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, 2003

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: (432) 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 ý No o

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, 2003: $88,007,644.

There were 9,372,575 shares of Common Stock, $.10 par value, of the registrant outstanding as of March 8, 2004.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the definitive proxy statement relating to the 2004 Annual Meeting of Stockholders, which will be filed with the Commission not later than April 29, 2004, 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
			Risk Factors
			Website Address

	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
			Key Factors to Consider
			Summary of Exploration Results
			Supplemental Information
			Operating Results

			Liquidity and Capital Resources
			Known Trends and Uncertainties
			Application of Critical Accounting Policies and Estimates
			Recent Accounting Pronouncements

	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

	Item 9A.	Controls and Procedures
			Disclosure Controls and Procedures
			Changes in Internal Control Over Financial Reporting

Part III
	Items 10-14.	Information Incorporated by Reference

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

This Annual Report on Form 10-K contains forward-looking statements that are based on management’s 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, 2003 were 62.9 Bcf of natural gas and 10.3 million barrels of oil and natural gas liquids, and our estimated present value of proved reserves was $335.1 million. During 2003, we added proved reserves of 9.7 Bcfe through extensions and discoveries and had downward revisions of previous estimates (resulting primarily from well performance) of 7.8 Bcfe. CWEI held interests in 537 gross (387.1 net) producing oil and gas wells and owned leasehold interests in approximately 1.2 million gross (598,000 net) undeveloped acres at December 31, 2003.

Clayton W. Williams beneficially owns, either individually or through his affiliates, approximately 48% 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 strategy and daily operations.

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

Prior to 1997, we were primarily a developmental driller of horizontal wells in the Austin Chalk (Trend) in east central Texas. As we approached the end of our development phase in this area, we began our transition to an exploration company in the Cotton Valley Reef Complex, a deep gas play in the same geographical area as our Austin Chalk (Trend) acreage. We also began looking for other opportunities to explore for domestic reserves in areas where we had knowledge and experience. Initially, we focused our search on the major on-shore producing regions in Texas and Louisiana, but have more recently expanded into other regions, including Mississippi.

As an oil and gas exploration company, our principal business strategy is to grow our oil and gas reserves through exploration activities, consisting of generating exploratory prospects, leasing the acreage applicable to the prospects, drilling exploratory wells on these prospects to determine if recoverable oil and gas reserves exist, drilling developmental wells on prospects, and producing and selling any resulting oil and gas production.

To generate a typical exploratory prospect, we first identify geographical areas that we believe may contain undiscovered oil and gas reserves. We then consider many other business factors related to those geographical areas, including proximity to our other areas of operations, our technical knowledge and experience in the area, the availability of acreage, and the overall potential for finding reserves. Most of our current exploration efforts are concentrated in regions that have been known to produce oil and gas. These regions include some of the larger producing regions in Texas, Louisiana and Mississippi.

In most cases, we then obtain and process seismic data using sophisticated geophysical technology to attempt to visualize underground structures and stratigraphic traps that may hold recoverable reserves. Although this technology increases our expectations of a successful discovery, it does not and cannot assure us of success. Many factors are involved in the interpretation of seismic data, including the field recording parameters of the data, the type of processing, the extent of attribute analyses, the availability of subsurface geological data, and the depth and complexity of the subsurface. Significant judgment is required in the evaluation of seismic data, and differences of opinion often exist between experienced professionals. These interpretations may turn out to be invalid and may result in unsuccessful drilling results.

Obtaining oil and gas reserves through exploration activities involves a higher degree of risk than through drilling developmental wells or purchasing proved reserves. We often commit significant resources to identify a prospect, lease the drilling rights and drill a test well before we know if a well will be productive. To offset this risk, our typical exploratory prospect is expected to offer a significantly higher reserve potential than a typical low-risk development prospect might offer. The reserve potential is determined by estimating the aerial extent of the structural or stratigraphic trap, the vertical thickness of the reservoir in the trap, and the recovery factor of the hydrocarbons in the trap. The recovery factor is affected by a combination of factors including (i) the reservoir drive mechanism (water drive, depletion drive or a combination of both), (ii) the permeability and porosity of the reservoir, and (iii) the bottom hole pressure (in the case of gas reserves).

Due to the high risk/high reward nature of oil and gas exploration, we expect to spend money on prospects that are ultimately nonproductive. However, over time, we believe our productive prospects will generate sufficient cash flow to provide us with an acceptable rate of return on our entire investment, both nonproductive and productive.

We are presently concentrating our exploration efforts principally in the Miocene Trend in south Louisiana, the Cotton Valley Reef Complex area of east central Texas and the Stones River/Knox Trend in the Black Warrior Basin of Mississippi. More than 90% of our planned expenditures for 2004 relate to exploratory prospects, as compared to approximately 83% of actual expenditures in 2003 and 95% of actual expenditures in 2002 (excluding the Romere Pass acquisition). During 2003, we spent $64.3 million on exploratory prospects, including $14.1 million on seismic and leasing activities and $50.2 million on drilling activities.

Acquisition and Divestitures of Proved Properties

Secondary to our exploration program, we are also engaged in the business of acquiring proved reserves. Competition for the purchase of proved reserves is intense. Sellers often utilize a bid process to sell properties. This process usually intensifies the competition and makes it extremely difficult for us to acquire reserves without assuming significant price and production risks. Although we did not acquire any proved reserves in 2003, we purchased, in 2002, all of the working interest in the Romere Pass Unit in Plaquemines Parish, Louisiana for total consideration of $21.2 million, net of closing costs. We are actively searching for opportunities to acquire proved oil and gas properties; however, because the competition is intense, we cannot give any assurance that we will be successful in our efforts during 2004.

From time to time, we decide to sell certain of our proved properties. 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.

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, 2003, we were the operator of 409 wells, or 76% of the 537 total productive wells in which we have a working interest. On an Mcfe basis, production from these operated wells represented 95% of our total net oil and gas production for 2003. 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. Serving as operator also subjects us to certain credit risks.

Drilling, Exploration and Production Activities

Following is a discussion of our significant drilling, exploration and production activities during 2003 and our plans for capital and exploratory expenditures in 2004. In 2003, we spent $77.3 million on exploration and drilling activities, all of which was financed out of cash flow from operations. We presently plan to spend approximately $75.6 million on exploration and drilling activities during 2004, most of which will be spent in our current areas of exploration. We may increase or decrease our planned activities, 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. In 2001, we acquired 3-D seismic data covering over 3,400 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 $43.9 million in south Louisiana during 2003, excluding the Romere Pass Unit, on exploration activities, of which $33.4 million was spent on drilling and completion activities and $10.5 million was spent on seismic and leasing activities.

Prior to 2003, we had drilled 17 exploratory wells in south Louisiana, of which 7 gross (6.7 net) wells were completed as producers. The following table sets forth certain information about our exploratory well activities or south Louisiana subsequent to December 31, 2002.

Spud Date	Well Name (Prospect)	Working Interest		Current Status

March 2003	State Lease 17521 #1 (Clio)	100	%	Dry
March 2003	State Lease 17569 #1 (Auguste Bay)	100	%	Dry
March 2003	OCS – G – 21142 #2 (Nonoperated)	13	%	Producing
April 2003	LL&E #1 – fka State Lease 3279 #1 (Floretta)	100	%	Producing
July 2003	OCS – G – 21142 #3 (Nonoperated)	10	%	Producing
September 2003	OCS – G – 21142 #4 (Nonoperated)	10	%	Completing
October 2003	State Lease 17378 #1 (Fleur)	75	%	Completing
October 2003	State Lease 17639 #1 (Neva)	100	%	Dry
October 2003	State Lease 17620 #1 (Pelican Point)	67	%	Waiting on pipeline
October 2003	State Lease 16656 #1 (Whiskey Bay)	100	%	Dry
October 2003	State Lease 17613 #1 (Top)	100	%	Dry
October 2003	State Lease 17620 #2 (Pelican Point)	67	%	Dry
December 2003	State Lease 17642 #1 (Brusile)	100	%	Dry
December 2003	State Lease 17707 #1 (Jones Point)	100	%	Dry
December 2003	Allen Gautreaux #1 (King)	100	%	Completing
December 2003	OCS – G – 21142 #5 (Nonoperated)	10	%	In progress
February 2004	Louisiana Fruit Co. #1 (Tiger Pass)	100	%	In progress
February 2004	Mervine Jankower #1 (Helen Gayle)	100	%	In progress

In 2004, we plan to spend approximately $51.9 million in south Louisiana on the following activities:

• $40.3 million to conclude drilling and/or completion activities on in-progress wells at December 31, 2003, and drill approximately 10 new wells on existing prospects; and

• $11.6 million to conduct seismic and leasing activities necessary to generate new exploratory prospects.

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 additional costs that may be incurred to complete successful exploratory wells.

Romere Pass Unit

In 2003, we spent $9.6 million in the Romere Pass Unit primarily to drill three developmental wells, all of which were productive. We currently have no plans for additional drilling activities in the Romere Pass Unit in 2004.

Cotton Valley Reef Complex

Most of the prospects drilled in our Cotton Valley Reef Complex area are on or adjacent to our Austin Chalk (Trend) acreage in east central Texas. As opposed to Austin Chalk (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 2003, we spent $10.9 million in the Cotton Valley Reefs Complex, of which $10.6 million was spent on drilling and completion activities, and $300,000 on leasing, seismic and other.

To date, we have drilled 14 exploratory wells in the Cotton Valley Reef Complex area in which we owned 100% of the working interest. Of the 14 wells, 11 were completed as producers. We drilled one well in 2003, the Muse-Patranella #1, which was not commercially productive. In addition, we have participated in the drilling of 3 gross (.4 net) wells as a non-operator, all of which were dry holes.

In 2004, we plan to spend approximately $7.5 million in the Cotton Valley Reef Complex area on the following activities:

• $7 million to drill two exploratory wells, one of which will be to test a shallower structure in the Knowles formation; and

• $500,000 to conduct other exploration and leasing activities.

Black Warrior Basin

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 Stones River/Knox Trend, an Ordovician age formation. 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 and $5.8 million was paid in 2003. 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.

In 2003, we spent $2.4 million in this area to add more leases to our acreage block and to continue our seismic processing. We currently have approximately 47,000 net acres in the Black Warrior Basin.

In 2004, we plan to spend $7.2 million in this area to drill two wells. In February 2004, we spudded the Weyerhaeuser #1, a 15,500-foot exploratory well in Webster County, Mississippi. We expect to complete drilling operations on this well in the second quarter of 2004.

Other Exploration and Development Activities

During 2003, we spent $10.5 million on exploration and development activities in other areas, including:

• $2.3 million in the Northern San Joaquin Basin of California to conduct seismic and leasing activities and drill an exploratory dry hole;

• $1.7 million on the Longellow Ranch prospect in Pecos County, Texas to participate in three nonoperated exploratory wells, two of which were productive;

• $1.5 million on leasing, recompletion and developmental drilling in the Austin Chalk (Trend);

• $1.5 million to participate in the drilling of two nonoperated wells in Wayne County, Mississippi, both of which were nonproductive;

• $1.3 million in Eddy County, New Mexico to drill four developmental wells, all of which were productive; and

• $1.2 million in the Chuar Basin of Arizona and Utah to acquire acreage and drill an exploratory dry hole.

In 2004, we plan to spend $3 million in the Austin Chalk (Trend) to conduct leasing, recompletion and developmental drilling activities, $3.4 million in New Mexico on developmental drilling and $2.6 million on various exploration activities in other areas, including 2 gross (1.3 net) exploratory wells in the Northern San Joaquin 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 four 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. In addition, we experience competition from major and independent oil and gas companies and oil and gas syndicates in bidding for desirable oil and gas properties, as well as in acquiring the equipment, data 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 liabilities 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 112 full-time employees, none of whom is subject to a collective bargaining agreement. In our opinion, our employee relations are good.

Risk Factors

There are many factors that affect our business, some of which are beyond our control. Following is a summary of certain factors that we have described elsewhere in this Item 1:

• We are primarily controlled by our principal shareholder (see “General”);

• Our business is subject to operational risks (see “Operational Hazards and Insurance”);

• Some of our competitors have substantially greater resources which may give them a competitive advantage over us (see “Competition and Markets”); and

• We are subject to complex government laws and regulations that may result in increased expenses and exposure to liabilities (see “Regulation”).

In addition, we have identified other risks and uncertainties that could have a material affect on our results of operations, cash flow, liquidity and capital resources if such uncertainties occur. For a discussion of these factors, see “Known Trends and Uncertainties” in Item 7.

Website Address

The Company maintains an internet website at www.claytonwilliams.com .. The Company makes available, free of charge, on its website, the annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports, as soon as reasonably practicable after providing such reports to the SEC.

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, 2003, we had interests in 537 gross (387.1 net) oil and gas wells and owned leasehold interests in approximately 1.2 million gross (598,000 net) undeveloped acres.

Reserves

The following table sets forth certain information as of December 31, 2003 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 Undeveloped		Total Proved
	Producing		Nonproducing		Proved Undeveloped		Total Proved
	(Dollars in thousands)
Gas (MMcf)	46,633		15,882		401		62,916
Oil and natural gas liquids (MBbls)	8,591		758		986		10,335
Total (MMcfe)	98,179		20,430		6,317		124,926
Present value of proved reserves	$	266,190	$	58,344	$	10,563	$	335,097
Standardized measure of discounted future net cash flows							$	252,980

The following table sets forth certain information as of December 31, 2003 regarding our proved oil and gas reserves in each of our principal producing areas.

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


						(In thousands)

Austin Chalk (Trend)	6,688	5,593	45,721	36.6	%	$	98,883	29.5	%
Cotton Valley Reef Complex	—	25,616	25,616	20.5	%	82,798		24.7	%
Louisiana	1,485	24,465	33,375	26.7	%	109,015		32.5	%
New Mexico / West Texas	1,980	4,325	16,205	13.0	%	33,485		10.0	%
Other	182	2,917	4,009	3.2	%	10,916		3.3	%
Total	10,335	62,916	124,926	100.0	%	$	335,097	100.0	%

(a) Includes natural gas liquids.

The estimates of proved reserves at December 31, 2003 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, 2003 were $30.45 per Bbl of oil and natural gas liquids and $5.61 per Mcf of gas, as compared to $28.98 per Bbl of oil and $4.44 per Mcf of gas as of December 31, 2002. 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 approximately $6 million and $21 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.

Since January 1, 2003, 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,
	2003		2002		2001
	Gross	Net	Gross	Net	Gross	Net
	(Excludes wells in progress at the end of any period)
Development Wells:
Oil	6	5.0	3	.8	28	17.5
Gas	2	2.0	—	—	5	2.2
Dry	—	—	1	.9	—	—
Total	8	7.0	4	1.7	33	19.7
Exploratory Wells:
Oil	—	—	—	—	1	.2
Gas	9	4.9	—	—	18	14.6
Dry	18	12.3	9	4.9	14	9.8
Total	27	17.2	9	4.9	33	24.6
Total Wells:
Oil	6	5.0	3	.8	29	17.7
Gas	11	6.9	—	—	23	16.8
Dry	18	12.3	10	5.8	14	9.8
Total	35	24.2	13	6.6	66	44.3

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, 2003, of productive wells in the areas indicated.

	Oil		Gas		Total
	Gross	Net	Gross	Net	Gross	Net

Austin Chalk (Trend)	301	230.7	26	16.4	327	247.1
New Mexico / West Texas	70	44.7	12	1.3	82	46.0
Louisiana	34	31.7	41	34.8	75	66.5
Cotton Valley	—	—	12	11.1	12	11.1
Other	7	5.5	34	10.9	41	16.4
Total	412	312.6	125	74.5	537	387.1

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, 2003, we were the operator of 409 wells, or 76% of the 537 total wells in which we have a working interest. On an Mcfe basis, production from these operated wells represented 95% of our total net oil and gas production for 2003.

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.

	Year Ended December 31,
	2003		2002		2001
Oil and Gas Production Data:
Gas (MMcf)	24,697		15,972		10,955
Oil (MBbls)	1,505		1,585		2,129
Natural gas liquids (MBbls)	234		227		249
Total (MMcfe)	35,131		26,844		25,223
Average Oil and Gas Sales Price (1):
Gas ($Mcf)	$	4.69	$	3.01	$	4.25
Oil ($Bbl)	$	27.74	$	22.00	$	25.47
Natural gas liquids ($/Bbl)	$	21.09	$	14.16	$	16.05
Average Production Costs
Lease operations ($/Mcfe)(2)	$	.80	$	.81	$	.81

(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,
	2003		2002		2001
	(In thousands)
Property Acquisitions:
Proved	$	—	$	18,249	$	1,278
Unproved	7,982		20,311		14,418
Developmental Costs	11,689		4,964		19,692
Exploratory Costs	49,277		27,011		75,857
Asset Retirement Costs (1)	776		3,500		—
Total	$	69,724	$	74,035	$	111,245

(1) Excluded from asset retirement costs in 2003 was $1.5 million related to the cumulative effect of the adoption of SFAS 143 on January 1, 2003.

Acreage

The following table sets forth certain information regarding our developed and undeveloped leasehold acreage as of December 31, 2003 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		Undeveloped		Total
	Gross	Net	Gross	Net	Gross	Net

Austin Chalk (Trend) / Cotton Valley	110,081	108,405	55,798	30,625	165,879	139,030
Louisiana	13,252	13,120	42,424	38,857	55,676	51,977
Mississippi	90	65	167,731	56,354	167,821	56,419
New Mexico/ West Texas	2,418	1,673	61,917	22,000	64,335	23,673
Other (1)	21,065	5,611	826,219	449,994	847,284	455,605
Total	146,906	128,874	1,154,089	597,830	1,300,995	726,704

(1) Net undeveloped acres are attributable to the following areas: Colorado – 233,694; Nevada – 162,951; Utah – 22,964; and other – 30,385.

Offices

We lease from a related partnership approximately 40,000 square feet of office space in Midland, Texas for our corporate headquarters. We also lease approximately 10,000 square feet of office space in Houston, Texas from an unaffiliated third party.

Item 3 - - Legal Proceedings

We were a defendant in a suit filed in the 82nd Judicial District Court in Robertson County, Texas by lessors of the lease on which our Lee Fazzino Unit #1 and #2 wells (the “Wells”) were drilled. In November 2003, we agreed to settle this litigation with the lessors. Under the settlement terms, we will (i) grant the lessor a 1.2% overriding royalty interest in the Wells, which interest reduces to 1% after 24 months and (ii) pay the lessors $400,000 in cash. We have also agreed to reimburse those royalty owners in the Wells whose interests were aligned with ours in the suit for certain of their attorney fees incurred in connection with the litigation. The lessors will (i) grant a new lease to us for approximately 500 net acres, (ii) ratify all existing leases and the unit agreement, and (iii) execute a release of any and all claims with regard to the leases, Wells and unit agreement. We recorded a $1.3 million pre-tax charge against earnings during the third quarter of 2003 for the settlement of this litigation. The charge is reported in other income (expense) in the accompanying statement of operations. This suit was dismissed with prejudice in March 2004.

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, 2003.

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 March 8, 2004, 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, 2003:
Fourth Quarter	$	31.85	$	18.72
Third Quarter	23.40		16.15
Second Quarter	19.90		10.30
First Quarter	14.08		10.64

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

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 never paid any cash dividends on our Common Stock, and our Board of Directors does not currently anticipate paying any cash dividends to the common stockholders in the foreseeable future. In addition, 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.

Stock Repurchase Program

In July 2002, our Board of Directors authorized the continuation until July 2004 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. 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. No shares were repurchased in 2003.

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, 2003.

	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)	842,042	$	14.63	655,066
Equity compensation plans not approved by security holders	—	—		—
Total	842,042	$	14.63	655,066

(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, 2003 was derived from our audited 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,
	2003			2002			2001			2000			1999
	(In thousands, except per share)
Statement of Operations Data:
Revenues:
Oil and gas sales	$	163,032		$	86,302		$	105,118		$	102,235		$	43,711
Natural gas services	8,758			5,568			8,820			6,682			3,684
Total revenues	171,790			91,870			113,938			108,917			47,395
Costs and expenses:
Lease operations	28,239			21,857			20,427			18,162			11,077
Exploration:
Abandonment and impairments	35,120			21,571			29,412			12,657			5,245
Seismic and other	8,755			8,578			12,868			7,953			1,418
Natural gas services	8,279			4,853			7,467			5,591			3,098
Depreciation, depletion and amortization	40,284			29,656			37,459			27,635			20,565
Impairment of property and equipment	170			349			18,170			—			81
Accretion of abandonment obligations	651			—			—			—			—
General and administrative	10,934			8,615			7,456			5,951			3,929
Total costs and expenses	132,432			95,479			133,259			77,949			45,413
Operating income (loss)	39,358			(3,609		)	(19,321		)	30,968			1,982
Other income (expense):
Interest expense	(3,138		)	(4,006		)	(2,925		)	(2,310		)	(2,893		)
Gain on sales of property and equipment	199			361			10,986			1,031			10,926
Change in fair value of derivatives	(1,593		)	(1,581		)	2,227			—			—
Other income	(1,662		)	1,755			66			269			474
Total other income (expense)	(6,194		)	(3,471		)	10,354			(1,010		)	8,507
Income (loss) before income taxes	33,164			(7,080		)	(8,967		)	29,958			10,489
Income tax expense (benefit)	10,515			(1,742		)	(3,421		)	2,517			—
Income (loss) from continuing operations	22,649			(5,338		)	(5,546		)	27,441			10,489
Cumulative effect of accounting change, net of tax	207			—			(164		)	—			—
Income (loss) from discontinued operations, including gain on sale of $1,196 in 2002, net of tax	—			1,335			406			372			265
NET INCOME (LOSS)	$	22,856		$	(4,003	)	$	(5,304	)	$	27,813		$	10,754
Net income (loss) per common share:
Basic:
Income (loss) from continuing operations	$	2.43		$	(.58	)	$	(.60	)	$	2.98		$	1.16
Net income (loss)	$	2.45		$	(.43	)	$	(.58	)	$	3.02		$	1.19
Diluted:
Income (loss) from continuing operations	$	2.38		$	(.58	)	$	(.60	)	$	2.88		$	1.15
Net income (loss)	$	2.40		$	(.43	)	$	(.58	)	$	2.91		$	1.18
Weighted average common shares outstanding:
Basic	9,329			9,241			9,219			9,211			9,005
Diluted	9,509			9,241			9,219			9,543			9,148
Other Data:
Net cash provided by operating activities	$	119,750		$	34,514		$	67,059		$	72,471		$	24,738

	December 31,
	2003			2002			2001			2000			1999
	(In thousands)
Balance Sheet Data:
Working capital (deficit)	$	(13,119	)	$	(18,843	)	$	(17,779	)	$	(18,656	)	$	(6,649	)
Total assets	224,433			218,992			183,279			164,864			109,166
Long-term debt	53,295			94,949			62,000			30,000			30,500
Stockholders’ equity	100,781			68,781			82,280			85,777			56,117

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 and should be read in conjunction with our consolidated financial statements and notes thereto included elsewhere in this Form 10-K.

Overview

We are an oil and gas exploration company. Our basic business is to find oil and gas reserves through exploration activities, and sell the production from those reserves at a profit. To be successful, we must, over time, be able to find oil and gas reserves and then sell our discovered production at a price that is sufficient to cover our finding costs, operating expenses, administrative costs and interest expense, plus offer us a return on our capital investment.

At first glance, the current economic climate in the domestic oil and gas industry appears to be very suitable for this business model. Product prices for both oil and gas are high by historical standards. The domestic oil markets are primarily controlled by world-wide supply and demand fundamentals. Recent improvements in the global economy, particularly in China and the US, have increased demand for oil and have eroded the cushion of production that has historically been available in tight oil markets. These factors seem to support an average oil price for 2004 at least equal to 2003, if not higher.

High oil prices and the ongoing decline in North American gas deliverability is expected to keep domestic gas prices high as well. If the US continues to experience the recent apparent economic recovery, demand for natural gas in the industrial sector is likely to rise in the near term, keeping spot gas prices near current levels for the year. Industry experts predict that it will be several years before rising imports of liquefied natural gas are expected to largely offset the declining gas supply.

But as we probe deeper into the obvious benefits afforded by higher product prices, we find a major hurdle that our company, along with most other small to mid-cap companies in this industry, must clear in order to be profitable for the long-term, the hurdle being that quality domestic oil and gas reserves are becoming harder to find. Reserves to be produced from undiscovered reservoirs appear to be smaller, and the risks we must take to find these reservoirs are greater. A recent report from the Energy Information Administration indicates that on-shore domestic finding costs are on the rise, and that the average reserves added per well are declining.

The risks involved in finding oil and gas reserves are high. During the past two years, we have had limited drilling successes and have not found sufficient reserves to replace our production. In order to avoid further liquidation of our existing reserves, we need to reverse this trend through successful drilling in 2004 and beyond.

Key Factors to Consider

The following summarizes the key factors that management considered in the review of our financial condition and operating performance for 2003 and the related outlook for 2004.

• Out of the 17.2 net exploratory wells drilled in 2003, 12.3 net wells (72%) were nonproductive. This contributed to $35.1 million of abandonment and impairment costs being charged to exploration expense in our 2003 statement of operations.

• We currently plan to spend $75.6 million in 2004 on exploration and development activities, of which more than 90% relates to exploratory prospects. These planned activities are in areas where we had limited success in 2003 and 2002. Since past results are not necessarily indicative of future results, we cannot predict our drilling success in 2004 or beyond. If we continue to have limited success in

our exploratory drilling, our future results of operations and financial condition could be adversely affected.

• Our proved oil and gas reserves declined 21% from 2002 to 2003 due primarily to the fact that we replaced only 28% of our 2003 production through extensions and discoveries of new reserves during the year. We also revised our previous reserve estimates downward by approximately 5% due primarily to performance-based adjustments on certain wells. If we do not find significant reserves through our exploration program, we could liquidate another 20% of our reserves through production in 2004.

• Excluding any additional production from wells currently in progress or to be drilled, we project that oil and gas production in 2004 will decline about 30% as compared to 2003. Absent a significant increase in product prices, lower production will cause our oil and gas sales and cash flow to be lower in 2004 than 2003.

• We produced more oil and gas in 2003 than in any other year in our history, and this achievement occurred at a time when average oil and gas prices were also favorable. As a result, we reported record oil and gas sales and cash flows from operating activities in 2003.

• We used a significant portion of our cash flow from operating activities to reduce our bank indebtedness by 46%. This improved our long-term debt-to-equity ratio from 1.38 to 1 at December 31, 2002 to .53 to 1 at December 31, 2003 and provided us with sufficient liquidity for at least 2004, based on our current cash flow estimates.

Summary of Exploration Results

We began our transition from a development company to an exploration company in 1997 as we approached the end of the development phase of our acreage in the Austin Chalk (Trend) where we had been active as a horizontal driller. Due to the high risk/high reward nature of oil and gas exploration, we made this transition expecting to incur costs on prospects that were ultimately nonproductive, but also expecting to generate sufficient cash flow from the productive prospects to provide us with an acceptable rate of return on our entire investment, both nonproductive and productive.

Following is a summary by area of our principal exploration efforts since 1997 and the results we have achieved to date.

Cotton Valley Reef Complex

We began this program in 1997 with a 3-D seismic shoot over a large portion of our existing acreage in the Austin Chalk (Trend) and identified several structures that we believed could be productive. Since 1998, we have drilled 14 wells, of which 11 were productive. Although we had a high success rate in this area, the economic success is largely attributable to one well, the Lee Fazzino Unit #2. At December 31, 2003, our net remaining reserves from this well are estimated at 14.6 Bcf, with a present value of proved reserves of $48.5 million.

Following is an economic summary of our direct investments (pre-tax) in the Cotton Valley Reef Complex area from inception through December 31, 2003.

	Inception through December 31, 2003
	(Dollars in thousands)
Investment:
Land and exploration costs	$	13,801
Drilling costs	90,154
	103,955

Net cash flow received from production	141,521

Net cash flow surplus	$	37,566

Remaining proved developed producing reserves (Bcfe)	25.6

We plan to spend $7.5 million in the Cotton Valley Reef Complex area in 2004 primarily to drill two exploratory wells, one of which will test a shallower structure in the Knowles formation. In addition to the deep test to be drilled this year, we have identified two additional deep structures that may be suitable for future exploratory drilling after 2004. If the Knowles test well is successful, it is likely that we will need to drill additional wells in order to determine the extent of the structure.

South Louisiana

Since 2000, a significant portion of our exploration effort has been directed toward the Miocene Trend in south Louisiana. Our team of geologists and geophysicists has access to over 5,000 square miles of 3-D seismic data in this area, and they are actively processing and evaluating this data in search of exploratory prospects with high reserve potential. The Miocene Trend includes much of south Louisiana which is one of the top gas-producing regions in the country.

To date, we have drilled, or participated in drilling, 30 gross (26.3 net) wells in this area, of which 11 gross (8.6 net) were productive. While we continue to believe that this area offers significant opportunities for a viable exploration program, we are disappointed with our results to date. We have tried several strategies for improving our success using enhanced 3-D seismic technology, but the results have been mixed and inconclusive. Some prospects that had specific seismic characteristics, such as amplitudes and AVO, combined with closures and formations that are high to existing production, were successful in finding quality oil and gas reserves, and others with similar characteristics have been unsuccessful. Our current strategy is to give preference to prospects with larger structures and higher reserve potentials, such as the Fleur prospect currently being completed and the Andrea prospect, a deep prospect scheduled to be drilled in 2004. Exploratory wells on deeper prospects will generally be more expensive to drill, and therefore may subject us to a higher risk of loss. However, these prospects will also provide the potential for high impact discoveries.

Following is an economic summary of our direct investments (pre-tax) in south Louisiana exploration efforts from inception through December 31, 2003. This summary excludes any investment in, or net cash flow from production attributable to, the acquisition or development of the Romere Pass Unit.

		Inception through December 31, 2003
		(Dollars in thousands)
Investment:
Land and exploration costs		$	48,084
Drilling costs		70,934
Less:	Costs of unevaluated acreage and drilling in progress
		(10,206		)
		108,812

Net cash flow received from production		34,507

Net cash flow deficit		$	(74,305	)

Remaining proved reserves (Bcfe):
Proved developed producing		7.0
Proved developed nonproducing		11.1
		18.1

Almost 50% of the unevaluated costs at December 31, 2003, as shown in the above table, are related to the Fleur prospect where completion operations are currently underway on the SL 17378 #1 in Plaquemines Parish. We are currently setting a liner in the well bore and expect to perforate and flow test the well by the end of March. If the test results are favorable, we will begin construction on the necessary production facilities, which could take up to four months, depending on permitting, weather and other construction-related issues. Once sustained production is achieved, we will need several months of production history to be able to assess the well’s ultimate reserve potential. To date, our share of drilling and completion costs on the SL 17378 #1 total approximately $7 million.

We currently plan to spend $51.9 million in south Louisiana in 2004 to generate and lease new exploratory prospects and to drill existing exploratory prospects. Previous drilling results are not necessarily indicative of future results. Actual results may be better or worse than our track record in this area. All of the planned expenditures are considered to be high risk.

Black Warrior Basin

In 2002 we began an exploration program in the southern portion of the Black Warrior Basin in Mississippi targeting the Stones River/Knox Trend, an Ordovician age formation. This program is on trend with the Maben Field where 11 wells are currently producing from this formation. Since our initial purchase of 21,500 net acres in 2002, we have been acquiring additional leases and processing and evaluating approximately 62 miles of proprietary and 1,750 miles of acquired 2-D seismic data to identify structural traps that could contain hydrocarbons. We currently hold approximately 47,000 net acres covering the Stones River/Knox Trend. From inception through December 31, 2003, we have spent $14.1 million in this area to acquire acreage and to obtain and evaluate seismic data.

To date, we have identified several Stones River structures that we plan to drill. In 2004, we expect to spend approximately $7.2 million to drill two wells. Our first exploratory well in this area, the Weyerhaeuser #1 in Webster County, is located about 16 miles from the nearest producer in the Maben Field and will be drilled to a total depth of 15,500 feet. Drilling operations should be completed in the second quarter of 2004. If productive, additional development drilling of six to twelve wells could be possible on this structure. We plan to drill a second exploratory well on one of the other identified structures later in 2004.

In addition to the Stones River formation, seismic data has revealed several structures in the shallower Pennsylvanian sand section that could be productive. These sands range in depths from 4,500 feet to 12,000 feet in the area and consists of several different styles of stratigraphic and structural traps similar in nature to those found in the Permian Basin of west Texas. Only one well in the Maben Field is currently producing from the Pennsylvanian formation.

Other

In addition to the above-described programs, we have conducted exploration activities in other areas such as south Texas, the Sweetlake area in Louisiana, and the Bossier and Glen Rose plays in east Texas. In the aggregate, we have invested approximately $53 million in these exploration programs. Through December 31, 2003, we have received net cash flow from production of approximately $9 million. Remaining proved developed producing reserves at December 31, 2003 totaled 2.5 Bcfe.

Supplemental Information

The following unaudited information is intended to supplement the consolidated financial statements included in this Form 10-K with data that is not readily available from those statements.

	As of or for the Year Ended December 31,
	2003			2002			2001
Oil and Gas Production Data:
Gas (MMcf)	24,697			15,972			10,955
Oil (MBbls)	1,505			1,585			2,129
Natural gas liquids (MBbls)	234			227			249
Total (MMcfe)	35,131			26,844			25,223

Average Realized Prices:
Gas ($/Mcf):
Before hedging gains (losses)	$	5.35		$	3.20		$	3.86
Hedging gains (losses)	(.66		)	(.19		)	.39
Net realized price	$	4.69		$	3.01		$	4.25
Oil ($/Bbl):
Before hedging gains (losses)	$	29.94		$	24.62		$	25.24
Hedging gains (losses)	(2.20		)	(2.62		)	.23
Net realized price	$	27.74		$	22.00		$	25.47

Natural gas liquids ($/Bbl):	$	21.09		$	14.16		$	16.05

Average Daily Production:
Gas (Mcf):
Austin Chalk (Trend)	3,667			3,398			4,230
Cotton Valley Reef Complex	42,493			26,724			19,478
Louisiana	17,570			8,274			1,411
New Mexico/West Texas	1,668			1,769			1,882
Other	2,265			3,594			3,013
Total	67,663			43,759			30,014
Oil (Bbls):
Austin Chalk (Trend)	2,715			3,318			4,808
Louisiana	608			242			87
New Mexico/West Texas	723			724			894
Other	77			58			44
Total	4,123			4,342			5,833
Natural Gas Liquids (Bbls):
Austin Chalk (Trend)	299			459			515
New Mexico/West Texas	171			133			42
Louisiana	171			30			125
Total	641			622			682

Total Proved Reserves:
Gas (MMcf)	62,916			86,912			74,974
Oil and natural gas liquids (MBbls)	10,335			11,884			9,291
Total gas equivalent (MMcfe)	124,926			158,216			130,720
Present value of proved reserves (in thousands)	$	335,097		$	382,518		$	186,868

Total Proved Reserves by Area:
Gas (MMcf):
Austin Chalk (Trend)	5,593		5,135		4,993
Cotton Valley Reef Complex	25,616		45,613		31,740
Louisiana	24,465		29,874		27,923
New Mexico/West Texas	4,325		4,204		3,652
Other	2,917		2,086		6,666
Total	62,916		86,912		74,974
Oil and natural gas liquids (MBbls):
Austin Chalk (Trend)	6,688		7,297		7,065
Louisiana	1,485		2,674		358
New Mexico/West Texas	1,980		1,762		1,558
Other	182		151		310
Total	10,335		11,884		9,291
Total Gas Equivalent (MMcfe):
Austin Chalk (Trend)	45,721		48,917		47,383
Cotton Valley Reef Complex	25,616		45,613		31,740
Louisiana	33,375		45,918		30,071
New Mexico/West Texas	16,205		14,776		13,000
Other	4,009		2,992		8,526
Total	124,926		158,216		130,720

Exploration Costs (in millions):
Abandonment and impairment costs:
South Louisiana	$	17.9	$	6.8	$	18.6
Cotton Valley Reef Complex	8.7		7.2		3.8
Nevada, Arizona, California and Utah	4.2		1.2		2.1
Mississippi (1)	3.8		0.5		—
West Texas	0.4		4.2		.1
Other	0.1		1.6		4.8
Total	35.1		21.5		29.4
Seismic and other	8.8		8.6		12.9
Total exploration costs	$	43.9	$	30.1	$	42.3

Oil and Gas Costs ($/Mcfe Produced):
Lease operating expenses	$	.80	$	.81	$	.81
Oil and gas depletion	$	1.10	$	1.05	$	1.44

Net Wells Drilled (2):
Exploratory Wells	17.2		4.9		24.6
Developmental Wells	7.0		1.7		19.7

(1) Includes a $2.1 million impairment of unproved acreage in the Black Warrior Basin in 2003.

(2) Excludes wells being drilled or completed at the end of each period.

Operating Results

The following discussion compares our results for the year ended December 31, 2003 to the two previous years. All references to 2003, 2002 and 2001 within this section refer to the respective annual periods.

Oil and gas operating results

We achieved the highest level of oil and gas sales in our company’s history during 2003. This was a year in which both basic components of oil and gas sales (production volumes and product prices) were favorable.

Production in 2003 (on an Mcfe basis) was 31% higher than 2002 and 39% higher than 2001. While oil production has been trending down since 2001 due mainly to a lack of developmental drilling opportunities in the oil-prone Austin Chalk (Trend) area, our gas production has been trending up at a greater rate due primarily to higher production from the Cotton Valley Reef Complex and from steadily increasing gas production from Louisiana. Approximately 43% of 2003 and 25% of 2002 Louisiana gas production was derived from the Romere Pass Unit that we acquired effective August 2002. The remainder of the Louisiana gas increases was related primarily to production from exploratory drilling.

In 2003, our realized gas price was 56% higher than 2002 and 10 % higher than 2001, while our realized oil price was 26% higher than 2002 and 9% higher than 2001. Historically, the markets for oil and gas have been volatile, and they are likely to continue to be volatile. We have very little control over the prices we receive for our production at the wellhead since most of our physical marketing arrangements are market-sensitive. However, we have, from time to time, entered into commodity derivative contracts to try to maximize the average realized price.

Looking forward, in the absence of new production from our exploration program or from acquisitions of proved reserves, we currently estimate that our oil and gas production on an Mcfe basis will be approximately 30% lower in 2004 than 2003. Oil production will continue to trend downward although at a slightly slower rate due to certain developmental drilling in New Mexico and water fracs in the Austin Chalk (Trend). Gas production will begin to trend downward due primarily to depletion in the Cotton Valley Reef Complex area. We plan to spend over $75 million in 2004 to explore for new oil and gas production. Through these exploration efforts, we believe we can add sufficient volumes of new production to reduce or eliminate this decline. If we do not offset this projected production decline with new production from exploration activities or acquisitions of proved properties, oil and gas sales and cash flow in 2004 may be significantly lower than 2003.

As for prices, we cannot predict with accuracy future prices for oil and gas although currently we believe the fundamentals are in place for a continued strong market. However, we have not designated our current commodity derivatives, and do not currently intend to designate future commodity derivatives, as cash flow hedges under SFAS 133. This means that, in future periods, our derivatives will be marked to market through our statement of operations as other income (loss) instead of through accumulated other comprehensive income on our balance sheet. Additionally, all realized gains or losses on these derivatives in future periods will be reported in other income instead of oil and gas sales. This accounting treatment affects the timing and classification of income (loss) from derivatives, but it has no effect on cash flow from operating activities. Since we cannot predict future oil and gas prices, we cannot predict the effect that this accounting treatment will have on oil and gas sales or other income (loss) in future periods.

Oil and gas production costs on an Mcfe basis have been consistent from 2001 through 2003. However, since a portion of these costs, such as labor, supervision, insurance and administration, are relatively fixed in nature and do not reduce significantly as production volumes decline, we currently estimate that our production costs per Mcfe produced will be between 20% and 40% higher in 2004 than 2003.

Depletion on an Mcfe basis dropped 27% from 2001 to 2002 due to unusually high depletion rates in 2001 caused by rapid depletion on certain marginally productive properties in the Bossier Sands, Sweetlake and south Texas areas. The rate per Mcfe increased only slightly in 2003 from 2002. However, we estimate that our depletion

expense per Mcfe produced could be between 15% and 25% higher in 2004 than 2003 due to a variety of factors, including the downward revision in previous reserve estimates during the fourth quarter of 2003.

Exploration costs

Since we follow the successful efforts method of accounting, our results of operations are adversely affected during any accounting period in which significant seismic costs, exploratory dry hole costs, and unproved acreage impairments are expensed. In 2003, we charged to expense $43.9 million of exploration costs, as compared to $30.1 million in 2002 and $42.3 million in 2001. Most of these costs were incurred in two of our principal exploration areas, the Cotton Valley Reef Complex and south Louisiana. In 2003, we drilled/completed 17.2 net exploratory wells, of which 4.9 were productive, resulting in a 28% success rate. None of the 4.9 net exploratory wells drilled in 2002 was productive.

We plan to spend approximately $75.6 million on exploration and development activities in 2004 primarily in the same core exploration areas as in 2003. Since exploratory drilling involves a high degree of risk, it is likely that a significant portion of this will be charged to exploration costs in 2004. However, we cannot predict our success rates and, accordingly, cannot predict our exploration costs related to abandonment and impairment costs.

Oil and gas reserves

One of the key indicators by which we measure overall performance is our reserve replacement percentage. Since oil and gas reserves are a depleting resource, we must, over time, replace more than 100% of our production with reserves from new sources in order to build shareholder value. The sources by which we can replace reserves are (i) extensions and discoveries, and (ii) purchases of proved properties. Revisions to previous estimates resulting from changes in prices and production performance, whether positive or negative, are also considered in the determination of reserve replacements during any period. Over the past three years, we have replaced 129% of our cumulative production, comprised of 95% from extensions and discoveries, 38% from purchases of proved properties and a negative 4% from net downward revisions. While this three-year replacement rate is acceptable, we are not satisfied with the more recent two-year trend. We replaced only 28% of our 2003 production and 18% of our 2002 production through extensions and discoveries. Due primarily to our limited reserve replacement in 2003, our proved reserves declined 21% from 2002 to 2003.

Over time, if we reinvest our cash flow from operations into exploration activities and do not find sufficient oil and gas reserves to replace our production, we are essentially liquidating our asset base. On a worst case scenario, if we do not replace any of our 2004 production through extensions and discoveries or acquisitions of proved properties, our estimated proved reserves at the end of 2004 would be approximately 20% lower than 2003, based on economic and operating conditions used in the determination of proved reserves at December 31, 2003.

Other

At December 31, 2003, we have $19.8 million of federal tax loss carryforwards that begin to expire in 2008. As long as we are profitable in future periods, it is likely that we will be able to utilize these carryforwards before they expire. However, to the extent we incur any pre-tax losses in future periods, we do not currently intend to record a deferred tax benefit. Instead, we will record a valuation allowance against the increase in deferred tax assets caused by such losses.

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. 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 $75.6 million on exploration and development activities during 2004, as summarized by area in the following table.

	Total Planned Expenditures Year Ended December 31, 2004		Percentage of Total
	(In thousands)
South Louisiana	$	51,900	69	%
Cotton Valley Reef Complex	7,500		10	%
Mississippi	7,200		10	%
New Mexico	3,400		4	%
Austin Chalk (Trend)	3,000		4	%
Other	2,600		3	%
	$	75,600	100	%

Over 90% 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 2004 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 2004.

As explained in “Operating Results,” we have had limited success in our exploration efforts during the past two years. Although previous drilling results are not necessarily indicative of future results, you should be aware that we are continuing to explore in substantially the same core areas as in 2003 and 2002.

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 2003, we had an outstanding balance under the Credit Facility of $93 million, and the borrowing base was $110 million, leaving $12.7 million of availability, after allowing for $4.3 million of outstanding letters of credit. During 2003, we generated cash flow from operating activities of $119.8 million, spent $64.8 million on capital expenditures and other investments and repaid $45.5 million on long-term debt. The outstanding balance on the Credit Facility at December 31, 2003 was $50 million, leaving $55.7 million available on the Credit Facility, after allowing for $4.3 million of outstanding letters of credit. Subsequent to December 31, 2003, the borrowing base was reduced to $95 million, and the maturity was extended to December 31, 2005.

We used our high cash flow from operating activities in 2003 to reduce our indebtedness on the Credit Facility, thereby improving our debt-to-equity ratio and our overall liquidity. At December 31, 2003, our long-term debt-to-equity ratio was .53 to 1, as compared to 1.38 to 1 at December 31, 2002.

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, 2003 was $13.1 million, as compared to a deficit of $18.8 million at December 31, 2002. Giving effect to the above adjustments and the subsequent reduction in our borrowing base, our working capital for loan compliance purposes is a positive $29.8 million at December 31, 2003, as compared to a positive $6.8 million at December 31, 2002. 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, 2003 and 2002.

	2003			2002
	(In thousands)
Working capital (deficit) per GAAP	$	(13,119	)	$	(18,843	)
Add funds available under the Credit Facility (1)	40,725			12,700
Exclude fair value of derivatives classified as current assets or current liabilities	2,233			12,917
Working capital per loan covenant	$	29,839		$	6,774

(1) As adjusted for reduction in borrowing base subsequent to December 31, 2003.

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, 2003.

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 formed to purchase and operate two commercial office buildings in Midland, Texas, one of which is the location of our corporate headquarters. Our ownership interest in the partnership is 31.9% before payout (as defined in the partnership agreement) and 33.4% after payout. We are not liable for any indebtedness of the partnership. An entity controlled by Clayton W. Williams serves as general partner of the partnership. We do not manage or control the operations of the partnership or these buildings. We currently utilize the equity method of accounting for our investment in this partnership. We are currently evaluating what impact, if any, SFAS Interpretation No. 46 “Consolidation of Variable Interest Entities”, as revised in December 2003 (“FIN 46R”), will have on our financial statements. We must adopt FIN 46R in the first quarter of 2004.

Contractual Obligations and Contingent Commitments

The following table summarizes our contractual obligations as of December 31, 2003 by payment due date.

	Payments Due by Period
	Total		2004		2005-2006		2007-2008		Thereafter
	(In thousands)
Contractual obligations:
Secured Bank Credit Facility	$	50,000	$	—	$	50,000	$	—	$	—
Vendor financing obligations	5,748		2,453		3,295		—		—
Abandonment obligations	8,849		—		4,483		900		3,466
Production payment obligations	1,000		—		92		341		567
Operating leases obligations	2,281		776		1,293		209		3
Total contractual obligations	$	67,878	$	3,229	$	59,163	$	1,450	$	4,036

Known Trends and Uncertainties

We have identified several known trends and uncertainties that are likely to have a material effect on our financial condition or operating performance if these trends continue or develop and/or if these uncertainties occur. The following is a description of these known trends and uncertainties and, in the case of known trends, their affect on our financial condition or operating performance, and in the case of known uncertainties, the affect they would have if they were to occur.

Focus on Exploration Activities

For 2004, more than 90% 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 that is know to be productive by 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 2003, 10 gross (8.8 net) of the 16 gross (12.7 net) wells drilled and completed 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 results of operations, cash flow and capital resources.

Replacement of 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. The average productive life of our reserves at December 31, 2003 is approximately 3.6 years, based on 2003 production levels. This is down from 5.9 years at December 31, 2002, based on 2002 production levels. Our oil and gas reserves will decline as they are produced unless we are able to conduct successful exploration and development 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 drilling development wells in the Austin Chalk (Trend).

During 2003, we replaced 28% of our 2003 net production through extensions and discoveries. After adjusting our reserves for downward revisions of previous estimates, we realized a net replacement of only 5% of our 2003 net production. In 2002, we replaced 207% of our 2002 net production, consisting of 119% from acquisitions of proved properties, 70% from upward revisions of previous estimates, and 18% from extensions and discoveries. If we do not replace our production with new reserves over time, we will liquidate our reserves, which could affect our liquidity and capital resources. We cannot assure you that we can successfully find and produce reserves economically or acquire additional proved reserves at acceptable costs in the future.

Volatility of Oil and Gas Prices

Historically, the markets for oil and gas have been volatile, and we believe that 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 our 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.

Reserve Estimates

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.

Concentration of Proved Reserves

Our proved developed reserves are concentrated in a limited number of fields and properties. Our top nine producing wells represent approximately 34% of our estimated proved reserves at December 31, 2003. In addition, approximately 87% of our estimated present value of 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.

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. In 2003, we increased the allowance for doubtful accounts related to amounts due from joint interest owners by approximately $900,000. We cannot assure you that we will not suffer any economic loss related to credit risks in the future.

Uncertainties Regarding Liquidity and Capital Resources

Our cash flow forecasts indicate 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 2004. 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. Below is a discussion of uncertainties that are likely to have a material effect on our liquidity and capital resources if such uncertainties occur.

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, 2003 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 2004 by approximately $1.3 million and $7.3 million, respectively.

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.

Application of Critical Accounting Policies and Estimates

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:
2003	10.3	62.9	$	30.45	$	5.61	$	335.1
2002	11.9	86.9	$	28.98	$	4.44	$	382.5
2001	9.3	75.0	$	17.92	$	2.64	$	186.9

(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 geological and geophysical 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.

Recent Accounting Pronouncements

In May 2003, the FASB issued Statement of Financial Accounting Standards No. 150 “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity” (“SFAS 150”). This statement establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity and requires that an issuer classify a financial instrument that is within its scope as a liability (or an asset in certain circumstances). SFAS 150 is effective at the beginning of the first interim period beginning after June 15, 2003 for financial instruments entered into or modified after May 31, 2003. Our adoption of SFAS 150 did not have a material effect on our consolidated financial position or results of operations.

In January 2003, the FASB issued Financial Interpretation No. 46, “Consolidation of Variable Interest Entities - an interpretation of ARB No. 51” (“FIN 46”). In December 2003, the FASB revised certain aspects of FIN 46 (“FIN 46R”). FIN 46R is an interpretation of Accounting Research Bulletin 51, “Consolidated Financial Statements”, and addresses consolidation by business enterprises of variable interest entities. The primary objective of FIN 46R is to provide guidance on the identification of, and financial reporting for, entities over which control is achieved through means other than voting rights; such entities are known as variable interest entities. FIN 46R requires an enterprise to consolidate a variable interest entity if that enterprise has a variable interest that will absorb a majority of the entity’s expected losses if they occur, receive a majority of the entity’s expected residual return if they occur, or both. An enterprise shall consider the rights and obligations conveyed by its variable interests in making this determination. We are currently evaluating what impact, if any, FIN 46R will have on our financial statements. We must adopt FIN 46R in the first quarter of 2004.

In its recent review of registrants’ filings, the staff of the Securities and Exchange Commission (“SEC”) has questioned the applicability of SFAS No. 142 “Goodwill and Other Intangible Assets” (“SFAS 142”) to lease agreements and drilling rights commonly utilized in the oil and gas industry. If applicable, SFAS 142 could require oil and gas companies to separately report on their balance sheets the costs of proved and unproved leasehold and mineral interests acquired after June 30, 2001, including related accumulated depletion, as intangible assets and provide related intangible asset disclosures. Oil and gas companies have generally included leasehold costs in the property and equipment caption on the balance sheet since the value of the proved leases is inseparable from the value of the related oil and gas reserves, and since the costs of unproved leasehold and mineral interests are regularly evaluated for impairment based on lease terms and drilling activity. The Emerging Issues Task Force has recently added this issue to its agenda. If SFAS 142 is determined to apply to oil and gas companies, we may be required to make certain reclassifications within property and equipment on the balance sheet, and additional disclosures may be required. The reclassification of these amounts would not affect the method in which such costs are amortized or the manner in which we assesses impairment of capitalized costs. As a result, net income would not be affected by the reclassification.

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, 2003 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 $8.6 million.

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 the Company’s net positions in open commodity derivatives applicable to periods subsequent to December 31, 2003.

	Oil Swaps
	Bbls	Average Price
Production Period:
1st Quarter 2004	100,000	$	31.53
2nd Quarter 2004	150,000	$	31.53
3rd Quarter 2004	150,000	$	31.53
4th Quarter 2004	150,000	$	31.53
	550,000

	Gas Collars
	MMBtu (a)	Floor		Ceiling
Production Period:
1st Quarter 2004	3,200,000	$	4.50	$	7.04
2nd Quarter 2004	2,500,000	$	4.20	$	5.28
3rd Quarter 2004	2,220,000	$	4.20	$	5.28
4th Quarter 2004	690,000	$	4.20	$	5.28
	8,610,000

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

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. The fair values of swaps react differently to changes in oil and gas prices than the fair values of collars. A $1 increase in the price per barrel of oil would result in an additional liability related to our position in oil swaps of $550,000. With regard to our position in gas collars, a $.50 per MMBtu increase in gas prices would result in a decrease in fair value of approximately $2.1 million, while a $.50 per MMBtu decrease in gas prices would result in an increase in fair value of approximately $1.7 million.

Interest Rates

All of our outstanding bank indebtedness at December 31, 2003 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. We do not have any interest rate derivatives in place at the present time.

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.

Item 9A - 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 as of the end of the period covered by 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 are effective in ensuring that information that is required to be disclosed by the Company in reports filed or submitted with the SEC is recorded, processed, summarized and reported within the time periods specified in the rules and forms established by the SEC.

Changes in Internal Control Over Financial Reporting

No changes in internal control over financial reporting were made during the quarter ended December 31, 2003 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART III

Information Incorporated by Reference

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 and Item 14 – Principal Accountant Fees and Services is incorporated by reference from our definitive proxy statement, which will be filed with the SEC no later than April 29, 2004. 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.

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, 2003, we filed the following reports on Form 8-K:

• Form 8-K dated November 5, 2003 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, 2003.

• Form 8-K dated November 5, 2003 announcing third quarter earnings.

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

Exhibit Number		Description of Exhibit

**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, filed as Exhibit 10.2 to the Company’s Form 10-K for the period ended December 31, 2002

*10.3		Second Amendment to Ninth Restated Loan Agreement dated as of December 23, 2003 among Clayton Williams Energy, Inc., et al and Bank One, NA, et al

*10.4		Third Amendment to Ninth Restated Loan Agreement dated as of March 3, 2004 among Clayton Williams Energy, Inc., et al and Bank One, NA, et al

**10.5†		1993 Stock Compensation Plan, filed as Exhibit 10.1 to the Company’s Form S-8 Registration Statement, Registration No. 33-68318

**10.6†		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

**10.7†		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

**10.8†		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

**10.9†		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

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

**10.11†		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

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

**10.13†		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

**10.14†		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

**10.15†		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

Exhibit Number		Description of Exhibit

**10.16†		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

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

**10.18†		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

**10.19		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

**10.20		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

**10.21		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

**10.22		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

**10.23†		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

**10.24†		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

**10.25†		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

**10.26†		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

**10.27†		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

**10.28†		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

**10.29†		Agreement of Limited Partnership of CWEI South Louisiana I, L.P. dated October 1, 2002, filed as Exhibit 10.27 to the Company’s Form 10-K for the period ended December 31, 2002

**10.30†		Agreement of Limited Partnership of CWEI Cotton Valley I, L.P. dated October 1, 2002, filed as Exhibit 10.28 to the Company’s Form 10-K for the period ended December 31, 2002

**10.31†		Agreement of Limited Partnership of CWEI Romere Pass, L.P. dated October 1, 2002, filed as Exhibit 10.29 to the Company’s Form 10-K for the period ended December 31, 2002

Exhibit Number		Description of Exhibit

*10.32†		Agreement of Limited Partnership of CWEI Longfellow Ranch I, L.P. dated April 1, 2003

*21		Subsidiaries of the Registrant

*23.1		Consent of KPMG LLP

*23.2		Consent of Williamson Petroleum Consultants, Inc.

*24.1		Power of Attorney

*31.1		Certification by the President and Chief Executive Officer of the Company pursuant to Rule 13a — 14(a) of the Securities Exchange Act of 1934

*31.2		Certification by the Chief Financial Officer of the Company pursuant to Rule 13a — 14(a) of the Securities Exchange Act of 1934

*32.1		Certification by the President and Chief Executive Officer of the Company pursuant to 18 U.S.C. § 1350

*32.2		Certification by the Chief Financial Officer of the Company pursuant to 18 U.S.C. § 1350

*			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.

AVO (amplitude versus offset). A seismic characteristic which may indicate the presence of natural gas in a structure.

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 10, 2004
		Clayton W. Williams	President and Chief Executive Officer and Director

		/s/ L. PAUL LATHAM	Executive Vice President,	March 10, 2004
		L. Paul Latham	Chief Operating Officer and Director

		/s/ MEL G. RIGGS *	Senior Vice President -	March 10, 2004
		Mel G. Riggs	Finance, Secretary, Treasurer, Chief Financial Officer and Director

		/s/ STANLEY S. BEARD *	Director	March 10, 2004
		Stanley S. Beard

		/s/ DAVIS L. FORD *	Director	March 10, 2004
		Davis L. Ford

		/s/ ROBERT L. PARKER *	Director	March 10, 2004
		Robert L. Parker

		/s/ JORDAN R. SMITH *	Director	March 10, 2004
		Jordan R. Smith

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

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, 2003 and 2002, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2003. These consolidated 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 consolidated 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, 2003 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, 2003, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 4 of the consolidated financial statements, effective January 1, 2003, the Company changed its method of accounting for abandonment obligations in accordance with Statement of Financial Accounting Standards No. 143 “Accounting for Asset Retirement Obligations”. As discussed in Note 6 of the consolidated financial statements, effective January 1, 2001, the Company changed its method of accounting for derivative instruments in accordance with Statement of Financial Accounting Standards No. 133 “Accounting for Derivative Instruments and Hedging Activities”.

KPMG LLP

Dallas, Texas

February 25, 2004

F-2

CLAYTON WILLIAMS ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

	December 31,
	2003			2002
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	15,454		$	5,676
Accounts receivable:
Oil and gas sales, net	16,725			14,426
Joint interest and other, net	2,972			3,714
Affiliates	453			223
Inventory	787			2,141
Deferred income taxes	1,241			524
Prepaids and other	1,518			5,215
	39,150			31,919
PROPERTY AND EQUIPMENT
Oil and gas properties, successful efforts method	656,531			617,320
Natural gas gathering and processing systems	16,829			16,203
Other	12,300			11,918
	685,660			645,441
Less accumulated depreciation, depletion and amortization	(504,101		)	(466,815		)
Property and equipment, net	181,559			178,626
OTHER ASSETS
Deferred income taxes	—			6,594
Investments and other	3,724			1,853
	3,724			8,447
	$	224,433		$	218,992

LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts payable:
Trade	$	33,523		$	22,440
Oil and gas sales	10,086			8,274
Affiliates	1,254			1,257
Current maturities of long-term debt	2,453			—
Fair value of derivatives	2,233			12,917
Accrued liabilities and other	2,720			5,874
	52,269			50,762
NON-CURRENT LIABILITIES
Long-term debt	53,295			94,949
Deferred income taxes	8,504			—
Other	9,584			4,500
	71,383			99,449
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS’ EQUITY
Preferred stock, par value $.10 per shares, authorized – 3,000,000 shares; issued and outstanding – none	—			—
Comon stock, par value $.10 per shares, authorized – 30,000,000 shares; issued and outstanding – 9,368,322 shares in 2003 and 9,277,415 shares in 2002	937			928
Additional paid-in capital	73,972			72,787
Retained earnings	25,872			3,016
Accumulated other comprehensive income (loss)	—			(7,950		)
	100,781			68,781
	$	224,433		$	218,992

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,
	2003			2002			2001
REVENUES
Oil and gas sales	$	163,032		$	86,302		$	105,118
Natural gas services	8,758			5,568			8,820
Total revenues	171,790			91,870			113,938

COSTS AND EXPENSES
Lease operations	28,239			21,857			20,427
Exploration:
Abandonments and impairments	35,120			21,571			29,412
Seismic and other	8,755			8,578			12,868
Natural gas services	8,279			4,853			7,467
Depreciation, depletion and amortization	40,284			29,656			37,459
Impairment of property and equipment	170			349			18,170
Accretion of abandonment obligations	651			—			—
General and administrative	10,934			8,615			7,456
Total costs and expenses	132,432			95,479			133,259
Operating income (loss)	39,358			(3,609		)	(19,321		)
OTHER INCOME (EXPENSE)
Interest expense	(3,138		)	(4,006		)	(2,925		)
Gain on sales of property and equipment	199			361			10,986
Change in fair value of derivatives	(1,593		)	(1,581		)	2,227
Other	(1,662		)	1,755			66
Total other income (expense)	(6,194		)	(3,471		)	10,354
Income (loss) before income taxes	33,164			(7,080		)	(8,967		)
Income tax expense (benefit)	10,515			(1,742		)	(3,421		)
Income (loss) from continuing operations	22,649			(5,338		)	(5,546		)
Cumulative effect of accounting change, net of tax	207			—			(164		)
Income from discontinued operations, including gain on sale of $1,196 in 2002, net of tax	—			1,335			406
NET INCOME (LOSS)	$	22,856		$	(4,003	)	$	(5,304	)
Net income (loss) per common share:
Basic:
Income (loss) from continuing operations	$	2.43		$	(.58	)	$	(.60	)
Net income (loss)	$	2.45		$	(.43	)	$	(.58	)

Diluted:
Income (loss) from continuing operations	$	2.38		$	(.58	)	$	(.60	)
Net income (loss)	$	2.40		$	(.43	)	$	(.58	)

Weighted average common shares outstanding:
Basic	9,329			9,241			9,219
Diluted	9,509			9,241			9,219

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)

												Accumulated
												Other			Total
	Common Stock					Additional						Compre-			Compre-
	No. of		Par			Paid-In			Retained			hensive			hensive
	Shares		Value			Capital			Earnings (Loss)			Income (Loss)			Income (Loss)

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 derivatives designated as cash flow hedges, net of tax	—		—			—			—			1,997			1,997
Total comprehensive 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, net of tax	—		—			—			—			(9,761		)	(9,761		)
Total comprehensive 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		)
Net income	—		—			—			22,856			—			$	22,856
Change in fair value of derivatives designated as cash flow hedges, net of tax	—		—			—			—			7,950			7,950
Total comprehensive income															$	30,806
Issuance of stock through compensation plans	91		9			1,185			—			—

BALANCE, December 31, 2003	9,368		$	937		$	73,972		$	25,872		$	—

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,
	2003			2002			2001
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	22,856		$	(4,003	)	$	(5,304	)
Adjustments to reconcile net income (loss) to cash provided by operating activities:
Depreciation, depletion and amortization	40,284			29,656			37,459
Impairment of property and equipment	170			349			18,170
Exploration costs	35,120			21,571			29,412
Gain on sales of property and equipment	(199		)	(361		)	(10,986		)
Deferred income taxes	10,172			(1,742		)	(3,421		)
Non-cash employee compensation	1,312			837			44
Change in fair value of derivatives	1,546			2,172			(1,739		)
Accretion of abandonment obligations	651			—			—
Cumulative effect of accounting change, net of tax	(207		)	—			164
Non-cash effect of discontinued operations, including gain on sale, net of tax	—			(1,029		)	449
Changes in operating working capital:
Accounts receivable	(1,787		)	(8,561		)	10,013
Accounts payable	8,655			(5,389		)	(7,429		)
Other	1,177			1,014			227
Net cash provided by operating activities	119,750			34,514			67,059

CASH FLOWS FROM INVESTING ACTIVITIES
Additions to property and equipment	(62,889		)	(71,635		)	(112,731		)
Proceeds from sales of property and equipment	239			7,607			16,334
Other	(2,120		)	(3		)	(1,545		)
Net cash used in investing activities	(64,770		)	(64,031		)	(97,942		)

CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt	—			32,949			32,000
Repayments of long-term debt	(45,483		)	—			—
Proceeds from sale of common stock	281			36			150
Repurchase and cancellation of common stock	—			(648		)	(795		)
Net cash provided by (used in) financing activities	(45,202		)	32,337			31,355

NET INCREASE IN CASH AND CASH EQUIVALENTS	9,778			2,820			472

CASH AND CASH EQUIVALENTS
Beginning of period	5,676			2,856			2,384
End of period	$	15,454		$	5,676		$	2,856

SUPPLEMENTAL DISCLOSURES
Cash paid for interest, net of amounts capitalized	$	2,941		$	3,995		$	2,946

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; and

• 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

F-7

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.

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”). 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, 2003, the Company’s unproved oil and gas properties had an aggregate net book value of $25.7 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.

Abandonment Obligations

The Company follows the provisions of Statement of Financial Accounting Standards No. 143 “Accounting for Asset Retirement Obligations” (“SFAS 143”), as amended. SFAS 143 requires the Company to recognize a liability for the present value of all legal obligations associated with the retirement of tangible, long-lived assets and capitalize an equal amount as a cost of the asset. The cost of the abandonment obligation, along with any estimated salvage value, is included in the computation of depreciation, depletion and amortization.

F-8

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.

Hedging Activities

From time to time, the Company utilizes derivative instruments, consisting primarily of swaps and collars, 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, 2003, 2002 and 2001, the Company capitalized interest totaling approximately $1.1 million, $600,000 and $523,000, 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 2003 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.

F-9

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 estimated at the date of grant using the Black-Scholes option pricing model. The estimated fair value of the stock options issued in 2003 was approximately $3 million. No options were granted during 2002. The following weighted average assumptions were used in this model.

	2003		2002

Risk-free interest rate	2.5	%	—
Stock price volatility	70	%	—
Expected life in years	10		—
Dividend yield	—		—

The SFAS 123 pro forma information for the years ended December 31, 2003, 2002 and 2001 is as follows:

	2003			2002			2001
	(In thousands, except per share)
Net income (loss), as reported	$	22,856		$	(4,003	)	$	(5,304	)
Add: Stock-based employee compensation expense (credit) included in net income (loss), net of tax	518			(21		)	(269		)
Deduct: Stock-based employee compensation expense determined under fair value based method (SFAS 123), net of tax	(2,602		)	(883		)	(795		)
Net income (loss), pro forma	$	20,772		$	(4,907	)	$	(6,368	)

Basic:
Net income (loss) per common share, as reported	$	2.45		$	(.43	)	$	(.58	)
Net income (loss) per common share, pro forma	$	2.23		$	(.53	)	$	(.69	)

Diluted:
Net income (loss) per common share, as reported	$	2.40		$	(.43	)	$	(.58	)
Net income (loss) per common share, pro forma	$	2.18		$	(.53	)	$	(.69	)

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, 2003 or 2002. 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. A

F-10

portion of the changes in fair value of derivatives required under SFAS 133 was reported as comprehensive income during 2003, 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. In 2003, the Company increased the allowance for doubtful accounts related to amounts due from joint interest owners in certain properties operated by the Company. The Company is actively seeking collections from these owners. Allowances for doubtful accounts at December 31, 2003 and 2002 consist of the following:

	2003		2002
	(In thousands)
Accounts receivable:
Joint interest and other	$	1,338	$	400
Oil and gas sales	—		286
	$	1,338	$	686

A significant portion of the Company’s estimated proved oil and gas reserves are concentrated in a few properties. Nine of the Company’s producing wells represent approximately 34% of the Company’s estimated proved reserves at December 31, 2003. 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.

Recent Accounting Pronouncements

In May 2003, the FASB issued Statement of Financial Accounting Standards No. 150 “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity” (“SFAS 150”). This statement establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity and requires that an issuer classify a financial instrument that is within its scope as a liability (or an asset in certain circumstances). SFAS 150 is effective at the beginning of the first interim period beginning after June 15, 2003 for financial instruments entered into or modified after May 31, 2003. The Company’s adoption of SFAS 150 did not have a material effect on its consolidated financial position or results of operations.

F-11

If it is ultimately determined that SFAS No. 142 requires the Company to reclassify costs associated with mineral rights from property and equipment to intangible assets, the amounts that would be reclassified are as follows, assuming all mineral rights are reclassified:

	December 31,
	2003			2002
	(In thousands)
INTANGIBLE ASSETS:
Proved leasehold acquisition costs	$	68,496		$	71,488
Unproved leasehold acquisition costs	18,466			18,763
Total leasehold acquisition costs	86,962			90,251
Less: Accumulated depletion	(42,249		)	(37,202		)
Net leasehold acquisition costs	$	44,713		$	53,049

The Company does not believe the reclassification of these amounts would affect the method in which such costs are amortized or the manner in which the Company assesses impairment of capitalized costs. As a result, net income would not be affected by the reclassification.

3. Long-Term Debt

Long-term debt at December 31, 2003 and 2002 consists of the following:

	2003		2002
	(In thousands)
Secured Bank Credit Facility (matures December 31, 2005)	$	50,000	$	93,000
Vendor finance obligations	5,748		1,949
	55,748		94,949
Less current maturities of vendor finance obligations	2,453		—
	$	53,295	$	94,949

Aggregate maturities of long-term debt at December 31, 2003 are as follows: 2004 - $2,453,000 and 2005 - $53,295,000.

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

F-12

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, 2003, 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 $55.7 million available under the credit facility at December 31, 2003. Subsequent to December 31, 2003, the borrowing base was reduced to $95 million, and the maturity was extended to December 31, 2005.

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 loans 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, 2003, the Company’s indebtedness under the credit facility consisted of $50 million of Eurodollar Loans at a rate of 2.7%. The effective annual interest rate on the credit facility, including bank fees and interest rate derivatives, for the year ended December 31, 2003 was 5.4%.

In addition, the Company pays the banks a commitment fee ranging from .25% to .38% 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, 2005.

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, 2003.

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, 2003 totaled $5.7 million, of which $2.5 million was classified as a current liability.

F-13

4. Other Non-Current Liabilities

Other non-current liabilities at December 31, 2003 and 2002 consist of the following:

	2003		2002
	(In thousands)
Abandonment obligations	$	8,849	$	3,500
Production payment	735		1,000
	$	9,584	$	4,500

Abandonment Obligations

As of December 31, 2002, the amounts represent future abandonment obligations applicable to wells acquired in the Romere Pass acquisition discussed in Note 14. The Company has been required to issue letters of credit aggregating $4.25 million to secure the Romere Pass obligation, $3.5 million to a prior owner of the acquired assets and $750,000 to a federal agency.

Upon adoption of SFAS 143 on January 1, 2003, the Company increased abandonment obligations by $4.1 million, increased asset costs by $1.5 million, reduced accumulated depreciation, depletion and amortization by $2.9 million, and recorded an after-tax credit of $207,000 for the cumulative effect of adoption on prior years. Changes in abandonment obligations from January 1, 2003 to December 31, 2003 consist primarily of $700,000 in revisions to previous estimates and $651,000 of accretion expense. The following sets forth pro forma results of operations for the years ended December 31, 2003, 2002 and 2001, assuming the Company adopted SFAS 143 on January 1, 2001.

	Pro forma Year Ended December 31,
	2003		2002			2001
	(In thousands, except per share)
Net income (loss)	$	22,649	$	(4,395	)	$	(5,674	)
Net income (loss) per common share:
Basic	$	2.43	$	(.48	)	$	(.62	)
Diluted	$	2.38	$	(.48	)	$	(.62	)

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-14

5. 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, 2003 and 2002 are as follows:

	2003			2002
	(In thousands)
Deferred tax assets:
Net operating loss carryforwards	$	6,915		$	10,623
Accrued stock-based compensation	335			132
Fair value of derivatives	783			4,523
Credits related to alternative minimum tax	343			—
Other	1,419			1,105
	9,795			16,383
Deferred tax liabilities:
Property and equipment	(17,058		)	(8,389		)
Valuation allowance	—			(876		)
	(17,058		)	(9,265		)
Net deferred tax assets (liabilities)	$	(7,263	)	$	7,118

Components of net deferred tax assets (liabilities):
Current assets	$	1,241		$	524
Non-current assets (liabilities)	(8,504		)	6,594
	$	(7,263	)	$	7,118

For the years ended December 31, 2003, 2002 and 2001, the Company’s effective income tax rates were different than the statutory federal income tax rates for the following reasons:

	2003			2002			2001
	(In thousands)
Income tax expense (benefit) at statutory rate of 35%	$	11,608		$	(2,478	)	$	(3,139	)
Tax depletion in excess of basis	(210		)	(174		)	(210		)
Revision of previous tax estimates	(12		)	39			(74		)
Change in valuation allowance	(871		)	871			—
Other	—			—			2
Income tax expense (benefit)	$	10,515		$	(1,742	)	$	(3,421	)

Current	$	343		$	—		$	—
Deferred	10,172			(1,742		)	(3,421		)
Income tax expense (benefit)	$	10,515		$	(1,742	)	$	(3,421	)

The Company derives an income tax benefit when employees and directors exercise options granted under the Company’s stock compensation plans (see Note 9). 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 of fixed stock options results in a permanent difference, which is recorded to additional paid-in capital when the tax benefit is realized.

During 2003, the Company’s pre-tax income was sufficient to cause deferred tax liabilities to exceed deferred tax assets. Based upon current commodity prices and production volumes, as well as the availability of tax planning strategies (such as elective capitalization of intangible drilling costs), the

F-15

Company presently believes that it is more likely than not that the Company will be able to utilize its cumulative tax loss carryforwards of $19.8 million at December 31, 2003 before they expire (beginning in 2008). Accordingly, during the quarter ended June 30, 2003, the Company reversed $876,000 of the valuation allowances provided at December 31, 2002, $5,000 of which was related to permanent differences arising from the exercise of employee stock options.

6. Derivatives

Commodity Derivatives

From time to time, the Company utilizes commodity derivatives, consisting of swaps and collars, 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. Collars 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 applicable to periods subsequent to December 31, 2003.

	Oil Swaps (a)
	Bbls	Average Price
Production Period:
1st Quarter 2004	100,000	$	31.53
2nd Quarter 2004	150,000	$	31.53
3rd Quarter 2004	150,000	$	31.53
4th Quarter 2004	150,000	$	31.53
	550,000

	Gas Collars
	MMBtu (b)	Floor		Ceiling
Production Period:
1st Quarter 2004	3,200,000	$	4.50	$	7.04
2nd Quarter 2004	2,500,000	$	4.20	$	5.28
3rd Quarter 2004	2,220,000	$	4.20	$	5.28
4th Quarter 2004	690,000	$	4.20	$	5.28
	8,610,000

(a) Positions taken in January 2004.

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

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 provided for the Company to pay a fixed rate of 3.63% for the two-year term of the swap. The counterparty paid a floating rate based on the LIBOR-BBA one-month rate. The swap required a monthly cash settlement for the difference between the fixed rate and the floating rate. The swap expired in November 2003.

F-16

Accounting For Derivatives

The Company accounts for its derivatives in accordance with Statement of Financial Accounting Standards No. 133 “Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”), as amended. The following table sets forth, for the years ended December 31, 2003 and 2002, 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, 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		)
Change in fair value of derivatives, net of tax	(5,429		)	(50		)	(5,479		)
Reclassifications to earnings, net of tax	12,719			710			13,429
Net changes during the period	7,290			660			7,950
Balance, December 31, 2003	$	—		$	—		$	—

The Company did not designate any of its currently open positions in commodity hedges; therefore, all changes in the fair value of these contracts prior to maturity, plus any realized gains or losses at maturity, are recorded as other income (expense) in the Company’s statements of operations.

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.

7. 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 $6.5 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.

F-17

The fair values of derivatives as of December 31, 2003 and 2002 are set forth below. The associated carrying values of derivatives at December 31, 2003 and 2002 are equal to their estimated fair values.

	2003			2002
	(In thousands)
Assets (liabilities):
Commodity derivatives	$	(2,233	)	$	(11,902	)
Interest rate derivatives	—			(1,015		)
Net assets (liabilities)	$	(2,233	)	$	(12,917	)

8. Stock Repurchase Program

In July 2002, the Company’s Board of Directors authorized the continuation until July 2004 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. Since initiation of this program in 2000, 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. No shares were repurchased in 2003.

9. 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, 2003 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 2003, 2002 and 2001.

	2003				2002				2001
	Shares		Weighted Average Price		Shares		Weighted Average Price		Shares		Weighted Average Price
Beginning of year	680,850		$	12.29	687,350		$	12.22	465,840		$	9.83
Granted	200,000		$	19.74	—		$	—	250,000		$	15.94
Exercised	(59,808	)	$	4.03	(6,500	)	$	5.50	(25,879	)	$	5.51
Forfeited	—		$	—	—		$	—	(2,611	)	$	7.95
End of year	821,042		$	14.66	680,850		$	12.29	687,350		$	12.22

Exercisable	821,042		$	14.66	668,032		$	12.41	655,467		$	12.54
Issuable	601,766				801,766				801,766

F-18

The following table summarizes information with respect to options outstanding and exercisable at December 31, 2003.

	Outstanding Options				Options Exercisable
	Shares	Weighted Average Exercise Price		Weighted Average Remaining Life in Years	Shares	Weighted Average Exercise Price
Range of exercise prices:
$ 5.50 - $6.00	170,042	$	5.50	4.3	170,042	$	5.50
$ 14.50 - $19.74	651,000	$	17.05	6.5	651,000	$	17.05
	821,042	$	14.66	4.7	821,042	$	14.66

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, 2003 and 2002 is classified as a current liability in the accompanying consolidated balance sheet and is comprised of the following activity for the years then ended.

	2003			2002
	(In thousands)
Beginning of year	$	377		$	417
Compensation expense (credit)	797			(32		)
Amounts reclassified to additional paid-in capital for options exercised during the period	(216		)	(8		)
End of year	$	958		$	377

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 33,000 shares of common stock (3,000 per year from 1993 through 2003) 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, 2003, options to purchase 21,000 shares were outstanding, and 53,300 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, 2003, 106,190 shares remain available for issuance under this plan.

F-19

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 2003, 2002 and 2001, the Company issued 15,275, 54,833 and 14,638 shares, respectively, of common stock to Mr. Williams in lieu of cash salary and bonuses aggregating $270,000, $647,000 and $230,000, respectively. The amounts of such compensation are included in general and administrative expense in the accompanying consolidated financial statements. At December 31, 2003, 137,479 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 2003, 2002 and 2001, the Company contributed $247,000, $224,000 and $228,000, respectively, in market value of common stock to the 401(k) plan.

Working Interest Trusts

Effective May 1, 2003, the working interest trust covering certain wells in the Cotton Valley Reef Complex and the Austin Chalk (Trend) paid out. The applicable working interests have been distributed to the participants, consisting of officers and key employees of the Company, excluding Mr. Williams. In 2003, participants were paid an aggregate of $750,000 with respect to the distributed interests. Based on estimates at December 31, 2003, using guidelines established by the SEC, proved oil and gas reserves attributable to the distributed interests totaled 663 MMcfe, and the present value of their future net revenues, discounted at 10%, totaled $2.2 million. Reserves attributable to the distributed interests have been excluded from the Company’s reserve estimates elsewhere in this Form 10-K.

After-Payout Working Interest Incentive Plans

The Compensation Committee of the Board of Directors, in September 2002, adopted an incentive plan for officers, 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 11), (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. In May 2003, the Company formed an additional partnership and committed to contribute 5% of its working interests in wells to be drilled on certain acreage in Pecos County, Texas. One of the partnerships is expected to pay out in 2004.

F-20

10. Transactions with Affiliates

The Company and other entities (the “Williams Entities”) controlled by Mr. Williams 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 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 following table summarizes the charges to and from the Williams Entities for the years ended December 31, 2003, 2002 and 2001.

	2003		2002		2001
	(In thousands)
Amounts received from the Williams Entities:
Service Agreement:
Services	$	288	$	224	$	195
Insurance premiums and benefits	682		383		370
Reimbursed expenses	357		272		355
	$	1,327	$	879	$	920
Amounts paid to the Williams Entities:
Rent (a)	$	402	$	370	$	273
Service Agreement:
Business entertainment (b)	79		64		55
Other services	45		34		37
Reimbursed expenses	73		57		9
	$	599	$	525	$	374

(a) Rent amounts were paid to the Partnership discussed in Note 11. The Company owns 31.9% of the Partnership and affiliates of the Company own 23.3%.

(b) Consists of hunting and fishing rights pertaining to land owned by affiliates of Mr. Williams.

Accounts receivable from affiliates and accounts payable to affiliates include, among other things, amounts for customary charges whereby the Company is the operator of certain wells in which affiliates own an interest.

11. Investment

In May 2001, we 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 our corporate headquarters. Our ownership interest in the partnership is 31.9% before payout (as defined in the partnership agreement) and 33.4% after payout. We are not liable for any indebtedness of the partnership. An entity controlled by Mr. Williams serves as general partner of the partnership. We do not manage or control the operations of the partnership or these buildings. We currently utilize the equity method of accounting for our investment in this partnership. For the years ended December 31, 2003, 2002 and 2001, the Company recorded pretax income of $47,000, $119,000 and a pretax loss of $63,000, respectively, from the partnership.

In October 2003, the Company invested $1.5 million in a privately-held company organized by a third party to acquire and expand a CO₂ distribution system in Pecos County, Texas. Of the total investment, 50% was for the purchase of common stock, representing 6.3% of the equity interests of the investee. The balance was a subordinated loan to the investee bearing interest at 6% per year. The Company accounts for the stock portion of its investment on the equity method of accounting.

F-21

12. 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 $578,000, $501,000 and $503,000 for the years ended December 31, 2003, 2002 and 2001, respectively.

Future minimum payments under noncancelable leases at December 31, 2003, are as follows:

	Operating Leases
	(In thousands)
2004	$	776
2005	689
2006	604
Thereafter	212
Total minimum lease payments	$	2,281

Legal Proceedings

The Company was a defendant in a suit filed in the 82nd Judicial District Court in Robertson County, Texas by lessors of the lease on which its Lee Fazzino Unit #1 and #2 wells (the “Wells”) were drilled. In November 2003, the Company agreed to settle this litigation with the lessors. Under the settlement terms, the Company will (i) grant the lessor a 1.2% overriding royalty interest in the Wells, which interest reduces to 1% after 24 months and (ii) pay the lessors $400,000 in cash. The Company has also agreed to reimburse those royalty owners in the Wells whose interests were aligned with the Company in the suit for certain of their attorney fees incurred in connection with the litigation. The lessors will (i) grant a new lease to the Company for approximately 500 net acres, (ii) ratify all existing leases and the unit agreement, and (iii) execute a release of any and all claims with regard to the leases, Wells and unit agreement. The Company recorded a $1.3 million pre-tax charge against earnings during the third quarter of 2003 for the settlement of this litigation. The charge is reported in other income (expense) in the accompanying statement of operations. This suit was dismissed with prejudice in March 2004.

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.

13. Impairment of Property and Equipment

The Company has recorded provisions for impairment of proved properties under SFAS 144 and SFAS 121 of $170,000 in 2003, $349,000 in 2002 and $18.2 million in 2001. The 2003 provision relates to the Sweetlake area impaired in prior years. 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 $7.3 million, $7.9 million and $10.2 million in 2003, 2002 and 2001, respectively, and have charged these impairments to exploration costs in the accompanying statements of operations.

F-22

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 $21.2 million, net of closing adjustments. The effective date of the purchase for accounting purposes was August 1, 2002. The purchase price consisted of $17 million cash, the assumption of future abandonment obligations, and the granting of a $1 million after payout production payment. 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 during the quarter ended September 30, 2002. 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
	(In thousands)
Revenues	$	363	$	1,065
Gain on sale of property and equipment	$	1,840	$	—
Income before income taxes	$	2,054	$	625
Net income	$	1,335	$	406

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 2002.

F-23

16. Quarterly Financial Data (Unaudited)

The following table summarizes results for each of the four quarters in the years ended December 31, 2003 and 2002.

	First Quarter			Second Quarter		Third Quarter			Fourth Quarter			Year
	(In thousands, except per share)
Year ended December 31, 2003:
Total revenues	$	50,745		$	45,303	$	40,241		$	35,501		$	171,790
Gross profit (a)	$	41,234		$	36,575	$	30,939		$	26,524		$	135,272
Income (loss) from continuing operations	$	16,121		$	6,311	$	7,554		$	(7,337	)	$	22,649
Net income (loss) (c)	$	16,328		$	6,311	$	7,554		$	(7,337	)	$	22,856

Net income (loss) per common share (b):
Basic:
Income (loss) from continuing operations	$	1.73		$	0.68	$	0.81		$	(0.78	)	$	2.43
Net income (loss)	$	1.76		$	0.68	$	0.81		$	(0.78	)	$	2.45

Diluted:
Income (loss) from continuing operations	$	1.71		$	0.67	$	0.79		$	(0.78	)	$	2.38
Net income (loss)	$	1.73		$	0.67	$	0.79		$	(0.78	)	$	2.40

Weighted average common shares outstanding:
Basic	9,303			9,319		9,330			9,364			9,329
Diluted	9,433			9,447		9,565			9,364			9,509

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 common shares outstanding:
Basic	9,211			9,236		9,255			9,272			9,241
Diluted	9,211			9,375		9,255			9,272			9,241

(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.

F-24

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, 2003, 2002 and 2001.

	2003		2002		2001
	(In thousands)
Property acquisitions:
Proved	$	—	$	18,249	$	1,278
Unproved	7,982		20,311		14,418
Developmental costs	11,689		4,964		19,692
Exploratory costs	49,277		27,011		75,857
Asset retirement costs (a)	776		3,500		—
Total	$	69,724	$	74,035	$	111,245

(a) Excluded from asset retirement costs in 2003 was $1.5 million related to the cumulative effect of the adoption of SFAS 143 on January 1, 2003.

The following table sets forth the capitalized costs for oil and gas properties as of December 31, 2003 and 2002.

	2003			2002
	(In thousands)
Proved properties	$	630,827		$	597,980
Unproved properties	25,704			19,340
Total capitalized costs	656,531			617,320
Accumulated depreciation, depletion and amortization	(483,628		)	(447,745		)
Net capitalized costs	$	172,903		$	169,575

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, 2003 are classified as proved developed nonproducing, which increases the imprecision inherent in estimating reserves which may ultimately be produced.

F-25

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, 2003, 2002 and 2001.

	2003						2002						2001
	Oil		Gas		MMcfe		Oil		Gas		MMcfe		Oil		Gas		MMcfe
Proved reserves:
Beginning of period	11,884		86,912		158,216		9,291		74,974		130,720		12,911		28,308		105,774
Revisions	(84	)	(7,323	)	(7,827	)	1,813		8,156		19,034		(1,943	)	(2,478	)	(14,136	)
Extensions and discoveries	274		8,024		9,668		92		4,259		4,811		786		63,403		68,119
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	(1,739	)	(24,697	)	(35,131	)	(1,812	)	(15,972	)	(26,844	)	(2,378	)	(10,955	)	(25,223	)
Discontinued operations	—		—		—		(6	)	(72	)	(108	)	(13	)	(158	)	(236	)
End of period	10,335		62,916		124,926		11,884		86,912		158,216		9,291		74,974		130,720

Proved developed reserves:
Beginning of period	9,349		76,224		132,318		8,414		74,407		124,891		10,565		26,278		89,668
End of period	9,349		62,514		118,606		9,349		76,224		132,318		8,414		74,407		124,891

The standardized measure of discounted future net cash flows relating to proved reserves as of December 31, 2003, 2002 and 2001 was as follows:

	2003			2002			2001
	(In thousands)

Future cash inflows	$	667,896		$	730,609		$	364,712
Future costs:
Production	(179,500		)	(165,806		)	(92,700		)
Abandonment	(6,034		)	—			—
Development	(17,446		)	(24,782		)	(18,247		)
Income taxes	(118,869		)	(137,059		)	(36,870		)
Future net cash flows	346,047			402,962			216,895
10% discount factor	(93,067		)	(109,264		)	(52,307		)
Standardized measure of discounted net cash flows	$	252,980		$	293,698		$	164,588

Changes in the standardized measure of discounted future net cash flows relating to proved reserves for the years ended December 31, 2003, 2002 and 2001 were as follows:

	2003			2002			2001
	(In thousands)
Standardized measure, beginning of period	$	293,698		$	164,588		$	232,064
Net changes in sales prices, net of production costs	28,745			138,566			(143,132		)
Revisions of quantity estimates	(21,212		)	49,551			(22,209		)
Accretion of discount	38,252			18,687			30,746
Changes in future development costs, including development costs incurred that reduced future development costs	10,106			5,094			14,399
Changes in timing and other	(5,938		)	(16,827		)	(17,542		)
Net change in income taxes	10,282			(66,540		)	53,111
Future abandonment cost, net of salvage	(3,579		)	—			—
Extensions and discoveries	37,419			14,834			120,363
Sales, net of production costs:
Continuing operations	(134,793		)	(64,445		)	(84,691		)
Discontinued operations	—			(306		)	(855		)
Sales of minerals-in-place	—			(1,744		)	(18,833		)
Purchases of minerals-in-place	—			52,240			1,167
Standardized measure, end of period.	$	252,980		$	293,698		$	164,588

F-26

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, 2003, 2002 and 2001 were as follows:

	Average Price
	Oil (a)		Gas
As of December 31:
2003	$	30.45	$	5.61
2002	$	28.98	$	4.44
2001	$	17.92	$	2.64

(a) Includes natural gas liquids

F-27

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

Price Range of Common Stock

Dividend Policy

Stock Repurchase Program

Item 6 - Selected Financial Data

Item 7A - Quantitative and Qualitative Disclosure About Market Risks

Item 8 - Financial Statements and Supplementary Data

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

Item 9A - Controls and Procedures

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

Exhibit Number

Description of Exhibit

Exhibit Number

Description of Exhibit

Exhibit Number

Description of Exhibit

Exhibit Number

Description of Exhibit

GLOSSARY OF TERMS

SIGNATURES

Attorney-in-Fact

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Number

Exhibit
Number

Exhibit
Number

Exhibit
Number