Clayton Williams Energy (CWEI) 10-K 2008 FY Annual report

  UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

FORM 10-K

(Mark One)
x	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
	OF THE SECURITIES EXCHANGE ACT OF 1934
	For the fiscal year ended December 31, 2008

¨	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 001-10924

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:

Title of each class	Name of each exchange on which registered
Common Stock - $.10 Par Value	The NASDAQ Stock Market LLC

 Securities registered pursuant to Section 12(g) of the Act:  None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act
	¨ Yes	x No
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
	¨ Yes	x No
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.
	x Yes	¨ No

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See definition of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
	Large accelerated filer  ¨	Accelerated filer  x
	Non-accelerated filer  ¨	Smaller reporting company ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
	¨ Yes	x No

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.  $647,925,345.

There were 12,134,089 shares of Common Stock, $.10 par value, of the registrant outstanding as of March 10, 2009.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the definitive proxy statement relating to the 2009 Annual Meeting of Stockholders, which will be filed with the Commission not later than April 30, 2009, are incorporated by reference in Part III of this Form 10-K.

CLAYTON WILLIAMS ENERGY, INC

TABLE OF CONTENTS

		Page
Part I
Item 1.	Business	4
	General	4
	Company Profile	5
	Investment in Larclay JV	7
	Exploration and Development Activities	8
	Marketing Arrangements	10
	Natural Gas Services	10
	Competition and Markets	10
	Regulation	11
	Environmental Matters	12
	Title to Properties	14
	Operational Hazards and Insurance	15
	Executive Officers	15
	Employees	15
	Website Address	16
Item 1A.	Risk Factors	16
Item 1B.	Unresolved Staff Comments	24
Item 2.	Properties	24
	Reserves	25
	Exploration and Development Activities	26
	Productive Well Summary	27
	Volumes, Prices and Production Costs	27
	Development, Exploration and Acquisition Expenditures	27
	Acreage	28
	Contract Drilling	28
	Offices	28
Item 3.	Legal Proceedings	28
Item 4.	Submission of Matters to a Vote of Security Holders	28
Part II
Item 5.	Market for the Registrant’s Common Equity, Related Stockholder Matters and
	Issuer Repurchases of Equity Securities	29
	Price Range of Common Stock	29
	Dividend Policy	29
	Securities Authorized for Issuance under Equity Compensation Plans	29
Item 6.	Selected Financial Data	30
Item 7.	Management’s Discussion and Analysis of Financial Condition and
	Results of Operations	31
	Overview	31
	Key Factors to Consider	31
	Proved Oil and Gas Reserves	32

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TABLE OF CONTENTS (Continued)

		Page
Item 7.	Management’s Discussion and Analysis of Financial Condition and
	Results of Operations (continued)
	Supplemental Information	33
	Operating Results	35
	Liquidity and Capital Resources	39
	Known Trends and Uncertainties	43
	Application of Critical Accounting Policies and Estimates	44
	Recent Accounting Pronouncements	47
Item 7A.	Quantitative and Qualitative Disclosure About Market Risks	48
	Oil and Gas Prices	48
	Interest Rates	49
Item 8.	Financial Statements and Supplementary Data	49
Item 9.	Changes in and Disagreements with Accountants on Accounting and
	Financial Disclosure	49
Item 9A.	Controls and Procedures	49
	Disclosure Controls and Procedures	49
	Internal Control Over Financial Reporting	50
	Changes in Internal Control Over Financial Reporting	50
	Management’s Report on Internal Control Over Financial Reporting	50
Item 9B.	Other Information	52
Part III
Items 10-14.	Information Incorporated by Reference	53
Part IV
Item 15.	Exhibits and Financial Statement Schedules	54
	Financial Statements and Schedules	54
	Exhibits	54
Glossary of Terms		61
Signatures		64

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Forward-Looking Statements

 The information in this Form 10-K includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934.  All statements, other than statements of historical or current facts, that address activities, events, outcomes and other matters that we plan, expect, intend, assume, believe, budget, predict, forecast, project, estimate or anticipate (and other similar expressions) will, should or may occur in the future are forward-looking statements.  These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events.  When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this Form 10-K.

Forward-looking statements appear in a number of places and include statements with respect to, among other things:

• estimates of our oil and gas reserves;

• estimates of our future oil and gas production, including estimates of any increases or decreases in production;

• planned capital expenditures and the availability of capital resources to fund those expenditures;

• our outlook on oil and gas prices;

• our outlook on domestic and worldwide economic conditions;

• our access to capital and our anticipated liquidity;

• our future business strategy and other plans and objectives for future operations;

• the impact of political and regulatory developments;

• our assessment of counterparty risks and the ability of our counterparties to perform their future obligations;

• estimates of the impact of new accounting pronouncements on earnings in future periods; and

• our future financial condition or results of operations and our future revenues and expenses.

 We caution you that these forward-looking statements are subject to all of the risks and uncertainties, many of which are beyond our control, incident to the exploration for and development, production and marketing of oil and gas.  These risks include, but are not limited to:

• the possibility of unsuccessful exploration and development drilling activities;

• our ability to replace and sustain production;

• commodity price volatility;

• domestic and worldwide economic conditions;

• the availability of capital on economic terms to fund our capital expenditures and acquisitions;

• our level of indebtedness;

• the impact of the current economic recession on our business operations, financial condition and ability to raise capital;

• declines in the value of our oil and gas properties resulting in a decrease in our borrowing base under our credit facility and impairments;

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• the ability of financial counterparties to perform or fulfill their obligations under existing agreements;

• the uncertainty inherent in estimating proved oil and gas reserves and in projecting future rates of production and timing of development expenditures;

• drilling and other operating risks;

• hurricanes and other weather conditions;

• lack of availability of goods and services;

• regulatory and environmental risks associated with drilling and production activities;

• the adverse effects of changes in applicable tax, environmental and other regulatory legislation; and

• the other risks described in this Form 10-K.

 Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact way.  The accuracy of any reserve estimate depends on the quality of available data and the interpretation of that data by geological engineers.  In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously.  If significant, these revisions would change the schedule of any further production and development drilling.  Accordingly, reserve estimates are generally different from the quantities of oil and gas that are ultimately recovered.

 Should one or more of the risks or uncertainties described above or elsewhere in this Form 10-K occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.  We specifically disclaim all responsibility to publicly update or revise any information contained in a forward-looking statement or any forward-looking statement in its entirety.

 All forward-looking statements attributable to us are expressly qualified in their entirety by this cautionary statement.

 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 and New Mexico.  Unless the context otherwise requires, references to the “Company”, “CWEI”, “we”, “us” or “our” mean Clayton Williams Energy, Inc. and its consolidated subsidiaries.  On December 31, 2008, our estimated proved reserves were 228.6 Bcfe, of which 82% were proved developed.  We have a balanced portfolio of oil and natural gas reserves, with approximately 45% of our proved reserves at December 31, 2008 consisting of natural gas and approximately 55% consisting of oil and natural gas liquids.  During 2008, we added proved reserves of 36.2 Bcfe through extensions and discoveries, had downward revisions of 49.7 Bcfe and had sales of minerals-in-place of 11.3 Bcfe.  We also achieved average net production of 102.4 MMcfe per day in 2008, which implies a reserve life of approximately 6.1 years.  CWEI held interests in 6,704 gross (899.8 net) producing oil and gas wells and owned leasehold interests in approximately 1.2 million gross (662,000 net) undeveloped acres at December 31, 2008.

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 Clayton W. Williams, Jr. beneficially owns, either individually or through his affiliates, approximately 26% of the outstanding shares of our common stock.  In addition, The Williams Children’s Partnership, Ltd. (“WCPL”), a limited partnership of which Mr. Williams’ adult children are the limited partners, owns an additional 25% 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

Business Strategy

 Our goal is to grow oil and gas reserves and increase shareholder value utilizing a flexible, opportunity-driven business strategy.  We do not adhere to rigid guidelines for resource allocations, risk profiles, product mixes, financial measurements or other operating parameters.  Instead, we try to identify exploratory and developmental projects that offer us the best possible opportunities for growth in oil and gas reserves and allocate our available resources to those projects.  Our direction is heavily influenced by Mr. Williams based on over 50 years of experience and leadership in the oil and gas industry.  Our business strategy consists of an aggressive exploration program, complimented by developmental drilling and proved property acquisitions.  From year to year, our allocation of investment capital may vary between exploratory and developmental activities depending on our analysis of all available growth opportunities, but our long-term focus remains consistent with our goal of value enhancement for our shareholders.

Recent Developments

 During the second half of 2008, global economies began to experience a significant slowdown sparked by a near-collapse in worldwide financial markets.  This slowdown has continued to intensify into the first quarter of 2009 and is currently being viewed by many economists as the most severe recession in United States history, second only to the Great Depression.  The United States government has taken significant steps to support the financial markets and stimulate the economy in an effort to slow or reverse the downward spiral of economic indicators, but the success of these measures and the duration of the current recession cannot be predicted.

Reduced demand for energy caused by the current recession has resulted in a significant deterioration in oil and gas prices, which in turn has led to a significant reduction in drilling activity throughout the oil and gas industry.  While the prices we pay for field services are beginning to decline as a result of reduced demand for those services, the decline in these prices is generally lagging behind the declines in oil and gas prices.  As a result, we experienced reductions in operating margins during the last half of 2008 and reported negative price revisions to our proved reserves due to lower product prices and still relatively high capital and operating costs.  The effects of lower operating margins on our business are significant since they reduce our cash flow from operations and diminish the present value of our oil and gas reserves.  These factors have an adverse affect on our ability to access the capital resources we need to grow our reserve base.  Lower operating margins also offer us less incentive to assume the drilling risks that are inherent in our business.  In response to decreases in product prices and the resulting effect on our operating margins, we currently plan to reduce capital spending during fiscal 2009 to $56 million compared to $372.7 million in fiscal 2008.

We are monitoring the impact of the recession on our business, including the extent to which lower commodity prices could affect our financial condition and liquidity.  While we believe we are taking appropriate actions to preserve our short-term liquidity, a prolonged recession of this magnitude could negatively impact our long-term liquidity, financial position and results of operations.

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

Our exploration program consists 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.

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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 (1) the reservoir drive mechanism (water drive, depletion drive or a combination of both), (2) the permeability and porosity of the reservoir, and (3) the bottom hole pressure (in the case of gas reserves).

Due to the higher risk/higher potential 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.

For 2009, we plan to concentrate our exploration efforts in South Louisiana, the Permian Basin of West Texas and East Texas.  Approximately 70% of our planned expenditures for 2009 relate to exploratory prospects, as compared to approximately 28% of actual expenditures in 2008 and 51% of actual expenditures in 2007.  During 2008, we spent $105.5 million on exploratory prospects, including $40 million on seismic and leasing activities and $65.5 million on drilling activities.

Development Program

Complimentary to our higher risk/higher potential exploration program is our development program.  A developmental well is a well drilled within the proved area of an oil and gas reservoir to a horizon known to be productive.  We have an inventory of developmental projects available for drilling in the future, most of which are located in the Permian Basin and the Austin Chalk (Trend).  Some of the developmental wells in our inventory meet the engineering standards necessary to be classified as proved reserves.  Our estimates of oil and gas reserves at December 31, 2008 include 65.8 Bcfe of proved reserves attributable to developmental projects that will require us to spend approximately $104.2 million over time to develop.  In addition, many of the developmental wells in our inventory have not been included in our estimates of proved reserves at December 31, 2008 because they either do not meet the engineering standards necessary to be defined as proved reserves or they are not commercially viable under current economic conditions.

In most cases, our leasehold interests in developmental projects are held by the continuous production of other wells, meaning that our rights to drill these projects are not subject to near-term expiration.  This provides us with a high degree of flexibility in the timing of developing these reserves.  Consistent with our business strategy, we have chosen, in recent years, to limit our spending on developmental projects in order to maximize our exploration efforts.  Due in large part to the unfavorable operating margins we are experiencing, we currently plan to spend approximately $17.5 million, or 30% of our planned expenditures for 2009, on developmental projects, most of which are in oil-prone areas.

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Acquisition and Divestitures of Proved Properties

In addition to our exploration and development activities, 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, we did not acquire any proved properties in 2008, and we cannot give any assurance that we will be successful in our efforts to acquire proved properties in 2009.

From time to time, we sell certain of our proved properties when we believe it is more advantageous to dispose of the selected properties than to continue to hold them.  We consider many factors in deciding to sell properties, including the need for liquidity, the risks associated with continuing to own the properties, our expectations for future development on the property, the fairness of the price offered, and other factors related to the condition and location of the property.  In 2008, we sold certain producing properties in South Louisiana for approximately $89.2 million and recorded a gain on sale of property and equipment of approximately $33.1 million.

Investment in Larclay JV

 We own a 50% equity interest in a joint venture with Lariat Services, Inc. (“Lariat”) to construct, own and operate 12 drilling rigs.  We refer to this joint venture as Larclay JV.  In 2006, Larclay JV obtained a $75 million secured term loan facility from a lender to finance the construction and equipping of the drilling rigs.  The Larclay JV term loan is secured by substantially all of the assets of Larclay JV.  As additional credit support, we granted the lender a limited guaranty in the original amount of $19.5 million.  The maximum obligation under the guaranty reduces by 10% on April 1 of each year, beginning April 1, 2008.  At December 31, 2008, our maximum obligation under the guaranty was approximately $17.6 million.  Although we are not obligated under the Larclay JV term loan except to the extent of the guaranty, we are required to fully consolidate the accounts of Larclay JV under Financial Accounting Standards Board (“FASB”) Interpretation No. 46R “Consolidation of Variable Interest Entities – an Interpretation of ARB No. 51 (as amended)” (“FIN 46R”).  The principal balance outstanding on the Larclay JV term loan at December 31, 2008 was $39.4 million.

 Since inception of this joint venture, we have made advances structured as subordinated loans to Larclay JV totaling $12.1 million, $4.6 million to finance excess construction costs and $7.5 million to finance our 50% share of working capital assessments made by Larclay JV.  Lariat has also advanced Larclay JV $7.5 million for its 50% share of working capital assessments.  Loans to Larclay JV by Lariat and us are due on demand and bear interest, payable monthly, at the same rate as the term loan.  However, these loans are subject to a subordination agreement with the Larclay JV lender that imposes restrictions on payments of principal and interest on the loans.

 In connection with the formation of Larclay JV, we entered into a three-year drilling contract with Larclay JV assuring the availability of each drilling rig for use in the ordinary course of our exploration and development drilling program throughout the term of the drilling contract.  The drilling contract, which is pledged as collateral to secure the Larclay JV term loan, expires on the earlier of December 31, 2009 or the termination and liquidation of Larclay JV.  The provisions of the drilling contract provide that we contract for each drilling rig on a well-by-well basis at then current market rates.  If a drilling rig is not needed by us at any time during the term of the contract, Larclay JV may contract with other operators for the use of such drilling rig, subject to certain restrictions.  If a drilling rig is idle, the contract requires us to pay Larclay JV an idle rig rate ranging from $8,100 per day to $10,300 per day (plus crew labor expenses, if applicable), depending on the size of the drilling rig.  Our maximum potential obligation to pay idle rig rates over the remaining term of the drilling contract, excluding any crew labor expenses, totals approximately $29 million at December 31, 2008.

 During most of 2008, the Larclay JV drilling rigs were being utilized primarily by Lariat and us in our respective drilling programs.  However, the material deterioration in oil and gas prices, which began in the second half of 2008 and has continued into the first quarter of 2009, has resulted in a significant reduction in drilling activity throughout the oil and gas industry.  As of March 1, 2009, all but two of the Larclay JV drilling rigs were idle, and the other two drilling rigs are expected to be idle by the end of April 2009.  We do not expect utilization of the Larclay JV drilling rigs to improve for the remainder of 2009.  If the drilling rigs remain idle, we may be required under the drilling contract with Larclay JV to pay up to $29 million to Larclay JV in 2009.  These payments will provide Larclay JV with adequate cash flow to meet its debt service obligations under the term loan through 2009.  If the drilling rigs remain idle beyond 2009 and Larclay JV is not able to meet its debt service obligations under the term loan, we may be required under the guaranty to make debt service payments on the term loan on behalf of Larclay JV.  We are currently assessing our options with respect to our investment in and obligations to Larclay JV.  These options may include debt

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restructuring, asset sales, and termination and liquidation of Larclay JV.

 On March 13, 2009, we and Lariat entered into an agreement pursuant to which Lariat has agreed to assign all of its right, title and interest in and to the Larclay JV to us effective as of April 15, 2009 (the “Effective Date”), and we have agreed to assume all of the obligations and liabilities of Lariat under the Larclay JV from and after the Effective Date, including Lariat’s obligations as operator of the Larclay JV drilling rigs.  After giving effect to the assignment to us by Lariat, we will own 100% of the Larclay JV  (See "Item 9B - Other Information - Larclay JV").

Exploration and Development Activities

 Most of our exploration and development efforts in 2008 have been directed toward developmental drilling for oil.  With oil prices on the rise during the last half of 2007, we began a program to exploit our large inventory of lower risk, developmental drilling locations, primarily in the Permian Basin and the Austin Chalk (Trend) areas of our asset base.  To a lesser degree, we continued investing in our higher risk, higher impact exploration programs, particularly our deep Bossier plays in East Texas and North Louisiana.

 In 2008, we spent $372.7 million on exploration and development activities which was financed primarily by cash flow from operating activities and proceeds from the sales of certain South Louisiana properties, drilling rigs and other assets.  In response to the unfavorable operating margins we are experiencing as a result of the current recession, we presently plan to spend approximately $56 million on exploration and development activities during 2009, all of which is expected to be financed by cash flow from operations.  We may increase or decrease our planned activities, depending upon drilling results, operating margins, the availability of capital resources, and other factors affecting the economic viability of such activities.

Permian Basin

 The Permian Basin is a sedimentary basin in West Texas and Southeastern New Mexico known for its large oil and gas deposits from the Permian geologic period.  Although many fields in the Permian Basin have been heavily exploited in the past, higher product prices and improved technology (including deep horizontal drilling) encouraged high levels of current drilling and recompletion activities.  We gained a significant position in the Permian Basin in 2004 when we acquired Southwest Royalties, Inc.  This acquisition provided us with an inventory of potential drilling and recompletion activities.

 We spent $152.7 million in the Permian Basin during 2008 on exploration and development activities, of which $137.3 million was spent on drilling and completion activities and $15.4 million was spent on seismic and leasing activities.  We drilled 37 gross (31.5 net) operated wells in the Permian Basin and conducted various remedial operations on other wells in 2008.  We currently plan to spend $14.6 million on drilling and completion activities in the Permian Basin in 2009.

Austin Chalk (Trend)

 Prior to 1998, we concentrated our drilling activities in an oil-prone area we refer to as the Austin Chalk (Trend) in Robertson, Burleson, Brazos, Milam and Leon Counties, Texas.  Most of our wells in this area were drilled as horizontal wells, many with multiple laterals in different producing horizons, including the Austin Chalk, Buda and Georgetown formations.  The existing spacing between some of our wells in this area affords us the opportunity to access additional oil and gas reserves by drilling new wells between existing wells, a technique referred to as in-fill drilling.  These in-fill wells are considered lower risk as compared to exploratory wells and until recently when declining product prices reduced our operating margins, offered more attractive rates of return.

 We spent $52.6 million in the Austin Chalk (Trend) area during 2008 to drill in-fill wells and conduct other well stimulation activities.  Due to recent declines in product prices and lower operating margins on drilling, we plan to reduce capital spending in the Austin Chalk (Trend) in 2009 to $2.1 million.

North Louisiana

 In 2005, we began a drilling program in North Louisiana targeting the Cotton Valley/Gray and Bossier formations.  In this area, the Cotton Valley/Gray formations are encountered at depths ranging from 8,000 to 12,000 feet, and the Bossier formation is encountered at depths ranging from 11,000 to 15,500 feet.  

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 To date, we have drilled 18 wells on our Terryville prospect and have completed 16 as producers.  On our Ruston prospect, we have completed three wells as producers and are currently completing a fourth well.  We do not plan to drill any additional wells on either of these prospects during 2009.

 In 2007, adverse drilling conditions forced us to abandon the David Barton #1, an exploratory well in the Winnsboro prospect in Richland Parish, prior to reaching the pressured Bossier formation. In 2008, we drilled and abandoned a second exploratory well, the Claudia’s Education Trust #1, after the targeted Bossier formation was deemed non-productive.  We recorded a pre-tax charge of $20.2 million related to abandonment and impairments of this well in fourth quarter of 2008.  We do not plan to drill any additional wells on this prospect during 2009.

 We spent $82.5 million in North Louisiana during 2008 on exploration and development activities, of which $73.9 million was spent on drilling and completion activities and $8.6 million was spent on seismic and leasing activities.  We plan to reduce capital spending in North Louisiana in 2009 to $1.9 million.

South Louisiana

 In late 2007, we entered into an agreement with an industry partner, under which they have committed to drill six wells on certain of our prospects in South Louisiana during 2008. The industry partner will operate the wells, and we will have a 15% before casing point working interest and a 50% after casing point working interest in each well drilled.  To date, five wells have been drilled, two of which are producing, two were dry, and one awaiting the completion of pipeline facilities to begin production.  A sixth and final well is expected to be drilled in the first half of 2009.

 In 2008, we drilled and completed two development wells on our Fleur prospect in Plaquemines Parish, which are currently producing.  We do not plan to drill any wells on this prospect in 2009.

 We participated in the drilling of the State Lease 18669 #1, an exploratory well in Plaquemines Parish (West Lake Washington prospect) in 2008.  The well was tested during the fourth quarter of 2008 at a rate of 11 million cubic feet of gas per day and 739 barrels of oil per day.  After construction of a pipeline is complete, we expect to have the well on production by the middle of 2009.  We own a 50% non-operated working interest in this well.

 In April 2008, we sold all of our interests in 16 producing wells in South Louisiana to an industry partner for approximately $89.2 million, net of customary closing adjustments, and recorded a gain of $33.1 million in the second quarter of 2008 in connection with this transaction.

 We spent $39.7 million in South Louisiana during 2008 on exploration and development activities, of which $35.2 million was spent on drilling and completion activities and $4.5 million was spent on seismic and leasing activities.  We currently plan to spend $17.7 million in 2009, of which $15.4 million relates to drilling and completion activities and the remaining $2.3 million relates to seismic and leasing activities.

East Texas Bossier

 We currently have approximately 145,000 net acres under lease in East Texas targeting the prolific deep Bossier sands which are encountered at depths ranging from 14,000 to 22,000 feet in this area.  Of this acreage, approximately 70,000 net acres are held by production from existing Austin Chalk (Trend) wells.  Exploration for deep Bossier gas sands in this area is in its early stages and involves a high degree of risk.  The geological structures are complex, and limited drilling activity offers minimal subsurface control.  Deep Bossier wells are expensive to drill, with completed wells costing approximately $18 million each.  Although seismic data is helpful in identifying possible sand accumulations, the only way to determine if the deep Bossier sand will be commercially productive is to drill wells to the targeted structures.

 We are currently completing the Sunny Unit #1, a 17,300-foot exploratory well in Burleson County, Texas.  The well was successfully drilled to the deep Bossier formation, and completion is being attempted in the middle Bossier sands.  The Sunny Unit #1 was drilled on a 3D-defined prospect that is on trend to and 20 miles southwest of our Lee Fazzino #2 well which has produced 34.6 Bcf of natural gas since first production in 2001.  To date, we have incurred drilling costs of approximately $13.3 million on this well (100% working interest).

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 Prior to drilling the Sunny Unit #1, we drilled two other wells targeting the deep Bossier sands in East Texas:  the Big Bill Simpson #1, a 19,500 foot exploratory well in Leon County (70% working interest), and the Margarita #1, a 18,300-foot exploratory well in Robertson County (100% working interest).  The Big Bill Simpson #1 is currently producing at minimal rates, and the Margarita #1 is currently producing at a rate of approximately 400 Mcf of gas per day from an upper Bossier sand.  Based on geological and engineering evaluations, we recorded provisions for proved property impairments and abandonment and impairment charges totaling approximately $51.9 million during 2008 in connection with these wells and other acreage impairments in this area.

Utah

 In 2008, we participated in the drilling of the Ron Lamb 31A-4-1, a 12,670-foot exploratory well in which we own a 33% non-operated working interest. The well was drilled in the central Overthrust area in Sanpete County, Utah targeting the oil-prone Navajo sandstone formation. We temporarily abandoned this well in the first quarter of 2009.  We recorded a pre-tax charge of approximately $6.4 million for drilling and leasehold impairments related to the abandonment of this well in fourth quarter of 2008 and expect to record an additional $1.3 million in the first quarter of 2009. We plan to participate in the drilling of a third exploratory well in this area in 2009 to further evaluate our acreage position.

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, Mississippi and New Mexico. These natural gas service facilities consist of interests in approximately 94 miles of pipeline, three treating plants, one dehydration facility, three compressor stations, and four wellhead type treating and/or compression facilities.  Most of our operated gas gathering and treating 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.

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Regulation

Generally.  Our oil and gas exploration, production and related operations and activities are subject to extensive rules and regulations promulgated by federal, state and local governmental agencies. Failure to comply with such rules and regulations can result in substantial penalties. 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. Although the regulatory burden on the oil and gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect others in our industry with similar types, quantities and locations of production.

Regulations affecting production.  All of the states in which we operate generally require permits for drilling operations, require 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, the spacing, plugging and abandonment of such wells, restrictions on venting or flaring natural gas and requirements regarding the ratability of production.

These laws and regulations may limit the amount of oil and natural gas we can produce from our wells and may limit the number of wells or the locations at which we can drill. Moreover, many states impose a production or severance tax with respect to the production and sale of oil and natural gas within their jurisdiction. States do not generally regulate wellhead prices or engage in other, similar direct economic regulation of production, but there can be no assurance they will not do so in the future.

In the event we conduct operations on federal, state or Indian oil and natural gas leases, our operations may be required to comply with additional regulatory restrictions, including various nondiscrimination statutes, royalty and related valuation requirements, and on-site security regulations and other appropriate permits issued by the Bureau of Land Management (“BLM”) or other relevant federal or state agencies.

Regulations affecting sales.  The sales prices of oil, natural gas liquids and natural gas are not presently regulated, but rather are set by the market.  We cannot predict, however, whether new legislation to regulate the price of energy commodities might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on the operations of the underlying 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.  The price and terms of access to pipeline transportation are subject to extensive federal and state regulation.  The FERC is continually proposing and implementing new rules and regulations affecting interstate transportation.  These initiatives also may affect the intrastate transportation of natural gas under certain circumstances.  The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry. We do not believe that we will be affected by any such FERC action in a manner materially differently than other natural gas producers in our areas of operation.

The price we receive from the sale of oil and natural gas liquids is affected by the cost of transporting those products to market.  Interstate transportation rates for oil, natural gas liquids and other products are regulated by the FERC.  The FERC has established an indexing system for such transportation, which allows such pipelines to take an annual inflation-based rate increase.  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.

Market manipulation and market transparency regulations.  Under the Energy Policy Act of 2005 (“EP Act 2005”), FERC possesses regulatory oversight over natural gas markets, including the purchase, sale and transportation of natural gas by “any entity” in order to enforce the anti-market manipulation provisions in the EP Act 2005. The Commodity Futures Trading Commission (“CFTC”) also holds authority to monitor certain segments of the physical and futures energy commodities market pursuant to the Commodity Exchange Act.  With regard to our physical purchases and sales of natural gas, natural gas liquids and crude oil, our gathering of these energy commodities, and any related hedging activities that we undertake, we are required to observe these anti-market manipulation laws and related regulations enforced by FERC and/or the CFTC.  These agencies hold substantial enforcement authority, including the ability to assess civil penalties of up to $1 million per day per violation, to order disgorgement of profits

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and to recommend criminal penalties.  Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third party damage claims by, among others, sellers, royalty owners and taxing authorities.

FERC has issued certain market transparency rules pursuant to its EP Act 2005 authority, which may affect some or all of our operations.  FERC issued a final rule in 2007, as amended by subsequent orders on rehearing (“Order 704”), which requires wholesale buyers and sellers of more than 2.2 million MMBtu of physical natural gas in the previous calendar year, including natural gas producers, gatherers, processors, and marketers, to report, on May 1 of each year, beginning in 2009, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to, or may contribute to the formation of price indices, as explained in the order. It is the responsibility of the reporting entity to determine which transactions should be reported based on the guidance of Order 704.  In addition, on November 20, 2008, FERC issued a final rule pursuant to its EP Act 2005 authority regarding daily scheduled flows and capacity posting requirements (“Order 720”).  Under Order 720, certain non-interstate pipelines delivering, on an annual basis, more than an average of 50 million MMBtu of gas over the previous three (3) calendar years, are required to post daily certain information regarding the pipeline’s capacity and scheduled flows for each receipt and delivery point that has a design capacity equal to or greater than 15,000 MMBtu per day. Requests for clarification and rehearing of Order 720 have been filed at FERC, and a decision on those requests is pending.  Over the previous three calendar years, we have delivered, on average, less than 50 million MMBtu of gas, and therefore we believe that we are currently exempt from Order 720.

Gathering regulations.  Section 1(b) of the federal Natural Gas Act ("NGA") exempts natural gas gathering facilities from the jurisdiction of the FERC under the NGA.  We own certain natural gas pipelines that we believe meet the traditional tests that the FERC has used to establish a pipeline’s status as a gatherer not subject to FERC jurisdiction.  The distinction between FERC-regulated transmission facilities and federally unregulated gathering facilities is, however, the subject of substantial, on-going litigation, so the classification and regulation of our gathering lines may be subject to change based on future determinations by the FERC, the courts or the U.S. Congress.

State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and in some instances complaint-based rate regulation.  Our gathering operations are also subject to state ratable take and common purchaser statutes, designed to prohibit discrimination in favor of one producer over another or one source of supply over another.  The regulations under these statutes can have the effect of imposing some restrictions on our ability as an owner of gathering facilities to decide with whom we contract to gather natural gas.  In addition, our natural gas gathering operations could be adversely affected should they be subject to more stringent application of state or federal regulation of rates and services, though we do not believe that we would be affected by any such action in a manner materially differently than other companies in our areas of operation.

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 commencing certain activities or in connection with our operations; restrict or prohibit the types, quantities and concentration of substances that we can release into the environment; restrict or prohibit 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 our operations and may prevent or delay the commencement or continuation of a given project and thus generally could have an adverse effect upon our capital expenditures, earnings, or competitive position.  Violation of these laws and regulations could result in significant fines or penalties.  We have experienced accidental spills, leaks and other discharges of contaminants at some of our properties, as have other similarly situated oil and gas companies, and some of the properties that we have acquired, operated or sold, or in which we may hold an interest but not operational control, may have past or ongoing contamination for which we may be held responsible.  Some of our operations are located in environmentally sensitive environments, such as coastal waters, wetlands and other protected areas.  Some of our properties are located in areas particularly susceptible to hurricanes and other destructive storms, which may damage facilities and cause the release of pollutants. Our environmental insurance coverage may not fully insure all of these risks. Although the costs of remedying such conditions may be significant, we do not believe these costs would have a material adverse impact on our financial condition and operations.

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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 2009.  We do not believe that we will be required to incur any material capital expenditures to comply with existing environmental requirements.  Nevertheless, changes in existing environmental laws and regulations or in the interpretations thereof could have a significant impact on our operations, as well as the oil and gas industry in general.  For instance, any changes in environmental laws and regulations that result in more stringent and costly waste handling, storage, transport, disposal or clean-up requirements could have an adverse impact on our operations.

Hazardous Substances.  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 are not aware of any liabilities for which we may be held responsible that would materially and adversely affect us.

Waste Handling.  The Resource Conservation and Recovery Act (“RCRA”), and analogous state laws, impose detailed requirements for the handling, storage, treatment and disposal of hazardous and solid wastes.  RCRA specifically excludes drilling fluids, produced waters, and other wastes associated with the exploration, development, or production of crude oil, natural gas or geothermal energy from regulation as hazardous wastes.  However, these wastes may be regulated by the U.S. Environmental Protection Agency (“EPA”) or state agencies as solid wastes.  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 believe that our costs in this regard are materially more burdensome than those for similarly situated companies.

Air Emissions.  The Federal Clean Air Act and comparable state laws and regulations impose restrictions on emissions of air pollutants from various industrial sources, including compressor stations and natural gas processing facilities, and also impose various monitoring and reporting requirements.  Such laws and regulations may require that we obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in the increase of existing air emissions, obtain and strictly comply with air permits containing various emissions and operational limits, or utilize specific emission control technologies to limit emissions.  Our failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations, and potentially criminal enforcement actions.  Capital expenditures for air pollution equipment may be required in connection with maintaining or obtaining operating permits and approvals relating to air emissions at facilities owned or operated by us. We do not believe that our operations will be materially adversely affected by any such requirements.

Water Discharges.  The Federal Water Pollution Control Act (“Clean Water Act”) and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States.  The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by EPA or an analogous state agency.  Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations.  In addition, the United States Oil Pollution Act of 1990 (“OPA”) and similar legislation enacted in Texas, Louisiana and other coastal states impose oil spill prevention and control requirements and significantly expand liability for damages resulting from oil spills.  OPA imposes strict and, with limited exceptions, joint and several liabilities upon each responsible party for oil spill response and removal costs and a variety of public and private damages.

Global Warming and Climate Change.  Recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases” and including carbon dioxide and methane, may be contributing to warming of the Earth’s atmosphere.  In response to such studies, President Obama has proposed, and the U.S. Congress is currently considering, legislation to reduce emissions of greenhouse gases by as much as 80% from

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current levels by 2050.  In addition, more than one-third of the states, either individually or through multi-state initiatives, already have begun implementing legal measures to reduce emissions of greenhouse gases.  Also, the U.S. Supreme Court’s holding in its 2007 decision, Massachusetts, et al. v. EPA, that carbon dioxide may be regulated as an “air pollutant” under the federal Clean Air Act could result in future regulation of greenhouse gas emissions from stationary sources, even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases.  In July 2008, the EPA released an “Advance Notice of Proposed Rulemaking” regarding possible future regulation of greenhouse gas emissions under the Clean Air Act.  Although the notice did not propose any specific, new regulatory requirements for greenhouse gases, it indicates that federal regulation of greenhouse gas emissions could occur in the near future and, since the inauguration of President Obama, the EPA has begun taking steps to regulate greenhouse gas emissions pursuant to the Clean Air Act.

Depending on the legislation or regulatory program that may be adopted to address emissions of greenhouse gases, we could be required to reduce greenhouse gas emissions resulting from our operations or we could be required to purchase and surrender allowances for greenhouse gas emissions associated with our operations or the oil and gas we produce.  Although we would not be impacted to a greater degree than other similarly situated producers of oil and gas, a stringent greenhouse gas control program could have an adverse effect on our cost of doing business and could reduce demand for the oil and gas we produce.

Pipeline Safety.  Some of our pipelines are subject to regulation by the U.S. Department of Transportation (“DOT”) under the Pipeline Safety Improvement Act of 2002, which was reauthorized and amended by the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006. The DOT, through the Pipeline and Hazardous Materials Safety Administration (“PHMSA”), has established a series of rules that require pipeline operators to develop and implement integrity management programs for gas, natural gas liquids (“NGLs”), oil and condensate transmission pipelines that, in the event of a failure, could affect “high consequence areas.” “High consequence areas” are currently defined to include areas with specified population densities, buildings containing populations with limited mobility, areas where people may gather along the route of a pipeline (such as athletic fields or campgrounds), environmentally sensitive areas, and commercially navigable waterways. Under the DOT’s regulations, integrity management programs are required to include baseline assessments to identify potential threats to each pipeline segment, implementation of mitigation measures to reduce the risk of pipeline failure, periodic reassessments, reporting and recordkeeping.

OSHA and Other Laws and Regulations.  We are subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes. These laws and the implementing regulations strictly govern the protection of the health and safety of employees. The OSHA hazard communication standard, EPA community right-to-know regulations under the Title III of CERCLA and similar state statutes require that we organize and/or disclose information about hazardous materials used or produced in our operations. We believe that we are in substantial compliance with these applicable requirements and with other OSHA and comparable requirements.

Claims are sometimes made or threatened against companies engaged in oil and gas exploration, production and related activities by owners of surface estates, adjoining properties or others alleging damages resulting from environmental contamination and other incidents of operations. We have been named as a defendant in a number of such lawsuits. While some jurisdictions in which we operate limit damages in such cases to the value of land that has been impaired, in other jurisdictions in which we operate, courts have allowed damage claims in excess of land value, including claims for the cost of remediation of contaminated properties. However, we do not believe that resolution of these claims 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.  These title investigations and title opinions, while consistent with industry standards, may not reveal existing or potential title defects, encumbrances or adverse claims as we are subject from time to time to claims or disputes regarding title to properties.  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 revolving credit facility and may be mortgaged under any future credit facilities entered into by us.

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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 13, 2009 of the name, age and position with the Company of each person who is an executive officer of the Company:

CLAYTON W. WILLIAMS, JR., age 77, 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 a director of certain entities which are controlled directly or indirectly by Mr. Williams.  Mr. Williams beneficially owns, either individually or through his affiliates, approximately 26% of the outstanding shares of our common stock.

L. PAUL LATHAM, age 57, is Executive Vice President, Chief Operating Officer and a director of the Company, having served in such capacities since September 1991.  Mr. Latham is the sole general partner of The Williams Children’s Partnership, Ltd. (“WCPL”), a limited partnership in which the adult children of Clayton W. Williams, Jr. are the limited partners.  WCPL holds approximately 25% of the outstanding shares of our common stock.  As the sole general partner, Mr. Latham has the power to vote or direct the voting of the shares of our common stock held by WCPL.  Mr. Latham also serves as an officer and director of certain entities which are controlled directly or indirectly by Mr. Williams.

MEL G. RIGGS, age 54, 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.

PATRICK C. REESBY, age 56, is Vice President – New Ventures of the Company, having served in such capacity since 1993.

ROBERT C. LYON, age 72, is Vice President – Gas Gathering and Marketing of the Company, having served in such capacity since 1993.

MICHAEL L. POLLARD, age 59, 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 52, is Vice President and General Counsel of the Company, having served in such capacity since 1993.

GREGORY S. WELBORN, age 35, is Vice President – Land of the Company, having served in such capacity since 2006.  Prior to that, Mr. Welborn was self-employed.

Employees

At December 31, 2008, we had 202 full-time employees, none of whom is subject to a collective bargaining agreement.  In our opinion, our relations with employees are good.

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Website Address

The Company maintains an internet website at www.claytonwilliams.com.  The Company makes available, free of charge, on its website, its annual reports 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.  The information contained in or incorporated in its website is not part of this report.

Item 1A - -              Risk Factors

There are many factors that affect our business, some of which are beyond our control.  Our business, financial condition and results of operations could be materially adversely affected by any of these risks.  The risks described below are not the only ones facing our company.  Additional risks not presently known to us or that we currently deem immaterial individually or in the aggregate may also impair our business operations.

Our exploration activities subject us to greater risks than development activities.

As a general rule, our oil and gas exploration activities pose a higher economic risk to us than our development activities. Exploration activities involve the drilling of wells in areas where there is little or no known production. Development activities relate to increasing oil or natural gas production from an area that is known 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.

For 2009, approximately 70% of our planned exploration and development activities relate to exploratory prospects, as compared to 28% in 2008.  To the extent we engage in 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 charged to expense $80.1 million in 2008 for abandonments and impairments, most of which was related to unsuccessful exploratory drilling activities in North Louisiana, the East Texas Bossier area and Utah.  We cannot assure you that any of our future exploration efforts will be successful. If these activities are unsuccessful, it will have a significant adverse affect on our results of operations, cash flow and capital resources.

If we do not replace reserves we produce, our financial results will suffer.

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 implied life of our proved reserves at December 31, 2008 is approximately 6.1 years, based on 2008 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 engaged to a large extent in exploration activities, our ability to replace produced reserves is subject to a higher level of risk and is less predictable than it might be if we limited our efforts to developmental drilling activities.  Also, we can give no assurance that we will be able to replace our reserves at a favorable finding cost.

Oil and gas prices are volatile. Declines in commodity prices have adversely affected, and in the future may adversely affect, our financial condition, results of operations, cash flows, access to the capital markets, and ability to grow.

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

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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 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.

Our liquidity, including the availability of capital resources, is uncertain.

Our internal cash flow forecasts indicate that the amount of funds available to us under our 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 2009.  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.

Our liquidity will suffer if our exploration activities are not successful.  For 2009, approximately 70% of our planned capital expenditures relate to exploratory prospects, where we have a greater risk of drilling dry holes or not finding oil and natural gas that can be produced economically.  Certain of our exploratory prospects target deep formations.  Wells on deep prospects generally are very expensive to drill and involve a very high degree of risk.  If these exploratory wells are unsuccessful, our cash flow from operations and our liquidity will be adversely affected.

Adverse changes in reserve estimates or commodity prices could reduce the borrowing base under our revolving credit facility.  The lenders under our revolving credit facility establish the borrowing base under such facility at least twice annually based upon the estimated value of our oil and gas properties using reserve reports and pricing models determined by the lenders.  Any adverse changes in estimated quantities of reserves, the pricing models being used, or the risk factors being applied, since the date of the last borrowing base determination, could lower the borrowing base under our revolving credit facility.

Adverse changes in the borrowing base under our revolving credit facility may cause outstanding debt to equal or exceed the borrowing base.  Our revolving credit facility limits the amounts we can borrow to a borrowing base amount.  The borrowing base is subject to review semi-annually; however, the lenders reserve the right to request additional redeterminations of the borrowing base at any other time during the year.  If the borrowing base under our revolving credit facility is reduced due to adverse changes in reserve estimates or commodity prices or otherwise, the outstanding debt under our revolving credit facility may equal or exceed our 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 our revolving credit facility, we may be unable to meet our obligations as they mature.

Failure to comply with covenants under our debt agreements could adversely impact our financial condition and results of operations.  Our revolving credit facility, the Indenture governing our 7¾% Senior Notes due 2013 and our other debt agreements require us to comply with certain financial covenants and ratios.  For example, our revolving credit facility requires us to, among other things, maintain positive working capital in accordance with computational guidelines contained in the related loan agreement and to maintain a ratio of indebtedness to cash flow of no more than 3 to 1.  Although we are in compliance with these covenants at December 31, 2008, adverse changes in our leverage or liquidity could cause us to fail to comply with one or more of these covenants.  If we fail to meet any of these loan covenants, the lenders under the revolving credit facility could accelerate the indebtedness and seek to foreclose on the pledged assets.  Additionally, our failure to comply with any of the restrictions or covenants in our revolving credit facility, the Indenture governing our 7¾% Senior Notes due 2013 and our other debt agreements could result in a default under those facilities, which could cause all of our existing indebtedness to be immediately due and payable.

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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, 2008 reserve estimates, we project that a $1 drop in oil price and a $.50 drop in gas price would reduce our gross revenues in 2009 by approximately $3.1 million and $8.6 million, respectively.

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 our revolving credit facility.  Until a well is on production, the lenders under our revolving credit facility may assign only a minimal borrowing base value to the well, and cash flows from the well are not available to fund our operating expenses.  Delays in bringing wells on production may reduce the borrowing base significantly, depending on the amounts borrowed and the length of the delays.

Commitments under long-term drilling contracts, including our drilling contract with Larclay JV, may reduce our cash flow from operating activities.  From time to time, we enter into long-term drilling contracts to ensure the availability of the drilling rigs we need to conduct our drilling program.  If we contract for a rig and do not need the rig due to changes in our drilling program, we will be required to pay a daily rate specified in the contract while the rig is idle during the contract term.  Currently, our only commitments under long-term drilling contracts are to Larclay JV.  As of March 1, 2009, all but two of the Larclay JV drilling rigs were idle, and those two are expected to be idle by the end of April 2009.  If these drilling rigs remain substantially idle during 2009, we may be required under the drilling contract with Larclay JV to pay up to $29 million in idle rig fees in 2009.  Long-term drilling commitments may also influence us to drill a well in 2009 that we may otherwise choose to defer until a later period in order to avoid paying for an idle rig.  Our cash flow from operations may be less than expected and/or our capital expenditures may be more than expected if commitments on long-term drilling contracts result in the payment of idle rig costs and/or an increase in drilling costs related to wells not currently included in our drilling schedule.

We may not be able to obtain funding, obtain funding on acceptable terms or obtain funding under our revolving credit facility because of the deterioration of the credit and capital markets and adverse changes in commodity prices and reserve amounts.  This may hinder or prevent us from meeting our future capital needs.

Global financial markets and economic conditions have been, and continue to be, disrupted and volatile. The debt and equity capital markets have been exceedingly distressed. These issues, along with significant write-offs in the financial services sector, the re-pricing of credit risk and the current weak economic conditions, have made, and will likely continue to make, it difficult to obtain funding.

In particular, the cost of raising money in the debt and equity capital markets has increased substantially while the availability of funds from those markets generally has diminished significantly. Also, as a result of concerns about the stability of financial markets generally and the solvency of counterparties specifically, the cost of obtaining funds from the credit markets generally has increased as many lenders and institutional investors have increased interest rates, enacted tighter lending standards, refused to refinance existing debt at maturity at all or on terms similar to our current debt and reduced and, in some cases, ceased to provide funding to borrowers.

We may not be able to obtain adequate funding under our revolving credit facility if our lending counterparties are unwilling or unable to meet their funding obligations or if our borrowing base under our revolving credit facility is reduced as a result of lower oil and gas prices, higher operating costs, declines in reserves, lending requirements or regulations or for any other reason.

Additionally, the Indenture governing our 7¾% Senior Notes due 2013 contains covenants restricting our ability to borrow money under our revolving credit facility.  One such covenant restricts our ability to borrow additional funds under our revolving credit facility if the outstanding balance on the facility is greater than $150 million and exceeds 30% of our Adjusted Consolidated Net Tangible Assets (“ACNTA”) as defined in the Indenture.  Adverse changes in commodity prices or reserve estimates could reduce our ACNTA, thereby limiting our ability to borrow under our revolving credit facility, even if funds would otherwise be available under the facility.

Due to these factors, we cannot be certain that funding will be available if needed and to the extent required, on acceptable terms. If funding is not available when needed, or is available only on unfavorable terms, we may be unable to meet our obligations as they come due or be required to post collateral to support our obligations, or we may be unable to implement our business plan, enhance our existing business, complete acquisitions or otherwise take

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advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our production, revenues and results of operations.

We have substantial indebtedness and may incur more debt in the future. Our leverage may materially affect our operations and financial condition.

As of December 31, 2008, the principal amount of our outstanding consolidated debt was approximately $366 million, which included approximately $94.1 million outstanding under our revolving credit facility.  Our level of indebtedness has several important effects on our business and operations, among other things, it may:

·   require us to use a significant portion of our cash flow to pay principal and interest on the debt, which will reduce the amount available to fund working capital, capital expenditures, and other general corporate purposes;

·   adversely affect the credit ratings assigned by third party rating agencies, which have in the past and may in the future, downgrade their ratings of our debt and other obligations due to changes in our debt level or our financial condition;

·   limit our access to the capital markets;

·   increase our borrowing costs, and impact the terms, conditions, and restrictions contained in our debt agreements, including the addition of more restrictive covenants;

·   limit our flexibility in planning for and reacting to changes in our business as covenants and restrictions contained in our existing and possible future debt arrangements may require that we meet certain financial tests and place restrictions on the incurrence of additional indebtedness;

·   place us at a disadvantage compared to similar companies in our industry that have less debt; and

·   make us more vulnerable to economic downturns and adverse developments in our business.

A higher level of debt will increase the risk that we may default on our financial obligations.  Our ability to meet our debt obligations and other expenses will depend on our future performance.  Our future performance will be affected by oil and gas prices, financial, business, domestic and worldwide economic conditions, governmental regulations and environmental regulations, and other factors, many of which we are unable to control.  If our cash flow is not sufficient to service our debt, we may be required to refinance the debt, sell assets, or sell shares of our stock on terms that we do not find attractive, if it can be done at all.

Our hedging transactions could result in financial losses or could reduce our income.  To the extent we have hedged a significant portion of our expected production and actual production is lower than expected or the costs of goods and services increase, our profitability would be adversely affected.

To achieve more predictable cash flow and to reduce our exposure to adverse fluctuations in the prices of oil and gas, we currently and may in the future enter into hedging transactions for a significant portion of our expected oil and gas production that could result in both realized and unrealized hedging losses. As of March 13, 2009, we had hedged approximately 45% of our estimated 2009 production through commodity swap agreements.

The extent of our commodity price exposure is related largely to the effectiveness and scope of our derivative activities.  For example, the derivative instruments we utilize are primarily based on NYMEX futures prices, which may differ significantly from the actual crude oil and gas prices we realize in our operations.  Furthermore, we have adopted a policy that requires, and our credit facility also mandates, that we enter into derivative transactions related to only a portion of our expected production volumes and, as a result, we will continue to have direct commodity price exposure on the portion of our production volumes not covered by these derivative transactions.

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Our actual future production may be significantly higher or lower than we estimate at the time we enter into derivative transactions for such period. If the actual amount is higher than we estimate, we will have greater commodity price exposure than we intended. If the actual amount is lower than the nominal amount that is subject to our derivative financial instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flow from our sale or purchase of the underlying physical commodity, resulting in a substantial diminution in our profitability and liquidity. As a result of these factors, our derivative activities may not be as effective as we intend in reducing the volatility of our cash flows, and in certain circumstances may actually increase the volatility of our cash flows.

In addition, our hedging transactions are subject to the following risks:

·   we may be limited in receiving the full benefit of increases in oil and gas prices as a result of these transactions;

·   a counterparty may not perform its obligation under the applicable derivative instrument or seek bankruptcy protection;

·   there may be a change in the expected differential between the underlying commodity price in the derivative instrument and the actual price received; and

·   the steps we take to monitor our derivative financial instruments may not detect and prevent violations of our risk management policies and procedures, particularly if deception or other intentional misconduct is involved.

Our proved reserves are estimates and depend on many assumptions. Any material inaccuracies in these assumptions could cause the quantity and value of our oil and gas reserves, and our revenue, profitability, and cash flow, to be materially different from our 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.  Downward adjustments to our estimated proved reserves could require us to write down the carrying value of our oil and gas properties, which would reduce our earnings and our stockholders' equity.

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 reserve reports prepared by independent engineers.  From time to time, estimates of our reserves are also made by the lenders under our revolving credit facility in establishing the borrowing base under such credit facility and by our engineers for use in developing business plans and making various decisions.  Such estimates may vary significantly from those of the independent engineers and have a material effect upon our business decisions and available capital resources.

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Price declines have resulted in and may in the future result in write-downs of our asset carrying values.

Commodity prices have a significant impact on the present value of our proved reserves.  Recent declines in oil and gas prices have resulted in material downward revisions in the estimated present value of our proved reserves.  Accounting rules require us to write down, as a non-cash charge to earnings, the carrying value of our oil and gas properties for impairments.  We are required to perform impairment tests on our assets periodically and whenever events or changes in circumstances warrant a review of our assets.  To the extent such tests indicate a reduction of the estimated useful life or estimated future cash flows of our assets, the carrying value may not be recoverable and therefore requires a write-down.  We recorded impairments of property and equipment totaling $12.9 million in 2008 and we may incur impairment charges in the future, which could have a material adverse effect on our results of operations in the period incurred.

Acquisitions are subject to the risks and uncertainties of evaluating reserves and potential liabilities and may be disruptive and difficult to integrate into our business.

Our on-going business strategy includes growing our reserves and drilling inventory through acquisitions.  Acquired properties can be subject to significant unknown liabilities. Prior to completing an acquisition, it is generally not feasible to conduct a detailed review of each individual property to be acquired in an acquisition.  Even a detailed review or inspection of each property may not reveal all existing or potential liabilities associated with owning or operating the property. Moreover, some potential liabilities, such as environmental liabilities related to groundwater contamination, may not be discovered even when a review or inspection is performed.

Our initial reserve estimates for acquired properties may be inaccurate. Downward adjustments to our estimated proved reserves, including reserves added through acquisitions, could require us to write down the carrying value of our oil and gas properties, which would reduce our earnings and our stockholders' equity.

Our failure to integrate acquired businesses successfully into our existing business could result in our incurring unanticipated expenses and losses.  In addition, we may have to assume cleanup or reclamation obligations or other unanticipated liabilities in connection with these acquisitions.  The scope and cost of these obligations may ultimately be materially greater than estimated at the time of the acquisition.

The process of integrating acquired operations into our existing operations may result in unforeseen operating difficulties and may require significant management attention and financial resources that would otherwise be available for the ongoing development or expansion of existing operations.

Drilling oil and natural gas wells is a high-risk activity and subjects us to a variety of factors that we cannot control.

Drilling oil and natural gas wells, including development wells, involves numerous risks, including the risk that we may not encounter commercially productive oil or natural gas reservoirs. We may not recover all or any portion of our investment in new wells. 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. In addition, we often are uncertain as to the future cost or timing of drilling, completing and operating wells. Further, our drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including:

·   unexpected drilling conditions;

·   title problems;

·   pressure or irregularities in formations;

·   equipment failures or accidents;

·   adverse weather conditions;

·   compliance with environmental and other governmental requirements, which may increase our costs or restrict our activities; and

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·   costs of, or shortages or delays in the availability of, drilling rigs, tubular materials and equipment and services.

We may not be insured against all of the operating hazards to which our business is exposed.

Our operations are subject to the usual hazards incident to the drilling and production of oil and gas, such as windstorms, blowouts, cratering, explosions, uncontrollable flows of oil, gas or well fluids, fires, severe weather 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, clean-up responsibilities, regulatory investigation and penalties, and suspension of operation, operations which could result in substantial loss. We maintain insurance against some, but not all, of the risks described above. Such insurance may not be adequate to cover losses or liabilities. Also, we cannot assure you of the continued availability of insurance at premium levels that justify its purchase.

Our business depends on oil and natural gas transportation facilities, most of which are owned by others.

The marketability of our oil and natural gas production depends in large part on the availability, proximity and capacity of pipeline systems owned by third parties. The unavailability of or lack of available capacity on these systems and facilities could result in the shut-in of producing wells or the delay or discontinuance of drilling plans for properties. Although we have some contractual control over the transportation of our product, material changes in these business relationships could materially affect our operations. Federal and state regulation of oil and natural gas production and transportation, tax and energy policies, changes in supply and demand, pipeline pressures, damage to or destruction of pipelines, maintenance and repair and general economic conditions could adversely affect our ability to produce, gather and transport oil and natural gas.

Future shortages of available drilling rigs, equipment and personnel may delay or restrict our operations.

The oil and natural gas industry is cyclical and, from time to time, there is a shortage of drilling rigs, equipment, supplies or personnel. During these periods, the costs and delivery times of drilling rigs, equipment and supplies are substantially greater. In addition, demand for, and wage rates of, qualified drilling rig crews rise with increases in the number of active rigs in service. Shortages of drilling rigs, equipment, supplies or personnel may increase drilling costs or delay or restrict our exploration and development operations, which in turn could impair our financial condition and results of operations.

Our industry is highly competitive.

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 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.

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Our success depends on key members of our management and our ability to attract and retain experienced technical and other professional personnel.

Our success is highly dependent on our senior management personnel, none of whom are currently subject to an employment contract. The loss of one or more of these individuals could have a material adverse effect on our business. Furthermore, competition for experienced technical and other professional personnel is intense. If we cannot retain our current personnel or attract additional experienced personnel, our ability to compete could be adversely affected.

We are primarily controlled by Clayton W. Williams, Jr. and his family limited partnership.

Clayton W. Williams, Jr. beneficially owns, either individually or through his affiliates, approximately 26% 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 over matters voted on by our shareholders, including the election of our Board members, and in all other facets of our business, including both our business strategy and daily operations.

WCPL, a limited partnership in which Mr. Williams’ adult children are the limited partners, owns an additional 25% of the outstanding shares of our common stock.  L. Paul Latham, our Executive Vice President and Chief Operating Officer, is the sole general partner of WCPL and has the power to vote or direct the voting of the shares held by WCPL.  In voting these shares, Mr. Latham will not be acting in his capacity as an officer and director of the Company and will consider the interests of WCPL and Mr. Williams’ children.  They may have interests that differ from the interests of our other shareholders.

The retirement, incapacity or death of Mr. Williams, or any change in the power to vote shares beneficially owned by Mr. Williams or held by WCPL, could result in negative market or industry perception and could have a material adverse effect on our business.

By extending credit to our customers, we are exposed to potential economic loss.

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.

Compliance with laws and regulations governing our activities could be costly and could negatively impact production.

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 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.

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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.

Under the EP Act 2005, FERC has civil penalty authority under the NGA to impose penalties for current violations of up to $1 million per day for each violation and disgorgement of profits associated with any violation. While our operations have not been regulated by FERC under the NGA, FERC has adopted regulations that may subject certain of our otherwise non-FERC jurisdictional entities to FERC annual reporting and daily scheduled flow and capacity posting requirements, as described more fully in Item 1 above. Additional rules and legislation pertaining to those and other matters may be considered or adopted by FERC from time to time. Failure to comply with those regulations in the future could subject us to civil penalty liability.

Our oil and gas exploration and production, and related activities are subject to extensive environmental regulations, and to laws that can give rise to substantial liabilities from environmental contamination.

Our operations are subject to extensive federal, state and local environmental laws and regulations, which impose limitations on the discharge of pollutants into the environment, establish standards for the management, treatment, storage, transportation and disposal of hazardous materials and of solid and hazardous wastes, and impose obligations to investigate and remediate contamination in certain circumstances.  Liabilities to investigate or remediate contamination, as well as other liabilities concerning hazardous materials or contamination such as claims for personal injury or property damage, may arise at many locations, including properties in which we have an ownership interest but no operational control, properties we formerly owned or operated and sites where our wastes have been treated or disposed of, as well as at properties that we currently own or operate.  Such liabilities may arise even where the contamination does not result from any noncompliance with applicable environmental laws.  Under a number of environmental laws, such liabilities may also be joint and several, meaning that we could be held responsible for more than our share of the liability involved, or even the entire share.  Environmental requirements generally have become more stringent in recent years, and compliance with those requirements more expensive.

We have incurred expenses in connection with environmental compliance, and we anticipate that we will continue to do so in the future.  Failure to comply with extensive applicable environmental laws and regulations could result in significant civil or criminal penalties and remediation costs.  Some of our properties, including properties in which we have an ownership interest but no operating control, may be affected by environmental contamination that may require investigation or remediation.  Some of our operations are located in environmentally sensitive environments, such as coastal waters, wetlands and other protected areas.  Some of our operations are in areas particularly susceptible to damage by hurricanes or other destructive storms, which could result in damage to facilities and discharge of pollutants.  In addition, claims are sometimes made or threatened against companies engaged in oil and gas exploration and production by owners of surface estates, adjoining properties or others alleging damage resulting from environmental contamination and other incidents of operation, and such claims have been asserted against us as well as companies we have acquired.  Compliance with, and liabilities for remediation under, these laws and regulations, and liabilities concerning contamination or hazardous materials, may adversely affect our business, financial condition and results of operations.

Item 1B - -              Unresolved Staff Comments

Not applicable.

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, 2008, we had interests in 6,704 gross (899.8 net) oil and gas wells and owned leasehold interests in approximately 1.2 million gross (662,000 net) undeveloped acres.

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Reserves

The following table sets forth certain information as of December 31, 2008 with respect to our estimated proved oil and gas reserves pursuant to SEC guidelines, standardized measure of discounted future net cash flows and present value of estimated proved reserves.

	Proved Developed				Proved		Total
	Producing		Non-producing		Undeveloped		Proved
			(Dollars in thousands)
Gas (MMcf)		74,058		13,282		16,589		103,929
Oil and natural gas liquids (MBbls)		14,792		2,023		3,961		20,776
Total (MMcfe)		162,810		25,420		40,355		228,585
Standardized measure of discounted
future net cash flows							$	405,166
Present value of proved reserves(a)							$	511,661

(a) We believe that the present value of proved reserves (a non-GAAP measure) is a useful supplemental disclosure to the standardized measure of discounted future net cash flows. While the standardized measure of discounted future net cash flows is dependent on the unique tax situation of each company, the present value of proved reserves is based on prices and discount factors that are consistent for all companies and can be used within the industry and by securities analysts to evaluate proved reserves on a more comparable basis. Standardized measure of discounted future net cash flows differs from the present value of proved reserves by the amount of estimated future income taxes and net abandonment costs.  Estimated future income taxes and future net abandonment costs (discounted at 10%) as of December 31, 2008 were $82.2 million and $24.3 million, respectively.

The following table sets forth certain information as of December 31, 2008 regarding our estimated proved oil and gas reserves in each of our principal producing areas.

													Percent
	Proved Reserves										Present		of Present
					Total Gas		Percent of				Value of		Value of
	Oil (a)		Gas		Equivalent		Total Gas				Proved		Proved
	(MBbls)		(MMcf)		(MMcfe)		Equivalent				Reserves		Reserves
										(In thousands)
Permian Basin		13,491		54,914		135,860		59.4	%		$	256,467		50.1	%
North Louisiana		285		19,750		21,460		9.4	%			64,377		12.6	%
South Louisiana		524		13,966		17,110		7.5	%			61,109		11.9	%
Austin Chalk (Trend)		6,280		4,471		42,151		18.4	%			102,370		20.0	%
Cotton Valley Reef Complex		-		9,281		9,281		4.1	%			22,029		4.3	%
East Texas Bossier		-		519		519		.2	%			1,297		.3	%
Other		196		1,028		2,204		1.0	%			4,012		.8	%
Total		20,776		103,929		228,585		100.0	%		$	511,661		100.0	%

 (a) Includes natural gas liquids.

Our estimated recoverable proved reserves have been determined 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, and does not include any economic impact that may result from our hedging activities.

Substantially all of our estimates of proved reserves are derived from reports prepared by Williamson Petroleum Consultants, Inc., independent petroleum engineers, and Ryder Scott Company, L.P., petroleum consultants.

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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, 2008 were $42.03 per Bbl of oil and natural gas liquids and $5.90 per Mcf of gas, as compared to $91.30 per Bbl of oil and natural gas liquids and $7.37 per Mcf of gas as of December 31, 2007.  We estimate that a $1 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 $11 million and $31.9 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, 2008, 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,
	2008				2007				2006
	Gross		Net		Gross		Net		Gross		Net
	(Excludes wells in progress at the end of any period)
Development Wells:
Oil		70		51.5		34		14.9		2		1.0
Gas		41		14.7		34		13.2		16		1.8
Dry		1		1.0		-		-		1		.8
Total		112		67.2		68		28.1		19		3.6
Exploratory Wells:
Oil		1		.5		-		-		6		5.2
Gas		3		1.7		12		8.0		35		14.5
Dry		4		3.0		7		5.8		10		8.7
Total		8		5.2		19		13.8		51		28.4
Total Wells:
Oil		71		52.0		34		14.9		8		6.2
Gas		44		16.4		46		21.2		51		16.3
Dry		5		4.0		7		5.8		11		9.5
Total		120		72.4		87		41.9		70		32.0

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.

In connection with the formation of Larclay JV, we entered into a three-year drilling contract with Larclay JV, a joint venture between us and Lariat described under “Business – Company Profile – Investment in Larclay JV”.  The drilling contract expires on the earlier of December 31, 2009 or the termination and liquidation of Larclay JV.  The terms of the drilling contract provide that we contract for each drilling rig on a well-by-well basis at then current market rates.  If a drilling rig is not needed by us at any time during the term of the contract, Larclay JV may contract with other operators for the use of such drilling rig, subject to certain restrictions.  If a drilling rig is idle, the contract requires us to pay Larclay JV an idle rig rate ranging from $8,100 per day to $10,300 per day (plus crew labor expenses, if applicable), depending on the size of the drilling rig.

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Except for the Larclay JV drilling rigs, we are not currently subject to any long-term drilling contracts.

Productive Well Summary

The following table sets forth certain information regarding our ownership, as of December 31, 2008, of productive wells in the areas indicated.

	Oil				Gas				Total
	Gross		Net		Gross		Net		Gross		Net
Permian Basin		5,481		482.8		736		96.2		6,217		579.0
North Louisiana		-		-		52		18.0		52		18.0
South Louisiana		6		3.6		48		23.5		54		27.1
Austin Chalk (Trend)		310		240.8		17		9.3		327		250.1
Cotton Valley Reef Complex		-		-		14		11.6		14		11.6
Other		6		5.3		34		8.7		40		14.0
Total		5,803		732.5		901		167.3		6,704		899.8

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,
	2008		2007		2006
Oil and Gas Production Data:
Gas (MMcf)		18,553		20,649		15,198
Oil (MBbls)		2,952		2,318		2,171
Natural gas liquids (MBbls)		182		222		199
Total (MMcfe)		37,357		35,889		29,418
Average Realized Prices (a):
Gas ($/Mcf)	$	9.02	$	7.01	$	6.68
Oil ($/Bbl)	$	97.35	$	70.36	$	62.92
Natural gas liquids ($/Bbl)	$	54.45	$	43.74	$	38.18
Average Production Costs:
Production ($/Mcfe) (b)	$	2.38	$	2.10	$	2.15

(a) No derivatives were designated as cash flow hedges in the table above.  All gains or losses on settled derivatives were included in gain/loss on derivatives.

(b) 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,
	2008		2007		2006
	(In thousands)
Property Acquisitions:
Proved	$	-	$	-	$	6,432
Unproved		36,397		15,746		54,437
Developmental Costs		260,073		45,611		35,698
Exploratory Costs		51,237		169,879		157,509
Total	$	347,707	$	231,236	$	254,076

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Acreage

The following table sets forth certain information regarding our developed and undeveloped leasehold acreage as of December 31, 2008 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
Permian Basin		86,278		47,699		351,167		159,653		437,445		207,352
East Texas (a)		118,806		115,048		147,689		107,623		266,495		222,671
North Louisiana		5,736		5,013		236,480		165,571		242,216		170,584
South Louisiana		8,662		5,882		23,034		20,168		31,696		26,050
Other (b)		10,938		3,507		392,850		208,687		403,788		212,194
Total		230,420		177,149		1,151,220		661,702		1,381,640		838,851

 (a) Includes our acreage in the Austin Chalk (Trend), Cotton Valley Reef Complex and East Texas Bossier areas.

 (b) Net undeveloped acres are attributable to the following areas:  Mississippi – 70,093; Utah – 53,781; Alabama – 38,912; Colorado – 28,979; and other – 16,922.

Contract Drilling

We own a 50% equity interest in Larclay JV to construct, own and operate 12 drilling rigs, consisting of five 1,000 horsepower rigs, five 1,300 horsepower rigs and two 2,000 horsepower rigs.  All of the rigs, except for one of the 2,000 horsepower rigs, are fully constructed.  As of March 1, 2009, all but two of the Larclay JV drilling rigs were idle, and the other two rigs are expected to be idle by the end of April 2009.

Offices

We lease from a related partnership approximately 71,000 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 unaffiliated third parties.

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 year ended December 31, 2008.

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PART II

Item 5 - Market for the Registrant's Common Equity, Related Stockholder Matters and Issuer Repurchases of Equity Securities

Price Range of Common Stock

Our Common Stock is quoted on the Nasdaq Stock Market’s Global Market under the symbol “CWEI”.  As of March 10, 2009, there were approximately 2,000 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 Global Market:

	High		Low
Year Ended December 31, 2008:
Fourth Quarter	$	68.89	$	29.70
Third Quarter		120.00		61.89
Second Quarter		121.50		48.86
First Quarter		53.50		30.84
Year Ended December 31, 2007:
Fourth Quarter	$	35.39	$	27.12
Third Quarter		34.54		21.33
Second Quarter		29.68		23.43
First Quarter		36.25		26.44

The closing price of our common stock at March 10, 2009 was $21.95 per share.

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.

Securities Authorized for Issuance under Equity Compensation Plans

For information concerning shares available for issuance under equity compensation plans, see Item 12, which is to be incorporated by reference to our proxy statement.

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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, 2008 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,
	2008			2007			2006			2005			2004
	(In thousands, except per share)
Statement of Operations Data:
Revenues:
Oil and gas sales	$	463,964		$	316,992		$	245,967		$	252,599		$	193,127
Natural gas services		10,926			10,230			11,327			12,080			9,083
Drilling rig services		46,124			52,649			6,937			-			-
Gain on sales of property and equipment		44,503			14,024			1,767			18,920			4,120
Total revenues		565,517			393,895			265,998			283,599			206,330
Costs and expenses:
Production		89,054			75,319			63,298			57,404			41,163
Exploration:
Abandonment and impairments		80,112			68,870			65,173			39,957			67,956
Seismic and other		22,685			4,765			11,299			10,780			7,124
Natural gas services		10,060			9,745			10,005			11,212			8,538
Drilling rig services		37,789			32,964			4,538			-			-
Depreciation, depletion and amortization		120,542			84,476			66,163			47,509			44,040
Impairment of property and equipment		12,882			12,137			21,848			18,266			-
Accretion of abandonment obligations		2,355			2,508			1,653			1,158			1,044
General and administrative		25,635			19,266			16,676			15,410			11,689
Loss on sales of property and equipment		2,122			9,815			99			209			14,337
Other		-			-			-			1,353			-
Total costs and expenses		403,236			319,865			260,752			203,258			195,891
Operating income		162,281			74,030			5,246			80,341			10,439
Other income (expense):
Interest expense		(24,994	)		(32,118	)		(20,895	)		(14,498	)		(7,877	)
Gain (loss) on derivatives		74,743			(31,968	)		37,340			(70,059	)		(25,329	)
Other income (expense)		6,539			5,355			(1,339	)		4,022			1,354
Total other income (expense)		56,288			(58,731	)		15,106			(80,535	)		(31,852	)
Income (loss) before income taxes		218,569			15,299			20,352			(194	)		(21,413	)
Income tax (expense) benefit		(77,327	)		(5,497	)		(1,979	)		451			7,385
Minority interest, net of tax		(708	)		(3,812	)		(574	)		-			-
NET INCOME (LOSS)	$	140,534		$	5,990		$	17,799		$	257		$	(14,028	)
Net income (loss) per common share:
Basic	$	11.78		$	.53		$	1.64		$	.02		$	(1.37	)
Diluted	$	11.67		$	.52		$	1.58		$	.02		$	(1.37	)
Weighted average common shares outstanding:
Basic		11,932			11,337			10,885			10,804			10,213
Diluted		12,039			11,494			11,244			11,241			10,213
Other Data:
Net cash provided by operating activities	$	381,980		$	234,866		$	145,990		$	163,475		$	126,980
	December 31,
	2008			2007			2006			2005			2004
	(In thousands)
Balance Sheet Data:
Working capital (deficit)	$	2,607		$	(76,388	)	$	(23,068	)	$	(35,812	)	$	(27,566	)
Total assets		943,409			861,096			795,433			587,335			462,235
Long-term debt		347,225			430,175			413,876			235,700			177,519
Stockholders’ equity		314,682			160,806			144,980			120,291			117,596

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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 independent oil and natural gas exploration, development, acquisition, and production company.  Our basic business model is to increase shareholder value by finding and developing oil and gas reserves through exploration and development activities, and selling 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 the resulting 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.  From time to time, we may also acquire producing properties if we believe the acquired assets offer us the potential for reserve growth through additional developmental or exploratory drilling activities.

 For most of 2008, the economic climate in the domestic oil and gas industry was suitable for our business model.  Until recently, oil and gas prices were favorable and provided us with the economic incentives necessary to assume the risks we face in our search for oil and gas reserves despite higher drilling, completion and operating expenses.

During the second half of 2008, global economies began to experience a significant slowdown sparked by a near-collapse in worldwide financial markets.  This slowdown has continued to intensify into the first quarter of 2009 and is currently being viewed by many economists as the most severe recession in United States history, second only to the Great Depression.  The United States government has taken significant steps to support the financial markets and stimulate the economy in an effort to slow or reverse the downward spiral of economic indicators, but the success of these measures and the duration of the current recession cannot be predicted.

Reduced demand for energy caused by the current recession has resulted in a significant deterioration in oil and gas prices, which in turn has led to a significant reduction in drilling activity throughout the oil and gas industry.  While the prices we pay for field services are beginning to decline as a result of reduced demand for those services, the decline in these prices is generally lagging behind the declines in oil and gas prices.  As a result, we experienced reductions in operating margins during the last half of 2008 and reported negative price revisions to our proved reserves due to lower product prices and still relatively high capital and operating costs.  The effects of lower operating margins on our business are significant since they reduce our cash flow from operations and diminish the present value of our oil and gas reserves.  These factors have an adverse affect on our ability to access the capital resources we need to grow our reserve base.  Lower operating margins also offer us less incentive to assume the drilling risks that are inherent in our business.  In response to decreases in product prices and the resulting effect on our operating margins, we currently plan to reduce capital spending during fiscal 2009 to $56 million compared to $372.7 million in fiscal 2008.

We are monitoring the impact of the recession on our business, including the extent to which lower commodity prices could affect our financial liquidity.  While we believe we are taking appropriate actions to preserve our short-term liquidity, a prolonged recession of this magnitude could negatively impact our long-term liquidity, financial position and results of operations.

Key Factors to Consider

The following summarizes the key factors considered by management in the review of our financial condition and operating performance for 2008 and the outlook for 2009.

·   Our oil and gas sales increased $147 million, or 46%, from 2007, comprised of $118.7 million in price variances and $28.3 million in volume variances.

·   During 2008, we decreased borrowings under our revolving credit facility by $71.7 million from $165.8 million at December 31, 2007 to $94.1 million at December 31, 2008 by utilizing cash proceeds from the sales of assets and the early termination of derivative contracts.

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·   We spent $372.7 million on exploration and development activities during fiscal 2008, of which approximately 28% was on exploratory prospects.  We currently plan to spend approximately $56 million on exploration and development for fiscal 2009, with approximately 70% applied to exploratory activities.

·   Exploration costs were $102.8 million for 2008, of which approximately $28.9 million related to unsuccessful exploratory well costs, $51.2 million related to impairment of unproved acreage and the remaining $22.7 million was spent on seismic related activities.  Most of the abandonment and impairment costs in 2008 related to prospects in the East Texas Bossier area and North Louisiana.

·   We recorded a non-cash charge during 2008 of $12.9 million for impairments pursuant to Statement of Financial Accounting Standards No. 144 “Accounting for Impairment or Disposal of Long-Lived Assets” (“SFAS 144”) including proved oil and gas property impairments of $11.3 million for the Margarita #1 well to reduce the carrying value to its estimated fair value.

·   At December 31, 2008, our capitalized unproved oil and gas properties totaled $90.8 million, of which approximately $52.5 million was attributable to unproved acreage.  Unproved properties are subject to a valuation impairment to the extent the carrying cost of a prospect exceeds its estimated fair value.  Therefore, our results of operations in future periods may be adversely affected by unproved property impairments.

·   We recorded a $74.7 million net gain on derivatives in fiscal 2008, consisting of a $25 million realized gain on settled contracts and a $49.7 million gain for changes in mark-to-market valuations.  In December 2008, the Company terminated substantially all of its then-existing derivative contracts for cash proceeds of $99.3 million.  The terminated contracts covered 2.6 million barrels of oil production and 15.2 million MMBtu of gas production for 2009 and 2010.  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 our results of operations.

·   Our estimated proved oil and gas reserves at December 31, 2008 were 228.6 Bcfe compared to 290.8 Bcfe at December 31, 2007.  We added 36.2 Bcfe through extensions and discoveries, had downward net revisions of 49.7 Bcfe and had sales of minerals-in-place of 11.3 Bcfe.

Proved Oil and Gas Reserves

 The following table summarizes changes in our estimated proved reserves during 2008 on a Bcfe basis.

	Bcfe
Total proved reserves, December 31, 2007		290.8
Extensions and discoveries		36.2
Sales of minerals-in-place		(11.3	)
Revisions		(49.7	)
Production		(37.4	)
Total proved reserves, December 31, 2008		228.6

During 2008, we replaced 97% of the 37.4 Bcfe that we produced in 2008 through extensions and discoveries. Following is a discussion of the important factors related to each source of net reserve changes during 2008.

Extensions and discoveries.  Our extensions and discoveries during 2008 consist of estimated proved reserves attributable directly to the drilling of discovery wells primarily in North Louisiana, South Louisiana and the Permian Basin.  Of the 36.2 Bcfe of additions, substantially all are proved developed reserves.  Due to the nature of exploratory drilling, we cannot predict the extent to which we will add any reserves in 2009 through extensions and discoveries.

Sales of minerals-in-place.  We sold all our interest in sixteen producing wells located in South Louisiana consisting of 11.3 Bcfe during the second quarter of 2008.

Revisions.  Our estimated proved reserves were 49.7 Bcfe lower due to revisions of previous estimates. Downward revisions of 57.1 Bcfe were attributable to the effects of lower product prices on the estimated quantities of proved reserves.  Net upward revisions of approximately 7.4 Bcfe were attributable to well

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performance and consisted primarily of net upward adjustments in the Permian Basin, Austin Chalk (Trend) and Cotton Valley Reef Complex, offset in part by downward adjustments in North and South 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,
	2008		2007			2006
Oil and Gas Production Data:
Gas (MMcf)		18,553		20,649			15,198
Oil (MBbls)		2,952		2,318			2,171
Natural gas liquids (MBbls)		182		222			199
Total (MMcfe)		37,357		35,889			29,418
Average Realized Prices (a):
Gas ($/Mcf)	$	9.02	$	7.01		$	6.68
Oil ($/Bbl)	$	97.35	$	70.36		$	62.92
Natural gas liquids ($/Bbl)	$	54.45	$	43.74		$	38.18
Gain (Losses) on Settled Derivative
Contracts (a):
Gas:    Net realized gain (loss)	$	11,764	$	12,229		$	(679	)
Per unit produced ($/Mcf)	$	.63	$	.59		$	(.04	)
Oil:      Net realized gain (loss)	$	15,560	$	(20,086	)	$	(19,886	)
Per unit produced ($/Bbl)	$	5.27	$	(8.67	)	$	(9.16	)
Average Daily Production:
Gas (Mcf):
Permian Basin		14,326		14,649			14,260
North Louisiana		17,500		8,096			988
South Louisiana		10,402		24,025			13,638
Austin Chalk (Trend)		2,367		2,220			2,504
Cotton Valley Reef Complex		5,745		7,133			9,735
Other		490		450			513
Total		50,830		56,573			41,638
Oil (Bbls):
Permian Basin		3,821		3,212			3,172
North Louisiana		415		182			12
South Louisiana		378		1,139			943
Austin Chalk (Trend)		3,384		1,737			1,770
Other		90		81			51
Total		8,088		6,351			5,948
Natural Gas Liquids (Bbls):
Permian Basin		183		198			226
North Louisiana		7		1			-
South Louisiana		49		141			44
Austin Chalk (Trend)		250		259			269
Other		10		9			6
Total		499		608			545
Total Proved Reserves:
Gas (MMcf)		103,929		123,156			119,167
Oil and natural gas liquids (MBbls)		20,776		27,946			25,381
Total gas equivalent (MMcfe)		228,585		290,832			271,453
Standardized measure of discounted
future net cash flows	$	405,166	$	925,969		$	514,800

(Continued)

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	As of or for the Year Ended December 31,
	2008		2007		2006
Total Proved Reserves by Area:
Gas (MMcf):
Permian Basin		54,914		65,248		64,620
North Louisiana		19,750		14,046		12
South Louisiana		13,966		27,196		34,250
Austin Chalk (Trend)		4,471		5,387		4,789
Cotton Valley Reef Complex		9,281		9,157		11,562
East Texas Bossier		519		-		-
Other		1,028		2,122		3,934
Total		103,929		123,156		119,167
Oil and Natural Gas Liquids (MBbls):
Permian Basin		13,491		17,318		15,679
North Louisiana		285		319		-
South Louisiana		524		1,117		2,231
Austin Chalk (Trend)		6,280		7,530		6,469
Other		196		1,662		1,002
Total		20,776		27,946		25,381
Total Gas Equivalent (MMcfe):
Permian Basin		135,860		169,156		158,694
North Louisiana		21,460		15,960		1,360
South Louisiana		17,110		33,898		46,288
Austin Chalk (Trend)		42,151		50,567		43,603
Cotton Valley Reef Complex		9,281		9,157		11,562
East Texas Bossier		519		-		-
Other		2,204		12,094		9,946
Total		228,585		290,832		271,453
Exploration Costs (in thousands):
Abandonment and impairment costs:
North Louisiana	$	25,414	$	30,356	$	9,235
South Louisiana		3,187		28,805		33,695
Permian Basin		717		1,322		5,638
East Texas Bossier   ��		40,544		2,640		-
Utah		6,331		4,062		-
Montana		-		9		6,462
Mississippi		1,270		1,148		328
Colorado		-		24		9,675
Other		2,649		504		140
Total		80,112		68,870		65,173
Seismic and other		22,685		4,765		11,299
Total exploration costs	$	102,797	$	73,635	$	76,472
Oil and Gas Costs ($/Mcfe Produced):
Production	$	2.38	$	2.10	$	2.15
DD&A	$	2.97	$	2.12	$	2.12
Net Wells Drilled (b):
Exploratory wells		5.2		13.8		28.4
Developmental wells		67.2		28.1		3.6
(a)No derivatives were designated as cash flow hedges in the table above. All gains or losses on settled derivatives were included in gain/loss on derivatives.
(b)Excludes wells being drilled or completed at the end of each period.

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Operating Results

2008 Compared to 2007

The following discussion compares our results for the year ended December 31, 2008 to the year ended December 31, 2007.  Unless otherwise indicated, references to 2008 and 2007 within this section refer to the respective annual periods.

Oil and gas operating results

Oil and gas sales in 2008 increased $147 million, or 46%, from 2007.  Price variances accounted for $118.7 million of this increase and production volume variances accounted for the remaining $28.3 million of incremental sales.  Production in 2008 (on an Mcfe basis) was 4% higher than 2007.  Oil production increased 27% and gas production decreased 10% in 2008 from 2007.  The comparability of production between 2007 and 2008 was affected by two primary factors.  Certain South Louisiana properties were sold during the second quarter of 2008 and South Louisiana production in 2008 was curtailed due to Hurricanes Gustav and Ike.   In 2008, our realized oil price was 38% higher than 2007, while our realized gas price was 29% higher.  Product prices during the first quarter of 2009 have continued to decline as a result of a global economic recession.  We cannot predict the extent or duration of the current product price environment.

Production costs, consisting of lease operating expenses, production taxes and other miscellaneous marketing costs, increased 18% in 2008 as compared to 2007.   Some of the key components giving rise to the higher costs included increases in oilfield service costs, higher repair and maintenance costs and increased production tax costs related to higher product prices.  After giving effect to a 4% increase in oil and gas production on an Mcfe basis, production costs per Mcfe increased 13% from $2.10 per Mcfe in 2007 to $2.38 per Mcfe in 2008.  We expect lower demand for field services to result in a reduction in production costs, but the timing and extent of any reductions cannot be predicted.

Oil and gas depletion expense increased $35 million from 2007 to 2008, of which rate variances accounted for a $31.9 million increase and production variances accounted for a $3.1 million increase.  On an Mcfe basis, depletion expense increased 40% from $2.12 per Mcfe in 2007 to $2.97 per Mcfe in 2008 due to a combination of higher depletable costs and lower estimated reserve quantities in 2008 compared to the 2007 period.  Depletion expense per Mcfe of oil and gas production is an operating metric that is indicative of our weighted average cost to find or acquire a unit of equivalent production.

We recorded a provision for impairment of property and equipment under SFAS 144 of $12.9 million during 2008, including $11.3 million related to the Margarita #1 well in our East Texas Bossier area.  We recorded a provision for impairment of property and equipment under SFAS 144 of $12.1 million during 2007, of which $7.1 million related to write-downs of two 2,000 horsepower drilling rigs and related components, $1.1 million related to well service equipment, and $3.9 million related to producing properties in the Permian Basin.

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 2008, we charged to expense $102.8 million of exploration costs, as compared to $73.6 million in 2007.

At December 31, 2008, our capitalized unproved oil and gas properties totaled $90.8 million, of which approximately $52.5 million was attributable to unproved acreage.  Unproved properties are subject to a valuation impairment to the extent the carrying cost of a prospect exceeds its estimated fair value.  Therefore, our results of operations in future periods may be adversely affected by unproved property impairments.

We plan to spend approximately $56 million on exploration and development activities in 2009, of which approximately 70% is expected to be allocated to exploration activities.  Since exploratory drilling involves a high degree of risk, it is likely that a significant portion of the costs we incur in 2009 will be charged to exploration costs. However, we cannot predict our success rates and, accordingly, cannot predict our exploration costs related to abandonment and impairment costs.

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Contract Drilling Services

In April 2006, we formed Larclay JV, a joint venture with Lariat to construct, own, and operate 12 new drilling rigs.  We own a 50% equity interest in Larclay JV.  Although the Company and Lariat own equal interests in Larclay JV, we meet the definition of the primary beneficiary of Larclay JV’s expected cash flows under FIN 46R.  As the primary beneficiary under FIN 46R, we are required to include the accounts of Larclay JV in our consolidated financial statements.  During 2008, we included contract drilling revenues of $50.8 million, other operating expenses of $37.8 million, depreciation expense of $8.6 million and interest expense of $3.9 million in our statement of operations (see Note 18 to the consolidated financial statements).  Since the Larclay JV drilling rigs are partially utilized by us, the reported amounts are net of any intercompany profits eliminated in consolidation.

General and Administrative

General and administrative (“G&A”) expenses increased 33% from $19.3 million in 2007 to $25.6 million in 2008.  Excluding non-cash employee compensation, G&A expenses increased from $17.4 million in 2007 to $19.8 million in 2008 due in part to cash bonuses paid to employees in connection with our sale of properties in South Louisiana and higher personnel costs.  In 2008, we recorded a $5.7 million non-cash compensation charge related to our after payout incentive plan and $92,000 for stock-based compensation to directors.  In 2007, we recorded a $1.8 million non-cash compensation charge related to our after payout incentive plan and $110,000 for stock-based compensation to directors.

Interest expense

Interest expense decreased 22% from $32.1 million in 2007 to $25 million in 2008 due to a combination of reduced debt levels and lower interest rates.  The average daily principal balance outstanding under our revolving credit facility for 2008 was $128.5 million compared to $176.5 million for 2007.  During 2008, we received approximately $117 million from the sale of property and equipment and used the net proceeds to reduce indebtedness outstanding under on our revolving credit facility.  In addition, we received approximately $99 million of cash proceeds from the early termination of derivative contracts.  Debt reductions on our revolving credit facility accounted for $3.5 million of the decrease in interest expense, while lower interest rates resulted in a decrease of approximately $3.3 million.  In addition, capitalized interest for 2008 was $3.8 million compared to $4.2 million in 2007, and interest expense associated with our Larclay JV during 2008 was $3.4 million compared to $4.3 million in 2007.

Gain/loss on derivatives

We did not designate any derivative contracts in 2008 or 2007 as cash flow hedges; therefore all cash settlements and changes resulting from mark-to-market valuations have been recorded as gain/loss on derivatives.  For 2008, we reported a $74.7 million net gain on derivatives, consisting of a $49.7 million non-cash gain to mark our derivative positions to their fair value and a $25 million realized gain on settled contracts.  For 2007, we reported a $32 million net loss on derivatives, consisting of an $24.3 million non-cash loss to mark our derivative positions to their fair value at December 31, 2007 and a $7.7 million realized loss on settled contracts.  Because oil and gas prices are volatile, and because we do not account for our derivatives as cash flow hedges, the effect of mark-to-market valuations on our gain/loss on derivatives can cause significant volatility in our results of operations.

Gain/loss on sales of property and equipment

 We recorded a net gain on sales of property and equipment of $42.4 million for 2008, which included a $33.1 million gain on sales of properties in South Louisiana, a $3 million gain on the sale of a North Louisiana prospect, and a $5.7 million gain on the sales of two drilling rigs and a surplus well servicing unit.  In 2007, we recorded a net gain of $4.2 million, which included the sale of all of our producing and non-producing acreage in Pecos County, Texas for $21 million, net of closing costs, and recorded a gain of approximately $12.5 million in connection with this sale, offset by a $9.8 million loss due primarily to the write-down of inventory to its market value.

Income tax expense

Our effective income tax rate in 2008 of 35.4% differed from the statutory federal rate of 35% due primarily to increases in the tax provision related primarily to the effects of the Texas Margin Tax and certain non-deductible expenses, offset in part by tax benefits derived from statutory depletion deductions.

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2007 Compared to 2006

The following discussion compares our results for the year ended December 31, 2007 to the year ended December 31, 2006.  Unless otherwise indicated, references to 2007 and 2006 within this section refer to the respective annual periods.

Oil and gas operating results

Oil and gas sales in 2007 increased $71 million, or 29%, from 2006, of which production variances accounted for a $45.6 million increase and price variances accounted for a $25.4 million increase.  Production in 2007 (on an Mcfe basis) was 22% higher than 2006.  Oil production increased 7% and gas production increased 36% in 2007 as compared to 2006 due primarily to production attributable to recent drilling activities in North and South Louisiana.  In 2007, our realized oil price was 12% higher than 2006, while our realized gas price was 5% higher.  Historically, the markets for oil and gas have been volatile, and they are likely to continue to be volatile.

Production costs, consisting of lease operating expenses, production taxes and other miscellaneous marketing costs, increased 19% in 2007 as compared to 2006 due to a combination of factors including increased oil and gas production, rising oilfield service costs, and higher repair and maintenance costs.  After giving effect to a 22% increase in oil and gas production on an Mcfe basis, production costs per Mcfe decreased 2% from $2.15 per Mcfe in 2006 to $2.10 per Mcfe in 2007.  It is likely that these factors will continue to contribute to higher production costs in future periods.

DD&A expense increased 28% from $66.2 million in 2006 to $84.5 million in 2007.  DD&A expense attributable to oil and gas properties increased $13.6 million, primarily due to production increases.  On an Mcfe basis, oil and gas depletion expense remained constant at $2.12 per Mcfe in 2006 and 2007.  DD&A per Mcfe of oil and gas production is an operating metric that is indicative of our weighted average cost to find or acquire a unit of equivalent production.

We recorded a provision for impairment of property and equipment under SFAS 144 of $12.1 million during 2007, of which $7.1 million related to write-downs of two 2,000 horsepower drilling rigs and related components and $1.1 million charge for well service equipment to reduce the carrying value to their estimated fair market value.  The remaining $3.9 million impairment related to producing properties in the Permian Basin.  We recorded a provision for impairment of proved properties of $21.8 million in 2006.  We have capitalized $26.3 million of drilling and completion costs associated with two wells in our East Texas Bossier area that were in progress at December 31, 2007 and were completed as marginal producers during the first quarter of 2008.  We have not assigned any proved reserves to these wells since we do not have sufficient production history to permit us to make a reasonable estimate at this time.  However, it appears to be unlikely that we will recover our capitalized drilling and completion costs on these wells through future production from only these wells.  Depending on our evaluations of these wells and the results of future drilling activities in our East Texas Bossier play, we may record impairments of proved properties related to these wells in future periods.

Gain on property sales

Gain on sales of property and equipment for 2007 was $14 million compared to $1.8 million in 2006.  In 2007, we sold all of our producing and non-producing acreage in Pecos County, Texas for $21 million, net of closing costs, and recorded a gain of approximately $12.5 million in connection with this sale.

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 2007, we charged to expense $73.6 million of exploration costs, as compared to $76.5 million in 2006.  Most of the 2007 costs were incurred in Louisiana.

At December 31, 2007, our capitalized unproved oil and gas properties totaled $115.9 million, of which approximately $75.4 million was attributable to unproved acreage.  Unproved properties are subject to a valuation impairment to the extent the carrying cost of a prospect exceeds its estimated fair value.  Therefore, our results of operations in future periods may be adversely affected by unproved property impairments.

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We plan to spend approximately $256.5 million on exploration and development activities in 2008, of which approximately 19% is expected to be allocated to exploration activities.  Since exploratory drilling involves a high degree of risk, it is likely that a significant portion of the costs we incur in 2008 will be charged to exploration costs. However, we cannot predict our success rates and, accordingly, cannot predict our exploration costs related to abandonment and impairment costs.

Contract Drilling Services

In April 2006, we formed Larclay JV, a joint venture with Lariat to construct, own, and operate 12 new drilling rigs.  We own a 50% equity interest in Larclay JV.  Although the Company and Lariat own equal interests in Larclay JV, we meet the definition of the primary beneficiary of Larclay JV’s expected cash flows under FIN 46R.  As the primary beneficiary under FIN 46R, we are required to include the accounts of Larclay JV in our consolidated financial statements.  During the year ended December 31, 2007, we included contract drilling revenues of $52.6 million, other operating expenses of $30.9 million, depreciation expense and impairment of property and equipment of $14.3 million and interest expense of $4.3 million in our statement of operations (see Note 18 to the consolidated financial statements).  Since the Larclay JV drilling rigs are partially utilized by us, the reported amounts are net of any intercompany profits eliminated in consolidation.

General and administrative expenses

G&A expenses increased 16% from $16.7 million in 2006 to $19.3 million in 2007.  Excluding non-cash employee compensation, G&A expenses increased from $14 million in 2006 to $17.4 million in 2007 due primarily to higher professional fees and personnel costs.  In 2007, we recorded a $1.8 million non-cash compensation charge related to our after payout incentive plan and $110,000 for stock-based employee compensation.  In 2006, we recorded a $2.5 million non-cash charge related to our after payout incentive plan and a $128,000 non-cash charge for stock-based employee compensation.

Interest expense

Interest expense increased 54% from $20.9 million in 2006 to $32.1 million in 2007 due to a combination of factors.  In 2006 and 2007, we used our revolving loan facility to partially finance our exploration and development activities.  The average daily principal balance outstanding under our revolving credit facility for 2007 was $176.5 million compared to $89 million for 2006.  Capitalized interest for 2007 was $4.2 million compared to $5.8 million in 2006.  We also included $4.3 million of interest expense associated with our Larclay JV during 2007 compared to $668,000 in 2006.

Gain/loss on derivatives

We did not designate any derivative contracts in 2007 or 2006 as cash flow hedges; therefore all cash settlements and changes resulting from mark-to-market valuations have been recorded as gain/loss on derivatives.  For 2007, we reported a $32 million net loss on derivatives, consisting of an $24.3 million non-cash loss to mark our derivative positions to their fair value at December 31, 2007 and a $7.7 million realized loss on settled contracts.  For 2006, we recorded a net gain on derivatives of $37.3 million, consisting of a $57.5 million non-cash gain related to changes in mark-to-market valuations and a $20.2 million realized loss on settled contracts.

Other

Loss on sale of assets for 2007 was $9.8 million compared to $99,000 for 2006.  The 2007 charge was due to recording losses on inventory which included a charge of $8.9 million to write-down inventory to its estimated market value at March 31, 2007.  The write-down resulted primarily from the sale of certain surplus equipment at an auction in March 2007.  Other income/expense for 2007 was income of $5.4 million compared to expense of $1.3 million for the 2006 period.  The 2007 period included a $2.9 million gain on settlement of litigation.  No lawsuit settlements or write-downs of inventory were recorded during the 2006 period.

Income tax expense (benefit)

Our effective income tax rate in 2007 of 35.9% differed from the statutory federal rate of 35% due primarily to increases in the tax provision related primarily to the effects of the recently-enacted Texas Margin Tax and certain non-deductible expenses, offset in part by tax benefits derived from statutory depletion deductions.

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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 a group of banks to secure our revolving credit facility.  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.  However, the effects of product prices on cash flow can be mitigated through the use of commodity derivatives.

During the last half of 2008, the economic climate in the oil and gas industry experienced a rapid adverse change.  Oil and gas prices have fallen drastically, yet the cost of field services have remained relatively high due to a lag in reaction to lower prices on reduced operating activity in the industry.  As a result, we experienced reductions in operating margins during the last half of 2008 and reported negative price revisions to our proved reserves due to lower product prices and still relatively high capital and operating costs.  The effects of lower operating margins on our business are significant since they reduce our cash flow from operations and diminish the estimated present value of our oil and gas reserves.  These factors have an adverse affect on our ability to access the capital resources we need to grow our reserve base.  Downward revisions in estimated proved reserves can adversely affect the amount of funds we can borrow on the credit facility.  Lower operating margins also offer us less incentive to assume the drilling risks that are inherent in our business.  In response to decreases in product prices and the resulting effect on our operating margins, we currently plan to reduce capital spending during fiscal 2009 to $56 million compared to $372.7 million in fiscal 2008.

The Indenture governing the issuance of our 7¾% Senior Notes due 2013 contains covenants that restrict our ability to borrow money.  One such covenant prohibits us from borrowing any additional funds under the revolving credit facility if our outstanding balance on the facility exceeds 30% of Adjusted Consolidated Net Tangible Assets, as defined in the Indenture.  Based on current product prices, we do not currently expect this covenant to limit our ability to borrow under the revolving credit facility.  However, we could be limited in future periods depending on the extent and severity of the current economic recession.

Capital expenditures

 The following table summarizes, by area, our planned expenditures for exploration and development activities during 2009, as compared to our actual expenditures in 2008.

	Actual		Planned
	Expenditures		Expenditures		2009
	Year Ended		Year Ended		Percentage
	December 31, 2008		December 31, 2009		of Total
	(In thousands)
South Louisiana	$	39,700	$	17,700		32	%
Permian Basin		152,700		14,600		26	%
East Texas Bossier		38,800		11,800		21	%
Utah/California		5,400		7,400		13	%
Austin Chalk (Trend)		52,600		2,100		4	%
North Louisiana		82,500		1,900		3	%
Other		1,000		500		1	%
	$	372,700	$	56,000		100	%

Our planned exploration and development activities for 2009 are substantially lower than fiscal 2008 actual expenditures in response to the unfavorable economic climate that we are currently experiencing in the oil and gas industry.  For 2009, we currently plan to defer most of our developmental drilling activities in the Permian Basin, the Austin Chalk (Trend) and North Louisiana, and to significantly reduce our exploration activities in the East Texas Bossier and South Louisiana.  However, our actual expenditures during fiscal 2009 may vary significantly from these estimates if our plans for exploration and development activities change during the year.  Factors, such as changes in operating margins and the availability of capital resources could increase or decrease our ultimate level of expenditures during fiscal 2009.

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 Approximately 70% of the 2009 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 cannot predict our drilling success on exploratory prospects, and our future results of operations and financial condition could be adversely affected by unsuccessful exploratory drilling results.

 We spent $372.7 million on exploration and development activities during 2008, of which approximately 28% was on exploratory prospects.  We currently plan to spend approximately $56 million for fiscal 2009, of which approximately 70% is estimated to be spent on exploratory prospects.  We financed these expenditures in 2008 with cash flow from operating activities and proceeds from the sales of certain South Louisiana properties, drilling rigs and other assets.  Based on preliminary estimates, our internal cash flow forecasts indicate that our anticipated operating cash flow will be sufficient to finance our exploration and development activities through 2009.  Although we believe the assumptions and estimates made in our forecasts are reasonable, we are unable to predict the extent and duration of lower operating margins resulting from the current economic depression.  Accordingly, cash flow may be less than expected, the availability of funds under the credit facility may be less than expected, or capital expenditures may be more than expected.  In the event we lack adequate liquidity to finance our expenditures through fiscal 2009, we will consider options for obtaining alternative capital resources, including selling assets or accessing capital markets.  Because of significant uncertainties regarding the current economic environment, we can give no assurance that these alternative capital resources can be obtained on terms acceptable to us.

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 the year ended December 31, 2008 increased $147.1 million, or 62.6%, as compared to the corresponding period in 2007.  Approximately $4 million of the increase in operating cash flow was attributable to Larclay JV.  All of Larclay JV’s cash flow is dedicated to the repayment of a $75 million secured term loan facility (see “- Larclay JV”).  The remainder of the increase in operating cash flow was derived primarily from oil and gas producing activities, offset in part by increases in production costs and seismic expense.

Credit facility

 A group of banks have provided us with a revolving credit facility on which we have historically relied 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.

 During 2008, we reduced indebtedness outstanding under our revolving credit facility by $71.7 million, primarily with the proceeds from the sales of assets and from the early termination of derivative contracts.  At December 31, 2008, we had a borrowing base of $250 million, leaving $155.1 million available under the revolving loan facility after accounting for outstanding letters of credit of $804,000.  This borrowing base is scheduled for redetermination in May 2009.

 Using the revolving 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 (1) include the amount of funds available under this

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facility as a current asset, (2) exclude current assets and liabilities related to the fair value of derivatives, and (3) exclude current maturities of vendor finance obligations, if any, when computing the working capital ratio at any balance sheet date.

 Working capital computed for loan compliance purposes differs from our working capital 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 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 decreased from $76.4 million at December 31, 2007 to a positive $2.6 million at December 31, 2008 due primarily to a combination of factors, including an increase in cash and a decrease in the net liability for the fair value of derivatives.  After giving effect to the adjustments, our working capital computed for loan compliance purposes was a positive $170.9 million at December 31, 2008, as compared to a positive $103.2 million at December 31, 2007.  The following table reconciles our GAAP working capital to the working capital computed for loan compliance purposes at December 31, 2008 and December 31, 2007.

	December 31,
	2008		2007
	(In thousands)
Working capital (deficit) per GAAP	$	2,607	$	(76,388	)
Add funds available under the revolving credit facility		155,096		108,396
Exclude fair value of derivatives classified as current assets or current liabilities		-		49,738
Exclude current assets and current liabilities of Larclay JV		13,205		21,423
Working capital per loan covenant	$	170,908	$	103,169

 Since we use this revolving credit facility for both short-term liquidity and long-term financing needs, it is important that we comply in all material respects with the loan agreement, including financial covenants that are computed quarterly.  The working capital covenant requires us to maintain positive working capital using the computations described above.  Another financial covenant under the credit facility requires us to maintain a ratio of indebtedness to cash flow of no more than 3 to 1.  While we were in compliance with all financial and non-financial covenants at December 31, 2008, our increased leverage and reduced liquidity 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 under the revolving credit facility at least twice a year, in May and November, and may request an unscheduled borrowing base redetermination at other times during the year.  The borrowing base was reduced in May 2008 from $275 million to $250 million in connection with our sale of certain properties in South Louisiana.  In June 2008, we elected to maintain the borrowing base at $250 million instead of increasing it to levels supported by the collateral values assigned by the banks.  If at any time, the borrowing base is less than the amount of outstanding indebtedness, we will be required to (1) pledge additional collateral, (2) prepay the excess in not more than five equal monthly installments, or (3) elect to convert the entire amount of outstanding indebtedness to a term obligation based on amortization formulas set forth in the loan agreement.  At December 31, 2008, we had $94.1 million outstanding on the revolving credit facility.

7¾% Senior Notes due 2013

 In July 2005, we issued, in a private placement, $225 million of aggregate principal amount of Senior Notes.  The Senior Notes were issued at face value and bear interest at 7¾% per year, payable semi-annually on February 1 and August 1 of each year, beginning February 1, 2006.  After the payment of transaction expenses, net proceeds of approximately $217 million were used to repay amounts outstanding on our secured credit facilities and for general corporate purposes, including the funding of planned exploration and development activities.

 At any time prior to August 1, 2009, we may redeem some or all of the Senior Notes at a redemption price equal to 100% of the principal amount of the Senior Notes to be redeemed, plus a make-whole premium, plus any accrued and unpaid interest.  On and after August 1, 2009, we may redeem some or all of the Senior Notes at redemption prices (expressed as percentages of principal amount) equal to 103.875% for the twelve-month period beginning on August 1, 2009, 101.938% for the twelve-month period beginning on August 1, 2010, and 100.00% beginning on August 1, 2011, for any period thereafter, in each case plus accrued and unpaid interest.

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 The Indenture governing the Senior Notes contains covenants that restrict our ability and the ability of our restricted subsidiaries to (1) borrow money, (2) issue redeemable or preferred stock, (3) pay distributions or dividends, (4) make investments, (5) create liens without securing the Notes, (6) enter into agreements that restrict dividends from subsidiaries, (7) sell certain assets or merge with or into other companies, (8) enter into transactions with affiliates, (9) guarantee indebtedness, and (10) enter into new lines of business.  One such covenant restricts our ability to borrow additional funds under the revolving credit facility if our outstanding balance on the facility is greater than $150 million and exceeds 30% of Adjusted Consolidated Net Tangible Assets, as defined in the Indenture.  Based on current economic conditions, we do not expect this covenant to limit our ability to borrow under the revolving credit facility in 2009.  These covenants are subject to a number of important exceptions and qualifications as described in the indenture.  We were in compliance with these covenants at December 31, 2008.

Larclay JV

 We own a 50% equity interest in Larclay JV, a joint venture with Lariat to construct, own and operate 12 drilling rigs.  In 2006, Larclay JV obtained a $75 million secured term loan facility from a lender to finance the construction and equipping of the drilling rigs.  The Larclay JV term loan is secured by substantially all of the assets of Larclay JV.  As additional credit support, we granted the lender a limited guaranty in the original amount of $19.5 million.  The maximum obligation under the guaranty reduces by 10% on April 1 of each year, beginning April 1, 2008.  At December 31, 2008, our maximum obligation under the guaranty was approximately $17.6 million.  Although we are not obligated under the Larclay JV term loan except to the extent of the guaranty, we are required to fully consolidate the accounts of Larclay JV under FIN 46R.  The principal balance outstanding on the Larclay JV term loan at December 31, 2008 was $39.4 million.

 The Larclay JV term loan, bears interest at a floating rate based on a LIBOR average, plus 3.25%, and provides for monthly principal and interest payments sufficient to retire the principal balance by 35% in the first year, 25% in each of the next two years, and 15% in the fourth year.  The Larclay JV term loan prohibits Larclay JV from making any cash distributions to Lariat or us until the balance on the term loan is fully repaid, and repayments by Larclay JV of any loans by Lariat or us are subordinated to the loans outstanding under the term loan and are subject to other restrictions.

 Since inception of this joint venture, we have made advances structured as subordinated loans to Larclay JV totaling $12.1 million, $4.6 million to finance excess construction costs and $7.5 million to finance our 50% share of working capital assessments made by Larclay JV.  Lariat has also advanced Larclay JV $7.5 million for its 50% share of working capital assessments.  Loans to Larclay JV by Lariat and us are due on demand and bear interest, payable monthly, at the same rate as the term loan.  However, these loans are subject to a subordination agreement with the Larclay JV lender that imposes restrictions on payments of principal and interest on the loans.

 In connection with the formation of Larclay JV, we entered into a three-year drilling contract with Larclay JV assuring the availability of each drilling rig for use in the ordinary course of our exploration and development drilling program throughout the term of the drilling contract.  The drilling contract, which is pledged as collateral to secure the Larclay JV term loan, expires on the earlier of December 31, 2009 or the termination and liquidation of Larclay JV.  The provisions of the drilling contract provide that we contract for each drilling rig on a well-by-well basis at then current market rates.  If a drilling rig is not needed by us at any time during the term of the contract, Larclay JV may contract with other operators for the use of such drilling rig, subject to certain restrictions.  If a drilling rig is idle, the contract requires us to pay Larclay JV an idle rig rate ranging from $8,100 per day to $10,300 per day (plus crew labor expenses, if applicable), depending on the size of the drilling rig.  Our maximum potential obligation to pay idle rig rates over the remaining term of the drilling contract, excluding any crew labor expenses, totals approximately $29 million at December 31, 2008.

 During most of 2008, the Larclay JV drilling rigs were being utilized primarily by Lariat and us in our respective drilling programs.  However, the material deterioration in oil and gas prices, which began in the second half of 2008 and has continued into the first quarter of 2009, has resulted in a significant reduction in drilling activity throughout the oil and gas industry.  As of March 1, 2009, all but two of the Larclay JV drilling rigs were idle, and those two drilling rigs are expected to be idle by the end of April 2009.  We do not expect utilization of the Larclay JV drilling rigs to improve for the remainder of 2009.  If the drilling rigs remain idle, we may be required under the drilling contract with Larclay JV to pay up to $29 million to Larclay JV in 2009.  These payments will provide Larclay JV with adequate cash flow to meet its debt service obligations under the term loan through 2009.  If the drilling rigs remain idle beyond 2009 and Larclay JV is not able to meet its debt service obligations under the term loan, we may be required under the guaranty to make debt service payments on term loan on behalf of Larclay JV.  We are currently

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assessing our options with respect to our investment in and obligations to Larclay JV.  These options may include debt restructuring, asset sales, and termination and liquidation of Larclay JV.

 On March 13, 2009, we and Lariat entered into an agreement pursuant to which Lariat has agreed to assign all of its right, title and interest in and to the Larclay JV to us effective as of April 15, 2009 (the “Effective Date”), and we have agreed to assume all of the obligations and liabilities of Lariat under the Larclay JV from and after the Effective Date, including Lariat’s obligations as operator of the Larclay JV drilling rigs.  After giving effect to the assignment to us by Lariat, we will own 100% of the Larclay JV  (See "Item 9B - Other Information - Larclay JV").

Alternative capital resources

 Although our base of oil and gas reserves, as collateral for both of our credit facilities, 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 senior or 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

 The following table summarizes our contractual obligations as of December 31, 2008 by payment due date.

	Payments Due by Period
	Total		2009		2010 to 2011		2012 to 2013
					(In thousands)
Contractual obligations:
7¾% Senior Notes (a)	$	225,000	$	-	$	-	$	225,000
Secured bank credit facility(a)		94,100		-		-		94,100
Drilling contracts with Larclay JV		29,008		29,008		-		-
Larclay JV note		39,375		18,750		20,625		-
Subordinated notes of Larclay JV(b)		7,500		-		7,500		-
Lease obligations		4,211		1,632		2,380		199
Total contractual obligations	$	399,194	$	49,390	$	30,505	$	319,299

(a) In addition to the principal payments presented, we expect to make annual interest payments of $17.4 million on the Senior Notes and approximately $4.5 million on the secured bank credit facility (based on the balances and interest rates at December 31, 2008).

(b) Note payable to Lariat for advances to Larclay JV.

Known Trends and Uncertainties

Operating Margins

 We analyze, on a Mcfe produced basis, those revenues and expenses that have a significant impact on our oil and gas operating margins.  Our weighted average oil and gas sales per Mcfe have been on an upward trend, from $8.36 per Mcfe in 2006, $8.83 per Mcfe in 2007 and $12.42 per Mcfe in 2008.  However, our expenses per Mcfe have also been on an upward trend and are resulting in a narrowing operating margin.  Our oil and gas DD&A per Mcfe has increased from $2.12 per Mcfe in 2006 and 2007 to $2.97 per Mcfe in 2008.  An upward trend in DD&A per Mcfe indicates that our cost to find and/or acquire reserves is increasing at a faster rate than the reserves we are adding.  Although we replaced 97% of our production in 2008, our cost to find those reserves was significantly higher than our historical combined rate.  Also affecting our operating margins is the cost of producing our reserves.  Our production costs per Mcfe have fluctuated from $2.15 per Mcfe in 2006, to $2.10 per Mcfe in 2007, to $2.38 per Mcfe in 2008.  The rise in operating costs per Mcfe in 2008 was due primarily to higher costs of field services and increased production taxes resulting from higher commodity prices.

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 During the last half of 2008, the economic climate in the oil and gas industry experienced a rapid adverse change.  Oil and gas prices have fallen drastically, yet the cost of field services have remained relatively high due to a lag in reaction to lower prices on reduced operating activity in the industry.  As a result, our operating margins for 2009 are expected to be lower than those experienced in recent years.  While we believe that supply and demand fundamentals will ultimately reduce the cost of field services if oil and gas prices remain low, we cannot predict the timing or extent of any improvements in our operating margins.

Oil and Gas Production

 As with all companies engaged in oil and gas exploration and production, we face the challenge of natural production decline since oil and gas reserves are a depletable resource.  With each unit of oil and gas we produce, we are depleting our proved reserve base, so we must be able to conduct successful exploration and development activities or acquire properties with proved reserves in order to grow our reserve base.  Prior to 2008 our production had been on a gradual decline since 2003 due to the effects of natural production decline, offset in part by reserve additions through exploration and development and acquisitions.  In 2008, our production increased to 37.4 Bcfe from 35.9 Bcfe in 2007, and we replaced 97% of our 2008 oil and gas production through extensions and discoveries.  While these reserve additions will contribute favorably to our production in 2009, we do not expect this production to be sufficient to fully offset the natural production declines from our base of oil and gas reserves.

 As discussed above, we are currently experiencing lower operating margins resulting from declines in product prices and relatively high costs of field services.  Lower operating margins offer us less incentive to assume the drilling risks that are inherent in our business.  As a result, we currently plan to reduce capital spending during fiscal 2009 to $56 million compared to $372.7 million in fiscal 2008.  Reduced spending levels may adversely impact our ability to replace our 2009 production with new reserves.  Failure to maintain or grow our oil and gas reserves may result in lower production and may adversely affect our financial condition, results of operations, and cash flow.

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 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	·Reserve estimates	·Oil and gas properties
for oil and gas properties	·Valuation of unproved	·Accumulated DD&A
	properties	·Provision for DD&A
	·Judgment regarding status of in progress exploratory wells	·Impairment of unproved  properties
		·Abandonment costs
		(dry hole costs)
Impairment of proved	·Reserve estimates and related	·Oil and gas properties
properties and long-	present value of future net	·Contract drilling equipment
lived assets	revenues (proved properties)	·Accumulated DD&A
	·Estimates of future undiscounted	·Impairment of proved properties
	cash flows (long-lived assets)	and long-lived assets
Asset retirement obligations	·Estimates of the present value	·Abandonment obligations
	of future abandonment costs	(non-current liability)
		·Oil and gas properties
		·Accretion of discount
		expense

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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 and the interpretation of that data, and judgment based on experience and training.  Annually, we engage independent petroleum engineering firms 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 may 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 non-producing	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 standardized measure of discounted future net cash flows 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.

									Standardized
									Measure
	Proved Reserves				Average Price				of Discounted
	Oil (a)		Gas		Oil (a)		Gas		Future
	(MMBbls)		(Bcf)		($/Bbl)		($/Mcf)		Net Cash Flows
									(In millions)
As of December 31:
2008		20.8		103.9	$	42.03	$	5.90	$	405.2
2007		27.9		123.2	$	91.30	$	7.37	$	926.0
2006		25.4		119.2	$	57.18	$	5.24	$	514.8

   (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;

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·   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.

Asset Retirement Obligations

We are required by SFAS 143 “Accounting for Asset Retirement Obligations” to estimate the present value of the amount we will incur to plug, abandon and remediate our producing properties at the end of their productive lives, in accordance with applicable state laws.  We compute our liability for asset retirement obligations by calculating the present value of estimated future cash flows related to each property.  This requires us to use significant assumptions, including current estimates of plugging and abandonment costs, annual inflation of these costs, the productive lives of wells and our risk-adjusted interest rate. Changes in any of these assumptions can result in significant revisions to the estimated asset retirement obligations.

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

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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 geological and geophysical 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.

Asset Retirement Obligations

Our asset retirement obligation is recorded as a liability at its estimated present value as of the asset’s inception, with an offsetting increase to oil and gas properties. Periodic accretion of discount of the estimated liability is recorded as an expense in the statement of operations.  During 2008, we had a downward revision of our estimated asset retirement obligations by $1.4 million based on a review of current plugging and abandonment costs. Revisions to the asset retirement obligation are recorded with an offsetting change to producing properties, resulting in prospective changes to depreciation, depletion and amortization expense and accretion expense. Because of the subjectivity of assumptions and the relatively long lives of most of our wells, the costs to ultimately retire our wells may vary significantly from prior estimates.

Recent Accounting Pronouncements

In December 2008, the Securities and Exchange Commission (“SEC”) released Final Rule, “Modernization of Oil and Gas Reporting”. The new disclosure requirements include provisions that permit the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes. The new requirements also will allow companies to disclose their probable and possible reserves to investors. In addition, the new disclosure requirements require companies to: (a) report the independence and qualifications of its reserves preparer or auditor, (b) file reports when a third party is relied upon to prepare reserves estimates or conducts a reserves audit, and (c) report oil and gas reserves using an average price based upon the prior 12-month period rather than year-end prices. The new disclosure requirements are effective for financial statements for fiscal years ending on or after December 31, 2009. The effect of adopting the SEC rule has not been determined, but it is not expected to have a significant effect on our reported financial position or results of operations.

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133” (“SFAS 161”). This statement is intended to improve transparency in financial reporting by requiring enhanced disclosures of an entity’s derivative instruments and hedging activities and their effects on the entity’s financial position, financial performance, and cash flows. SFAS 161 applies to all derivative instruments within the scope of SFAS 133 as well as related hedged items, bifurcated derivatives, and non-derivative instruments that are designated and qualify as hedging instruments. Entities with instruments subject to SFAS 161 must provide more robust qualitative disclosures and expanded quantitative disclosures. SFAS 161 is effective prospectively for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application permitted.  We are currently evaluating the disclosure implications of this statement.

In December 2007, the FASB issued SFAS No. 141R, “Business Combinations” (“SFAS 141R”) and SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements” (“SFAS 160”). SFAS 141R requires most identifiable assets, liabilities, noncontrolling interests, and goodwill acquired in a business combination to be recorded at “fair value.” The Statement applies to all business combinations, including combinations among mutual entities and combinations by contract alone. Under SFAS 141R, all business combinations will be accounted for by applying the acquisition method. SFAS 141R is effective for periods beginning on or after December 15, 2008.

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SFAS 160 will require noncontrolling interests (previously referred to as minority interests) to be treated as a separate component of equity, not as a liability or other item outside of permanent equity.  The statement applies to the accounting for noncontrolling interests and transactions with noncontrolling interest holders in consolidated financial statements. SFAS 160 is effective for periods beginning on or after December 15, 2008 and will be applied prospectively to all noncontrolling interests, including any that arose before the effective date except that comparative period information must be recast to classify noncontrolling interests in equity, attribute net income and other comprehensive income to noncontrolling interests, and provide other disclosures required by SFAS 160.  The impact on our financial statements from the adoption of SFAS 141R and SFAS 160 in 2009 will depend on future acquisition activity.

In November 2007, FASB Staff Position No. 157-2 (“FSP 157-2”) was issued. FSP 157-2 delays, the effective date of adoption of SFAS No. 157 (“SFAS 157”), “Fair Value Measurements (as amended)," for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). We adopted the non-deferred provisions of SFAS 157 on January 1, 2008 (See Note 8).  FSP 157-2 defers the effective date to fiscal years beginning after November 15, 2008. The effect of adopting FSP 157-2 did not have an effect on our reported financial position or earnings.

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, 2008 reserve estimates, we project that a $1 decline in the price per Bbl of oil and a $.50 decline in the price per Mcf of gas from year end 2008 would reduce our gross revenues for the year ending December 31, 2009 by $11.7 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.

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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, 2008, all of which were entered into subsequent to December 31, 2008.  The settlement prices of commodity derivatives are based on NYMEX futures prices.

Swaps:

	Gas				Oil
	MMBtu (a)		Price		Bbls		Price
Production Period:
1st Quarter 2009		1,180,000	$	5.47		160,000	$	46.39
2nd Quarter 2009		1,570,000	$	5.47		470,000	$	49.68
3rd Quarter 2009		1,450,000	$	5.47		440,000	$	48.13
4th Quarter 2009		1,850,000	$	5.47		400,000	$	46.15
2010		7,540,000	$	6.80		327,000	$	53.30
2011		6,420,000	$	7.07		-	$	-
		20,010,000				1,797,000

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

Interest Rates

 We are exposed to interest rate risk on our long-term debt with a variable interest rate.  At December 31, 2008, our fixed rate debt had a carrying value of $225 million and an approximate fair value of $126 million, based on current market quotes.  We estimate that the hypothetical change in the fair value of our long-term debt resulting from a 100-basis point change in interest rates would be approximately $4 million.  Based on our outstanding variable rate indebtedness at December 31, 2008 of $141 million, a change in interest rates of 100 basis points would affect annual interest payments by $1.4 million.

Item 8 - -                 Financial Statements and Supplementary Data

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

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

None.

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.

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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, 2008 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, 2008.  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, 2008, our internal control over financial reporting is effective based on those criteria.

KPMG LLP has issued an audit report on the effectiveness of the Company’s internal control over financial reporting as of December 31, 2008, the contents of which are shown below.

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Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders

Clayton Williams Energy, Inc.:

We have audited Clayton Williams Energy, Inc.’s (the Company) internal control over financial reporting as of December 31, 2008, 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, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on 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, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included 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.

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.

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

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, 2008 and 2007, 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, 2008, and our report dated March 16, 2009 expressed an unqualified opinion on those consolidated financial statements.

KPMG LLP

Dallas, Texas

March 16, 2009

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Item 9B - -              Other Information

Service Agreement

On March 11, 2009, Clayton Williams Energy, Inc. (the “Company”) entered into an Amendment to Second Amended and Restated Service Agreement (the “Amendment”) with Clayton W. Williams, Jr., Clayton Williams Ranch Holdings, Inc. (“Ranch Holdings”), Claydesta L.P. (“Claydesta”), The Williams Children’s Partnership, Ltd. (successor in interest to Clayton Williams Partnership, Ltd.) (“WCPL”), and CWPLCO, Inc. (“CWPLCO”, and collectively, the “Williams Entities”).  Ranch Holdings, Claydesta, and CWPLCO are controlled by Mr. Williams.  Mr. Williams is the Chairman of the Board, President, Chief Executive Officer and a director of the Company.  Mr. Williams beneficially owns, either individually or through his affiliates, approximately 26% of the outstanding shares of our common stock.  In addition, WCPL, a limited partnership of which Mr. Williams’ adult children are the limited partners, owns an additional 25% of the outstanding shares of our common stock.  L. Paul Latham, our Executive Vice President, Chief Operating Officer and a director of the Company, is the sole member of the general partner of WCPL.

The Company and the Williams Entities are parties to a Second Amended and Restated Service Agreement, dated as of March 1, 2005 (the “Service Agreement”).  Under the Service Agreement, the Williams Entities provide tax return preparation, tax planning and business entertainment services to the Company, and the Company provides legal, computer, payroll and benefits administration, insurance administration and general accounting services to the Williams Entities, as well as technical services with respect to the operation of certain oil and gas properties owned by the Williams Entities.  The Williams Entities also furnish hunting and fishing rights to the Company on lands owned by the Williams Entities pursuant to the terms of separate annual hunting leases.

The Amendment amends the Service Agreement to provide that from and after January 1, 2008, the effective date of the Amendment, the Company shall provide to the Williams Entities certain tax services that previously were performed by personnel of the tax department of the Williams Entities.  Pursuant to the Amendment, the Williams Entities will pay the Company for the use of the Company’s personnel involved in rendering tax services to the Williams Entities at the Company’s actual cost based on the salary and benefits received by such persons (assuming a 2,000 hour work year per person).  Also pursuant to the Amendment, the Williams Entities will reimburse the Company for certain general and administrative and incidental expenses incurred in rendering tax services to the Williams Entities.  The Amendment also amends the form of a hunting lease attached as an exhibit to the Service Agreement.

The Amendment was approved by the Company’s Audit Committee and by the full Board of Directors.

The foregoing description is only a summary of, and is qualified in its entirety by reference to, the Amendment, which is filed as Exhibit 10.26 to this Annual Report on Form 10-K and is incorporated herein by reference.  The Service Agreement was filed as Exhibit 99.1 to the Company’s Current Report on Form 8-K filed with the SEC on March 3, 2005, and is incorporated herein by reference.

Larclay JV

On March 13, 2009, we and Lariat entered into an Assignment and Assumption Agreement (the “Assignment”) pursuant to which Lariat has agreed to assign all of its right, title and interest in and to the Larclay JV to us effective as of April 15, 2009 (the “Effective Date”), and we have agreed to assume all of the obligations and liabilities of Lariat under the Larclay JV from and after the Effective Date, including Lariat’s obligations as operator of the Larclay JV drilling rigs.  The assignment from Lariat to us includes all of Lariat’s right, title and interest in the subordinated loans previously advanced by Lariat to Larclay JV.  Pursuant to the Assignment, we and Lariat have also agreed to indemnify each other for certain losses, and to waive certain claims (whether known or unknown) we may have against each other arising from the Larclay JV.  As a result of the transactions contemplated by the Assignment, as of the Effective Date, we will own a 100% interest in Larclay JV.

The foregoing description is only a summary of, and is qualified in its entirety by reference to, the Assignment, which is filed as Exhibit 10.74 to this Annual Report on Form 10-K and is incorporated herein by reference.

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PART III

Item 10 - -               Directors, Executive Officers and Corporate Governance

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, 2009.

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, 2009.

Item 12 -    Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

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, 2009.

Item 13 - -               Certain Relationships and Related Transactions, and Director Independence

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, 2009.

Item 14 - -               Principal Accounting 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, 2009.

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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
**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	Corporate Bylaws of Clayton Williams Energy, Inc., as amended, filed as Exhibit 3.1 to the Company’s Current Report on Form 8-K filed with the Commission on March 13, 2008††
**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††
**4.2	Indenture, dated July 20, 2005, among Clayton Williams Energy, Inc., the Subsidiary Guarantors and Wells Fargo Bank, National Association, as Trustee, filed as Exhibit 4.1 to the Company’s Current Report on Form 8-K filed with the Commission on July 22, 2005††
**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††

54

**10.2	First Amendment to Amended and Restated Credit Agreement dated July 18, 2005, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on July 20, 2005††
**10.3	Second Amendment to Amended and Restated Credit Agreement dated December 30, 2005, filed as Exhibit 10.3 to the Company’s Form 10-K for the period ended December 31, 2005††
**10.4	Third Amendment to Amended and Restated Credit Agreement dated June 30, 2006, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on July 14, 2006††
*10.5	Fourth Amendment to Amended and Restated Credit Agreement dated July 28, 2006
**10.6	Fifth Amendment to Amended and Restated Credit Agreement dated June 13, 2008, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on June 18, 2008††
**10.7	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††
**10.8†	1993 Stock Compensation Plan, filed as Exhibit 10.1 to the Company’s Form S-8 Registration Statement, Commission File No. 033-68318
**10.9†	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††
**10.10†	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
**10.11†	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
**10.12†	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
**10.13†	Fifth Amendment to 1993 Stock Compensation Plan, filed as Exhibit 10.13 to the Company’s Form 10-K for the period ended December 31, 2005††
**10.14†	Outside Directors Stock Option Plan, filed as Exhibit 10.1 to the Company’s Form S-8 Registration Statement, Commission File No. 33-68316
**10.15†	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††
**10.16†	Second 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, 2005††
**10.17†	Bonus Incentive Plan, filed as Exhibit 10.1 to the Company’s Form S-8 Registration Statement, Commission File No. 33-68320
**10.18†	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††
**10.19†	Scudder Trust Company Prototype Defined Contribution Plan adopted by Clayton Williams Energy, Inc. effective as of August 1, 2004, filed as Exhibit 10.12 to the Company’s Form 10-K for the period ended December 31, 2004††

55

**10.20†	Executive Incentive Stock Compensation Plan, filed as Exhibit 10.1 to the Company’s Form S-8 Registration Statement, Commission File No. 33-92834
**10.21†	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††
**10.22	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
**10.23	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††
**10.24	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
**10.25	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††
*10.26	Amendment to Second Amended and Restated Service Agreement effective January 1, 2008 among Clayton Williams Energy, Inc. and its subsidiaries, Clayton Williams, Jr., Clayton Williams Ranch Holdings, Inc., ClayDesta L.P., The Williams Children’s Partnership, Ltd. and CWPLCO, Inc.††
**10.27†	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††
**10.28†	Agreement of Limited Partnership of CWEI South Louisiana II, L.P. effective as of January 1, 2004, filed as Exhibit 10.29 to the Company’s Form 10-K for the period ended December 31, 2004††
**10.29†	Agreement of Limited Partnership of Rocky Arroyo, L.P. effective as of January 2, 2005, filed as Exhibit 10.31 to the Company’s Form 10-K for the period ended December 31, 2004††
**10.30†	Agreement of Limited Partnership of CWEI West Pyle/McGonagill, L.P. effective as of January 2, 2005, filed as Exhibit 10.33 to the Company’s Form 10-K for the period ended December 31, 2004††
**10.31†	Agreement of Limited Partnership of CWEI South Louisiana III, L.P. effective as of March 1, 2005, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on April 14, 2005††
**10.32†	Agreement of Limited Partnership of CWEI North Louisiana, L.P. effective as of March 1, 2005, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on April 14, 2005††

56

**10.33†	Agreement of Limited Partnership of Floyd Prospect, L.P. effective as of March 1, 2005, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on June 3, 2005††
**10.34†	Amendment to Agreement dated April 23, 1993 between the Company and Robert C. Lyon, filed as Exhibit 10.35 to the Company’s Form 10-K for the period ended December 31, 2004††
**10.35†	Second Amendment to Agreement dated April 23, 1993 between the Company and Robert C. Lyon, filed as Exhibit 10.36 to the Company’s Form 10-K for the period ended December 31, 2004††
**10.36†	Form of stock option agreement for 1993 Stock Compensation Plan, filed as Exhibit 10.32 to the Company’s Form 10-K for the period ended December 31, 2004††
**10.37†	Form of stock option agreement for Outside Directors Stock Option Plan, filed as Exhibit 10.38 to the Company’s Form 10-K for the period ended December 31, 2004††
**10.38	Letter agreement dated October 20, 2005 between Clayton Williams Energy, Inc. and Lariat Services, Inc., filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on October 27, 2005††
**10.39	Limited Liability Company Agreement, dated April 21, 2006, by and between Clayton Williams Energy, Inc. and Lariat Services, Inc., with respect to the formation of Larclay GP, LLC, a Texas limited liability company, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on April 26, 2006††
**10.40	Agreement of Limited Partnership, dated April 21, 2006, by and among Larclay GP, LLC, Clayton Williams Energy, Inc. and Lariat Services, Inc., with respect to the formation of Larclay, L.P., a Texas limited partnership, filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K filed with the Commission on April 26, 2006††
**10.41	Drilling Contract for Multiple Rigs, dated April 21, 2006, by and between Clayton Williams Energy, Inc. and Larclay, L.P., filed as Exhibit 10.3 to the Company’s Current Report on Form 8-K filed with the Commission on April 26, 2006††
**10.42	Subordination Agreement, dated April 21, 2006, by and among Clayton Williams Energy, Inc., Lariat Services, Inc. and Merrill Lynch Capital, as agent, filed as Exhibit 10.4 to the Company’s Current Report on Form 8-K filed with the Commission on April 26, 2006††
**10.43	Consent and Agreement, dated April 21, 2006, by and among Clayton Williams Energy, Inc., Lariat Services, Inc. and Merrill Lynch Capital, as agent, filed as Exhibit 10.5 to the Company’s Current Report on Form 8-K filed with the Commission on April 26, 2006††
**10.44	Letter of Credit, dated March 21, 2007, issued in favor of Merrill Lynch Capital, as agent, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on March 27, 2007††
**10.45	Form of Unconditional Limited Guaranty, to be issued by Clayton Williams Energy, Inc. in favor of Merrill Lynch Capital, as agent, filed as Exhibit 10.7 to the Company’s Current Report on Form 8-K filed with the Commission on April 26, 2006††

57

**10.46	Second Amendment to Term Loan and Security Agreement and Amendment to Limited Guaranty dated as of March 15, 2007 among Larclay, L.P., Clayton Williams Energy, Inc., Merrill Lynch Capital, as agent, and the other signatories thereto, filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K filed with the Commission on March 27, 2007††
**10.47†	Agreement of Limited Partnership of Floyd Prospect II, L.P. dated May 15, 2006., filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on May 17, 2006††
**10.48†	Participation Agreement relating to South Louisiana IV dated August 2, 2006, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on August 7, 2006††
**10.49†	Participation Agreement relating to North Louisiana — Hosston/Cotton Valley dated August 2, 2006, filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K filed with the Commission on August 7, 2006††
**10.50†	Participation Agreement relating to North Louisiana — Bossier dated August 2, 2006, filed as Exhibit 10.3 to the Company’s Current Report on Form 8-K filed with the Commission on August 7, 2006††
**10.51†	Participation Agreement relating to Floyd Prospect III dated November 15, 2006, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on November 17, 2006††
**10.52†	Participation Agreement relating to North Louisiana - Bossier II dated November 15, 2006, filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K filed with the Commission on November 17, 2006††
**10.53†	Participation Agreement relating to North Louisiana - Hosston/Cotton Valley II dated November 15, 2006, filed as Exhibit 10.3 to the Company’s Current Report on Form 8-K filed with the Commission on November 17, 2006††
**10.54†	Participation Agreement relating to South Louisiana V dated November 15, 2006, filed as Exhibit 10.4 to the Company’s Current Report on Form 8-K filed with the Commission on November 17, 2006††
**10.55†	Southwest Royalties Reward Plan dated January 15, 2007, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with Commission on January 18, 2007††
**10.56†	Form of Notice of Bonus Award Under the Southwest Royalties Reward Plan, filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K filed with the Commission on January 18, 2007††
**10.57†	Participation Agreement relating to West Coast Energy Properties, L.P. dated December 11, 2006, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on December 14, 2006††
**10.58†	Participation Agreement relating to RMS/Warnick dated April 10, 2007, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on April 13, 2007††
**10.59†	Participation Agreement relating to East Texas Bossier – Big Bill Simpson dated December 17, 2007, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on December 20, 2007††

58

**10.60†	Participation Agreement relating to East Texas Bossier – Margarita dated December 17, 2007, filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K filed with the Commission on December 20, 2007††
**10.61†	Amaker Tippett Reward Plan dated June 19, 2008, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on June 25, 2008††
**10.62†	Austin Chalk Reward Plan dated June 19, 2008, filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K filed with the Commission on June 25, 2008††
**10.63†	Barstow Area Reward Plan dated June 19, 2008, filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K filed with the Commission on June 25, 2008††
**10.64†	Participation Agreement relating to CWEI Andrews Area dated June 19, 2008, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on June 25, 2008††
**10.65†	Participation Agreement relating to CWEI Crockett County Area dated June 19, 2008, filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K filed with the Commission on June 25, 2008††
**10.66†	Participation Agreement relating to CWEI North Louisiana Bossier III dated June 19, 2008, filed as Exhibit 10.3 to the Company’s Current Report on Form 8-K filed with the Commission on June 25, 2008††
**10.67†	Participation Agreement relating to CWEI North Louisiana Hosston/Cotton Valley III dated June 19, 2008, filed as Exhibit 10.4 to the Company’s Current Report on Form 8-K filed with the Commission on June 25, 2008††
**10.68†	Participation Agreement relating to CWEI South Louisiana VI dated June 19, 2008, filed as Exhibit 10.5 to the Company’s Current Report on Form 8-K filed with the Commission on June 25, 2008††
**10.69†	Participation Agreement relating to CWEI Utah dated June 19, 2008, filed as Exhibit 10.6 to the Company’s Current Report on Form 8-K filed with the Commission on June 25, 2008††
**10.70†	Participation Agreement relating to CWEI Sacramento Basin I dated August 12, 2008, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on August 14, 2008††
*10.71†	Form of Director Indemnification Agreement
**10.72†	Participation Agreement relating to CWEI East Texas Bossier - Sunny dated November 19, 2008, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on November 20, 2008††
**10.73††	Beard Consulting Agreement dated December 1, 2008, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on December 2, 2008††
*10.74††	Assignment and Assumption Agreement between Lariat Services, Inc. and Clayton Williams Energy, Inc.

59

**21	Subsidiaries of the Registrant, filed as Exhibit 21 to the Company’s Form 10-Q for the period ended June 30, 2008
*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
***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
*** Furnished herewith
† 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.

60

GLOSSARY OF TERMS

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

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

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

Bcf.  One billion cubic feet.

Bcfe.  One billion cubic feet of natural gas equivalents.

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

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

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

Development well.  A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

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

Exploratory well.  A well drilled to find and produce oil or natural gas reserves not classified as proved, to find a new productive reservoir in a field previously found to be productive of oil or natural gas in another reservoir or to extend a known reservoir.

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

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

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

MBbls.  One thousand barrels.

Mcf.  One thousand cubic feet.

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

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

MMcf.  One million cubic feet.

MMcfe.  One million cubic feet of natural gas equivalents.

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

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

61

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, discounted at 10% annually, 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 (i) estimated future abandonment costs, net of the estimated salvage value of related equipment, (ii) nonproperty related expenses such as general and administrative expenses, debt service and future income tax expense, or (iii) depreciation, depletion and amortization.

Proved developed non-producing 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 non-producing 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 (PUD).  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.  Present value of proved reserves, as adjusted to give effect to (i) estimated future abandonment costs, net of the estimated salvage value of related equipment, and (ii) estimated future income taxes.

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.

62

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.

63

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

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

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature	Title	Date
/s/ CLAYTON W. WILLIAMS *	Chairman of the Board,	March 13, 2009
Clayton W. Williams	President and Chief Executive
	Officer and Director
/s/ L. PAUL LATHAM	Executive Vice President,	March 13, 2009
L. Paul Latham	Chief Operating Officer and
	Director
/s/ MEL G. RIGGS	Senior Vice President -	March 13, 2009
Mel G. Riggs	Finance, Secretary, Treasurer,
	Chief Financial Officer and Director
/s/ MICHAEL L. POLLARD	Vice President – Accounting and	March 13, 2009
Michael L. Pollard	Principal Accounting Officer
/s/ TED GRAY, JR.*	Director	March 13, 2009
Ted Gray, Jr.
/s/ DAVIS L. FORD *	Director	March 13, 2009
Davis L. Ford
/s/ ROBERT L. PARKER *	Director	March 13, 2009
Robert L. Parker
/s/ JORDAN R. SMITH *	Director	March 13, 2009
Jordan R. Smith
*        By:  /s/ L. PAUL LATHAM
L. Paul Latham
Attorney-in-Fact

64

CLAYTON WILLIAMS ENERGY, INC.

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

AND FINANCIAL STATEMENT SCHEDULES

	Page
Report of Independent Registered Public Accounting Firm	F-2
Consolidated Balance Sheets	F-3
Consolidated Statements of Operations	F-5
Consolidated Statements of Stockholders' Equity	F-6
Consolidated Statements of Cash Flows	F-7
Notes to Consolidated Financial Statements	F-8
Financial Statement Schedule Schedule II—Valuation and Qualifying Accounts	S-1

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, 2008 and 2007, 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, 2008. 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 the 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 audits 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, 2008 and 2007, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2008, 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, presents fairly, in all material respects, the information set forth therein.

As discussed in Note 2 of the consolidated financial statements, effective January 1, 2007, the Company adopted the provisions of Financial Accounting Standards Board Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” and effective January 1, 2008, the Company adopted Statement of Financial Accounting Standards No. 157, “Fair Value Measurements”, as it relates to financial instruments.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Clayton Williams Energy, Inc.’s internal control over financial reporting as of December 31, 2008, 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 16, 2009 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

KPMG LLP

Dallas, Texas

March 16, 2009

F-2

CLAYTON WILLIAMS ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

ASSETS
	December 31,
	2008			2007
CURRENT ASSETS
Cash and cash equivalents	$	41,199		$	12,344
Accounts receivable:
Oil and gas sales		26,009			36,698
Joint interest and other, net		14,349			16,666
Affiliates		227			308
Inventory		20,052			14,348
Deferred income taxes		3,637			3,581
Fair value of derivatives		-			7,191
Assets held for sale		-			17,281
Prepaids and other		20,011			3,962
		125,484			112,379
PROPERTY AND EQUIPMENT
Oil and gas properties, successful efforts method		1,526,473			1,374,090
Natural gas gathering and processing systems		17,816			18,404
Contract drilling equipment		91,151			89,956
Other		14,954			14,505
		1,650,394			1,496,955
Less accumulated depreciation, depletion and amortization		(840,366	)		(765,877	)
Property and equipment, net		810,028			731,078
OTHER ASSETS
Debt issue costs, net		6,225			6,963
Other		1,672			10,676
		7,897			17,639
	$	943,409		$	861,096

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

F-3

CLAYTON WILLIAMS ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

LIABILITIES AND STOCKHOLDERS' EQUITY
	December 31,
	2008		2007
CURRENT LIABILITIES
Accounts payable:
Trade	$	67,189	$	72,477
Oil and gas sales		24,702		24,806
Affiliates		1,627		1,747
Current maturities of long-term debt		18,750		22,500
Fair value of derivatives		-		56,929
Accrued liabilities and other		10,609		10,308
		122,877		188,767
NON-CURRENT LIABILITIES
Long-term debt		347,225		430,175
Deferred income taxes		120,414		44,302
Other		38,211		37,046
		505,850		511,523
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS’ EQUITY
Preferred stock, par value $.10 per share, authorized – 3,000,000
shares; none issued		-		-
Common stock, par value $.10 per share, authorized – 30,000,000
shares; issued and outstanding – 12,115,898 shares in 2008
and 11,354,051 shares in 2007		1,212		1,135
Additional paid-in capital		137,046		121,063
Retained earnings		176,424		35,890
Accumulated other comprehensive income, net of tax		-		2,718
		314,682		160,806
	$	943,409	$	861,096

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

F-4

CLAYTON WILLIAMS ENERGY, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share)

	Year Ended December 31,
	2008			2007			2006
REVENUES
Oil and gas sales	$	463,964		$	316,992		$	245,967
Natural gas services		10,926			10,230			11,327
Drilling rig services		46,124			52,649			6,937
Gain on sales of property and equipment		44,503			14,024			1,767
Total revenues		565,517			393,895			265,998
COSTS AND EXPENSES
Production		89,054			75,319			63,298
Exploration:
Abandonments and impairments		80,112			68,870			65,173
Seismic and other		22,685			4,765			11,299
Natural gas services		10,060			9,745			10,005
Drilling rig services		37,789			32,964			4,538
Depreciation, depletion and amortization		120,542			84,476			66,163
Impairment of property and equipment		12,882			12,137			21,848
Accretion of abandonment obligations		2,355			2,508			1,653
General and administrative		25,635			19,266			16,676
Loss on sales of property and equipment		2,122			9,815			99
Total costs and expenses		403,236			319,865			260,752
Operating income		162,281			74,030			5,246
OTHER INCOME (EXPENSE)
Interest expense		(24,994	)		(32,118	)		(20,895	)
Gain (loss) on derivatives		74,743			(31,968	)		37,340
Other		6,539			5,355			(1,339	)
Total other income (expense)		56,288			(58,731	)		15,106
Income before income taxes and minority interest		218,569			15,299			20,352
Income tax expense		(77,327	)		(5,497	)		(1,979	)
Minority interest, net of tax		(708	)		(3,812	)		(574	)
NET INCOME	$	140,534		$	5,990		$	17,799
Net income per common share:
Basic	$	11.78		$	.53		$	1.64
Diluted	$	11.67		$	.52		$	1.58
Weighted average common shares outstanding:
Basic		11,932			11,337			10,885
Diluted		12,039			11,494			11,244

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

F-5

CLAYTON WILLIAMS ENERGY, INC.

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY

(In thousands)

									Accumulated
									Other			Total
	Common Stock				Additional				Compre-			Compre-
	No. of		Par		Paid-In		Retained		hensive			hensive
	Shares		Value		Capital		Earnings		Income			Income
BALANCE,
December 31, 2005		10,815	$	1,082	$	107,108	$	12,101	$	-
Net income and total
comprehensive income		-		-		-		17,799		-		$	17,799
Issuance of stock through
compensation plans, including
income tax benefits		337		33		6,857		-		-
BALANCE,
December 31, 2006		11,152		1,115		113,965		29,900		-
Net income		-		-		-		5,990		-		$	5,990
Unrealized gain on
marketable securities,
net of tax of $1,464		-		-		-		-		2,718			2,718
Total comprehensive
income												$	8,708
Issuance of stock through
compensation plans, including
income tax benefits		202		20		7,098		-		-
BALANCE,
December 31, 2007		11,354		1,135		121,063		35,890		2,718
Net income		-		-		-		140,534		-		$	140,534
Unrealized gain on
marketable securities,
net of tax of $2,015		-		-		-		-		3,742			3,742
Reclassification adjustment for
securities gains included
in income, net of tax of $3,479		-		-		-		-		(6,460	)		-
Total comprehensive
income												$	144,276
Issuance of stock through
compensation plans, including
income tax benefits		762		77		15,983		-		-
BALANCE,
December 31, 2008		12,116	$	1,212	$	137,046	$	176,424	$	-

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

F-6

CLAYTON WILLIAMS ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

	Year Ended December 31,
	2008			2007			2006
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	140,534		$	5,990		$	17,799
Adjustments to reconcile net income to cash
provided by operating activities:
Depreciation, depletion and amortization		120,542			84,476			66,163
Impairment of property and equipment		12,882			12,137			21,848
Exploration costs		80,112			68,870			65,173
Gain on sales of property and equipment, net		(42,381	)		(4,209	)		(1,668	)
Deferred income taxes		77,327			3,768			215
Non-cash employee compensation		5,834			1,865			2,279
Unrealized (gain) loss on derivatives		(49,738	)		24,249			(57,568	)
Settlements on derivatives with financing elements		43,486			28,468			29,407
Amortization of debt issue costs		1,354			1,281			1,308
Accretion of abandonment obligations		2,355			2,508			1,653
Excess tax benefit on exercise of stock options		-			(963	)		(1,807	)
Minority interest, net of tax		708			3,812			574
Changes in operating working capital:
Accounts receivable		13,087			(10,028	)		(8,101	)
Accounts payable		(4,946	)		10,992			3,543
Other		(19,176	)		1,650			5,172
Net cash provided by operating activities		381,980			234,866			145,990
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to property and equipment		(350,106	)		(233,453	)		(254,840	)
Additions to equipment of Larclay JV		(1,683	)		(29,302	)		(60,655	)
Proceeds from sales of property and equipment		117,226			22,773			4,451
Change in equipment inventory		(8,247	)		18,166			(662	)
Other		3,935			(14,443	)		1,753
Net cash used in investing activities		(238,875	)		(236,259	)		(309,953	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt		-			25,800			129,300
Proceeds from long-term debt of Larclay JV		7,500			8,727			66,254
Repayments of long-term debt		(71,700	)		-			-
Repayments of long-term debt of Larclay JV		(22,500	)		(13,125	)		-
Proceeds from sale of common stock		15,936			6,000			3,914
Settlements on derivatives with financing elements		(43,486	)		(28,468	)		(29,407	)
Excess tax benefit on exercise of stock options		-			963			1,807
Net cash provided by (used in) financing activities		(114,250	)		(103	)		171,868
NET INCREASE (DECREASE) IN CASH AND
CASH EQUIVALENTS		28,855			(1,496	)		7,905
CASH AND CASH EQUIVALENTS
Beginning of period		12,344			13,840			5,935
End of period	$	41,199		$	12,344		$	13,840
SUPPLEMENTAL DISCLOSURES
Cash paid for interest, net of amounts capitalized	$	24,027		$	35,213		$	19,653
Cash paid for income taxes	$	16,652		$	348		$	196

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

F-7

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” or “CWEI”) is an independent oil and gas company engaged in the exploration for and development and production of oil and natural gas primarily in its core areas in Texas, Louisiana and New Mexico.  Approximately 26% of the Company’s outstanding common stock is beneficially owned by Clayton W. Williams, Jr. (“Mr. Williams”), Chairman of the Board and Chief Executive Officer of the Company, and approximately 25% is owned by a partnership in which Mr. Williams’ adult children are limited partners.

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, the relative strength of the U.S. dollar, 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 periods.  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 abandonment obligations.

Principles of Consolidation

The consolidated financial statements include the accounts of Clayton Williams Energy, Inc., its wholly-owned subsidiaries and the accounts of the Larclay JV (see Note 11).  The Company also accounts for its undivided interests in oil and gas limited partnerships using the proportionate consolidation method.  Under this method, the Company consolidates its proportionate share of assets, liabilities, revenues and expenses of these limited partnerships utilizing accounting policies followed by the Company.  Less than 5% of the Company’s consolidated total assets and total revenues are derived from oil and gas limited partnerships.  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 of properties are credited to property costs, and a gain or loss is recognized when a significant portion of an amortization base is sold or abandoned.

F-8

CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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 Systems 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 repairs and maintenance are charged to expense as incurred.  The cost 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 operating 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 20 years.

Contract Drilling

The Company consolidates the accounts of Larclay JV (see Note 11), a joint venture engaged in contract drilling of oil and gas wells.  Larclay recognizes revenues and expenses from daywork drilling contracts as the work is performed, but defers revenues and expenses from footage or turnkey contracts until the well is substantially completed or until a loss, if any, on a contract is determinable.

Property and equipment, including major replacements, improvements and capitalized interest on construction-in-progress, are capitalized and are depreciated using the straight-line method over estimated useful lives of 3 to 7 years.  Upon disposition, the costs and related accumulated depreciation of assets are eliminated from the accounts and the resulting gain or loss is recognized.

Valuation of Property and Equipment

The Company follows the provisions of Statement of Financial Accounting Standards (“SFAS”) 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, and contract drilling equipment, 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 difference 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 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 impairing the costs of such properties within appropriate groups based on the Company's historical experience, acquisition dates and average lease terms.  The valuation of unproved properties is subjective and requires management of the Company to make estimates and assumptions which, with the passage of time, may prove to be materially different from actual realizable values.

Abandonment Obligations

The Company follows the provisions of SFAS 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 associated with the abandonment obligation, along with any estimated salvage value, is included in the computation of depreciation, depletion and amortization.

F-9

CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Income Taxes

The Company follows the asset and liability method prescribed by SFAS 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.  Effective January 1, 2008, the Company adopted FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes”  - “An Interpretation of FASB Statement No. 109” (“FIN 48”).  FIN 48 clarifies financial statement recognition and disclosure requirements for uncertain tax positions taken or expected to be taken in a tax return.  Financial statement recognition of the tax position is dependent on an assessment of a 50% or greater likelihood that the tax position will be sustained upon examination, based on the technical merits of the position.  Any interest and penalties related to uncertain tax positions are recorded as interest expense. 

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 SFAS No. 133 “Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”), as amended.  SFAS No. 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 is 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 gain (loss) on derivatives.

Inventory

Inventory consists primarily of tubular goods and other well equipment which the Company plans to utilize in its exploration and development activities and is stated at the lower of average cost or estimated 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, 2008, 2007 and 2006, the Company capitalized interest totaling approximately $3.8 million, $4.2 million and $5.8 million, respectively.  In addition, the Company capitalized interest relating to the construction of drilling rigs in the Larclay JV of $2 million in 2007.

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 net income (loss) per share is computed by dividing net income (loss) by the weighted average number of common shares outstanding for the period.  Diluted net income per share reflects the potential dilution that could occur if dilutive stock options were exercised, calculated using the treasury stock method.  The diluted net income per share calculations for 2008, 2007 and 2006 include an increase in potential shares attributable to dilutive stock options.

F-10

CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Marketable Securities

All marketable equity securities are included in other non-current assets and are considered available-for-sale securities carried at fair value, in accordance with SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities”. The unrealized gains and losses related to these securities are included in accumulated other comprehensive income.  The fair values are based on quoted market prices.

Stock-Based Compensation

Effective January 1, 2006, the Company adopted SFAS No. 123 (revised 2004) “Share-Based Payment,” (“SFAS 123R”) which requires the measurement and recognition of compensation expense for all share-based payment awards, including employee stock options, based on estimated fair values. The value of the portion of the award that is ultimately expected to vest is recognized as expense on a straight-line basis over the requisite service periods.  SFAS 123R supersedes the Company’s previous accounting under Accounting Principles Board Opinion No. 25 “Accounting for Stock Issued to Employees” (“APB 25”) for periods beginning in 2006.

SFAS 123R requires the Company to estimate the fair value of stock option awards on the date of grant using an option-pricing model.  The Company uses the Black-Scholes option-pricing model (“Black-Scholes Model”) as its method of valuation for share-based awards granted on or after January 1, 2006, which is the same model used for the Company’s pro forma information required under SFAS 123.  The Company’s determination of fair value of share-based payment awards on the date of grant using an option-pricing model is affected by the Company’s stock price, as well as assumptions regarding a number of subjective variables.  These variables include, but are not limited to, the Company’s expected stock price volatility over the term of the awards, as well as actual and projected exercise and forfeiture activity.

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, 2008 or 2007.  Revenues from natural gas services are recognized as services are provided.

Comprehensive Income

SFAS 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.  In 2007, the Company reported an unrealized gain on marketable securities as comprehensive income.  There were no differences between net income and comprehensive income in 2008 or 2006.

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, 2008 and 2007 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

In December 2008, the Securities and Exchange Commission (“SEC”) released Final Rule, “Modernization of Oil and Gas Reporting”. The new disclosure requirements include provisions that permit the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes. The new requirements also will allow companies to disclose their probable and possible reserves to investors. In addition, the new disclosure requirements require companies to: (i) report the independence and qualifications of its reserves preparer or auditor, (ii) file reports when a third party is relied upon to prepare reserves estimates or conducts a reserves audit, and (iii) report oil and gas reserves using an average price based upon the prior 12-month period rather than year-end prices. The new disclosure requirements are effective for financial statements for fiscal years ending on or after December 31, 2009. The effect of adopting

F-11

CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

the SEC rule has not been determined, but it is not expected to have a significant effect on our reported financial position or results of operations.

In March 2008, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133” (“SFAS 161”). This statement is intended to improve transparency in financial reporting by requiring enhanced disclosures of an entity’s derivative instruments and hedging activities and their effects on the entity’s financial position, financial performance, and cash flows. SFAS 161 applies to all derivative instruments within the scope of SFAS 133 as well as related hedged items, bifurcated derivatives, and non-derivative instruments that are designated and qualify as hedging instruments. Entities with instruments subject to SFAS 161 must provide more robust qualitative disclosures and expanded quantitative disclosures. SFAS 161 is effective prospectively for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application permitted.  The Company is currently evaluating the disclosure implications of this statement.

In December 2007, the FASB issued SFAS No. 141R, “Business Combinations” (“SFAS 141R”) and SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements” (“SFAS 160”). SFAS 141R requires most identifiable assets, liabilities, noncontrolling interests, and goodwill acquired in a business combination to be recorded at “fair value.” The Statement applies to all business combinations, including combinations among mutual entities and combinations by contract alone. Under SFAS 141R, all business combinations will be accounted for by applying the acquisition method. SFAS 141R is effective for periods beginning on or after December 15, 2008. SFAS 160 will require noncontrolling interests (previously referred to as minority interests) to be treated as a separate component of equity, not as a liability or other item outside of permanent equity.  The statement applies to the accounting for noncontrolling interests and transactions with noncontrolling interest holders in consolidated financial statements. SFAS 160 is effective for periods beginning on or after December 15, 2008 and will be applied prospectively to all noncontrolling interests, including any that arose before the effective date except that comparative period information must be recast to classify noncontrolling interests in equity, attribute net income and other comprehensive income to noncontrolling interests, and provide other disclosures required by SFAS 160.  The impact on our financial statements from the adoption of SFAS 141R and SFAS 160 in 2009 will depend on future acquisition activity.

In November 2007, FASB Staff Position No. 157-2 (“FSP 157-2”) was issued. FSP 157-2 delays the effective date of adoption of SFAS No. 157, “Fair Value Measurements (as amended)” (SFAS 157), for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). The Company adopted the non-deferred provisions of SFAS 157 on January 1, 2008 (See Note 8).  FSP 157-2 defers the effective date to fiscal years beginning after November 15, 2008. The effect of adopting FSP 157-2 is not expected to have an effect on our reported financial position or results of operations.

3.         Long-Term Debt

Long-term debt consists of the following:

	December 31,			December 31,
	2008			2007
	(In thousands)
7¾% Senior Notes due 2013	$	225,000		$	225,000
Secured bank credit facility, due May 2012		94,100			165,800
Secured term loan of Larclay JV, due June 2011		39,375			61,875
Subordinated notes of Larclay JV(a)		7,500			-
		365,975			452,675
Less current maturities(b)		(18,750	)		(22,500	)
	$	347,225		$	430,175

(a)Note payable to Lariat Services Inc. (See Note 11).

(b)Amounts in both periods relate to the current portion of the term loan of Larclay JV.

Aggregate maturities of long-term debt at December 31, 2008 are as follows:  2009 - $18.8 million; 2010 - $22.5 million; 2011 - $5.6 million; 2012 - $94.1 million; and 2013 - $225 million.

F-12

CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

7¾% Senior Notes due 2013

In July 2005, the Company issued, in a private placement, $225 million of aggregate principal amount of 7¾% Senior Notes due 2013 (“Senior Notes”).  The Senior Notes were issued at face value and bear interest at 7¾% per year, payable semi-annually on February 1 and August 1 of each year, beginning February 1, 2006.

At any time prior to August 1, 2009, the Company may redeem some or all of the Senior Notes at a redemption price equal to 100% of the principal amount of the Senior Notes to be redeemed, plus a make-whole premium, plus any accrued and unpaid interest.  On and after August 1, 2009, the Company may redeem some or all of the Senior Notes at redemption prices (expressed as percentages of principal amount) equal to 103.875% for the twelve-month period beginning on August 1, 2009, 101.938% for the twelve-month period beginning on August 1, 2010, and 100.00% beginning on August 1, 2011 or for any period thereafter, in each case plus accrued and unpaid interest.

The Indenture governing the Senior Notes contains covenants that restrict the ability of the Company and its restricted subsidiaries to:  (i) borrow money; (ii) issue redeemable and preferred stock; (iii) pay distributions or dividends; (iv) make investments; (v) create liens without securing the Senior Notes; (vi) enter into agreements that restrict dividends from subsidiaries; (vii) sell certain assets or merge with or into other companies; (viii) enter into transactions with affiliates; (ix) guarantee indebtedness; and (x) enter into new lines of business.  One such covenant prohibits the Company from borrowing any additional funds under the revolving credit facility if the Company’s outstanding balance on the facility exceeds 30% of Adjusted Consolidated Net Tangible Assets, as defined in the Indenture.  The Company was in compliance with these covenants at December 31, 2008.

Secured Bank Credit Facility

The Company’s secured bank credit facility provides for a revolving loan facility in an amount not to exceed the lesser of the borrowing base, as established by the banks, or that portion of the borrowing base determined by the Company to be the elected borrowing limit.  The borrowing base, which is based on the discounted present value of future net revenues from oil and gas production, is subject to redetermination at any time, but at least semi-annually in May and November, and is made at the discretion of the banks.  If, at any time, the redetermined borrowing base is less than the amount of outstanding indebtedness, the Company will be required to (i) pledge additional collateral, (ii) prepay the excess in not more than five equal monthly installments, or (iii) elect to convert the entire amount of outstanding indebtedness to a term obligation based on amortization formulas set forth in the loan agreement.  Substantially all of the Company’s oil and gas properties are pledged to secure advances under the credit facility.  In June 2008, the Company elected to maintain the borrowing base at $250 million instead of increasing it to levels supported by the collateral values assigned by the banks.  After allowing for outstanding letters of credit totaling $804,000, the Company had $155.1 million available under the credit facility at December 31, 2008.

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.  Interest and fees are payable at least quarterly.  The effective annual interest rate on borrowings under the combined credit facility, excluding bank fees and amortization of debt issue costs, for the year ended December 31, 2008 was 4.7%.

The loan agreement applicable to the revolving credit facility contains 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.  Another financial covenant under the credit facility requires the Company to maintain a ratio of indebtedness to cash flow of no more than 3 to 1.  The computations of current assets, current liabilities, cash flow and indebtedness are defined in the loan agreement.  The Company was in compliance with all financial and non-financial covenants at December 31, 2008.

Secured Term Loan of Larclay JV

In connection with the Company’s investment in Larclay JV (see Note 11), Larclay JV obtained a $75 million secured term loan facility from a lender to finance the construction and equipping of 12 new drilling rigs.  The Larclay JV term loan is secured by substantially all of the assets of Larclay JV.  As additional credit support, the Company granted the lender a limited guaranty in the original amount of $19.5 million.  The maximum obligation under the guaranty reduces by 10% on April 1 of each year, beginning April 1, 2008.  At December 31, 2008, the maximum obligation of the Company under the guaranty is approximately $17.6 million.  The Company is required to fully consolidate the accounts of Larclay JV under FASB Interpretation No. 46R “Consolidation of Variable Interest Entities – an Interpretation of ARB No. 51 (as amended)” (“FIN 46R”).

F-13

CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The Larclay JV term loan, bears interest at a floating rate based on a LIBOR average, plus 3.25%, and provides for monthly principal and interest payments sufficient to retire the principal balance by 35% in the first year, 25% in each of the next two years, and 15% in the fourth year.  The Larclay JV term loan prohibits Larclay JV from making any cash distributions to the Company or Lariat until the balance on the term loan is fully repaid, and repayments by Larclay JV of any loans by the Company or Lariat are subordinated to the loans outstanding under the term loan and are subject to other restrictions.  At December 31, 2008, the effective annual interest rate on the Larclay JV term loan was 6.4%.

4.         Other Non-Current Liabilities

Other non-current liabilities at December 31, 2008 and 2007 consist of the following:

	2008		2007
	(In thousands)
Abandonment obligations	$	31,737	$	30,994
Minority interest, net of tax		5,594		4,886
Other taxes payable		145		358
Other		735		808
	$	38,211	$	37,046

Abandonment Obligations

Changes in abandonment obligations for 2008 and 2007 are as follows:

	2008			2007
	(In thousands)
Beginning of year	$	30,994		$	27,846
Additional abandonment obligations from new wells		1,780			936
Sales of properties		(1,991	)		(1,726	)
Accretion expense		2,355			2,508
Revisions of previous estimates		(1,401	)		1,430
End of year	$	31,737		$	30,994

5.         Income Taxes

Deferred tax assets and liabilities are the result of temporary differences between the financial statement carrying values and the tax bases of assets and liabilities.  Significant components of net deferred tax assets (liabilities) at December 31, 2008 and 2007 are as follows:

	2008			2007
	(In thousands)
Deferred tax assets:
Net operating loss carryforwards	$	9,033		$	-
Fair value of derivatives		-			17,224
Statutory depletion carryforwards		6,096			5,366
Alternative minimum tax credit carryforwards		437			437
Other		301			11,132
		15,867			34,159
Deferred tax liabilities:
Property and equipment		(108,903	)		(74,880	)
Tax deferred derivative settlements and other		(23,741	)		-
		(132,644	)		(74,880	)
Net deferred tax liabilities	$	(116,777	)	$	(40,721	)
Components of net deferred tax assets (liabilities):
Current assets	$	3,637		$	3,581
Non-current liabilities		(120,414	)		(44,302	)
	$	(116,777	)	$	(40,721	)

F-14

CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the years ended December 31, 2008, 2007 and 2006, the Company’s effective income tax rates were different than the statutory federal income tax rates for the following reasons:

	2008			2007			2006
	(In thousands)
Income tax expense at statutory rate of 35%	$	76,500		$	5,355		$	7,123
Tax depletion in excess of basis		(700	)		(700	)		(700	)
Revision of previous tax estimates		55			16			(152	)
State income taxes, net of federal tax effect		1,375			738			(4,429	)
Other		97			88			137
Income tax expense	$	77,327		$	5,497		$	1,979
Current	$	12		$	1,729		$	1,764
Deferred		77,315			3,768			215
Income tax expense	$	77,327		$	5,497		$	1,979

The Company derives a tax deduction when employees and directors exercise options granted under the Company’s stock option plans.  To the extent these tax deductions are used to reduce currently payable taxes in any period, the Company records a tax benefit for the excess of the tax deduction over cumulative book compensation expense as additional paid-in capital and as a financing cash flow in the accompanying consolidated financial statements.  At December 31, 2008, the Company’s cumulative tax loss carryforwards were approximately $25.8 million.

 The Company and its subsidiaries file federal income tax returns with the United States Internal Revenue Service (“IRS”) and state income tax returns in various state tax jurisdictions.  As a general rule, the Company’s tax returns for fiscal years after 2004 currently remain subject to examination by appropriate taxing authorities.  None of the Company’s income tax returns are under examination at this time.

 In December 2008, the Company made an estimated federal income tax payment of $16 million.  Currently, the Company does not expect to owe any federal income tax on its 2008 income tax return and plans to request a refund of overpaid taxes upon filing of the return.  Accordingly, this $16 million claim for refund is classified in the accompanying balance sheet as prepaid expenses and other current assets.

 Upon adoption of FIN 48, the Company recorded a liability for taxes payable related to unrecognized tax benefits arising from uncertain tax positions taken by the Company in previous periods.  A reconciliation of the changes in this tax liability during the years ended December 31, 2008 and December 31, 2007 is as follows in thousands:

Balance at December 31, 2006	$	-
Adoption of FIN 48 on January 1, 2007		1,585
Reductions for tax positions of prior years		(1,227	)
Balance at December 31, 2007		358
Reductions for tax positions of prior years		(214	)
Balance at December 31, 2008	$	144

No unrecognized tax benefits originated during 2008.  Reductions in this tax liability resulted from changes in accounting methods which were submitted to the taxing authority during 2007.  All of the remaining unrecognized tax benefits at December 31, 2008 relate to tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductions.  Because of the impact of deferred tax accounting, the disallowance of the shorter deduction period would not affect the annual effective tax rate but would only accelerate the payment of taxes to the taxing authority or change the amount of deferred tax assets related to net operating loss carryforwards.

F-15

CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 Tax liabilities recorded under FIN 48 are included in other non-current liabilities in the accompanying consolidated financial statements, and any interest and penalties accrued on unrecognized tax benefits are recorded as interest expense in the accompanying statements of operations.  However, due to the Company’s net operating loss carryforwards, no interest or penalties have been accrued on the Company’s unrecognized tax benefits.

6.         Assets Held For Sale

 At December 31, 2007, the Company had $17.3 million in assets held for sale, which included $15.8 million for the estimated fair value of two 2,000 horsepower drilling rigs and related components and $1.5 million for well service equipment that the Company has designated as held for sale assets under SFAS 144.  In connection with the determination to sell these assets, the Company recorded an $8.2 million charge which was included in impairment of property and equipment in 2007.  These assets were sold during the second quarter of 2008 (See Note 15).

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.  In floor transactions, 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 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 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. Commodity derivatives are settled monthly as the contract production periods mature.

 In December 2008, the Company terminated all of its existing oil and gas derivative contracts for cash proceeds of $99.3 million.  The terminated contracts covered approximately 2.6 million barrels of oil and 15.2 million MMBtu of gas production for the months of January 2009 through December 2010.  Proceeds from these transactions were used to repay a portion of the Company’s outstanding bank indebtedness.

The following summarizes information concerning the Company’s net positions in open commodity derivatives applicable to periods subsequent to December 31, 2008, all of which were entered into after December 31, 2008.  The settlement prices of commodity derivatives are based on NYMEX futures prices.

Swaps:

	Gas				Oil
	MMBtu (a)		Price		Bbls		Price
Production Period:
1st Quarter 2009		1,180,000	$	5.47		160,000	$	46.39
2nd Quarter 2009		1,570,000	$	5.47		470,000	$	49.68
3rd Quarter 2009		1,450,000	$	5.47		440,000	$	48.13
4th Quarter 2009		1,850,000	$	5.47		400,000	$	46.15
2010		7,540,000	$	6.80		327,000	$	53.30
2011		6,420,000	$	7.07		-	$	-
		20,010,000				1,797,000

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

F-16

CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Accounting for Derivatives

The Company accounts for its derivatives in accordance with SFAS 133.  The Company did not designate any of its currently open commodity or interest rate derivatives 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 the year ended December 31, 2008, the Company reported a $74.7 million net gain on derivatives, consisting of a $49.7 million gain related to changes in mark-to-market valuations and a $25 million gain for settled contracts.  For the year ended December 31, 2007, the Company reported a $32 million net loss on derivatives, consisting of a $24.3 million loss related to changes in mark-to-market valuations and a $7.7 million cash charge for settled contracts.

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 Company’s secured bank credit facility was estimated to have a fair value approximating the carrying amount since the interest rate is generally market sensitive.  The estimated fair value of the Company’s Senior Notes at December 31, 2008 and 2007 was approximately $126 million and $196.9 million; respectively, based on market valuations.

Determination of Fair Value

The Company adopted SFAS No. 157, “Fair Value Measurements (as amended)” (“SFAS 157”) effective January 1, 2008.  SFAS 157 defines fair value, establishes a framework for measuring fair value, outlines a fair value hierarchy based on the quality of inputs used to measure fair value and enhances disclosure requirements for fair value measurements.  As permitted by FSP No. 157-2, the Company has not applied the provisions of SFAS 157 to nonfinancial assets and liabilities.  The Company has not applied the provisions of SFAS 157 to its asset retirement obligations.

Fair value is defined as the price at which an asset could be exchanged in a current transaction between knowledgeable, willing parties at the measurement date. Where available, fair value is based on observable market prices or parameters or derived from such prices or parameters. Where observable prices or inputs are not available, use of unobservable prices or inputs are used to estimate the current fair value, often using an internal valuation model. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the item being valued.

In accordance with SFAS 157, the Company categorizes its assets and liabilities recorded at fair value in the accompanying consolidated balance sheets based upon the level of judgment associated with the inputs used to measure their fair value. Hierarchical levels, defined by SFAS 157 and directly related to the amount of subjectivity associated with the inputs to fair valuation of these assets and liabilities, are as follows:

Level 1 - Inputs are unadjusted, quoted prices in active markets for identical assets or liabilities at the measurement date.

Level 2 - Inputs (other than quoted prices included in Level 1) are either directly or indirectly observable for the asset or liability through correlation with market data at the measurement date and for the duration of the instrument’s anticipated life.

Level 3 - Inputs reflect management’s best estimate of what market participants would use in pricing the asset or liability at the measurement date. Consideration is given to the risk inherent in the valuation technique and the risk inherent in the inputs to the model.

F-17

CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The fair value of the Company’s investment in common stock of SandRidge Energy Inc. (see Note 11) is measured using Level 1 inputs, and is determined by market prices on an active market.

The fair value of derivative contracts are measured using Level 2 inputs, and are determined by either market prices on an active market for similar assets or by prices quoted by a broker or other market-corroborated prices.

The estimated fair values of assets and liabilities included in the accompanying consolidated balance sheet at December 31, 2007 are summarized below.  At December 31, 2008, the Company had closed all of its then existing commodity and interest derivatives and sold its investment in SandRidge Energy Inc. (see Note 11).

	Fair Value Measurements
	December 31, 2007
	Quoted Prices In		Significant
	Active Markets For		Other
	Identical		Observable
	Assets/Liabilities		Inputs
Description	Level 1		Level 2
	(In thousands)
Assets:
Fair value of commodity
derivatives	$	-	$	7,191
Investment securities		7,188		-
Total assets	$	7,188	$	7,191
Liabilities:
Fair value of derivatives:
Commodity derivatives	$	-	$	55,885
Interest rate derivatives		-		1,044
Total liabilities	$	-	$	56,929

9.         Compensation Plans

Stock-Based Compensation

The Company has reserved 1,798,200 shares of common stock for issuance under the 1993 Stock Compensation Plan (“1993 Plan”).  The 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, 2008 expire 10 years from the date of grant and become exercisable based on varying vesting schedules.  The Company issues new shares, not repurchased shares, to option holders that exercise stock options under the 1993 Plan.  At December 31, 2008, 101,766 shares remain available for issuance under this plan.

The Company has reserved 86,300 shares of common stock for issuance under the Outside Directors Stock Option Plan (“Directors Plan”).  Since the inception of the Directors Plan, the Company has issued options covering 52,000 shares of common stock at option prices ranging from $3.25 to $41.74 per share.  All outstanding options expire 10 years from the grant date and are fully exercisable upon issuance.  At December 31, 2008, 34,300 shares remain available for issuance under this plan.  Effective January 1, 2009, no additional grants of options will be made under the Directors Plan.

F-18

CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The following table sets forth certain information regarding the Company’s stock option plans as of and for the year ended December 31, 2008:

						Weighted
				Weighted		Average
				Average		Remaining		Aggregate
				Exercise		Contractual		Intrinsic
	Shares			Price		Term		Value (a)
Outstanding at January 1, 2008		811,485		$	20.49
Granted		4,000		$	31.16
Exercised (b)		(761,847	)	$	20.92
Outstanding at December 31, 2008		53,638		$	15.20		2.68	$	1,621,838
Vested at December 31, 2008		53,638		$	15.20		2.68	$	1,621,838
Exercisable at December 31, 2008		53,638		$	15.20		2.68	$	1,621,838
(a) Based on closing price at December 31, 2008 of $45.44 per share and $31.16 per share at December 31, 2007.
(b) Cash received for options exercised totaled $15.9 million in 2008 and $6 million in 2007.

 The following table summarizes information with respect to options outstanding at December 31, 2008, all of which are currently exercisable.

	Outstanding and Exercisable Options
			Weighted
		Weighted	Average
		Average	Remaining
		Exercise	Life in
	Shares	Price	Years
Range of exercise prices:
$5.50	27,638	$ 5.50	.3
$10.00 - $19.74	8,000	$ 12.42	2.9
$22.90 - $41.74	18,000	$ 31.34	6.2
	53,638	$ 15.20	2.7

The following table presents certain information regarding stock-based compensation amounts for the years ended December 31, 2008, 2007 and 2006.

	2008			2007			2006
	(In thousands, except per share)
Weighted average grant date fair value of options granted per share	$	23.06		$	27.56		$	31.91
Intrinsic value of options exercised	$	20,480		$	261		$	9,725
Stock-based employee compensation expense	$	92		$	110		$	128
Tax benefit		(32	)		(38	)		(45	)
Net stock-based employee compensation expense	$	60		$	72		$	83

F-19

CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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 following weighted average assumptions were used in this model.

	2008	2007	2006
Risk-free interest rate	4%	4.7%	4.4%
Stock price volatility	63%	64%	66%
Expected life in years	10	10	10
Dividend yield	-	-	-

After-Payout Incentive Plan

 The Compensation Committee of the Board of Directors has adopted an incentive plan for officers, key employees and consultants 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 interest in the production developed, directly or indirectly, by the participants.  The plan generally provides for the creation of a series of partnerships or participation arrangements (“APO Partnerships”) between the Company and the participants to which the Company contributes a portion of its economic interest in wells drilled or acquired within certain areas.  Generally, the Company pays all costs to acquire, drill and produce applicable wells and receives all revenues until it has recovered all of its costs, plus interest (“payout”).  At payout, the participants receive 99% to 100% of all subsequent revenues and pay 99% to 100% of all subsequent expenses attributable to the APO Partnerships.  Between 5% and 7.5% of the Company’s economic interests in specified wells drilled or acquired by the Company subsequent to October 2002 are subject to APO Partnerships.  The Company records its allocable share of the assets, liabilities, revenues, expenses and oil and gas reserves of these APO Partnerships in its consolidated financial statements.

In January 2007, the Company granted awards under the Southwest Royalties Reward Plan (the “SWR Reward Plan”), a one-time incentive plan which established a quarterly bonus amount for participants equal to the after-payout cash flow from a 22.5% working interest in one well.  Under the plan, two-thirds of the quarterly bonus amount is payable to the participants until the full vesting date of October 25, 2011.  After the full vesting date, the deferred portion of the quarterly bonus amount, with interest at 4.83% per year, as well as 100% of all subsequent quarterly bonus amounts, are payable to participants.

 In May 2008, the Company formed three bonus plans (the “APO Bonus Plans”) for wells drilled in three distinct areas where the APO Partnership structure was not effective.  Each of these APO Bonus Plans establishes a quarterly bonus amount equal to 7% of the after-payout cash flow from wells drilled in the respective plan areas after the effective date set forth in each plan, which dates range from January 1, 2007 to May 5, 2008.  Under these plans, 100% of the quarterly bonus amount is payable to the participants, and the full vesting date is May 5, 2013.

To continue as a participant in the SWR Reward Plan or the APO Bonus Plans, participants must remain in the employment or service of the Company through the full vesting date established for each plan.  The full vesting date may be accelerated in the event of a change of control or sale transaction, as defined in the plan documents.

The Company recognizes compensation expense related to APO Partnerships based on the estimated fair value of the economic interests conveyed to the participants.  Compensation expense applicable to the APO Bonus Plans and SWR Reward Plan is recognized over the vesting period.  The Company recorded non-cash compensation expense of $5.7 million in 2008, $1.8 million in 2007, and $2.5 million in 2006 in connection with all plans established under the After-Payout Incentive Plan.

F-20

CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

10.      Transactions with Affiliates

The Company and other entities (the “Williams Entities”) controlled by Mr. Williams are parties to an agreement (the “Service Agreement”) pursuant to which the Company furnishes services to, and receives services from, such entities.  Under the Service Agreement, the Company provides legal, payroll, benefits administration, and financial and accounting services to the Williams Entities, as well as technical services with respect to certain oil and gas properties owned by the Williams Entities.  The Williams Entities provide tax preparation services, tax planning services, and business entertainment to or for the benefit of the Company.  The following table summarizes the charges to and from the Williams Entities for the years ended December 31, 2008, 2007 and 2006.

	2008		2007		2006
	(In thousands)
Amounts received from the Williams Entities:
Service Agreement:
Services	$	581	$	299	$	337
Insurance premiums and benefits		868		707		580
Reimbursed expenses		467		676		407
	$	1,916	$	1,682	$	1,324
Amounts paid to the Williams Entities:
Rent (a)	$	807	$	663	$	619
Service Agreement:
Business entertainment (b)		91		113		113
Tax services		-		150		150
Reimbursed expenses		197		122		118
	$	1,095	$	1,048	$	1,000

 (a) Rent amounts were paid to a Partnership within the Williams Entities.  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 by the Company as operator of certain wells in which affiliates own an interest.

11.      Investments

Larclay JV

 In April 2006, the Company formed a joint venture (“Larclay JV”) with Lariat Services, Inc. (“Lariat”) to construct, own and operate 12 new drilling rigs.  The Company and Lariat each own a 50% equity interest in Larclay JV.  A lender has provided a $75 million secured term loan to Larclay JV to finance the cost of constructing and equipping of the drilling rigs (see Note 3).  The principal balance outstanding on the Larclay JV term loan at December 31, 2008 was $39.4 million.  The Larclay JV term loan is secured by substantially all of the assets of Larclay JV.  As additional credit support, the Company granted the lender a limited guaranty in the original amount of $19.5 million.  The maximum obligation under the guaranty reduces by 10% on April 1 of each year, beginning April 1, 2008.  At December 31, 2008, the Company’s maximum obligation under the guaranty was approximately $17.6 million.  The Company is not obligated under the Larclay JV term loan except to the extent of the guaranty.

 Since inception of this joint venture, the Company has made advances structured as subordinated loans to Larclay JV totaling $12.1 million, $4.6 million to finance excess construction costs and $7.5 million to finance the Company’s 50% share of working capital assessments made by Larclay JV.  Lariat has also advanced Larclay JV $7.5 million for its 50% share of working capital assessments.  Loans to Larclay JV by Lariat and the Company are due on demand and bear interest, payable monthly, at the same rate as the term loan.  However, these loans are subject to a subordination agreement with the Larclay JV lender that imposes restrictions on payments of principal and interest on the loans.

 In connection with the formation of Larclay, the Company entered into a three-year drilling contract with Larclay JV assuring the availability of each drilling rig for use in the ordinary course of the Company’s exploration and development drilling program throughout the term of the drilling contract.  The drilling contract, which is pledged as collateral to secure the Larclay JV term loan, expires on the earlier of December 31, 2009 or the termination and liquidation of Larclay JV.  The provisions of the drilling contract provide that the Company contract for each drilling rig on a well-by-well basis at then current market rates.  If a drilling rig is not needed by the Company at any time

F-21

CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

during the term of the contract, Larclay JV may contract with other operators for the use of such drilling rig, subject to certain restrictions.  If a drilling rig is idle, the contract requires the Company to pay Larclay JV an idle rig rate ranging from $8,100 per day to $10,300 per day (plus crew labor expenses, if applicable), depending on the size of the drilling rig.  The Company’s maximum potential obligation to pay idle rig rates over the remaining term of the drilling contract, excluding any crew labor expenses, totals approximately $29 million at December 31, 2008.  The Company paid $5.2 million for idle rig fees during the year ended December 31, 2008 and $1.5 million in 2007.

Although the Company and Lariat own equal interests in Larclay JV, the Company meets the definition of the primary beneficiary of Larclay JV’s expected cash flows under FIN 46R.  As the primary beneficiary under FIN 46R, the Company is required to include the accounts of Larclay JV in the Company’s consolidated financial statements.  As of December 31, 2008, Lariat’s equity ownership in the net assets of Larclay JV was $5.6 million, which is recorded as minority interest and included in other non-current liabilities in the accompanying consolidated financial statements.  The Company’s intercompany accounts and profits with Larclay JV have been eliminated in consolidation.

On March 13, 2009, the Company and Lariat entered into an agreement pursuant to which Lariat has agreed to assign all of its right, title and interest in and to the Larclay JV to us effective as of April 15, 2009 (the “Effective Date”), and the Company has agreed to assume all of the obligations and liabilities of Lariat under the Larclay JV from and after the Effective Date, including Lariat’s obligations as operator of the Larclay JV drilling rigs.  After giving effect to the assignment to the Company by Lariat, the Company will own 100% of the Larclay JV.

SandRidge Energy Inc.

 During the fourth quarter of 2007, SandRidge Energy Inc. (“SandRidge”) became publicly traded and listed its shares on the New York Stock Exchange.  The Company’s original cost investment in SandRidge was increased to fair market value in 2007 and the change in fair market value of $4.2 million, net of tax of $1.5 million, was recorded in accumulated other comprehensive income at December 31, 2007.  In September 2008, the Company sold its investment of 200,460 shares in SandRidge for $4.3 million and recorded a gain of $1.3 million in other income.

12.      Inventory

The Company maintains an inventory of tubular goods and other well equipment for use in its exploration and development drilling activities.  Any gains or losses on disposition of inventory, and any losses on write-down of inventory to its estimated market value, are reported as gain or loss on sales of assets in the accompanying consolidated statements of operations.  The 2007 period included a charge of $8.9 million to write-down inventory to its estimated market value at March 31, 2007.  The write-down resulted primarily from the sale of certain surplus equipment at an auction in March 2007.  The Company received $4.5 million of net proceeds from the auction in April 2007 when the auction sale was consummated.

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 $997,000, $846,000 and $791,000 for the years ended December 31, 2008, 2007 and 2006, respectively.

Future minimum payments under noncancelable leases at December 31, 2008, are as follows:

	Leases
	Capital (a)		Operating		Total
	(In thousands)
2009	$	526	$	1,106	$	1,632
2010		322		1,075		1,397
2011		95		888		983
Thereafter		-		199		199
Total minimum lease payments	$	943	$	3,268	$	4,211

 (a)      Relates to vehicle leases.

F-22

CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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 of $12.9 million in 2008, $12.1 million in 2007, and $21.8 million in 2006.  The 2008 provision related primarily to oil and gas proved property impairments of $11.3 million for the Margarita #1 well on our East Texas Bossier prospect.  The 2007 provision included $7.1 million to write-down two 2,000 horsepower drilling rigs and related components, and $1.1 million for well service equipment to their estimated fair market value. The remaining $3.9 million impairment is related to producing properties in the Permian Basin.  The 2006 provision related to production performance for properties in West Texas.

The Company has also recorded provisions for impairment of unproved properties aggregating $46.1 million, $16.8 million and $12.9 million in 2008, 2007 and 2006, respectively, and 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 Property and Equipment

 In April 2008, the Company and its affiliates sold all of their interests in 16 producing wells for approximately $89.2 million, net of customary closing adjustments.  The Company recorded a gain of approximately $33.1 million in the second quarter of 2008 in connection with this transaction.  In April 2008, the Company sold a surplus well servicing unit for $1.8 million and recorded a gain of approximately $75,000 in the second quarter of 2008 and sold two 2,000 horsepower drilling rigs in June 2008 for $21.8 million, net of customary closing adjustments and recorded a gain of $5.7 million.  In September 2008, the Company sold its interest in a prospect in North Louisiana for $3.2 million and recorded a gain of $3 million.

 Gain on sales of property and equipment for 2007 was $14 million due primarily to the sale of its oil and gas properties in Pecos County, Texas, for $21 million.  The Company recorded a gain of approximately $12.5 million in the fourth quarter of 2007 in connection with this sale.  Gain on sale of property and equipment for 2006 was $1.8 million.

F-23

CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

16.      Quarterly Financial Data (Unaudited)

The following table summarizes results for each of the four quarters in the years ended December 31, 2008 and 2007.

	First			Second			Third		Fourth
	Quarter			Quarter			Quarter		Quarter			Year
	(In thousands, except per share)
Year ended December 31, 2008:
Total revenues	$	136,858		$	191,268		$	146,985	$	90,406		$	565,517
Operating income (loss)	$	64,415		$	119,001		$	18,126	$	(39,261	)	$	162,281
Net income (loss) (a)	$	7,179		$	(21,171	)	$	94,629	$	59,897		$	140,534
Net income (loss) per common share (b):
Basic	$	.63		$	(1.75	)	$	7.81	$	4.94		$	11.78
Diluted	$	.62		$	(1.75	)	$	7.79	$	4.93		$	11.67
Weighted average common shares outstanding:
Basic		11,387			12,111			12,114		12,114			11,932
Diluted		11,643			12,111			12,141		12,148			12,039
Year ended December 31, 2007:
Total revenues	$	72,501		$	92,564		$	101,839	$	126,991		$	393,895
Operating income	$	6,242		$	13,698		$	13,749	$	40,341		$	74,030
Net income (loss) (a)	$	(12,310	)	$	8,810		$	986	$	8,504		$	5,990
Net income (loss) per common share (b):
Basic	$	(1.09	)	$	.78		$	.09	$	.75		$	.53
Diluted	$	(1.09	)	$	.77		$	.09	$	.74		$	.52
Weighted average common shares outstanding:
Basic		11,290			11,352			11,352		11,352			11,337
Diluted		11,290			11,507			11,521		11,529			11,494

(a) The Company recorded a $10 million charge for impairment of property and equipment in the third quarter of 2008 and a $2.9 million charge in the fourth quarter of 2008.  The Company recorded an $8 million charge for impairment of proved properties in the third quarter of 2007 and a $3.1 million charge in the fourth quarter of 2007.

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

17.      Costs of Oil and Gas Properties

The following table sets forth certain information with respect to costs incurred in connection with the Company's oil and gas producing activities during the years ended December 31, 2008, 2007 and 2006.

	2008		2007		2006
	(In thousands)
Property acquisitions:
Proved	$	-	$	-	$	6,432
Unproved		36,397		15,746		54,437
Developmental costs		260,073		45,611		35,698
Exploratory costs		51,237		169,879		157,509
Total	$	347,707	$	231,236	$	254,076

F-24

CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The following table sets forth the capitalized costs for oil and gas properties as of December 31, 2008 and 2007.

	2008			2007
	(In thousands)
Proved properties	$	1,435,718		$	1,258,166
Unproved properties		90,755			115,924
Total capitalized costs		1,526,473			1,374,090
Accumulated depreciation, depletion and amortization		(791,507	)		(727,739	)
Net capitalized costs	$	734,966		$	646,351

18.      Segment Information

In accordance with SFAS No. 131, “Disclosures about Segments of an Enterprise and Related Information” (“SFAS 131”), the Company has two reportable operating segments, which are oil and gas exploration and production and contract drilling services.

The following tables present selected financial information regarding the Company’s operating segments for 2008 and 2007.

				Contract			Intercompany			Consolidated
For the Year Ended December 31, 2008	Oil and Gas			Drilling			Eliminations			Total
	(In thousands)
Revenues	$	514,686		$	64,153		$	(13,322	)	$	565,517
Depreciation, depletion and amortization (a)		124,874			10,651			(2,101	)		133,424
Other operating expenses (b)		232,047			47,493			(9,728	)		269,812
Interest expense		21,134			3,860			-			24,994
Other (income) expense		(81,282	)		-			-			(81,282	)
Income before income taxes		217,913			2,149			(1,493	)		218,569
Income tax expense		76,546			781			-			77,327
Minority interest, net of tax		381			(1,089	)		-			(708	)
Net income (loss)	$	141,748		$	279		$	(1,493	)	$	140,534
Total assets	$	864,260		$	85,006		$	(5,857	)	$	943,409
Additions to property and equipment	$	350,184		$	1,195		$	(1,493	)	$	349,886

			Contract			Intercompany			Consolidated
For the Year Ended December 31, 2007	Oil and Gas		Drilling			Eliminations			Total
	(In thousands)
Revenues	$	341,246	$	64,551		$	(11,902	)	$	393,895
Depreciation, depletion and amortization (a)		82,240		16,060			(1,687	)		96,613
Other operating expenses (b)		192,334		39,138			(8,220	)		223,252
Interest expense		27,818		4,300			-			32,118
Other (income) expense		26,613		-			-			26,613
Income before income taxes		12,241		5,053			(1,995	)		15,299
Income tax expense		3,305		2,192			-			5,497
Minority interest, net of tax		2,053		(5,865	)		-			(3,812	)
Net income (loss)	$	10,989	$	(3,004	)	$	(1,995	)	$	5,990
Total assets	$	753,480	$	114,849		$	(7,233	)	$	861,096
Additions to property and equipment	$	235,679	$	23,538		$	(1,995	)	$	257,222

(a)   Includes impairment of property and equipment.

(b)   Includes the following expenses:  production, exploration, natural gas services, accretion of abandonment obligations, general and administrative and loss on sales of property and equipment.

F-25

CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

19.      Guarantor Financial Information

In July 2005, Clayton Williams Energy, Inc. (“Issuer”) issued $225 million of Senior Notes (see Note 3).  Other than West Coast Energy Properties GP, LLC (“WCEP LLC”), the general partner of West Coast Energy Properties, L.P., an affiliated limited partnership, all of the Issuer’s wholly-owned and active subsidiaries (“Guarantor Subsidiaries”) have jointly and severally, irrevocably and unconditionally guaranteed the performance and payment when due of all obligations under the Senior Notes.  Larclay JV, a 50%-owned drilling rig joint venture formed in April 2006, and WCEP, LLC have not guaranteed the Senior Notes and are referred to in this Note 19 as Non-Guarantor Entities.

The financial information on the following pages sets forth the Company’s condensed consolidating financial statements as of and for the periods indicated.

Condensed Consolidating Balance Sheet

December 31, 2008

(Dollars in thousands)					Non-
			Guarantor		Guarantor		Adjustments/
	Issuer		Subsidiaries		Entities		Eliminations			Consolidated
Current assets	$	178,349	$	173,636	$	15,749	$	(242,250	)	$	125,484
Property and equipment, net		388,189		345,327		76,512		-			810,028
Investments in subsidiaries		72,082		-		-		(72,082	)		-
Other assets		19,629		372		211		(12,315	)		7,897
Total assets	$	658,249	$	519,335	$	92,472	$	(326,647	)	$	943,409
Current liabilities	$	83,288	$	253,627	$	28,212	$	(242,250	)	$	122,877
Non-current liabilities:
Long-term debt		319,100		-		40,225		(12,100	)		347,225
Other		101,213		57,301		114		(3	)		158,625
		420,313		57,301		40,339		(12,103	)		505,850
Stockholders’ equity		154,648		208,407		23,921		(72,294	)		314,682
Total liabilities and
stockholders’ equity	$	658,249	$	519,335	$	92,472	$	(326,647	)	$	943,409

F-26

CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Condensed Consolidating Balance Sheet

December 31, 2007

(Dollars in thousands)					Non-
			Guarantor		Guarantor		Adjustments/
	Issuer		Subsidiaries		Entities		Eliminations			Consolidated
Current assets	$	127,668	$	109,010	$	21,225	$	(145,524	)	$	112,379
Property and equipment, net		369,421		275,609		86,048		-			731,078
Investments in subsidiaries		81,583		-		-		(81,583	)		-
Other assets		21,354		340		545		(4,600	)		17,639
Total assets	$	600,026	$	384,959	$	107,818	$	(231,707	)	$	861,096
Current liabilities	$	112,536	$	179,243	$	42,512	$	(145,524	)	$	188,767
Non-current liabilities:
Long-term debt		390,800		-		43,975		(4,600	)		430,175
Other		24,708		56,528		112		-			81,348
		415,508		56,528		44,087		(4,600	)		511,523
Stockholders’ equity		71,982		149,188		21,219		(81,583	)		160,806
Total liabilities and
stockholders’ equity	$	600,026	$	384,959	$	107,818	$	(231,707	)	$	861,096

Condensed Consolidating Statement of Operations

Year Ended December 31, 2008

(Dollars in thousands)							Non-
				Guarantor			Guarantor			Adjustments/
	Issuer			Subsidiaries			Entities			Eliminations			Consolidated
Total revenue	$	346,570		$	173,154		$	65,186		$	(19,393	)	$	565,517
Costs and expenses		254,093			108,166			58,877			(17,900	)		403,236
Operating income (loss)		92,477			64,988			6,309			(1,493	)		162,281
Other income (expense)		65,414			(5,502	)		(3,624	)		-			56,288
Income tax expense		(77,327	)		-			-			-			(77,327	)
Minority interest, net of tax		(708	)		-			-			-			(708	)
Net income (loss)	$	79,856		$	59,486		$	2,685		$	(1,493	)	$	140,534

Condensed Consolidating Statement of Operations

Year Ended December 31, 2007

(Dollars in thousands)							Non-
				Guarantor			Guarantor			Adjustments/
	Issuer			Subsidiaries			Entities			Eliminations			Consolidated
Total revenue	$	224,743		$	117,208		$	65,241		$	(13,297	)	$	393,895
Costs and expenses		198,535			83,947			48,686			(11,303	)		319,865
Operating income (loss)		26,208			33,261			16,555			(1,994	)		74,030
Other income (expense)		(46,373	)		(8,213	)		(4,145	)		-			(58,731	)
Income tax expense		(5,497	)		-			-			-			(5,497	)
Minority interest, net of tax		(3,812	)		-			-			-			(3,812	)
Net income (loss)	$	(29,474	)	$	25,048		$	12,410		$	(1,994	)	$	5,990

F-27

CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Condensed Consolidating Statement of Operations

Year Ended December 31, 2006

(Dollars in thousands)						Non-
				Guarantor		Guarantor			Adjustments/
	Issuer			Subsidiaries		Entities			Eliminations			Consolidated
Total revenue	$	154,159		$	106,550	$	11,397		$	(6,108	)	$	265,998
Costs and expenses		176,951			79,456		9,450			(5,105	)		260,752
Operating income (loss)		(22,792	)		27,094		1,947			(1,003	)		5,246
Other income (expense)		4,453			11,281		(628	)		-			15,106
Income tax expense		(1,979	)		-		-			-			(1,979	)
Minority interest, net of tax		(574	)		-		-			-			(574	)
Net income (loss)	$	(20,892	)	$	38,375	$	1,319		$	(1,003	)	$	17,799

Condensed Consolidating Statement of Cash Flows

Year Ended December 31, 2008

(Dollars in thousands)							Non-
				Guarantor			Guarantor			Adjustments/
	Issuer			Subsidiaries			Entities			Eliminations			Consolidated
Operating activities	$	319,182		$	53,388		$	7,309		$	2,101		$	381,980
Investing activities		(126,079	)		(109,172	)		(1,523	)		(2,101	)		(238,875	)
Financing activities		(163,047	)		56,306			(7,509	)		-			(114,250	)
Net increase (decrease) in
cash and cash equivalents		30,056			522			(1,723	)		-			28,855
Cash at the beginning of
the period		5,325			1,288			5,731			-			12,344
Cash at end of the period	$	35,381		$	1,810		$	4,008		$	-		$	41,199

Condensed Consolidating Statement of Cash Flows

Year Ended December 31, 2007

(Dollars in thousands)							Non-
				Guarantor			Guarantor			Adjustments/
	Issuer			Subsidiaries			Entities			Eliminations			Consolidated
Operating activities	$	149,216		$	60,738		$	23,225		$	1,687		$	234,866
Investing activities		(189,626	)		(21,303	)		(24,143	)		(1,187	)		(236,259	)
Financing activities		39,620			(39,445	)		222			(500	)		(103	)
Net decrease in
cash and cash equivalents		(790	)		(10	)		(696	)		-			(1,496	)
Cash at the beginning of
the period		6,116			1,298			6,426			-			13,840
Cash at end of the period	$	5,326		$	1,288		$	5,730		$	-		$	12,344

F-28

CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Condensed Consolidating Statement of Cash Flows

Year Ended December 31, 2006

(Dollars in thousands)							Non-
				Guarantor			Guarantor			Adjustments/
	Issuer			Subsidiaries			Entities			Eliminations			Consolidated
Operating activities	$	50,130		$	65,343		$	30,229		$	288		$	145,990
Investing activities		(215,405	)		(22,007	)		(72,753	)		212			(309,953	)
Financing activities		167,089			(43,671	)		48,950			(500	)		171,868
Net increase (decrease) in
cash and cash equivalents		1,814			(335	)		6,426			-			7,905
Cash at the beginning of
the period		4,302			1,633			-			-			5,935
Cash at end of the period	$	6,116		$	1,298		$	6,426		$	-		$	13,840

20.           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 SEC and the FASB, 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 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 are classified as proved developed nonproducing and proved undeveloped, which increases the imprecision inherent in estimating reserves which may ultimately be produced.

F-29

CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The following table sets forth estimated 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, 2008, 2007 and 2006.

	Oil			Gas			MMcfe
Proved reserves:
December 31, 2005		27,835			126,758			293,768
Revisions		(2,383	)		(14,402	)		(28,700	)
Extensions and discoveries		1,367			21,204			29,406
Purchases of minerals-in-place		932			805			6,397
Production		(2,370	)		(15,198	)		(29,418	)
December 31, 2006		25,381			119,167			271,453
Revisions		3,194			1,761			20,925
Extensions and discoveries		1,902			23,533			34,945
Purchases of minerals-in-place		-			(624	)		(624	)
Production		(2,531	)		(20,681	)		(35,867	)
December 31, 2007		27,946			123,156			290,832
Revisions		(5,620	)		(15,938	)		(49,658	)
Extensions and discoveries		2,057			23,824			36,166
Sales of minerals-in-place		(473	)		(8,560	)		(11,398	)
Production		(3,134	)		(18,553	)		(37,357	)
December 31, 2008		20,776			103,929			228,585
Proved developed reserves:
December 31, 2006		18,872			90,217			203,450
December 31, 2007		20,627			98,434			222,196
December 31, 2008		16,815			87,340			188,230

Our proved reserves were 49.7 Bcfe lower due to revisions of previous estimates. Downward revisions of 57.1 Bcfe were attributable to the effects of lower product prices on the estimated quantities of proved reserves.  Net upward revisions of approximately 7.4 Bcfe were attributable to well performance and consisted primarily of net upward adjustments in the Permian Basin, Austin Chalk (Trend) and Cotton Valley, offset in part by downward adjustments in North and South Louisiana.

The standardized measure of discounted future net cash flows relating to estimated proved reserves as of December 31, 2008, 2007 and 2006 was as follows:

	2008			2007			2006
	(In thousands)
Future cash inflows	$	1,374,684		$	3,363,271		$	1,991,628
Future costs:
Production		(569,053	)		(999,945	)		(685,021	)
Development		(104,223	)		(174,264	)		(160,264	)
Income taxes		(126,819	)		(653,808	)		(293,870	)
Future net cash flows		574,588			1,535,254			852,473
10% discount factor		(169,423	)		(609,285	)		(337,673	)
Standardized measure of discounted net cash flows	$	405,166		$	925,969		$	514,800

F-30

CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Changes in the standardized measure of discounted future net cash flows relating to estimated proved reserves for the years ended December 31, 2008, 2007 and 2006 were as follows:

	2008			2007			2006
	(In thousands)
Standardized measure, beginning of period	$	925,969		$	514,800		$	753,712
Net changes in sales prices, net of production costs		(600,719	)		483,032			(356,919	)
Revisions of quantity estimates		(101,889	)		82,451			(76,332	)
Accretion of discount		131,824			70,844			111,789
Changes in future development costs, including
development costs incurred that reduced future
development costs		69,466			2,665			11,665
Changes in timing and other		(9,385	)		24,497			(37,086	)
Net change in income taxes		299,193			(203,369	)		174,488
Future abandonment cost, net of salvage		(548	)		(4,204	)		(7,880	)
Extensions and discoveries		155,006			197,219			113,110
Sales, net of production costs		(373,988	)		(240,733	)		(181,280	)
Sales of minerals-in-place		(89,763	)		(1,233	)		-
Purchases of minerals-in-place		-			-			9,533
Standardized measure, end of period.	$	405,166		$	925,969		$	514,800

The estimated present value of future cash flows relating to estimated proved reserves is extremely sensitive to prices used at any measurement period.  The average prices used for each commodity for the years ended December 31, 2008, 2007 and 2006 were as follows:

	Average Price
	Oil (a)		Gas
As of December 31:
2008	$	42.03	$	5.90
2007	$	91.30	$	7.37
2006	$	57.18	$	5.24

(a)      Includes natural gas liquids.

F-31

CLAYTON WILLIAMS ENERGY, INC.

Schedule II – Valuation and Qualifying Accounts
	Balance at							Balance at
	Beginning of							End of
Description	Period		Additions(a)		Deductions(b)			Period
			(In thousands)
Year Ended December 31, 2008:
Allowance for doubtful accounts - Joint interest and other	$	1,387	$	-	$	-		$	1,387
Year Ended December 31, 2007:
Allowance for doubtful accounts - Joint interest and other	$	1,044	$	343	$	-		$	1,387
Year Ended December 31, 2006:
Allowance for doubtful accounts - Joint interest and other	$	1,087	$	-	$	(43	)	$	1,044
(a) Additions relate to provisions for doubtful accounts.
(b) Deductions relate to the write-off or recovery of the provisions for doubtful accounts.

S-1