UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

	(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, 2004

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. $147,894,730.

There were 10,794,195 shares of Common Stock, $.10 par value, of the registrant outstanding as of March 10, 2005.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the definitive proxy statement relating to the 2005 Annual Meeting of Stockholders, which will be filed with the Commission not later than April 30, 2005, are incorporated by reference in Part III of this Form 10-K.

CLAYTON WILLIAMS ENERGY, INC

Part I
	Item 1.	Business
			General
			Company Profile
			Exploration and Development Activities
			Marketing Arrangements
			Natural Gas Services
			Competition and Markets
			Regulation
			Environmental Matters
			Title to Properties
			Operational Hazards and Insurance
			Executive Officers
			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
			Acquisition of Southwest Royalties, Inc.
			Recent Exploration and Developmental Activities
			Proved Oil and Gas Reserves

			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
			Internal Control Over Financial Reporting
			Changes in Internal Control Over Financial Reporting
			Management’s Report on Internal Control Over Financial Reporting

	Item 9B.	Other Information

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
			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, 2004 were 138.3 Bcf of natural gas and 26.8 million barrels of oil and natural gas liquids, and our estimated present value of proved reserves was $705.3 million. During 2004, we added proved reserves of 46.8 Bcfe through extensions and discoveries, had upward revisions of previous estimates of 16.6 Bcfe, acquired 170.8 Bcfe through an acquisition and sold 28.1 Bcfe of reserves in place. CWEI held interests in 6,582 gross (886.9 net) producing oil and gas wells and owned leasehold interests in approximately 737,000 gross (388,000 net) undeveloped acres at December 31, 2004.

Clayton W. Williams beneficially owns, either individually or through his affiliates, approximately 41% 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, including the election of our Board members. 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, then expanded into other regions, including Mississippi and New Mexico.

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 and Louisiana.

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 lower-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 Louisiana and the Permian Basin area of west Texas and New Mexico. Approximately 66% of our planned expenditures for 2005 relate to exploratory prospects, as compared to approximately 81% of actual expenditures in 2004 and 83% of actual expenditures in 2003. During 2004, we spent $95.9 million on exploratory prospects, including $19.8 million on seismic and leasing activities and $76.1 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. 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 2005.

On May 21, 2004, we acquired all the outstanding common stock of Southwest Royalties, Inc. (“SWR”) through a merger. Prior to the acquisition, SWR was a privately-held, Midland-based energy company engaged in oil and gas exploration, production, development and acquisition activities in the United States. Most of SWR’s properties are located in the Permian Basin. Using reserve guidelines established by the SEC, the SWR acquisition added approximately 170.8 Bcfe to our proved oil and gas reserves on the effective date of the acquisition.

In connection with the acquisition, we paid $57.1 million to holders of SWR common stock and common stock warrants and assumed and refinanced approximately $113.9 million of SWR bank debt at closing. In addition, we incurred approximately $9.4 million of merger-related costs, including (i) the assumption of SWR’s obligations to its officers and employees pursuant to change of control arrangements and (ii) investment banking, legal, accounting and other direct transaction costs related to the acquisition.

From time to time, we decide to sell certain of our proved properties. In November 2004, we sold our interest in the Jo-Mill Unit in Borden County, Texas for cash proceeds of $22.1 million, subject to normal post-closing adjustments. This property was acquired in connection with the SWR acquisition. We realized a gain on sale of this property of $2.1 million. In December 2004, we sold substantially all of our interests in the Romere Pass Unit in Plaquemines Parish, Louisiana for cash proceeds of $8.2 million, subject to normal post-closing adjustments. We retained drilling rights to five locations in the unit, of which two are proved undeveloped locations and three are exploratory locations. Since the purchaser assumed all of our asset retirement obligations applicable to the unit, we were able to cancel a $3.5 million letter of credit issued to a previous owner. We realized a loss of $14.1 million on the sale of this property.

Exploration and Development Activities

In 2004, we spent $117.8 million on exploration and drilling activities, all of which was financed out of cash flow from operations. We presently plan to spend approximately $124.1 million on exploration and drilling activities during 2005, 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.

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.

We spent $68 million in south Louisiana during 2004 on exploration activities, of which $56.9 million was spent on drilling and completion activities and $11.1 million was spent on seismic and leasing activities.

Prior to 2004, we had drilled 35 gross (29.3 net) exploratory wells in south Louisiana, of which 15 gross (10.5 net) were completed as producers. The following table sets forth certain information about our exploratory well activities in south Louisiana in 2004.

Spud Date	Well Name (Prospect)	Working Interest		Current Status

February 2004	Louisiana Fruit Co. #1 (Tiger Pass)	100	%	Productive
February 2004	Mervine Jankower #1 (Bosco)	100	%	Dry
March 2004	Louisiana Fruit Co. #2 (Tiger Pass)	100	%	Productive
March 2004	State Lease 17341 #1 (Brandi)	100	%	Dry
March 2004	State Lease 17057 #1 (Nonoperated)	13	%	Dry
May 2004	State Lease 17378 #2 (Fleur) (a)	75	%	Productive
July 2004	JL&S #1 (Nonoperated)	55	%	Dry
August 2004	McIlhenny #1 (Tabasco)	33	%	Dry
September 2004	State Lease 17657 #1 (Nonoperated)	20	%	Dry
September 2004	Daigle et al #1 (King)	100	%	Productive
October 2004	LL&E “A” #1 (Jonita)	100	%	Dry
November 2004	Orleans Levee District #1 (American Bay)	45	%	Productive

(a) This well is classified as a developmental well based on data obtained in drilling the State Lease 17378 #1 (Fleur).

Approximately half of the 8.4 net wells commenced in Louisiana in 2004, as shown in the above table, were completed as producers. In addition, approximately 55% of the extensions and discoveries of proved oil and gas reserves during 2004 were derived from south Louisiana prospects. Despite these favorable results, our abandonment and impairment costs from south Louisiana prospects totaled $32.8 million due primarily to high costs on three wells. The State Lease 17378 #1 (Fleur) well was ultimately completed as a producer in a shallower zone after attempts to complete the well in a deeper zone were unsuccessful. As a result, we recorded an abandonment charge of approximately $10.7 million for costs incurred in the abandoned portion of the well. The Mervine Jankower #1 (Bosco) and the McIlhenny #1 (Tabasco) were high-cost exploratory wells that were determined to be dry, resulting in combined abandonment charges of $10.3 million.

In 2005, we currently plan to spend approximately $51.9 million in Louisiana on the following activities:

• $34.3 million to conclude drilling and/or completion activities on in-progress wells at December 31, 2004, and drill approximately 19 new wells on existing prospects; and

• $17.6 million to conduct seismic and leasing activities necessary to generate new exploratory prospects in Louisiana.

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.

Mississippi

In 2002 we began an exploration program in the southern portion of the Black Warrior Basin in Mississippi targeting the Stones River formation. Based on our evaluation of approximately 1,800 miles

of 2-D seismic data, we engaged in a significant lease play in which we acquired more than 100,000 net acres. In 2004, we spent $20 million in this area, of which $4.5 million was spent on leasing and seismic activities and $15.5 million was spent on exploratory drilling. To date, we have drilled three wells in this area, all of which were unsuccessful. The Weyerhaeuser #1 and the Mississippi State University #1 were both drilled to the Stones River formation and also tested several Pennsylvanian–aged sands at a shallower depth. The Inez West #1 well, which began drilling in January 2005, was drilled exclusively to test the Pennsylvanian sands. We recorded abandonment and impairment charges totaling $29.5 million in 2004 and expect to expense approximately $2.6 million in additional abandonment costs in the first quarter of 2005. We continue to carry approximately $1.1 million of unimpaired acreage costs attributable to one prospect in the Black Warrior Basin that we believe is prospective for production from the Pennsylvanian sands.

In 2005, we currently plan to spend $2.5 million in this area to conduct seismic activities on the remaining prospect and to participate in a non-operated well outside of the Black Warrior Basin.

Permian Basin

The acquisition of SWR in 2004 has provided us with several developmental drilling opportunities to significantly enhance our existing activities in the Permian Basin. In 2004, we spent $18.4 million in the Permian Basin, including $9.5 million on SWR drilling activities and $8.9 million on leasing and drilling activities in other areas of the Permian Basin. We currently plan to spend $48.3 million in the Permian Basin in 2005 to acquire acreage and to drill wells. Most of the wells we plan to drill in this area will be developmental wells, which generally involve a lower success risk than exploratory wells. We believe that the longer life reserves typically associated with Permian Basin production, plus the lower risk profile, will complement our more aggressive exploration program.

Cotton Valley/Knowles

Most of the prospects drilled in our Cotton Valley/Knowles 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, and the Knowles formation is encountered at depths of 14,000 to 15,000 feet.

We did not drill any Cotton Valley Reef wells in 2004. Prior to 2004, we had 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 also participated in the drilling of 3 gross (.4 net) wells as a non-operator in this area prior to 2004, all of which were dry holes.

In 2004, we spent $6.2 million in this area for leasing activities and to drill the Catherine Destefano #1, a 14,600-foot exploratory well in Robertson County, Texas targeting the Knowles formation. This structure was identified by 3-D seismic technology in connection with our exploration program in the Cotton Valley Reef Complex area. We began drilling this well in August 2004. We are currently attempting to complete this well and cannot presently determine if this well will be commercially productive. If this well is ultimately determined to be nonproductive, we will charge to expense all cumulative drilling and completion costs during the period such determination is made. We expect to spend approximately $2.4 million to complete our activities on this well in 2005.

Other Exploration and Development Activities

During 2004, we spent $5.2 million on exploration and development activities in other areas, including:

• $2 million primarily in California in connection with a non-operated drilling program that resulted in two dry holes; and

• $1.8 million for leasing in Montana.

In 2005, we currently plan to spend $16.7 million in other areas, including:

• $5.7 million for leasing and seismic activities in Utah and Montana;

• $5.6 million for leasing and drilling activities in east central Texas; and

• $4.5 million for drilling activities in south Texas.

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, four treating plants (two of which were constructed to treat gas production from wells in our Cotton Valley Reef Complex area), one dehydration facility and five compressor stations. Most of our operated gas gathering and processing activities exist to facilitate the transportation and marketing of our operated oil and gas production.

Competition and Markets

Competition in all areas of our operations is intense. 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. Competitors 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. Our ability to increase reserves in the future will depend on our success at selecting and acquiring suitable producing properties and prospects for future development and exploration activities.

In addition, 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. The price and availability of alternative energy sources could adversely affect our revenue.

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 2005. 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 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.

The Resource Conservation and Recovery Act (“RCRA”), and analogous state laws govern the handling and disposal of hazardous and solid wastes. Wastes that are classified as hazardous under RCRA are subject to stringent handling, recordkeeping, disposal and reporting requirements. RCRA specifically excludes from the definition of hazardous waste “drilling fluids, produced waters, and other wastes associated with the exploration, development, or production of crude oil, natural gas or geothermal energy.” However, these wastes may be regulated by the EPA or state agencies as solid waste. Moreover, many ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes and waste compressor oils, are regulated as hazardous wastes. Although the costs of managing hazardous waste may be significant, we do not expect to experience more burdensome costs than similarly situated companies

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. In addition, the presence of unanticipated pressures or irregularities in formations, miscalculations, or accidents may cause our drilling activities to be unsuccessful and result in a total loss of our investment.

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.

Executive Officers

The following is a list, as of March 11, 2005 of the name, age and position with the Company of each person who is an executive officer of the Company:

CLAYTON W. WILLIAMS, age 72, is Chairman of the Board, President, Chief Executive Officer and a director of the Company, having served in such capacities since September 1991. For more than the past five years, Mr. Williams has also been the chief executive officer and director of certain entities which are controlled directly or indirectly by Mr. Williams.

L. PAUL LATHAM, age 52, is Executive Vice President, Chief Operating Officer and a director of the Company, having served in such capacities since September 1991. Mr. Latham also serves as an officer and director of certain entities controlled by Mr. Williams.

MEL G. RIGGS, age 49, is Senior Vice President and Chief Financial Officer of the Company, having served in such capacities since September 1991. Mr. Riggs has served as a director of the Company since May 1994.

JERRY F. GRONER, age 42, is Vice President – Land and Lease Administration of the Company, having served in such capacity since 1993.

PATRICK C. REESBY, age 52, is Vice President – New Ventures of the Company, having served in such capacity since 1993.

ROBERT C. LYON, age 68, is Vice President – Gas Gathering and Marketing of the Company, having served in such capacity since 1993.

MICHAEL L. POLLARD, age 54, is Vice President – Accounting of the Company, having served in such capacity since 2003. Prior to that, Mr. Pollard had served as Controller of the Company since 1993.

T. MARK TISDALE, age 48, is Vice President and General Counsel of the Company, having served in such capacity since 1993.

Employees

At December 31, 2004, we had 173 full-time employees, none of whom is subject to a collective bargaining agreement. In our opinion, our relations with employees 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, 2004, we had interests in 6,582 gross (886.9 net) oil and gas wells and owned leasehold interests in approximately 737,000 gross (388,000 net) undeveloped acres.

Reserves

The following table sets forth certain information as of December 31, 2004 with respect to our estimated proved oil and gas reserves pursuant to SEC guidelines, present value of proved reserves and standardized measure of discounted future net cash flows.

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

Gas (MMcf)	80,813		14,410		43,055		138,278
Oil and natural gas liquids (MBbls)	18,078		1,721		6,994		26,793
Total (MMcfe)	189,281		24,736		85,019		299,036
Present value of proved reserves	$	469,993	$	72,247	$	163,074	$	705,314
Standardized measure of discounted future net cash flows							$	500,198

The following table sets forth certain information as of December 31, 2004 regarding our proved oil and gas reserves in each of our principal producing areas.

				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)	7,586	6,225	51,741	17.3	%	$	124,429	17.6	%
Cotton Valley Reef Complex	—	19,116	19,116	6.4	%	63,954		9.1	%
Louisiana	1,942	26,844	38,496	12.9	%	167,288		23.7	%
New Mexico / West Texas	2,116	7,024	19,720	6.6	%	46,528		6.6	%
SWR (b)	14,997	78,219	168,201	56.2	%	298,481		42.3	%
Other	152	850	1,762	0.6	%	4,634		0.7	%
Total	26,793	138,278	299,036	100.0	%	$	705,314	100.0	%

(a) Includes natural gas liquids.

(b) Primarily West Texas and New Mexico.

The estimates of proved reserves at December 31, 2004 and the present value of proved reserves were derived from reports prepared by Williamson Petroleum Consultants, Inc., independent petroleum engineers and Ryder Scott Company, L.P., petroleum consultants. The following tables summarize the estimates derived from each report.

	Proved Developed				Proved Undeveloped		Total Proved
	Producing		Nonproducing		Proved Undeveloped		Total Proved
	(Dollars in thousands)
Williamson Petroleum Consultants, Inc.:
Gas (MMcf)	40,768		8,018		11,273		60,059
Oil and natural gas liquids (MBbls)	8,063		773		2,960		11,796
Present value of proved reserves	$	291,089	$	46,519	$	69,225	$	406,833

Ryder Scott Company, L.P.:
Gas (MMcf)	40,045		6,392		31,782		78,219
Oil and natural gas liquids (MBbls)	10,015		948		4,034		14,997
Present value of proved reserves	$	178,904	$	25,728	$	93,849	$	298,481

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 average prices utilized for the purposes of estimating our proved reserves and the present value of proved reserves as of December 31, 2004 were $41.48 per Bbl of oil and natural gas liquids and $5.59 per Mcf of gas, as compared to $30.45 per Bbl of oil and $5.61 per Mcf of gas as of December 31, 2003. 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 $15 million and $38 million, respectively.

The reserve information shown is estimated. The accuracy of any reserve estimate is a function of the quality of available geological, geophysical, engineering and economic data, the precision of the engineering and geological interpretation and judgment. 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. Although we believe these estimates are reasonable, 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, 2004, 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,
	2004		2003		2002
	Gross	Net	Gross	Net	Gross	Net
	(Excludes wells in progress at the end of any period)
Development Wells:
Oil	39	11.7	6	5.0	3	.8
Gas	2	1.3	2	2.0	—	—
Dry	2	.9	—	—	1	.9
Total	43	13.9	8	7.0	4	1.7

Exploratory Wells:
Oil	1	.3	—	—	—	—
Gas	7	4.9	9	4.9	—	—
Dry	13	7.1	18	12.3	9	4.9
Total	21	12.3	27	17.2	9	4.9

Total Wells:
Oil	40	12.0	6	5.0	3	.8
Gas	9	6.2	11	6.9	—	—
Dry	15	8.0	18	12.3	10	5.8
Total	64	26.2	35	24.2	13	6.6

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, 2004, of productive wells in the areas indicated.

	Oil		Gas		Total
	Gross	Net	Gross	Net	Gross	Net
Austin Chalk (Trend)	298	227.8	26	16.4	324	244.2
New Mexico / West Texas	79	51.5	12	1.3	91	52.8
Louisiana	5	2.7	23	15.1	28	17.8
Cotton Valley	—	—	12	11.1	12	11.1
Southwest Royalties	5,395	456.2	686	86.0	6,081	542.2
Other	12	7.8	34	11.0	46	18.8
Total	5,789	746.0	793	140.9	6,582	886.9

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,
	2004		2003		2002
Oil and Gas Production Data:
Gas (MMcf)	17,938		24,697		15,972
Oil (MBbls)	2,094		1,505		1,585
Natural gas liquids (MBbls)	249		234		227
Total (MMcfe)	31,996		35,131		26,844

Average Realized Prices (1):
Gas ($Mcf)	$	5.60	$	4.69	$	3.01
Oil ($Bbl)	$	40.65	$	27.74	$	22.00
Natural gas liquids ($/Bbl)	$	27.90	$	21.09	$	14.16

Average Production Costs
Production ($/Mcfe)(2)	$	1.29	$	.80	$	.81

(1) Includes the effects of hedging transactions designated as cash flow hedges under applicable accounting standards.

(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,
	2004		2003		2002
	(In thousands)
Property Acquisitions:
Proved	$	237,042	$	—	$	18,249
Unproved	33,826		7,982		20,311
Developmental Costs	27,075		11,689		4,964
Exploratory Costs	73,655		49,277		27,011
Asset Retirement Costs (1)	394		776		3,500
Total	$	371,992	$	69,724	$	74,035

(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, 2004 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	109,276	107,601	55,517	29,255	164,793	136,856
Louisiana	11,193	11,040	30,603	27,302	41,796	38,342
Mississippi	90	65	241,493	136,771	241,583	136,836
New Mexico/ West Texas	2,558	1,813	54,213	11,570	56,771	13,383
SWR	72,663	39,923	176,020	77,325	248,683	117,248
Other (1)	11,611	4,969	178,659	106,082	190,270	111,051
Total	207,391	165,411	736,505	388,305	943,896	553,716

(1) Net undeveloped acres are attributable to the following areas: Arizona – 45,265; Colorado – 27,713; Alabama – 13,486; Utah – 10,032; Nevada – 889; and other – 8,697.

Offices

We lease from a related partnership approximately 52,000 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 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, 2004.

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 February 17, 2005, there were approximately 1,700 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, 2004:
Fourth Quarter	$	24.69	$	18.65
Third Quarter	26.95		17.53
Second Quarter	35.85		22.26
First Quarter	38.90		28.20

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

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 facilities prohibit the payment of cash dividends.

Stock Repurchase Program

Our stock repurchase program expired in July 2004. In 2001 and 2002, we spent $1.4 million to repurchase for cancellation 115,100 shares of our common stock. We did not repurchase any shares under this program in 2003 or 2004.

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, 2004.

	Number of securities to be issued upon exercise of outstanding options	Weighted average exercise price of outstanding options		Number of securities remaining Available for future issuance
Equity compensation plans approved by security holders (1)	1,139,136	$	17.72	352,066
Equity compensation plans not approved by security holders	—	—		—
Total	1,139,136	$	17.72	352,066

(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, 2004 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,
	2004			2003			2002			2001			2000
	(In thousands, except per share)
Statement of Operations Data:
Revenues:
Oil and gas sales	$	193,127		$	163,032		$	86,302		$	105,118		$	102,235
Natural gas services	9,083			8,758			5,568			8,820			6,682
Gain on sales of property and equipment	4,120			267			2,241			10,986			1,031
Total revenues	206,330			172,057			94,111			124,924			109,948
Costs and expenses:
Production	41,163			28,239			21,857			20,427			18,162
Exploration:
Abandonment and impairments	67,956			35,120			21,571			29,412			12,657
Seismic and other	7,124			8,755			8,578			12,868			7,953
Natural gas services	8,538			8,279			4,853			7,467			5,591
Depreciation, depletion and amortization	44,040			40,284			29,656			37,459			27,635
Impairment of property and equipment	—			170			349			18,170			—
Accretion of abandonment obligations	1,044			651			—			—			—
General and administrative	11,689			10,934			8,615			7,456			5,951
Loss on sales of property and equipment	14,337			68			1,880			—			—
Total costs and expenses	195,891			132,500			97,359			133,259			77,949
Operating income (loss)	10,439			39,557			(3,248		)	(8,335		)	31,999
Other income (expense):
Interest expense	(7,877		)	(3,138		)	(4,006		)	(2,925		)	(2,310		)
Change in fair value of derivatives	(25,329		)	(1,593		)	(1,581		)	2,227			—
Other income	1,354			(1,662		)	1,755			66			269
Total other income (expense)	(31,852		)	(6,393		)	(3,832		)	(632		)	(2,041		)
Income (loss) before income taxes	(21,413		)	33,164			(7,080		)	(8,967		)	29,958
Income tax expense (benefit)	(7,385		)	10,515			(1,742		)	(3,421		)	2,517
Income (loss) from continuing operations	(14,028		)	22,649			(5,338		)	(5,546		)	27,441
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
NET INCOME (LOSS)	$	(14,028	)	$	22,856		$	(4,003	)	$	(5,304	)	$	27,813
Net income (loss) per common share:
Basic:
Income (loss) from continuing operations	$	(1.37	)	$	2.43		$	(.58	)	$	(.60	)	$	2.98
Net income (loss)	$	(1.37	)	$	2.45		$	(.43	)	$	(.58	)	$	3.02
Diluted:
Income (loss) from continuing operations	$	(1.37	)	$	2.38		$	(.58	)	$	(.60	)	$	2.88
Net income (loss)	$	(1.37	)	$	2.40		$	(.43	)	$	(.58	)	$	2.91
Weighted average common shares outstanding:
Basic	10,213			9,329			9,241			9,219			9,211
Diluted	10,213			9,509			9,241			9,219			9,543
Other Data:
Net cash provided by operating activities	$	126,980		$	119,750		$	34,514		$	67,059		$	72,471

	December 31,
	2004			2003			2002			2001			2000
	(In thousands)
Balance Sheet Data:
Working capital (deficit)	$	(27,566	)	$	(13,119	)	$	(18,843	)	$	(17,779	)	$	(18,656	)
Total assets	462,235			224,433			218,992			183,279			164,864
Long-term debt	177,519			53,295			94,949			62,000			30,000
Stockholders’ equity	117,596			100,781			68,781			82,280			85,777

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 model 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.

We believe that the economic climate in the domestic oil and gas industry continues to be suitable for our business model. Oil and gas prices have remained strong. Supply and demand fundamentals continue to suggest that energy prices will remain high for the near term, providing us with the economic incentives necessary for us to assume the risks we face in our search for oil and gas reserves.

Finding quality domestic oil and gas reserves through exploration is a significant challenge and involves a high degree of risk. Although our 2004 exploration results improved significantly from 2003, our drilling success over the past three years has been limited, and we have not found sufficient reserves to replace our production through exploration activities. In order to grow our reserve base through our exploration program, we need to continue to improve our drilling success. We will also continue to look for opportunities to complement our exploration program through the purchase of proved reserves as we did in 2004 with the acquisition of SWR.

Key Factors to Consider

The following summarizes the key factors considered by management in the review of our financial condition and operating performance for 2004 and the outlook for 2005.

• In May 2004, we completed the acquisition of SWR.

• Exploration costs related to abandonments and impairments totaled $68 million for 2004, most of which was in Louisiana and the Black Warrior Basin of Mississippi.

• We recorded a loss of $25.3 million for 2004 related to the change in fair value of derivatives. Cash settlements to counterparties accounted for $18.2 million of this loss, and changes in mark-to-market valuations accounted for $7.1 million. Since we do not presently designate our derivatives as cash flow hedges under applicable accounting standards, we recognize the full effect of changing prices on mark-to-market valuations as a current charge or credit to results of operations.

• Our proved oil and gas reserves at December 31, 2004 increased 139% to 299 Bcfe. The SWR acquisition added 170.8 Bcfe, extensions and discoveries added 46.8 Bcfe, and net revisions added another 16.6 Bcfe.

• We currently plan to spend $124.1 million in 2005 on exploration and development activities, of which approximately 66% relates to exploratory prospects. Although recent discoveries in Louisiana accounted for 25.9 Bcfe of proved reserve additions in 2004, this area also accounted for $32.8 million of the $68 million in abandonment and impairment charges for 2004. Approximately 42% of our planned expenditures in 2005 are projected to be spent on Louisiana prospects.

• Our oil and gas production for 2004 totaled 32 Bcfe, 9% lower than 2003 production. Excluding any production we may derive from our exploratory drilling activities, we currently estimate that 2005 production will be relatively flat compared to 2004 production levels.

Acquisition of Southwest Royalties, Inc.

On May 21, 2004, we acquired all the outstanding common stock of SWR through a merger. Prior to the acquisition, SWR was a privately-held, Midland-based energy company engaged in oil and gas exploration, production, development and acquisition activities in the United States. Most of SWR’s properties are located in the Permian Basin. Using reserve guidelines established by the SEC, the SWR acquisition added approximately 170.8 Bcfe to our proved oil and gas reserves on the effective date of the acquisition.

Recent Exploration and Developmental Activities

Louisiana

Approximately half of the 8.4 net wells commenced in Louisiana in 2004 were completed as producers. In addition, approximately 55% of the extensions and discoveries of proved oil and gas reserves during 2004 were derived from south Louisiana prospects. Despite these favorable results, our abandonment and impairment costs from south Louisiana prospects totaled $32.8 million due primarily to high costs on three wells. The State Lease 17378 #1 (Fleur) well was ultimately completed as a producer in a shallower zone after attempts to complete the well in a deeper zone were unsuccessful. As a result, we recorded an abandonment charge of approximately $10.7 million for costs incurred in the abandoned portion of the well. The Mervine Jankower #1 (Bosco) and the McIlhenny #1 (Tabasco) were high-cost exploratory wells that were determined to be dry, resulting in combined abandonment charges of $10.4 million.

To date, we have drilled, or participated in drilling, 47 gross (37.7 net) wells in south Louisiana, of which 20 gross (14.7 net) wells were productive. Although our success rate from inception of this program is lower than we had expected, our 2004 success rate of approximately 50% is encouraging. We have tried several strategies for improving our exploration results in south Louisiana, where the geology is very complex, but the results have been mixed and often inconclusive. Similar to our approach in 2004, our current strategy is a moderate approach through which we attempt to balance our exploration efforts between prospects with large, deep structures and those with shallower structures. We carefully consider the geological characteristics of each prospect in making our final determination of its risk

profile. In some cases, we may elect to reduce our risks associated with drilling the deeper, more expensive prospects by selling a portion of these prospects to industry partners.

We currently plan to spend $51.9 million in Louisiana in 2005 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 in this area 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 formation. Based on our evaluation of approximately 1,800 miles of 2-D seismic data, we engaged in a significant lease play in which we acquired more than 100,000 net acres. To date, we have drilled three wells in this area, all of which were unsuccessful. The Weyerhaeuser #1 and the Mississippi State University #1 were both drilled to the Stones River formation and also tested several Pennsylvanian–aged sands at a shallower depth. The Inez West #1 well, which began drilling in January 2005, was drilled exclusively to test the Pennsylvanian sands. We recorded abandonment and impairment charges totaling $29.5 million in 2004 and will expense approximately $2.6 million in additional abandonment costs in the first quarter of 2005. We continue to carry approximately $1.1 million of unimpaired acreage costs attributable to one prospect in the Black Warrior Basin that we believe is prospective for production from the Pennsylvanian sands.

Permian Basin

The acquisition of SWR in 2004 has provided us with several developmental drilling opportunities in the Permian Basin of west Texas and southeast New Mexico. We currently plan to spend $48.3 million in the Permian Basin in 2005 to acquire acreage and drill wells. Most of the wells we plan to drill in this area will be developmental wells, which generally involve a lower success risk than exploratory wells. We believe that the longer life reserves typically associated with Permian Basin production, plus the lower risk profile, will complement our more aggressive exploration program.

Other

We are currently attempting to complete the Catherine Destefano #1, a 14,600-foot exploratory well in Robertson County, Texas targeting the Knowles formation. This structure was identified by 3-D seismic in connection with our exploration program in the Cotton Valley Reef Complex area. We began drilling this well in August 2004, and to date, we have incurred drilling and completion costs totaling $7.1 million, of which $5.3 million was incurred in 2004. We cannot presently determine if this well will be commercially productive. If this well is ultimately determined to be nonproductive, we will charge to expense all cumulative drilling and completion costs during the period such determination is made.

In addition, we currently plan to spend $19.2 million in 2005 to explore for oil and gas in other areas, including south and east Texas, Utah, Montana, and Colorado.

Proved Oil and Gas Reserves

Our proved oil and gas reserves increased 139% to 299 Bcfe at December 31, 2004 from 124.9 Bcfe at December 31, 2003. The pre-tax present value of estimated future net revenues from these reserves, discounted at 10% and computed in accordance with SEC guidelines, totaled $705.3 million at December 31, 2004, as compared to $335.1 million at December 31, 2003. The estimates were based on weighted average oil and NGL prices of $41.48 per Bbl in 2004, as compared to $30.45 in 2003, and gas prices of $5.59 per Mcf in 2004, as compared to $5.61 per Mcf in 2003.

The following table summarizes changes in our proved reserves during 2004 on a Bcfe basis.

	Bcfe
Total proved reserves, December 31, 2003	124.9
Purchases of reserves in place	170.8
Extensions and discoveries	46.8
Revisions of previous estimates	16.6
Sales of reserves in place	(28.1	)
Production	(32.0	)
Total proved reserves, December 31, 2004	299.0

During 2004, we replaced 732% of the 32 Bcfe that we produced in 2004, computed by dividing the sum of all reserve additions (purchases of reserves in place, extensions and discoveries, and revisions in previous estimates) by production. We use this reserve replacement ratio as a benchmark for determining the sources through which we have expanded or contracted our base of proved reserves. Following is a discussion of the important factors related to each source of reserve additions during 2004.

Purchases of reserves in place. All of the purchased reserves in 2004 were derived from the acquisition of SWR. Of the 170.8 Bcfe acquired, 117.8 Bcfe were classified as proved developed reserves. The remaining 53 Bcfe of proved undeveloped reserves will require the expenditure of approximately $50.3 million over the next 4 years before the reserves can ultimately be converted to cash flow. Although we are continually looking for acquisitions, we cannot predict the likelihood of adding any reserves in 2005 through purchases of reserves in place.

Extensions and discoveries. Our extensions and discoveries during 2004 consist primarily of 32.7 Bcfe of proved reserves attributable directly to the drilling of discovery wells during the year and 14.1 Bcfe of proved undeveloped reserves added during the year, primarily in the Austin Chalk (Trend) and Permian Basin, that are associated with drilling locations which we believe are now feasible to drill under current economic conditions. Proved undeveloped reserves added through this source will require the expenditure of approximately $42.6 million over the next 4 years before the reserves can ultimately be converted to cash flow. Due to the nature of exploratory drilling, we cannot predict the extent to which we will add any reserves in 2005 through extensions and discoveries.

Revisions of previous estimates. Of the 16.6 Bcfe of proved reserves added through revisions of previous estimates, approximately 65% was attributable to improved well performance, primarily from properties acquired in the SWR merger. The remainder was attributable to the effects of higher product prices on the estimated quantities of proved reserves. Most of this increase was applicable to properties that are currently contributing to our cash flow. This source is subject to volatility due to well performance and product prices and can generate both upward revisions and downward revisions.

As we discuss under “Known Trends and Uncertainties” elsewhere in this Item 7, reserve estimates are inherently imprecise. Proved undeveloped reserves are generally the least accurate due to limitations on available information. This increases the risk that the reserve additions in 2004 that are classified as proved undeveloped reserves could be subject to downward revisions in the future as economic conditions change and as more information is obtained through drilling.

The sales of reserves in place were attributable to the Jo-Mill Unit in Borden County, Texas and the Romere Pass Unit in Plaquemines Parish, Louisiana.

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,
	2004		2003			2002
Oil and Gas Production Data:
Gas (MMcf)	17,938		24,697			15,972
Oil (MBbls)	2,094		1,505			1,585
Natural gas liquids (MBbls)	249		234			227
Total (MMcfe)	31,996		35,131			26,844

Average Realized Prices (1):
Gas ($/Mcf):
Before hedging gains (losses)	$	5.60	$	5.35		$	3.20
Hedging gains (losses)	—		(.66		)	(.19		)
Net realized price	$	5.60	$	4.69		$	3.01
Oil ($/Bbl):
Before hedging gains (losses)	$	40.65	$	29.94		$	24.62
Hedging gains (losses)	—		(2.20		)	(2.62		)
Net realized price	$	40.65	$	27.74		$	22.00
Natural gas liquids ($/Bbl):	$	27.90	$	21.09		$	14.16

Average Daily Production:
Gas (Mcf):
Austin Chalk (Trend)	3,155		3,667			3,398
Cotton Valley Reef Complex	23,131		42,493			26,724
Louisiana	12,089		17,570			8,274
New Mexico/West Texas	1,728		1,668			1,769
Other	1,312		2,265			3,594
SWR (2)	7,730		—			—
Total	49,145		67,663			43,759
Oil (Bbls):
Austin Chalk (Trend)	2,215		2,715			3,318
Louisiana	1,055		608			242
New Mexico/West Texas	813		723			724
Other	57		77			58
SWR (2)	1,597		—			—
Total	5,737		4,123			4,342
Natural Gas Liquids (Bbls):
Austin Chalk (Trend)	284		299			459
New Mexico/West Texas	213		171			133
Louisiana/Other	185		171			30
Total	682		641			622

Total Proved Reserves:
Gas (MMcf)	138,278		62,916			86,912
Oil and natural gas liquids (MBbls)	26,793		10,335			11,884
Total gas equivalent (MMcfe)	299,036		124,926			158,216
Present value of proved reserves (in thousands)	$	705,314	$	335,097		$	382,518

(Continued)

	As of or for the Year Ended December 31,
	2004		2003		2002
Total Proved Reserves by Area:
Gas (MMcf):
Austin Chalk (Trend)	6,225		5,593		5,135
Cotton Valley Reef Complex	19,116		25,616		45,613
Louisiana	26,844		24,465		29,874
New Mexico/West Texas	7,024		4,325		4,204
SWR	78,219		—		—
Other	850		2,917		2,086
Total	138,278		62,916		86,912
Oil and Natural Gas Liquids (MBbls):
Austin Chalk (Trend)	7,586		6,688		7,297
Louisiana	1,942		1,485		2,674
New Mexico/West Texas	2,116		1,980		1,762
SWR	14,997		—		—
Other	152		182		151
Total	26,793		10,335		11,884
Total Gas Equivalent (MMcfe):
Austin Chalk (Trend)	51,741		45,721		48,917
Cotton Valley Reef Complex	19,116		25,616		45,613
Louisiana	38,496		33,375		45,918
New Mexico/West Texas	19,720		16,205		14,776
SWR	168,201		—		—
Other	1,762		4,009		2,992
Total	299,036		124,926		158,216

Exploration Costs (in thousands):
Abandonment and impairment costs:
South Louisiana	$	32,760	$	17,904	$	7,009
Cotton Valley Reef Complex	205		8,694		7,182
Nevada, Arizona, California and Utah	2,513		4,172		1,211
Mississippi (3)	29,547		3,773		631
West Texas	1,772		361		4,096
SWR	606		—		—
Other	553		216		1,442
Total	67,956		35,120		21,571

Seismic and other	7,124		8,755		8,578
Total exploration costs	$	75,080	$	43,875	$	30,149

Oil and Gas Costs ($/Mcfe Produced):
Production	$	1.29	$	.80	$	.81
Oil and gas depletion	$	1.28	$	1.10	$	1.05

Net Wells Drilled (4):
Exploratory Wells	12.3		17.2		4.9
Developmental Wells	13.9		7.0		1.7

(1) Includes the effects of hedging transactions designated as cash flow hedges under applicable accounting standards.

(2) Average daily production for SWR on an annualized basis for 2004 was 12,593 Mcf of gas and 2,599 barrels of oil based on 224 days of production.

(3) Includes a $13.7 million impairment of unproved acreage in the Black Warrior Basin in 2004 and $2.1 million in 2003.

(4) 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, 2004 to the two previous years. All references to 2004, 2003 and 2002 within this section refer to the respective annual periods.

Oil and gas operating results

Our oil and gas sales reached a record high again in 2004, exceeding the previous record in 2003. Oil prices continued to climb to record levels, and gas prices remained favorable. Comparing 2004 to 2003, oil and gas sales increased $30.1 million, of which price variances accounted for a $45.2 million increase and production variances accounted for a $15.1 million decrease. Comparing 2003 to 2002, oil and gas sales increased $76.7 million, of which price variances accounted for a $51.9 million increase and production variances accounted for a $24.8 million increase.

Production in 2004 (on an Mcfe basis) was 9% lower than 2003 and 19% higher than 2002. We increased our oil production in 2004 due primarily to the acquisition of SWR in May 2004 and production from two new wells in Louisiana. Our gas production was 27% lower in 2004 than 2003 due primarily to normal production declines in the Cotton Valley Reef Complex area and in Louisiana, offset in part by additional gas production from the SWR acquisition.

In 2004, our realized gas price was 19% higher than 2003 and 86% higher than 2002, while our realized oil price was 47% higher than 2003 and 85% higher than 2002. 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.

Looking forward, excluding any new production from our exploration program or from acquisitions of proved reserves, oil and gas production for 2005 should remain relatively constant with 2004 levels. We plan to spend $124.1 million in 2005 to explore for new oil and gas production. Through these exploration efforts, we believe we can add sufficient volumes of new production to replace our production. If we do not replace our production, oil and gas sales after 2005 may decline.

We cannot predict with accuracy future prices for oil and gas although currently we believe the fundamentals are in place for a continued strong oil and gas commodities 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 as oil and gas prices fluctuate, 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 (loss) 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 increased from $.80 per Mcfe in 2003 to $1.29 per Mcfe in 2004. The 2003 rates remained relatively constant with the 2002 rates. The increase in operating costs in 2004 was primarily due to the added expense related to higher cost oil properties acquired in connection with the SWR merger, as well as increased production tax costs related to higher product prices. It is likely that these factors will continue to contribute to higher production costs in future periods.

Depletion on an Mcfe basis increased 16% from 2003 and 22% from 2002. Comparing 2004 to 2003, depletion expense increased $2.5 million, of which rate variances accounted for a $6 million increase and production variances accounted for a $3.5 million decrease. Comparing 2003 to 2002, depletion expense

increased $10.3 million, of which rate variances accounted for a $1.5 million increase and production variances accounted for a $8.8 million increase. Depletion rates for each depletable group are a function of net capitalized costs and estimated reserve quantities. The rates for 2005 are expected to be similar to the 2004 rates.

General and administrative (“G&A”) expenses, excluding non-cash stock-based employee compensation, were 18% higher than 2003 and 38% higher than 2002 due primarily to higher personnel costs, professional fees and insurance costs. Professional fees include approximately $440,000 related to compliance with Section 404 of the Sarbanes-Oxley Act of 2002 regarding internal control over financial reporting. G&A expenses for 2004 include a non-cash credit (reduction of expense) of $245,000 for stock-based employee compensation required by Financial Accounting Standards Board Interpretation No. 44. A non-cash charge of $797,000 was required for the 2003 period and a credit of $32,000 was needed for 2002. Because the amount of this non-cash provision or credit is based on the quoted market value of our common stock, the future results of our operations may be subject to significant volatility based on changes in the market price of our common stock.

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 2004, we charged to expense $75.1 million of exploration costs, as compared to $43.9 million in 2003 and $30.1 million in 2002. Most of these costs were incurred in south Louisiana and Mississippi.

We plan to spend approximately $124.1 million on exploration and development activities in 2005 primarily in the same core exploration areas as in 2004. 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 2005. However, we cannot predict our success rates and, accordingly, cannot predict our exploration costs related to abandonment and impairment costs.

Gains and losses on property sales

Gain on sales of property and equipment for 2004 was $4.1 million, as compared to $267,000 in 2003 and $2.2 million in 2002. The 2004 gain included the sale of the Jo-Mill Unit in Borden County, Texas. Loss on sale of property and equipment for 2004 was $14.3 million, as compared to $68,000 in 2003 and $1.9 million in 2002. The 2004 loss included the sale of the Romere Pass Unit in Plaquemines Parish, Louisiana.

Interest expense

Interest expense was $7.9 million in 2004 as compared to $3.1 million in 2003 and $4 million in 2002. In May 2004, our indebtedness increased as a result of our assuming and refinancing approximately $113.9 million of bank debt in the SWR acquisition. The average daily principal balance outstanding under the credit facilities in 2004 was $148.8 million, as compared to $71.1 million in 2003 and $84.8 million in 2002. The effective annual interest rate on bank debt, including bank fees and designated interest rate derivatives, in 2004 was 5.3%, as compared to 5.4% in 2003 and 5.4% in 2002. We anticipate our 2005 interest expense to be approximately 50% higher than 2004 because of the increased indebtedness.

Change in fair value of derivatives

We recorded a loss of $25.3 million for the change in fair value of derivatives compared to a loss of $1.6 million for each of the previous two periods. The increase is partly attributable to certain derivative contracts being designated as cash flow hedges prior to 2004, and as a result, changes in the fair value of such instruments were not recorded in this account. Beginning in 2004, because we have not designated any

derivative contracts as cash flow hedges, all cash settlements and changes resulting from mark-to-market valuations are recorded as changes in fair value of derivatives. Future gains or losses on changes in derivatives will be impacted by the volatility of commodity and interest rates, as well as the terms of any new derivative contracts.

Other

At December 31, 2004, our cumulative tax loss carryforwards were approximately $22.6 million. 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), we believe that it is more likely than not that we will be able to utilize these tax loss carryforwards before they expire (beginning in 2008). Accordingly, no valuation allowance exists at December 31, 2004. A valuation allowance at December 31, 2002 was reversed during 2003.

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 revolving 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 revolving credit facility as needed to supplement our operating cash flow as a financing source for our capital expenditure program. Our ability to fund 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 we are unable to replace our oil and gas reserves through our exploration program, we may also suffer a reduction in our operating cash flow and access to funds under the revolving 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 the principal factors that can affect our liquidity and capital resources.

Capital Expenditures

Our planned expenditures for exploration and development activities during 2005 total $124.1 million, as summarized by area in the following table.

	Total Planned Expenditures Year Ended December 31, 2005		Percentage of Total
Louisiana	$	51,900	42	%
Permian Basin	48,300		39	%
South and East Texas	8,300		7	%
Utah/Montana	5,700		4	%
Mississippi	4,700		4	%
Other	5,200		4	%
	$	124,100	100	%

Our actual expenditures during 2005 may be substantially higher or lower than these estimates since our plans for exploration and development activities may change during the year. Other factors, such as prevailing product prices and the availability of capital resources, could also increase or decrease the ultimate level of expenditures during 2005.

Approximately 66% 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. We do not attempt to forecast our success rate on exploratory drilling. Accordingly, these current estimates do not include costs we may incur to complete any future 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.

We project that substantially all of the cash needed to finance our planned expenditures for exploration and development activities in 2005 will be provided by operating activities. To the extent that actual costs exceed our cash provided by operating activities, we plan to utilize some or all of our existing availability under the revolving credit facility to finance such excess.

Cash Flow Provided by Operating Activities

Substantially all of our cash flow from operating activities is derived from the production of our oil and gas reserves. We use this cash flow to fund our on-going exploration and development activities in search of new oil and gas reserves. Variations in cash flow from operating activities may impact our level of exploration and development expenditures.

Cash flow provided by operating activities for 2004 was 6% higher than 2003 due to the combined effects of several drivers. The positive benefits of an 18% increase in oil and gas sales, driven primarily by higher oil and gas prices, were offset in part by increases in production costs, costs of settling commodity hedges and interest expense. Our primary source of cash from operating activities is our oil and gas sales, net of production costs. Our cash flow provided by operating activities is subject to material variation from changes in oil and gas production levels and product prices. Higher oil and gas prices also resulted in an increase in cash required to settle derivative contracts, excluding those contracts that contain a financing element as in the case of the contracts assumed in SWR acquisition. Interest expense increased in 2004 due primarily to higher levels of indebtedness resulting from the SWR acquisition.

Credit Facilities

A group of banks have provided us with a revolving credit facility on which we rely heavily for both our short-term liquidity (working capital) and our long-term financing needs. The funds available to us at any time under this revolving credit facility are limited to the amount of the borrowing base established by the banks. As long as we have sufficient availability under this credit facility to meet our obligations as they come due, we will have sufficient liquidity and will be able to fund any short-term working capital deficit.

In connection with the acquisition of SWR, we entered into new credit facilities with the banks that provided for an $85 million increase in borrowing capacity under the revolving credit facility and established a new $75 million senior term credit facility. Immediately prior to the SWR acquisition, we had $40.7 million of availability under the revolving credit facility, taking into account $4.3 million of outstanding letters of credit. Of the $168.2 million of funds needed to finance the purchase of SWR (net of cash acquired of $12.3 million), $30 million was provided through a private placement of common stock, $50 million (net of repayments) was borrowed under the senior term credit facility, and $100 million was obtained from the revolving credit facility. Giving effect to the $85 million increase in the borrowing base,

this purchase transaction initially used $3.2 million of availability on the revolving credit facility. All other changes in our availability under the revolving credit facilities combined to provide a $9.2 million increase. As a result, our availability under the revolving credit facility at December 31, 2004, taking into account outstanding letters of credit, increased to $46.7 million.

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 revolving 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 revolving 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 revolving credit facility requires us to (i) include the amount of funds available under this facility as a current asset, (ii) exclude current assets and liabilities related to the fair value of derivatives, and (iii) exclude current maturities of vendor finance obligations, when computing the working capital ratio at any balance sheet date.

Working capital computed for loan compliance purposes differs from our working capital computed in accordance with generally accepted accounting principles (GAAP). Since compliance with financial covenants is a material requirement under the credit facilities, we consider the loan compliance working capital computation to be useful as a measure of our liquidity because it includes the funds available to us under the revolving credit facility and is not affected by the volatility in working capital caused by changes in fair value of derivatives. Our reported working capital deficit increased from $13.1 million at December 31, 2003 to $27.6 million at December 31, 2004 due primarily to an increase in current liabilities related to the fair value of derivatives. After giving effect to the adjustments, our working capital computed for loan compliance purposes was a positive $32.9 million at December 31, 2004, as compared to a positive $32.3 million at December 31, 2003. The following table reconciles our GAAP working capital to the working capital computed for loan compliance purposes at December 31, 2004 and December 31, 2003.

	December 31, 2004			December 31, 2003
	(In thousands)
Working capital (deficit) per GAAP	$	(27,566	)	$	(13,119	)
Add funds available under the revolving credit facility	46,725			40,725
Exclude fair value of derivatives classified as current assets or current liabilities	13,693			2,233
Exclude current maturities of vendor finance Obligations	—			2,453
Working capital per loan covenant	$	32,852		$	32,292

The acquisition of SWR significantly increased our indebtedness and decreased our liquidity. Our long-term debt (including current maturities) increased from $55.7 million at December 31, 2003 to $177.6 million at December 31, 2004. As a result, our long-term debt as a percentage of total capitalization (debt plus stockholders’ equity) increased from 36% to 60%. This additional leverage increased our cost of capital initially by approximately 150 basis points due primarily to a higher rate of interest on the senior term credit facility and the amortization of debt issue costs incurred in connection with the new credit facilities.

Since we rely on the credit facilities for both short-term liquidity and long-term financing needs, it is important that we comply in all material respects with the applicable loan agreements, including financial

covenants that are computed quarterly. The working capital covenant requires us to maintain positive working capital using the computations described above. Other financial covenants under the credit facilities require us to maintain a ratio of indebtedness to cash flow, as each is determined in accordance with the applicable credit facility, of no more than 3 to 1, and a ratio of reserve value to indebtedness, as each is determined in accordance with the applicable credit facility, of at least 1.5 to 1. While we were in compliance with all financial and non-financial covenants at December 31, 2004, our increased leverage may result in our failing to comply with one or more of these covenants in the future. If we fail to meet any of these loan covenants, we would ask the banks to allow us sufficient time to obtain additional capital resources through alternative means. If a suitable arrangement could not be reached with the banks, the banks could accelerate the indebtedness and seek to foreclose on the pledged assets.

The banks redetermine the borrowing base at least twice a year, in May and November. 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 applicable loan agreement.

Alternative Capital Resources

Although our base of oil and gas reserves, as collateral for the revolving credit facility, has historically been our primary capital resource, we have in the past, and we believe we could in the future, use alternative capital resources, such as asset sales, vendor financing arrangements, and/or public or private issuances of common stock. 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.

Contractual Obligations and Contingent Commitments

In connection with the acquisition of SWR, we entered into new credit facilities with the banks. At December 31, 2004, based on the new terms, we are contractually obligated to repay indebtedness of $147.5 million on the revolving loan in 2007 and $30 million on the senior term loan in 2008. In addition, we assumed approximately $8.4 million of asset retirement obligations in connection with the SWR acquisition, substantially all of which are expected to mature after 2008.

The following table summarizes our contractual obligations as of December 31, 2004 by payment due date.

	Payments Due by Period
	Total		2005		2006-2007		2008-2009		Thereafter
	(In thousands)
Contractual obligations:
Secured bank credit facilities:
Revolving loan	$	147,500	$	—	$	147,500	$	—	$	—
Senior term loan	30,000		—		—		30,000		—
Abandonment obligations	16,147		6,335		1,554		2,084		6,174
Lease obligations	2,322		1,059		1,250		13		—
Other	50		31		19		—		—
Total contractual obligations	$	196,019	$	7,425	$	150,323	$	32,097	$	6,174

Excluded from the table above is our mark-to-market liability related to commodity and interest rate derivatives. Our derivative obligations, based on mark-to-market valuations at December 31, 2004, would mature as follows: 2005 - $13,693; 2006 - $12,209; 2007 - $9,932; and 2008 - $6,817.

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

We are primarily an exploration company. For 2005, approximately 66% of our planned capital expenditures relate to exploratory prospects. Exploration activities involve the drilling of wells in areas where there is little or no known production. Exploration is a higher risk activity than development. 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 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. 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, 2004 is approximately 9.3 years, based on 2004 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).

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 revolving 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. Our management may elect to enter into and terminate hedges based on expectations of future market conditions. If prices continue to rise while our hedges are in place, we will forego revenue we would have otherwise received. If we terminate a hedge because we anticipate an increase in product prices that we would not realize with the hedge in place, and product prices do not increase as anticipated, we may be exposed to downside risk that would not have existed otherwise.

Reserve Estimates

The accuracy of proved reserves estimates and estimated future net revenues from such reserves is a function of the quality of available geological, geophysical, engineering and economic data and is subject to various assumptions including assumptions required by the SEC relating to oil and gas prices, drilling and operating expenses, and other matters. Although we believe that our estimated proved reserves represent reserves that we are reasonably certain to recover, 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 used to determine proved reserves. Any significant variance could materially affect the estimated quantities and value of our oil and gas reserves, which in turn could 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.

The present value of proved reserves will not necessarily equal the current fair market value of our estimated oil and gas reserves. In accordance with the reserve reporting 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 affect 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 our banks in establishing the borrowing base under our revolving 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.

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. 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 revolving 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 2005. 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 revolving 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, 2004 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 2005 by approximately $2.3 million and $10.5 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 revolving 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 revolving credit facility. Until a well is on production, the banks may assign only a minimal borrowing base value to the well, and cash flows 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. 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. While we believe this reconciliation process improves the accuracy of the reserve estimates by reducing the likelihood of a material error in judgment, it is possible that in exchanging information, our internal reservoir engineer could influence the independent engineer’s estimates and assumptions.

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
	Oil (a) (MMBbls)	Gas (Bcf)	Oil (a) ($/Bbl)		Gas ($/Mcf)		of Proved Reserves
							(In millions)

As of December 31:
2004	26.8	138.3	$	41.48	$	5.59	$	705.3
2003	10.3	62.9	$	30.45	$	5.61	$	335.1
2002	11.9	86.9	$	28.98	$	4.44	$	382.5

(a) Includes natural gas liquids

Valuation of unproved properties

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

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

• The nature and extent of 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 unless such estimates were unreasonable or did not comply with applicable SEC accounting rules. 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 December 2004, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards No. 153 “Exchanges of Nonmonetary Assets, an amendment of APB Opinion No. 29” (“SFAS 153”). SFAS 153 specifies the criteria required to record a nonmonetary asset exchange using carryover basis. SFAS 153 is effective for nonmonetary asset exchanges occurring after July 1, 2005. The Company will adopt this statement in the third quarter of 2005, and it is not expected to have a material effect on the financial statements when adopted.

In December 2004, the FASB issued Statement of Financial Accounting Standards No. 123 (revised 2004) “Share-Based Payments” (“SFAS 123R”). SFAS 123R requires that the cost from all share-based payment transactions, including stock options, be recognized in the financial statements at fair value. The Company currently uses the intrinsic-value method to account for these share-based payments. SFAS 123R is effective for public companies in the first interim period after June 15, 2005. The Company will adopt the provisions of this statement in the third quarter of 2005 and is currently assessing the effect of SFAS 123R on the financial statements.

The Financial Accounting Standards Board has proposed FASB Staff Position No. 19-a “FSP 19-a”, which has a comment deadline of March 7, 2005. FSP 19-a would amend the present guidance in SFAS 19, paragraphs 31 and 34, regarding when exploratory drilling costs pending determination of proved reserves can be carried as an asset of an oil and gas company that uses the successful efforts accounting method. Based on our present understanding of this proposed statement, the adoption of FSP 19-a will not have a significant impact on our results of operations. At December 31, 2004 and 2003, we had capitalized $5.4 million and $872,000, respectively, of exploratory drilling costs applicable to wells that were pending determination of proved reserves. All of the December 31, 2003 capitalized costs were classified as productive wells in 2004. All of the December 31, 2004 capitalized costs relate to wells for which drilling and completion activities are continuing.

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 our revolving 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, 2004 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, 2005 by $12.8 million.

From time to time, we utilize commodity derivatives, consisting primarily of swaps, floors and collars to attempt to optimize the price received for our oil and natural gas production. When using swaps to hedge our 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. When purchasing floors, we receive a fixed price (put strike price) if the market price falls below the put strike price for the respective commodity. If the market price is greater than the put strike price, no payments are due from either party. Costless collars are a combination of puts and calls, and contain a fixed floor price (put strike price) and ceiling price (call strike price). 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, 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.

The decision to initiate or terminate commodity hedges is made by management based on its expectation of future market price movements. We have no set goals for the percentage of our production we hedge and we do not use any formulas or triggers in deciding when to initiate or terminate a hedge. If we enter into swaps or collars and the floating market price at the settlement date is higher than the fixed price or the fixed ceiling price, we will forego revenue we would have otherwise received. If we terminate a swap, collar or floor because we anticipate future increases in market prices, we may be exposed to downside risk that would not have existed otherwise.

The following summarizes information concerning our net positions in open commodity derivatives applicable to periods subsequent to December 31, 2004.

Floors:

	Gas			Oil
	MMBtu	Floor		Bbls	Floor
Production Period:
1st Quarter 2005	1,800,000	$	4.50	117,000	$	28.00
1st Quarter 2005	1,180,000	$	5.00
2nd Quarter 2005	1,820,000	$	4.50	118,300	$	28.00
2nd Quarter 2005	1,820,000	$	5.00
3rd Quarter 2005	1,840,000	$	4.50	119,600	$	28.00
4th Quarter 2005	1,840,000	$	4.50	119,600	$	28.00
	10,300,000			474,500

Collars:

	Gas					Oil
	MMBtu (a)	Floor		Ceiling		Bbls	Floor		Ceiling
Production Period:
1st Quarter 2005	649,000	$	4.00	$	5.23	170,000	$	23.00	$	25.41
2nd Quarter 2005	630,000	$	4.00	$	5.23	168,000	$	23.00	$	25.41
3rd Quarter 2005	607,000	$	4.00	$	5.23	165,000	$	23.00	$	25.41
4th Quarter 2005	588,000	$	4.00	$	5.23	162,000	$	23.00	$	25.41
2006	2,024,000	$	4.00	$	5.21	613,000	$	23.00	$	25.32
2007	1,831,000	$	4.00	$	5.18	562,000	$	23.00	$	25.20
2008	1,279,000	$	4.00	$	5.15	392,000	$	23.00	$	25.07
	7,608,000					2,232,000

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

In December 2004, we terminated gas swaps covering 1,800,000 MMBtu at a fixed gain of $2 million which will be realized in the first quarter of 2005.

We use a sensitivity analysis technique to evaluate the hypothetical effect that changes in the market value of oil and gas may have on the fair value of our commodity derivatives. A $1 per barrel change in the price of oil and a $.50 per MMBtu change in the price of gas would change the fair value of our commodity derivatives by approximately $5 million.

Interest Rates

All of our outstanding bank indebtedness at December 31, 2004 is subject to market rates of interest as determined from time to time by the banks pursuant to our credit facilities. We may designate borrowings under our credit facilities 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 assumed our interest rate swaps in connection with the acquisition of SWR. The following summarizes information concerning our net positions in open interest rate swaps applicable to periods subsequent to December 31, 2004.

Interest Rate Swaps:

	Principal Balance		Libor Rates
Period:
January 1, 2005 to November 1, 2005	$	60,000,000	2.97	%
November 1, 2005 to November 1, 2006	$	55,000,000	4.29	%
November 1, 2006 to November 1, 2007	$	50,000,000	5.19	%
November 1, 2007 to November 1, 2008	$	45,000,000	5.73	%

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 our management 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:

• management has 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.

Internal Control Over Financial Reporting

Management designed our internal control over financial reporting to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of our financial statements for

external purposes in accordance with generally accepted accounting principles. Our internal control over financial reporting includes those policies and procedures that:

• pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets;

• provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of management and our Board of Directors; and

• provide reasonable assurance regarding prevention or timely detection of any unauthorized acquisition, use or disposition of our assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Changes in Internal Control Over Financial Reporting

No changes in internal control over financial reporting were made during the quarter ended December 31, 2004 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Management’s Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934. Management assessed the effectiveness of our internal control over financial reporting as of December 31, 2004. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework. Based on this assessment, management has concluded that, as of December 31, 2004, our internal control over financial reporting is effective based on those criteria.

The scope of management’s report on internal control over financial reporting excludes Southwest Royalties, Inc. and its subsidiaries and affiliated limited partnerships (“SWR”). We acquired SWR through a merger that was completed on May 21, 2004. As of December 31, 2004, management has not assessed the effectiveness of SWR’s internal controls over financial reporting based on the criteria set forth by COSO, and management’s conclusion regarding the effectiveness of our internal control over financial reporting does not extend to SWR. As of December 31, 2004, we reported consolidated total assets of $462.2 million, of which SWR accounted for $259.1 million. For the year ended December 31, 2004, our consolidated revenues totaled $206.3 million, of which SWR accounted for $45.1 million. Our management report on internal control over financial reporting for 2005 will include SWR.

KPMG LLP has issued an attestation report on management’s assessment of internal control over financial reporting, the contents of which are printed below.

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders

Clayton Williams Energy, Inc.:

We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control Over Financial Reporting, that Clayton Williams Energy, Inc. (Company) maintained effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

In our opinion, management’s assessment that the Company maintained effective internal control over financial reporting as of December 31, 2004, is fairly stated, in all material respects, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

The Company acquired Southwest Royalties, Inc. and its subsidiaries and affiliated limited partnerships (SWR) during 2004, and management excluded from its assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004, SWR’s internal control over financial reporting associated with total assets of $259.1 million and total revenues of $45.1 million included in the consolidated financial statements of the Company and subsidiaries as of and for the year

ended December 31, 2004. Our audit of internal control over financial reporting of the Company also excluded an evaluation of the internal control over financial reporting of SWR

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Clayton Williams Energy, Inc. and subsidiaries as of December 31, 2004 and 2003, and the related consolidated statements of operations, stockholders’ equity, cash flows and all related financial statement schedules for each of the years in the three-year period ended December 31, 2004, and our report dated March 11, 2005, expressed an unqualified opinion on those consolidated financial statements

KPMG LLP

Dallas, Texas

March 11, 2005

Item 9B - Other Information

None.

PART III

Item 10 - Directors and Executive Officers of the Registrant

Information required by this Item is incorporated by reference to our definitive proxy statement, which will be filed with the SEC no later than April 30, 2005.

Item 11 - Executive Compensation

Information required by this Item is incorporated by reference to our definitive proxy statement, which will be filed with the SEC no later than April 30, 2005.

Item 12 - Security Ownership of Certain Beneficial Owners and Management

Information required by this Item is incorporated by reference to our definitive proxy statement, which will be filed with the SEC no later than April 30, 2005.

Item 13 - Certain Relationships and Related Transactions

Information required by this Item is incorporated by reference to our definitive proxy statement, which will be filed with the SEC no later than April 30, 2005.

Item 14 - Principal Accountant Fees and Services

Information required by this Item is incorporated by reference to our definitive proxy statement, which will be filed with the SEC no later than April 30, 2005.

PART IV

Item 15 - Exhibits and Financial Statement Schedules

Financial Statements and Schedules

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

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

**2.1		Agreement and Plan of Merger among Clayton Williams Energy, Inc. and Southwest Royalties, Inc. dated May 3, 2004, filed as Exhibit 2.1 to the Company’s Current Report on Form 8-K filed with the Commission on June 3, 2004††

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

Exhibit Number		Description of Exhibit

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

**3.3		Bylaws of the Company, filed as Exhibit 3.4 to the Company’s Form S-1 Registration Statement, Commission File No. 033-43350

**4.1		Stock Purchase Agreement dated May 19, 2004 by and among Clayton Williams Energy, Inc. and various institutional investors, filed as Exhibit 4 to the Company’s Current Report on Form 8-K filed with the Commission on June 2, 2004††

**10.1		Amended and Restated Credit Agreement dated as of May 21, 2004 among Clayton Williams Energy, Inc., et al, and Bank One, NA, et al, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K/A filed with the Commission on June 23, 2004††

**10.2		Senior Term Credit Agreement dated as of May 21, 2004 among Clayton Williams Energy, Inc., et al, and Bank One, NA, et al, filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K/A filed with the Commission on June 23, 2004††

**10.3†		1993 Stock Compensation Plan, filed as Exhibit 10.1 to the Company’s Form S-8 Registration Statement, Commission File No. 033-68318

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

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

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

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

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

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

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

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

*10.12†		Scudder Trust Company Prototype Defined Contribution Plan adopted by Clayton Williams Energy, Inc. effective as of August 1, 2004

Exhibit Number		Description of Exhibit

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

**10.14†		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††

**10.15		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, Commission File No. 033-43350

**10.16		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††

**10.17		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, Commission File No. 033-43350

**10.18		Second Amended and Restated Service Agreement effective March 1, 2005 among Clayton Williams Energy, Inc. and its subsidiaries, Clayton Williams Ranch Holdings, Inc., ClayDesta L.P., Clayton Williams Partnership, Ltd. and CWPLCO, Inc., filed as Exhibit 99.1 to the Company’s Current Report on Form 8-K filed with the Commission on March 3, 2005††

**10.19†		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††

**10.20†		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††

**10.21†		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††

**10.22†		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††

**10.23†		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††

**10.24†		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††

**10.25†		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††

**10.26†		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††

Exhibit Number		Description of Exhibit

**	10.27†	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††

**	10.28†	Agreement of Limited Partnership of CWEI Longfellow Ranch I, L.P. dated April 1, 2003, filed as Exhibit 10.32 to the Company’s Form 10-K for the period ended December 31, 2003††

*	10.29†	Agreement of Limited Partnership of CWEI South Louisiana II, L.P. effective as of January 1, 2004

*	10.30†	Agreement of Limited Partnership of CWEI Mississippi I, L.P. effective as of January 1, 2004

*	10.31†	Agreement of Limited Partnership of Rocky Arroyo, L.P. effective as of January 2, 2005

*	10.32†	Agreement of Limited Partnership of CWEI Mississippi II, L.P. effective as of January 2, 2005

*	10.33†	Agreement of Limited Partnership of CWEI West Pyle/McGonagill, L.P. effective as of January 2, 2005

*	10.34†	Agreement of Limited Partnership of CWEI Destefano, L.P. effective as of January 2, 2005

*	10.35†	Amendment to Agreement dated April 23, 1993 between the Company and Robert C. Lyon

*	10.36†	Second Amendment to Agreement dated April 23, 1993 between the Company and Robert C. Lyon

*	10.37†	Form of stock option agreement for 1993 Stock Compensation Plan

*	10.38†	Form of stock option agreement for Outside Directors Stock Option Plan

*	21	Subsidiaries of the Registrant

*	23.1	Consent of KPMG LLP

*	23.2	Consent of Williamson Petroleum Consultants, Inc.

*	23.3	Consent of Ryder Scott Company, L.P.

*	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

Exhibit Number		Description of Exhibit

*32.1		Certifications by the Chief Executive Officer and 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.
††			Filed under the Company’s Commission File No. 001-10924.

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 15, 2005
	Clayton W. Williams		President and Chief Executive
			Officer and Director


	/s/ L. PAUL LATHAM		Executive Vice President,	March 15, 2005
	L. Paul Latham		Chief Operating Officer and
			Director


	/s/ MEL G. RIGGS		Senior Vice President -	March 15, 2005
	Mel G. Riggs		Finance, Secretary, Treasurer,
			Chief Financial Officer and Director

	/s/ MICHAEL L. POLLARD		Vice President – Accounting and	March 15, 2005
	Michael L. Pollard		Principal Accounting Officer

	/s/ STANLEY S. BEARD *		Director	March 15, 2005
	Stanley S. Beard

	/s/ DAVIS L. FORD *		Director	March 15, 2005
	Davis L. Ford

	/s/ ROBERT L. PARKER *		Director	March 15, 2005
	Robert L. Parker

	/s/ JORDAN R. SMITH *		Director	March 15, 2005
	Jordan R. Smith

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

CLAYTON WILLIAMS ENERGY, INC.

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

AND FINANCIAL STATEMENT SCHEDULES

Report of Independent Registered Public Accounting Firm

Consolidated Balance Sheets

Consolidated Statements of Operations

Consolidated Statements of Stockholders’ Equity

Consolidated Statements of Cash Flows

Notes to Consolidated Financial Statements

Financial Statement Schedule Schedule II-Valuation and Qualifying Accounts

F-1

REPORT OF INDEPENDENT REGISTERED

PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders

Clayton Williams Energy, Inc.:

We have audited the accompanying consolidated balance sheets of Clayton Williams Energy, Inc. and subsidiaries as of December 31, 2004 and 2003, 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, 2004. In connection with our audits of the consolidated financial statements, we also have audited the accompanying financial statement schedule. These consolidated financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements and financial statement schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). 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, 2004 and 2003, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2004, in conformity with U.S. generally accepted accounting principles. Also in our opinion, the related financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.

As discussed in Note 5 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”.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Clayton Williams Energy, Inc.’s internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 11, 2005, expressed an unqualified opinion on management’s assessment of, and the effective operations of, internal control over financial reporting.

KPMG LLP

Dallas, Texas

March 11, 2005

F-2

CLAYTON WILLIAMS ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

	December 31,
	2004			2003
ASSETS

CURRENT ASSETS
Cash and cash equivalents	$	16,359		$	15,454
Accounts receivable:
Oil and gas sales	25,573			16,725
Joint interest and other, net	4,653			2,972
Affiliates	553			453
Inventory	5,202			787
Deferred income taxes	625			1,241
Fair value of derivatives	2,333			—
Prepaids and other	1,401			1,518
	56,699			39,150
PROPERTY AND EQUIPMENT
Oil and gas properties, successful efforts method	909,095			656,531
Natural gas gathering and processing systems	17,286			16,829
Other	11,839			12,300
	938,220			685,660
Less accumulated depreciation, depletion and amortization	(539,860		)	(504,101		)
Property and equipment, net	398,360			181,559
OTHER ASSETS	7,176			3,724
	$	462,235		$	224,433

LIABILITIES AND STOCKHOLDERS’ EQUITY

CURRENT LIABILITIES
Accounts payable:
Trade	$	51,014		$	33,523
Oil and gas sales	11,223			10,086
Affiliates	2,954			1,254
Current maturities of long-term debt	31			2,453
Fair value of derivatives	16,026			2,233
Accrued liabilities and other	3,017			2,720
	84,265			52,269
NON-CURRENT LIABILITIES
Long-term debt	177,519			53,295
Deferred income taxes	36,897			8,504
Fair value of derivatives	28,958			—
Other	17,000			9,584
	260,374			71,383
COMMITMENTS AND CONTINGENCIES

STOCKHOLDERS’ EQUITY
Preferred stock, par value $.10 per shares, authorized – 3,000,000 shares; issued and outstanding – none	—			—
Common stock, par value $.10 per shares, authorized – 30,000,000 shares; issued and outstanding – 10,787,013 shares in 2004 and 9,368,322 shares in 2003	1,078			937
Additional paid-in capital	104,674			73,972
Retained earnings	11,844			25,872
	117,596			100,781
	$	462,235		$	224,433

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,
	2004			2003			2002
REVENUES
Oil and gas sales	$	193,127		$	163,032		$	86,302
Natural gas services	9,083			8,758			5,568
Gain on sales of property and equipment	4,120			267			2,241
Total revenues	206,330			172,057			94,111

COSTS AND EXPENSES
Production	41,163			28,239			21,857
Exploration:
Abandonments and impairments	67,956			35,120			21,571
Seismic and other	7,124			8,755			8,578
Natural gas services	8,538			8,279			4,853
Depreciation, depletion and amortization	44,040			40,284			29,656
Impairment of property and equipment	—			170			349
Accretion of abandonment obligations	1,044			651			—
General and administrative	11,689			10,934			8,615
Loss on sales of property and equipment	14,337			68			1,880
Total costs and expenses	195,891			132,500			97,359

Operating income (loss)	10,439			39,557			(3,248		)

OTHER INCOME (EXPENSE)
Interest expense	(7,877		)	(3,138		)	(4,006		)
Change in fair value of derivatives	(25,329		)	(1,593		)	(1,581		)
Other	1,354			(1,662		)	1,755
Total other income (expense)	(31,852		)	(6,393		)	(3,832		)

Income (loss) before income taxes	(21,413		)	33,164			(7,080		)
Income tax expense (benefit)	(7,385		)	10,515			(1,742		)
Income (loss) from continuing operations	(14,028		)	22,649			(5,338		)
Cumulative effect of accounting change, net of tax	—			207			—
Income from discontinued operations, including gain on sale of $1,196 in 2002, net of tax	—			—			1,335

NET INCOME (LOSS)	$	(14,028	)	$	22,856		$	(4,003	)

Net income (loss) per common share:
Basic:
Income (loss) from continuing operations	$	(1.37	)	$	2.43		$	(.58	)
Net income (loss)	$	(1.37	)	$	2.45		$	(.43	)

Diluted:
Income (loss) from continuing operations	$	(1.37	)	$	2.38		$	(.58	)
Net income (loss)	$	(1.37	)	$	2.40		$	(.43	)

Weighted average common shares outstanding:
Basic	10,213			9,329			9,241
Diluted	10,213			9,509			9,241

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

F-4

CLAYTON WILLIAMS ENERGY, INC.

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(In thousands)

	Common Stock					Additional						Accumulated Other			Total
	No. of		Par			Paid-In			Retained			Comprehensive			Comprehensive
	Shares		Value			Capital			Earnings (Loss)			Income (Loss)			Income (Loss)
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			—
Net loss and total comprehensive loss	—		—			—			(14,028		)	—			$	(14,028	)
Issuance of stock through compensation plans	38		3			853			—			—
Issuance of common stock, net of offering costs of $1,773	1,381		138			29,849			—			—
BALANCE,
December 31, 2004	10,787		$	1,078		$	104,674		$	11,844		$	—

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,
	2004			2003			2002
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	(14,028	)	$	22,856		$	(4,003	)
Adjustments to reconcile net income (loss) to cash provided by operating activities:
Depreciation, depletion and amortization	44,040			40,284			29,656
Impairment of property and equipment	—			170			349
Exploration costs	67,956			35,120			21,571
Loss (gain) on sales of property and equipment	10,217			(199		)	(361		)
Deferred income taxes	(7,645		)	10,172			(1,742		)
Non-cash employee compensation	536			1,312			837
Change in fair value of derivatives	7,104			1,546			2,172
Settlements on derivatives with financing elements	9,890			—			—
Accretion of abandonment obligations	1,044			651			—
Cumulative effect of accounting change, net of tax	—			(207		)	—
Non-cash effect of discontinued operations, including gain on sale, net of tax	—			—			(1,029		)

Changes in operating working capital, net of the effects of a business acquisition in 2004:
Accounts receivable	581			(1,787		)	(8,561		)
Accounts payable	8,881			8,655			(5,389		)
Other	(1,596		)	1,177			1,014
Net cash provided by operating activities	126,980			119,750			34,514

CASH FLOWS FROM INVESTING ACTIVITIES
Additions to property and equipment	(123,991		)	(62,889		)	(71,635		)
Acquisition of a business, net of cash acquired of $12,341	(168,204		)	—			—
Proceeds from sales of property and equipment	35,020			239			7,607
Other	269			(2,120		)	(3		)
Net cash used in investing activities	(256,906		)	(64,770		)	(64,031		)

CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt	172,500			—			32,949
Repayments of long-term debt	(60,530		)	(45,483		)	—
Proceeds from sale of common stock, net of offering costs	30,018			281			36
Repurchase and cancellation of common stock	—			—			(648		)
Payment of debt issue costs	(4,156		)	—			—
Settlements on derivatives with financing elements	(9,890		)	—			—
Other	2,889			—			—
Net cash provided by (used in) financing activities	130,831			(45,202		)	32,337

NET INCREASE IN CASH AND CASH EQUIVALENTS	905			9,778			2,820

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

End of period	$	16,359		$	15,454		$	5,676

SUPPLEMENTAL DISCLOSURES
Cash paid for interest, net of amounts capitalized	$	7,246		$	2,941		$	3,995

Cash paid for income taxes	$	90		$	—		$	—

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 41% of the Company’s outstanding 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 into appropriate groups of properties based on geographical and geological similarities. These capitalized costs are amortized using the unit-of-production method based on estimated proved reserves. Proceeds from sales

F-7

of properties are credited to property costs, and a gain or loss is recognized when a significant portion of an amortization base is sold or abandoned.

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 nonproductive. The determination of an exploratory well’s ability to produce must be made within one year from the completion of drilling activities. 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. An impairment is recognized when the estimated undiscounted future net cash flows of the asset are less than its carrying value. Any such impairment is recognized based on the differences in the carrying value and estimated fair value of the impaired asset.

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, 2004, the Company’s unproved oil and gas properties had an aggregate net book value of $35.2 million, including $5.4 million of exploratory drilling costs for which the determination of proved reserves had not been made. None of these costs are attributable to wells for which drilling activities have been completed for more than one year. 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.

F-8

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.

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 of swaps, floors and collars, to attempt to reduce its exposure to changes in commodity prices and interest rates. 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. 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 periods for which exploration activities are in progress. During the years ended December 31, 2004, 2003 and 2002, the Company capitalized interest totaling approximately $877,000, $1.1 million and $600,000, respectively.

F-9

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 are computed by dividing net income by the weighted average number of common shares outstanding for the period. Diluted earnings per share reflect 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 2004 and 2002 as the effect would be anti-dilutive.

Stock-Based Compensation

The Company accounts for stock-based compensation utilizing the intrinsic value method prescribed by Accounting Principles Board Opinion No. 25 “Accounting for Stock Issued to Employees” (“APB 25”) and related interpretations. The following pro forma information, as required by Statement of Financial Accounting Standards No. 123 “Accounting for Stock-Based Compensation” (“SFAS 123”), as amended by Statement of Financial Accounting Standards No. 148 (“SFAS 148”), presents net income and earnings per share information as if the stock options issued since December 31, 1994 were accounted for using the fair value method. The fair value of stock options issued for each year was estimated at the date of grant using the Black-Scholes option pricing model. The estimated fair value of the stock options issued in 2004 and 2003 was approximately $5.9 million and $3 million; respectively. No options were granted during 2002. The following weighted average assumptions were used in this model.

	2004		2003

Risk-free interest rate	2.5	%	2.5	%
Stock price volatility	69	%	70	%
Expected life in years	10		10
Dividend yield	—		—

The SFAS 123 pro forma information for the years ended December 31, 2004, 2003 and 2002 is as follows:

	2004			2003			2002
	(In thousands, except per share)

Net income (loss), as reported	$	(14,028	)	$	22,856		$	(4,003	)
Add: Stock-based employee compensation expense (credit) included in net income (loss), net of tax	(159		)	518			(21		)
Deduct: Stock-based employee compensation expense determined under fair value based method (SFAS 123), net of tax	(3,840		)	(2,602		)	(883		)
Net income (loss), pro forma	$	(18,027	)	$	20,772		$	(4,907	)
Basic:
Net income (loss) per common share, as reported	$	(1.37	)	$	2.45		$	(.43	)
Net income (loss) per common share, pro forma	$	(1.77	)	$	2.23		$	(.53	)
Diluted:
Net income (loss) per common share, as reported	$	(1.37	)	$	2.40		$	(.43	)
Net income (loss) per common share, pro forma	$	(1.77	)	$	2.18		$	(.53	)

F-10

Revenue Recognition and Gas Balancing

The Company utilizes the sales method of accounting for oil, natural gas and natural gas liquids revenues whereby revenues, net of royalties, 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, 2004 or 2003. 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. There were no differences between net income and comprehensive income in 2004. A portion of the changes in fair value of derivatives required under SFAS 133 was reported in comprehensive income during 2003 and 2002.

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. Allowances for doubtful accounts at December 31, 2004 and 2003 relate to amounts due from joint interest owners.

Reclassifications

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

Recent Accounting Pronouncements

The Financial Accounting Standards Board has proposed FASB Staff Position No. 19-a “FSP 19-a”, which has a comment deadline of March 7, 2005. FSP 19-a would amend the present guidance in SFAS 19, paragraphs 31 and 34, regarding when exploratory drilling costs pending determination of proved reserves can be carried as an asset of an oil and gas company that uses the successful efforts accounting method. Based on the Company’s present understanding of this proposed statement, the adoption of FSP 19-a will not have a significant impact on the Company’s results of operations. At December 31, 2004 and 2003, the Company had capitalized $5.4 million and $872,000, respectively, of exploratory drilling costs applicable to wells that were pending determination of proved reserves. All of the December 31, 2003 capitalized costs were

F-11

classified as productive wells in 2004. All of the December 31, 2004 capitalized costs relate to wells for which drilling and completion activities are continuing.

3. Acquisition of Southwest Royalties

On May 21, 2004, the Company acquired all the outstanding common stock of Southwest Royalties, Inc. (“SWR”) through a merger. Prior to the acquisition, SWR was a privately-held, Midland-based energy company engaged in oil and gas exploration, production, development and acquisition activities in the United States. Most of SWR’s properties are located in the Permian Basin of west Texas and southeastern New Mexico.

In connection with the acquisition of SWR, the Company paid $57.1 million to holders of SWR common stock and common stock warrants and assumed and refinanced approximately $113.9 million of SWR bank debt at closing. In addition, the Company incurred approximately $9.4 million of merger-related costs, including (i) the assumption of SWR’s obligations to its officers and employees pursuant to change of control arrangements and (ii) investment banking, legal, accounting and other direct transaction costs related to the acquisition of SWR.

The Company has accounted for the acquisition of SWR using the purchase method of accounting for business combinations. Under this method of accounting, CWEI is deemed to be the acquirer for accounting purposes. SWR’s assets and liabilities were revalued under the purchase method of accounting and recorded at their estimated fair values.

Pursuant to SFAS 149, which amended SFAS 133, the derivative instruments assumed in connection with the SWR acquisition are deemed to contain a significant financing element, and all cash flow associated with these positions are reported as a financing activity in the statement of cash flows.

The following table sets forth the calculation of the purchase price for SWR and the related allocation of the purchase price to the assets acquired (in thousands):

Purchase price:
Acquisition of outstanding common stock and warrants		$		57,139
Long-term debt assumed and refinanced by CWEI		113,949
Assumption of other non-current liabilities		31,024
Transaction costs incurred		9,355
Current liabilities assumed		26,546
Deferred income taxes		36,655
		$		274,668

Allocation of purchase price:
Current assets	$		23,436
Proved oil and gas properties	229,238
Unproved oil and gas properties	18,130
Other property and equipment	3,494
Other assets	370
	$		274,668

The revaluation of SWR’s assets and liabilities under the purchase method of accounting created significant differences between the carrying value for financial reporting purposes and those used for income tax reporting purposes, resulting in federal and state deferred tax liabilities of $36.6 million on the effective date of the acquisition.

F-12

The following table reflects the unaudited pro forma results of operations for the year ended December 31, 2004 and 2003 as though the acquisition of SWR had occurred on January 1, 2003. The pro forma amounts are not necessarily indicative of the results that may be reported in the future.

	Year Ended December 31,
	2004			2003
	(In thousands, except per share data)

Revenues	$	230,163		$	226,297
Net income (loss) from continuing operations	$	(25,233	)	$	19,434

Net income (loss) from continuing operations per share:
Basic	$	(2.34	)	$	1.81
Diluted	$	(2.34	)	$	1.78

4. Long-Term Debt

Long-term debt at December 31, 2004 and 2003 consists of the following:

	2004			2003
	(In thousands)

Secured bank credit facilities:
Revolving loan, due May 2007	$	147,500		$	50,000
Senior term loan, due May 2008	30,000			—
Vendor finance obligations	—			5,748
Other	50			—
	177,550			55,748
Less current maturities	(31		)	(2,453		)
	$	177,519		$	53,295

Aggregate maturities of long-term debt at December 31, 2004 are as follows: 2005 – $31,000; 2006 - $19,000; 2007 - $147,500,000; and 2008 - $30,000,000.

Secured Bank Credit Facilities

In connection with the acquisition of SWR in May 2004 (see Note 3), the Company entered into new credit facilities with a group of banks that provided for an increase in borrowing capacity under the Company’s existing revolving credit facility and established a new senior term credit facility. The borrowing base established under the revolving credit facility increased from $95 million to $180 million, and the Company initially borrowed $75 million on the senior term credit facility. With a portion of the net proceeds from the private placement of common stock in May 2004, the Company reduced the principal balance on the senior term credit facility to $50 million.

In November 2004, the banks increased the borrowing base under the revolving credit facility to $195 million, and the Company paid down the senior term credit to $30 million with proceeds from certain asset sales (see Note 15).

The revolving credit facility provides for interest at rates based on the agent bank’s prime rate plus margins ranging from .25% to 1%, or if elected by the Company based on LIBOR plus margins ranging from 1.5% to 2.25%. The Company also pays a commitment fee on the unused portion of the revolving credit facility. Initially, the senior term credit facility provided for interest at rates based on the agent bank’s prime rate plus a margin of 3.5%, or if elected by the Company based on LIBOR plus a margin of 5%.

F-13

Until the principal balance on the senior term credit facility was equal to or less than $40 million, the applicable margins increased by .5% per quarter. Now that the principal balance is $30 million, the prime rate margin is fixed at 2.5%, and the LIBOR margin is fixed at 4%. Interest and fees are payable at least quarterly. The effective annual interest rate on the combined credit facility, including bank fees and amortization of debt issue costs, for the year ended December 31, 2004 was 5.3%.

The amount of funds available to the Company under the revolving credit facility is the lesser of the borrowing base, as established by the banks, or that portion of the borrowing base determined by the Company to be the elected borrowing limit. The borrowing base, which is based on the discounted present value of future net revenues from oil and gas production, is subject to redetermination at any time, but at least semi-annually in May and November, and is made at the discretion of the banks. At December 31, 2004, the borrowing base was $195 million, with no monthly commitment reductions. After taking into account outstanding letters of credit totaling $775,000, the Company had approximately $46.7 million available under the revolving credit facility at December 31, 2004.

Principal under the senior term note is due at maturity; however, mandatory prepayments are required when the Company raises funds from capital markets transactions or sales of assets. Prepayments that reduce the principal balance on the senior term note below $40 million are subject to a 1% fee through May 2005.

The loan agreements applicable to the respective credit facilities contain financial covenants that are computed quarterly. The working capital covenant requires the Company to maintain a ratio of current assets to current liabilities of at least 1 to 1. Other financial covenants under the credit facilities require the Company to maintain a ratio of indebtedness to cash flow of no more than 3 to 1, and a ratio of reserve value to indebtedness of at least 1.5 to 1. The computations of current assets, current liabilities, cash flow, indebtedness and reserve value are defined in the respective loan agreements. The Company was in compliance with all financial and non-financial covenants at December 31, 2004.

Vendor Finance Obligations

In August 2003, 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%, were to be repaid out of a percentage of the net revenues from the wells drilled under the arrangement. In December 2004, the Company repaid all balances owed under this arrangement.

5. Other Non-Current Liabilities

Other non-current liabilities at December 31, 2004 and 2003 consist of the following:

	2004		2003
	(In thousands)

Abandonment obligations	$	16,147	$	8,849
Production payment	—		735
Other	853		—
	$	17,000	$	9,584

Abandonment Obligations

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.

F-14

Changes in abandonment obligations for 2004 and 2003 are as follows:

	2004			2003
	(In thousands)

Beginning of year	$	8,849		$	7,632
Abandonment obligations related to the acquisition of SWR	8,512			—
Additional abandonment obligations from new wells	411			203
Sales of properties	(2,711		)	(337		)
Accretion expense	1,044			651
Revisions of previous estimates	42			700
End of year	$	16,147		$	8,849

The following sets forth pro forma results of operations for the year ended December 31, 2002, assuming the Company adopted SFAS 143 on January 1, 2002.

	2002
	(In thousands, except per share)

Net loss	$	(4,395	)
Net loss per common share:
Basic	$	(.48	)
Diluted	$	(.48	)

Production Payment

Also in connection with the Romere Pass acquisition, the Company granted to the seller a $1 million after-payout production payment which was discharged in connection with the sale of the Romere Pass assets in December 2004 (see Note 15).

F-15

6. 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, 2004 and 2003 are as follows:

	2004			2003
	(In thousands)
Deferred tax assets:
Net operating loss carryforwards	$	7,915		$	6,915
Accrued stock-based compensation	240			335
Fair value of derivatives	14,930			783
Credits related to alternative minimum tax	279			343
Depletion carryforwards	3,209			—
Other	5,058			1,419
	31,631			9,795
Deferred tax liabilities:
Property and equipment	(67,903		)	(17,058		)

Net deferred tax liabilities	$	(36,272	)	$	(7,263	)

Components of net deferred tax liabilities:
Current assets	$	625		$	1,241
Non-current liabilities	(36,897		)	(8,504		)
	$	(36,272	)	$	(7,263	)

For the years ended December 31, 2004, 2003 and 2002, the Company’s effective income tax rates were different than the statutory federal income tax rates for the following reasons:

	2004			2003			2002
	(In thousands)
Income tax expense (benefit) at statutory rate of 35%	$	(7,495	)	$	11,608		$	(2,478	)
Tax depletion in excess of basis	(447		)	(210		)	(174		)
Revision of previous tax estimates	(51		)	(12		)	39
Change in valuation allowance	—			(871		)	871
State income taxes	608			—			—
Income tax expense (benefit)	$	(7,385	)	$	10,515		$	(1,742	)

Current	$	260		$	343		$	—
Deferred	(7,645		)	10,172			(1,742		)
Income tax expense (benefit)	$	(7,385	)	$	10,515		$	(1,742	)

The Company derives an income tax benefit when employees and directors exercise options granted under the Company’s stock compensation plans (see Note 10). 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.

In connection with the SWR merger, the Company acquired $29.3 million of tax loss carryforwards that are subject to Section 382 limitations from a prior change in control that occurred in April 2002 and from the change in control that occurred in connection with the Company’s acquisition of SWR in May 2004. The Company has completed a review of the facts surrounding these changes in control and

F-16

presently believes that it will be able to utilize all of SWR’s tax loss carryforwards. Therefore, the Company has reversed the valuation allowance related to these tax loss carryforwards that was previously recorded at June 30, 2004, and has adjusted the SWR purchase price accordingly.

At December 31, 2004, the Company’s cumulative tax loss carryforwards were approximately $22.6 million. 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 Company believes that it is more likely than not that the Company will be able to utilize these tax loss carryforwards before they expire (beginning in 2008). Accordingly, no valuation allowance exists at December 31, 2004. A valuation allowance at December 31, 2002 was reversed during 2003.

7. Derivatives

Commodity Derivatives

From time to time, the Company utilizes commodity derivatives, consisting of swaps, floors 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. When purchasing floors, the Company receives a fixed price (put strike price) if the market price falls below the put strike price for the respective commodity. If the market price is greater than put strike price, no payments are due from either party. Costless collars are a combination of puts and calls, and contain a fixed floor price (put strike price) and ceiling price (call strike price). 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, 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, 2004. The settlement prices of commodity derivatives are based on NYMEX futures prices.

Floors:

	Gas			Oil
	MMBtu	Floor		Bbls	Floor
Production Period:
1st Quarter 2005	1,800,000	$	4.50	117,000	$	28.00
1st Quarter 2005	1,180,000	$	5.00
2nd Quarter 2005	1,820,000	$	4.50	118,300	$	28.00
2nd Quarter 2005	1,820,000	$	5.00
3rd Quarter 2005	1,840,000	$	4.50	119,600	$	28.00
4th Quarter 2005	1,840,000	$	4.50	119,600	$	28.00

	10,300,000			474,500

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Collars:

	Gas					Oil
	MMBtu (a)	Floor		Ceiling		Bbls	Floor		Ceiling
Production Period:
1st Quarter 2005	649,000	$	4.00	$	5.23	170,000	$	23.00	$	25.41
2nd Quarter 2005	630,000	$	4.00	$	5.23	168,000	$	23.00	$	25.41
3rd Quarter 2005	607,000	$	4.00	$	5.23	165,000	$	23.00	$	25.41
4th Quarter 2005	588,000	$	4.00	$	5.23	162,000	$	23.00	$	25.41
2006	2,024,000	$	4.00	$	5.21	613,000	$	23.00	$	25.32
2007	1,831,000	$	4.00	$	5.18	562,000	$	23.00	$	25.20
2008	1,279,000	$	4.00	$	5.15	392,000	$	23.00	$	25.07

	7,608,000					2,232,000

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

In December 2004, the Company terminated gas swaps covering 1,800,000 MMBtu at a fixed gain of $2 million which will be realized in the first quarter of 2005.

The following summarizes information concerning the Company’s net positions in open interest rate swaps applicable to periods subsequent to December 31, 2004.

Interest Rate Swaps:

	Principal Balance		Libor Rates
Period:
January 1, 2005 to November 1, 2005	$	60,000,000	2.97	%
November 1, 2005 to November 1, 2006	$	55,000,000	4.29	%
November 1, 2006 to November 1, 2007	$	50,000,000	5.19	%
November 1, 2007 to November 1, 2008	$	45,000,000	5.73	%

Accounting For Derivatives

The Company accounts for its derivatives in accordance with 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. There was no activity in this account during 2004.

	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	$	—		$	—		$	—

F-18

The Company did not designate any of its currently open positions in commodity hedges as cash flow 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. For 2004, changes in fair value of undesignated contracts consisted of net realized losses of $18.2 million and losses related to changes in mark-to-market valuations of $7.1 million.

8. 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. Abandonment obligations are carried at net present value which approximates their fair value since the discount rate is based on the Company’s credit-adjusted, risk-free rate. The fair value of other noncurrent liabilities approximate their carrying value.

The fair values of derivatives as of December 31, 2004 and 2003 are set forth below. The associated carrying values of derivatives at December 31, 2004 and 2003 are equal to their estimated fair values.

	2004			2003
	(In thousands)
Assets (liabilities):
Commodity derivatives	$	(41,162	)	$	(2,233	)
Interest rate derivatives	(1,489		)	—
Net assets (liabilities)	$	(42,651	)	$	(2,233	)

9. Common Stock

In May 2004, the Company sold 1,380,869 shares of its common stock to certain institutional investors at a price of $23.00 per share in a private placement that raised approximately $31.8 million in gross proceeds. After the payment of typical transaction expenses, net proceeds of approximately $30 million were used to repay a portion of the bank indebtedness incurred to finance the acquisition of SWR (see Note 3).

The Company’s stock repurchase program expired in July 2004. Since its inception in 2001, the Company spent $1.4 million to repurchase for cancellation 115,100 shares of common stock, none of which were repurchased in 2003 or 2004.

10. 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, 2004 expire 10 years from the date of grant and become exercisable based on varying vesting schedules.

F-19

The following table reflects activity in the 1993 Plan for 2004, 2003 and 2002.

	2004				2003				2002
	Shares		Weighted Average Price		Shares		Weighted Average Price		Shares		Weighted Average Price
Beginning of year	821,042		$	14.66	680,850		$	12.29	687,350		$	12.22
Granted	300,000		$	26.06	200,000		$	19.74	—		$	—
Exercised	(3,906	)	$	5.50	(59,808	)	$	4.03	(6,500	)	$	5.50
End of year	1,117,136		$	17.75	821,042		$	14.66	680,850		$	12.29

Exercisable	1,117,136		$	17.75	821,042		$	14.66	668,032		$	12.41
Issuable	301,766				601,766				801,766

The following table summarizes information with respect to options outstanding at December 31, 2004, all of which are currently exercisable.

	Outstanding and Exercisable Options
	Shares	Weighted Average Exercise Price		Weighted Average Remaining Life in Years
Range of exercise prices:
$5.50 - $6.00	166,136	$	5.50	3.3
$14.50 - $26.06	951,000	$	19.89	6.3
	1,117,136	$	17.75	4.5

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, 2004 and 2003 is classified as a current liability in the accompanying consolidated balance sheet and is comprised of the following activity for the years then ended.

	2004			2003
	(In thousands)
Beginning of year	$	958		$	377
Compensation expense (credit)	(245		)	797
Amounts reclassified to additional paid-in capital for options exercised during the period	(28		)	(216		)
End of year	$	685		$	958

F-20

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 36,000 shares of common stock at option prices ranging from $3.25 to $28.93 per share. All outstanding options expire 10 years from the grant date and are fully exercisable upon issuance. At December 31, 2004, options to purchase 22,000 shares were outstanding, and 50,300 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, 2004, 106,190 shares remain available for issuance under this plan.

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 2004, 2003 and 2002, the Company issued 18,609, 15,275 and 54,833 shares, respectively, of common stock to Mr. Williams in lieu of cash salary and bonuses aggregating $463,000, $270,000 and $647,000, respectively. The amounts of such compensation are included in general and administrative expense in the accompanying consolidated financial statements. At December 31, 2004, 118,870 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. 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 at any time. There are no vesting requirements in the plan. During 2004, 2003 and 2002, the Company contributed $318,000, $247,000 and $224,000, respectively, in market value of common stock to the 401(k) plan.

After-Payout Working Interest Incentive Plans

In September 2002, the Compensation Committee of the Board of Directors 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 at least 99% of all subsequent revenues and pay at least 99% of all subsequent expenses attributable to the partnerships’ interests.

From 3% to 5% of the Company’s working interests in substantially all wells drilled by the Company subsequent to October 2002 are subject to this arrangement. The Company consolidates its proportionate share of the assets, liabilities, revenues, expenses and oil and gas reserves of these partnerships in its consolidated financial statements. In April 2004, one of the partnerships achieved payout, and the Company’s interest in the partnership was reduced to 1%. Aggregate cash distributions of $334,000 were paid to the limited partners during 2004.

F-21

11. 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, 2004, 2003 and 2002.

	2004		2003		2002
	(In thousands)
Amounts received from the Williams Entities:
Service Agreement:
Services	$	314	$	288	$	224
Insurance premiums and benefits	691		682		383
Reimbursed expenses	388		357		272
	$	1,393	$	1,327	$	879
Amounts paid to the Williams Entities:
Rent (a)	$	493	$	402	$	370
Service Agreement:
Business entertainment (b)	113		79		64
Other services	85		45		34
Reimbursed expenses	105		73		57
	$	796	$	599	$	525

(a) Rent amounts were paid to the Partnership discussed in Note 12. 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.

12. Investments

In May 2001, the Company invested approximately $1.6 million as a limited partner in ClayDesta Buildings, L.P. (“CDBLP”). The general partner of CDBLP is owned and controlled by Mr. Williams. CDBLP purchased and presently operates two commercial office buildings in Midland, Texas, one of which is the location of the Company’s corporate headquarters. The Company’s ownership interest in CDBLP is 31.9% before payout (as defined in the partnership agreement) and 33.4% after payout. The Company is not liable for any indebtedness of CDBLP. Since the Company does not control CDBLP or manage the operations of these buildings, and since CDBLP does not meet the characteristics of a variable interest entity under FIN 46R, the Company utilizes the equity method of accounting for its investment in CDBLP. For the years ended December 31, 2004, 2003 and 2002, the Company recorded pretax income of $60,000, $47,000 and $119,000, 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 at cost.

F-22

13. 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 $678,000, $578,000 and $501,000 for the years ended December 31, 2004, 2003 and 2002, respectively.

Future minimum payments under noncancelable leases at December 31, 2004, are as follows:

	Leases
	Capital (a)		Operating		Total
	(In thousands)
2005	$	300	$	759	$	1,059
2006	223		705		928
2007	102		220		322
Thereafter	—		13		13
Total minimum lease payments	$	625	$	1,697	$	2,322

(a) Relates to vehicle leases.

Legal Proceedings

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.

14. 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 and $349,000 in 2002. 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 Company has also recorded provisions for impairment of unproved properties aggregating $20.4 million, $7.3 million and $7.9 million in 2004, 2003 and 2002, respectively, and have charged these impairments to exploration costs in the accompanying statements of operations. The impairments of unproved properties recorded were based on drilling results and management’s plans for future drilling activities.

15. Sales of Assets

Gain on sale of property and equipment for 2004 was $4.1 million, including the sale of the Jo-Mill Unit in Borden County, Texas. Loss on sale of property and equipment for 2004 was $14.3 million including the sale of the Romere Pass Unit in Plaquemines Parish, Louisiana. Under EITF 03-13, “Applying the Conditions in Paragraph 42 of FASB Statement No. 144 in Determining Whether to Report Discontinued Operations”, the Company has determined that these sales do not qualify for discontinued operations reporting. The Company adopted EITF 03-13 during the fourth quarter of 2004.

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

F-23

payout production payment. The Company financed the acquisition through borrowings under its bank credit facility (see Note 4).

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
	(In thousands)
Revenues	$	363
Gain on sale of property and equipment	$	1,840
Income before income taxes	$	2,054
Net income	$	1,335

16. 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-24

17. Quarterly Financial Data (Unaudited)

The following table summarizes results for each of the four quarters in the years ended December 31, 2004 and 2003.

	First Quarter		Second Quarter		Third Quarter			Fourth Quarter			Year
	(In thousands, except per share)
Year ended December 31, 2004:
Total revenues	$	38,864	$	43,552	$	54,679		$	69,235		$	206,330
Gross profit (loss) (a)	$	14,301	$	8,291	$	15,726		$	(16,190	)	$	22,128
Income (loss) from continuing operations	$	4,813	$	2,869	$	(9,188	)	$	(12,522	)	$	(14,028	)
Net income (loss) (b)	$	4,813	$	2,869	$	(9,188	)	$	(12,522	)	$	(14,028	)

Net income (loss) per common share (c):
Basic:
Income (loss) from continuing operations	$	0.51	$	0.29	$	(0.85	)	$	(1.16	)	$	(1.37	)
Net income (loss)	$	0.51	$	0.29	$	(0.85	)	$	(1.16	)	$	(1.37	)

Diluted:
Income (loss) from continuing operations	$	0.50	$	0.28	$	(0.85	)	$	(1.16	)	$	(1.37	)
Net income (loss)	$	0.50	$	0.28	$	(0.85	)	$	(1.16	)	$	(1.37	)

Weighted average common shares outstanding:
Basic	9,371		9,923		10,769			10,780			10,213
Diluted	9,720		10,230		10,769			10,780			10,213

Year ended December 31, 2003:
Total revenues	$	50,745	$	45,525	$	40,272		$	35,515		$	172,057
Gross profit (loss) (a)	$	23,689	$	15,445	$	15,097		$	(3,740	)	$	50,491
Income (loss) from continuing operations	$	16,121	$	6,311	$	7,554		$	(7,337	)	$	22,649
Net income (loss) (b)	$	16,328	$	6,311	$	7,554		$	(7,337	)	$	22,856

Net income (loss) per common share (c):
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

(a) Gross profit equals operating income (loss) before general and administrative expenses.

(b) The Company recorded a $10.2 million net loss on the sales of property and equipment and $38.7 million for abandonments and impairments in the fourth quarter of 2004 and $17.8 million for abandonments and impairments in the fourth quarter of 2003.

(c) 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-25

18. 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, 2004, 2003 and 2002.

	2004		2003		2002
	(In thousands)
Property acquisitions:
Proved	$	237,042	$	—	$	18,249
Unproved	33,826		7,982		20,311
Developmental costs	27,075		11,689		4,964
Exploratory costs	73,655		49,277		27,011
Asset retirement costs (a)	394		776		3,500
Total	$	371,992	$	69,724	$	74,035

(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, 2004 and 2003.

	2004			2003
	(In thousands)
Proved properties	$	873,939		$	630,827
Unproved properties	35,156			25,704
Total capitalized costs	909,095			656,531
Accumulated depreciation, depletion and amortization	(518,787		)	(483,628		)
Net capitalized costs	$	390,308		$	172,903

19. 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. Future cash inflows were computed by applying year-end prices to the year-end quantities of proved reserves. Future development, abandonment and production costs were computed by estimating the expenditures to be incurred in developing, producing, and abandoning proved oil and gas reserves at the end of the year, based on year-end costs. Future income taxes were computed by applying statutory tax rates to the estimated net pre-tax cash flows after consideration of tax basis and tax credits and carryforwards. All of the Company’s reserves are located in the United States. For information about the Company’s results of operations from oil and gas producing activities, see the accompanying consolidated statements of operations.

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, 2004 are classified as proved developed nonproducing, which increases the imprecision inherent in estimating reserves which may ultimately be produced.

F-26

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, 2004, 2003 and 2002.

	2004						2003						2002
	Oil		Gas		MMcfe		Oil		Gas		MMcfe		Oil		Gas		MMcfe
Proved reserves:
Beginning of period	10,335		62,916		124,926		11,884		86,912		158,216		9,291		74,974		130,720
Revisions	1,603		6,962		16,580		(84	)	(7,323	)	(7,827	)	1,813		8,156		19,034
Extensions and discoveries	3,966		23,034		46,828		274		8,024		9,668		92		4,259		4,811
Sales of minerals-in-place	(3,359	)	(7,967	)	(28,121	)	—		—		—		(76	)	(1,009	)	(1,465	)
Purchases of minerals-in-place	16,591		71,271		170,819		—		—		—		2,582		16,576		32,068
Production:
Continuing operations	(2,343	)	(17,938	)	(31,996	)	(1,739	)	(24,697	)	(35,131	)	(1,812	)	(15,972	)	(26,844	)
Discontinued operations	—		—		—		—		—		—		(6	)	(72	)	(108	)
End of period	26,793		138,278		299,036		10,335		62,916		124,926		11,884		86,912		158,216
Proved developed reserves:
Beginning of period	9,349		62,514		118,806		9,349		76,224		132,318		8,414		74,407		124,891
End of period	19,799		95,224		214,018		9,349		62,514		118,606		9,349		76,224		132,318

The standardized measure of discounted future net cash flows relating to proved reserves as of December 31, 2004, 2003 and 2002 was as follows:

	2004			2003			2002
	(In thousands)
Future cash inflows	$	1,884,841		$	667,896		$	730,609
Future costs:
Production	(569,999		)	(179,500		)	(165,806		)
Abandonment	(17,599		)	(6,034		)	—
Development	(119,807		)	(17,446		)	(24,782		)
Income taxes	(336,030		)	(118,869		)	(137,059		)
Future net cash flows	841,406			346,047			402,962
10% discount factor	(341,208		)	(93,067		)	(109,264		)
Standardized measure of discounted net cash flows	$	500,198		$	252,980		$	293,698

Changes in the standardized measure of discounted future net cash flows relating to proved reserves for the years ended December 31, 2004, 2003 and 2002 were as follows:

	2004			2003			2002
	(In thousands)
Standardized measure, beginning of period	$	252,980		$	293,698		$	164,588
Net changes in sales prices, net of production costs	43,178			28,745			138,566
Revisions of quantity estimates	37,629			(21,212		)	49,551
Accretion of discount	51,870			38,252			18,687
Changes in future development costs, including development costs incurred that reduced future development costs	(2,489		)	10,106			5,094
Changes in timing and other	(16,297		)	(5,938		)	(16,827		)
Net change in income taxes	(119,605		)	10,282			(66,540		)
Future abandonment cost, net of salvage	(3,395		)	(3,579		)	—
Extensions and discoveries	149,680			37,419			14,834
Sales, net of production costs:
Continuing operations	(151,963		)	(134,793		)	(64,445		)
Discontinued operations	—			—			(306		)
Sales of minerals-in-place	(56,142		)	—			(1,744		)
Purchases of minerals-in-place	314,752			—			52,240
Standardized measure, end of period	$	500,198		$	252,980		$	293,698

F-27

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, 2004, 2003 and 2002 were as follows:

	Average Price
	Oil (a)		Gas
As of December 31:
2004	$	41.48	$	5.59
2003	$	30.45	$	5.61
2002	$	28.98	$	4.44

(a) Includes natural gas liquids

F-28

CLAYTON WILLIAMS ENERGY, INC.

Schedule II – Valuation and Qualifying Accounts

Description	Balance at Beginning of Period		Additions(a)		Deductions(b)			Balance at End of Period
	(In thousands)
Year Ended December 31, 2004:
Allowance for doubtful accounts - Joint interest and other	$	1,338	$	50	$	(375	)	$	1,013
	$	1,338	$	50	$	(375	)	$	1,013
Year Ended December 31, 2003:
Allowance for doubtful accounts - Joint interest and other	$	400	$	1,002	$	(64	)	$	1,338
Allowance for doubtful accounts - Oil and gas sales	286		—		(286		)	—
	$	686	$	1,002	$	(350	)	$	1,338
Year Ended December 31, 2002:
Allowance for doubtful accounts - Joint interest and other	$	400	$	46	$	(46	)	$	400
Allowance for doubtful accounts - Oil and gas sales	286		—		—			286
	$	686	$	46	$	(46	)	$	686

(a) Additions relate to provisions for doubtful accounts

(b) Deductions relate to the write-off of accounts receivable deemed uncollectible

S-1

TABLE OF CONTENTS

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

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

Item 7A - Quantitative and Qualitative Disclosure About Market Risks

Item 8 - Financial Statements and Supplementary Data

Exhibit Number

Description of Exhibit

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