excluded acreage in which our interest is limited to a royalty or overiding royalty interest. Developed Undeveloped ----------------- ----------------- Gross Net Gross Net ------- ------- ------- ------- Colorado .............. 320 80 -- -- Kansas ................ 6,400 4,064 -- -- Kentucky .............. 13,689 11,964 9,358 9,199 Louisiana ............. 76,972 56,830 7,415 1,442 Mississippi ........... 1,360 210 -- -- New Mexico ............ -- -- 151,442 66,634 Offshore Gulf of Mexico 92,232 42,471 28,768 11,671 Oklahoma .............. 37,440 5,336 -- -- Texas ................. 220,197 139,346 71,268 30,761 Wyoming ............... 13,440 927 -- -- ------- ------- ------- ------- Total ....... 462,050 261,228 268,251 119,707 ======= ======= ======= ======= 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 gas prices. A portion of the natural gas production from our Double A Wells field is sold under a long-term contract to Houston Pipe Line Company LP, a subsidiary of American Electric Power Company, Inc. ("HPL"). The contract with HPL expires on October 31, 2004 with pricing based on spot natural gas prices for natural gas delivered to the Houston Ship Channel. Total natural gas sales in 2002 to HPL accounted for approximately 15% of our total 2002 oil and gas sales. Reliant Energy Services, Inc. ("Reliant") is another significant purchaser of our natural gas production accounting for approximately 16% of our total 2002 oil and gas sales. We discontinued sales to Reliant beginning in November 2002. 15 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 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. We provide reserves for the estimated costs of plugging and abandoning our wells, to the extent such costs exceed the estimated salvage value of the wells, on a unit of production basis. 16 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 its 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 hydrocarbons or hazardous substances into the environment could subject us to substantial expense, including the cost to comply with applicable regulations that require a response to the discharge, such as containment or cleanup, claims by neighboring landowners or other third parties for personal injury, property damage or their response costs and penalties assessed, or other claims sought, by regulatory agencies for response cost or for natural resource damages. 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. 17 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 (the "EPA") 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 its ordinary operations, we may have managed substances that may fall within Superfund's definition of a "hazardous substance." Therefore, we may be jointly and severally liable under the Superfund for all or part of the costs required to clean up sites where we disposed of or arranged for the disposal of these substances. This potential liability extends to properties that we previously owned or operated, as well as to properties owned and operated by others at which disposal of our hazardous substances occurred. 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. 18 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. We lease office space in Frisco, Texas covering 20,046 square feet at a monthly rate of $34,706. The lease expires on May 31, 2006. In addition to our leased office space in Frisco, Texas, we leased 2,329 square feet of office space in Houston, Texas at a monthly rate of $3,299 beginning April 1, 2003. This lease expires on March 31, 2007. We also have a lease for office space formally used by DevX Energy, Inc. The lease covers 9,573 square feet at a monthly rate of $19,458. This lease expires on December 3, 2003. We also own production offices and pipe yard facilities near Marshall and Livingston, Texas, near Logansport, Louisiana and near Guston, Kentucky. Employees As of December 31, 2002, we had 62 employees and utilized contract employees for certain of our field operations. We consider our employee relations to be satisfactory. Directors, Executive Officers and Other Management The following table sets forth certain information concerning our executive officers and directors. Name Age Position with Company - ----------------------- ------- ----------------------------------------- M. Jay Allison......... 47 President, Chief Executive Officer and Chairman of the Board of Directors Roland O. Burns........ 43 Senior Vice President, Chief Financial Officer, Secretary, Treasurer and Director Mack D. Good........... 52 Vice President of Operations Stephen E. Neukom...... 53 Vice President of Marketing Richard G. Powers...... 48 Vice President of Land Daniel K. Presley...... 42 Vice President of Accounting and Controller Michael W. Taylor...... 50 Vice President of Corporate Development David K. Lockett....... 48 Director Cecil E. Martin, Jr.... 61 Director David W. Sledge........ 46 Director 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. 19 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. 20 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. 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. ITEM 3. LEGAL PROCEEDINGS We are not a party to any legal proceedings which management believes will have a material adverse effect on our consolidated results of operations or financial condition. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS No matters were submitted to a vote of our security holders during the fourth quarter of 2002. 21 PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS Our common stock is listed for trading on the New York Stock Exchange under the symbol "CRK." The following table sets forth, on a per share basis for the periods indicated, the high and low sales prices by calendar quarter for the periods indicated as reported by the New York Stock Exchange. High Low -------- -------- 2001 - First Quarter................. $ 14.63 $ 9.65 Second Quarter................ 12.48 8.95 Third Quarter................. 10.12 5.00 Fourth Quarter................ 8.15 5.26 2002 - First Quarter................. $ 7.95 $ 5.70 Second Quarter................ 9.47 6.65 Third Quarter................. 8.10 5.50 Fourth Quarter................ 9.74 6.61 As of March 26, 2003, we had 28,934,561 shares of common stock outstanding, which were held by 472 holders of record and approximately 6,000 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, the terms of the indenture for our senior notes due in 2007 and the terms of our 1999 Series A Preferred Stock from paying or declaring cash dividends. The following table summarizes securities issuable and authorized by the stockholders under certain equity compensation plans: Number of securities Weighted average Number of securities to be issued upon exercise price of authorized for future exercise of outstanding issuance under equity outstanding options options compensation plans ------------------- ------------------ ---------------------- Equity compensation plans approved by stockholders 4,170,525 $8.18 352,786 (1) - ---------- (1) Plus 1% of the outstanding shares of common stock each year beginning on January 1, 2003. 22 ITEM 6. SELECTED FINANCIAL DATA The historical financial data presented in the table below as of and for each of the years in the five-year period ended December 31, 2002 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." Our consolidated financial statements as of and for the four years ended December 31, 2001, have been restated. For a further discussion of the restatement, see "Management's Discussion and Analysis of Financial Condition and Results of Operations-- Restatement of Previously Issued Financial Statements," and our audited consolidated financial statements and notes thereto, including Note 13. Statement of Operations Data: Year Ended December 31, ------------------------------------------------------------- 1998 1999 2000 2001 2002 ---------- ---------- ---------- ---------- ---------- (Restated) (Restated) (Restated) (Restated) (Unaudited) (Unaudited) (In thousands, except per share data) Oil and gas sales ............................ $ 91,373 $ 88,833 $ 168,084 $ 166,118 $ 142,085 Operating expenses: Oil and gas operating (1) ................. 23,971 23,117 29,277 31,855 33,499 Exploration ............................... 8,901 2,248 3,505 6,611 5,479 Depreciation, depletion and amortization .. 50,301 44,801 44,472 48,790 54,405 Impairment ................................ 16,942 -- -- 1,400 -- General and administrative, net ........... 1,617 2,399 3,537 4,351 5,113 --------- -------- --------- --------- --------- Total operating expenses ............. 101,732 72,565 80,791 93,007 98,496 --------- -------- --------- --------- --------- Income (loss) from operations ................ (10,359) 16,268 87,293 73,111 43,589 Other income (expenses): Interest income ........................... 201 134 230 196 62 Interest expense .......................... (16,977) (23,361) (24,611) (20,737) (30,002) Gain (loss) from derivatives .............. -- -- -- 243 (2,326) Other income .............................. 73 1,907 122 272 8,027 --------- -------- --------- --------- --------- (16,703) (21,320) (24,259) (20,026) (24,239) --------- -------- --------- --------- --------- Income (loss) from continuing operations before income taxes expense ............ (27,062) (5,052) 63,034 53,085 19,350 Income tax benefit (expense) ................. 9,471 1,769 (22,061) (18,579) (6,773) --------- -------- --------- --------- --------- Net income (loss) from continuing operations . (17,591) (3,283) 40,973 34,506 12,577 Discontinued operations including loss on disposal, net of income taxes ............. 33 197 227 396 (1,072) --------- -------- --------- --------- --------- Net income (loss) ............................ (17,558) (3,086) 41,200 34,902 11,505 Preferred stock dividends .................... -- (1,853) (2,471) (1,604) (1,604) --------- -------- --------- --------- --------- Net income (loss) attributable to common stock $ (17,558) $ (4,939) $ 38,729 $ 33,298 $ 9,901 ========= ======== ========= ========= ========= Net income (loss) per share from continuing operations: Basic ..................................... $ (0.72) $ (0.21) $ 1.46 $ 1.13 $ 0.38 ========= ======== ========= ========= ========= Diluted.................................... $ 1.20 $ 1.00 $ 0.37 ========= ========= ========= Net income (loss) per share: Basic...................................... $ (0.72) $ (0.20) $ 1.47 $ 1.15 $ 0.34 ========= ======== ========= ========= ========= Diluted.................................... $ 1.20 $ 1.01 $ 0.34 ========= ========= ========= Weighted average shares outstanding: Basic...................................... 24,275 24,601 26,290 29,030 28,764 ========== ========= ========= ========= ========= Diluted.................................... 34,219 34,552 33,901 ========= ========= ========= - ------------------------- (1) Includes lease operating costs and production and ad valorem taxes. 23 Balance Sheet Data: As of December 31, ----------------------------------------------------- 1998 1999 2000 2001 2002 -------- -------- -------- --------- --------- (Restated) (Restated) (Restated) (Restated) (Unaudited) (Unaudited) (Unaudited) (In thousands) Cash and cash equivalents ............ $ 5,176 $ 7,648 $ 7,105 $ 6,122 $ 1,682 Property and equipment, net .......... 403,652 394,497 434,065 636,274 664,208 Total assets ......................... 429,307 433,956 489,082 680,769 711,053 Total debt ........................... 278,104 254,131 234,101 372,464 366,272 Redeemable convertible preferred stock -- 30,000 17,573 17,573 17,573 Stockholders' equity ................. 109,273 106,512 161,735 195,668 208,427 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Restatement of Previously Issued Financial Statements Subsequent to the issuance of our Annual Report for the year ended December 31, 2001, we determined that certain outstanding advances made by us to our partner under our joint exploration venture in the Gulf of Mexico for seismic data acquisition should have been charged to exploration expense rather than reflected on the balance sheet as an asset. As a result of changing our accounting treatment for the advances used for seismic data acquisition, we determined that our financial statements for 1998, 1999, 2000 and 2001 should be restated. The effect of the restatement is a reduction to previously reported net income by $0.4 million, $0.3 million, $0.2 million and $1.6 million for the years 1998, 1999, 2000 and 2001, respectively, as a result of the additional exploration expense in each year. These changes primarily affect the timing of our recognition of exploration expense. As reimbursements are received for the advances we have made, our future exploration expense will be reduced. In addition, we have reclassified our Series 1999 Preferred Stock from stockholder's equity at December 31, 2001 to temporary equity. The adjustments to previously reported net income relating to the restatement are summarized in the following table: Year Ended December 31, --------------------------------------------- 1998 1999 2000 2001 -------- -------- -------- -------- (In thousands) Net income (loss) attributable to common stock as previously reported $(17,168) $ (4,669) $ 38,932 $ 34,854 Adjustment to exploration expense (600) (416) (313) (2,396) Income tax effect .................. 210 146 110 840 -------- -------- -------- -------- Net income (loss) attributable to common stock as restated........... $(17,558) $ (4,939) $ 38,729 $ 33,298 ======== ======== ======== ======== 24 The following balance sheet accounts as of December 31, 2001 were affected by the restatement: Year Ended December 31, 2001 -------------------------- Previously Reported Restated ----------- ----------- (In thousands) Unevaluated oil and gas properties ................. $ 13,416 $ 11,609 Oil and gas properties ............................. 901,206 900,711 Net property and equipment ......................... 638,576 636,274 Total assets ....................................... 683,071 680,769 Accounts payable and accrued expenses .............. 37,389 38,812 Total current liabilities .......................... 38,416 39,839 Deferred taxes payable ............................. 47,911 46,607 Retained earnings .................................. 54,183 51,762 Redeemable preferred stock ......................... -- 17,573 Total stockholders' equity ......................... 215,662 195,668 Total liabilities and stockholders' equity ......... 683,071 680,769 The following presents the impact of the restatement on the operating results and cash flows for the years ended December 31, 2000 and 2001: Year Ended Year Ended December 31, 2000 December 31, 2001 ---------------------- --------------------- Previously Previously Reported (1) Restated Reported (1) Restated ----------- ---------- ----------- --------- (In thousands, except per share amounts) Exploration expense ............................ $ 3,192 $ 3,505 $ 4,215 $ 6,611 Total operating expenses ....................... 80,478 80,791 90,611 93,007 Income from continuing operations before income taxes ......................... 63,347 63,034 55,481 53,085 Income tax expense ............................. (22,171) (22,061) (19,419) (18,579) Net income from continuing operations .......... 41,176 40,973 36,062 34,506 Net income ..................................... 41,403 41,200 36,458 34,902 Net income attributable to common stock ........ 38,932 38,729 34,854 33,298 Net income per share from continuing operations: Basic...................................... $1.48 $1.46 $1.20 $1.13 Diluted.................................... $1.21 $1.20 $1.06 $1.00 Net income per share: Basic...................................... $1.48 $1.47 $1.20 $1.15 Diluted.................................... $1.21 $1.20 $1.06 $1.01 Net cash provided by operating activities....... $104,556 $105,073 $ 110,090 $ 108,636 Net cash used for investing activities.......... $(83,361) $(83,878) $(189,601) $(188,147) 25 The following presents the impact related to the restatement on the quarterly results for the year ended December 31, 2001: Three Months Ended March 31, 2001 --------------------------------------- Previously Reported (1) Adjustment Restated ----------- ------------ ----------- (In thousands, except per share amounts) Exploration expense ......................... $ 2,831 $ 1,053 $ 3,884 Total expenses .............................. 30,485 1,053 31,538 Income from continuing operations before income taxes ...................... 36,572 (1,053) 35,519 Income tax expense .......................... (12,800) 369 (12,431) Net income from continuing operations ....... 23,772 (684) 23,088 Net income .................................. 23,974 (684) 23,290 Net income attributable to common stock ..... 23,578 (684) 22,894 Net income per share from continuing operations: Basic................................... $0.82 ($0.02) $0.80 Diluted................................. $0.68 ($0.02) $0.66 Net income per share: Basic................................... $0.83 ($0.02) $0.81 Diluted................................. $0.68 ($0.02) $0.66 Three Months Ended June 30, 2001 -------------------------------------- Previously Reported (1) Adjustment Restated ----------- ------------ ---------- (In thousands, except per share amounts) Exploration expense.......................... $ 477 $ 782 $ 1,259 Total expenses............................... 26,601 782 27,383 Income from continuing operations before income taxes....................... 19,517 (782) 18,735 Income tax expense........................... (6,831) 274 (6,557) Net income from continuing operations........ 12,686 (508) 12,178 Net income................................... 12,838 (508) 12,330 Net income attributable to common stock...... 12,438 (508) 11,930 Net income per share from continuing operations: Basic................................... $0.42 ($0.02) $0.40 Diluted................................. $0.36 ($0.02) $0.34 Net income per share: Basic................................... $0.43 ($0.02) $0.41 Diluted................................. $0.37 ($0.02) $0.35 Three Months Ended September 30, 2001 ---------------------------------------- Previously Reported (1) Adjustment Restated ----------- ------------ ------------ (In thousands, except per share amounts) Exploration expense.......................... $ 63 $ (82) $ (19) Total expenses............................... 25,061 (82) 24,979 Income from continuing operations before income taxes....................... 4,357 82 4,439 Income tax expense........................... (1,525) (29) (1,554) Net income from continuing operations........ 2,832 53 2,885 Net income................................... 2,890 53 2,943 Net income attributable to common stock...... 2,486 53 2,539 Net income per share from continuing operations: Basic................................... $0.08 $0.00 $0.08 Diluted................................. $0.08 $0.00 $0.08 Net income per share: Basic................................... $0.09 $0.00 $0.09 Diluted................................. $0.09 $0.00 $0.09 - ------------ (1) Previously reported amounts have been adjusted for the effects of discontinued operations. 26 Results of Operations Our operating data for the last three years is summarized below: Year Ended December 31, ---------------------------------- 2000 2001 2002 -------- -------- -------- Net Production Data: Oil (MBbls) ....................... 1,792 1,510 1,303 Natural gas (MMcf) ................ 26,799 27,859 33,171 Natural gas equivalent (MMcfe) .... 37,548 36,918 40,986 Average Sales Price: Oil (MBbls) ....................... $ 30.04 $ 25.46 $ 24.95 Natural gas (MMcf) ................ 4.26 4.58 3.30 Average equivalent price (per Mcfe) 4.48 4.50 3.47 Expenses ($ per Mcfe): Oil and gas operating(1) .......... $ 0.78 $ 0.86 $ 0.82 General and administrative ........ 0.09 0.12 0.12 Depreciation, depletion and amortization(2) ................ 1.14 1.28 1.29 Cash Margin ($ per Mcfe)(3) ........... $ 3.61 $ 3.52 $ 2.53 - ----------- (1)Includes lease operating costs and production and ad valorem taxes. (2)Represents depreciation, depletion and amortization of oil and gas properties only. (3)Represents average equivalent price per Mcfe less oil and gas operating expenses per Mcfe and general and administrative expenses per Mcfe. Year Ended December 31, 2002 Compared to Year Ended December 31, 2001 Our oil and gas sales decreased $24.0 million or 14% in 2002 to $142.1 million from $166.1 million in 2001. The decrease in sales is mostly due to the lower natural gas prices in 2002. Our average natural gas price decreased by 28% and our average oil price decreased by 2%. On an equivalent unit basis, our average price received for our production in 2002 was $3.47 per Mcfe, which was 23% lower than our average price in 2001 of $4.50 per Mcfe. Our average natural gas price in 2002 was $0.04 higher as a result of gains from hedging activities. Without the hedging gains, our natural gas price would have averaged $3.26 in 2002. The lower prices were partially offset by an 11% increase in production. Our natural gas production was up 19% while our oil production fell by 14%. The natural gas production increase is related to our acquisition of DevX Energy, Inc. which we completed in December 2001. The oil production decrease was due to normal depletion of our oil properties. Our oil and gas operating expenses, which includes production taxes, increased $1.6 million or 5%, to $33.5 million in 2002 from $31.9 million in 2001. The increase is due to the higher production level in 2002. Our oil and gas operating expenses per equivalent Mcf produced decreased by $0.04 to $0.82 in 2002 from $0.86 for 2001. The decrease in per unit lifting costs is primarily related to lower production taxes resulting from the lower oil and natural gas prices in 2002. 27 In 2002, we had $5.5 million in exploration expense, which primarily related to the write-off of four exploratory dry holes. Exploration expense for 2001 was $6.6 million (as restated) which related to the write-off of three dry holes and the expensing of $2.4 million in advances made by us to our joint venture partner for seismic data acquisition. Our depreciation, depletion and amortization increased $5.6 million (12%) to $54.4 million in 2002 from $48.8 million in 2001. The increase is attributable to our higher production level in 2002. Our depreciation, depletion and amortization per equivalent Mcf produced increased to $1.29 in 2002 from $1.28 in 2001. Our general and administrative expenses, which are reported net of overhead reimbursements that we receive, increased $762,000 or 18%, to $5.1 million in 2002 from $4.4 million in 2001. The increase was primarily due to an increase in the number of employees and higher compensation paid to our employees in 2002. Our interest expense increased $9.3 million or 45% to $30.0 million in 2002 from $20.7 million for 2001. The increase is due to the higher debt level we had as a result of the acquisition of DevX Energy, Inc. in December 2001. In addition, in March 2002 we issued an additional $75.0 million of our 11 1/4% Senior Notes which refinanced amounts that were borrowed under our bank credit facility. In 2002, we averaged $172.0 million outstanding under our bank credit facility at a weighted average interest of 3.6%. In 2001, our average outstanding balance was $65.2 million under the bank credit facility with a weighted average interest rate of 5.6%. Our other income in 2002 increased to $8.0 million from $272,000 in 2001. Included in other income in 2002 was $7.7 million related to refunds of severance taxes paid in prior years. For 2002 we reported net income from continuing operations of $11.0 million, after deducting preferred stock dividends of $1.6 million. These results compared to net income in 2001 of $32.9 million (as restated), after deducting preferred stock dividends of $1.6 million. Our income from continuing operations per share for 2002 was $0.37 on diluted weighted average shares outstanding of 33.9 million as compared to net income from continuing operations per share of $1.00 (as restated) for 2001 on diluted weighted average shares outstanding of 34.6 million. In April 2002 and July 2002, we sold certain oil and gas properties, which resulted in a loss of $1.8 million. The operating results of these properties have been reflected as discontinued operations in the consolidated financial statements including the losses on disposal. Year Ended December 31, 2001 Compared to Year Ended December 31, 2000 Our oil and gas sales decreased $2.0 million or 1% in 2001 to $166.1 million from $168.1 million in 2000. The slight decrease in sales is due to a 2% decrease in our oil and natural gas production in 2001. Our oil production in 2001 decreased by 16% and natural gas production increased by 4%. Our average oil price in 2001 decreased by 15% which was offset by a 8% increase to our average natural gas price. On an equivalent unit basis, our average price received for our production in 2001 was $4.50 per Mcfe, 1% higher than our average price in 2000 of $4.48 per Mcfe. Our oil and gas operating expenses, which includes production taxes, increased $2.6 million or 9%, to $31.9 million in 2001 from $29.3 million in 2000. Our oil and gas operating expenses per equivalent Mcf produced increased by $0.08 to $0.86 in 2001 from $0.78 for 2000. The increase is due to higher field level operating costs including additional treating fees paid in 2001 to process our Btu rich natural gas. 28 In 2001, we had $6.6 million (as restated) in exploration expense which represents the write-off of three offshore exploratory dry holes and the expensing of $2.4 million in advances made by us to our joint venture partner for seismic data acquisition. Exploration expense for 2000 was $3.5 million (as restated) which primarily related to the write-off of five dry holes. Our depreciation, depletion and amortization increased $4.3 to $48.8 million in 2001 from $44.5 million in 2000. The increase is attributable to higher capitalized costs on our properties which increased our amortization rate in 2001. Our depreciation, depletion and amortization per equivalent Mcf produced increased to $1.28 in 2001 from $1.14 in 2000. Our general and administrative expenses, which are reported net of overhead reimbursements that we receive, increased $814,000 or 23%, to $4.4 million in 2001 from $3.5 million in 2000. The increase was primarily due to an increase in the number of employees and higher compensation paid to our employees in 2001. Our interest expense decreased $3.9 million or 16% to $20.7 million in 2001 from $24.6 million for 2000. The decrease is due to lower average borrowings outstanding under our bank credit facility as well as a lower average interest rate under the bank credit facility. In 2001, we had a $65.6 million average outstanding balance under the bank credit facility at a weighted average interest of 5.6%. In 2000, our average outstanding balance was $104.2 million under the bank credit facility with a weighted average interest rate 6.9%. We reported net income from continuing operations of $32.9 million (as restated), after deducting preferred stock dividends of $1.6 million, in 2001. These results compared to net income from continuing operations of $38.5 million (as restated), after deducting preferred stock dividends of $2.5 million, in 2000. Our income from continuing operations per share for 2001 was $1.00 (as restated) on diluted weighted average shares outstanding of 34.6 million as compared to net income from continuing operations per share of $1.20 (as restated) for 2000 on diluted weighted average shares outstanding of 34.2 million. Liquidity and Capital Resources Funding for our activities has historically been provided by our operating cash flow, debt or equity financings or asset dispositions. In 2002, our net cash flow provided by operating activities totaled $79.3 million. Our other primary funding source in 2002 were proceeds from the sale of $75.0 million of our senior notes and borrowings of $31.0 million under our bank credit facility. Our primary needs for capital, in addition to funding our ongoing operations, relate to the acquisition, development and exploration of our oil and gas properties and the repayment of our debt. In 2002, we incurred capital expenditures of $83.4 million for development and exploration activities and for the acquisitions. We also repaid $112.9 million of our long-term debt. 29 Our annual capital expenditure activity is summarized in the following table: Year Ended December 31, ---------------------------- 2000 2001 2002 ------- -------- ------- (In thousands) Acquisitions of proved oil and gas properties . $ 9,684 $160,794 $11,435 Acquisitions of unproved oil and gas properties 5,863 7,113 4,268 Developmental leasehold costs ................. 1,618 974 98 Workovers and recompletions ................... 10,252 5,563 7,414 Offshore production facilities ................ 1,629 907 4,867 Development drilling .......................... 35,047 43,646 22,893 Exploratory drilling .......................... 19,202 33,382 31,074 Other ......................................... 616 172 1,332 ------- -------- ------- Total ..................................... $83,911 $252,551 $83,381 ======= ======== ======= 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 $73.6 million, $91.6 million and $70.6 million on development and exploration activities in 2000, 2001 and 2002, respectively. We have budgeted approximately $100.0 million for development and exploration projects in 2003. 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 $9.7 million, $160.8 million and $11.4 million on acquisition activities in 2000, 2001 and 2002, respectively. We do not have a specific acquisition budget for 2003 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. We entered into a $350.0 million revolving credit facility on December 17, 2001 with Toronto Dominion (Texas), Inc. as administrative agent. The bank credit facility is a three year revolving credit line with a current borrowing base of $240.0 million. Indebtedness under the bank credit facility is secured by substantially all of our assets. All of our subsidiaries are guarantors of this indebtedness. The revolving credit line 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 gas properties. The borrowing base may be affected by the performance of our properties and changes in oil and gas prices. The determination of the borrowing base is at the sole discretion of the administrative agent and the bank group. The revolving credit line bears interest, based on the utilization of the borrowing base, at our option at either (i) LIBOR plus 1.5% to 2.375% or (ii) the corporate base rate (generally the federal funds rate plus 0.5%) plus 0.5% to 1.375%. The bank credit facility matures on January 2, 2005 and contains covenants that, among other things, restrict our ability to pay cash dividends, limit the amount of our consolidated debt and limit our ability to make certain loans and investments. Financial covenants include the maintenance of a current ratio, maintenance of tangible net worth and maintenance of an interest coverage ratio. 30 On March 7, 2002, we closed the sale in a private placement of $75.0 million of our 11 1/4% senior notes due 2007 at a net price of 97.25% after the placements agents' discount. As a result of this transaction, $220.0 million of aggregate principal amount of our senior notes are outstanding. The net proceeds were used to reduce amounts outstanding under our bank credit facility. These notes are unsecured obligations of Comstock and are guaranteed by all of our subsidiaries. On July 19, 2002, we filed a registration statement on Form S-4 to register the $75.0 million of these notes for resale. This registration statement was declared effective by the SEC on August 5, 2002. The following table summarizes our aggregate liabilities and commitments by year of maturity: 2003 2004 2005 2006 2007 2008 Total -------- -------- -------- --------- --------- -------- -------- (In thousands) Bank credit facility ... $ -- $ -- $146,000 $ -- $ -- $ -- $146,000 Senior notes ........... -- -- -- -- 220,000 -- 220,000 Other debt ............. 270 -- -- -- -- 2 272 Operating leases ....... 656 452 477 198 -- -- 1,783 Derivative liabilities . 57 -- -- -- -- -- 57 Preferred stock (1) .... -- -- 5,858 5,858 5,857 -- 17,573 -------- -------- -------- -------- -------- -------- -------- $ 983 $ 452 $152,335 $ 6,056 $225,857 $ 2 $385,685 ======== ======== ======== ======== ======== ======== ======== - ------------ (1) Represents the redemption of our Series A 1999 Convertible Preferred Stock, which at our option, can be paid in shares of our common stock. 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. Federal Taxation At December 31, 2002, we had federal income tax net operating loss carryforwards of approximately $123.0 million. We have established a $23.0 million valuation allowance against part of the net operating loss carryforwards acquired from DevX Energy, Inc. due to a "change in control" limitation which will prevent us from fully realizing these carryforwards. The carryforwards expire from 2018 through 2022. 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. We are also 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 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 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. 31 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. There are numerous uncertainties inherent in estimating oil and natural gas reserves and their values, including many factors beyond our control. 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 estimate. Accordingly, reserve estimates are often different from the quantities of oil and gas reserves that are ultimately recovered. The estimates of our proved oil and gas reserves used in preparation of our 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"). The determination of impairment of our oil and gas reserves is based on the oil and gas reserve estimates using projected future oil and natural gas prices that we have determined to be reasonable. The projected prices that we employ represent our long- term oil and natural gas price forecast and may be higher or lower than current 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, 2002, we used an initial oil price of $30.00 per barrel and an initial natural gas price of $5.00 per Mcf. Such prices were reduced to $25.00 per barrel for oil and $4.00 per Mcf for gas in the second year and escalated each year thereafter to a maximum price of $40.00 per barrel for oil and $5.00 per Mcf for natural gas. To the extent we had used lower prices in our impairment review, an impairment could have been indicated on certain of our oil and gas properties. New Accounting Standards In August 2001, the FASB issued Statement of Financial Accounting Standards No. 143 ("SFAS 143") "Accounting for Asset Retirement Obligations," which we adopted effective January 1, 2003. This statement requires us to record a liability in the period in which an asset retirement obligation ("ARO") is incurred. Upon recognition of an ARO liability, additional asset cost would be capitalized to equal the amount of the liability. Upon the initial adoption of SFAS 143, we recognized a liability for any existing AROs not already provided for in our reserve for future abandonment costs. We also recognized additional capitalized cost related to the additional liability and accumulated depreciation on the additional capitalized cost. Under SFAS 143, we estimate that our total ARO for our oil and natural gas properties is approximately $15.2 million which was $1.5 million less than the liability that we had provided for in our reserve for future abandonment as of December 31, 2002. The impact of adopting SFAS 143, which will be recorded as the cumulative effect of an accounting change was an increase to net income of approximately $0.7 million, net of tax. In June 2002, the FASB issued Statement of Financial Accounting Standards 146, "Accounting for Costs Associated with Exit or Disposal Activities" ("SFAS 146"). The Statement establishes accounting and reporting standards that are effective for exit or disposal activities beginning after December 31, 2002 which require that a liability be recognized for an exit or disposal activity when that liability is incurred. We have not determined the effect, if any, that the adoption of SFAS 146 will have on our financial statements. In January 2003, the FASB issued Interpretation ("FIN") No. 45, "Guarantor's Accounting and Disclosure Requirement for Guarantees, including Indirect Guarantees of Indebtedness of Others." FIN 45 requires an entity to recognize a liability for the obligations it has undertaken in issuing a guarantee. This liability would be recorded at the inception of a guarantee and 32 would be measured at fair value. Certain guarantees are excluded from the measurement and disclosure provisions while certain other guarantees are excluded from the measurement provisions of the interpretation. The measurement provisions of this statement apply prospectively to guarantees issued or modified after December 31, 2002. The disclosure provisions of the statement apply to financial statements for periods ending after December 15, 2002. The adoption of the statement is not expected to have a material effect on our financial statements when adopted. In January 2003, the FASB issued Interpretation No. 46, "Consolidation of Variable Interest Entities." FIN 46 requires an entity to consolidate a variable interest entity if it is designated as the primary beneficiary of that entity even if the entity does not have a majority of voting interests. A variable interest entity is generally defined as an entity where its equity is unable to finance its activities or where the owners of the entity lack the risk and rewards of ownership. The provisions of this statement apply at inception for any entity created after January 31, 2003. For an entity created before February 1, 2003, the provisions of this interpretation must be applied at the beginning of the first interim or annual period beginning after June 15, 2003. Comstock is not the primary beneficiary of any variable interest entities, and accordingly, the adoption of FIN 46 is not expected to have a material effect on our financial statements when adopted. Related Party Transactions In recent years we have not entered into any material transactions with our officers or directors apart from the compensation they are provided for their services. We also have not entered into any business transactions with our significant stockholders or any other related parties. ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISKS Oil and Natural Gas Prices Our financial condition, results of operations and capital resources are highly dependent upon the prevailing market prices of oil and natural gas. These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond our control. Factors influencing oil and natural gas prices include the level of global demand for crude oil, the foreign supply of oil and natural gas, the establishment of and compliance with production quotas by oil exporting countries, weather conditions which determine the demand for natural gas, the price and availability of alternative fuels and overall economic conditions. It is impossible to predict future oil and natural gas prices with any degree of certainty. Sustained weakness in oil and natural gas prices may adversely affect our financial condition and results of operations, and may also reduce the amount of oil and natural gas reserves that we can produce economically. Any reduction in our oil and natural gas reserves, including reductions due to price fluctuations, can have an adverse affect on our ability to obtain capital for our exploration and development activities. Similarly, any improvements in oil and natural gas prices can have a favorable impact on our financial condition, results of operations and capital resources. Based on our oil and natural gas production in 2002, 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 $1.2 million and a $1.00 change in the price per Mcf of natural gas would have changed our cash flow by approximately $31.8 million. We periodically use hedging transactions with respect to a portion of our oil and natural gas production to mitigate our exposure to price changes. While the use of these hedging 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 33 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 hedge. 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 cap. The following table sets out the derivative financial instruments outstanding at December 31, 2002 which are held for natural gas price risk management: Volume Type Floor Period Beginning Period Ending (MMBtu) of Instrument Price - ----------------- ----------------- ----------- -------------- ---------- January 1, 2003 December 31, 2003 2,250,000 Floor $2.00 The fair value of the commodity price derivative financial instruments at December 31, 2002 was a net asset of $3,000. In 2002, we hedged a portion of our natural gas production for the period April 2002 through October 2002, in order to increase the predictability of our cash flow from operations in order to support our 2002 drilling program. We entered into price swaps covering 50 MMBtus per day of our natural gas production at an average price of $3.46 for April 2002 to October 2002. We realized a $1.3 million gain on this hedge position in 2002, which was included in oil and gas sales and increased our average natural gas price realization from $3.26 per Mcf to $3.30 per Mcf. Interest Rates At December 31, 2002, we had long-term debt of $366.0 million. Of this amount, $220.0 million bears interest at a fixed rate of 11 1/4%. The fair market value of the fixed rate debt as of December 31, 2002 was $233.2 million based on the market price of 106% of the face amount. We had $146.0 million outstanding under our bank credit facility, which is subject to floating market rates of interest. Borrowings under the bank credit facility bear interest at a fluctuating rate that is tied to LIBOR or the corporate base rate, at our option. Any increases in these interest rates can have an adverse impact on our results of operations and cash flow. Based on borrowings outstanding at December 31, 2002, a 100 basis point change in interest rates would change our interest expense on our variable rate debt by approximately $1.5 million. From January 1, 2002 to April 30, 2002 we had an interest rate swap in place which fixed our LIBOR rate on $25.0 million of our floating rate debt at 4.5%. As a result of this interest rate swap, we realized a loss of $218,000 in 2002. In December 2002 we entered into an interest rate swap agreement to hedge the impact of interest rate changes on $25.0 million of our floating rate debt beginning on January 1, 2003 and expiring on December 31, 2003. This interest rate swap fixed LIBOR at 1.7%. The fair value of this interest rate derivative financial instrument was a net liability of $57,000 at December 31, 2002. 34 ITEM 8. FINANCIAL STATEMENTS Our consolidated financial statements are included on pages F-1 to F-29 of this report. We have prepared these financial statements in conformity with generally accepted accounting principles. We are responsible for the fairness and reliability of the financial statements and other financial data included in this report. In the preparation of the financial statements, it is necessary for us to make informed estimates and judgments based on currently available information on the effects of certain events and transactions. We maintain accounting and other controls which we believe provide reasonable assurances that our financial records are reliable, our assets are safeguarded, and that transactions are properly recorded in accordance with management's authorizations. However, limitations exist in any system of internal controls based upon the recognition that the cost of the system should not exceed benefits derived. Our independent public accountants, KPMG LLP, are engaged to audit our financial statements and to express an opinion thereon. Their audit is conducted in accordance with auditing standards generally accepted in the United States to enable them to report whether the financial statements present fairly, in all material respects, our financial position and results of operations in accordance with accounting principles generally accepted in the United States. The audit committee of our board of directors is composed of three directors who are not our employees. This committee meets periodically with our independent public accountants and management. Our independent public accountants have full and free access to the audit committee to meet, with and without management being present, to discuss the results of their audits and the quality of our financial reporting. ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE Our Audit Committee annually considers and recommends to our board of directors the selection of our independent public accountants. As recommended by the Audit Committee, on April 22, 2002, the board of directors decided to no longer engage Arthur Andersen LLP as our independent public accountants and engaged KPMG LLP to serve as our independent public accountants for 2002. Arthur Andersen LLP's reports on our consolidated financial statements for the past two years did not contain an adverse opinion or disclaimer of opinion, nor were they qualified or modified as to uncertainty, audit scope or accounting principles. During our two most recent fiscal years and through the date of their appointment, there were no disagreements with Arthur Andersen LLP on any matters of accounting principles or practices, financial statement disclosure, or auditing scope or procedure which, if not resolved to Arthur Andersen LLP's satisfaction, would have caused them to make reference to the subject matter in connection with their report on our consolidated financial statements for such years; and there were no reportable events, as listed in Item 304 (a) (l) (v) of Regulation S-K. During our two most recent fiscal years and through April 22, 2002, we did not consult KPMG LLP with respect to the application of accounting principles to a specified transaction, either completed or proposed, or the type of audit opinion that might be rendered on our consolidated financial statements, or any other matters or reportable events listed in Items 304 (a) (2) (i) and (ii) of Regulation S-K. 35 PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT The information required by this item is incorporated herein by reference to our definitive proxy statement which will be filed with the Securities and Exchange Commission within 120 days after December 31, 2002. ITEM 11. EXECUTIVE COMPENSATION The information required by this item is incorporated herein by reference to our definitive proxy statement which will be filed with the Securities and Exchange Commission within 120 days after December 31, 2002. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS The information required by this item is incorporated herein by reference to our definitive proxy statement which will be filed with the Securities and Exchange Commission within 120 days after December 31, 2002. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS The information required by this item is incorporated herein by reference to our definitive proxy statement which will be filed with the Securities and Exchange Commission within 120 days after December 31, 2002. ITEM 14. CONTROLS AND PROCEDURES Within 90 days prior to the date of this report, we carried out an evaluation, under the supervision and with the participation of the chief executive officer and chief financial officer, of the effectiveness of the design and operation of our disclosure controls and procedures. Based on this evaluation, the chief executive officer and chief financial officer concluded that our disclosure controls and procedures are effective in timely alerting them to material information required to be included in our periodic SEC reports. In addition, we reviewed our internal controls and there has been no significant changes in our internal controls or in other factors, including any corrective actions with regard to significant deficiencies and material weaknesses, that could significantly affect those controls subsequent to the date of their last evaluation. 36 PART IV ITEM 15. EXHIBITS AND REPORTS ON FORM 8-K Exhibits: The following exhibits are included this report. Exhibit No. Description - ------------ ----------------------------------------------------------------- 2.1 Agreement and Plan of Merger among Comstock, Comstock Holdings, Inc., Comstock Acquisition Inc. and DevX Energy, Inc. dated as of November 12, 2001 (incorporated by reference to Exhibit 2.1 to our Current Report on Form 8-K filed on November 13, 2001). 3.1(a) Restated Articles of Incorporation (incorporated by reference to Exhibit 3.1 to our Annual Report on Form 10-K for the year ended December 31, 1995). 3.1(b) Certificate of Amendment to the Restated Articles of Incorporation dated July 1, 1997 (incorporated herein by reference to Exhibit 3.1 to our Quarterly Report on Form 10-Q for the quarter ended June 30, 1997). 3.2 Bylaws (incorporated by reference to Exhibit 3.2 to our Registration Statement on Form S-3, dated October 25, 1996). 4.1 Rights Agreement dated as of December 14, 2000, by and between Comstock and American Stock Transfer and Trust Company, as Rights Agent (incorporated herein by reference to Exhibit 1 to our Registration Statement on Form 8-A dated January 11, 2001). 4.2 Certificate of Voting Powers, Designations, Preferences, and Relative, Participating, Optional or Other Special Rights of the Series A 1999 Convertible Preferred Stock and Series B 1999 Non-Convertible Preferred Stock (incorporated herein by reference to Exhibit 4.1 to our Current Report on Form 8-K dated April 29, 1999). 4.3* Articles of Amendment to the Certificate of Voting Powers, Designations, Preferences, and Relative, Participating, Optional or Other Special Rights of Series A 1999 Convertible Preferred Stock and Series B 1999 Non-Convertible Preferred Stock. 4.4 Stock Purchase Agreement dated April 29, 1999 between Comstock and certain purchasers (incorporated herein by reference to Exhibit 10.1 to our Current Report on Form 8-K dated April 29, 1999). 4.5 Certificate of Designation, Preferences and Rights of Series B Junior Participating Preferred Stock (incorporated herein by reference to Exhibit 2 to our Registration Statement on Form 8-A dated January 11, 2001). 4.6 Indenture dated April 29, 1999 between Comstock and U.S. Trust Company of Texas, N.A., Trustee for the 11 1/4% Senior Notes due 2007 (incorporated herein by reference to Exhibit 10.5 to our Current Report on Form 8-K dated April 29, 1999). 4.7 First Supplemental Indenture, dated March 7, 2002, by and between Comstock and U.S. Trust Company of Texas, N.A., Trustee for the 11 1/4% Senior Notes due 2007 (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K dated March 12, 2002). 10.1 Credit Agreement, dated as of December 17, 2001, by and among Comstock, as borrower, each lender from time to time party thereto, Toronto Dominion (Texas), Inc., as administrative agent, and Toronto-Dominion Bank, as Issuing Bank (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K dated December 21, 2001). 37 Exhibit No. Description - ------------ ----------------------------------------------------------------- 10.2 Amendment No.1 dated December 26, 2001 to the Credit Agreement, dated as of December 17, 2001, by and among Comstock, as borrower, each lender from time to time party thereto, Toronto Dominion (Texas), Inc., as administrative agent, and Toronto-Dominion Bank, as Issuing Bank (incorporated by reference to Exhibit 10.2 to our Annual Report on Form 10-K for the year ended December 31, 2001). 10.3 Amendment No. 2 dated February 4, 2002 to the Credit Agreement, dated as of December 17, 2001, by and among Comstock, as borrower, each lender from time to time party thereto, Toronto Dominion (Texas), Inc., as administrative agent, and Toronto-Dominion Bank, as Issuing Bank (incorporated by reference to Exhibit 10.3 to our Annual Report on Form 10-K for the year ended December 31, 2001). 10.4 Amendment No. 3 dated April 15, 2002 to the Credit Agreement, dated as of December 17, 2001, by and among Comstock, as borrower, each lender from time to time party thereto, Toronto Dominion (Texas), Inc., as administrative agent, and Toronto-Dominion Bank, as Issuing Bank (incorporated by reference to Exhibit 10.1 to our Quarterly Report for the quarter ended March 31, 2002). 10.5 Placement Agreement dated February 28, 2002, by and between Comstock and Morgan Stanley & Co. Incorporated, TD Securities (USA), inc. and BMO Nesbitt Burns Corp. (incorporated herein by reference to Exhibit 10.1 to our Current Report on Form 8-K filed on March 12, 2002). 10.6 Registration Rights Agreements dated March 7, 2002, by and between Comstock and Morgan Stanley & Co. Incorporated, TD Securities (USA), Inc. and BMO Nesbitt Burns Corp. (incorporated herein by reference to Exhibit 10.2 to our Current Report on Form 8-K filed on March 12, 2002). 10.7# Employment Agreement dated June 1, 2002, by and between Comstock and M. Jay Allison (incorporated herein by reference to Exhibit 10.1 to our Quarterly Report on Form 10-Q for the quarter ended June 30, 2002). 10.8# Employment Agreement dated June 1, 2002, by and between Comstock and Roland O. Burns (incorporated herein by reference to Exhibit 10.2 to our Quarterly Report on Form 10-Q for the quarter ended June 30, 2002). 10.9# Comstock Resources, Inc. 1999 Long-term Incentive Plan (incorporated herein by reference to Exhibit 10.1 to our Quarterly Report on Form 10-Q for the quarter ended June 30, 1999). 10.10# Form of Nonqualified Stock Option Agreement between Comstock and certain officers and directors of Comstock (incorporated herein by reference to Exhibit 10.2 to our Quarterly Report on Form 10-Q for the year ended June 30, 1999). 10.11# Form of Restricted Stock Agreement between Comstock and certain officers of Comstock (incorporated herein by reference to Exhibit 10.3 to our Quarterly Report on Form 10-Q for the quarter ended June 30, 1999). 10.12 Exploration Agreement dated July 31, 2001 by and between Comstock and Bois 'd Arc Offshore Ltd. (incorporated by reference to Exhibit 10.2 to our Quarterly Report on Form 10-Q for the quarter ended June 30, 2001). 10.13 Warrant Agreement dated July 31, 2001 by and between Comstock and Gary W. Blackie and Wayne L. Laufer (incorporated herein by reference to Exhibit 10.1 to our Quarterly Report on Form 10-Q for the quarter ended June 30, 2001). 10.14* Supplement to the 2001 Exploration Agreement dated December 20, 2002 by and between Comstock and Bois 'd Arc Offshore Ltd. 38 Exhibit No. Description - ------------ ----------------------------------------------------------------- 10.15 Office Lease Agreement dated August 12, 1997 between Comstock and Briar Center LLC (incorporated by reference to Exhibit 10.2 to our Quarterly Report on Form 10-Q for the quarter ended September 30, 1997). 16 Letter of Arthur Andersen LLP to the Securities and Exchange Commission dated April 26, 2002 (incorporated by reference to Exhibit 16 to our Current Report on Form 8-K dated April 22, 2002). 99.1* Certification for the Chief Executive Officer as required by Section 906 of the Sarbanes-Oxley Act of 2002. 99.2* Certification for the Chief Financial Officer as required by Section 906 of the Sarbanes-Oxley Act of 2002. 21* Subsidiaries of the Company. 23* Consent of KPMG LLP. - --------------- *Filed herewith. # Management contract or compensatory plan document. Reports on Form 8-K: Form 8-K Reports filed subsequent to September 30, 2002 are as follows: Date Item Description - ----------------- ---- ------------------------------------------------------ February 18, 2002 5 Operating results for the fourth quarter and year ended December 31, 2002 and restatement of previously reported financial results for years ended December 31, 1998, 1999, 2000 and 2001. March 21, 2003 5 Disclosure of the delivery of required notice to executive officers and directors under Regulation BTR. 39 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. COMSTOCK RESOURCES, INC. By:/s/ M. JAY ALLISON ---------------------- M. Jay Allison President and Chief Executive Officer Date: March 26, 2003 (Principal Executive Officer) Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. /s/ M. JAY ALLISON President, Chief Executive Officer and March 26, 2003 - ------------------ Chairman of the Board of Directors M. Jay Allison (Principal Executive Officer) /s/ ROLAND O. BURNS Senior Vice President, Chief Financial Officer, March 26, 2003 - ------------------- Secretary, Treasurer and Director Roland O. Burns (Principal Financial and Accounting Officer) /s/ DAVID K. LOCKETT Director March 26, 2003 - -------------------- David K. Lockett /s/ CECIL E. MARTIN, JR. Director March 26, 2003 - ----------------------- Cecil E. Martin, Jr. /s/ DAVID W. SLEDGE Director March 26, 2003 - ------------------- David W. Sledge 40 CERTIFICATIONS I, M. Jay Allison, Chief Executive Officer, certify that: 1. I have reviewed this annual report on Form 10-K of Comstock Resources, Inc.; 2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; 3. Based on my knowledge, the financial statements and other financial information included in this annual report, fairly present in all material respects the consolidated financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions): a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officer and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. Date: March 26, 2003 By: /s/ M. Jay ALLISON ------------------- M. Jay Allison, Chief Executive Officer 41 CERTIFICATIONS I, Roland O. Burns, Chief Financial Officer, certify that: 1. I have reviewed this annual report on Form 10-K of Comstock Resources, Inc.; 2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; 3. Based on my knowledge, the financial statements and other financial information included in this annual report, fairly present in all material respects the consolidated financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions): a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officer and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. Date: March 26, 2003 By: /s/ ROLAND O. BURNS ------------------- Roland O. Burns, Chief Financial Officer 42 CONSOLIDATED FINANCIAL STATEMENTS OF COMSTOCK RESOURCES, INC. AND SUBSIDIARIES INDEX Independent Auditors' Report................................................F-2 Consolidated Balance Sheets as of December 31, 2001 and 2002................F-3 Consolidated Statements of Operations for the Years Ended December 31, 2000, 2001 and 2002...................................F-4 Consolidated Statements of Stockholders' Equity and Comprehensive Income for the Years Ended December 31, 2000, 2001 and 2002..............F-5 Consolidated Statements of Cash Flows for the Years Ended December 31, 2000, 2001 and 2002..................................F-6 Notes to Consolidated Financial Statements..................................F-7 F-1 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Board of Directors of Comstock Resources, Inc.: We have audited the accompanying consolidated balance sheets of Comstock Resources, Inc. and subsidiaries as of December 31, 2001 and 2002, and the related consolidated statements of operations, stockholders' equity and comprehensive income, and cash flows for each of the three years in the period ended December 31, 2002. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Comstock Resources, Inc. and subsidiaries as of December 31, 2001 and 2002, and the results of their operations and their cash flows for each of the years in the three year period ended December 31, 2002, in conformity with accounting principles generally accepted in the United States of America. As explained in Note 1 of the financial statements effective January 1, 2001, the Company changed its method of accounting for derivative instruments. As discussed in Note 13 to the accompanying consolidated financial statements, the Company has restated the consolidated balance sheet as of December 31, 2001, and the related consolidated statements of operations, stockholders' equity and comprehensive income, and cash flows for the two year period then ended, which consolidated financial statements were previously audited by other independent auditors who have ceased operations. KPMG LLP Dallas, Texas March 19, 2003 F-2 COMSTOCK RESOURCES, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS As of December 31, 2001 and 2002 ASSETS December 31, ---------------------- 2001 2002 --------- --------- Restated (In thousands) Cash and Cash Equivalents ................................................. $ 6,122 $ 1,682 Accounts Receivable: Oil and gas sales ............................................... 20,015 30,135 Joint interest operations ....................................... 4,717 5,407 Derivatives ............................................................... 1,342 -- Other Current Assets ...................................................... 7,418 2,678 --------- --------- Total current assets ............................................ 39,614 39,902 Property and Equipment: Unevaluated oil and gas properties .............................. 11,609 14,880 Oil and gas properties, successful efforts method ............... 900,711 961,562 Other ........................................................... 2,633 2,570 Accumulated depreciation, depletion and amortization ............ (278,679) (314,804) --------- --------- Net property and equipment ...................................... 636,274 664,208 Derivatives ............................................................... 254 3 Other Assets .............................................................. 4,627 6,940 --------- --------- $ 680,769 $ 711,053 ========= ========= LIABILITIES AND STOCKHOLDERS' EQUITY Current Portion of Long-Term Debt ......................................... $ 229 $ 270 Accounts Payable and Accrued Expenses ..................................... 38,812 49,470 Derivatives ............................................................... 798 57 --------- --------- Total current liabilities ....................................... 39,839 49,797 Long-Term Debt, less current portion ...................................... 372,235 366,002 Deferred Taxes Payable .................................................... 46,607 52,577 Derivatives ............................................................... 1,053 -- Reserve for Future Abandonment Costs ...................................... 7,794 16,677 Redeemable Convertible Preferred Stock--$10.00 par, liquidation value of $17,573,000, 5,000,000 shares authorized, 1,757,310 shares issued and outstanding ...................................................... 17,573 17,573 Stockholders' Equity: Common stock--$0.50 par, 50,000,000 shares authorized, 28,552,553 and 28,919,561 shares issued and outstanding at December 31, 2001 and 2002, respectively ..................... 14,276 14,460 Additional paid-in capital ...................................... 130,956 133,828 Retained earnings ............................................... 51,762 61,663 Deferred compensation-restricted stock grants ................... (1,187) (1,487) Accumulated other comprehensive loss ............................ (139) (37) --------- --------- Total stockholders' equity ...................................... 195,668 208,427 --------- --------- $ 680,769 $ 711,053 ========= ========= The accompanying notes are an integral part of these statements. F-3 COMSTOCK RESOURCES, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS For the Years Ended December 31, 2000, 2001 and 2002 2000 2001 2002 --------- --------- --------- (Restated) (Restated) (In thousands, except per share amounts) Oil and gas sales ........................... $ 168,084 $ 166,118 $ 142,085 Operating expenses: Oil and gas operating .................. 29,277 31,855 33,499 Exploration ............................ 3,505 6,611 5,479 Depreciation, depletion and amortization 44,472 48,790 54,405 Impairment ............................. -- 1,400 -- General and administrative, net ........ 3,537 4,351 5,113 --------- --------- --------- Total operating expenses ...... 80,791 93,007 98,496 --------- --------- --------- Income from operations ...................... 87,293 73,111 43,589 Other income (expenses): Interest income ........................ 230 196 62 Interest expense ....................... (24,611) (20,737) (30,002) Gain (loss) from derivatives ........... -- 243 (2,326) Other income ........................... 122 272 8,027 --------- --------- --------- (24,259) (20,026) (24,239) --------- --------- --------- Income from continuing operations before income tax expense ....... 63,034 53,085 19,350 Income tax expense .......................... (22,061) (18,579) (6,773) --------- --------- --------- Net income from continuing operations ....... 40,973 34,506 12,577 Discontinued operations including loss on disposal, net of income taxes .......... 227 396 (1,072) --------- --------- --------- Net income .................................. 41,200 34,902 11,505 Preferred stock dividends ................... (2,471) (1,604) (1,604) --------- --------- --------- Net income attributable to common stock ..... $ 38,729 $ 33,298 $ 9,901 ========= ========= ========= Net income per share from continuing operations: Basic.......................... $ 1.46 $ 1.13 $ 0.38 ========= ========= ========= Diluted........................ $ 1.20 $ 1.00 $ 0.37 ========= ========= ========= Net income per share: Basic.......................... $ 1.47 $ 1.15 $ 0.34 ========= ========= ========= Diluted........................ $ 1.20 $ 1.01 $ 0.34 ========= ========= ========= Weighted average shares outstanding: Basic.......................... 26,290 29,030 28,764 ========= ========= ========= Diluted........................ 34,219 34,552 33,901 ========= ========= ========= The accompanying notes are an integral part of these statements. F-4 COMSTOCK RESOURCES, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY AND COMPREHENSIVE INCOME For the Years Ended December 31, 2000, 2001 and 2002 Deferred Accumulated Additional Retained Compensation Other Common Paid-In Earnings Restricted Comprehensive Stock Capital (Deficit) Stock Grants Loss Total --------- --------- --------- ------------ --------- -------- (In thousands) Balance at December 31, 1999... $ 12,688 $ 114,855 $ (19,603) $ (766) $ -- $ 107,174 Adjustment................... -- -- (662) -- -- (662) --------- --------- --------- --------- --------- -------- Balance at December 31, 1999 (Restated) 12,688 114,855 (20,265) (766) -- 106,512 Conversion of preferred stock.. 1,553 10,874 -- -- -- 12,427 Issuance of common stock....... 150 706 -- -- -- 856 Value of stock options issued for exploration prospects.. -- 2,990 -- -- -- 2,990 Restricted stock grants......... 28 471 -- (278) -- 221 Net income attributable to common stock (Restated).... -- -- 38,729 -- -- 38,729 --------- --------- --------- --------- --------- --------- Balance at December 31, 2000 (Restated) 14,419 129,896 18,464 (1,044) -- 161,735 --------- --------- --------- --------- --------- --------- Issuance of common stock...... 283 3,538 -- -- -- 3,821 Value of stock options issued for exploration prospects.. -- 1,968 -- -- -- 1,968 Restricted stock grants.......... 28 333 -- (143) -- 218 Repurchases of common stock...... (454) (4,779) (5,233) Net income attributable to common stock (Restated).... -- -- 33,298 -- -- 33,298 Unrealized hedge losses.......... -- -- -- -- (139) (139) --------- Comprehensive income (Restated). -- -- -- -- -- 33,159 --------- --------- --------- --------- --------- --------- Balance at December 31, 2001 (Restated) 14,276 130,956 51,762 (1,187) (139) 195,668 --------- --------- --------- --------- --------- --------- Issuance of common stock....... 156 1,547 -- -- -- 1,703 Value of stock options issued for exploration prospects.. -- 836 -- -- -- 836 Restricted stock grants.......... 28 489 -- (300) -- 217 Net income attributable to common stock............... -- -- 9,901 -- -- 9,901 Unrealized hedge gains........... -- -- -- -- 102 102 --------- Comprehensive income........... -- -- -- -- -- 10,003 --------- --------- --------- --------- --------- --------- Balance at December 31, 2002..... $ 14,460 $ 133,828 $ 61,663 $ (1,487) $ (37) $ 208,427 ========= ========= ========= ========= ========= ========= The accompanying notes are an integral part of these statements. F-5 COMSTOCK RESOURCES, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS For the Years Ended December 31, 2000, 2001 and 2002 2000 2001 2002 --------- --------- --------- (Restated) (Restated) (In thousands) CASH FLOWS FROM OPERATING ACTIVITIES: Net income ..................................................... $ 41,200 $ 34,902 $ 11,505 Adjustments to reconcile net income to net cash provided by operating activities, net of acquisition effects: Compensation paid in common stock ............................ 314 244 218 Depreciation, depletion and amortization ..................... 44,472 48,790 54,405 Impairment of oil and gas properties ......................... -- 1,400 -- Deferred income taxes ........................................ 22,061 17,799 6,773 Dry hole costs ............................................... 3,192 4,215 5,139 Gain on sales of property .................................... (33) (12) -- Unrealized gain on derivatives ............................... -- (254) (119) Non-cash effect of discontinued operations, net .............. 608 614 1,395 --------- --------- --------- Working capital provided by operations ..................... 111,814 107,698 79,316 Decrease (increase) in accounts receivable ..................... (15,596) 18,371 (10,810) Decrease (increase) in other current assets .................... (1,585) (1,229) 4,740 Increase (decrease) in accounts payable and accrued expenses ............................................. 10,440 (16,204) 11,191 --------- --------- --------- Net cash provided by operating activities .................. 105,073 108,636 84,437 --------- --------- --------- CASH FLOWS FROM INVESTING ACTIVITIES: Proceeds from sales of properties .............................. 33 45 3,478 Capital expenditures and acquisitions .......................... (83,911) (188,192) (83,381) --------- --------- --------- Net cash used for investing activities ..................... (83,878) (188,147) (79,903) --------- --------- --------- CASH FLOWS FROM FINANCING ACTIVITIES: Borrowings ..................................................... 18,408 261,730 31,736 Proceeds from senior notes offering ............................ -- -- 75,000 Debt issuance costs ............................................ -- -- (2,267) Principal payments on debt ..................................... (38,438) (178,355) (112,928) Proceeds from common stock issuances ........................... 763 1,989 1,089 Repurchases of common stock .................................... -- (5,232) -- Dividends paid on preferred stock .............................. (2,471) (1,604) (1,604) --------- --------- --------- Net cash provided by (used for) financing activities ....... (21,738) 78,528 (8,974) --------- --------- --------- Net decrease in cash and cash equivalents .................. (543) (983) (4,440) Cash and cash equivalents, beginning of year ............... 7,648 7,105 6,122 --------- --------- --------- Cash and cash equivalents, end of year ..................... $ 7,105 $ 6,122 $ 1,682 ========= ========= ========= The accompanying notes are an integral part of these statements. F-6 COMSTOCK RESOURCES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (1) Summary of Significant Accounting Policies Accounting policies used by Comstock Resources, Inc. ("Comstock" or the "Company") reflect oil and natural gas industry practices and conform to accounting principles generally accepted in the United States of America. Basis of Presentation and Principles of Consolidation Comstock is engaged in oil and natural gas exploration, development and production, and the acquisition of producing oil and natural gas properties. The consolidated financial statements include the accounts of Comstock and its wholly owned subsidiaries. All significant intercompany accounts and transactions have been eliminated in consolidation. Use of Estimates in the Preparation of Financial Statements The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual amounts could differ from those estimates. Changes in the future estimated oil and natural gas reserves or the estimated future cash flows attributable to the reserves that are utilized for impairment analysis could have a significant impact on the future results of operations. Other Current Assets Other current assets at December 31, 2001 and 2002 consists of the following: As of December 31, ---------------------- 2001 2002 ------ ------ (In thousands) Prepaid expenses .................. $3,602 $1,109 Income tax receivable ............. 3,347 -- Insurance claims receivable ....... 58 1,125 Inventory ......................... 411 444 ------ ------ $7,418 $2,678 ====== ====== Property and Equipment Comstock follows the successful efforts method of accounting for its oil and natural gas properties. Acquisition costs for proved oil and natural gas properties, costs of drilling and equipping productive wells, and costs of unsuccessful development wells are capitalized and amortized on an equivalent unit-of- production basis over the life of the remaining related oil and gas reserves. Equivalent units are determined by converting oil to natural gas at the ratio of six barrels of oil for one thousand cubic feet of natural gas. Cost centers for amortization purposes are determined on a field area basis. The estimated future costs of dismantlement, restoration and abandonment are included on the balance sheet in the reserve for future abandonment and accrued as part of depreciation, depletion and amortization expense. Costs incurred to F-7 COMSTOCK RESOURCES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) acquire oil and gas leasehold are capitalized. Unproved oil and gas properties are periodically assessed and any impairment in value is charged to exploration expense. The costs of unproved properties which are determined to be productive are transferred to proved oil and gas properties and amortized on an equivalent unit of production basis. Exploratory expenses, including geological and geophysical expenses and delay rentals for unevaluated oil and gas properties, are charged to expense as incurred. Exploratory drilling costs are initially capitalized as unproved property but charged to expense if and when the well is determined not to have found proved oil and gas reserves. In accordance with the Statement of Financial Accounting Standards No. 144 "Accounting for the Impairment or Disposal of Long-Lived Assets," ("SFAS 144") Comstock assesses the need for an impairment of the costs capitalized of its oil and gas properties on a property or cost center basis. If an impairment is indicated based on undiscounted expected future cash flows, then an impairment is recognized to the extent that net capitalized costs exceed discounted expected future cash flows based on escalated prices and including probable reserves, where appropriate. No impairment was required in 2000 or 2002. In 2001 Comstock provided an impairment of $1.4 million for certain of its oil and gas properties. Other property and equipment consists primarily of work boats, gas gathering systems, computer equipment and furniture and fixtures which are depreciated over estimated useful lives on a straight-line basis. Other Assets Other assets primarily consists of deferred costs associated with issuance of Comstock's 11 1/4% senior notes. These costs are amortized over the eight year life of the senior notes on a straight-line basis which approximates the amortization that would be calculated using an effective interest rate method. Stock Options Comstock applies the intrinsic value-based method of accounting prescribed by Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees," ("APB 25") and related interpretations, in accounting for its incentive plan stock options. As such, compensation expense would be recorded on the date of grant only if the current market price of the underlying stock exceeded the exercise price. Statement of Financial Accounting Standards 123, "Accounting for Stock-Based Compensation," ("SFAS 123") established accounting and disclosure requirements using a fair value-based method of accounting for stock- based employee compensation plans. As allowed by SFAS 123, Comstock has elected to continue to apply the intrinsic value-based method of accounting described above, and has adopted the disclosure requirements of SFAS 123. F-8 COMSTOCK RESOURCES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) The following table illustrates the effect on net income if the fair-value-based method had been applied to all outstanding stock options in each period. Year Ended December 31, ------------------------------- 2000 2001 2002 -------- -------- ------- (Restated) (Restated) (In thousands, except per share amounts) Net income, as reported ........................ $ 38,729 $ 33,298 $ 9,901 Add stock-based employee compensation expense included in reported net income, net of tax 204 159 142 Deduct total stock-based employee compensation expense determined under fair-value-based method for all rewards, net of tax ........ (2,178) (1,845) (1,066) -------- -------- ------- Pro forma net income ............... $ 36,755 $ 31,612 $ 8,977 ======== ======== ======= Basic earnings per share: As Reported......... $1.47 $1.15 $0.34 Pro Forma........... $1.40 $1.09 $0.31 Diluted earnings per share: As Reported......... $1.20 $1.01 $0.34 Pro Forma........... $1.15 $0.96 $0.31 Because the SFAS 123 method of accounting has not been applied to options granted prior to January 1, 1995, the resulting pro forma compensation cost may not be representative of that to be expected in future years. The fair value of each option grant is estimated on the date of grant using the Black-Scholes option pricing model with the following weighted average assumptions used for grants in 2000, 2001 and 2002, respectively: average risk-free interest rates of 6.2, 4.9 and 3.8 percent; average expected lives of 7.8, 7.4 and 5.9 years; average expected volatility factors of 66.4, 67.2 and 68.9; and no dividend yield. The estimated weighted average fair value of options to purchase one share of common stock issued under the Company's Incentive Plans was $5.98 in 2000, $6.80 in 2001 and $5.88 in 2002. Segment Reporting Comstock presently operates in one business segment, the exploration and production of oil and natural gas. Derivative Instruments and Hedging Activities On January 1, 2001, Comstock adopted Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" ("SFAS 133") which requires that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded on the balance sheet as either an asset or liability measured at its fair value. SFAS 133 requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Comstock estimates fair value based on quotes obtained from the counterparties to the derivative contract. The fair value of derivative contracts that expire in less than one year are recognized as current assets or liabilities. Those that expire in more than one year are recognized as long-term F-9 COMSTOCK RESOURCES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) assets or liabilities. Derivative financial instruments that are not accounted for as hedges are adjusted to fair value through income. If the derivative is designated as a cash flow hedge, changes in fair value are recognized in other comprehensive income until the hedged item is recognized in earnings. Major Purchasers In 2002, Comstock had two purchasers of its oil and natural gas production which individually accounted for more than 10% of total oil and gas sales. Such purchasers accounted for 16% and 15% of total 2002 oil and gas sales. In 2001, Comstock had four purchasers which accounted for 24%, 19%, 16% and 12% of total 2001 oil and gas sales. In 2000, Comstock had three purchasers which accounted for 29%, 21% and 11% of total 2000 oil and gas sales. Revenue Recognition and Gas Balancing Comstock utilizes the sales method of accounting for natural gas revenues whereby revenues are recognized based on the amount of gas sold to purchasers. The amount of gas sold may differ from the amount to which the Company is entitled based on its revenue interests in the properties. Comstock did not have any significant imbalance positions at December 31, 2000, 2001 or 2002. General and Administrative Expenses General and administrative expenses are reported net of reimbursements of overhead costs that are allocated to working interest owners of the oil and gas properties operated by Comstock. Other Income Included in other income in 2002 was $7.7 million related to refunds received in 2002 of severance taxes paid in prior years. Income Taxes Comstock accounts for income taxes using the asset and liability method, whereby deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their respective tax bases, as well as the future tax consequences attributable to the future utilization of existing tax net operating loss and other types of carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. Comprehensive Income Comprehensive income is defined as the change in equity of a business enterprise during a period from transactions and other events and circumstances from non-owner sources. F-10 COMSTOCK RESOURCES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) For the years ended December 31, 2001 and 2002,Comstock's comprehensive income differed from net income by approximately $139,000 and $102,000, respectively due to the recognition in comprehensive income of unrealized gains or losses related to certain of Comstock's derivative instruments which have been designated as hedges. For the year ended December 31, 2000, there were no differences between Comstock's net income or net loss and comprehensive income. Earnings Per Share Basic and diluted earnings per share for 2000, 2001 and 2002 were determined as follows: Year Ended December 31, ---------------------------------------------------------------------------------------------- 2000 2001 2002 ----------------------------- ----------------------------- ----------------------------- Per Per Per Income Shares Share Income Shares Share Income Shares Share -------- ------- ------- -------- ------- ------- -------- ------- ------- (Restated) (Restated)(Restated) (Restated) (In thousands except per share data) Basic Earnings Per Share: Income from Continuing Operations.. $ 40,973 26,290 $ 34,506 29,030 $ 12,577 28,764 Less Preferred Stock Dividends.............. (2,471) -- (1,604) -- (1,604) -- -------- ------- -------- ------- -------- -------- Net Income from Continuing Operations Available to Common Stockholders..... 38,502 26,290 $1.46 32,902 29,030 $1.13 10,973 28,764 $0.38 ======= ======= ======== Income from Discontinued Operations 227 26,290 0.01 396 29,030 0.02 (1,072) 28,764 (0.04) -------- ======= ------ -------- ======= ------- -------- ======== ------- Net Income Available to Common Stockholders.... $ 38,729 26,290 $1.47 $ 33,298 29,030 $1.15 $ 9,901 28,764 $0.34 ======== ======= ====== ======== ======= ======= ======== ======== ======= Diluted Earnings Per Share: Income from Continuing Operations $ 40,973 26,290 $ 34,506 29,030 $ 12,577 28,764 Effect of Dilutive Securities: Stock Options.............. -- 1,184 -- 1,129 -- 744 Convertible Preferred Stock -- 6,745 -- 4,393 -- 4,393 -------- ------- -------- ------- -------- -------- Net Income from Continuing Operations Available to Common Stockholders With Assumed Conversions.... 40,973 34,219 $1.20 34,506 34,552 $1.00 12,577 33,901 $0.37 ======= ======= ======== Income from Discontinued Operations. 227 34,219 -- 396 34,552 0.01 (1,072) 33,901 (0.03) -------- ======== ------ -------- ======= -------- -------- ======== ------- Net Income Available to Common Stockholders...... $ 41,200 34,219 $1.20 $ 34,902 34,552 $1.01 $ 11,505 33,901 $0.34 ======== ======== ====== ======== ======= ======== ======== ======== ======= Stock options and warrants to purchase common stock at exercise prices in excess of the average actual stock price for the period that were anti-dilutive and that were excluded from the determination of diluted earnings per share are as follows: 2000 2001 2002 -------------- --------------- ---------------- (In thousands except per share data) Stock options and warrants to purchase common stock.......... 2,979 2,559 2,737 Exercise Price.................... $8.88 - $14.00 $9.63 - $14.00 $8.06 - $14.00 F-11 Statements of Cash Flows For the purpose of the consolidated statements of cash flows, Comstock considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. The following is a summary of all significant noncash investing and financing activities and cash payments made for interest and income taxes: Year Ended December 31, -------------------------- 2000 2001 2002 ------- ------- ------- (in thousands) Noncash activities - Common stock issued for director compensation................. $ 93 $ 26 $ -- Value of vested stock options under exploration venture....... 2,990 3,028 1,286 Cash payments - Interest payments............................................. $24,731 $20,837 $28,987 Income tax payments........................................... -- 243 -- New Accounting Standards In August 2001, the Financial Accounting Standards Board (the "FASB") issued Statement of Financial Accounting Standards No. 143 ("SFAS 143") "Accounting for Asset Retirement Obligations," which Comstock adopted effective January 1, 2003. This statement requires Comstock to record a liability in the period in which an asset retirement obligation ("ARO") is incurred. Upon recognition of an ARO liability, additional asset cost would be capitalized to equal the amount of the liability. Upon the initial adoption of SFAS 143, Comstock recognized a liability for any existing AROs not already provided for in Comstock's reserve for future abandonment costs. Comstock also recognized additional capitalized cost related to the additional liability and accumulated depreciation on the additional capitalized cost. Under SFAS 143, Comstock estimates that its total ARO for its oil and natural gas properties is approximately $15.2 million which was $1.5 million less than the liability that Comstock had provided for in its reserve for future abandonment as of December 31, 2002. The impact of adopting SFAS 143, which will be recorded as the cumulative effect of an accounting change, was an increase to net income of approximately $0.7 million, net of tax. In June 2002, the FASB issued Statement of Financial Accounting Standards 146, "Accounting for Costs Associated with Exit or Disposal Activities" ("SFAS 146"). The Statement establishes accounting and reporting standards that are effective for exit or disposal activities beginning after December 31, 2002 which require that a liability be recognized for an exit or disposal activity when that liability is incurred. Comstock has not determined the effect, if any, that the adoption of SFAS 146 will have on its financial statements. F-12 COMSTOCK RESOURCES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) In December 2002, the FASB issued Statement of Financial Accounting Standards No. 148, "Accounting for Stock-Based Compensation - Transition and Disclosure, an amendment of FASB Statement No. 123". This Statement amends No. 123, "Accounting for Stock-Based Compensation," to provide alternative methods of transition for a voluntary change to the fair value method of accounting for stock-based employee compensation. In addition, this statement amends the disclosure requirements of SFAS 123 to require prominent disclosures in both annual and interim financial statements. Certain of the disclosure modifications are included in the notes to these consolidated financial statements. In January 2003, the FASB issued Interpretation ("FIN") No. 45, "Guarantor's Accounting and Disclosure Requirement for Guarantees, including Indirect Guarantees of Indebtedness of Others." FIN 45 requires an entity to recognize a liability for the obligations it has undertaken in issuing a guarantee. This liability would be recorded at the inception of a guarantee and would be measured at fair value. Certain guarantees are excluded from the measurement and disclosure provisions while certain other guarantees are excluded from the measurement provisions of the interpretation. The measurement provisions of this statement apply prospectively to guarantees issued or modified after December 31, 2002. The disclosure provisions of the statement apply to financial statements for periods ending after December 15, 2002. The adoption of the statement is not expected to have a material effect on the Company's financial statements when adopted. In January 2003, the FASB issued Interpretation No. 46, "Consolidation of Variable Interest Entities." FIN 46 requires an entity to consolidate a variable interest entity if it is designated as the primary beneficiary of that entity even if the entity does not have a majority of voting interests. A variable interest entity is generally defined as an entity where its equity is unable to finance its activities or where the owners of the entity lack the risk and rewards of ownership. The provisions of this statement apply at inception for any entity created after January 31, 2003. For an entity created before February 1, 2003, the provisions of this interpretation must be applied at the beginning of the first interim or annual period beginning after June 15, 2003. Comstock is not the primary beneficiary of any variable interest entities, and accordingly, the adoption of FIN 46 is not expected to have a material effect on the Company's financial statements when adopted. (2) Acquisitions In December 2002, Comstock acquired interests in the Ship Shoal 113 Unit for $7.8 million. The acquisition included interest in 26 producing wells, 11.7 net wells, and seven production facilities in the Gulf of Mexico. Comstock also acquired interests in a South Texas field for $1.7 million in December 2002. The acquisition included interest in 15 producing wells, 15 net wells, and over 7,000 acres. Comstock plans to redevelop these fields in the future. F-13 COMSTOCK RESOURCES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) On December 17, 2001, Comstock completed the acquisition of DevX Energy, Inc. ("DevX") by acquiring 100% of the common stock of DevX for $92.6 million through a cash tender offer and subsequent merger into a wholly owned subsidiary. As a result of the acquisition, DevX became a wholly owned subsidiary of Comstock. DevX is an independent energy company engaged in the exploration, development and acquisition of oil and gas properties. DevX owns interests in 600 producing oil and gas wells located onshore primarily in East and South Texas, Kentucky, Oklahoma and Kansas. The DevX acquisition added approximately 163.4 billion cubic feet equivalent of natural gas reserves to Comstock's reserve base (unaudited). Subsequent to the acquisition, Comstock repurchased approximately $49.8 million of DevX's 12 1/2% senior notes which were due in 2008 for 110% of the principal amount plus accrued interest. DevX's operations have been included in the consolidated financial statements since December 17, 2001. The following table summarizes the estimated fair values of the assets acquired and liabilities assumed at the date of the acquisition. December 17, 2001 ----------------- (in thousands) Current assets .......... $ 8,317 Oil and gas properties .. 160,794 Derivatives ............. 1,577 -------- Total assets acquired ... 170,688 -------- Current liabilities ..... 8,990 Long-term debt .......... 54,988 Deferred tax liability .. 7,324 Derivatives ............. 1,873 -------- Total liabilities assumed 73,175 -------- Net assets acquired ..... $ 97,513 ======== Set forth in the following table is certain unaudited pro forma financial information for the years ended December 31, 2000 and 2001. This information has been prepared assuming the DevX acquisition was consummated on January 1, 2000 and is based on estimates and assumptions deemed appropriate by Comstock. The pro forma information is presented for illustrative purposes only. If the transactions had occurred in the past, Comstock's operating results might have been different from those presented in the following table. The pro forma information should not be relied upon as an indication of the operating results that Comstock would have achieved if the transactions had occurred on January 1, 2000. The pro forma information also should not be used as an indication of the future results that Comstock will achieve after the acquisition. Adjustments were made to adjust the historical operating results of DevX (i) to conform DevX to the successful efforts method of accounting for oil and gas activities; (ii) to reverse the costs of the closed Dallas and Ottawa corporate offices of DevX; and (iii) to record the pro forma interest expense based on Comstock's average interest rate under its bank credit facility. F-14 COMSTOCK RESOURCES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) Year Ended December 31, ------------------------ 2000 2001 --------- --------- (Restated) (Restated) (In thousands, except per share amounts) Oil and gas sales ........................ $ 210,289 $ 204,717 Total operating expenses ................. (103,005) (113,349) Total other income (expenses) ............ (36,602) (24,947) --------- --------- Income from continuing operations before income taxes ........... 70,682 66,421 Provision for income taxes ............... (24,738) (23,247) --------- --------- Income from continuing operations ... 45,944 43,174 Discontinued operations .................. 227 396 --------- --------- Net income .......................... 46,171 43,570 Preferred stock dividends ................ (2,471) (1,604) --------- --------- Net income from continuing operations attributable to common stock $ 43,700 $ 41,966 ========= ========= Net income from continuing operations per share: Basic................................. $ 1.65 $ 1.42 ========= ========= Diluted............................... $ 1.34 $ 1.24 ========= ========= Net income per share: Basic................................. $ 1.66 $ 1.45 ========= ========= Diluted............................... $ 1.35 $ 1.26 ========= ========= (3) Oil and Gas Producing Activities Set forth below is certain information regarding the aggregate capitalized costs of oil and gas properties and costs incurred by Comstock for its oil and gas property acquisition, development and exploration activities: Capitalized Costs As of December 31, ----------------------- 2001 2002 --------- --------- (Restated) (In thousands) Proved properties .............. $ 900,711 $ 961,562 Unproved properties ............ 11,609 14,880 Accumulated depreciation, depletion and amortization (277,670) (313,608) --------- --------- $ 634,650 $ 662,834 ========= ========= F-15 COMSTOCK RESOURCES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) Costs Incurred For the Year Ended December 31, ----------------------------------- 2000 2001 2002 -------- -------- ------- (Restated) (Restated) (In thousands) Property acquisitions Proved properties ............... $ 9,684 $160,794 $11,435 Unproved properties ............. 5,863 7,113 4,268 Development costs ..................... 48,546 51,090 35,272 Exploration costs ..................... 19,515 35,778 31,414 -------- -------- ------- $ 83,608 $254,775 $82,389 ======== ======== ======= Due to the tax-free nature of the merger between Comstock and DevX in December 2001, additional deferred tax liabilities of $7.3 million were allocated to proved oil and gas properties and are included in the proved property acquisition costs in 2001. In 2001 and 2002, Comstock capitalized interest expense of $230,000 and $281,000, respectively, on its unproved properties under development which is included in the unproved property acquisition costs in each year. Results of Operations for Oil and Gas Producing Activities The following table includes revenues and expenses associated directly with Comstock's oil and natural gas producing activities. The amounts presented do not include any allocation of Comstock's interest costs or general corporate overhead and, therefore, are not necessarily indicative of the contribution to net earnings of Comstock's oil and gas operations. Income tax expense has been calculated by applying statutory income tax rates to oil and gas sales after deducting costs, including depreciation, depletion and amortization and after giving effect to permanent differences. For the Year Ended December 31, ---------------------------------- 2000 2001 2002 --------- --------- --------- (Restated) (Restated) (In thousands) Oil and gas sales ............................................. $ 168,084 $ 166,118 $ 142,085 Oil gas operating ............................................. (29,277) (31,855) (33,499) Exploration ................................................... (3,505) (6,611) (5,479) Depreciation, depletion and amortization ...................... (42,992) (47,140) (52,869) Impairment .................................................... -- (1,400) -- --------- --------- --------- Income from continuing operations ......................... 92,310 79,112 50,238 Provision for income taxes .................................... (32,309) (27,689) (17,583) --------- --------- --------- Income from continuing operations, after tax .............. 60,001 51,423 32,655 Discontinued operations, including loss on disposal, net of income taxes ...................... 227 396 (1,072) --------- --------- --------- Results of operations of oil and gas producing activities . $ 60,228 $ 51,819 $ 31,583 ========= ========= ========= F-16 (4) Long-Term Debt Long-term debt is comprised of the following: As of December 31, 2001 2002 --------- --------- (In thousands) Revolving Bank Credit Facility ............. $ 227,000 $ 146,000 11 1/4% Senior Notes due 2007 .............. 145,000 220,000 Other ...................................... 464 272 --------- --------- 372,464 366,272 Less current portion ....................... (229) (270) --------- --------- $ 372,235 $ 366,002 ========= ========= On December 17, 2001, Comstock entered into a bank credit facility which consists of a $350.0 million three year revolving credit commitment provided by a syndicate of banks for which Toronto Dominion (Texas), Inc. serves as administrative agent. 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 Comstock's oil and natural gas properties. The borrowing base at December 31, 2002 was $240.0 million. The revolving credit line bears interest, based on the utilization of the borrowing base, at the option of Comstock at either (i) LIBOR plus 1.5% to 2.375% or (ii) the corporate base rate (generally the federal funds rate plus 0.5%) plus 0.5% to 1.375%. The facility matures on January 2, 2005. Indebtedness under the bank credit facility is secured by substantially all of Comstock's and its subsidiaries' assets and Comstock's subsidiaries are guarantors of the bank credit facility. The bank credit facility contains covenants that, among other things, restrict the payment of cash dividends, limit the amount of consolidated debt and limit Comstock's ability to make certain loan and investments. Financial covenants include the maintenance of a current ratio, maintenance of tangible net worth and maintenance of an interest coverage ratio. The Company was in compliance with these covenants as of December 31, 2002. Comstock issued $150.0 million in aggregate principal amount of 11 1/4% Senior Notes due in 2007 (the "Notes") on April 29, 1999. Interest on the Notes is payable semiannually on May 1 and November 1, commencing on November 1, 1999. The Notes are unsecured obligations of Comstock and are guaranteed by all of its principal operating subsidiaries. Comstock repurchased $5.0 million of the Notes in July 2001. The Notes can be redeemed beginning on May 1, 2004. On March 7, 2002, Comstock closed the sale in a private placement of $75.0 million of additional Notes at a net price of 97.25% after the placements agents' discount. As a result of this transaction, $220.0 million of aggregate principal amount of the Notes are outstanding. The fair market value of the Notes as of December 31, 2002 was $233.2 million based on the market price of 106% of the face amount as of December 31, 2002. F-17 COMSTOCK RESOURCES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) The following table summarizes our debt by year of maturity: 2003 2004 2005 2006 2007 Thereafter Total ------- -------- -------- -------- -------- -------- -------- (In thousands) Bank credit facility $ -- $ -- $146,000 $ -- $ -- $ -- $146,000 Senior notes ....... -- -- -- -- 220,000 -- 220,000 Other debt ......... 270 -- -- -- -- 2 272 ------- -------- -------- -------- -------- -------- -------- $ 270 -- $146,000 -- $220,000 $ 2 $366,272 ======= ======== ======== ======== ======== ======== ======== (5) Commitments and Contingencies Lease Commitments Comstock rents office space under noncancelable leases. Rent expense for the years ended December 31, 2000, 2001 and 2002 was $432,000, $526,000 and $495,000, respectively. Minimum future payments under the leases are as follows: (In thousands) 2003 $ 656 2004 452 2005 477 2006 198 2007 -- ------ $1,783 ====== Contingencies From time to time Comstock is involved in certain litigation that arises in the normal course of its operations. The Company records a loss contingency for these matters when it is probable that a liability has been incurred and the amount of the loss can be reasonably estimated. In 2002, Comstock accrued $1.5 million related to its estimate of losses to be incurred in resolving certain contingencies. After consideration of amounts accrued, the Company does not believe the resolution of these matters will have a material effect on the Company's financial position or results of operations. (6) Convertible Preferred Stock On April 29, 1999, Comstock issued 3,000,000 shares of convertible preferred stock (the "Series 1999 Preferred Stock") in a private placement and received proceeds of $30.0 million. The Series 1999 Preferred Stock accrues dividends at an annual rate of 9% which are payable quarterly in cash or Comstock has the option to issue shares of Common Stock. Dividends paid per share have been $0.91 per share in each of 2000, 2001 and 2002. Each share of the Series 1999 Preferred Stock is convertible, at the option of the holder, into 2.5 shares of Common Stock. On May 1, 2005 and on each May 1, thereafter, so long as any shares of the Series 1999 Preferred Stock are outstanding, Comstock is obligated to redeem an amount of shares of the Series 1999 Preferred Stock equal to one-third of the shares of the Series 1999 Preferred Stock outstanding on May 1, 2005 at $10.00 per share plus accrued and unpaid dividends. The mandatory redemption amounts of the Series 1999 Preferred Stock F-18 COMSTOCK RESOURCES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) total $5.9 million per year for each of the years ended December 31, 2005, 2006 and 2007. The mandatory redemption price may be paid either in cash or in shares of Common Stock, at the option of the Company. The fair value of the Series 1999 Preferred Stock at issuance date was equal to the mandatory redemption value. Comstock has the option to redeem the shares of Series 1999 Preferred Stock upon payment to the holders of the Series 1999 Preferred Stock at a specified rate of return on the initial purchase. Upon a change of control of Comstock, the holders of the Series 1999 Preferred Stock have the right to require Comstock to purchase all or a portion of the Series 1999 Preferred Stock for cash. Due to the change of control provision, the Series 1999 Preferred Stock has been classified as temporary equity. The financial statements for prior years have been reclassified to reflect the Series 1999 Preferred Stock outside of stockholders' equity. On March 19, 2003, the terms of the Series 1999 Preferred Stock were modified to allow the payment of the redemption after a change of control in shares of Common Stock at the option of the Company. The holders of the Series 1999 Preferred Stock similarly have the right to require the Company to satisfy the redemption obligation with shares of Common Stock. Accordingly, the Series 1999 Preferred Stock will be classified as part of the stockholders' equity after this date. In September and October 2000, holders of 1,242,690 shares of the Series 1999 Preferred Stock converted their shares into 3,106,725 shares of Common Stock. As a result of these conversions, $12.4 million of preferred stock was transferred to common stockholders' equity. (7) Stockholders' Equity The authorized capital stock of Comstock consists of 50 million shares of common stock, par value $.50 per share (the "Common Stock"), and 5 million shares of preferred stock, par value $10.00 per share. The preferred stock may be issued in one or more series, and the terms and rights of such stock will be determined by the Board of Directors. Comstock's Board of Directors has designated 500,000 shares of the preferred stock as Series B Junior Participating Preferred Stock (the "Series B Junior Preferred Stock") in connection with the adoption of a shareholder rights plan. At December 31, 2002 there were no shares of Series B Junior Preferred Stock issued or outstanding. The Series B Junior Preferred Stock is entitled to receive cumulative quarterly dividends per share equal to the greater of $1.00 or 100 times the aggregate per share amount of all dividends (other than stock dividends) declared on Common Stock since the immediately preceding quarterly dividend payment date or, with respect to the first payment date, since the first issuance of Series B Junior Preferred Stock. Holders of the Series B Junior Preferred Stock are entitled to 100 votes per share (subject to adjustment to prevent dilution) on all matters submitted to a vote of the stockholders. The Series B Junior Preferred Stock is neither redeemable nor convertible. The Series B Junior Preferred Stock ranks prior to the Common Stock but junior to all other classes of preferred stock. Under a plan adopted by the Board of Directors, non-employee directors can elect to receive shares of Common Stock valued at the then current market price in payment of annual director and consulting fees. Under this plan, Comstock issued 8,182 and 5,342 shares of Common Stock in 2000 and 2001, respectively, in payment of fees aggregating $93,000 and $26,000 for 2000 and 2001, respectively. Stock options were exercised to purchase 291,400 shares, 560,606 shares and 310,758 shares in 2000, 2001, and 2002, respectively. Such exercises yielded net proceeds of approximately $763,000, $2.0 million and $1.1 million in 2000, 2001, and 2002, respectively. F-19 COMSTOCK RESOURCES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) During 2001, Comstock repurchased 907,400 shares of Common Stock in open market purchases totaling $5.2 million. Such shares were retired upon repurchase. Stock Options On June 23, 1999, the stockholders approved the 1999 Long-term Incentive Plan for the management including officers, directors and managerial employees which replaced the 1991 Long-term Incentive Plan. The 1999 Long-term Incentive Plan together with the 1991 Long-term Incentive Plan (the "Incentive Plans") authorize the grant of non-qualified stock options and incentive stock options and the grant of restricted stock to key executives of Comstock. As of December 31, 2002, the Incentive Plans provide for future awards of stock options or restricted stock grants of up to 352,786 shares of Common Stock plus 1% of the outstanding shares of Common Stock each year beginning on January 1, 2003. The following table summarizes information about the Incentive Plans stock options outstanding at December 31, 2002: Number of Number of Shares Weighted Average Shares Exercise Price Outstanding Remaining Life Exercisable -------------- ----------- ---------------- -------------- (Years) $3.44 246,375 4.8 246,375 3.88 926,900 5.4 688,150 6.42 437,750 6.1 175,000 6.69 74,000 5.3 47,000 6.94 150,000 1.0 150,000 7.40 20,000 3.6 20,000 8.70 30,000 4.4 30,000 8.88 249,250 6.5 -- 9.20 273,750 6.0 -- 11.00 1,150,000 3.0 1,150,000 11.12 33,500 5.0 20,000 11.94 20,000 0.9 20,000 12.38 559,000 2.0 559,000 ----------- ---------- 4,170,525 4.3 3,105,525 =========== ========== F-20 COMSTOCK RESOURCES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) The following table summarizes stock option activity during 2000, 2001 and 2002 under the Incentive Plans: Number Weighted Average of Shares Exercise Price Exercise Price -------------- ----------------- ---------------- Outstanding at December 31, 1999......... 4,630,000 $2.00 to $12.38 $7.08 Granted.......................... 351,250 $6.69 to $8.88 8.24 Exercised................................ (291,400) $2.00 to $4.81 2.62 -------------- Outstanding at December 31, 2000......... 4,689,850 $2.00 to $12.38 7.45 Granted.......................... 493,250 $6.42 to $11.12 6.80 Exercised................................ (580,450) $2.00 to $11.94 3.86 Forfeited........................ (213,000) $6.56 to $11.12 6.61 -------------- Outstanding at December 31, 2001......... 4,389,650 $2.50 to $12.38 7.89 Granted.......................... 303,750 $8.70 to $9.20 9.15 Exercised................................ (313,875) $2.50 to $6.69 3.55 Forfeited........................ (209,000) $9.63 to $11.94 10.52 -------------- Outstanding at December 31, 2002......... 4,170,525 $3.44 to $12.38 8.18 ============== Exercisable at December 31, 2002......... 3,105,525 $3.44 to $12.38 8.51 ============== Restricted Stock Grants Under the Incentive Plans, officers and managerial employees may be granted a right to receive shares of Common Stock without cost to the employee. The shares vest over a specified period with credit given for past service rendered to Comstock. Restricted stock grants for 56,250 shares were made in each of the years 2000, 2001 and 2002. In the aggregate, 723,750 restricted stock grants have been awarded under the Incentive Plans. As of December 31, 2002, 526,875 shares of such awards are vested. A provision for the restricted stock grants is made ratably over the vesting period. Compensation expense recognized for restricted stock grants for the years ended December 31, 2000, 2001 and 2002 was $221,000, $218,000 and $217,000, respectively. (8) Exploration Venture On July 31, 2001, Comstock entered into a new exploration agreement with Bois d' Arc Offshore, Ltd. and its principals ("Bois d' Arc"), which replaces an exploration agreement entered into on December 8, 1997. The 2001 Exploration Agreement established a joint exploration venture between Comstock and Bois d' Arc covering the state coastal waters of Louisiana and Texas and corresponding federal offshore waters in the Gulf of Mexico. The new venture was effective April 1, 2001 and will end on December 31, 2006. Under the joint exploration venture, Bois d' Arc generates exploration prospects in the Gulf of Mexico utilizing 3-D seismic data and their extensive geological expertise in the region. Comstock advances 100% of the funds for the acquisition of 3 D seismic data and leases as needed. Comstock recovers its advances based on Bois d' Arc's ability to sell interests in drillable prospects. Upon a sale of a successful prospect by Bois d' Arc, Comstock is reimbursed for the costs that were advanced and is entitled to a 40% non-promoted working interest in each prospect generated. Comstock capitalizes advances made for leases as unevaluated properties and expenses advances made for seismic costs as exploration costs. F-21 COMSTOCK RESOURCES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) Under the exploration agreement, Bois d' Arc has the opportunity to earn warrants to purchase up to 1,620,000 shares of Common Stock. Warrants to purchase 60,000 shares are earned by Bois d' Arc for each prospect which results in a successful discovery. The exercise price on the new warrants is determined based on the current market price for the Common Stock on a semiannual basis each year that the venture is in operation. The agreement requires that Comstock must fund a minimum of $5.0 million for the acquisition of seismic data over the term of the agreement or Bois d' Arc has the right to terminate the agreement. Bois d' Arc earned warrants to purchase 360,000 and 240,000 shares under the exploration agreement in 2001 and 2002, respectively. The warrants are exercisable at a weighted average price of $7.51. The value of the warrants based on the Black-Scholes option pricing model was $5.64 per option share or an aggregate of $2.0 million in 2001 and $5.36 per option share or an aggregate of $1.3 million in 2002. Such costs were capitalized as a cost of oil and gas properties. Bois d' Arc had also earned warrants to purchase 600,000 shares of Common Stock at $14.00 per share under the prior exploration agreement during the period from January 1998 to April 2001. The value of these warrants based on the Black-Scholes option pricing model was $9.97 per option share. The estimated value of $6.0 million for the warrants earned under the prior exploration agreement were capitalized to oil and gas properties in 1998 through 2001. (9) Retirement Plan Comstock has a 401(k) Profit Sharing Plan which covers all of its employees. At its discretion, Comstock may match a certain percentage of the employees' contributions to the plan. The matching percentage is determined annually by the Board of Directors. Comstock's matching contributions to the plan were $84,000, $96,000 and $116,000 for the years ended December 31, 2000, 2001 and 2002, respectively. (10) Income Taxes The tax effects of significant temporary differences representing the net deferred tax liability at December 31, 2001 and 2002 were as follows: 2001 2002 -------- -------- (Restated) (In thousands) Net deferred tax assets (liabilities): Property and equipment ............. $(73,965) $(88,931) Net operating loss carryforwards ... 34,504 43,037 Valuation allowance on net operating loss carryforwards ............... (8,043) (8,043) Other carryforwards ................ 897 1,360 -------- -------- $(46,607) $(52,577) ======== ======== F-22 COMSTOCK RESOURCES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) The following is an analysis of the consolidated income tax expense: 2001 2002 ------- ------- (Restated) (In thousands) Current.............. $ -- $ -- Deferred ............ 18,579 6,773 ------- ------ $18,579 $6,773 ======= ====== There were no significant differences between income taxes computed using the statutory rate of 35% and Comstock's effective tax rate in 2000, 2001 and 2002 of 35%. At December 31, 2002, Comstock had the following carryforwards available to reduce future income taxes: Years of Expiration Types of Carryforward Carryforward Amounts - ----------------------------------------- ----------------- --------------- (In thousands) Net operating loss - U.S. federal........ 2018 - 2022 $122,964 Alternative minimum tax credits.......... Unlimited 1,220 Charitable contributions carryforward.... 2003 - 2007 400 The utilization of $42.9 million of the net operating loss carryforwards of DevX are limited to approximately $1.1 million per year pursuant to a prior change of control. Accordingly, a valuation allowance of $23.0 million, with a tax effect of $8.0 million, has been established for Comstock's estimate of DevX's net operating loss carryforwards that it will not be able to utilize. Realization of Comstock's and DevX's net operating carryforwards requires Comstock to generate taxable income within the carryforward period. (11) Derivatives and Hedging Activities Comstock uses 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, Comstock receives a settlement from the counterparty based on the difference multiplied by the volume hedge. Similarly, when the applicable settlement price exceeds the price specified in the contract, Comstock pays the counterparty based on the difference. Comstock generally receives 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, generally Comstock receives a settlement from the counterparty when the settlement price is below the floor and pays a settlement to the counterparty when the settlement price exceeds the cap. No settlement occurs when the settlement price falls between the floor and cap. F-23 COMSTOCK RESOURCES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) The following table sets out the derivative financial instruments outstanding at December 31, 2002 which are held for natural gas price risk management: Volume Type Floor Period Beginning Period Ending (MMBtu) of Instrument Price - ------------------ ------------------ ------------ -------------- --------- January 1, 2003 December 31, 2003 2,250,000 Floor $2.00 The fair value of the commodity price derivative financial instruments at December 31, 2002 was a net asset of $3,000. In 2002, Comstock hedged a portion of its natural gas production for the period April 2002 through October 2002. The Company entered into price swaps covering 50 MMBtus per day of its natural gas production at an average price of $3.46 for April 2002 to October 2002. Comstock realized a $1.3 million gain on this hedge position in 2002, which was included in oil and gas sales and increased its average natural gas price realization from $3.26 per Mcf to $3.30 per Mcf. Comstock assumed certain natural gas price derivative financial instruments in connection with the acquisition of DevX. These derivative financial instruments were not designated as cash flow hedges. Comstock had an unrealized gain of $243,000 on these contracts in 2001. In 2002, Comstock realized a loss of $2.3 million related to these instruments. Comstock periodically enters into interest rate swap agreements to hedge the impact of interest rate changes on its floating rate long-term debt. As a result of certain hedging transaction for interest rates, Comstock has realized the following gains or losses which were included in interest expense: 2000 2001 2002 -------- -------- -------- (In thousands) Realized Gains (Losses).......... $ 988 $ (199) $ (218) As of December 31, 2002, Comstock had an interest rate swap agreement covering $25.0 million of its floating rate debt which fixed the LIBOR rate at 1.7% for the period January 2003 through December 2003. Comstock has designated this position as a hedge. The change in fair value of this instrument resulted in an unrealized after tax loss of $139,000 was recognized in other comprehensive income. (12) Discontinued Operations In April and July 2002, Comstock sold certain marginal oil and gas properties for cash proceeds of $3.5 million plus forgiveness of certain accounts payable related to the properties. The properties sold include various interests in nonoperated properties in Nueces, Hardeman, Montague and Wharton counties in Texas. Comstock realized a loss of $1.8 million ($1.2 million, after tax) on these property sales. The results of operations of these sold properties, including the losses on disposal, have been presented as discontinued operations in the accompanying consolidated statements of operations. F-24 COMSTOCK RESOURCES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) Prior year results have also been reclassifed to report the results of operations of the properties as discontinued operations. Results for these properties reported as discontinued operations were as follows: Year Ended December 31, ------------------------------ 2000 2001 2002 ------- ------- ------- (In thousands) Oil and gas sales ............................. $ 1,266 $ 1,571 $ 390 Operating expenses ............................ (916) (963) (264) Loss on disposal ........................ -- -- (1,778) ------- ------- ------- Income (loss) before taxes .............. 350 608 (1,652) Income tax provision (benefit) ................ 123 212 (580) ------- ------- ------- Income (loss) from discontinued operations .... $ 227 $ 396 $(1,072) ======= ======= ======= (13) Restatement of Previously Issued Financial Statements Subsequent to the issuance of its Annual Report for the year ended December 31, 2001, Comstock determined that certain outstanding advances made by the Company to its joint venture partner under its joint exploration venture in the Gulf of Mexico for seismic data acquisition should have been charged to exploration expense rather than reflected on the balance sheet as an asset. As a result of changing the accounting treatment for the advances used for seismic data, the Company determined that its financial statements for 1998, 1999, 2000 and 2001 should be restated. The effect of the restatement is a reduction to previously reported net income by $0.2 million and $1.6 million for the years 2000 and 2001, respectively, as a result of the additional exploration expense in each year. Management believes these changes primarily affect the timing of Comstock's recognition of exploration expense. If reimbursements are received for the advances made, future exploration expense will be reduced. In addition, the Series 1999 Preferred Stock has been reclassified from shareholders' equity at December 31, 2001 to temporary equity. The following balance sheet accounts as of December 31, 2001 were affected by the restatement: Year Ended December 31, 2001 ---------------------------- Previously Reported Restated ----------- ----------- (In thousands) Unevaluated oil and gas properties ............ $ 13,416 $ 11,609 Oil and gas properties ........................ 901,206 900,711 Net property and equipment .................... 638,576 636,274 Total assets .................................. 683,071 680,769 Accounts payable and accrued expenses ......... 37,389 38,812 Total current liabilities ..................... 38,416 39,839 Deferred taxes payable ........................ 47,911 46,607 Retained earnings ............................. 54,183 51,762 Redeemable preferred stock .................... -- 17,573 Total stockholders' equity .................... 215,662 195,668 Total liabilities and stockholders' equity .... 683,071 680,769 F-25 COMSTOCK RESOURCES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) The following presents the impact of the restatement on the operating results and cash flows for the years ended December 31, 2000 and 2001: Year Ended Year Ended December 31, 2000 December 31, 2001 --------------------- ----------------------- Previously Previously Reported (1) Restated Reported (1) Restated ----------- --------- ------------ --------- (In thousands, except per share amounts) Exploration expense ................... $ 3,192 $ 3,505 $ 4,215 $ 6,611 Total operating expenses .............. 80,478 80,791 90,611 93,007 Income from continuing operations before income taxes ................ 63,347 63,034 55,481 53,085 Income tax expense .................... (22,171) (22,061) (19,419) ( 18,579) Net income from continuing operations . 41,176 40,973 36,062 34,506 Net income ............................ 41,403 41,200 36,458 34,902 Net income attributable to common stock 38,932 38,729 34,854 33,298 Net income per share from continuing operations: Basic............................. $1.48 $1.46 $1.20 $1.13 Diluted........................... $1.21 $1.20 $1.06 $1.00 Net income per share: Basic............................. $1.48 $1.47 $1.20 $1.15 Diluted........................... $1.21 $1.20 $1.06 $1.01 Net cash provided by operating activities............... $104,556 $105,073 $ 110,090 $ 108,626 Net cash used for investing activities. $(83,361) $(83,878) $(189,601) $(188,147) - ------------- (1) Previously reported amounts have been adjusted for the effects of discontinued operations. (14) Supplementary Quarterly Financial Data (Unaudited) 2001- First Second Third Fourth Total -------- -------- -------- -------- -------- (In thousands, except per share amounts) Total oil and gas sales ...................... $ 66,910 $ 45,997 $ 29,305 $ 23,906 $166,118 ======== ======== ======== ======== ======== Net income (loss) from continuing operations attributable to common stock (As Restated) $ 22,692 $ 11,779 $ 2,482 $ (4,051) $ 32,902 ======== ======== ======== ======== ======== Net income (loss) attributable to common stock (As Restated)............. $ 22,894 $ 11,931 $ 2,539 $ (4,066) $ 33,298 ======== ======== ======== ======== ======== Net income (loss) from continuing operations per share (As Restated): Basic................................ $0.79 $0.40 $0.09 ($0.14) $1.13 ======== ======== ======== ========= ======== Diluted.............................. $0.66 $0.35 $0.08 $1.00 ======== ======== ======== ======== Net income (loss) per share (As Restated): Basic................................ $0.80 $0.41 $0.09 ($0.13) $1.15 ======== ======== ======== ========= ======== Diluted.............................. $0.66 $0.35 $0.09 $1.01 ======== ======== ======== ======== F-26 2002 - First Second Third Fourth Total -------- -------- -------- -------- -------- (In thousands, except per share amounts) Total oil and gas sales....................... $ 26,490 $ 38,004 $ 35,550 $ 42,041 $142,085 ======== ======== ======== ======== ======== Net income (loss) from continuing operations attributable to common stock.............. $ (4,698) $ 3,206 $ 2,970 $ 9,495 $ 10,973 ======== ======== ======== ======== ======== Net income (loss) attributable to common stock........................... $ (5,423) $ 2,804 $ 3,025 $ 9,777 $ 9,901 ======== ======== ======== ======== ======== Net income (loss) from continuing operations per share: Basic................................ ($0.16) $0.11 $0.10 $0.33 $0.38 ======== ======== ======== ======== ======== Diluted.............................. $0.11 $0.10 $0.29 $0.37 ======== ======== ======== ======== Net income (loss) per share: Basic................................ ($0.19) $0.10 $0.10 $0.33 $0.34 ======== ======== ======== ======== ======== Diluted.............................. $0.09 $0.10 $0.29 $0.34 ======== ======== ======== ======== (15) Oil and Gas Reserves Information (Unaudited) Set forth below is a summary of the changes in Comstock's net quantities of crude oil and natural gas reserves for each of the three years ended December 31, 2002. 2000 2001 2002 -------------------- -------------------- -------------------- Oil Gas Oil Gas Oil Gas (MBbls) (MMcf) (MBbls) (MMcf) (MBbls) (MMcf) -------- -------- -------- -------- -------- -------- Proved Reserves: Beginning of year ............ 19,467 258,121 17,451 297,835 17,348 462,085 Revisions of previous estimates ............... (1,725) 1,205 (1,177) (10,959) (11) (5,182) Extensions and discoveries ... 1,599 54,574 1,395 46,777 2,360 39,467 Purchases of minerals in place 416 11,059 1,213 156,515 2,637 29,651 Sales of minerals in place ... (499) (134) -- -- (182) (4,066) Production ................... (1,807) (26,990) (1,534) (28,083) (1,303) (33,171) -------- -------- -------- -------- -------- -------- End of year .................. 17,451 297,835 17,348 462,085 20,849 488,784 ======== ======== ======== ======== ======== ======== Proved Developed Reserves: Beginning of year ............ 14,379 184,123 12,290 200,349 12,212 315,779 ======== ======== ======== ======== ======== ======== End of year .................. 12,290 200,349 12,212 315,779 13,937 319,155 ======== ======== ======== ======== ======== ======== F-27 COMSTOCK RESOURCES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) The following table sets forth the standardized measure of discounted future net cash flows relating to proved reserves at December 31, 2001 and 2002: 2001 2002 ----------- ----------- (In thousands) Cash Flows Relating to Proved Reserves: Future Cash Flows ................................. $ 1,566,780 $ 3,088,593 Future Costs: Production .................................... (453,416) (646,018) Development and Abandonment ................... (156,906) (190,534) ----------- ----------- Future Net Cash Flows Before Income Taxes ......... 956,458 2,252,041 Future Income Taxes ............................... (177,551) (639,286) ----------- ----------- Future Net Cash Flows ............................. 778,907 1,612,755 10% Discount Factor ............................... (331,634) (691,640) ----------- ----------- Standardized Measure of Discounted Future Net Cash Flows $ 447,273 $ 921,115 =========== =========== The following table sets forth the changes in the standardized measure of discounted future net cash flows relating to proved reserves for the years ended December 31, 2000, 2001 and 2002: 2000 2001 2002 ----------- ----------- --------- (In thousands) Standardized Measure, Beginning of Year ........... $ 468,713 $ 1,288,764 $ 447,273 Net Change in Sales Price, Net of Production Costs 1,141,880 (1,298,306) 590,290 Development Costs Incurred During the Year Which Were Previously Estimated ....................... 17,340 26,627 35,272 Revisions of Quantity Estimates ................... (44,256) (21,342) (11,636) Accretion of Discount ............................. 51,506 173,747 54,068 Changes in Future Development and Abandonment Costs (41,525) (6,571) (12,052) Changes in Timing and Other ....................... (166,410) (141,844) (58,022) Extensions and Discoveries ........................ 375,632 86,026 150,317 Purchases of Reserves in Place .................... 62,621 120,147 105,206 Sales of Reserves in Place ........................ (3,355) -- (5,243) Sales, Net of Production Costs .................... (139,643) (135,272) (108,586) Net Changes in Income Taxes ....................... (433,739) 355,297 (265,772) ----------- ----------- --------- Standardized Measure, End of Year ................. $ 1,288,764 $ 447,273 $ 921,115 =========== =========== ========= The estimates of proved oil and gas reserves utilized in the preparation of the financial statements were estimated by independent petroleum consultants of Lee Keeling and Associates in accordance with guidelines established by the Securities and Exchange Commission and the Financial Accounting Standards Board, which require that reserve reports be prepared under existing economic and operating conditions with no provision for price and cost escalation except by contractual agreement. All of Comstock's reserves are located onshore in or offshore to the continental United States of America. F-28 COMSTOCK RESOURCES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) Future cash inflows are calculated by applying year-end prices adjusted for transportation and other charges to the year-end quantities of proved reserves, except in those instances where fixed and determinable price changes are provided by contractual arrangements in existence at year-end. Comstock's average yearend prices used in the reserve estimates were as follows: 2000 2001 2002 ------- ------- ------- Crude Oil (Per Barrel)................. $ 26.34 $ 18.73 $ 30.07 Natural Gas (Per Mcf).................. $ 10.51 $ 2.69 $ 5.04 Future development and production costs are computed by estimating the expenditures to be incurred in developing and producing proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. Future income tax expenses are computed by applying the appropriate statutory tax rates to the future pre-tax net cash flows relating to proved reserves, net of the tax basis of the properties involved. The future income tax expenses give effect to permanent differences and tax credits, but do not reflect the impact of future operations. F-29
Exhibit 4.3
Pursuant to the provisions of Articles 78.385 and 78.390 of the General Corporation Law of Nevada, the undersigned corporation adopts the following Articles of Amendment to Certificate of Voting Powers, Designations, Preferences and Relative Participating, Optional and other Special Rights of Series A 1999 Convertible Preferred Stock and Series B 1999 Non-Convertible Preferred Stock (the Certificate of Designation):
I
The name of the corporation is Comstock Resources, Inc.
II
The following Amendment to the Certificate of Designation was approved by all holders of shares of the Series A 1999 Convertible Preferred Stock:
1. Certain Definitions. The following term is added to Section 1 of the Certificate of Designation:
COC Cash Equivalent Amount means, with respect to any cash amount which may be paid to the holders of the Series 1999 Preferred Stock by way of dividend, redemption or other distribution, the number of shares (or fraction thereof) of Freely Tradeable Common Stock equal in value to such cash amount. For purposes of determining the COC Cash Equivalent Amount, the shares of Freely Tradeable Common Stock shall be valued at sixty-seven percent (67%) multiplied by the lower of (i) the 30-Day Average Price of the Common Stock or (ii) the 5-Day Average Price of the Common Stock; provided, that if the COC Cash Equivalent Amount cannot be ascertained by such methods, then the Freely Tradeable Common Stock shall be valued at sixty-seven percent (67%) multiplied by the lower of (i) the net book value per share of Common Stock, determined in accordance with generally accepted accounting principles, or (ii) the fair value per share of Common Stock determined pursuant to the Valuation Procedure. The COC Cash Equivalent Amount shall be determined as of the date immediately prior to the date of issuance of any such Freely Tradeable Common Stock.
2. Redemptions Upon Change of Control or Merger. Clause (a) of Section 4.2 of the Certificate of Designation is hereby amended to read in its entirety as follows:
(a)(i) Upon the sale, conveyance or disposition of all or substantially all of the assets of the Company, a merger, consolidation or other reorganization of the Company in a transaction or series of related transactions (except for a merger, consolidation or reorganization as to which Subsection 4.2(b) applies or after the consummation of which the stockholders of the Company own a majority of the voting securities of the surviving corporation or its parent corporation) each holder of the Series 1999 Preferred Stock shall have the right to require that the Company redeem all or any part of such holders Series 1999 Preferred Stock on a date that is no earlier than three Business Days following the date such holder notifies the Company of its election to cause the Company to redeem its Series 1999 Preferred Stock for cash out of legally available funds at a price per share equal to the Liquidation Amount. |
(ii) Upon a Change of Control, each holder of the Series 1999 Preferred Stock shall have the right to require that the Company redeem all or any part of such holders Series 1999 Preferred Stock on a date that is no earlier than three Business Days following the date such holder notifies the Company of its election to cause the Company to redeem its Series 1999 Preferred Stock. Redemptions pursuant to this Section 4.2(a)(ii) shall be paid, at the option of the Company (subject to the rights of holders under Section 4.5 below), (i) in cash for a price per share of Series 1999 Preferred Stock equal to the Liquidation Amount, (ii) with shares (whether whole or fractional) of Freely Tradeable Common Stock having a COC Cash Equivalent Amount equal to the Liquidation Amount or (iii) by a combination of cash and such shares; provided, that if such redemption shall be paid in a combination of cash and shares of Freely Tradeable Common Stock, all holders of the Series 1999 Preferred Stock shall receive cash and shares of Freely Tradeable Common Stock in the same ratio, except that the Company, at its option, may pay cash in lieu of fractional shares of Freely Tradeable Common Stock valued at the COC Cash Equivalent Amount. |
3. Redemption Notice. Section 4.5 of the Certificate of Designation is hereby amended to read in its entirety as follows:
The Company shall give written notice (the Redemption Notice) to each holder of the class of Series 1999 Preferred Stock to be redeemed by the Company at least 20 Business Days prior to the date (the Redemption Date) of any redemption required or permitted to be made by the Company under this Section 4, such notice to be addressed to each holder at the address as it appears on the stock transfer books of the Company. Such notice shall specify (i) the class or classes of Series 1999 Preferred Stock to be redeemed, (ii) the Redemption Date, (iii) the number of all shares of each class of the Series 1999 Preferred Stock of each holder to be redeemed and (iv) the amount and form or forms of payment therefor and the method of calculation thereof (the Redemption Amount). On or after each such Redemption Date, each holder of the Series 1999 Preferred Stock shall surrender a certificate or certificates representing the number of shares of each class of the Series 1999 Preferred Stock to be redeemed as stated in the Redemption Notice provided by the Company. If the Redemption Notice shall have been duly given, and if on the Redemption Date the Redemption Amount is either paid or made reasonably available for payment in immediately available funds, Common Stock or a combination thereof as provided herein to the holders of the Series 1999 Preferred Stock being redeemed, then notwithstanding that the certificates evidencing any of the Series 1999 Preferred Stock so called for redemption shall not have been surrendered, the dividends with respect to such shares shall cease to accrue after the Redemption Date and all rights with respect to such shares shall forthwith terminate after the Redemption Date, except only the right of the holders to receive the Redemption Amount without interest upon surrender of their certificate or certificates. Notwithstanding anything to the contrary contained herein, (i) with respect to any shares of Series 1999 Preferred Stock scheduled for redemption pursuant to a Redemption Notice, the holders of such shares may at any time prior to the Redemption Date, upon written notice to the Company as provided herein, exercise their right to convert all or any portion of such shares into Common Stock at the Conversion Price; and (ii) with respect to a Redemption Notice delivered pursuant to a Change of Control, if the Redemption Notice provides that the Redemption Amount will be paid in cash, the holders of shares of Series 1999 Preferred Stock shall have the option, upon written notice to the Company delivered prior to the Redemption Date, to require the Company to pay the Redemption Amount in shares of Freely Tradeable Common Stock valued at the COC Cash Equivalent Amount. For purposes of calculating the redemption payment of the Series B 1999 Preferred Stock to be made pursuant to this Section 4.5, the Series B 1999 Preferred Stock shall be deemed to have the same Conversion Price as the Series A 1999 Preferred Stock.
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III
In order to effectuate the Amendment to the Certificate of Designation, the Directors of the corporation adopted a resolution setting forth the Amendment proposed, declaring its advisability, and submitting it to approval by the holders of the Series 1999 Preferred Stock.
IV
The number of shares of Series 1999 Preferred Stock of the corporation outstanding and entitled to approve the Amendment at the time of adoption was 1,757,310 shares.
V
The number of shares approving the Amendment to the Certificate of Designation was 1,757,310. The number of shares voting against such Amendment was 0 and the number of shares abstaining was 0.
Dated: March 19, 2003
COMSTOCK RESOURCES, INC.
/s/
M. JAY ALLISON
M. Jay Allison
Chief Executive Officer
/s/
ROLAND O. BURNS
Roland O. Burns
Secretary
Exhibit 10.14
This Supplement to Exploration Agreement (the Supplement) is dated as of December 20, 2002 by and among Comstock Resources, Inc., a Nevada corporation (CRI), Comstock Offshore, LLC, a Nevada limited liability company (Comstock), Bois dArc Offshore, Ltd., a Texas limited partnership (Bois dArc Ltd.), Bois dArc Oil & Gas Company, LLC, a Texas limited liability company (Bois dArc LLC) (Bois dArc Ltd. and Bois dArc LLC are collectively referred to herein as (Bois dArc)), Wayne L. Laufer (Laufer) and Gary W. Blackie (Blackie).
WHEREAS, the parties hereto are parties to the 2001 Exploration Agreement effective as of April 1, 2001 (the Exploration Agreement) pursuant to which they have agreed to pursue a joint exploration program with respect to certain properties identified by Bois dArc;
WHEREAS, Bois dArc has identified certain properties to be acquired (the Murphy Acquisition) from Murphy Exploration and Production Company (Murphy); and
WHEREAS, the parties desire that the development of the properties from Murphy be subject to the terms of this Supplement rather than the Exploration Agreement, except as otherwise provided herein.
NOW, THEREFORE, in consideration of the mutual agreements herein contained and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereby agree as follows:
1. | Comstock shall pay 100% of the costs to acquire the properties from Murphy, which are more fully described on Schedule I hereto (the Subject Properties). Comstock shall then assign to Bois dArc at no cost a 10% interest of the working interest acquired from Murphy in the Subject Properties (including production, facilities, pipelines and responsibility for plugging and abandonment). Such assignment shall be effective the first day of the calendar month in which the Murphy Acquisition is closed. To the extent permitted, Comstock will grant to Bois dArc a license with respect to the seismic data, if any, acquired in the Murphy Acquisition. |
2. | Comstock shall also assign to Bois dArc an overriding royalty interest equal to 2% of 8/8ths proportionately reduced to the working interest acquired from Murphy in the Subject Properties. Such overriding royalty interest will be attributable to the leases and all production therefrom, with the exception of production from existing wellbores listed on Schedule II attached hereto. The overriding royalty interest will apply to all future wells drilled, sidetracked or deepened, including the sidetracking or deepening of any wellbore listed on Schedule II. (These projects will be undertaken in an effort to discover and produce unique reserves not obtainable from the wellbores listed on Schedule II.) The overriding royalty interest shall not apply to any such well drilled or sidetracked as a replacement well for any of the wellbores listed on Schedule II as long as such replacement wellbore stays within 100 feet horizontally of the wellbore being replaced. The overriding royalty interest will apply to any wells completed in or in the future recompleted into the proposed M-8 sand water flood reservoir. The assignment of any overriding royalty interest described in this Section 2 shall be effective the first day of the month in which the Murphy Acquisition is closed. |
3. | Bois dArc shall have the option to be assigned an additional 15% of the initial working interest acquired from Murphy once Comstock receives net proceeds from the Subject Properties that allow it to recover its investment in the acquisition, including all transaction costs and capital expenditures made on the Subject Properties, and earn a 15% annual return on its unrecovered investment in the Subject Properties. Such option shall be exercisable for a period of thirty (30) days commencing at the beginning of the month subsequent to the month that the payout described herein occurs. The annual return shall be calculated on a monthly basis from the date the acquisition closed based on Comstocks unrecovered investment multiplied by 15% per annum. The unrecovered investment shall be the total of (i) the purchase price paid for the Subject Properties after all price adjustments including pre-closing revenues and expenses and all transaction expenses plus (ii) any operating expenses and capital expenditures incurred with respect to the Subject Properties less (iii) net revenues received by Comstock from the Subject Properties. |
4. | Comstock will be named operator with respect to the Subject Properties. Comstock will open an office that will have the first level of responsibility and authority for the daily operation and development of the Subject Properties. Comstock agrees to locate such office in close proximity to Bois dArcs Houston office and provide Bois dArc full access at all times to the personnel and files in such office in connection with Bois dArcs ownership interest in the Subject Properties. Through December 31, 2006, Bois dArc will have the right to approve any personnel which Comstock desires to designate or hire to manage the Subject Properties (Comstock Personnel), including any independent third party consultants, contractors and field personnel. |
5. | In consideration for the interests being conveyed to Bois dArc pursuant to this Agreement, until December 31, 2006 Bois dArc agrees to provide at no cost to Comstock certain geological, engineering and other technical personnel (Bois dArc Personnel), which Bois dArc, in its sole and reasonable discretion, deems necessary for the operation and development of the Subject Properties. The Bois dArc Personnel will work in conjunction with the Comstock Personnel and be involved in all decisions relative to the management and operation of the Subject Properties. If the Bois dArc Personnel and Comstock Personnel are unable to agree upon the day-to-day management, field operations, long range planning, or budget/economic considerations and strategy, such issues will be resolved jointly by the chief executive officer of Comstock and Laufer and Blackie. |
6. | The South Pelto 19/20 acreage to be acquired or farmed-in from Murphy will be subject to the terms of the Exploration Agreement and not this Supplement, except that Comstock will be entitled to a 50% working interest in any prospect developed on such acreage. |
7. | The parties acknowledge and agree that the Subject Properties and any development with respect thereto shall not in any case be considered a Successful Prospect (as defined in the Exploration Agreement). |
8. | Comstock and Bois dArc agree to negotiate in good faith, subject to the approval of any affected third party working interest owner, a processing agreement similar to the Bois dArc South Timbalier Block 9/Ship Shoal Block 67 processing agreements to permit processing of production from blocks in close proximity to the Subject Properties which Comstock and/or Bois dArc now own or may hereafter acquire provided that such additional production to be processed will not impair the ability to process the production from the Subject Properties. |
9. | This Supplement shall be effective only upon the closing of the Murphy Acquisition, and if such acquisition is not consummated on or before February 28, 2003, this Supplement shall be null and void. |
10. | Comstock agrees that if it acquires any additional working interests in the Subject Properties (beyond the interests acquired in the Murphy Acquisition) during the twenty-four (24) month period following the date of this Supplement and on terms that are at least as favorable as those contained in the Murphy Acquisition, such additional interests shall be subject to the terms of this Supplement. |
11. | This Supplement shall not be amended unless in writing signed by all parties. |
12. | This Supplement shall be binding upon and inure to the benefit of the parties hereto and their respective successors, assigns and legal representatives. No party shall assign this Supplement or any rights hereunder without the prior written consent of the other party. Notwithstanding the foregoing, Bois dArc shall have the right to assign this Supplement and all rights and obligations hereunder to an entity controlled by Laufer and Blackie. For purposes hereof, an entity shall be controlled by Laufer and Blackie if Laufer and Blackie own, directly or indirectly, in the aggregate 100% of the ownership interest in such entity. |
13. | This Supplement may be executed in counterparts, each of which shall be deemed an original and together shall constitute one instrument. |
IN WITNESS WHEREOF, the undersigned have executed this Supplement as of the date written above.
COMSTOCK RESOURCES, INC. | ||||
By: /s/ M. JAY ALLISON | ||||
M. Jay Allison, President | ||||
COMSTOCK OFFSHORE, LLC | ||||
By: /s/ M. JAY ALLISON | ||||
M. Jay Allison, Manager | ||||
BOIS D' ARC OFF SHORE, LTD. | ||||
By: Bois d'Arc Oil & Gas Company, LLC | ||||
general partner | ||||
By: /s/ WAYNE L. LAUFER | ||||
Wayne L. Laufer, Manager | ||||
By: /s/ GARY BLACKIE | ||||
Gary Blackie, Manager | ||||
EXHIBIT 21
Name | Incorporation | Business Name | ||
---|---|---|---|---|
Comstock Oil & Gas, Inc. | Nevada | Comstock Oil & Gas, Inc. | ||
Comstock Oil & Gas Holdings, Inc.(1) | Nevada | Comstock Oil & Gas Holdings, Inc. | ||
Comstock Oil & Gas - Louisiana, LLC(2) | Nevada | Comstock Oil & Gas - Louisiana, LLC | ||
Comstock Offshore, LLC(3) | Nevada | Comstock Offshore, LLC | ||
DevX Energy, Inc.(1) | Delaware | DevX Energy, Inc. | ||
DevX Energy, Inc.(4) | Nevada | DevX Energy, Inc. | ||
DevX Operating Company(4) | Nevada | DevX Operating Company |
(1)
Subsidiary of Comstock Oil & Gas, Inc.
(2) Subsidiary
of Comstock Oil & Gas Holdings, Inc.
(3) Subsidiary of Comstock Oil & Gas Louisiana, LLC
(4) Subsidiary of DevX Energy, Inc.
Exhibit 23
The Board of Directors
and Stockholders of Comstock Resources, Inc.:
We consent to the incorporation by reference in registration statements (Nos. 33-20981, 33-88962, 333-45860 and 333-81483) on Forms S-3 and S-8 of Comstock Resources, Inc. and subsidiaries of our report dated March 19, 2003, with respect to the consolidated balance sheets of Comstock Resources, Inc. and subsidiaries as of December 31, 2002 and 2001, and the related consolidated statements of operations, stockholders equity and comprehensive income, and cash flows for each of the years in the three-year period ended December 31, 2002, which report appears in the December 31, 2002 annual report on Form 10-K of Comstock Resources, Inc. and subsidiaries. Our report dated March 19, 2003 contains an explanatory note that refers to a restatement of the consolidated financial statements as of December 31, 2001 and for the two-year period then ended. Our report also refers to a change in the Companys method of accounting for derivative instruments.
/s/ KPMG LLP
Dallas, Texas
March 26, 2003
Exhibit 99.1
In connection with the Annual Report of Comstock Resources, Inc. (the Company) on Form 10-K for the period ending December 31, 2002 as filed with the Securities and Exchange Commission on the date hereof (the Report), I, M. Jay Allison, Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the SarbanesOxley Act of 2002, that:
(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and |
(2) The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Company. |
/s/ M. JAY ALLISON
M. Jay Allison
Chief Executive Officer
March 26, 2003
Exhibit 99.2
In connection with the Annual Report of Comstock Resources, Inc. (the Company) on Form 10-K for the period ending December 31, 2002 as filed with the Securities and Exchange Commission on the date hereof (the Report), I, Roland O. Burns, Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes- Oxley Act of 2002, that:
(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and |
(2) The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Company. |
/s/ ROLAND O. BURNS
Roland O. Burns
Chief Financial Officer Officer
March 26, 2003