FORM 10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

(Mark One)
ý	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2002

o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File Number 0-20838

CLAYTON WILLIAMS ENERGY, INC.

(Exact name of registrant as specified in its charter)

Delaware		75-2396863
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

Six Desta Drive - Suite 6500 Midland, Texas		79705-5510
(Address of principal executive offices)		(Zip code)

Registrant’s telephone number, including area code: (915) 682-6324

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

None

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

Common Stock - $.10 Par Value

(Title of Class)

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 ý No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K ý

Indicate by check mark whether the registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2).

Yes o No ý

State the aggregate market value of the voting and non-voting common equity held by non-affiliates, computed by reference to the price at which common equity was last sold, as of the last business day of the registrant’s most recently completed second fiscal quarter. As of June 30, 2002: $54,862,525.

There were 9,312,766 shares of Common Stock, $.10 par value, of the registrant outstanding as of March 21, 2003.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the definitive proxy statement relating to the 2003 Annual Meeting of Stockholders, which will be filed with the

Commission not later than April 30, 2003, are incorporated by reference in Part III of this Form 10-K.

CLAYTON WILLIAMS ENERGY, INC

TABLE OF CONTENTS

Part I
Item 1.	Business
	General
	Company Profile
	Drilling, Exploration and Production Activities
	Marketing Arrangements
	Natural Gas Services
	Competition and Markets
	Regulation
	Environmental Matters
	Title to Properties
	Operational Hazards and Insurance
	Employees
	Officers and Directors
	Risk Factors

Item 2.	Properties
	Reserves
	Exploration and Development Activities
	Productive Well Summary
	Volumes, Prices and Production Costs
	Development, Exploration and Acquisition Expenditures
	Acreage
	Offices

Item 3.	Legal Proceedings

Item 4.	Submission of Matters to a Vote of Security Holders

Part II
Item 5.	Market for the Registrant’s Common Stock and Related Stockholder Matters
	Price Range of Common Stock
	Dividend Policy
	Stock Repurchase Program
	Securities Authorized for Issuance under Equity Compensation Plans

Item 6.	Selected Financial Data

Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations
	Overview
	Application of Critical Accounting Policies
	Liquidity and Capital Resources
	Results of Operations

Item 7A.	Quantitative and Qualitative Disclosure About Market Risks
	Oil and Gas Prices
	Interest Rates

Item 8.	Financial Statements and Supplementary Data

Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

Part III
Item 14.	Controls and Procedures
	Disclosure Controls and Procedures
	Changes in Internal Controls

Part IV
Item 15.	Exhibits, Financial Statement Schedules and Reports on Form 8-K
	Financial Statements and Schedules
	Reports on Form 8-K
	Exhibits

Glossary of Terms

Signatures

Certifications

This Annual Report on Form 10-K contains forward-looking statements that are based on our current expectations. Forward-looking statements include statements regarding our plans, beliefs or current expectations and may be signified by the words “could”, “should”, “expect”, “project”, “estimate”, “believe”, “anticipate”, “intend”, “budget”, “plan”, “forecast”, “predict” and other similar expressions. Forward-looking statements appear throughout this Form 10-K with respect to, among other things: profitability; planned capital expenditures; estimates of oil and gas production; future project dates; estimates of future oil and gas prices; estimates of oil and gas reserves; our future financial condition or results of operations; and our business strategy and other plans and objectives for future operations. Actual results in future periods may differ materially from those expressed or implied by such forward-looking statements because of a number of risks and uncertainties affecting our business, including those discussed in “Item 1 – Business – Risk Factors” and elsewhere in this report. We disclaim any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

Definitions of terms commonly used in the oil and gas industry and in this Form 10-K can be found in the Glossary of Terms.

PART I

Item 1 - Business

General

Clayton Williams Energy, Inc., incorporated in Delaware in 1991, is an independent oil and gas company engaged in the exploration for and production of oil and natural gas primarily in Texas, Louisiana, New Mexico and Mississippi. Unless the context otherwise requires, references to the “Company”, “CWEI”, “we”, “us” or “our” mean Clayton Williams Energy, Inc. and its consolidated subsidiaries. Our total estimated proved reserves at December 31, 2002 were 86.9 Bcf of natural gas and 11.9 million barrels of oil and natural gas liquids, and our estimated present value of proved reserves was $382.5 million. During 2002, we added proved reserves of 32.1 Bcfe through acquisitions and 4.8 Bcfe through extensions and discoveries. Revisions of previous estimates, resulting from well performance and higher year-end product prices, added net reserves of 19 Bcfe. CWEI held interests in 526 gross (380.5 net) producing oil and gas wells and owned leasehold interests in 1,117,854 gross (577,201 net) undeveloped acres at December 31, 2002.

Company Profile

Domestic Operations

We conduct all of our drilling, exploration and production activities in the United States. All of our oil and gas assets are located in the United States, and all of our revenues are derived from sales to customers within the United States.

Exploration Program

In recent years, we have aggressively sought to transform CWEI from a development driller of horizontal wells in the Austin Chalk (Trend) to an exploration company committed to generating and drilling exploratory prospects, primarily through advanced seismic technology. We are presently concentrating our efforts toward finding and producing oil and natural gas through exploration activities, principally in the Miocene Trend in south Louisiana, the Cotton Valley Reef Complex area of east central Texas and the Deep Knox play in the Black Warrior Basin of Mississippi.

Approximately 83% of our planned expenditures for 2003 relate to exploratory prospects, as compared to approximately 95% of actual expenditures in 2002 (excluding the Romere Pass acquisition) and 84% of actual expenditures in 2001. During 2002, we spent $55.6 million on exploratory prospects, including $26.7 million on seismic and leasing activities and $28.9 million on drilling activities. Exploratory prospects involve a higher degree of risk than developmental prospects. To offset the higher risk, we generally strive to achieve a higher reserve potential and rate of return on investments in exploratory prospects.

Acquisition and Divestitures of Proved Properties

In July 2002, we purchased all of the working interest in the Romere Pass Unit in Plaquemines Parish, Louisiana for $21.7 million, net of estimated closing costs. Also in July 2002, we sold our interests in certain wells in Wharton County, Texas for $3.2 million and reported a net gain on the sale of approximately $1.8 million. In 2001, we sold certain east Texas properties that we purchased, along with an affiliated limited partnership, in 1998 and recognized a $10.7 million gain on the sale, net to our interest. Although we are actively searching for similar opportunities to acquire and sell proved oil and gas properties, we cannot give any assurance that we will be successful in these endeavors during 2003.

Control of Operations

We seek to serve as operator of the wells in which we own a significant interest. As operator, we are in a better position to (i) control the timing and plans for future drilling and exploitation efforts, (ii) control costs of drilling, completing and producing oil and gas wells and (iii) market our oil and gas production. At December 31, 2002, we were the operator of 404 wells, or 77% of the 526 total productive wells in which we have a working interest. On an Mcfe basis, production from these operated wells represented 92% of our total net oil and gas production for 2002. Serving as operator, however, does not necessarily assure us of full control over drilling and completion activities. At times, the oil and gas industry experiences strong demand for drilling rigs and other well-related services, resulting in shortages in available equipment and trained personnel. In these cases, we may not be able to control the timing and cost of our future drilling and exploitation efforts to the extent desired due to such shortages.

Adaptable to Changes

We seek to adapt quickly to changes in economic conditions caused by fluctuations in product prices, results of exploration activities, competition for leases and drilling equipment, the availability of capital resources, and other events which require flexibility and prompt, decisive action. As economic conditions change, whether favorably or unfavorably, or as opportunities for growth in reserves and production are identified, we can make appropriate changes to our planned capital or exploratory expenditures. However, our ability to increase planned expenditures will be limited to the availability of our capital resources (see “Risk Factors” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations”).

Drilling, Exploration and Production Activities

Following is a discussion of our significant drilling, exploration and production activities during 2002, together with our plans for capital and exploratory expenditures in 2003. Under current economic conditions, we presently plan to spend approximately $73.7 million on exploration and drilling activities during 2003. We may increase or decrease our planned activities for 2003, depending upon drilling results, product prices, the availability of capital resources, and other factors affecting the economic viability of such activities.

South Louisiana

During 2000, we began establishing a new core area of operation in south Louisiana. We have assembled a team of experienced consulting geologists and geophysicists to identify drilling prospects in the Miocene Trend in south Louisiana based on enhanced 3-D seismic data and technology. Our focus in south Louisiana is the transition zone (swamps) in Plaquemines Parish that exists between dry land and the Gulf of Mexico. In 2001, we acquired 3-D seismic data covering over 3,100 square miles in this area, and in October 2002 we acquired the rights to data covering an additional 2,000 square miles. In July 2002, we also acquired a 100% working interest in the Romere Pass Unit, a unit in the Romere Pass Field of Plaquemines Parish with existing production and additional development and exploratory opportunities.

Exploration Activities

We spent $25.5 million in south Louisiana during 2002 on exploration activities, of which $10.2 million was spent on seismic and leasing activities, $13.6 million was spent on drilling and completion activities and $1.7 million was spent on constructing a natural gas pipeline.

Prior to 2002, we had drilled 13 exploratory wells in Plaquemines Parish, of which 6 gross (5.7 net) wells were completed as producers. The following table sets forth certain information about our well activities in south Louisiana subsequent to December 31, 2001.

Spud Date	Well Name	Working Interest		Current Status

February 2002	State Lease 16847 #2	94	%	Dry
May 2002	Chicago Mill and Lumber Co. #1	100	%	Dry
August 2002	State Lease 17269 #1	94	%	Dry
November 2002	State Lease 16901 #1	100	%	Producing
March 2003	State Lease 17521 #1	100	%	Dry
March 2003	State Lease 17569 #1	100	%	In progress

Delays in obtaining drilling permits from regulatory agencies limited our drilling activities in south Louisiana to the four wells in 2002. However, during this time, we were active in generating prospects for future drilling activities. We reprocessed and re-evaluated a large portion of our existing seismic data in an effort to improve the quality of information available to us, and began evaluating new seismic data obtained in October 2002.

In 2003, we plan to spend approximately $40.2 million in south Louisiana, excluding the Romere Pass Unit discussed below, on the following activities:

• $9.3 million to conduct seismic and leasing activities necessary to generate new exploratory prospects; and

• $30.9 million to conclude drilling and/or completion activities on in-progress wells at December 31, 2002, and drill approximately 17 new exploratory wells on existing prospects.

The 2003 plans include our participation in 2 gross (.3 net) non-operated wells which are currently in progress.

We do not attempt to forecast our potential success rate on exploratory drilling. Accordingly, the current estimate of expenditures in this area does not include any completion costs that may be incurred to complete successful exploratory wells.

Romere Pass Unit

In July 2002, we purchased all of the working interest in the Romere Pass Unit in Plaquemines Parish for total consideration of $21.7 million, net of closing adjustments. The purchase price consisted of $17.2 million cash, the assumption of abandonment obligations totaling $3.5 million, and the granting of an after-payout production payment in the amount of $1 million. In addition, we spent $2.5 million during 2002 on workover and drilling

activities. We plan to spend $12.4 million in 2003 to drill 3 developmental and 2 exploratory wells in this unit, and to conduct certain recompletion and workover operations.

Cotton Valley Reef Complex

Since 1997, we have been actively exploring for gas reserves in the Cotton Valley Reef Complex area primarily in Robertson County, Texas. Most of the prospects drilled in this area are on or adjacent to our Austin Chalk (Trend) acreage. As opposed to Trend formations, which are encountered at depths of 5,500 to 7,000 feet in this area, Cotton Valley Reefs are encountered at depths below 15,000 feet. During 2002, we spent $12.4 million in this area, of which $11.5 million was spent on drilling and completion activities, and $900,000 on leasing, seismic and other.

Prior to 2002, we had drilled 12 exploratory wells in the Cotton Valley Reef Complex area in which we owned 100% of the working interest. Of the 12 wells, 10 were completed as producers. In addition, we had participated in the drilling of 3 gross (.4 net) wells as a non-operator, all of which were dry holes. The following table sets forth certain information about our well activities in the Cotton Valley Reef Complex area subsequent to December 31, 2001.

Spud Date	Well Name	Working Interest		Current Status

September 2002	Cotropia Gas Unit #1	100	%	Producing
October 2002	Scamardo Gas Unit #1 RE	100	%	Dry
January 2003	Muse-Patranella Gas Unit #1	100	%	In progress

In 2003, we plan to spend approximately $9.3 million in the Cotton Valley Reef Complex area on the following activities:

• $2.8 million to conclude drilling and/or completion operations on the Cotropia Gas Unit #1 and the Scamardo Gas Unit #1 RE;

• $5 million to drill the Muse-Patranella Gas Unit #1, a 17,000-foot exploratory well located approximately one mile from our Lee Fazzino #2 well; and

• $1.5 million to conduct other exploration and leasing activities.

Depending on the results of the Muse-Patranella Gas Unit #1, we may drill additional wells in this area in 2003.

Mississippi/Alabama

During 2002, we entered into an agreement with an industry participant to explore and develop an area of mutual interest in the Black Warrior Basin of Mississippi, targeting the Deep Knox formations. Under the agreement, we purchased a 50% interest in approximately 43,000 acres within the area of mutual interest and acquired the rights to utilize certain 2-D seismic data and other geological and engineering data. We recorded a total cost of $9.1 million for the acreage covered by the agreement (as amended) of which $3.3 million was paid at closing, $3.8 million was paid during the first quarter of 2003 and $2 million will be paid during the second quarter of 2003.

In addition to the $9.1 million acquisition costs discussed above, we spent $2.6 million in the Black Warrior Basin in 2002 to acquire and process seismic data and to lease approximately 14,000 additional net acres in this area. We also spent $400,000 on other drilling activities related to non-operated wells in other areas of Mississippi and Alabama.

In 2003, we plan to spend $3.7 million in the Black Warrior Basin to conduct additional seismic and leasing activities and to drill 1 gross (.5 net) exploratory well in Webster County, Mississippi. The test well will be drilled to a depth of approximately 15,000 feet and is expected to begin drilling in the second quarter of 2003. In addition, we plan to spend $1 million primarily to participate in a non-operated well in another area of Mississippi.

Other Exploration and Development Activities

During 2002, we spent $3.1 million on leasing, recompletion and developmental drilling activities, primarily in the Austin Chalk (Trend). We also spent $5.6 million in 2002 on exploration activities in other areas, including:

• $2 million in west Texas to acquire acreage in the Longfellow Ranch area of Pecos County, Texas and to drill 3 gross (1.7 net) exploratory wells in the Delaware Basin of Ward County, Texas, all of which were dry holes;

• $1.2 million in the Northern San Joaquin Basin of California to conduct seismic and leasing activities;

• $1.1 million in the Chuar Basin of Arizona and Utah to acquire acreage; and

• $800,000 in Nevada to drill 1 gross (.35 net) non-operated well which was a dry hole.

In 2003, we plan to spend $1.6 million in the Austin Chalk (Trend) to conduct limited leasing, recompletion and developmental drilling activities, $1 million in New Mexico on developmental drilling and $4.5 million on various exploration activities in other areas, including 3 gross (2.25 net) exploratory wells in the Northern San Joaquin Basin, the Chuar Basin and Colorado.

Marketing Arrangements

We sell substantially all of our oil production under short-term contracts based on prices quoted on the New York Mercantile Exchange (“NYMEX”) for spot West Texas Intermediate contracts, less agreed-upon deductions which vary by grade of crude oil. The majority of our gas production is sold under short-term contracts based on pricing formulas which are generally market responsive. From time to time, we may also sell a portion of our gas production under short-term contracts at fixed prices. We believe that the loss of any of our oil and gas purchasers would not have a material adverse effect on our results of operations due to the availability of other purchasers.

Natural Gas Services

We own an interest in and operate natural gas service facilities in the states of Texas, Louisiana and Mississippi. These natural gas service facilities consist of interests in approximately 94 miles of pipeline, five treating plants (two of which were constructed to treat gas production from wells in our Cotton Valley Reef Complex area), one dehydration facility and five compressor stations. Most of our operated gas gathering and processing activities exist to facilitate the transportation and marketing of our operated oil and gas production.

Competition and Markets

Competition in all areas of our operations is intense. The oil and gas industry as a whole also competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers. Major and independent oil and gas companies and oil and gas syndicates actively bid for desirable oil and gas

properties, as well as for the equipment and labor required to operate and develop such properties. A number of our competitors have financial resources and acquisition, exploration and development budgets that are substantially greater than ours, which may adversely affect our ability to compete with these companies. Such companies may be able to pay more for productive oil and gas properties and exploratory prospects and to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit.

The market for our oil, gas and natural gas liquids production depends on factors beyond our control, including domestic and foreign political conditions, the overall level of supply of and demand for oil, gas and natural gas liquids, the price of imports of oil and gas, weather conditions, the price and availability of alternative fuels, the proximity and capacity of gas pipelines and other transportation facilities and overall economic conditions.

Regulation

Our oil and 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.

All of the states in which we operate generally require permits for drilling operations, drilling bonds and reports concerning operations and impose other requirements relating to the exploration and production of oil and gas. Such states also have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of oil and gas properties, the establishment of maximum rates of production from oil and gas wells and the spacing, plugging and abandonment of such wells. The statutes and regulations of certain states also limit the rate at which oil and gas can be produced from our properties.

The Federal Energy Regulatory Commission (“FERC”) regulates interstate natural gas transportation rates and service conditions, which affect the marketing of gas we produce, as well as the revenues we receive for sales of such production. Since the mid-1980s, the FERC has issued various orders that have significantly altered the marketing and transportation of gas. These orders resulted in a fundamental restructuring of interstate pipeline sales and transportation services, including the unbundling by interstate pipelines of the sales, transportation, storage and other components of the city-gate sales services such pipelines previously performed. These FERC actions were designed to increase competition within all phases of the gas industry. The interstate regulatory framework may enhance our ability to market and transport our gas, although it may also subject us to greater competition and to the more restrictive pipeline imbalance tolerances and greater associated penalties for violation of such tolerances.

Our sales of oil and natural gas liquids are not presently regulated and are made at market prices. The price we receive from the sale of those products is affected by the cost of transporting the products to market. The FERC has implemented regulations establishing an indexing system for transportation rates for oil pipelines, which, generally, would index such rate to inflation, subject to certain conditions and limitations. We are not able to predict with any certainty what effect, if any, these regulations will have on us, but, other factors being equal, the regulations may, over time, tend to increase transportation costs which may have the effect of reducing wellhead prices for oil and natural gas liquids.

Environmental Matters

Our operations pertaining to oil and gas exploration, production and related activities are subject to numerous and constantly changing federal, state and local laws governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may require the acquisition of certain permits prior to or in connection with drilling activities, restrict or prohibit the types,

quantities and concentration of substances that can be released into the environment in connection with drilling and production, restrict or prohibit drilling activities that could impact wetlands, endangered or threatened species or other protected areas or natural resources, require some degree of remedial action to mitigate pollution from former operations, such as pit cleanups and plugging abandoned wells, and impose substantial liabilities for pollution resulting from our operations. Such laws and regulations may substantially increase the cost of exploring for, developing, producing or processing oil and gas and may prevent or delay the commencement or continuation of a given project and thus generally could have a material adverse effect upon our capital expenditures, earnings, or competitive position. We believe that we are in substantial compliance with current applicable environmental laws and regulations, and the cost of compliance with such laws and regulations has not been material and is not expected to be material during the next fiscal year. Nevertheless, changes in existing environmental laws and regulations or in the interpretations thereof could have a significant impact on our operating, as well as the oil and gas industry in general. For instance, legislation has been proposed in Congress from time to time that would reclassify certain oil and gas production wastes as “hazardous wastes,” which reclassification would make exploration and production wastes subject to much more stringent handling, disposal and clean-up requirements. State initiatives to further regulate the disposal of oil and gas wastes and naturally occurring radioactive materials, if adopted, could have a similar impact on us.

The United States Oil Pollution Act of 1990 (“OPA ‘90”), and similar legislation enacted in Texas, Louisiana and other coastal states, addresses oil spill prevention and control and significantly expands liability exposure across all segments of the oil and gas industry. OPA ‘90 and such similar legislation and related regulations impose on us a variety of obligations on the Company related to the prevention of oil spills and liability for damages resulting from such spills. OPA ‘90 imposes strict and, with limited exceptions, joint and several liability upon each responsible party for oil removal costs and a variety of public and private damages.

The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), also known as the “Superfund” law, imposes liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of the disposal site or the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances at the site where the release occurred. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. We are able to control directly the operation of only those wells with respect to which we act as operator. Notwithstanding our lack of direct control over wells operated by others, the failure of an operator other than us to comply with applicable environmental regulations may, in certain circumstances, be attributed to us. We do not believe that we will be required to incur any material capital expenditures to comply with existing environmental requirements.

State water discharge regulations and federal waste discharge permitting requirements adopted pursuant to the Federal Water Pollution Control Act prohibit or are expected in the future to prohibit the discharge of produced water and sand and some other substances related to the oil and gas industry, into coastal waters. Although the costs to comply with such mandates under state or federal law may be significant, the entire industry will experience similar costs, and we do not believe that these costs will have a material adverse impact on our financial condition and operations.

Title to Properties

As is customary in the oil and gas industry, we perform a minimal title investigation before acquiring undeveloped properties. A title opinion is obtained prior to the commencement of drilling operations on such properties. We have obtained title opinions on substantially all of our producing properties and believe that we have satisfactory title to such properties in accordance with standards generally accepted in the oil and gas industry. Our properties are subject to customary royalty interests, liens incident to operating agreements, liens for current taxes

and other burdens that we believe do not materially interfere with the use of or affect the value of such properties. Substantially all of our oil and gas properties are currently mortgaged to secure borrowings under our secured bank credit facility and may be mortgaged under any future credit facilities entered into by us.

Operational Hazards and Insurance

Our operations are subject to the usual hazards incident to the drilling and production of oil and gas, such as blowouts, cratering, explosions, uncontrollable flows of oil, gas or well fluids, fires and pollution and other environmental risks. These hazards can cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage and suspension of operation.

We maintain insurance of various types to cover our operations with policy limits and retention liability customary in the industry. We believe the coverage and types of insurance are adequate. The occurrence of a significant adverse event, the risks of which are not fully covered by insurance, could have a material adverse effect on our financial condition and results of operations. We cannot give any assurances that we will be able to maintain adequate insurance in the future at rates we consider reasonable.

Employees

Presently, we have 116 full-time employees, none of whom is subject to a collective bargaining agreement. In our opinion, our employee relations are satisfactory.

Officers and Directors

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

Name	Age	Position With the Company

Clayton W. Williams	71	Chairman of the Board, President, Chief Executive Officer and Director
L. Paul Latham	51	Executive Vice President, Chief Operating Officer and Director
Mel G. Riggs	48	Senior Vice President – Finance, Secretary, Treasurer, Chief Financial Officer and Director
Jerry F. Groner	40	Vice President – Land and Lease Administration and Director
Robert C. Lyon	66	Vice President – Gas Gathering and Marketing
Patrick C. Reesby	50	Vice President – New Ventures
T. Mark Tisdale	46	Vice President and General Counsel
Michael L. Pollard	53	Vice President – Accounting
Stanley S. Beard	62	Director
Robert L. Parker	79	Director
Jordan R. Smith	68	Director

Risk Factors

There are many factors that affect our business and our results of operations, some of which are beyond our control. The following is a description of some of the important factors that may cause results of operations in future periods to differ materially from those currently expected or desired.

Oil and gas prices are volatile and could adversely affect our revenues, cash flow, liquidity and reserve estimates.

Historically, the markets for oil and gas have been volatile, and they are likely to continue to be volatile. Significant changes in oil and gas prices may result from relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty and other factors that are beyond our control. We cannot predict, with any degree of certainty, future oil and natural gas prices. Changes in oil and natural gas prices significantly affect our revenues, operating results, profitability and the value of our oil and gas reserves. Those prices also affect the amount of cash flow available for capital expenditures, our ability to borrow money or raise additional capital and the amount of oil and natural gas that we can produce economically. The amount we can borrow under a line of credit we have established with a group of banks (called a “Credit Facility”) is subject to periodic redeterminations based in part on current prices for oil and natural gas at the time of the redetermination.

Changes in oil and gas prices impact both our estimated future net revenue and the estimated quantity of proved reserves. Price increases may permit additional quantities of reserves to be produced economically, and price decreases may render uneconomic the production of reserves previously classified as proved. Thus, we may experience material increases and decreases in reserve quantities solely as a result of price changes and not as a result of drilling or well performance.

We attempt to optimize the price we receive for our oil and gas production while maintaining a prudent hedging program to mitigate our exposure to declining product prices. This strategy means that within the framework of a comprehensive hedging program, we sometimes terminate a hedge when we believe that market factors indicate there could be an increase in product prices that we would not realize with the hedge in place. While we attempt to make informed market decisions on the termination of hedges, this strategy may sometimes expose us to downside risk that would not have existed otherwise.

A fixed-price derivative entered into as an effective hedge may, however, adversely affect our liquidity if the derivative is “out of the money”, meaning that the market price of the hedged item exceeds the fixed sell price of the derivative. In this case, we may be required to provide credit support (a “Margin Call”) to the counterparty to the extent that the mark-to-market of the derivative exceeds specified credit limits. See “Liquidity and Capital Resources – Uncertainties Regarding Liquidity and Capital Resources.”

Our level of indebtedness may adversely affect operations.

As of December 31, 2002, our borrowing base under the Credit Facility was $110 million and our outstanding indebtedness was $93 million. Our level of debt affects our operations in several ways, including the following:

• A portion of our cash flow from operations must be used to make interest payments;

• We may not have sufficient funds available through the Credit Facility and from our cash flow from operations to fund capital expenditures;

• A high level of debt affects our flexibility and planning for or reacting to changes in market conditions;

• Our leveraged financial position may make us more vulnerable to adverse economic and industry conditions;

• A high level of debt may make it more difficult for us to remain in compliance with the covenants under the Credit Facility.

The borrowing base under the Credit Facility is periodically redetermined by the banks based upon an evaluation of our oil and gas reserves. If our indebtedness is in excess of the borrowing base upon a redetermination, we could be forced to repay a portion of our bank debt. We may not have sufficient funds to make those repayments. In addition, a higher level of debt increases the risk that we may default on our debt obligations, giving the banks the right to foreclose on our oil and gas properties, thereby threatening our financial viability. Our ability to meet our debt obligations and to reduce our level of debt depends on our future performance. General economic conditions and financial, business and other factors affect our operations and future performance, and many of these factors are beyond our control.

Our focus on exploration activities subjects us to greater risk.

In recent years, we have changed the focus of our operations from development drilling to generating and drilling exploratory prospects. For 2003, approximately 83% of our planned capital expenditures relate to exploratory prospects. Exploration activities have greater risk than development activities. Development activities relate to increasing oil or natural gas production from an area with producing wells through drilling additional wells, working over and recompleting existing wells and other production enhancement techniques. Exploration activities involve the drilling of wells in areas where there is little or no known production. Exploration projects are identified through subjective analysis of geological and geophysical data, including the use of 3-D seismic and other available technology. By comparison, the identification of development prospects is significantly based upon existing production surrounding or adjacent to the proposed drilling site.

Because our focus is on exploration activities, we have a greater risk of drilling dry holes or not finding oil and natural gas that can be produced economically. The seismic data and other technology we use does not allow us to know with certainty prior to drilling a well whether oil or natural gas is present or can be produced economically. In 2002, four of the six wells drilled in our core areas of south Louisiana and Cotton Valley Reef Complex were dry holes. We cannot assure you that any of our future exploration efforts will be successful, and if such activities are unsuccessful, it will have a significant adverse affect on our operations and financial condition.

Estimates of oil and natural gas reserves are uncertain and inherently imprecise.

Estimates of our proved reserves and the estimated future net revenues from such reserves are based upon various assumptions including assumptions required by the SEC relating to oil and gas prices, drilling and operating expenses, and other matters. The process of estimating oil and gas reserves requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. The interpretation of such data is a subjective process dependent upon the quality of the data and the decision-making and judgment of reservoir engineers. Estimates prepared by different engineers or by the same engineers at different times may vary substantially. Therefore, the estimates of our oil and gas reserves are inherently imprecise.

Actual future production, oil and gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and gas reserves will most likely vary from the assumptions and estimates. Any significant variance could materially affect the estimated quantities and value of our oil and gas reserves, which in turn may adversely affect our cash flow, results of operations and the availability of capital resources. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and gas prices and other factors, many of which are beyond our control.

You should not assume that the present value of proved reserves is equal to the current fair market value of our estimated oil and gas reserves. In accordance with the requirements of the SEC, the estimated discounted future net cash flows from proved reserves are generally based on prices and costs as of the date of the estimate. Actual future prices and costs may be materially higher or lower than those as of the date of the estimate. The timing of both the production and the expenses with respect to the development and production of oil and gas properties will effect the timing of future net cash flows from proved reserves and their present value.

The estimated proved reserve information is based upon a reserve report prepared by independent engineers. From time to time, estimates of our reserves are also made by the banks in establishing the borrowing base under the Credit Facility and by our engineers for use in developing business plans and making various decisions. Such estimates may vary significantly and have a material effect upon our business decisions and available capital resources.

A significant portion of our proved reserves are concentrated in a few properties.

Our proved developed reserves are concentrated in a limited number of fields and properties. Our top six producing wells represent approximately 36% of our estimated proved reserves at December 31, 2002. In addition, approximately 89% of our estimated proved reserves are located in three geographic areas, the Austin Chalk (Trend), the Cotton Valley Reef Complex area and in south Louisiana. Such concentration of reserves makes us more susceptible to adverse developments with respect to any single well or area of operations and substantially dependent upon a few selected oil and gas properties. An adverse event related to a single well or geographic area may have a significant adverse effect on our reserves, production, cash flow and general financial condition.

We may not be able to replace production with new reserves.

In general, the volume of production from an oil and gas property declines as reserves related to that property are depleted. The decline rates depend upon reservoir characteristics. Historically, our oil and gas properties have had steep rates of decline and short estimated productive lives. While the average productive life of our reserves has improved slightly over the past two years, our oil and gas properties are generally considered short-lived reserves with an average productive life of approximately 5.9 years at December 31, 2002 (based upon 2002 production levels). Our oil and gas reserves will decline as they are produced unless we are able to conduct successful development and exploration activities or acquire properties with proved reserves. Because we are currently focused on exploration activities, our ability to replace produced reserves is subject to a higher level of risk than it was when we were heavily involved in developmental drilling in the Austin Chalk (Trend). On a percentage basis, acquisitions replaced 119% of 2002 net production, revisions of previous estimates replaced 70% and extensions and discoveries replaced 18%. We cannot assure you that we can successfully find and produce reserves economically or acquire additional proved reserves at acceptable costs in the future.

Our estimates and assumptions can have a significant impact on the application of our critical accounting policies.

We account for our oil and gas activities using the successful efforts method of accounting. This method requires us to expense, as incurred, geological and geophysical (G&G) costs and the costs of drilling unsuccessful exploratory wells. Because our focus is now primarily on exploration activities, many of the estimates and assumptions we use in the application of successful efforts method of accounting can significantly affect our profitability. These include estimates and assumptions regarding our oil and gas reserves and the related present value of their future net cash flows, estimates and assumptions regarding the value of our unproved properties, and judgments regarding the status of in-progress exploratory wells.

Generally accepted accounting principles do not require, or even permit, the restatement of previously issued financial statements due to changes in estimates. We are required to use our best judgment in making estimates and assumptions, taking into consideration the best and most current data available to us at the time of the estimate. At each accounting period, we make a new estimate using new data, and continue the cycle. You should be aware that estimates prepared at various times may be substantially different due to new or additional information. While an estimate made at one point in time may differ from an estimate made at a later date, both may be proper due to the differences in available information or assumptions. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Application of Critical Accounting Policies.”

We may not be able to fund our planned capital expenditures.

We have spent and will continue to spend a substantial amount of capital for the exploration, development, acquisition and production of oil and gas reserves. Without continuing to expend substantial capital in such activities, we will not be able to replace the production from our existing oil and gas reserves with new reserves. We anticipate that our capital expenditures for 2003 will be approximately $73.7 million. We believe that we will be able to fund such capital expenditures from cash flow from operations and availability under the Credit Facility. However, those capital resources may be limited and insufficient to fund our planned capital expenditures if there are decreases in oil and natural gas prices, reductions in anticipated production, operating or marketing difficulties and other factors, many of which are beyond our control. If cash flow from operations and funds available under the Credit Facility are insufficient to fund our planned capital expenditures, we may be required to either reduce our level of capital expenditures, sell assets or seek alternative sources of financing. A reduction in our planned capital expenditures or a sale of assets may adversely affect our ability to replace depleted oil and gas reserves, reduce our ability to generate cash flow and adversely affect the borrowing base under the Credit Facility. We cannot assure you that alternative sources of financing, such as vendor financing or the issuance of other debt and equity securities, will be available on terms acceptable to us.

Our business is subject to certain credit risks.

We sell our oil and natural gas production to various customers, serve as operator in the drilling, completion and operation of oil and gas wells, and enter into derivatives with various counterparties. As appropriate, we obtain letters of credit to secure amounts due from our principal oil and gas purchasers and follow other procedures to monitor credit risk from joint owners and derivatives counterparties. Except for the loss reported in 2001 in connection with the financial failure of Enron North America Corp., a derivatives counterparty (see Note 5 to the accompanying consolidated financial statements), we have not experienced any significant credit losses. We cannot assure you that we will not suffer any economic loss related to credit risks in the future.

We are primarily controlled by our principal stockholder.

Clayton W. Williams beneficially owns, either individually or through his affiliates, approximately 50% of the outstanding shares of our common stock. Mr. Williams is also our Chairman of the Board and Chief Executive Officer. As a result, Mr. Williams has significant influence in matters voted on by our shareholders and in management decisions. Mr. Williams effectively controls the election of our Board members through his ownership of our common stock. Mr. Williams actively participates in all facets of our business and has a significant impact on both our business plan and daily operations.

The loss of key personnel could adversely affect our ability to operate.

We depend, and will continue to depend in the foreseeable future, on the services of our officers and key employees with extensive experience and expertise in evaluating and analyzing producing oil and gas properties and drilling prospects, maximizing production from oil and gas properties and marketing oil and gas production. Our ability to retain our officers and key employees is important to our continued success and growth. The unexpected loss of the services of one or more of these individuals could have a detrimental effect on our business.

Our business is subject to many operational risks that may cause production or transportation difficulties and may result in significant liabilities.

Our success is significantly affected by risks associated with our drilling and other operational activities. We do not conduct drilling operations ourselves, but contract with independent drilling companies. Costs of drilling differ greatly depending upon demand for drilling rigs and any difficulties encountered during drilling. These costs directly affect our profitability. Perhaps the most significant drilling risk is the risk that no oil or gas will be found that can be produced economically. If we are not successful in finding oil or gas when drilling, or if drilling costs are significantly higher than projected, it will adversely affect our financial results.

Our production and other operations, and the transportation of our production by others, also involve a number of hazards and risks such as fires, natural disasters, explosions, blowouts and spills. These hazards and risks may result in property damage or personal injury and may cause operations to be suspended. We maintain insurance coverage that we consider adequate and customary in the oil and gas industry. However, we are not fully insured against some of these risks, either because the insurance is not available or because of high premium costs. If a significant accident or other event happens and is not fully covered by insurance, it could adversely affect our financial condition and operations.

Some of our competitors have substantially greater resources which may give them a competitive advantage over us.

We have substantial competition in acquiring seismic data, leasehold acreage and proved properties, marketing oil and gas, and employing trained personnel. Many of our competitors have substantially larger financial resources, staffs and facilities. If we directly compete against one of those larger companies in attempting to acquire oil and gas properties or hiring or retaining experienced and skilled personnel, we may be at a disadvantage and may be unsuccessful.

We are subject to complex government laws and regulation, including environmental regulations, that may result in increased expenses and exposure to liability.

Our operations are affected from time to time in varying degrees by political developments and federal, state and local laws and regulations. In particular, oil and gas production, operations and economics are or have been significantly affected by price controls, taxes and other laws. 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, financial condition or results of operations.

Specifically, our operations are subject to complex and constantly changing environmental laws and regulations adopted by federal, state and local governmental authorities. We believe that compliance with those laws has not significantly affected our operations to-date other than to cause delays in our drilling schedule. If we discharge oil, gas or other pollutants into the air, soil or water, we may incur significant liabilities to the government and third parties. Our results of operations and financial condition may be adversely affected by existing or future environmental laws or regulations.

Item 2 - Properties

Our properties consist primarily of oil and gas wells and our ownership in leasehold acreage, both developed and undeveloped. At December 31, 2002, we had interests in 526 gross (380.5 net) oil and gas wells and owned leasehold interests in 1,117,854 gross (577,201 net) undeveloped acres.

Reserves

The following table sets forth certain information as of December 31, 2002 with respect to our estimated proved oil and gas reserves, present value of proved reserves and standardized measure of discounted future net cash flows.

	Proved Developed				Proved
	Producing		Nonproducing		Undeveloped		Total
	(Dollars in thousands)

Gas (MMcf)	65,682		10,542		10,688		86,912
Oil and natural gas liquids (MBbls)	8,473		876		2,535		11,884
Total (MMcfe)	116,520		15,798		25,898		158,216
Present value of proved reserves	$	295,415	$	32,431	$	54,672	$	382,518
Standardized measure of discounted future net cash flows							$	293,698

The following table sets forth certain information as of December 31, 2002 regarding our proved oil and gas reserves in each of our principal producing areas.

	Proved Reserves					Present Value of Proved Reserves		Percentage of Present Value of Proved Reserves
	Oil (a) (MBbls)	Gas (MMcf)	Total Gas Equivalent (MMcfe)	Percent of Total Gas Equivalent		Present Value of Proved Reserves		Percentage of Present Value of Proved Reserves
						(In thousands)

Trend	7,297	5,135	48,917	30.9	%	$	100,644	26.3	%
Cotton Valley Reef Complex	—	45,613	45,613	28.8	%	129,675		33.9	%
Louisiana	2,674	29,874	45,918	29.0	%	114,671		30.0	%
New Mexico / West Texas	1,762	4,204	14,776	9.4	%	30,042		7.8	%
Other	151	2,086	2,992	1.9	%	7,486		2.0	%
Total	11,884	86,912	158,216	100.0	%	$	382,518	100.0	%

(a) Includes natural gas liquids.

The estimates of proved reserves at December 31, 2002 and the present value of proved reserves were derived from a report prepared by Williamson Petroleum Consultants, Inc., independent petroleum engineers. Estimated recoverable proved reserves have been determined without regard to any economic impact that may result from our hedging activities. These calculations were prepared using standard geological and engineering methods generally accepted by the petroleum industry and in accordance with SEC financial accounting and reporting standards. The estimated present value of proved reserves does not give effect to indirect expenses such as general and administrative expenses, debt service and future income tax expense or to depletion, depreciation and amortization.

In accordance with applicable financial accounting and reporting standards of the SEC, the estimates of our proved reserves and the present value of proved reserves set forth herein are made using oil and gas sales prices estimated to be in effect as of the date of such reserve estimates and are held constant throughout the life of the

properties. Estimated quantities of proved reserves and their present value are affected by changes in oil and gas prices. The prices utilized for the purposes of estimating our proved reserves and the present value of proved reserves as of December 31, 2002 were $28.98 per Bbl of oil and natural gas liquids and $4.44 per Mcf of gas, as compared to $17.92 per Bbl of oil and $2.64 per Mcf of gas as of December 31, 2001. We estimate that a $1.00 per Bbl change in oil price and a $.50 per Mcf change in gas price from those utilized in calculating the present value of proved reserves would change the present value by $7.1 million and $31.3 million, respectively.

There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves and their present value, and in projecting future rates of production and timing of development expenditures, including many factors beyond our control. The reserve information shown is estimated. Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data, the precision of the engineering and geological interpretation, and judgment. As a result, estimates of different engineers often vary. The estimates of reserves, future cash flows and present value are based on various assumptions, including those prescribed by the SEC, and are inherently imprecise. Actual future production, cash flows, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates. Also, the use of a 10% discount factor for reporting purposes may not necessarily represent the most appropriate discount factor, given actual interest rates and risks to which our business or the oil and natural gas industry in general are subject. See “Risk Factors.”

Since January 1, 2002, we have not filed an estimate of our net proved oil and gas reserves with any federal authority or agency other than the SEC.

Exploration and Development Activities

We drilled, or participated in the drilling of, the following numbers of wells during the periods indicated.

	Year Ended December 31,
	2002		2001		2000
	Gross	Net	Gross	Net	Gross	Net
	(Excludes wells in progress at the end of any period)
Development Wells:

Oil	3	.8	28	17.5	41	33.0
Gas	—	—	5	2.2	11	1.7
Dry	1	.9	—	—	1	.4
Total	4	1.7	33	19.7	53	35.1

Exploratory Wells:

Oil	—	—	1	.2	1	.5
Gas	—	—	18	14.6	8	5.3
Dry	9	4.9	14	9.8	10	4.8
Total	9	4.9	33	24.6	19	10.6

Total Wells:

Oil	3	.8	29	17.7	42	33.5
Gas	—	—	23	16.8	19	7.0
Dry	10	5.8	14	9.8	11	5.2
Total	13	6.6	66	44.3	72	45.7

The information contained in the foregoing table should not be considered indicative of future drilling performance, nor should it be assumed that there is any necessary correlation between the number of productive wells drilled and the amount of oil and gas that may ultimately be recovered by us.

We do not own any drilling rigs, and all of our drilling activities are conducted by independent drilling contractors.

Productive Well Summary

The following table sets forth certain information regarding our ownership, as of December 31, 2002, of productive wells in the areas indicated.

	Oil		Gas		Total
	Gross	Net	Gross	Net	Gross	Net

Trend	303	233.1	27	17.3	330	250.4
New Mexico / West Texas	66	40.8	12	1.3	78	42.1
Louisiana	34	31.7	35	30.9	69	62.6
Cotton Valley	—	—	11	10.1	11	10.1
Other	7	5.5	31	9.8	38	15.3
Total	410	311.1	116	69.4	526	380.5

We seek to serve as operator of the wells in which we own a significant interest. As operator of a well, we are able to manage drilling and production operations as well as other matters affecting the production and sale of oil and gas. In addition, we receive fees from other working interest owners for the operation of the wells. At December 31, 2002, we were the operator of 404 wells, or 77% of the 526 total wells in which we have a working interest. On an Mcfe basis, production from these operated wells represented 92% of our total net oil and gas production for 2002.

Volumes, Prices and Production Costs

The following table sets forth certain information regarding the production volumes of, average sales prices received from, and average production costs associated with our sales of oil and gas for the periods indicated. Periods prior to 2002 have been adjusted to account for the sale of certain oil and gas properties in 2002 as discontinued operations (see Note 14 to the accompanying consolidated financial statements).

	Year Ended December 31,
	2002		2001		2000
Oil and Gas Production Data :
Gas (MMcf)	15,972		10,955		7,460
Oil (MBbls)	1,585		2,129		2,375
Natural gas liquids (MBbls)	227		249		220
Total (MMcfe)	26,844		25,223		23,030

Average Oil and Gas Sales Price (1):
Gas ($/Mcf)	$	3.01	$	4.25	$	3.69
Oil ($/Bbl)	$	22.00	$	25.47	$	29.44
Natural gas liquids ($/Bbl)	$	14.16	$	16.05	$	20.54

Average Production Costs
Lease operations ($/Mcfe)(2)	$	.81	$	.81	$	.79

(1) Includes effects of hedging transactions.

(2) Includes direct lifting costs (labor, repairs and maintenance, materials and supplies), workover costs, administrative costs of production offices, insurance and property and severance taxes.

Development, Exploration and Acquisition Expenditures

The following table sets forth certain information regarding the costs we incurred in our development, exploration and acquisition activities during the periods indicated.

	Year Ended December 31,
	2002		2001		2000
	(In thousands)
Property Acquisitions:
Proved	$	21,749	$	1,278	$	—
Unproved	20,311		14,418		11,131
Developmental Costs	4,964		19,692		36,510
Exploratory Costs	27,011		75,857		32,297
Total	$	74,035	$	111,245	$	79,938

Acreage

The following table sets forth certain information regarding our developed and undeveloped leasehold acreage as of December 31, 2002 in the areas indicated. This table excludes options to acquire leases and acreage in which our interest is limited to royalty, overriding royalty and similar interests.

	Developed Acres		Undeveloped Acres		Total Acres
	Gross	Net	Gross	Net	Gross	Net

Trend / Cotton Valley	111,719	107,930	61,875	39,234	173,594	147,164
Louisiana	7,112	6,380	33,186	30,176	40,298	36,556
Mississippi	40	40	115,461	39,466	115,501	39,506
West Texas / New Mexico	2,378	1,633	72,044	23,877	74,422	25,510
Other (1)	11,758	5,116	835,288	444,448	847,046	449,564
Total	133,007	121,099	1,117,854	577,201	1,250,861	698,300

(1) Net undeveloped acres are attributable to the following areas: Colorado – 227,406; Nevada – 162,950; Utah – 15,825; Alabama – 13,625; and other – 24,642.

Offices

We lease approximately 40,000 square feet of office space in Midland, Texas from a related partnership and approximately 7,000 square feet of office space in Houston, Texas.

Item 3 - Legal Proceedings

We are a defendant in a personal injury suit filed in the 38th Judicial District Court in Cameron Parish, Louisiana in 2002. The plaintiff, an employee of one of our subcontractors, claims he was injured while working on a barge drilling rig owned and operated by another subcontractor, Parker Drilling Company (“PDC”). PDC was also named as a defendant in the suit. Robert L. Parker is the Chairman of the Board of Directors of PDC and is a member of our Board of Directors. The plaintiff has not yet specified the amount of damages sought, and no interrogatories or other discovery has been conducted. Currently, there are uncertainties concerning the extent of our insurance coverage. Our insurance company is providing defense under a reservation of rights pending resolution of these uncertainties. The plaintiff’s employer is subject to the terms of an agreement with us in which it agrees to indemnify us from damages resulting from injuries to its employees. PDC is seeking indemnification from us for any damages resulting from the fault or negligence of PDC under the terms of our drilling contract with PDC.

Due to these uncertainties, we are currently unable to determine our financial exposure, if any, in this matter. We have filed an answer denying liability and intend to vigorously defend this suit.

We are a defendant in a suit filed in the 82nd Judicial District Court in Robertson County, Texas in January 2003 by lessors of the lease on which our Lee Fazzino #1 and Lee Fazzino #2 wells were drilled. The plaintiffs allege that we formed the Lee Fazzino Unit #1, a 320-acre unit that pooled various leases, including the plaintiffs’ lease, in bad faith. The plaintiffs are seeking to have the unit declared to be null and void, with the effect being that the plaintiffs, and certain non-participating royalty owners claiming through the plaintiffs’ lease, are entitled to 100% of the royalties from both wells. If the plaintiffs are successful, our ability to collect all the royalties previously paid to the pooled royalty owners is uncertain, and our net revenue interest in the wells will be reduced from 76.8% to 75%. We are currently unable to determine our financial exposure, if any, in this matter. We deny all claims and intend to vigorously defend this suit.

In addition, we are a defendant in several lawsuits that have arisen in the ordinary course of business. While the outcome of these lawsuits cannot be predicted with certainty, management does not expect any of these to have a material adverse effect on our consolidated financial condition or results of operations.

Item 4 - Submission of Matters to a Vote of Security Holders

No matter was submitted to a vote of our security holders during the fourth quarter of our fiscal year ended December 31, 2002.

PART II

Item 5 - Market for the Registrant’s Common Stock and Related Stockholder Matters

Price Range of Common Stock

Our Common Stock is quoted on the Nasdaq Stock Market’s National Market under the symbol “CWEI”. As of December 31, 2002, there were approximately 1,500 beneficial stockholders as reflected in security position listings. The following table sets forth, for the periods indicated, the high and low sales prices for our Common Stock, as reported on the Nasdaq National Market:

	High		Low
Year Ended December 31, 2002:

Fourth Quarter	$	12.69	$	8.00
Third Quarter	11.84		7.45
Second Quarter	15.00		10.89
First Quarter	13.71		8.89

Year Ended December 31, 2001:

Fourth Quarter	$	15.85	$	8.78
Third Quarter	16.95		8.10
Second Quarter	22.35		14.90
First Quarter	29.75		16.75

The quotations in the table above reflect inter-dealer prices without retail markups, markdowns or commissions and may not necessarily reflect actual transactions.

Dividend Policy

We have not paid any cash dividends on our Common Stock, and our Board of Directors does not anticipate paying any cash dividends in the foreseeable future. The terms of our secured bank credit facility limit our payment of cash dividends during any fiscal year to a maximum of 50% of our net income during such period, assuming compliance with other terms in the loan agreement. Subject to the restrictions imposed by our lenders, future dividend policy will depend on a number of factors, including our future earnings, capital requirements, financial condition, future prospects and such other factors as the Board of Directors may deem relevant.

Stock Repurchase Program

In July 2002, our Board of Directors authorized the continuation of a stock repurchase program initiated in July 2000. Under this program, we are authorized to spend up to $3 million to repurchase shares of Common Stock on the open market at times and prices deemed appropriate by our management. This authorization expires in July 2004. Since initiation of this program in 2000, we have spent $1.4 million to repurchase and cancel 115,100 shares of Common Stock, of which 50,800 shares were repurchased during the year ended December 31, 2002 at an aggregate cost of $648,000.

Securities Authorized for Issuance under Equity Compensation Plans

The following table provides information regarding options or warrants authorized for issuance under our equity compensation plans as of December 31, 2002.

Plan Category	Number of securities to be issued upon exercise of outstanding options	Weighted average exercise price of outstanding options		Number of securities to be authorized for future issuance under equity compensation plans

Equity compensation plans approved by security holders (1)	698,850	$	12.33	858,066
Equity compensation plans not approved by security holders	—	—		—
Total	698,850	$	12.33	858,066

(1) Consists of the 1993 Stock Compensation Plan and the Outside Directors Stock Option Plan.

Item 6 - Selected Financial Data

The following table sets forth selected consolidated financial data for CWEI as of the dates and for the periods indicated. The consolidated financial data for each of the years in the five-year period ended December 31, 2002 was derived from our audited financial statements. Periods prior to 2002 have been adjusted to account for the sale of certain oil and gas properties in 2002 as discontinued operations (see Note 14 to the accompanying consolidated financial statements). The data set forth in this table should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the accompanying consolidated financial statements, including the notes thereto.

	Year Ended December 31,
	2002			2001			2000			1999			1998
	(In thousands, except per share)
Statement of Operations Data:
Revenues:
Oil and gas sales	$	86,302		$	105,118		$	102,235		$	43,711		$	51,242
Natural gas services	5,568			8,820			6,682			3,684			3,795
Total revenues	91,870			113,938			108,917			47,395			55,037
Costs and expenses:
Lease operations	21,857			20,427			18,162			11,077			14,060
Exploration:
Abandonments and impairments	21,571			29,412			12,657			5,245			16,128
Seismic and other	8,578			12,868			7,953			1,418			4,501
Natural gas services	4,853			7,467			5,591			3,098			3,242
Depreciation, depletion and amortization	29,656			37,459			27,635			20,565			30,424
Impairment of property and equipment	349			18,170			—			81			8,493
General and administrative	8,615			7,456			5,951			3,929			4,299
Total costs and expenses	95,479			133,259			77,949			45,413			81,147
Operating income (loss)	(3,609		)	(19,321		)	30,968			1,982			(26,110		)
Other income (expense):
Interest expense	(4,006		)	(2,925		)	(2,310		)	(2,893		)	(2,384		)
Gain on sales of property and equipment	361			10,986			1,031			10,926			53
Change in fair value of derivatives	(1,581		)	2,227			—			—			—
Other income	1,755			66			269			474			85
Total other income (expense)	(3,471		)	10,354			(1,010		)	8,507			(2,246		)
Income (loss) before income taxes	(7,080		)	(8,967		)	29,958			10,489			(28,356		)
Income tax expense (benefit)	(1,742		)	(3,421		)	2,517			—			—
Income (loss) from continuing operations	(5,338		)	(5,546		)	27,441			10,489			(28,356		)
Cumulative effect of accounting change, net of tax	—			(164		)	—			—			—
Income (loss) from discontinued operations, including gain on sale of $1,196 in 2002, net of tax	1,335			406			372			265			(728		)
NET INCOME (LOSS)	$	(4,003	)	$	(5,304	)	$	27,813		$	10,754		$	(29,084	)
Net income (loss) per common share:
Basic:
Income (loss) from continuing operations	$	(.58	)	$	(.60	)	$	2.98		$	1.16		$	(3.18	)
Net income (loss)	$	(.43	)	$	(.58	)	$	3.02		$	1.19		$	(3.27	)
Diluted:
Income (loss) from continuing operations	$	(.58	)	$	(.60	)	$	2.88		$	1.15		$	(3.18	)
Net income (loss)	$	(.43	)	$	(.58	)	$	2.91		$	1.18		$	(3.27	)
Weighted average common shares outstanding:
Basic	9,241			9,219			9,211			9,005			8,905
Diluted	9,241			9,219			9,543			9,148			8,905
Other Data:
Net cash provided by operating activities	$	34,514		$	67,059		$	72,471		$	24,738		$	33,505

	December 31,
	2002			2001			2000			1999			1998
	(In thousands)
Balance Sheet Data:
Working capital (deficit)	$	(18,843	)	$	(17,779	)	$	(18,656	)	$	(6,649	)	$	(15,848	)
Total assets	218,992			183,279			164,864			109,166			120,653
Long-term debt	99,449			62,000			30,000			30,500			39,100
Stockholders’ equity	68,781			82,280			85,777			56,117			44,394

Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion is intended to provide information relevant to an understanding of our financial condition, changes in our financial condition and our results of operations and cash flows. Our consolidated financial statements and notes thereto included in this Form 10-K contain detailed information that should be considered in conjunction with this discussion.

Overview

In recent years, we have been aggressively seeking to transform CWEI from a development driller of horizontal wells in the Austin Chalk (Trend) to an exploration company committed to generating and drilling exploratory prospects, primarily through advanced seismic technology. We are now concentrating our efforts toward finding and producing oil and natural gas through exploration activities, principally in the Miocene Trend in south Louisiana, the Cotton Valley Reef Complex area of east central Texas and the Deep Knox play in the Black Warrior Basin of Mississippi.

Since our inception, we have accounted for our oil and gas activities using the successful efforts method of accounting. Under this method, geological and geophysical (G&G) costs and exploratory dry hole costs are expensed as incurred. Companies that emphasize developmental drilling are usually not affected to a large degree by these costs, making the successful efforts method a preferred accounting method for those companies. The alternative to the successful efforts method is the full cost method of accounting. Companies that are heavily involved in exploration activities most often select this method so they can capitalize G&G costs and exploratory dry hole costs, and thereby reduce the level of volatility in their reported earnings.

As long as we remain heavily involved in exploration activities, the successful efforts method of accounting may contribute to the volatility of our reported earnings. Through discussions like this, we will attempt to explain how the application of this method affects our financial statements, and assist you in making your analysis of our performance as compared to our peers. Following, you will find a detailed discussion about our critical accounting policies and the estimates and assumptions we must use to implement those accounting policies.

Application of Critical Accounting Policies

Summary

In this section, we will identify the critical accounting policies we follow in preparing our financial statements and disclosures. Many of these policies require us to make difficult, subjective and complex judgments in the course of making estimates of matters that are inherently imprecise. We will explain the nature of these estimates, assumptions and judgments, and the likelihood that materially different amounts would be reported in our financial statements under different conditions or using different assumptions.

The following table lists our critical accounting policies, the estimates and assumptions that can have a significant impact on the application of these accounting policies, and the financial statement accounts affected by these estimates and assumptions.

Accounting Policies	Estimates or Assumptions	Accounts Affected
Successful efforts accounting for oil and gas properties	· Reserve estimates · Valuation of unproved properties · Judgment regarding status of in-progress exploratory wells	· Oil and gas properties · Accumulated DD&A · Provision for DD&A · Impairment of unproved properties · Abandonment costs (dry hole costs)

Impairment of proved properties	· Reserve estimates and related present value of future net revenues	· Oil and gas properties · Accumulated DD&A · Impairment of proved properties

Valuation allowance for net deferred tax assets	· Estimates related to utilizing net operating loss (NOL) carryforwards	· Deferred tax assets · Deferred tax liabilities · Deferred income taxes

* DD&A means depreciation, depletion and amortization.

Significant Estimates and Assumptions

Oil and gas reserves

Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact manner. The accuracy of a reserve estimate depends on the quality of available geological and engineering data, the precision of the interpretation of that data, and judgment based on experience and training. As a result, estimates of different petroleum engineers often vary, and the variances can be material. Annually, we engage an independent petroleum engineering firm to evaluate our oil and gas reserves. As a part of this process, our internal reservoir engineer and the independent engineers exchange information and attempt to reconcile any material differences in estimates and assumptions. We believe this reconciliation process improves the accuracy of the reserve estimates by reducing the likelihood of a material error in judgment.

The techniques used in estimating reserves usually depend on the nature and extent of available data, and the accuracy of the estimates vary accordingly. As a general rule, the degree of accuracy of reserve estimates varies with the reserve classification and the related accumulation of available data, as shown in the following table.

Type of Reserves	Nature of Available Data	Degree of Accuracy
Proved undeveloped	Data from offsetting wells, seismic data	Least accurate

Proved developed nonproducing	Logs, core samples, well tests, pressure data	More accurate

Proved developed producing	Production history, pressure data over time	Most accurate

Assumptions as to future commodity prices and operating and capital costs also play a significant role in estimating oil and gas reserves and the estimated present value of the cash flows to be received from the future production of those reserves. Volumes of recoverable reserves are affected by the assumed prices and costs due to what is known as the economic limit (that point in the future when the projected costs and expenses of producing recoverable reserves exceed the projected revenues from the reserves). But more significantly, the estimated present value of future cash flows from the reserves is extremely sensitive to prices and costs, and may vary materially based on different assumptions. SEC financial accounting and reporting standards require that pricing parameters be tied to the price received for oil and natural gas on the effective date of the reserve report. This requirement can result in

significant changes from period to period given the volatile nature of oil and gas product prices, as illustrated in the following table.

	Proved Reserves		Average Price				Present Value of Proved Reserves
	Oil (a) (MMBbls)	Gas (Bcf)	Oil (a) ($/Bbl)		Gas ($/Mcf)		Present Value of Proved Reserves
							(In millions)
As of December 31:
2002	11.9	86.9	$	28.98	$	4.44	$	382.5
2001	9.3	75.0	$	17.92	$	2.64	$	186.9
2000	12.9	28.3	$	25.12	$	10.09	$	307.5

(a) Includes natural gas liquids

Valuation of unproved properties

Placing a fair market value on unproved properties (also known as prospects) is very subjective since there is no quoted market for undeveloped exploratory prospects. The negotiated price of any prospect between a willing seller and willing buyer depends on the specific facts regarding the prospect, including:

• The location of the prospect in relation to known fields and reservoirs, available markets and transportation systems for oil and gas production in the vicinity, and other critical services;

• The nature and extent of G&G data on the prospect;

• The terms of the leases holding the acreage in the prospect, such as ownership interests, expiration terms, delay rental obligations, depth limitations, drilling and marketing restrictions, and similar terms;

• The prospect’s risk-adjusted potential for return on investment, giving effect to such factors as potential reserves to be discovered, drilling and completion costs, prevailing commodity prices, and other economic factors; and

• The results of drilling activity in close proximity to the prospect that could either enhance or condemn the prospect’s chances of success.

Valuation allowance for NOL Carryforwards

In computing our provision for income taxes, we must assess the need for a valuation allowance on deferred tax assets, which consist primarily of net operating loss (“NOL”) carryforwards. For federal income tax purposes, these NOL carryforwards, if unused, expire 15 to 20 years from the year of origination. Generally, we assess our ability to fully utilize these carryforwards by comparing expected future book income to expected future taxable income based on the assumption that we will produce our existing reserves, as scheduled for production in our reserve report, under current economic conditions. If future book income does not exceed future taxable income by amounts sufficient to utilize NOLs before they expire, we must impair the resulting deferred tax asset. These computations are inherently imprecise due to the extensive use of estimates and assumptions. As a result, we may make additional impairments to allow for such uncertainties.

Effects of Estimates and Assumptions on Financial Statements

Generally accepted accounting principles do not require, or even permit, the restatement of previously issued financial statements due to changes in estimates. We are required to use our best judgment in making estimates and assumptions, taking into consideration the best and most current data available to us at the time of the estimate. At each accounting period, we make a new estimate using new data, and continue the cycle. You should be aware that estimates prepared at various times may be substantially different due to new or additional information. While an estimate made at one point in time may differ from an estimate made at a later date, both may be proper due to the differences in available information or assumptions. In this section, we will discuss the effects of different estimates on our financial statements.

Provision for DD&A

We compute our provision for DD&A on a unit-of-production method. Each quarter, we use the following formulas to compute the provision for DD&A for each of our producing properties (or appropriate groups of properties based on geographical and geological similarities):

• DD&A Rate = Unamortized Cost ¸ Beginning of Period Reserves

• Provision for DD&A = DD&A Rate ´ Current Period Production

Reserve estimates have a significant impact on the DD&A rate. If reserve estimates for a property or group of properties are revised downward in future periods, the DD&A rate for that property or group of properties will increase as a result of the revision. Alternatively, if reserve estimates are revised upward, the DD&A rate will decrease.

Impairment of Unproved Properties

Each quarter, we review our unproved oil and gas properties to determine if there has been, in our judgment, an impairment in value of each prospect that we consider individually significant. To the extent that the carrying cost of a prospect exceeds its estimated value, we make a provision for impairment of unproved properties, and record the provision as abandonments and impairments within exploration costs on our statement of operations. If the value is revised upward in a future period, we do not reverse the prior provision, and we continue to carry the prospect at a net cost that is lower than its estimated value. If the value is revised downward in a future period, an additional provision for impairment is made in that period.

Impairment of Proved Properties

Each quarter, we assess our producing properties for impairment. If we determine there has been an impairment in any of our producing properties (or appropriate groups of properties based on geographical and geological similarities), we will estimate the value of each affected property. In accordance with applicable accounting standards, the value for this purpose is a fair value instead of a standardized reserve value as prescribed by the SEC. We attempt to value each property using reserve classifications and pricing parameters similar to what a willing seller and willing buyer might use. These parameters may include escalations of prices instead of constant pricing, and they may also include the risk-adjusted value of reserves that do not qualify as proved reserves. To the extent that the carrying cost for the affected property exceeds its estimated value, we make a provision for impairment of proved properties. If the value is revised upward in a future period, we do not reverse the prior provision, and we continue to carry the property at a net cost that is lower than its estimated value. If the value is revised downward in a future period, an additional provision for impairment is made in that period. Accordingly, the carrying costs of producing properties on our balance sheet will vary from (and often will be less than) the present value of proved reserves for these properties.

Judgment Regarding Status of In-Progress Wells

On a quarterly basis, we review the status of each in-progress well to determine the proper accounting treatment under the successful efforts method of accounting. Cumulative costs on in-progress wells remain capitalized until their productive status becomes known. If an in-progress exploratory well is found to be unsuccessful (often referred to as a dry hole) prior to the issuance of our financial statements, we write-off all costs incurred through the balance sheet date to abandonments and impairments expense, a component of exploration costs. Costs incurred on that dry hole after the balance sheet date are charged to exploration costs in the period incurred.

Occasionally, we are unable to make a final determination about the productive status of a well prior to issuance of our financial statements. In these cases, we leave the well classified as in-progress until we have had sufficient time to conduct additional completion or testing operations and to evaluate the pertinent G&G and engineering data obtained. At the time when we are able to make a final determination of a well’s productive status, the well is removed from the in-progress status and the proper accounting treatment is recorded.

Valuation allowance for NOL carryforwards

Each quarter, we assess our ability to utilize NOL carryforwards. An increase in the valuation allowance from one period to the next will result in a decrease in our net deferred tax assets and a decrease in earnings. Similarly, a decrease in the valuation allowance will result in an increase in our net deferred tax assets and an increase in earnings.

This process requires estimates and assumptions which are complex and may vary materially from our actual ability to utilize NOL carryforwards in the future. Also, the current tax laws in this area are complicated due to the impact of alternative minimum tax on the utilization of NOL carryforwards. As a mitigating factor, as long as we are actively drilling for new production, we have some tax planning strategies available to us, such as elective capitalization of intangible drilling costs, to help us utilize these NOL carryforwards before they expire.

Liquidity and Capital Resources

Overview

Our primary financial resource is our base of oil and gas reserves. We pledge our producing oil and gas properties to secure a line of credit, called a Credit Facility, with a group of banks. The banks establish a borrowing base by making an estimate of the collateral value of our oil and gas properties. We borrow funds on the Credit Facility as needed to supplement our operating cash flow as a financing source for our capital expenditure program. Our capital expenditure program is dependent upon the level of product prices and the success of our exploration program in replacing our existing oil and gas reserves. If product prices decrease, our operating cash flow may decrease and the banks may require additional collateral or reduce our borrowing base, thus reducing funds available to fund our capital expenditure program. The effects of product prices on cash flow can be mitigated through the use of commodity derivatives. See “Quantitative and Qualitative Disclosure About Market Risks – Oil and Gas Prices”). If our exploration program does not replace our oil and gas reserves, we may also suffer a reduction in our operating cash flow and access to funds under the Credit Facility. Under extreme circumstances, product price reductions or exploration drilling failures could allow the banks to seek to foreclose on our oil and gas properties, thereby threatening our financial viability.

In this section, we will describe our current plans for capital spending, identify the capital resources available to finance our capital spending, and discuss certain factors that can affect our liquidity and capital resources.

Capital Expenditures

We presently plan to spend approximately $73.7 million on exploration and development activities during 2003, as summarized by area in the following table.

	Planned Expenditures for 2003
	Total		Percent of Total
	(In thousands)

South Louisiana	$	52,600	71	%
Cotton Valley Reef Complex	9,300		13	%
Mississippi	4,700		6	%
Other	7,100		10	%
	$	73,700	100	%

Approximately 83% of the planned expenditures relate to exploratory prospects. Exploratory prospects involve a higher degree of risk than developmental prospects. To offset the higher risk, we generally strive to achieve a higher reserve potential and rate of return on investments in exploratory prospects. You need to be aware

that actual expenditures during 2003 may be substantially higher or lower than these estimates since our plans for exploration and development activities may change during the year. We do not attempt to forecast our success rate on exploratory drilling. Accordingly, these current estimates do not include any costs we may incur to complete our successful exploratory wells and construct the required production facilities for these wells. Also, we are actively searching for other opportunities to increase our oil and gas reserves, including the evaluation of new prospects for exploratory and developmental drilling activities and potential acquisitions of proved oil and gas properties. Other factors, such as prevailing product prices and the availability of capital resources, could also increase or decrease the ultimate level of expenditures during 2003.

Credit Facility

We rely heavily on the Credit Facility for both our short-term liquidity and our long-term financing needs. The funds available to us at any time under this Credit Facility are limited to the amount of the borrowing base established by the banks. As long as we have sufficient availability under the Credit Facility to meet our obligations as they come due, we have sufficient liquidity.

At the beginning of 2002, we had an outstanding balance under the Credit Facility of $62 million, and the borrowing base was $85 million, leaving $23 million of availability. During 2002, we generated cash flow from operating activities of $34.5 million, received $7.6 million from the sales of property and equipment, and spent $71.6 million on capital expenditures and other investments which was financed primarily by borrowing $31 million on the Credit Facility. Also during 2002, the banks increased the borrowing base to $110 million. The outstanding balance on the Credit Facility at December 31, 2002 was $93 million, leaving $12.7 million available on the Credit Facility, after allowing for $4.3 million of outstanding letters of credit.

Using the Credit Facility for both our short-term liquidity and long-term financing needs can cause unusual fluctuations in our reported working capital, depending on the timing of cash receipts and expenditures. On a daily basis, we use most of our available cash to pay down our outstanding balance on the Credit Facility, which is classified as a non-current liability since we currently have no required principal reductions. As we use cash to pay a non-current liability, our reported working capital decreases. Conversely, as we draw on the Credit Facility for funds to pay current liabilities (such as payables for drilling and operating costs), our reported working capital increases. Also, volatility in oil and gas prices can cause significant fluctuations in reported working capital as we record changes in the fair value of derivatives from period to period. For these reasons, the working capital covenant related to the Credit Facility requires us to (i) include the amount of funds available under the Credit Facility as a current asset, and (ii) exclude current assets and liabilities related to the fair value of derivatives, when computing the working capital ratio at any balance sheet date.

Our reported working capital deficit at December 31, 2002 was $18.8 million, as compared to a deficit of $17.8 million at December 31, 2001. Giving effect to the above adjustments, our working capital for loan compliance purposes is a positive $6.8 million at December 31, 2002, as compared to a positive $1.5 million at December 31, 2001. Although working capital computed for loan compliance purposes differs from our working capital in accordance with generally accepted accounting principles (GAAP), the loan compliance working capital is useful in measuring our liquidity since it includes the resources available to us under the Credit Facility and negates the volatility in working capital caused by changes in fair value of derivatives. The following table reconciles our GAAP working capital to the working capital computed under the loan covenant at December 31, 2002 and 2001.

	2002			2001
	(In thousands)

Working capital (deficit) per GAAP	$	(18,843	)	$	(17,779	)
Add funds available under the Credit Facility	12,700			23,000
Exclude fair value of derivatives classified as current assets or current liabilities	12,917			(3,767		)
Working capital per loan covenant	$	6,774		$	1,454

The banks redetermine the borrowing base at least twice a year, in May and November, using the method described below. If at any time, the borrowing base is less than the amount of outstanding indebtedness, we will be required to (i) pledge additional collateral, (ii) prepay the excess in not more than five equal monthly installments, or (iii) elect to convert the entire amount of outstanding indebtedness to a term obligation based on amortization formulas set forth in the loan agreement. The loan agreement contains financial covenants that are computed quarterly and requires us to maintain minimum levels of working capital and cash flow. We were in compliance with all of the financial and non-financial covenants at December 31, 2002.

Uncertainties Regarding Liquidity and Capital Resources

We believe that the amount of funds available to us under the Credit Facility, when combined with our anticipated operating cash flow, will be sufficient to finance our capital expenditures and will provide us with adequate liquidity at least through the next twelve months. Although we believe the assumptions and estimates made in our forecasts are reasonable, uncertainties exist which could cause the borrowing base to be less than expected, cash flow to be less than expected, or capital expenditures to be more than expected. Any of these uncertainties could adversely affect our liquidity and could require us to reduce capital expenditures, sell assets, or seek alternative capital resources. Below is a discussion of certain significant factors that could adversely affect our liquidity.

Adverse changes in reserve estimates or commodity prices could reduce the borrowing base. The banks establish the borrowing base at least twice annually by preparing a reserve report using price-risk assumptions they believe are proper under the circumstances. Any adverse changes in estimated quantities of reserves, the pricing parameters being used, or the risk factors being applied, since the date of the last borrowing base determination, could lower the borrowing base under the Credit Facility.

Adverse changes in reserve estimates or commodity prices could reduce our cash flow from operating activities. We rely on estimates of reserves to forecast our cash flow from operating activities. If the production from those reserves is delayed or is lower than expected, our cash flow from operating activities may be lower than we anticipated. Commodity prices also impact our cash flow from operating activities. Based on December 31, 2002 reserve estimates, we project that a $1.00 drop in oil price and a $.50 drop in gas price would reduce our gross revenues in 2003 by $1.5 million and $11.1 million, respectively, before giving effect to hedging activities. See “Quantitative and Qualitative Disclosure About Market Risks – Oil and Gas Prices.”

Oil and gas reserves are depletable assets. We must replace our existing production with newly discovered reserves, or our borrowing base will decline. If we fail to find new reserves to add to the borrowing base, we may not have sufficient funds to continue drilling activities. Because our focus is on exploration activities, we have a greater risk of drilling dry holes or not finding oil and natural gas that can be produced economically. The seismic data and other technology we use does not allow us to know with certainty prior to drilling a well whether oil or natural gas is present or can be produced economically. In 2002, four of the six wells drilled in our core areas of south Louisiana and Cotton Valley Reef Complex area were dry holes. We cannot assure you that any of our future exploration efforts will be successful, and if such activities are unsuccessful, it will have a significant adverse affect on our operations and financial condition.

Adverse changes in the borrowing base may cause outstanding debt to equal or exceed the borrowing base. In this event, we will not be able to borrow any additional funds, and we will be required to repay the excess or convert the debt to a term note. Without availability under the Credit Facility, we may be unable to meet our obligations as they mature.

Delays in bringing successful wells on production may reduce our liquidity. As a general rule, we experience a significant lag time between the initial cash outlay on a prospect and the inclusion of any value for such prospect in the borrowing base under the Credit Facility. Until a well is on production, the banks may assign only a minimal borrowing base value to the well, and cash flow from the well are not available to fund our

operating expense. Delays in bringing wells on production may reduce the borrowing base significantly, depending on the amounts borrowed and the length of the delays.

We may not be able to comply with certain financial covenants in the Credit Facility if the borrowing base does not increase. The Credit Facility requires us to maintain a working capital average ratio of at least 1 to 1, as adjusted for availability under the Credit Facility and the exclusion of fair value of derivatives. We may not be able to maintain this ratio unless the borrowing base is increased due to new reserve additions, improved reserve performance, or favorable price changes.

Margin calls on derivative contracts could adversely affect our liquidity. Due to the highly volatile nature of the oil and gas commodity markets, a fixed-price derivative entered into as an effective hedge transaction may be “out of the money” at any time prior to its scheduled maturity, meaning that the current market price exceeds the fixed sell price of the derivative. The ISDA master agreement between us and our principal counterparty gives either party the right to request credit support (a “Margin Call”) to the extent that the fair value of the derivatives exceeds specified credit limits. Currently, our credit limit under the master agreement is $2 million. The counterparty issued Margin Calls totaling $4 million in 2002. Funds paid to the counterparty for Margin Calls are held for our account in interest-bearing trust accounts controlled by the counterparty.

At December 31, 2002, the fair value of the commodity derivatives with the counterparty was a liability of $11.9 million. Our sensitivity analysis indicates that a 10% increase in the underlying commodity prices would have increased this fair value to a liability of $16.9 million.

Based on current product prices, we have sufficient liquidity under our bank Credit Facility to cover our Margin Call obligations. However, in the event of a significant increase in the future market prices of oil and gas commodity derivatives, the availability of funds under the Credit Facility may be inadequate to cover future Margin Calls. If inadequate, we would be forced to obtain alternative sources of financing to avoid being in default with the counterparty. If future Margin Calls are not paid when due, the counterparty may liquidate our derivative positions and seek to collect from us the resulting monetary obligation to the counterparty.

Alternative Capital Resources

Although our base of oil and gas reserves, as collateral for the Credit Facility, has historically been our primary capital resource, we have in the past, and could in the future, use alternative capital resources, such as asset sales, vendor financing arrangements, and/or issuances of common stock through a secondary public offering or a rights offering. We could also issue subordinated debt or preferred stock in a public or a private placement if we choose to raise capital through either of these markets. While we believe we would be able to obtain funds through one or more of these alternatives, if needed, there can be no assurance that these capital resources would be available on terms acceptable to us.

Off-Balance Sheet Arrangement

In May 2001, we invested approximately $1.6 million as a limited partner in a partnership that purchased and operates two commercial office buildings in Midland, Texas, one of which is the location of our corporate headquarters. In addition, we loaned the partnership $100,000 against an unsecured note due in September 2002 and guaranteed up to $675,000 of partnership indebtedness. In August 2002, the partnership repaid the loan, and we were released from the guaranty. Our ownership interest in the partnership is 31.9% before payout (as defined in the partnership agreement) and 33.4% after payout. Substantially all of the partnership’s indebtedness is non-recourse, and we are not liable for any indebtedness of the partnership. An affiliate of Clayton W. Williams serves as general partner of the partnership. Since we do not manage or control the operations of the partnership or these buildings, we utilize the equity method of accounting for our investment in this limited partnership.

Contractual Obligations and Contingent Commitments

The following table summarizes our contractual obligations as of December 31, 2002 by payment due date.

	Payments Due by Period
	Total		2003		2004 - 2005		2006 - 2007		Thereafter
	(In thousands)

Contractual obligations:
Secured Bank Credit Facility	$	93,000	$	—	$	93,000	$	—	$	—
Vendor financing obligations	1,949		—		1,949		—		—
Abandonment obligations	3,500		663		612		612		1,613
Production payment obligations	1,000		—		464		536		—
Operating leases obligations	2,801		796		1,261		744		—
Total contractual obligations	$	102,250	$	1,459	$	97,286	$	1,892	$	1,613

The contractual obligations shown in the above table do not include any amounts that we may be required to record upon adoption in 2003 of Statement of Financial Accounting Standards No. 143 “Accounting for Asset Retirement Obligations.” See Note 2 to the accompanying consolidated financial statements.

In November 1999, we guaranteed loans from a bank to several of our employees, including Mr. Williams, in the aggregate amount of $834,000. The proceeds of these loans were used to finance the exercise of employee stock options. All of the employees except Mr. Williams have repaid the loans. During 2002, the Company obtained a release from the bank and is no longer contingently liable as a guarantor of these loans.

Results of Operations

The following table sets forth certain operating information for the periods presented. Periods prior to 2002 have been adjusted to account for the sale of certain oil and gas properties in 2002 as discontinued operations (see Note 14 to the accompanying consolidated financial statements).

	Year Ended December 31,
	2002		2001		2000
Oil and Gas Production Data:
Gas (MMcf)	15,972		10,995		7,460
Oil (MBbls)	1,585		2,129		2,375
Natural gas liquids (MBbls)	227		249		220
Total (MMcfe)	26,844		25,223		23,030

Average Oil and Gas Sales Prices (1):
Gas ($/Mcf)	$	3.01	$	4.25	$	3.69
Oil ($/Bbl)	$	22.00	$	25.47	$	29.44
Natural gas liquids ($/Bbl)	$	14.16	$	16.05	$	20.54

Operating Costs and Expenses ($/Mcfe Produced):
Lease operations	$	.81	$	.81	$	.79
Oil and gas depletion	$	1.05	$	1.44	$	1.16
General and administrative	$	.32	$	.30	$	.26

Net Wells Drilled (2):
Exploratory Wells	4.9		24.6		10.6
Developmental Wells	1.7		19.7		35.1

(1) Includes effects of hedging transactions.

(2) Excludes in-progress wells at the end of each period.

2002 Compared to 2001

The following discussion compares our results of operations for the year ended December 31, 2002 to the year ended December 31, 2001. All references to 2002 and 2001 within this section refer to the respective annual periods.

Revenues

Oil and gas sales decreased 18% from $105.1 million in 2001 to $86.3 million in 2002 due primarily to a 26% decline in oil production and a 29% decrease in the average gas prices received. Since most of our recent drilling activities have targeted gas reserves, a substantial portion of these decreases was offset by a 46% increase in gas production compared to 2001.

Costs and Expenses

Lease operations expenses increased 7% from $20.4 million in 2001 to $21.9 million in 2002, while oil and gas production on a Mcfe basis increased 6%. Production costs on a Mcfe basis remained constant at $.81.

Exploration costs totaled $30.1 million in 2002, as compared to $42.3 million in 2001, due to the following:

• $21.5 million of abandonments (dry hole costs) and unproved property impairments including $7.2 million related to the Cotton Valley Reef Complex area, $6.8 million related to prospects in Plaquemines Parish, Louisiana, $4.2 million in West Texas, $1.2 million in Nevada, and $500,000 in Mississippi; and

• $8.6 million of seismic and other exploration costs related primarily to the acquisition, processing and interpretation of 3-D seismic data including $4.9 million in south Louisiana, $1.2 million in California and $800,000 in Mississippi.

Since we follow the successful efforts method of accounting, our results of operations may be adversely affected during any accounting period in which seismic costs, exploratory dry hole costs, and unproved property impairments are expensed.

Depreciation, depletion and amortization (“DD&A”) expense decreased 21% from $37.5 million in 2001 to $29.7 million in 2002 due primarily to a 26% decrease in the average depletion rate. Under the successful efforts method of accounting, costs of oil and gas properties are amortized on a unit-of-production method based on estimated proved reserves. The average depletion rate per Mcfe decreased from $1.44 in 2001 to $1.05 in 2002. The depletion rates in 2001 were higher than normal due to the effects of lower product prices on reserve estimates, particularly on certain marginally economic properties in the Bossier Sands, Sweetlake and south Texas areas. The depletion rates in 2002 declined due to increases in reserve estimates caused primarily by a combination of higher product prices and significant improvements in production performance attributable to a Cotton Valley Reef Complex well.

We recorded a provision for impairment of property and equipment of $349,000 during 2002 compared to $18.2 million during 2001. The prospects affected by the impairment in 2002 are the Sweetlake area and one prospect in Mississippi. Both of the impairments were production performance related. During 2001, the areas affected by the impairment were the Bossier Sands area, the Sweetlake area and the south Texas area. The estimated market values for 2001 were adversely affected due to unfavorable changes in product prices and production performance.

General and administrative expenses (“G&A”), excluding non-cash stock-based employee compensation, increased 9% from $7.9 million in 2001 to $8.6 million in 2002 due primarily to increased legal costs applicable to a dispute with an insurer (settled during the third quarter of 2002) and other increases in insurance costs, franchise

taxes and professional fees. G&A expenses for 2002 include a non-cash credit (reduction of expense) of $32,000 for stock-based employee compensation required by Financial Accounting Standards Board Interpretation No. 44 (see Note 8 to the accompanying consolidated financial statements). A $414,000 credit was required for the 2001 period. Since the amount of this non-cash provision or credit is based on the quoted market value of our common stock, the future results of our operations may be subject to significant volatility.

Interest Expense and Other

Interest expense increased 38% from $2.9 million in 2001 to $4 million in 2002 due primarily to higher average levels of indebtedness under the Credit Facility, offset in part by lower effective interest rates. The average daily principal balance outstanding under the Credit Facility for 2002 was $84.8 million compared to $51.4 million in the 2001 period. The increased borrowings were used to finance our capital expenditures (see “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources”). The effective annual interest rate on bank debt, including bank fees and interest rate derivatives, during 2002 was 5.4% compared to 6.6% in 2001. Included in the computation of our effective annual interest rate are losses on interest rate derivatives of $927,000 in 2002 and $78,000 in 2001 (see Note 5 to the accompanying consolidated financial statements). Capitalized interest for 2002 was $600,000 compared to $523,000 in 2001.

We recorded a gain of $361,000 on the sales of property and equipment in 2002 as compared to $11 million in 2001. During 2001, we sold our oil and gas interests in three east Texas fields (including interests held through an affiliated limited partnership) for net proceeds of $15.9 million, resulting in a net gain of $10.7 million.

We reported a net loss on the change in fair value of derivatives of $1.6 million during the 2002 period compared to a $2.2 million net gain in 2001 in accordance with Statement of Financial Accounting Standards No. 133 “Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”), which we adopted effective January 1, 2001 (see Note 5 to the accompanying consolidated financial statements).

Other income for 2002 includes a $1.4 million gain on settlement of an insurance dispute (see Note 15 to the accompanying consolidated financial statements).

Income Taxes

During 2002, we recorded an income tax benefit of $1.7 million, as compared to a benefit of $3.4 million in 2001 (see Note 4 to the accompanying consolidated financial statements). To the extent we incur losses in future periods, it is unlikely that we will record a related tax benefit due to uncertainties about the realization of additional net deferred tax assets.

2001 Compared to 2000

The following discussion compares our results of operations for the year ended December 31, 2001 to the year ended December 31, 2000. All references to 2001 and 2000 within this section refer to the respective annual periods.

Revenues

Oil and gas sales increased 3% from $102.2 million in 2000 to $105.1 million in 2001 due primarily to a 47% increase in gas production, offset substantially by a 10% decrease in oil production and a 13% decline in the average oil price. The increase in gas production was attributable primarily to our Cotton Valley Reef Complex area. The oil production decline was due primarily to lower levels of drilling activity in the Austin Chalk (Trend).

Costs and Expenses

Lease operations expenses increased 12% from $18.2 million in 2000 to $20.4 million in 2001, while oil and gas production on an Mcfe basis increased 10%, resulting in a 3% increase in production costs on an Mcfe basis from $.79 in 2000 to $.81 in 2001.

Exploration costs totaled $42.3 million in 2001, as compared to $20.6 million in 2000, due to the following:

• $29.4 million in abandonments (dry hole costs) and unproved property impairments, including $15.5 million related to certain prospects in Plaquemines Parish, Louisiana, $3.8 million related to the Cotton Valley Reef Complex area, and $3.1 million related to certain prospects in the Sweetlake area; and

• $12.9 million of seismic and other exploration costs related primarily to the acquisition, processing and interpretation of 3-D seismic data in south Louisiana.

DD&A increased 36% from $27.6 million in 2000 to $37.5 million in 2001 due primarily to a 24% increase in the average depletion rate. Under the successful efforts method of accounting, costs of oil and gas properties are amortized on a unit-of-production method based on estimated proved reserves. The average depletion rate per Mcfe increased from $1.16 in 2000 to $1.44 in 2001 due primarily to higher finding costs and the effects of lower product prices on reserve estimates. A portion of the increase is attributable to areas affected by the SFAS 121 provision for impairment discussed below.

We recorded a provision for impairment of property and equipment of $18.2 million during 2001 to adjust the carrying value of certain proven properties to their estimated market value in accordance with Statement of Financial Accounting Standards No. 121 (see Note 12 to the accompanying consolidated financial statements), as compared to no provision during the 2000 period. The prospects affected by the impairment are the Bossier Sands area, the Sweetlake area and the south Texas area. The estimated market values of these prospects were adversely affected due to unfavorable changes in product prices and production performance.

G&A expenses, excluding non-cash stock-based employee compensation, increased 58% from $5 million in 2000 to $7.9 million in 2001 due primarily to higher personnel costs attributable to increased levels of drilling and operating activities, and bonuses paid during 2001 to certain officers and employees. G&A expenses during 2001 include a non-cash credit of $414,000 for stock-based employee compensation pursuant to the requirements of Financial Accounting Standards Board Interpretation No. 44 (see Note 8 to the accompanying consolidated financial statements). A $937,000 charge to expense was required during the 2000 period. Since the amount of this non-cash provision or credit is based on the quoted market value of our common stock, our future results of operations will be subject to significant volatility.

Interest Expense and Other

Interest expense increased 26% from $2.3 million in 2000 to $2.9 million in 2001 due primarily to higher average levels of indebtedness under the Credit Facility, offset in part by lower effective interest rates. The average daily principal balance outstanding under the Credit Facility for 2001 was $51.4 million compared to $30.3 million in 2000. The effective annual interest rate on bank debt, including bank fees and interest rate derivatives, was 6.6% compared to 9.2% in 2000. Included in the computation of our effective annual interest rate for 2001 is a loss on interest rate derivatives of $78,000 (see Note 5 to the accompanying consolidated financial statements). Capitalized interest in 2001 was $523,000 compared to $483,000 in 2000.

During 2001, we sold our oil and gas interests in three east Texas fields (including interests held through an affiliated limited partnership) for net proceeds of $15.9 million, resulting in a net gain of $10.7 million.

We reported a net gain on the change in fair value of derivatives of $2.2 million during the 2001 period in accordance with SFAS 133 (see Note 5 to the accompanying consolidated financial statements), which was adopted effective January 1, 2001. This gain consists of $7.7 million of net gains resulting primarily from certain gas swaps that were not designated as cash flow hedges under SFAS 133, offset in part by a charge of $5.5 million due to a default by Enron North America Corp., a counterparty to certain of our then-existing commodity derivates.

Income Taxes

During 2001, we recorded an income tax benefit of $3.4 million, as compared to a provision of $2.5 million in 2000 (see Note 4 to the accompanying consolidated financial statements).

Item 7A- Quantitative and Qualitative Disclosure About Market Risks

Our business is impacted by fluctuations in commodity prices and interest rates. The following discussion is intended to identify the nature of these market risks, describe our strategy for managing such risks, and to quantify the potential affect of market volatility on our financial condition and results of operations.

Oil and Gas Prices

Our financial condition, results of operations, and capital resources are highly dependent upon the prevailing market prices of, and demand for, 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. These factors include the level of global demand for petroleum products, foreign supply of oil and gas, the establishment of and compliance with production quotas by oil-exporting countries, weather conditions, the price and availability of alternative fuels, and overall economic conditions, both foreign and domestic. We cannot predict future oil and gas prices with any degree of certainty. Sustained weakness in oil and gas prices may adversely affect our financial condition and results of operations, and may also reduce the amount of net oil and gas reserves that we can produce economically. Any reduction in reserves, including reductions due to price fluctuations, can reduce the borrowing base under the Credit Facility and adversely affect our liquidity and our ability to obtain capital for our exploration and development activities. Similarly, any improvements in oil and gas prices can have a favorable impact on our financial condition, results of operations and capital resources. Based on December 31, 2002 reserve estimates, we project that a $1.00 drop in the price per Bbl of oil and a $.50 drop in the price per Mcf of gas would reduce our gross revenues for the year ending December 31, 2003 by $12.6 million, before giving effect to hedging activities.

From time to time, we utilize commodity derivatives, consisting primarily of swaps, to attempt to optimize the price received for our oil and natural gas production. When using swaps to hedge oil and natural gas production, we receive a fixed price for the respective commodity and pay a floating market price as defined in each contract (generally NYMEX futures prices), resulting in a net amount due to or from the counterparty. In the past we have also used collars which contain a fixed floor price (put) and ceiling price (call). If the market price for the respective commodity exceeds the call strike price or falls below the put strike price, then we receive the fixed price and pay the market price. If the market price is between the call and the put strike prices, then no payments are due from either party. The commodity derivatives we use differ from futures contracts in that there is not a contractual obligation that requires or permits the future physical delivery of the hedged products. We do not enter into commodity derivatives for trading purposes. In addition to commodity derivatives, we may, from time to time, sell a portion of our gas production under short-term contracts at fixed prices.

We attempt to optimize the price we receive for our oil and gas production while maintaining a prudent hedging program to mitigate our exposure to declining product prices. This strategy means that within the framework of a comprehensive hedging program, we sometimes terminate a hedge when we believe that market factors indicate that there could be an increase in product prices that we would not realize with the hedge in place. While we attempt to make informed market decisions on the termination of hedges, this strategy may sometimes expose us to downside risk that would not have existed otherwise.

The following summarizes information concerning our net positions in open commodity derivatives as of December 31, 2002.

	Oil Swaps			Gas Swaps
	Bbls	Average Price		MMBtu(a)	Average Price
Production Period:
1st Quarter 2003	160,000	$	25.27	2,275,000	$	3.55
2nd Quarter 2003	240,000	$	24.67	1,545,000	$	3.51
3rd Quarter 2003	120,000	$	24.20	1,810,000	$	3.58
4th Quarter 2003	80,000	$	24.20	1,720,000	$	3.80
Year 2003 (b)	600,000	$	24.68	7,350,000	$	3.61

(a) One MMBtu equals one Mcf at a Btu factor of 1,000.

(b) Based on current estimates, approximately 45% and 35% of our oil and gas production, respectively, for 2003 is subject to commodity derivatives.

In February 2003, we terminated, prior to their scheduled maturity, swaps covering 535,000 MMBtu of natural gas production for the month of April 2003 at a fixed price of $7.75 per MMBtu, which will require a $2.3 million payment to the counterparty in April 2003.

We use a sensitivity analysis technique to evaluate the hypothetical effect that changes in the market value of oil and gas may have on the fair value of our commodity derivatives. A 10% increase in the underlying commodity prices would have changed the fair value of our commodity derivatives at December 31, 2002 from a liability of $11.9 million to a liability of $16.9 million.

Interest Rates

All of our outstanding indebtedness at December 31, 2002 is subject to market rates of interest as determined from time to time by the banks pursuant to the Credit Facility. We may designate borrowings under the Credit Facility as either “Base Rate Loans” or “Eurodollar Loans.” Base Rate Loans bear interest at a fluctuating rate that is linked to the discount rates established by the Federal Reserve Board. Eurodollar Loans bear interest at a fluctuating rate that is linked to LIBOR. Any increases in these interest rates can have an adverse impact on our results of operations and cash flow. Prompted by declining interest rates during 2001, we entered into a LIBOR-based swap in November 2001 on $50 million of our indebtedness at a fixed price of 3.63% for two years.

We use a sensitivity analysis technique to evaluate the hypothetical effect that changes in market rates of interest may have on the fair value of our interest rate derivatives. A 10% decrease in the underlying market interest rates would have changed the fair value of our interest rate derivatives at December 31, 2002 from a liability of $1 million to a liability of $1.1 million.

Item 8 - Financial Statements and Supplementary Data

For the financial statements and supplementary data required by this Item 8, see the Index to Consolidated Financial Statements included elsewhere in this Form 10-K.

Item 9 - Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

PART III

The information called for by Item 10 – Directors and Executive Officers of the Registrant, Item 11 – Executive Compensation, Item 12 – Security Ownership of Certain Beneficial Owners and Management (other than information concerning securities authorized for issuance under equity compensation plans), and Item 13 – Certain Relationships and Related Transactions is incorporated by reference from our definitive proxy statement, which will be filed with the SEC no later than April 30, 2003. For information concerning securities authorized for issuance under equity compensation plans, see “Market for the Registrant’s Common Stock and Related Stockholder Matters – Securities Authorized for Issuance under Equity Compensation Plans” in Part II of this Form 10-K.

Item 14 - Controls and Procedures

Disclosure Controls and Procedures

In September 2002, our Board of Directors adopted a policy designed to establish disclosure controls and procedures that are adequate to provide reasonable assurance that we will be able to collect, process and disclose both financial and non-financial information, on a timely basis, in our reports to the SEC and other communications with our stockholders. Disclosure controls and procedures include all processes necessary to ensure that material information is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and is accumulated and communicated to our management, including our chief executive and chief financial officers, to allow timely decisions regarding required disclosures.

With respect to our disclosure controls and procedures:

• We have evaluated the effectiveness of our disclosure controls and procedures within 90 days prior to the filing of this report;

• This evaluation was conducted under the supervision and with the participation of our management, including our chief executive and chief financial officers; and

• It is the conclusion of our chief executive and chief financial officers that these disclosure controls and procedures operate such that material information flows to the appropriate collection and disclosure points in a timely manner and are effective in ensuring that material information is accumulated and communicated to our management and is made known to the chief executive and chief financial officers, particularly during the period in which this report was prepared, as appropriate to allow timely decisions regarding required disclosures.

Changes in Internal Controls

There were no significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date the controls were evaluated. No significant deficiencies or material weaknesses were identified in the evaluation of our internal controls and therefore no corrective actions have been taken.

PART IV

Item 15 - Exhibits, Financial Statement Schedules and Reports on Form 8-K

Financial Statements and Schedules

For a list of the consolidated financial statements filed as part of this Form 10-K, see the Index to Consolidated Financial Statements on page F-1.

No financial statement schedules are required to be filed as a part of this Form 10-K.

Reports on Form 8-K

During the quarter ended December 31, 2002, we filed the following Form 8-K:

• Form 8-K dated November 21, 2002 to provide public disclosure of certain financial and operating estimates in order to permit the preparation of models to forecast our operating results for the quarter and year ended December 31, 2002.

Exhibits

The following exhibits are filed as a part of this Report, with each exhibit that consists of or includes a management contract or compensatory plan or arrangement being identified with a “†”:

Exhibit Number		Description of Exhibit

**3.1		Second Restated Certificate of Incorporation of the Company, filed as Exhibit 3.1 to the Company’s Form S-2 Registration Statement, Registration No. 333-13441

**3.2		Certificate of Amendment of Second Restated Certificate of Incorporation of Clayton Williams Energy, Inc., filed as Exhibit 3.1 to the Company’s Form 10-Q for the period ended September 30, 2000

**3.3		Bylaws of the Company, filed as Exhibit 3.4 to the Company’s Form S-1 Registration Statement, Registration No. 33-43350

**10.1		Ninth Restated Loan Agreement dated July 18, 2002 among Clayton Williams Energy, Inc., Warrior Gas Co., CWEI Acquisitions, Inc., Romere Pass Acquisition Corp., Bank One, NA, Union Bank of California, N.A., and Bank of Scotland, filed as Exhibit 10.1 to the Company’s Form 10-Q for the period ended June 30, 2002

*10.2		First Amendment to Ninth Restated Loan Agreement dated August 9, 2002 among Clayton Williams Energy, Inc., et al and Bank One, NA, et al

**10.3†		1993 Stock Compensation Plan, filed as Exhibit 10.1 to the Company’s Form S-8 Registration Statement, Registration No. 33-68318

**10.4†		First Amendment to 1993 Stock Compensation Plan, filed as Exhibit 10.11 to the Company’s Form 10-K for the period ended December 31, 1995

Exhibit Number		Description of Exhibit

**10.5†		Second Amendment to the 1993 Stock Compensation Plan, filed as Exhibit 10.2 to the Company’s Form S-8 Registration Statement, Registration No. 33-68318

**10.6†		Third Amendment to 1993 Stock Compensation Plan, filed as Exhibit 10.4 to the Company’s Form S-8 Registration Statement, Registration No. 333-47232

**10.7†		Fourth Amendment to 1993 Stock Compensation Plan, filed as Exhibit 10.5 to the Company’s Form S-8 Registration Statement, Registration No. 333-47232

**10.8†		Outside Directors Stock Option Plan, filed as Exhibit 10.1 to the Company’s Form S-8 Registration Statement, Registration No. 33-68316

**10.9†		First Amendment to Outside Directors Stock Option Plan, filed as Exhibit 10.13 to the Company’s Form 10-K for the period ended December 31, 1995

**10.10†		Bonus Incentive Plan, filed as Exhibit 10.1 to the Company’s Form S-8 Registration Statement, Registration No. 33-68320

**10.11†		First Amendment to Bonus Incentive Plan, filed as Exhibit 10.9 to the Company’s Form 10-K for the period ended December 31, 1997

**10.12†		Amended and Restated 401(k) Plan & Trust, filed as Exhibit 10.15 to the Company’s Form 10-K for the period ended December 31, 1995

**10.13†		Second Amendment to Amended and Restated 401(k) Plan & Trust, filed as Exhibit 10.16 to the Company’s Form 10-K for the period ended December 31, 1995

**10.14†		Third Amendment to Amended and Restated 401(k) Plan & Trust, filed as Exhibit 10.17 to the Company’s Form 10-K for the period ended December 31, 1995

**10.15†		Executive Incentive Stock Compensation Plan, filed as Exhibit 10.1 to the Company’s Form S-8 Registration Statement, Registration No. 33-92834

**10.16†		First Amendment to Executive Incentive Stock Compensation Plan, filed as Exhibit 10.16 to the Company’s Form 10-K for the period ended December 31, 1996

**10.17		Consolidation Agreement dated May 13, 1993 among Clayton Williams Energy, Inc., Warrior Gas Co. and the Williams Entities, filed as Exhibit 10.1 to the Company’s Form S-1 Registration Statement, Registration No. 33-43350

**10.18		Amendment to Consolidation Agreement dated August 7, 2000 among Clayton Williams Energy, Inc., Warrior Gas Co., Clayton W. Williams, Jr. and the Williams Companies, filed as Exhibit 10.1 to the Company’s Form 10-Q for the period ended September 30, 2000

**10.19		Agreement dated April 23, 1993 between the Company and Robert C. Lyon, filed as Exhibit 10.42 to the Company’s Form S-1 Registration Statement, Registration No. 33-43350

**10.20		Service Agreement effective October 1, 1995 among Clayton Williams Energy, Inc. and certain Williams Entities, filed as Exhibit 10.23 to the Company’s Form 10-K for the period ended December 31, 1995

Exhibit Number		Description of Exhibit

**10.21†		East Texas/Chalk Working Interest Trust Agreement dated May 30, 2001, filed as Exhibit 10.21 to the Company’s Form 10-K for the period ended December 31, 2001

**10.22†		Louisiana Working Interest Trust Agreement dated May 30, 2001, filed as Exhibit 10.22 to the Company’s Form 10-K for the period ended December 31, 2001

**10.23†		New Mexico Working Interest Trust Agreement dated May 30, 2001, filed as Exhibit 10.23 to the Company’s Form 10-K for the period ended December 31, 2001

**10.24†		South Texas Working Interest Trust Agreement dated May 30, 2001, filed as Exhibit 10.24 to the Company’s Form 10-K for the period ended December 31, 2001

**10.25†		West Texas I Working Interest Trust Agreement dated May 30, 2001, filed as Exhibit 10.25 to the Company’s Form 10-K for the period ended December 31, 2001

**10.26†		West Texas II Working Interest Trust Agreement dated May 30, 2001, filed as Exhibit 10.26 to the Company’s Form 10-K for the period ended December 31, 2001

*10.27†		Agreement of Limited Partnership of CWEI South Louisiana I, L.P. dated October 1, 2002

*10.28†		Agreement of Limited Partnership of CWEI Cotton Valley I, L.P. dated October 1, 2002

*10.29†		Agreement of Limited Partnership of CWEI Romere Pass, L.P. dated October 1, 2002

**21		Subsidiaries of the Registrant, filed as Exhibit 21 to the Company’s Form 10-Q for the period ended June 30, 2002

*23.1		Consent of KPMG LLP

*23.2		Consent of Williamson Petroleum Consultants, Inc.

*24.1		Power of Attorney

*24.2		Certified copy of resolution of Board of Directors of Clayton Williams Energy, Inc. authorizing signature pursuant to Power of Attorney

*			Filed herewith
**			Incorporated by reference to the filing indicated
†			Identifies an Exhibit that consists of or includes a management contract or compensatory plan or arrangement.

GLOSSARY OF TERMS

The following are abbreviations and definitions of terms commonly used in the oil and gas industry and this Form 10-K.

3-D seismic. 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.

Bbl. One barrel, or 42 U.S. gallons of liquid volume.

Bcf. One billion cubic feet.

Bcfe. One billion cubic feet of natural gas equivalents.

Completion. The installation of permanent equipment for the production of oil or gas.

Credit Facility. A line of credit provided by a group of banks, secured by oil and gas properties.

DD&A. Refers to depreciation, depletion and amortization of the Company’s property and equipment.

Development well. 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. A well found to be incapable of producing hydrocarbons in sufficient quantities to justify completion as an oil or gas well.

Exploratory well. 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.

Extensions and discoveries. As to any period, the increases to proved reserves from all sources other than the acquisition of proved properties or revisions of previous estimates.

Gross acres or wells. Refers to the total acres or wells in which the Company has a working interest.

Horizontal drilling. A drilling technique that permits the operator to contact and intersect a larger portion of the producing horizon than conventional vertical drilling techniques and may, depending on the horizon, result in increased production rates and greater ultimate recoveries of hydrocarbons.

MBbls. One thousand barrels.

Mcf. One thousand cubic feet.

Mcfe. One thousand cubic feet of natural gas equivalents, based on a ratio of 6 Mcf for each barrel of oil, which reflects the relative energy content.

MMbtu. One million British thermal units. One British thermal unit is the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.

MMcf. One million cubic feet.

MMcfe. One million cubic feet of natural gas equivalents.

Natural gas liquids. Liquid hydrocarbons that have been extracted from natural gas, such as ethane, propane, butane and natural gasoline.

Net acres or wells. Refers to gross acres or wells multiplied, in each case, by the percentage working interest owned by the Company.

Net production. Oil and gas production that is owned by the Company, less royalties and production due others.

NYMEX. New York Mercantile Exchange, the exchange on which commodities, including crude oil and natural gas futures contracts, are traded.

Oil. Crude oil or condensate.

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

Present value of proved reserves. The present value of estimated future revenues to be generated from the production of proved reserves determined in accordance with 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 nonproperty related expenses such as general and administrative expenses, debt service, future income tax expense, or depreciation, depletion and amortization, and discounted using an annual discount rate of 10%.

Proved developed nonproducing reserves. Reserves that consist of (i) proved reserves from wells which have been completed and tested but are not producing due to lack of market or minor completion problems which are expected to be corrected and (ii) proved reserves currently behind the pipe in existing wells and which are expected to be productive due to both the well log characteristics and analogous production in the immediate vicinity of the wells.

Proved developed producing reserves. Proved reserves that can be expected to be recovered from currently producing zones under the continuation of present operating methods.

Proved developed reserves. The combination of proved developed producing and proved developed nonproducing reserves.

Proved reserves. 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. Proved 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.

Royalty. 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.

SEC. The United States Securities and Exchange Commission.

Standardized measure of discounted future net cash flows. The after-tax present value of proved reserves determined in accordance with SEC guidelines.

Undeveloped acreage. Leased acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas, regardless of whether such acreage contains proved reserves.

Working interest. 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 is entitled will be smaller than the share of costs that the working interest owner is required to bear to the extent of any royalty burden.

Workover. Operations on a producing well to restore or increase production.

SIGNATURES

In accordance with 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.

			CLAYTON WILLIAMS ENERGY, INC.
			(Registrant)


			By:	/s/ CLAYTON W. WILLIAMS *
				Clayton W. Williams
				Chairman of the Board, President and Chief Executive Officer

In accordance with 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.

Signature	Title	Date

/s/ CLAYTON W. WILLIAMS *	Chairman of the Board,	March 24, 2003
Clayton W. Williams	President and Chief Executive Officer and Director

/s/ L. PAUL LATHAM	Executive Vice President,	March 24, 2003
L. Paul Latham	Chief Operating Officer and Director

/s/ MEL G. RIGGS *	Senior Vice President -	March 24, 2003
Mel G. Riggs	Finance, Secretary, Treasurer, Chief Financial Officer and Director

/s/ JERRY F. GRONER *	Vice President – Land and	March 24, 2003
Jerry F. Groner	Lease Administration and Director

/s/ STANLEY S. BEARD *	Director	March 24, 2003
Stanley S. Beard

/s/ ROBERT L. PARKER *	Director	March 24, 2003
Robert L. Parker

/s/ JORDAN R. SMITH *	Director	March 24, 2003
Jordan R. Smith

*	By:	/s/ L. PAUL LATHAM
	L. Paul Latham
	Attorney-in-Fact

CERTIFICATION OF
CHIEF EXECUTIVE OFFICER
CLAYTON WILLIAMS ENERGY, INC.

CERTIFICATION

I, Clayton W. Williams, certify that:

1. I have reviewed this annual report on Form 10-K of Clayton Williams Energy, 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 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 the registrant’s board of directors (or persons performing the equivalent function):

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 24, 2003

/s/ Clayton W. Williams
Clayton W. Williams
Chief Executive Officer

CERTIFICATION OF
CHIEF FINANCIAL OFFICER
CLAYTON WILLIAMS ENERGY, INC.

CERTIFICATION

I, Mel G. Riggs, certify that:

1. I have reviewed this annual report on Form 10-K of Clayton Williams Energy, Inc.;

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;

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

Date: March 24, 2003

/s/ Mel G. Riggs
Mel G. Riggs
Chief Financial Officer

CLAYTON WILLIAMS ENERGY, INC.

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

Independent Auditors Report

Consolidated Balance Sheets

Consolidated Statements of Operations

Consolidated Statements of Stockholders’ Equity

Consolidated Statements of Cash Flows

Notes to Consolidated Financial Statements

F-1

INDEPENDENT AUDITORS REPORT

To the Board of Directors of Clayton Williams Energy, Inc.:

We have audited the accompanying consolidated balance sheets of Clayton Williams Energy, Inc. and subsidiaries as of December 31, 2001 and 2002, and the related consolidated statements of operations, stockholders’ equity, 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 Clayton Williams Energy, 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 5 of the consolidated financial statements, effective January 1, 2001, the Company changed its method of accounting for derivative instruments.

KPMG LLP

Dallas, Texas

February 28, 2003

F-2

CLAYTON WILLIAMS ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(Dollars in thousands)

	December 31,
	2002			2001
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	5,676		$	2,856
Accounts receivable:
Oil and gas sales, net	14,426			7,489
Joint interest and other, net	3,714			2,103
Affiliates	223			210
Inventory	2,141			2,663
Deferred income taxes	524			438
Fair value of derivatives	—			4,426
Prepaids and other	5,215			1,035
	31,919			21,220
PROPERTY AND EQUIPMENT
Oil and gas properties, successful efforts method	617,320			576,784
Natural gas gathering and processing systems	16,203			14,513
Other	11,918			11,370
	645,441			602,667
Less accumulated depreciation, depletion and amortization	(466,815		)	(443,307		)
Property and equipment, net	178,626			159,360
OTHER ASSETS
Deferred income taxes	6,594			401
Fair value of derivatives	—			505
Investments and other	1,853			1,793
	8,447			2,699
	$	218,992		$	183,279

LIABILITIES AND STOCKHOLDERS’ EQUITY

CURRENT LIABILITIES
Accounts payable:
Trade	$	22,440		$	28,742
Oil and gas sales	8,274			7,890
Affiliates	1,257			374
Fair value of derivatives	12,917			659
Accrued liabilities and other	5,874			1,334
	50,762			38,999
LONG-TERM DEBT	99,449			62,000

COMMITMENTS AND CONTINGENCIES

STOCKHOLDERS’ EQUITY
Preferred stock, par value $.10 per share; authorized - 3,000,000 shares; issued and outstanding - none	—			—
Common stock, par value $.10 per share; authorized - 30,000,000 shares; issued - 9,277,415 shares in 2002 and 9,246,066 shares in 2001	928			925
Additional paid-in capital	72,787			72,525
Retained earnings	3,016			7,019
Accumulated other comprehensive income (loss)	(7,950		)	1,811
	68,781			82,280
	$	218,992		$	183,279

The accompanying notes are an integral part of these consolidated financial statements.

F-3

CLAYTON WILLIAMS ENERGY, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share)

	Year Ended December 31,
	2002			2001			2000
REVENUES
Oil and gas sales	$	86,302		$	105,118		$	102,235
Natural gas services	5,568			8,820			6,682
Total revenues	91,870			113,938			108,917

COSTS AND EXPENSES
Lease operations	21,857			20,427			18,162
Exploration:
Abandonments and impairments	21,571			29,412			12,657
Seismic and other	8,578			12,868			7,953
Natural gas services	4,853			7,467			5,591
Depreciation, depletion and amortization	29,656			37,459			27,635
Impairment of property and equipment	349			18,170			—
General and administrative	8,615			7,456			5,951
Total costs and expenses	95,479			133,259			77,949
Operating income (loss)	(3,609		)	(19,321		)	30,968
OTHER INCOME (EXPENSE)
Interest expense	(4,006		)	(2,925		)	(2,310		)
Gain on sales of property and equipment	361			10,986			1,031
Change in fair value of derivatives	(1,581		)	2,227			—
Other	1,755			66			269
Total other income (expense)	(3,471		)	10,354			(1,010		)
Income (loss) before income taxes	(7,080		)	(8,967		)	29,958
Income tax expense (benefit)	(1,742		)	(3,421		)	2,517
Income (loss) from continuing operations	(5,338		)	(5,546		)	27,441
Cumulative effect of accounting change, net of tax	—			(164		)	—
Income from discontinued operations, including gain on sale of $1,196 in 2002, net of tax	1,335			406			372
NET INCOME (LOSS)	$	(4,003	)	$	(5,304	)	$	27,813
Net income (loss) per common share:
Basic:
Income (loss) from continuing operations	$	(.58	)	$	(.60	)	$	2.98
Net income (loss)	$	(.43	)	$	(.58	)	$	3.02

Diluted:
Income (loss) from continuing operations	$	(.58	)	$	(.60	)	$	2.88
Net income (loss)	$	(.43	)	$	(.58	)	$	2.91

Weighted average common shares outstanding:
Basic	9,241			9,219			9,211
Diluted	9,241			9,219			9,543

The accompanying notes are an integral part of these consolidated financial statements.

F-4

CLAYTON WILLIAMS ENERGY, INC.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(In thousands)

	Common Stock					Additional Paid-In Capital			Retained Earnings			Accumulated Other Compre- hensive Income (Loss)			Total Compre- hensive Income (Loss)


	No. of Shares		Par Value

BALANCE, December 31, 1999	9,168		$	917		$	70,690		$	(15,490	)	$	—

Issuance of stock through compensation plans	86		8			1,839			—			—
Net income	—		—			—			27,813			—
BALANCE, December 31, 2000	9,254		925			72,529			12,323			—

Net loss	—		—			—			(5,304		)	—			$	(5,304	)
Cumulative effect of accounting change	—		—			—			—			(186		)	(186		)
Change in fair value of cash flow derivatives	—		—			—			—			1,997			1,997
Total comprehensive income (loss)															$	(3,493	)
Issuance of stock through compensation plans	56		6			785			—			—
Repurchase and cancellation of common stock	(64	)	(6		)	(789		)	—			—
BALANCE, December 31, 2001	9,246		925			72,525			7,019			1,811

Net loss	—		—			—			(4,003		)	—			$	(4,003	)
Change in fair value of derivatives designated as cash flow hedges	—		—			—			—			(9,761		)	(9,761		)
Total comprehensive income (loss)															$	(13,764	)
Issuance of stock through compensation plans	82		8			905			—			—
Repurchase and cancellation of common stock	(51	)	(5		)	(643		)	—			—
BALANCE, December 31, 2002	9,277		$	928		$	72,787		$	3,016		$	(7,950	)

The accompanying notes are an integral part of these consolidated financial statements.

F-5

CLAYTON WILLIAMS ENERGY, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)

	Year Ended December 31,
	2002			2001			2000
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	(4,003	)	$	(5,304	)	$	27,813
Adjustments to reconcile net income (loss) to cash provided by operating activities:
Depreciation, depletion and amortization	29,656			37,459			27,635
Impairment of property and equipment	349			18,170			—
Exploration costs	21,571			29,412			12,657
Gain on sales of property and equipment	(361		)	(10,986		)	(1,031		)
Deferred income taxes	(1,742		)	(3,421		)	2,517
Non-cash employee compensation	(32		)	(414		)	937
Change in fair value of derivatives	2,172			(1,739		)	—
Non-cash effect of discontinued operations, including gain on sale, net of tax	(1,029		)	449			359
Cumulative effect of accounting change, net of tax	—			164			—
Other	869			458			399

Changes in operating working capital:
Accounts receivable	(8,561		)	10,013			(6,579		)
Accounts payable	(5,389		)	(7,429		)	12,473
Other	1,014			227			(4,709		)
Net cash provided by operating activities	34,514			67,059			72,471

CASH FLOWS FROM INVESTING ACTIVITIES
Additions to property and equipment	(71,635		)	(112,731		)	(72,584		)
Proceeds from sales of property and equipment	7,607			16,334			1,075
Other	(3		)	(1,545		)	3
Net cash used in investing activities	(64,031		)	(97,942		)	(71,506		)

CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt	32,949			32,000			—
Repayments of long-term debt	—			—			(500		)
Proceeds from sale of common stock	36			150			285
Repurchase and cancellation of common stock	(648		)	(795		)	—
Net cash provided by (used in) financing activities	32,337			31,355			(215		)

NET INCREASE IN CASH AND CASH EQUIVALENTS	2,820			472			750

CASH AND CASH EQUIVALENTS
Beginning of period	2,856			2,384			1,634
End of period	$	5,676		$	2,856		$	2,384

SUPPLEMENTAL DISCLOSURES
Cash paid for interest, net of amounts capitalized	$	3,995		$	2,946		$	2,434	.

The accompanying notes are an integral part of these consolidated financial statements.

F-6

CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Nature of Operations

Clayton Williams Energy, Inc. (a Delaware corporation) and its subsidiaries (collectively, the “Company”) is an independent oil and gas company engaged in the exploration for and development and production of oil and natural gas primarily in Texas, Louisiana, New Mexico and Mississippi. Approximately 50% of the Company’s common stock is beneficially owned by its Chairman of the Board and Chief Executive Officer, Clayton W. Williams (“Mr. Williams”). Oil and gas exploration and production is the only business segment in which the Company operates.

Substantially all of the Company’s oil and gas production is sold under short-term contracts which are market-sensitive. Accordingly, the Company’s financial condition, results of operations and capital resources are highly dependent upon prevailing market prices of, and demand for, oil and natural gas. These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond the control of the Company. These factors include the level of global demand for petroleum products, foreign supply of oil and gas, the establishment of and compliance with production quotas by oil-exporting countries, weather conditions, the price and availability of alternative fuels, and overall economic conditions, both foreign and domestic.

2. Summary of Significant Accounting Policies

Estimates and Assumptions

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management of the Company 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 results could differ materially from those estimates. The accounting policies most affected by management’s estimates and assumptions are as follows:

• The reliance on estimates of proved reserves to compute the provision for depreciation, depletion and amortization, and to determine the amount of any impairment of proved properties;

• The valuation of unproved acreage and proved oil and gas properties to determine the amount of any impairments of oil and gas properties;

• Judgment regarding the productive status of in-progress exploratory wells to determine the amount of any provision for abandonment.

• Estimates regarding the future utilization of net operating loss carryforwards.

Principles of Consolidation

The consolidated financial statements include the accounts of Clayton Williams Energy, Inc. and its subsidiaries. The Company accounts for its undivided interest in oil and gas limited partnerships using the proportionate consolidation method, whereby its share of assets, liabilities, revenues and expenses are consolidated with other operations. All significant intercompany transactions and balances associated with the consolidated operations have been eliminated.

Oil and Gas Properties

The Company follows the successful efforts method of accounting for its oil and gas properties, whereby costs of productive wells, developmental dry holes and productive leases are capitalized and amortized using the unit-of-production method based on estimated proved reserves. Proceeds from sales of properties are credited to property costs, and a gain or loss is recognized when a significant portion of an amortization base is sold or abandoned.

F-7

Exploration costs, including geological and geophysical expenses and delay rentals, are charged to expense as incurred. Exploratory drilling costs, including the cost of stratigraphic test wells, are initially capitalized but charged to exploration expense if and when the well is determined to be unsuccessful. The acquisition costs of unproved acreage are initially capitalized and are carried at cost, net of accumulated impairment provisions, until such leases are transferred to proved properties or charged to exploration expense as impairments of unproved properties.

Natural Gas and Other Property and Equipment

Natural gas gathering and processing systems consist primarily of gas gathering pipelines, compressors and gas processing plants. Other property and equipment consists primarily of field equipment and facilities, office equipment, leasehold improvements and vehicles. Major renewals and betterments are capitalized while the costs of repairs and maintenance are charged to expense as incurred. The costs of assets retired or otherwise disposed of and the applicable accumulated depreciation are removed from the accounts, and any gain or loss is included in other income in the accompanying consolidated statements of operations.

Depreciation of natural gas gathering and processing systems and other property and equipment is computed on the straight-line method over the estimated useful lives of the assets, which generally range from 3 to 12 years.

Valuation of Property and Equipment

The Company follows the provisions of Statement of Financial Accounting Standards No. 144 “Accounting for Impairment or Disposal of Long-Lived Assets” (“SFAS 144”), which supercedes Statement of Financial Accounting Standards No. 121. SFAS 144 requires that the Company’s long-lived assets, including its oil and gas properties, be assessed for potential impairment in their carrying values whenever events or changes in circumstances indicate such impairment may have occurred.

SFAS 144 provides for future revenue from the Company’s oil and gas production to be estimated based upon prices at which management reasonably estimates such products will be sold. These estimates of future product prices may differ from current market prices of oil and gas. Any downward revisions to management’s estimates of future production or product prices could result in an impairment of the Company’s oil and gas properties in subsequent periods.

Unproved oil and gas properties with individually significant acquisition costs are periodically assessed, and any impairment in value is charged to exploration costs. The amount of impairment recognized on unproved properties which are not individually significant is determined by amortizing the costs of such properties within appropriate groups based on the Company’s historical experience, acquisition dates and average lease terms. At December 31, 2002, the Company’s unproved oil and gas properties had an aggregate net book value of $19.3 million. The valuation of unproved properties is subjective and requires management of the Company to make estimates and assumptions which, with the passage of time, may prove to be materially different from actual realizable values.

Income Taxes

The Company follows the asset and liability method prescribed by Statement of Financial Accounting Standards No. 109 “Accounting for Income Taxes” (“SFAS 109”). Under this method of accounting for income taxes, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. 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 are expected to be recovered or settled. Under SFAS 109, the effect on deferred tax assets and liabilities of a change in enacted tax rates is recognized in income in the period that includes the enactment date.

F-8

Hedging Activities

From time to time, the Company utilizes derivative instruments, consisting primarily of swaps, to reduce its exposure to changes in commodity prices and interest rates. Effective January 1, 2001, the Company adopted Statement of Financial Accounting Standards No. 133 “Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”) which established accounting and reporting requirements for derivative instruments and hedging activities. SFAS 133 requires that all derivative instruments be recognized as assets or liabilities in the balance sheet, measured at fair value. The accounting for changes in the fair value of a derivative depends on both the intended purpose and the formal designation of the derivative. Designation is established at the inception of a derivative, but subsequent changes to the designation are permitted. For derivatives designated as cash flow hedges and meeting the effectiveness guidelines of SFAS 133, changes in fair value are recognized in other comprehensive income until the hedged item is recognized in earnings. Hedge effectiveness is measured quarterly based on relative changes in fair value between the derivative contract and the hedged item over time. Any change in fair value resulting from ineffectiveness is recognized immediately in earnings. Changes in fair value of derivative instruments which are not designated as cash flow hedges or do not meet the effectiveness guidelines of SFAS 133 are recorded in earnings as the changes occur. If designated as cash flow hedges, actual gains or losses on settled commodity derivatives are recorded as oil and gas revenues in the period the hedged production was sold, while actual gains or losses on interest rate derivatives are recorded in interest expense for the applicable period. Actual gains or losses from derivatives not designated as cash flow hedges are recorded in other income (expense) as changes in fair value of derivatives.

Inventory

Inventory consists primarily of tubular goods and other well equipment which the Company plans to utilize in its ongoing exploration and development activities and is carried at the lower of cost or market value.

Capitalization of Interest

Interest costs associated with the Company’s inventory of unproved oil and gas property lease acquisition costs are capitalized. During the years ended December 31, 2002, 2001 and 2000, the Company capitalized interest totaling approximately $600,000, $523,000 and $483,000, respectively.

Cash and Cash Equivalents

The Company considers all cash and highly liquid investments with original maturities of three months or less to be cash equivalents.

Net Income (Loss) Per Common Share

Basic earnings per share is computed by dividing net income by the weighted average number of common shares outstanding for the period. Diluted earnings per share reflects the potential dilution that could occur if dilutive stock options were exercised, calculated using the treasury stock method. The diluted earnings per share calculations for 2000 include an increase in potential shares attributable to dilutive stock options. Stock options were not considered in the diluted earnings per share calculations for 2002 and 2001 as the effect would be anti-dilutive.

Stock-Based Compensation

The Company accounts for stock-based compensation utilizing the intrinsic value method prescribed by Accounting Principles Board Opinion No. 25 “Accounting for Stock Issued to Employees” (“APB 25”) and related interpretations. The following pro forma information, as required by Statement of Financial Accounting Standards No. 123 “Accounting for Stock-Based Compensation” (“SFAS 123”), as amended by Statement of Financial Accounting Standards No. 148 (“SFAS 148”), presents net income and earnings per share information as if the stock options issued since December 31, 1994 were accounted for using the fair value method. The fair value of stock options issued for each year was

F-9

estimated at the date of grant using the Black-Scholes option pricing model. No options were granted during 2002. The following weighted average assumptions were used in this model.

	2001		2000

Risk-free interest rate	4.5	%	5.5	%
Stock price volatility	76	%	74	%
Expected life in years	7		7
Dividend yield	—		—

The SFAS 123 pro forma information for the years ended December 31, 2002, 2001 and 2000 is as follows:

	2002			2001			2000

Net income (loss), as reported	$	(4,003	)	$	(5,304	)	$	27,813
Add: Stock-based employee compensation expense included in net income (loss), net of tax	(21		)	(269		)	609
Deduct: Stock-based employee compensation expense determined under fair value based method (SFAS 123), net of tax	(883		)	(795		)	(719		)
Net income (loss), pro forma	$	(4,907	)	$	(6,368	)	$	27,703

Basic:
Net income (loss) per common share, as reported	$	(.43	)	$	(.58	)	$	3.02
Net income (loss) per common share, pro forma	$	(.53	)	$	(.69	)	$	3.01

Diluted:
Net income (loss) per common share, as reported	$	(.43	)	$	(.58	)	$	2.91
Net income (loss) per common share, pro forma	$	(.53	)	$	(.69	)	$	2.90

Revenue Recognition and Gas Balancing

The Company utilizes the sales method of accounting for oil, natural gas and natural gas liquids revenues whereby revenues are recognized as the production is 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. The Company did not have any significant gas imbalance positions at December 31, 2002 or 2001. Revenues from natural gas services are recognized as services are provided.

Comprehensive Income

Statement of Financial Accounting Standards No. 130 “Reporting Comprehensive Income” (“SFAS 130”) established standards for reporting and displaying of comprehensive income and its components (revenue, expenses, gains and losses) in a full set of general-purpose financial statements. For the year ended December 31, 2000, the Company reported no differences between comprehensive income and net income. A portion of the changes in fair value of derivatives required under SFAS 133 was reported as comprehensive income during 2002 and 2001.

Concentration Risks

The Company sells its oil and natural gas production to various customers, serves as operator in the drilling, completion and operation of oil and gas wells, and enters into derivatives with various counterparties. When management deems appropriate, the Company obtains letters of credit to secure amounts due from its principal oil and gas purchasers and follows other procedures to monitor credit risk from joint owners and derivatives counterparties. Except for the loss reported in 2001 in connection with

F-10

the financial failure of Enron North America Corp., a derivatives counterparty (see Note 5), the Company has not experienced any significant credit losses. Allowances for doubtful accounts at December 31, 2002 and 2001 consist of the following:

	2002		2001
	(In thousands)
Accounts receivable:
Oil and gas sales	$	286	$	286
Joint interest and other	400		400
	$	686	$	686

A significant portion of the Company’s estimated proved oil and gas reserves are concentrated in a few properties. Six of the Company’s producing wells represent approximately 36% of the Company’s estimated proved reserves at December 31, 2002. An adverse event related to any one of these wells could have a significant adverse effect on the Company’s reserves, production, cash flow and general financial condition.

Reclassifications

Certain reclassifications of prior year financial statement amounts have been made to conform to current year presentations.

3. Long-Term Debt

Long-term debt at December 31, 2002 and 2001 consists of the following:

	2002		2001
	(In thousands)

Secured Bank Credit Facility (matures December 31, 2004)	$	93,000	$	62,000
Vendor finance obligations	1,949		—
Abandonment obligations	3,500		—
Production payment obligations	1,000		—
	$	99,449	$	62,000

Aggregate maturities of long-term debt at December 31, 2002 are as follows: 2003 - $663,000; 2004 - $95,255,000; 2005 - $770,000; 2006 - $700,000; thereafter - $2,061,000.

The Company’s secured bank credit facility provides for a revolving loan facility in an amount not to exceed the lesser of the borrowing base, as established by the banks, or that portion of the borrowing base determined by the Company to be the elected borrowing limit. The borrowing base, which is based on the discounted present value of future net revenues from oil and gas production, is subject to redetermination at any time, but at least semi-annually in May and November, and is made at the discretion of the banks. If, at any time, the redetermined borrowing base is less than the amount of outstanding indebtedness, the Company will be required to (i) pledge additional collateral, (ii) prepay the excess in not more than five equal monthly installments, or (iii) elect to convert the entire amount of outstanding indebtedness to a term obligation based on amortization formulas set forth in the loan agreement. Substantially all of the Company’s oil and gas properties are pledged to secure advances under the credit facility.

At December 31, 2002, the borrowing base established by the banks was $110 million, with no monthly commitment reductions. After allowing for outstanding letters of credit totaling $4.3 million, the Company had $12.7 million available under the credit facility at December 31, 2002.

F-11

All outstanding balances under the credit facility may be designated, at the Company’s option, as either “Base Rate Loans” or “Eurodollar Loans” (as defined in the loan agreement), provided that not more than two Eurodollar traunches may be outstanding at any time. Base Rate Loans bear interest at the fluctuating Base Rate plus a Base Rate Margin ranging from 0% to .5% per annum, depending on levels of outstanding advances and letters of credit. Eurodollar Loans bear interest at the LIBOR rate plus a Eurodollar Margin ranging from 1.25% to 2.25% per annum. At December 31, 2002, the Company’s indebtedness under the credit facility consisted of $93 million of Eurodollar Loans at a rate of 3.4%.

In addition, the Company pays the banks a commitment fee equal to 1/4% per annum on the unused portion of the revolving loan commitment. Interest on the revolving loan and commitment fees are payable quarterly, and all outstanding principal and interest will be due December 31, 2004.

The loan agreement contains financial covenants that are computed quarterly and require the Company to maintain minimum levels of working capital and cash flow. The Company was in compliance with all of the financial and non-financial covenants at December 31, 2002.

Vendor Finance Obligations

In August 2002, the Company initiated a vendor financing arrangement for wells to be drilled in south Louisiana whereby all costs of participating vendors, including interest at an annual rate of 9%, will be repaid out of a percentage of the net revenues from the wells drilled under the arrangement. If net revenues are insufficient to repay financed costs within an 18-month period, the Company has agreed to repay any unpaid balance. Under the terms of the secured bank credit facility, no more than $6 million of vendor finance obligations, with recourse to the Company, may be outstanding at any time. Vendor finance obligations at December 31, 2002 totaled $1.9 million and were classified as non-current liabilities.

Abandonment Obligations

In connection with the Romere Pass acquisition discussed in Note 14, the Company assumed the obligation to abandon the acquired assets at the end of their useful lives in accordance with applicable contracts and governmental regulations. Although the estimated abandonment obligation is $3.5 million, the Company has been required to issue letters of credit aggregating $4.25 million to secure this obligation, $3.5 million to a prior owner of the acquired assets and $750,000 to a federal agency.

Production Payment

Also in connection with the Romere Pass acquisition, the Company granted to the seller a $1 million after-payout production payment. After the Company has recouped $21 million, plus certain developmental drilling costs, and interest on the combined amounts at an annual rate of 12%, the Company will pay to the seller 5% of its net proceeds from production until the $1 million production payment is satisfied.

F-12

4. Income Taxes

Deferred tax assets and liabilities are the result of temporary differences between the financial statement carrying values and the tax bases of assets and liabilities. Significant components of net deferred tax assets (liabilities) at December 31, 2002 and 2001 are as follows:

	2002			2001
	(In thousands)
Deferred tax assets:
Net operating loss carryforwards	$	10,623		$	16,964
Depletion carryforwards	—			1,229
Accrued stock-based compensation	132			146
Fair value of derivatives	4,523			—
Other	1,105			971
	16,383			19,310
Deferred tax liabilities:
Property and equipment	(8,389		)	(16,978		)
Fair value of derivatives	—			(1,493		)
Valuation allowance	(876		)	—
	(9,265		)	(18,471		)
Net deferred tax assets	$	7,118		$	839

Components of net deferred tax assets:
Current assets	$	524		$	438
Non-current assets	6,594			401
	$	7,118		$	839

At December 31, 2002, the Company had cumulative net operating loss carryforwards of $30.4 million, of which $14.8 million expire from 2009 through 2011. Net operating loss carryforwards represent a material portion of the Company’s net deferred tax assets. Due to uncertainties about the Company’s ability to fully utilize its net deferred tax assets, the Company recorded a valuation allowance at December 31, 2002 of $876,000, of which $871,000 relates to tax benefits from operating losses and $5,000 relates to tax benefits from the exercise of employee stock options.

For the years ended December 31, 2002, 2001 and 2000, the Company’s effective income tax rates differed from the statutory federal income tax rates for the following reasons:

	2002			2001			2000
	(In thousands)

Income tax expense (benefit) at statutory rate of 35%	$	(2,478	)	$	(3,139	)	$	10,486
Tax depletion in excess of basis	(174		)	(210		)	(965		)
Revision of previous tax estimates	39			(74		)	114
Change in valuation allowance	871			—			(7,149		)
Other	—			2			31
Income tax expense (benefit) - deferred	$	(1,742	)	$	(3,421	)	$	2,517

The Company derives an income tax benefit when employees and directors exercise options granted under the Company’s stock compensation plans (see Note 8). Employee stock options that are classified as fixed stock options under APB 25 do not result in a charge against book income when the option price is equal to or greater than the market price at date of grant. Therefore, any tax benefit from the exercise

F-13

of fixed stock options results in a permanent difference, which is recorded to additional paid-in capital when the tax benefit is realized. Accordingly, the Company credited additional paid-in capital for $81,000 and $1,159,000 during 2001 and 2000, respectively, related to the exercise of employee stock options. Paid-in capital was not credited in 2002 due to a $5,000 valuation allowance on the tax benefit derived from exercises of employee stock options in 2002.

5. Derivatives

Commodity Derivatives

From time to time, the Company utilizes commodity derivatives, consisting primarily of swaps, to attempt to optimize the price received for its oil and gas production. When using swaps to hedge oil and natural gas production, the Company receives a fixed price for the respective commodity and pays a floating market price as defined in each contract (generally NYMEX futures prices), resulting in a net amount due to or from the counterparty. In the past the Company has also used collars which contain a fixed floor price (put) and ceiling price (call). If the market price for the respective commodity exceeds the call strike price or falls below the put strike price, then the Company receives the fixed price and pays the market price. If the market price is between the call and the put strike prices, then no payments are due from either party.

The following summarizes information concerning the Company’s net positions in open commodity derivatives as of December 31, 2002.

	Oil Swaps			Gas Swaps
	Bbls	Average Price		MMBtu(a)	Average Price
Production Period:
1st Quarter 2003	160,000	$	25.27	2,275,000	$	3.55
2nd Quarter 2003	240,000	$	24.67	1,545,000	$	3.51
3rd Quarter 2003	120,000	$	24.20	1,810,000	$	3.58
4th Quarter 2003	80,000	$	24.20	1,720,000	$	3.80
Year 2003 (b)	600,000	$	24.68	7,350,000	$	3.61

(a) One MMBtu equals one Mcf at a Btu factor of 1,000.

(b) Based on current estimates, approximately 45% and 35% of the Company’s oil and gas production, respectively, for 2003 is subject to commodity derivatives.

In February 2003, the Company terminated swaps covering 535,000 MMBtu of natural gas production for the month of April 2003 at a fixed price of $7.75 per MMBtu, which will require a $2.3 million cash payment to the counterparty in April 2003.

Interest Rate Derivatives

In November 2001, the Company entered into an interest rate swap on $50 million of its long-term bank debt designated as Eurodollar Loans (see Note 3). The swap provides for the Company to pay a fixed rate of 3.63% for the two-year term of the swap. The counterparty will pay a floating rate based on the LIBOR-BBA one-month rate. The swap requires a monthly cash settlement for the difference between the fixed rate and the floating rate.

Accounting For Derivatives

Upon adoption of SFAS 133, the Company recorded liabilities aggregating $539,000 applicable to the fair value of all derivatives held by the Company as of January 1, 2001, resulting in a provision for the cumulative effect of accounting change of $164,000 (net of deferred taxes of $89,000), and a charge to accumulated other comprehensive income of $186,000 (net of deferred taxes of $100,000).

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The following table sets forth, for the years ended December 31, 2002 and 2001, the components of accumulated other comprehensive income, as reported in stockholders’ equity, all of which is related to derivatives designated as cash flow hedges under SFAS 133.

	Accumulated Other Comprehensive Income (Loss)
	Commodity Derivatives			Interest Rate Derivatives			Total
	(In thousands)
Balance, December 31, 2000	$	—		$	—		$	—
Adoption of SFAS 133, net of tax	(186		)	—			(186		)
Change in fair value of derivatives, net of tax	5,276			(236		)	5,040
Reclassifications to earnings, net of tax	(3,093		)	50			(3,043		)
Balance, December 31, 2001	1,997			(186		)	1,811
Change in fair value of derivatives, net of tax	(14,147		)	(1,076		)	(15,223		)
Reclassifications to earnings, net of tax	4,860			602			5,462
Net changes during the period	(9,287		)	(474		)	(9,761		)
Balance, December 31, 2002	$	(7,290	)	$	(660	)	$	(7,950	)

During the twelve months subsequent to December 31, 2002, the Company expects to reclassify $6.2 million of net deferred losses associated with open cash flow hedges and $1.7 million of net deferred losses on terminated cash flow hedges from accumulated other comprehensive income to earnings. The unrealized deferred hedge losses associated with open cash flow hedges remain subject to market price fluctuations until the position is either settled under the terms of the hedge arrangement or terminated prior to maturity. The net deferred losses on terminated cash flow hedges are fixed.

Sale of Enron Claim

During the fourth quarter 2001, Enron North America Corp. (“Enron”), a counterparty to certain of the Company’s then-existing commodity derivatives, defaulted on its obligations, and the Company terminated all derivatives with Enron. At December 31, 2001, the Company placed no value on the terminated derivatives. The effect of accounting for the terminated derivatives under SFAS 133 was to record a non-cash charge to earnings during the fourth quarter of 2001 of $5.5 million and to reclassify $2 million of non-cash credits out of accumulated other comprehensive income into earnings in 2002.

In September 2002, the Company assigned $4.9 million of its claim in the bankruptcy proceedings of Enron to a third party for $392,000, net of transactions fees totaling $50,000. If the claim is ultimately disallowed, in whole or in part, by the bankruptcy court, the Company will be required to refund a proportionate part of the sales price, with interest, based on the ratio of the amount of the disallowed claim to the total claim. The gain on the sale of the claim was recorded as a change in fair value of derivatives in the accompanying statement of operations.

Margin Calls

The ISDA master agreement between the Company and its principal derivative counterparty gives either party the right to request credit support (a “Margin Call”) to the extent that the fair value of the derivatives exceeds specified credit limits. Currently, the Company’s credit limit under the master agreement is $2 million. The counterparty issued Margin Calls totaling $4 million in 2002. Funds paid to the counterparty for Margin Calls are held in interest-bearing trust accounts controlled by the counterparty and are included in other current assets in the accompanying consolidated balance sheet.

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6. Financial Instruments

Cash and cash equivalents, receivables, accounts payable and accrued liabilities were each estimated to have a fair value approximating the carrying amount due to the short maturity of those instruments. Indebtedness under the secured bank credit facility was estimated to have a fair value approximating the carrying amount since the stated interest rate is generally market sensitive. All other long-term debt, in the aggregate, has an estimated fair value of $5.7 million based on the net present value of future cash outflows and using assumptions for timing of payments and discount rates that the Company considers appropriate.

The fair values of derivatives as of December 31, 2002 and 2001 are set forth below. The associated carrying values of derivatives at December 31, 2002 are equal to their estimated fair values.

	2002			2001
	(In thousands)
Assets (liabilities):
Commodity derivatives	$	(11,902	)	$	4,558
Interest rate derivatives	(1,015		)	(286		)
Net assets (liabilities)	$	(12,917	)	$	4,272

7. Stock Repurchase Program

In July 2002, the Company’s Board of Directors authorized the continuation of a stock repurchase program initiated in July 2000. Under this program, the Company is authorized to spend up to $3 million to repurchase shares of its common stock on the open market at times and prices deemed appropriate by the Company’s management. This authorization expires in July 2004. To date, the Company has spent $1.4 million to repurchase and cancel 115,100 shares of common stock, of which 50,800 shares were repurchased during the year ended December 31, 2002 at an aggregate cost of $648,000.

8. Compensation Plans

1993 Plan

The Company has reserved 1,798,200 shares of common stock for issuance under the 1993 Stock Compensation Plan (“1993 Plan”). The 1993 Plan provides for the issuance of nonqualified stock options with an exercise price which is not less than the market value of the Company’s common stock on the date of grant. All options granted through December 31, 2002 expire 10 years from the date of grant and become exercisable based on varying vesting schedules.

The following table reflects activity in the 1993 Plan for 2002, 2001 and 2000.

	2002				2001				2000
	Shares		Weighted Average Price		Shares		Weighted Average Price		Shares		Weighted Average Price
Beginning of year	687,350		$	12.22	465,840		$	9.83	526,165		$	9.03
Granted	—		$	—	250,000		$	15.94	2,059		$	14.50
Exercised	(6,500	)	$	5.50	(25,879	)	$	5.51	(59,499	)	$	3.11
Forfeited	—		$	—	(2,611	)	$	7.95	(2,885	)	$	5.50
End of year	680,850		$	12.29	687,350		$	12.22	465,840		$	9.83

Exercisable	668,032		$	12.41	655,467		$	12.54	356,122		$	11.11
Issuable	801,766				801,766				1,049,155

F-16

The following table summarizes information with respect to options outstanding and exercisable at December 31, 2002.

	Outstanding Options				Options Exercisable
	Shares	Weighted Average Exercise Price		Weighted Average Remaining Life in Years	Shares	Weighted Average Exercise Price
Range of exercise prices:
$3.25	21,575	$	3.25	3.2	21,575	$	3.25
$5.50 - $6.00	208,275	$	5.50	5.3	195,797	$	5.50
$14.50 - $15.94	451,000	$	15.85	6.1	450,660	$	15.85
	680,850	$	12.29	5.3	668,032	$	12.41

In accordance with Financial Accounting Standards Board Interpretation No. 44 (“FIN 44”) to APB 25, the Company changed the classification of 233,141 stock options repriced in April 1999 from fixed stock options to variable stock options. The Company is required to recognize compensation expense on the repriced options to the extent that the quoted market value of the Company’s common stock at the end of each period after July 1, 2000 exceeds the amended option price ($5.50 per share), except that options vested as of July 1, 2000 must recognize compensation expense only to the extent that the quoted market value exceeds the market value on that date ($31.94 per share). As the repriced options are exercised, the cumulative amount of accrued compensation expense is credited to additional paid-in capital. Since this provision is based on changes in the quoted market value of the Company’s common stock, the Company’s future results of operations may be subject to significant volatility. Accrued compensation expense at December 31, 2002 and 2001 is classified as a current liability in the accompanying consolidated balance sheet and is comprised of the following activity for the years then ended.

	2002			2001
	(In thousands)

Beginning of year	$	417		$	933
Compensation expense (credit)	(32		)	(414		)
Amounts reclassified to additional paid-in capital for options exercised during the period	(8		)	(102		)
End of year	$	377		$	417

Directors Plan

The Company has reserved 86,300 shares of common stock for issuance under the Outside Directors Stock Option Plan (“Directors Plan”). Since inception of the Directors Plan, the Company has issued options covering 30,000 shares of common stock (3,000 per year from 1993 through 2002) at option prices ranging from $3.25 to $18.50 per share. All options expire seven to 10 years from date of grant and are fully exercisable upon issuance. At December 31, 2002, options to purchase 18,000 shares were outstanding, and 56,300 shares remain available for future grants.

Bonus Incentive Plan

The Company has reserved 115,500 shares of common stock for issuance under the Bonus Incentive Plan. The plan provides that the Board of Directors each year may award bonuses in cash, common stock of the Company, or a combination thereof. At December 31, 2002, 106,190 shares remain available for issuance under this plan.

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Executive Stock Compensation Plan

The Company has a compensation plan which permits the Company to pay all or part of selected executives’ salaries and bonuses in shares of common stock in lieu of cash. The Company reserved an aggregate of 500,000 shares of common stock for issuance under this plan. During 2002, 2001 and 2000, the Company issued 54,833, 14,638 and 11,811 shares, respectively, of common stock to Mr. Williams in lieu of cash salary and bonuses aggregating $647,000, $230,000 and $231,000, respectively. The amounts of such compensation are included in general and administrative expense in the accompanying consolidated financial statements. At December 31, 2002, 152,754 shares remain available for issuance under this plan.

401(k) Plan

Employees who have met certain age and length of employment requirements are eligible to participate in a 401(k) plan sponsored by the Company. Each participant may make annual contributions to the plan in amounts not to exceed the lesser of (i) 100% of the participant’s pre-tax annual earnings and (ii) the maximum amount of annual contributions allowed by law. The Company may, in its sole discretion, provide a matching contribution equal to a percentage of the participants’ contributions. Participants become vested in the Company’s contributions at a rate of 25% per year. The plan permits the Company to make its matching contributions in common stock of the Company. Participants are allowed to transfer the matched portion of their accounts out of Company common stock after becoming fully vested. During 2002, 2001 and 2000, the Company contributed $224,000, $228,000 and $189,000, respectively, in market value of common stock to the 401(k) plan.

Working Interest Trusts

During 2001, the Company created six trusts from which officers and key employees of the Company, excluding Mr. Williams, will receive after-payout working interests in wells or groups of wells drilled by the Company subsequent to the formation of the trusts. The aggregate working interests assignable to the trusts range from 4% to 5% of the Company’s working interest in the properties. Five of the six trusts are not expected to achieve payout and will be dissolved. One of the trusts, covering wells drilled in the Cotton Valley Reef Complex and the Austin Chalk (Trend), is expected to payout in 2003. Upon payout, the trust will be dissolved and the working interests held by the trust will be distributed to the participants. Based on estimates at December 31, 2002, using guidelines established by the SEC, proved oil and gas reserves attributable to the working interests assigned to this trust totaled 1.4 Bcfe, and the present value of their future net revenues, discounted at 10%, totaled $3.6 million. Reserves attributable to this trust have been excluded from the Company’s reserve estimates included elsewhere in this Form 10-K.

After-Payout Working Interest Incentive Plans

In lieu of the working interest trusts discussed above, the Compensation Committee of the Board of Directors, in September 2002, adopted an incentive plan for key employees and consultants, excluding Mr. Williams, who promote the Company’s drilling and acquisition programs. Management’s objective in adopting this plan is to further align the interests of the participants with those of the Company by granting the participants an after-payout working interest in the production developed, directly or indirectly, by the participants. The plan provides for the creation of a series of limited partnerships to which the Company, as general partner, contributes a portion of its working interest in wells drilled within certain areas, and the key employee and consultants, as limited partners, contribute cash. The Company pays all costs and receives all revenues until payout of its costs, plus interest. At payout, the limited partners receive 99% of all subsequent revenues and pay 99% of all subsequent expenses attributable to the partnerships’ interests.

In October 2002, the Company formed three limited partnerships pursuant to this plan and committed to contribute to the partnerships 5% of its working interests in all applicable wells. Applicable wells will include (i) wells purchased in the Romere Pass acquisition (see Note 14), (ii) a Robertson County, Texas well which was in progress of being drilled at October 1, 2002, and (iii) wells drilled subsequent to October 1, 2002 in Louisiana and in Robertson, Burleson and Milam Counties, Texas. The

F-18

Company consolidates its proportionate share of partnership assets, liabilities, revenues, expenses and oil and gas reserves in its consolidated financial statements.

9. Transactions with Affiliates

The Company and other entities controlled by Mr. Williams (the “Williams Entities”) are parties to an agreement (the “Service Agreement”) pursuant to which the Company furnishes services to, and receives services from, such entities. Under the Service Agreement, the Company provides legal, payroll, benefits administration, and financial and accounting services to the Williams Entities, as well as lease operating and technical services with respect to certain oil and gas properties owned by the Williams Entities. The Williams Entities provide tax preparation services, tax planning services, and business entertainment to or for the benefit of the Company. The Company believes that the rates charged for the services to and from the Williams Entities are favorable to the Company. The following table summarizes the charges to and from the Williams Entities for the years ended December 31, 2002, 2001 and 2000.

	2002		2001		2000
	(In thousands)
Amounts received from the Williams Entities:
Services	$	248	$	239	$	228
Reimbursed expenses	631		681		437
	$	879	$	920	$	665

Amounts paid to the Williams Entities	$	525	$	374	$	172

The amounts paid to the Williams Entities in 2002 and 2001 include $370,000 and $273,000, respectively, of rents paid to the partnership discussed in Note 10.

During 2001, the Company acted as agent for Mr. Williams in the placement of certain natural gas hedges covering the sale of 1,100,000 MMBtu at an average price of $3.11 per MMBtu from February through December 2002 and 420,000 MMBtu at an average price of $3.17 per MMBtu from January 2003 through June 2003. The fair value of these derivatives at December 31, 2002 was a loss of $409,000. Any proceeds received by the Company from the counterparty are passed through to Mr. Williams. The Company requires Mr. Williams to maintain a cash deposit with the Company to the extent of any projected losses on these derivatives based on their estimated fair value. The Company does not plan to serve as agent for Mr. Williams on any future hedging transactions.

Accounts receivable from affiliates and accounts payable to affiliates include, among other things, amounts for charges whereby the Company is the operator of certain wells in which affiliates own an interest. These charges are on terms which are consistent with the terms offered to unaffiliated third parties which own interests in wells operated by the Company.

10. Investment

In May 2001, the Company invested approximately $1.6 million as a limited partner in a partnership formed to purchase and operate two commercial office buildings in Midland, Texas, one of which is the location of the Company’s corporate headquarters. In addition, the Company loaned the partnership $100,000 against an unsecured note due in September 2002 and guaranteed up to $675,000 of partnership indebtedness. In August 2002, the partnership repaid the loan, and the Company was released from the guaranty. The Company’s ownership interest in the partnership is 31.9% before payout (as

F-19

defined in the partnership agreement) and 33.4% after payout. Substantially all of the partnership’s indebtedness is non-recourse, and the Company is not liable for any partnership indebtedness. An affiliate of Mr. Williams serves as general partner of the partnership. Since the Company does not manage or control the operations of these buildings, the Company utilizes the equity method of accounting for its investment in this limited partnership. For the years ended December 31, 2002 and 2001, the Company recorded pretax income of $119,000 and a pretax loss of $63,000, respectively, from the partnership.

11. Commitments and Contingencies

Leases

The Company leases office space from affiliates and nonaffiliates under noncancelable operating leases. Rental expense pursuant to the office leases amounted to $501,000, $503,000 and $400,000 for the years ended December 31, 2002, 2001 and 2000, respectively.

Future minimum payments under noncancelable leases at December 31, 2002, are as follows:

	Operating Leases
	(In thousands)
2003	$	796
2004	654
2005	607
Thereafter	744
Total minimum lease payments	$	2,801

Legal Proceedings

The Company is a defendant in a personal injury suit filed in the 38th Judicial District Court in Cameron Parish, Louisiana in 2002. The plaintiff, an employee of one of the Company’s subcontractors, claims he was injured while working on a barge drilling rig owned and operated by another subcontractor, Parker Drilling Company (“PDC”). PDC was also named as a defendant in the suit. Robert L. Parker is the Chairman of the Board of Directors of PDC and is a member of our Board of Directors. The plaintiff has not yet specified the amount of damages sought, and no interrogatories or other discovery has been conducted. Currently, there are uncertainties concerning the extent of the Company’s insurance coverage. The Company’s insurance company is providing defense under a reservation of rights pending resolution of these uncertainties. The plaintiff’s employer is subject to the terms of an agreement with the Company in which it agrees to indemnify the Company from damages resulting from injuries to its employees. PDC is seeking indemnification from the Company for any damages resulting from the fault or negligence of PDC under the terms of the drilling contract. Due to these uncertainties, the Company is currently unable to determine its financial exposure, if any, in this matter. The Company has filed an answer denying liability and intends to vigorously defend this suit.

The Company is a defendant in a suit filed in the 82nd Judicial District Court in Robertson County, Texas in January 2003 by lessors of the lease on which its Lee Fazzino #1 and Lee Fazzino #2 wells were drilled. The plaintiffs allege that the Company formed the Lee Fazzino Unit #1, a 320-acre unit that pooled various leases, including the plaintiffs’ lease, in bad faith. The plaintiffs are seeking to have the unit declared to be null and void, with the effect being that the plaintiffs, and certain non-participating royalty owners claiming through the plaintiffs’ lease, are entitled to 100% of the royalties from both wells. If the plaintiffs are successful, the Company’s ability to collect all the royalties previously paid to the pooled royalty owners is uncertain, and the Company’s net interest in the wells will be reduced from 76.8% to 75%.

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The Company is currently unable to determine its financial exposure, if any, in this matter. The Company denies all claims and intends to vigorously defend this suit.

In addition, the Company is a defendant in several lawsuits that have arisen in the ordinary course of business. While the outcome of these lawsuits cannot be predicted with certainty, management does not expect any of these to have a material adverse effect on the Company’s consolidated financial condition or results of operations.

Guarantees

In November 1999, the Company guaranteed loans from a bank to certain employees of the Company, including Mr. Williams, in the aggregate amount of $834,000, the proceeds from which were used to finance the exercise of stock options granted under the 1993 Plan. During 2000, all employees other than Mr. Williams repaid their respective loans. In 2002, the bank released the Company from its obligations under this guaranty.

12. Impairment of Property and Equipment

The Company has recorded provisions for impairment of proved properties under SFAS 144 and SFAS 121 of $349,000 in 2002 and $18.2 million in 2001. The 2002 provision was needed due to poor production performance on prospects in the Sweetlake area and one prospect in Mississippi. The 2001 provision relates primarily to prospects in the Bossier Sand, Sweetlake and south Texas areas. Price declines during the last half of 2001, coupled with high capital expenditures and lower than expected production and reserves in these areas, resulted in the need for this impairment in 2001.

The Company has also recorded provisions for impairment of unproved properties aggregating $7.9 million, $10.2 million and $4.3 million in 2002, 2001 and 2000, respectively, and have charged these impairments to exploration costs in the accompanying statements of operations.

13. Accounting Pronouncements

In August 2001, the FASB issued SFAS No. 143 “Accounting for Asset Retirement Obligations” (“SFAS 143”). SFAS 143 addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated retirement costs. The Company is required and plans to adopt the provisions of SFAS 143 for the quarter ending March 31, 2003. To accomplish this, the Company must identify all legal obligations for asset retirement obligations, if any, and determine the fair value of these obligations on the date of adoption. The determination of fair value is complex and requires the Company to gather market information and develop cash flow models. Due to these complexities, the Company has not completed all of the computations necessary to adopt SFAS 143. The effects of adoption may materially increase the Company’s liabilities, and may have a material effect on its results of operations.

In December 2002, the FASB issued SFAS 148, which amends SFAS 123, to provide alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, this statement amends the disclosure requirements of SFAS 123 to require disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on the reported results. SFAS 148 is effective for the Company’s year ended December 31, 2002 and for interim financial statements commencing in 2003. The Company’s adoption of this pronouncement did not have an impact on financial condition or results of operations.

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14. Purchases and Sales of Assets

In July 2002, the Company purchased all of the working interest in the Romere Pass Unit in Plaquemines Parish, Louisiana for total consideration of $21.7 million, net of estimated closing adjustments. The effective date of the purchase for accounting purposes was August 1, 2002. The purchase price consisted of $17.2 million cash, the assumption of abandonment obligations totaling $3.5 million, and the granting of an after-payout production payment in the amount of $1 million. The Company financed the acquisition through borrowings under its bank credit facility (see Note 3).

Also in July 2002, the Company sold its interests in certain wells in Wharton County, Texas, effective July 1, 2002, for $3.2 million and reported a net gain on the sale of approximately $1.8 million. Pursuant to the requirements of SFAS 144, the historical operating results from these properties have been reported as discontinued operations in the accompanying consolidated statements of operations. The following table summarizes certain historical operating information related to the discontinued operations.

	2002		2001		2000
	(In thousands)

Revenues	$	363	$	1,065	$	915
Gain on sale of property and equipment	$	1,840	$	—	$	—
Income before income taxes	$	2,054	$	625	$	572
Net income	$	1,335	$	406	$	372

In September 2001, the Company sold its oil and gas interests in three east Texas fields (including interests held through an affiliated limited partnership) for net proceeds to the Company of $15.9 million, resulting in a net gain of $10.7 million.

15. Settlement of Claim

During June 2002, the Company received $5.5 million from its insurer in full settlement of a coverage dispute regarding the August 2000 blowout of the Mary Muse #1, a Cotton Valley Reef Complex well in Robertson County, Texas. The proceeds were applied first to recover $4.1 million of unamortized costs attributable to the Mary Muse well. The remaining $1.4 million was recorded as other income in the accompanying consolidated statements of operations.

F-22

16. Quarterly Financial Data (Unaudited)

The following table summarizes results for each of the four quarters in the years ended December 31, 2002 and 2001.

	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Year
	(In thousands, except per share)
Year ended December 31, 2002:
Total revenues	$	19,817		$	20,215		$	23,378		$	28,460		$	91,870
Gross profit (a)	$	13,653		$	14,184		$	17,160		$	20,163		$	65,160
Income (loss) from continuing operations	$	(3,072	)	$	1,267		$	(2,166	)	$	(1,367	)	$	(5,338	)
Net income (loss)	$	(3,014	)	$	1,348		$	(970	)	$	(1,367	)	$	(4,003	)
Net income (loss) per common share (b):
Basic:
Income (loss) from continuing operations	$	(0.33	)	$	0.14		$	(0.23	)	$	(0.15	)	$	(0.58	)
Net income (loss)	$	(0.33	)	$	0.15		$	(0.10	)	$	(0.15	)	$	(0.43	)
Diluted:
Income (loss) from continuing operations	$	(0.33	)	$	0.14		$	(0.23	)	$	(0.15	)	$	(0.58	)
Net income (loss)	$	(0.33	)	$	0.14		$	(0.10	)	$	(0.15	)	$	(0.43	)
Weighted average commons shares outstanding:
Basic	9,211			9,236			9,255			9,272			9,241
Diluted	9,211			9,375			9,255			9,272			9,241

Year ended December 31, 2001:
Total revenues	$	35,601		$	32,880		$	24,506		$	20,951		$	113,938
Gross profit (a)	$	28,003		$	25,875		$	17,547		$	14,619		$	86,044
Income (loss) from continuing operations	$	2,255		$	(8,370	)	$	6,025		$	(5,456	)	$	(5,546	)
Net income (loss)	$	2,258		$	(8,234	)	$	6,109		$	(5,437	)	$	(5,304	)
Net income (loss) per common share (b):
Basic:
Income (loss) from continuing operations	$	0.24		$	(0.90	)	$	0.65		$	(0.59	)	$	(0.60	)
Net income (loss)	$	0.24		$	(0.89	)	$	0.66		$	(0.59	)	$	(0.58	)
Diluted:
Income (loss) from continuing operations	$	0.24		$	(0.90	)	$	0.65		$	(0.59	)	$	(0.60	)
Net income (loss)	$	0.24		$	(0.89	)	$	0.65		$	(0.59	)	$	(0.58	)
Weighted average commons shares outstanding:
Basic	9,261			9,273			9,262			9,243			9,219
Diluted	9,516			9,273			9,403			9,243			9,219

(a) Gross profit is computed by the sum of oil and gas sales plus natural gas services revenues less operating expenses. Operating expenses consist of lease operations and costs associated with natural gas services.

(b) The sum of the individual quarterly net income (loss) per share amounts may not agree to the total for the year due to each period’s computation based on the weighted average number of common shares outstanding during each period.

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17. Costs of Oil and Gas Properties

The following table sets forth certain information with respect to costs incurred in connection with the Company’s oil and gas producing activities during the years ended December 31, 2002, 2001 and 2000.

	2002		2001		2000
	(In thousands)
Property acquisitions:
Proved	$	21,749	$	1,278	$	—
Unproved	20,311		14,418		11,131
Developmental costs	4,964		19,692		36,510
Exploratory costs	27,011		75,857		32,297
Total	$	74,035	$	111,245	$	79,938

The following table sets forth the capitalized costs for oil and gas properties as of December 31, 2002 and 2001.

	2002			2001
	(In thousands)

Proved properties	$	597,980		$	565,313
Unproved properties	19,340			11,471
Total capitalized costs	617,320			576,784
Accumulated depreciation, depletion and amortization	(447,745		)	(425,557		)
Net capitalized costs	$	169,575		$	151,227

18. Oil and Gas Reserve Information (Unaudited)

The estimates of proved oil and gas reserves utilized in the preparation of the consolidated financial statements were prepared by independent petroleum engineers. Such estimates are 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 economic and operating conditions existing at the registrant’s year end with no provision for price and cost escalations except by contractual arrangements. The Company’s reserves are substantially located onshore in the United States.

The Company emphasizes that reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. In addition, a portion of the Company’s proved reserves at December 31, 2002 are classified as proved developed nonproducing, which increases the imprecision inherent in estimating reserves which may ultimately be produced.

F-24

The following table sets forth proved oil and gas reserves together with the changes therein (oil in MBbls, gas in MMcf, oil converted to MMcfe at six MMcf per MBbl) for the years ended December 31, 2002, 2001 and 2000.

	2002						2001						2000
	Oil (a)		Gas		MMcfe		Oil (a)		Gas		MMcfe		Oil		Gas		MMcfe
Proved reserves:
Beginning of period	9,291		74,974		130,720		12,911		28,308		105,774		11,904		30,141		101,565
Revisions (b)	1,813		8,156		19,034		(1,943	)	(2,478	)	(14,136	)	770		(2,406	)	2,214
Extensions and discoveries	92		4,259		4,811		786		63,403		68,119		2,623		8,620		24,358
Sales of minerals-in-place	(76	)	(1,009	)	(1,465	)	(72	)	(3,994	)	(4,426	)	—		—		—
Purchases of minerals-in-place	2,582		16,576		32,068		—		848		848		—		—		—
Production:
Continuing operations	(1,812	)	(15,972	)	(26,844	)	(2,378	)	(10,955	)	(25,223	)	(2,375	)	(7,914	)	(22,164	)
Discontinued operations	(6	)	(72	)	(108	)	(13	)	(158	)	(236	)	(11	)	(133	)	(199	)
End of period	11,884		86,912		158,216		9,291		74,974		130,720		12,911		28,308		105,774

Proved developed reserves:
Beginning of period	8,414		74,407		124,891		10,565		26,278		89,668		9,028		26,960		81,128
End of period	9,349		76,224		132,318		8,414		74,407		124,891		10,565		26,278		89,668

(a) For 2001, all reserve volumes include natural gas liquids. Due to the change described in note (b) below, only revisions and ending reserves for 2000 include natural gas liquids.

(b) Effective December 31, 2000, the Company changed its method of estimating future natural gas production from a wet stream to a dry stream. This change resulted in an increase in natural gas liquids of 1,262 MBOE, a decrease in natural gas of 3,976 MMcf and an increase in gas equivalents of 3,594 MMcfe.

The standardized measure of discounted future net cash flows relating to proved reserves as of December 31, 2002, 2001 and 2000 was as follows:

	2002			2001			2000
	(In thousands)

Future cash inflows	$	730,609		$	364,712		$	609,867
Future costs:
Production	(165,806		)	(92,700		)	(135,919		)
Development	(24,782		)	(18,247		)	(27,336		)
Income taxes	(137,059		)	(36,870		)	(118,534		)
Future net cash flows	402,962			216,895			328,078
10% discount factor	(109,264		)	(52,307		)	(96,014		)
Standardized measure of discounted future net cash flows	$	293,698		$	164,588		$	232,064

F-25

Changes in the standardized measure of discounted future net cash flows relating to proved reserves for the years ended December 31, 2002, 2001 and 2000 were as follows:

	2002			2001			2000
	(In thousands)

Standardized measure, beginning of period	$	164,588		$	232,064		$	151,642
Net changes in sales prices, net of production costs	138,566			(143,132		)	91,001
Revisions of quantity estimates	49,551			(22,209		)	6,196
Accretion of discount	18,687			30,746			17,650
Changes in future development costs, including development costs incurred that reduced future development costs	5,094			14,399			7,007
Changes in timing and other	(16,827		)	(17,542		)	10,639
Net change in income taxes	(66,540		)	53,111			(50,533		)
Extensions and discoveries	14,834			120,363			83,266
Sales, net of production costs:
Continuing operations	(64,445		)	(84,691		)	(84,073		)
Discontinued operations	(306		)	(855		)	(731		)
Sales of minerals-in-place	(1,744		)	(18,833		)	—
Purchases of minerals-in-place	52,240			1,167			—
Standardized measure, end of period.	$	293,698		$	164,588		$	232,064

The estimated present value of future cash flows relating to proved reserves is extremely sensitive to prices used at any measurement period. The prices used for each commodity for the years ended December 31, 2002, 2001 and 2000 were as follows:

	Average Price
	Oil (a)		Gas
As of December 31:
2002	$	28.98	$	4.44
2001	$	17.92	$	2.64
2000	$	25.12	$	10.09

(a) Includes natural gas liquids

F-26

Part III

Name

Age

Position With the Company

Income Taxes

Bbls

Average Price

MMBtu(a)

Average Price

GLOSSARY OF TERMS

LIABILITIES AND STOCKHOLDERS’ EQUITY

Hedging Activities

Concentration Risks

Bbls

Average Price

MMBtu(a)

Average Price

Average
Price

Average
Price

Average
Price

Average
Price