UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

FORM 10-K/A

Amendment No. 1

(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, 2009

¨	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 whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
	¨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.  $111,191,777.

There were 12,145,536 shares of Common Stock, $.10 par value, of the registrant outstanding as of March 10, 2010.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the definitive proxy statement relating to the 2010 Annual Meeting of Stockholders, which will be filed with the Commission not later than April 30, 2010, are incorporated by reference in Part III of this Form 10-K.

EXPLANATORY NOTE

We filed our Annual Report on Form 10-K for the year ended December 31, 2009 (“Form 10-K”) on March 12, 2010.  In response to comments from the staff of the Securities and Exchange Commission, we are filing this Amendment No. 1 on Form 10-K/A (“Form 10-K/A”) to replace in its entirety Item 2 – Properties and to file or furnish certain updated exhibits.

Item 2 – Properties is being amended to:

• Add disclosures regarding the technologies we use to establish the appropriate level of certainty for reserve estimates from material properties;

• Add disclosures regarding our delivery commitments; and

• Add disclosures regarding our lease acreage expirations.

Certain exhibits have been updated and are being filed or furnished with this Form 10-K/A to:

• Amend in their entirety the reports of our independent consulting engineers in order to address staff comments to include all required items listed under Item 1202(a)8 of Regulation S-K;

• Provide updated consents of our independent consulting engineers;

• Correct the inadvertent omission of KPMG LLP’s signature on their consent dated March 12, 2010 and which was filed with the Form 10-K; and

• Provide the required certifications by our principal executive officer and principal financial officer.

Except as set forth above, this Form 10-K/A does not modify, amend or update in any way any other items or disclosure in the Form 10-K. This Form 10-K/A continues to speak as of the date of the original Form 10-K and other than as specifically reflected in this Form 10-K/A does not reflect events occurring after the filing of the original Form 10-K.  Accordingly, this Form 10-K/A should be read in conjunction with the Form 10-K and our other filings with the Securities and Exchange Commission subsequent to filing of the Form 10-K.

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PART I

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, 2009, we had interests in 6,750 gross (941.2 net) oil and gas wells and owned leasehold interests in approximately 1.1 million gross (618,000 net) undeveloped acres.

Reserves

Rule Changes Applicable to Reserve Estimates and Disclosures

In 2009, the SEC issued its final rule on the modernization of oil and gas reporting, and the Financial Accounting Standards Board (“FASB”) adopted conforming changes to Accounting Standards Codification (“ASC”) Topic 932, “Extractive Industries”, to align the FASB’s reserves requirements with those of the SEC.  The final rule is now in effect for companies with fiscal years ending on or after December 31, 2009.  As it affects our reserve estimates and disclosures, the final rule:

·   amends the definition of proved reserves to require the use of average commodity prices based upon the prior 12-month period rather than year-end prices;

·   expands the type of technologies available to establish reserve estimates and categories;

·   modifies certain definitions used in estimating proved reserves;

·   permits disclosure of probable and possible reserves;

·   requires disclosure of internal controls over reserve estimations and the qualifications of technical persons primarily responsible for the preparation or audit of reserve estimates;

·   permits disclosure of reserves based on different price and cost criteria, such as futures prices or management forecasts; and

·   requires disclosure of material changes in proved undeveloped reserves, including a discussion of investments and progress made to convert proved undeveloped reserves to proved developed reserves.

See “Glossary of Terms” for current definitions of terms related to oil and gas reserves.

The following table sets forth our estimated quantities of proved reserves as of December 31, 2009, all of which are located within the United States.

	Proved Reserves(a)
			Natural		Total Oil
	Oil(b)		Gas		Equivalents(c)
Reserve Category	(MBbls)		(MMcf)		(MBOE)
Developed		16,779		70,840		28,586
Undeveloped		4,174		5,263		5,051
Total Proved		20,953		76,103		33,637

(a)   None of our oil and gas reserves are derived from non-traditional sources.

(b)   Oil reserves include crude oil, condensate and natural gas liquids.

(c)   Natural gas reserves have been converted to oil equivalents at the rate of six Mcf of gas to one barrel of oil.

The present value of future net cash flows from proved reserves, before deductions for estimated future income taxes and asset retirement obligations, discounted at 10% (“PV-10 Value”), totaled $460.4 million at December 31, 2009.  The commodity prices used to estimate proved reserves and their related PV-10 Value at December 31, 2009 were based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for the period from January 2009 through December 2009.  These benchmark average prices were further adjusted for quality, energy content, transportation fees and other price differentials specific to our properties, resulting in an average adjusted price of $54.81 per barrel of oil and NGL and $3.71 per Mcf of natural gas over the remaining life of our proved reserves.  Operating costs were not escalated.

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PV-10 Value is not a generally accepted accounting principle (“GAAP”) financial measure, but we believe it is useful as a supplemental disclosure to the standardized measure of discounted future net cash flows presented in our consolidated financial statements.  To compute our standardized measure of discounted future net cash flows at December 31, 2009, we began with the PV-10 Value of our proved reserves and deducted the present value of estimated future income taxes of $66.8 million and net abandonment costs of $29.3 million, discounted at 10%.  At December 31, 2009, our standardized measure of discounted future net cash flows totaled $364.3 million.  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.

The following table summarizes certain information as of December 31, 2009 regarding our estimated proved reserves in each of our principal producing areas.

													Percent
	Proved Reserves										PV-10		of PV-10
			Natural		Total Oil		Percent of				Value of		Value of
	Oil (a)		Gas		Equivalents(b)		Total Oil				Proved		Proved
	(MBbls)		(MMcf)		(MBOE)		Equivalent				Reserves		Reserves
										(In thousands)
Permian Basin		13,325		39,874		19,971		59.4	%		$	259,180		56.3	%
Austin Chalk (Trend)		6,887		5,131		7,742		23.0	%			131,408		28.5	%
North Louisiana		291		17,205		3,159		9.4	%			37,140		8.1	%
South Louisiana		243		5,968		1,238		3.7	%			21,801		4.7	%
Cotton Valley Reef Complex		-		5,981		997		3.0	%			5,444		1.2	%
Other		207		1,944		530		1.5	%			5,417		1.2	%
Total		20,953		76,103		33,637		100.0	%		$	460,390		100.0	%

(a)   Oil reserves include crude oil, condensate and natural gas liquids.

(b)   Natural gas reserves have been converted to oil equivalents at the rate of six Mcf to one barrel of oil.

The following table summarizes changes in our estimated proved reserves during 2009.

	Proved
	Reserves
	(MBOE)
As of December 31, 2008		38,098
Extensions and discoveries		3,655
Revisions		(2,353	)
Production		(5,763	)
As of December 31, 2009		33,637

Extensions and discoveries.  Extensions and discoveries in 2009 added 3,655 MBOE of proved reserves, replacing 63% of our 2009 production.  These additions resulted primarily from our drilling activities in the Permian Basin and the Austin Chalk (Trend) despite curtailments of capital spending during the first half of 2009 due to recessionary uncertainties.  Of the total reserve additions, proved developed reserves accounted for 2,738 MBOE, while the remaining 917 MBOE were proved undeveloped reserves.

Revisions.  Net downward revisions of 2,353 MBOE consisted of downward revisions of 2,420 MBOE related to performance and upward revisions of 67 MBOE related to pricing.  Substantially all of the downward performance revisions resulted from the reclassification of certain Permian Basin reserves from proved undeveloped to probable (see discussion below regarding changes in proved undeveloped reserves).  Net upward revisions of 67 MBOE were attributable to the effects of higher product prices on the estimated quantities of proved reserves.

Proved undeveloped reserves decreased 1,673 MBOE in 2009 from 6,724 MBOE at the beginning of the year to 5,051 MBOE at December 31, 2009 due primarily to the reclassification of 2,412 MBOE of Permian Basin reserves from proved undeveloped to probable.  These reclassified reserves relate to undrilled locations we acquired in 2004 in connection with the purchase of Southwest Royalties, Inc.  These undrilled locations are on leases which are held by existing production from other wells.  Although we expect to develop these reserves in the future, the reserves were downgraded to probable due to a provision in the new SEC reserves rule that requires proved undeveloped reserves to be developed within five years from their date of origin.  We added 917 MBOE of proved reserves from extensions and

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discoveries related to nine proved undeveloped locations that we plan to drill in 2010 at an expected cost of approximately $15 million.  Net downward revisions to proved undeveloped reserves of 178 MBOE resulted primarily from the loss of one drilling location due to expiration of drilling rights, offset in part by upward revisions in estimates due to price increases.  We did not convert any proved undeveloped reserves at December 31, 2008 to proved developed reserves during 2009.

Alternative Pricing Cases

In addition to the estimated proved reserves disclosed above in accordance with the commodities pricing required by the new reserves rule (referred to as the “SEC Case”), the following table sets forth certain information regarding our proved reserves based on two supplementary pricing cases.

	Proved Reserves
			Natural		Total Oil
	Oil(a)		Gas		Equivalents (b)
Pricing Cases	(MBbls)		(MMcf)		(MBOE)		PV-10 Value
							(In thousands)
SEC Case		20,953		76,103		33,637	$	460,386
Year-end Pricing Case		23,117		84,389		37,182	$	741,427
Futures Pricing Case		22,040		82,019		35,710	$	832,292

(a)   Oil reserves include crude oil, condensate and natural gas liquids.

(b)   Natural gas has been converted to oil equivalents at the rate of six Mcf to one barrel of oil.

Year-end Pricing Case.  The Year-end Pricing Case was provided to compare our estimated proved reserves based on the SEC Case with those estimates obtained based on previous pricing guidelines.  Under the Year-end Pricing Case, we used the spot prices in effect on December 31, 2009 as our benchmark prices.  These benchmark prices were further adjusted for quality, energy content, transportation fees and other price differentials specific to our properties, resulting in an average adjusted price of $70.98 per barrel of oil and NGL and $5.61 per Mcf of natural gas over the remaining life of our proved reserves.  Operating costs were not escalated.

Futures Pricing Case.  The Futures Pricing Case discloses our estimated proved reserves using future market-based commodities prices instead of the average historical prices used in the SEC Case.  Under the Futures Pricing Case, we used futures prices, as quoted on the New York Mercantile Exchange (“NYMEX”) on December 31, 2009, as benchmark prices for 2010 through 2014, and continued to use the 2014 futures price for all subsequent years.  These benchmark prices were further adjusted for quality, energy content, transportation fees and other price differentials specific to our properties, resulting in an average adjusted price of $79.99 per barrel of oil and NGL and $6.38 per Mcf of natural gas over the remaining life of the proved reserves.  Operating costs were escalated at 2% per year.

Reserve Estimation Procedures

Overview

We have established a system of internal controls over our reserve estimation process, which we believe provides us reasonable assurance that reserve estimates have been prepared in accordance with SEC and FASB standards.  These controls include oversight by trained technical personnel employed by us and by the use of qualified independent petroleum engineers to evaluate our proved reserves on an annual basis.  Substantially all of our estimated proved reserves as of December 31, 2009 were derived from engineering evaluation reports prepared by Williamson Petroleum Consultants, Inc. (“Williamson”) and Ryder Scott Company, L.P. (“Ryder Scott”).  Of our total SEC Case estimated proved reserves, Williamson evaluated 53.2% and Ryder Scott evaluated 46.2% on a BOE basis.

Qualifications of Technical Manager and Consultants

Ron D. Gasser, our Engineering Manager, is the person within our organization that is primarily responsible for overseeing the preparation of the reserve estimates.  Mr. Gasser joined our Company in 2002 as a Senior Engineer working on acquisitions/divestitures and special projects and was promoted to his current position as Engineering Manager in 2006.  Mr. Gasser has 27 years experience as a petroleum engineer, including 24 years directly involved in the estimation and evaluation of oil and gas reserves.  Mr. Gasser holds a Bachelor of Science degree in Petroleum Engineering from Texas Tech University.  He is a Registered Professional Engineer in the State of Texas and is a member of the Society of Petroleum Engineers.

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Williamson is an independent petroleum engineering consulting firm registered in the State of Texas, and John D. Savage, Executive Vice President – Engineering Manager of Williamson, is the technical person primarily responsible for evaluating the proved reserves covered by their report.  Mr. Savage has 28 years experience in evaluating oil and gas reserves, including 26 years experience as a consulting reservoir engineer.  Mr. Savage holds a Bachelor of Science degree in Petroleum Engineering from Texas A&M University.  He is a Registered Professional Engineer in the State of Texas and is a member of the Society of Petroleum Engineers and the Society of Independent Professional Earth Scientists.

Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world for over 70 years.  John E. Hamlin, Managing Senior Vice President of Ryder Scott, is the technical person primarily responsible for evaluating the proved reserves covered by their report.  Mr. Hamlin has more than 33 years of experience in the estimation and evaluation of petroleum reserves.  Mr. Hamlin holds a Bachelor of Science degree in Petroleum Engineering from the University of Texas.  He is a Registered Professional Engineer in the State of Texas and is a member of the Society of Petroleum Engineers.

Technology Used to Establish Proved Reserves

Under current SEC standards, proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations.  The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and/or natural gas actually recovered will equal or exceed the estimate.  Reasonable certainty can be established using techniques that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty.  Reliable technology is a grouping of one or more technologies (including computational methods) that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

In order to establish reasonable certainty with respect to our estimated proved reserves, we employ technologies that have been demonstrated to yield results with consistency and repeatability.  The technological data used in the estimation of our proved reserves include, but are not limited to, electrical logs, radioactivity logs, core analyses, geologic maps and available downhole and production data, seismic data and well test data.  Generally, oil and gas reserves are estimated using, as appropriate, one or more of these available methods: production decline curve analysis, analogy to similar reservoirs or volumetric calculations.  Reserves attributable to producing wells with sufficient production history are estimated using appropriate decline curves or other performance relationships.  Reserves attributable to producing wells with limited production history and for undeveloped locations are estimated using performance from analogous wells in the surrounding area and technological data to assess the reservoir continuity.  In some instances, particularly in connection with exploratory discoveries, analogous performance data is not available, requiring us to rely primarily on volumetric calculations to determine reserve quantities.  Volumetric calculations are primarily based on data derived from geologic-based seismic interpretation, open-hole logs and completion flow data.  When using production decline curve analysis or analogy to estimate proved reserves, we limit our estimates to the quantities of oil and gas derived through volumetric calculations.

More than 90% of our additions to proved reserves in 2009 were derived from wells drilled in the Permian Basin and the Austin Chalk (Trend).  A significant amount of technological data is available in these areas, which allows us to estimate with reasonable certainty the proved reserves and production decline rates attributable to most of our reserve additions through analogy to historical performance from wells in the same reservoirs.  None of our additions to proved reserves for 2009 were estimated solely on volumetric calculations.

Processes and Controls

Mr. Gasser and his engineering staff maintain a reserves database covering substantially all of our oil and gas properties utilizing AriesTM,a widely-used reserves and economics software package licensed by a unit of Halliburton Company.  Some of our properties are not evaluated since they are individually and collectively insignificant to our total proved reserves and related PV-10 Value.  Our engineering staff assimilates all technological and operational data necessary to evaluate our reserves and updates the reserves database throughout the year.  Technological data is described above under “Technologies Used to Establish Proved Reserves.” Operational data includes ownership interests, product prices, operating expenses and future development costs.

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Using the most appropriate method available, Mr. Gasser applies his professional judgment, based on his training and experience, to project a production profile for each evaluated property.  Mr. Gasser consults with other engineers and geoscientists within our company as needed to validate the accuracy and completeness of his estimates and to determine if any of the technological data upon which his estimates were based are incorrect or outdated.

The engineering staff consults with our accounting department to validate the accuracy and completeness of certain operational data maintained in the reserves database, including ownership interests, average commodity prices, price differentials, and operating costs.

Although we believe that the estimates of reserves prepared by our engineering staff have been prepared in accordance with professional engineering standards consistent with SEC and FASB guidelines, we engage independent petroleum engineering consultants to prepare annual evaluations of our estimated reserves.  After Mr. Gasser and our engineering staff have made an internal evaluation of our estimated reserves, we provide copies of the AriesTM reserves database to Ryder Scott as it relates to properties owned by Southwest Royalties, Inc., one of our wholly-owned subsidiaries, and to Williamson as it relates to properties owned by CWEI and Warrior Gas Company, another of our wholly-owned subsidiaries.  In addition, we provide to the consultants for their analysis all pertinent data needed to properly evaluate our reserves.  The services provided by Williamson and Ryder Scott are not audits of our reserves but instead consist of complete engineering evaluations of the respective properties.  For more information about the evaluations performed by Williamson and Ryder Scott, see copies of their respective reports filed as exhibits to this Form 10-K.

Both Williamson and Ryder Scott use the AriesTM reserves database which we provide to them as a starting point for their evaluations.  This process reduces the risk of errors that can result from data input and also results in significant cost savings to us.  The petroleum engineering consultants generally rely on the technical and operational data provided to them without independent verification; however, in the course of their evaluation, if any issue comes to their attention that questions the validity or sufficiency of that data, the consultants will not rely on the questionable data until they have resolved the issue to their satisfaction.  The consultants analyze each production decline curve to determine if they agree with our interpretation of the underlying technical data.  If they arrive at a different conclusion, the consultants revise the estimates in the database to reflect their own interpretations.

After Williamson and Ryder Scott complete their respective evaluations, they return a modified AriesTM reserves database to our engineering staff for review.  Mr. Gasser identifies all material variances between our initial estimates and those of the consultants and discusses the variances with Williamson or Ryder Scott, as applicable, in order to resolve the discrepancies.  If any variances relate to inaccurate or incomplete data, corrected or additional data is provided to the consultants and the related estimates are revised.  When variances are caused solely by judgment differences between Mr. Gasser and the consultants, we accept the estimates of the consultants.

The final reserve estimates are then analyzed by our financial accounting group under the direction of Mel G. Riggs, our Senior Vice President and Chief Financial Officer.  The group reconciles changes in reserve estimates during the year by source, consisting of changes due to extensions and discoveries, purchases/sales of mineral-in-place, revisions of previous estimates, and production.  Revisions of previous estimates are further analyzed by changes related to pricing and changes related to performance.  All material fluctuations in reserve quantities identified through this analysis are discussed with Mr. Gasser.  Although unlikely, if an error in the estimated reserves is discovered through this review process, Mr. Gasser will submit the facts related to the error to the appropriate consultant for correction prior to the public release of the reserve estimates.

Other Information Concerning our Proved Reserves

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 PV-10 Value are based on various assumptions 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, 2009, we have not filed an estimate of our net proved oil and gas reserves with any federal authority or agency other than the SEC.

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Delivery Commitments

As of December 31, 2009, we had no commitments to provide fixed and determinable quantities of oil or natural gas in the near future under contracts or agreements, other than through customary marketing arrangements which require us to nominate estimated volumes of natural gas production for sale during periods of one month or less.

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,
	2009				2008				2007
	Gross		Net		Gross		Net		Gross		Net
	(Excludes wells in progress at the end of any period)
Development Wells:
Oil		58		49.5		70		51.5		34		14.9
Gas		11		5.4		41		14.7		34		13.2
Dry		1		1.0		1		1.0		-		-
Total		70		55.9		112		67.2		68		28.1
Exploratory Wells:
Oil		1		.2		1		.5		-		-
Gas		1		.1		3		1.7		12		8.0
Dry		6		4.4		4		3.0		7		5.8
Total		8		4.7		8		5.2		19		13.8
Total Wells:
Oil		59		49.7		71		52.0		34		14.9
Gas		12		5.5		44		16.4		46		21.2
Dry		7		5.4		5		4.0		7		5.8
Total		78		60.6		120		72.4		87		41.9

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.

Productive Well Summary

The following table sets forth certain information regarding our ownership, as of December 31, 2009, of productive wells in the areas indicated.

	Oil				Gas				Total
	Gross		Net		Gross		Net		Gross		Net
Permian Basin		5,516		518.9		736		96.1		6,252		615.0
Austin Chalk (Trend)		313		243.7		17		9.3		330		253.0
North Louisiana		-		-		51		16.7		51		16.7
South Louisiana		7		3.8		49		23.7		56		27.5
Cotton Valley Reef Complex		-		-		14		11.6		14		11.6
Other		6		5.2		41		12.2		47		17.4
Total		5,842		771.6		908		169.6		6,750		941.2

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Volumes, Prices and Production Costs

All of our oil and gas properties are located in one geographical area, specifically the United States.  The following table sets forth certain information regarding the production volumes of, average sales prices received from, and average production costs associated with all of our sales of oil and gas production for the periods indicated.

	Year Ended December 31,
	2009		2008		2007
Oil and Gas Production Data:
Oil (MBbls)		2,865		2,952		2,318
Gas (MMcf)		15,949		18,553		20,649
Natural gas liquids (MBbls)		240		182		222
Total (MBOE)		5,763		6,226		5,982
Average Realized Prices (a):
Oil ($/Bbl)	$	57.37	$	97.35	$	70.36
Gas ($/Mcf)	$	4.35	$	9.02	$	7.01
Natural gas liquids ($/Bbl)	$	30.83	$	54.45	$	43.74
Average Production Costs:
Production ($/MBOE) (b)	$	9.82	$	9.83	$	8.53

(a) Excludes any realized gains or losses on settled derivatives since none were designated as cash flow hedges during the periods presented.

(b) Excludes property taxes and severance taxes.

Only one field, the Giddings field in the Austin Chalk (Trend), accounted for 15% or more of our total proved reserves (on a BOE basis) as of December 31, 2009.  The following table discloses our oil, gas and natural gas liquids production from the Giddings field for the periods indicated.

	Year Ended December 31,
	2009		2008		2007
Giddings Field Oil and Gas Production Data:
Oil (MBbls)		963		1,189		589
Gas (MMcf)		773		709		621
Natural gas liquids (MBbls)		94		83		87
Total (MBOE)		1,186		1,390		780

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,
	2009		2008		2007
	(In thousands)
Property Acquisitions:
Proved	$	-	$	-	$	-
Unproved		12,558		36,397		15,746
Developmental Costs		86,672		260,073		45,611
Exploratory Costs		32,758		51,237		169,879
Total	$	131,988	$	347,707	$	231,236

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Acreage

The following table sets forth certain information regarding our developed and undeveloped leasehold acreage as of December 31, 2009 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		84,478		36,864		333,674		151,873		418,152		188,737
East Texas (a)		133,903		122,454		186,484		116,979		320,387		239,433
North Louisiana		5,405		4,613		160,326		149,729		165,731		154,342
South Louisiana		7,782		5,288		17,513		16,281		25,295		21,569
Other (b)		10,902		3,458		356,536		183,303		367,438		186,761
Total		242,470		172,677		1,054,533		618,165		1,297,003		790,842

(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:  Utah – 53,376; Mississippi – 43,187; Alabama – 38,912; Colorado – 28,798; and other – 19,030.

The following table sets forth expiration dates of the leases of our gross and net undeveloped acres as of December 31, 2009.

	Acres Expiring (a)
	2010				2011				2012
	Gross		Net		Gross		Net		Gross		Net
Permian Basin		89,746		42,813		31,599		19,085		2,986		2,493
East Texas (b)		30,566		23,453		35,900		31,030		73,277		35,746
North Louisiana		60,586		59,886		94,637		84,565		1,531		1,341
South Louisiana		11,365		11,151		4,161		3,525		195		190
Other		112,897		62,207		54,127		27,141		37,425		21,707
		305,160		199,510		220,424		165,346		115,414		61,477
(a)Acres expiring are based on contractual lease maturities. We may extend the leases prior to their expiration based upon planned activities or for other business activities. (b)Includes our acreage in the Austin Chalk (Trend), Cotton Valley Reef Complex and East Texas Bossier areas.

Desta Drilling

Through a wholly-owned subsidiary, Desta Drilling, we own and operate 12 drilling rigs, consisting of five 1,000 horsepower rigs, five 1,300 horsepower rigs and two 2,000 horsepower rigs.  As of March 12, 2010, we were using four of the 1,000 horsepower rigs and four of the 1,300 horsepower rigs to drill wells in our developmental drilling program.  The Desta Drilling rigs are reserved for our use, and we do not have any current plans to conduct contract drilling operations for third parties.  We are attempting to sell both of the 2,000 horsepower rigs and have classified those rigs as Assets Held for Sale in the accompanying consolidated financial statements.

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.

10

PART IV

Item 15 -                 Exhibits and Financial Statement Schedules

Financial Statements and Schedules

The consolidated financial statements and financial statement schedules were previously filed.

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††
**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

11

**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	Sixth Amendment to Amended and Restated Credit Agreement dated April 14, 2009, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on April 17, 2009††
**10.8	Seventh Amendment to Amended and Restated Credit Agreement dated May 26, 2009, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on May 26, 2009††
**10.9†	Outside Directors Stock Option Plan, filed as Exhibit 10.1 to the Company’s Form S-8 Registration Statement, Commission File No. 33-68316
**10.10†	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††
**10.11†	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††
**10.12†	Bonus Incentive Plan, filed as Exhibit 10.1 to the Company’s Form S-8 Registration Statement, Commission File No. 33-68320
**10.13†	First Amendment to Bonus Incentive Plan, filed as Exhibit 10.9 to the Company’s Form 10-K for the period ended December 31, 1997††
**10.14†	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††
**10.15†	Executive Incentive Stock Compensation Plan, filed as Exhibit 10.1 to the Company’s Form S-8 Registration Statement, Commission File No. 33-92834
**10.16†	First Amendment to Executive Incentive Stock Compensation Plan, filed as Exhibit 10.16 to the Company’s Form 10-K for the period ended December 31, 1996††
**10.17	Consolidation Agreement dated May 13, 1993 among Clayton Williams Energy, Inc., Warrior Gas Co. and the Williams Entities, filed as Exhibit 10.1 to the Company’s Form S-1 Registration Statement, Commission File No. 033-43350
**10.18	Amendment to Consolidation Agreement dated August 7, 2000 among Clayton Williams Energy, Inc., Warrior Gas Co., Clayton W. Williams, Jr. and the Williams Companies, filed as Exhibit 10.1 to the Company’s Form 10-Q for the period ended September 30, 2000††
**10.19	Agreement dated April 23, 1993 between the Company and Robert C. Lyon, filed as Exhibit 10.42 to the Company’s Form S-1 Registration Statement, Commission File No. 033-43350
**10.20	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††
**10.21	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.††

12

**10.22†	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††
**10.23†	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††
**10.24†	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††
**10.25†	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††
**10.26†	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††
**10.27†	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††
**10.28†	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††
**10.29†	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††
**10.30†	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††
**10.31†	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††
**10.32†	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††
**10.33†	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††
**10.34†	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††
**10.35†	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††
**10.36†	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††

13

**10.37†	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††
**10.38†	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††
**10.39†	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††
**10.40†	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††
**10.41†	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††
**10.42†	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††
**10.43†	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††
**10.44†	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††
**10.45†	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††
**10.46†	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††
**10.47†	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††
**10.48†	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††
**10.49†	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††
**10.50†	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††
**10.51†	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††
**10.52†	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††

14

**10.53†	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††
**10.54†	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††
**10.55†	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††
**10.56†	Form of Director Indemnification Agreement
**10.57†	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††
**10.58†	Fuhrman-Mascho Reward Plan dated December 1, 2009, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on December 2, 2009††
****21	Subsidiaries of the Registrant
*23.1	Consent of KPMG LLP
*23.2	Consent of Williamson Petroleum Consultants, Inc.
*23.3	Consent of Ryder Scott Company, L.P.
****24.1	Power of Attorney
*31.1	Certification by the President and Chief Executive Officer of the Company pursuant to Rule 13a – 14(a) of the Securities Exchange Act of 1934
*31.2	Certification by the Chief Financial Officer of the Company pursuant to Rule 13a – 14(a) of the Securities Exchange Act of 1934
***32.1	Certifications by the Chief Executive Officer and Chief Financial Officer of the Company pursuant to 18 U.S.C. § 1350
*99.1	Report of Williamson Petroleum Consultants, Inc. independent consulting engineers
*99.2	Report of Ryder Scott Company, L.P. independent consulting engineers
*Filed herewith
**Incorporated by reference to the filing indicated
***Previously furnished
****Previously filed
†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.

15

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)
Date:  December 20, 2010	By:	/s/ MEL G. RIGGS
		Mel G. Riggs
		Executive Vice President,
		Chief Operating Officer

16

CLAYTON WILLIAMS ENERGY, INC.

EXHIBIT INDEX

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††
**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

17

**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	Sixth Amendment to Amended and Restated Credit Agreement dated April 14, 2009, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on April 17, 2009††
**10.8	Seventh Amendment to Amended and Restated Credit Agreement dated May 26, 2009, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on May 26, 2009††
**10.9†	Outside Directors Stock Option Plan, filed as Exhibit 10.1 to the Company’s Form S-8 Registration Statement, Commission File No. 33-68316
**10.10†	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††
**10.11†	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††
**10.12†	Bonus Incentive Plan, filed as Exhibit 10.1 to the Company’s Form S-8 Registration Statement, Commission File No. 33-68320
**10.13†	First Amendment to Bonus Incentive Plan, filed as Exhibit 10.9 to the Company’s Form 10-K for the period ended December 31, 1997††
**10.14†	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††
**10.15†	Executive Incentive Stock Compensation Plan, filed as Exhibit 10.1 to the Company’s Form S-8 Registration Statement, Commission File No. 33-92834
**10.16†	First Amendment to Executive Incentive Stock Compensation Plan, filed as Exhibit 10.16 to the Company’s Form 10-K for the period ended December 31, 1996††
**10.17	Consolidation Agreement dated May 13, 1993 among Clayton Williams Energy, Inc., Warrior Gas Co. and the Williams Entities, filed as Exhibit 10.1 to the Company’s Form S-1 Registration Statement, Commission File No. 033-43350
**10.18	Amendment to Consolidation Agreement dated August 7, 2000 among Clayton Williams Energy, Inc., Warrior Gas Co., Clayton W. Williams, Jr. and the Williams Companies, filed as Exhibit 10.1 to the Company’s Form 10-Q for the period ended September 30, 2000††
**10.19	Agreement dated April 23, 1993 between the Company and Robert C. Lyon, filed as Exhibit 10.42 to the Company’s Form S-1 Registration Statement, Commission File No. 033-43350
**10.20	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††
**10.21	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.††

18

**10.22†	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††
**10.23†	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††
**10.24†	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††
**10.25†	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††
**10.26†	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††
**10.27†	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††
**10.28†	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††
**10.29†	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††
**10.30†	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††
**10.31†	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††
**10.32†	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††
**10.33†	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††
**10.34†	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††
**10.35†	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††
**10.36†	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††

19

**10.37†	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††
**10.38†	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††
**10.39†	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††
**10.40†	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††
**10.41†	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††
**10.42†	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††
**10.43†	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††
**10.44†	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††
**10.45†	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††
**10.46†	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††
**10.47†	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††
**10.48†	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††
**10.49†	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††
**10.50†	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††
**10.51†	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††
**10.52†	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††

20

**10.53†	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††
**10.54†	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††
**10.55†	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††
**10.56†	Form of Director Indemnification Agreement
**10.57†	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††
**10.58†	Fuhrman-Mascho Reward Plan dated December 1, 2009, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on December 2, 2009††
****21	Subsidiaries of the Registrant
*23.1	Consent of KPMG LLP
*23.2	Consent of Williamson Petroleum Consultants, Inc.
*23.3	Consent of Ryder Scott Company, L.P.
***24.1	Power of Attorney
*31.1	Certification by the President and Chief Executive Officer of the Company pursuant to Rule 13a – 14(a) of the Securities Exchange Act of 1934
*31.2	Certification by the Chief Financial Officer of the Company pursuant to Rule 13a – 14(a) of the Securities Exchange Act of 1934
***32.1	Certifications by the Chief Executive Officer and Chief Financial Officer of the Company pursuant to 18 U.S.C. § 1350
*99.1	Report of Williamson Petroleum Consultants, Inc. independent consulting engineers
*99.2	Report of Ryder Scott Company, L.P. independent consulting engineers
*Filed herewith
**Incorporated by reference to the filing indicated
***Previously furnished
****Previously filed
†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.

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