Clayton Williams Energy CORRESP Correspondence with SEC

September 1, 2010

Securities and Exchange Commission

Division of Corporation Finance

100 F Street, N.E.

Washington, D.C. 20549-7010

Attention: Mr. H. Roger Schwall

Re:	Clayton Williams Energy, Inc.
	Form 10-K for Fiscal Year Ended December 31, 2009
	filed March 12, 2010 (File No. 1-10924)

Dear Mr. Schwall:

We submit the following responses to the comments of the staff of the Securities and Exchange Commission (the “Staff”) set forth in the second comment letter dated August 16, 2010 (the “Comment Letter”). For your convenience, we have repeated each comment of the Staff exactly as it appears in the Comment Letter and provided the Company’s response below the comment.

Form 10-K for the Fiscal Year Ended December 31, 2009

Exhibits 99.1 and 99.2

1. We note your response to prior comments 7 through 9 from our letter to you dated June 2, 2010. In the revised reports you file, please ensure that Ryder Scott addresses those issues that the staff discussed with Ryder Scott. Please also ensure that the revised reports you file disclose:

· The 12 month average benchmark product prices and the average adjusted prices used to determine reserves. In this regard, we note that the Williamson report has disclosed the benchmark prices used, but not the average adjusted prices used. The Ryder Scott report does not appear to disclose either price; and

· The aggregate percentage difference between your proved reserve estimates and those of your third party engineer.

Response:

We note the Staff’s comments and propose to obtain and file revised reports of Williamson Petroleum Consultants, Inc. and Ryder Scott Company, L.P. that address the staff’s comments. Attached as Schedule 1 and Schedule 2 are copies of the revised reports of Williamson Petroleum Consultants, Inc. and Ryder Scott Company, L.P., respectively, which have been marked to show all changes from the versions submitted with our first response letter dated June 16, 2010. Specifically, these revised reports disclose the 12-month average benchmark product prices used to determine reserves and the weighted average realized price of those reserves after giving effect to the differentials applicable to each evaluated property. Additionally, we have been advised by Ryder Scott that their revised report addresses those issues that the Staff discussed with Ryder Scott.

In regards to the Staff’s comment that the revised reports disclose the aggregate percentage difference between our proved reserves estimates and those of our third party engineers, we do not believe this disclosure is applicable since the third party engineers develop their own estimates of our reserves, rather than audit internal reserve estimates. Our internal engineering staff assimilates all available technical and operational data necessary to evaluate our reserves and provides this data to our third party engineers in an AriesTM database prior to the effective date of the report. As subsequent data becomes available, including data on wells drilled and/or completed prior to the issuance of the report, this data is provided to our third party engineers for use in developing their estimates. Since we do not make a complete, internal reserve estimate at year-end, we do not have an in-house estimate of reserves to compare to the estimates of our third party engineers.

2. The revised copy of the Ryder Scott report refers to a consent. If the report refers to a consent, it needs to make clear that it refers to the consent for the report to be incorporated by reference into filings under the Securities Act of 1933. Insofar as the Exchange Act does not provide for the filing of a consent, the report should not include text which may be read to suggest otherwise.

Response:

We note the Staff’s comment. The revised report of Ryder Scott attached as Schedule 2 has addressed the Staff’s comment.

We acknowledge that (1) the Company is responsible for the adequacy and accuracy of the disclosures in the filings, (2) Staff comments or changes to disclosures in response to Staff comments do not foreclose the Commission from taking any action with respect to the filings, (3) the Company may not assert Staff comments as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the United States.

We respectfully request an opportunity to discuss this Response Letter further with the Staff if, following a review of this information, the Staff does not concur with our views. We propose to file an

amendment to our Form 10-K for the year ended December 31, 2009 to address all of the Staff’s comments upon receipt of the Staff’s reply to this response. Please do not hesitate to contact the undersigned by telephone at (432) 682-6324 or facsimile at (432) 682-1452 with any further questions or comments.

	Sincerely,


	/s/ Mel G. Riggs
	Mel G. Riggs
	Senior Vice President and
	Chief Financial Officer

cc:	Nabil Nehme (KPMG LLP)
	William R. Volk (Vinson & Elkins L.L.P.)

Schedule 21

Exhibit 99.1

WILLIAMSON PETROLEUM CONSULTANTS, INC.

TEXAS REGISTERED ENGINEERING FIRM F-81

303 VETERANS AIRPARK LANE, SUITE 1100

MIDLAND, TEXAS 79705

PHONE: 432-685-6100

FAX: 432-685-3909

E-MAIL: WPC@WPC-INC.COM

February 15, 2010

Clayton Williams Energy, Inc.

Six Desta Drive, Suite 3000

Midland, Texas 79705

Attention Mr. Ron D. Gasser

Gentlemen:

Subject: Evaluation of Oil and Gas Reserves

to the Interests of Clayton Williams Energy, Inc.

in Certain Domestic Oil and Gas Reserves and

to the Interests of Warrior Gas Company

in the Gataga Gas Unit No. 5A, Vermejo

(Ellenburger) Field, Loving County, Texas

Effective December 31, 2009

for Disclosure to the

Securities and Exchange Commission

Williamson Project 9.9376

Williamson Petroleum Consultants, Inc. has performed an engineering evaluation to estimate proved reserves and future net revenue from domestic oil and gas reserves to the subject interests as of December 31, 2009. This evaluation was authorized by Mr. Ron D. Gasser of Clayton Williams Energy, Inc. (Williams Energy). Warrior Gas Company is a wholly-owned subsidiary of Williams Energy. Projections of the reserves and future net revenue to the evaluated interests were estimated based on the definitions and disclosure guidelines ~~contained in~~of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). The results of our evaluation, completed on February 15, 2010, are presented herein. This evaluation ~~may be used in disclosure to the Securities and Exchange Commission~~was prepared for public disclosure by Williams Energy in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations and is an annual update of the evaluated properties.

Based on information provided by Williams Energy, the total proved reserves summarized in our report represent approximately 53.2 percent of their consolidated proved reserves on a barrel equivalent basis for their continuing operations located in the states of California, Louisiana, Mississippi, New Mexico, North Dakota, Texas and Wyoming. Our report addresses 51 percent of the total proved developed net liquid hydrocarbon reserves, 57 percent of the total proved developed net gas reserves, 60 percent of the total proved

undeveloped net liquid hydrocarbon reserves, and 21 percent of the total proved undeveloped net gas reserves of Williams Energy as of December 31, 2009.

The hydrocarbon prices used in the preparation of this report are based on the average prices during the 12-month period prior to the effective date of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements as required by the SEC regulations. Actual future prices may vary significantly from the prices required by SEC regulations; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report.

Following is a summary of the results of the evaluation effective December 31, 2009:

	PROVED DEVELOPED PRODUCING	PROVED DEVELOPED NONPRODUCING	PROVED UNDEVELOPED	TOTAL PROVED
Net Reserves to the Evaluated Interests:
Oil/Condensate, MBBL	7,090.555	293.531	2,389.076	9,773.161
NGL, MBBL	1,126.627	2.600	111.916	1,241.144
Gas, MMCF	39,828.266	421.470	1,106.806	41,356.543

Future Net Revenue, M$:
Undiscounted	328,496.031	9,367.857	65,199.016	403,062.938
Discounted Per Annum at 10.00 Percent	227,367.609	6,287.630	35,293.367	268,948.625

Note: Due to the method of rounding in ARIES, Total Proved may not equal PDP + PDNP + PU

The attached Definitions describe all categories of reserves, and the Discussion describes the bases of this evaluation.

It has been a pleasure to serve you by preparing this engineering evaluation. All related data will be retained in our files and are available for your review.

Yours very truly,

WILLIAMSON PETROLEUM CONSULTANTS, INC.

John D. Savage, P.E.

Executive Vice President

JDS/chk

Attachments

	Williamson Petroleum Consultants, Inc.
	F-81

D I S C U S S I O N

INTRODUCTION

Williamson Petroleum Consultants, Inc. (Williamson) has performed an engineering evaluation to estimate proved reserves and future net revenue from certain domestic oil and gas reserves to the interests of Clayton Williams Energy, Inc. (Williams Energy) and to the interests of Warrior Gas Company (Warrior), a wholly-owned subsidiary of Williams Energy, in the Gataga Gas Unit No. 5A, Vermejo (Ellenburger) Field, Loving County, Texas. This evaluation was authorized by Mr. Ron D. Gasser of Williams Energy. The results of the evaluation are summarized in the cover letter and are presented by year in the summary tables.

The properties in this report are organized into the following six groups as instructed by Williams Energy.

Trend Group - This is the core group of Williams Energy properties which represents 48.6 percent of the total future net revenue discounted at 10.0 percent (DFNR). In this group, 98.0 percent of the value is in properties producing from or will produce from the Austin Chalk/Buda formations. The proved developed producing properties comprise 89.3 percent of this group’s value.

Louisiana Group - The 130 properties in this group are located in 19 fields in Bienville, Caddo, Claiborne, Jackson, Jefferson, Lincoln, Plaquemines, St. Bernard, Tensas, Union, Vernon, and Webster Parishes, Louisiana. The properties represent 21.9 percent of the total DFNR. The proved developed producing properties comprise 90.0 percent of this group’s value.

Permian Group — This group includes only properties in Texas and represents 16.2 percent of the total DFNR. The proved developed producing properties comprise 96.6 percent of this group’s value. The properties are in Andrews, Crockett, Garza, Gaines, Glasscock, Reeves, Sterling, Upton, and Yoakum Counties. The Gataga Gas Unit No. 5A, Vermejo (Ellenburger) Field, Loving County is also included in this group and makes up 1.4 percent of this group.

New Mexico Group - This group includes all properties in New Mexico and represents 9.4 percent of the total DFNR. These New Mexico properties are in the Empire; Empire, East; Empire, South; Red Lake; and Rocky Arroyo Fields in Eddy County and in the Button Mesa and Foster Fields in Lea County. The proved developed producing properties comprise 56.5 percent of this group’s value.

Cotton Valley Reef Group - There are 15 wells in this group which represent 2.1 percent of the total DFNR. These wells are in the Bear Grass, Bossier and Kenwood Fields, Leon County, Texas and Bossier; Cotropia; Fazzino; Highcotton; Mumford, N.; Oak Grove; Tall City; and Whatley Fields, Robertson County, Texas. This group is 100.0 percent proved developed producing.

Other Group - The remaining 1.8 percent of the total DFNR is in properties in various fields in the states of California, Louisiana, Mississippi, North Dakota and Texas. The proved developed producing properties comprise 88.5 percent of this group’s value.

In addition to the Total Summaries published in this report, reserve category summaries, Lists of Properties, and individual lease reserves and economics projections are included for each group.

Williamson evaluated individually those properties designated by Williams Energy as major-value properties net to the Williams Energy interests and certain properties associated with nonproducing reserves. These major-value properties represent 99.999

percent of the total DFNR. Thirty-two properties in the Giddings Field area, Texas; nine properties in the Pearsall Field, Texas; and 37 non-operated overriding royalty interest properties in Louisiana, Mississippi, North Dakota, and Texas were designated by Williams Energy as minor-value properties and were not evaluated individually but were combined and projected as three minor-value property composites. These minor-value property composites represent the remaining 0.001 percent of the total DFNR. These composite projections of net production were based on data supplied by Williams Energy. The lists of the properties included in these minor-value group composite projections are presented in Volume I of this report following the List of Properties evaluated individually.

The individual projections of lease reserves and economics include data that describe the production forecasts and associated evaluation parameters such as interests, taxes, product prices, operating costs, investments, salvage values, abandonment costs, and net profit interests.

The properties evaluated in this report are located in the states of California, Louisiana, Mississippi, New Mexico, North Dakota, Texas and Wyoming, with greater than 70 percent of the value in the properties in the Giddings Field, Brazos, Burleson, Fayette, Lee, Milam, and Robertson Counties, Texas and in the properties in the state of Louisiana.

Projections of the reserves and future net revenue to the evaluated interests were based on economic parameters and operating conditions considered to be applicable as of December 31, 2009. This evaluation may be used in disclosure to the Securities and Exchange Commission (SEC) and is an annual update of the evaluated properties.

Net income to the evaluated interests is the future net revenue after consideration of royalty revenue payable to others, taxes, operating expenses, investments, salvage values, abandonment costs, and net profit interests, as applicable. The future net revenue is before federal income tax and excludes consideration of any encumbrances against the properties if such exist.

The future net revenue values presented in the Lease Reserves and Economics section of this report and summarized in the cover letter were based on projections of oil and gas production. It was assumed there would be no significant delay between the date of oil and gas production and the receipt of the associated revenue for this production.

Unless specifically identified and documented by Williams Energy as having curtailment problems, gas production trends have been assumed to be a function of well productivity and not of market conditions.

Oil and gas reserves were evaluated for the proved developed producing, proved developed nonproducing, and proved undeveloped categories. The summary classification of proved developed reserves combines the proved developed producing and proved developed nonproducing categories. In preparing this evaluation, no attempt has been made to quantify the element of uncertainty associated with any category. Reserves were assigned to each category as warranted. The attached Definitions describe all categories of reserves.

Oil reserves are expressed in thousands of United States (U.S.) barrels (MBBL) of 42 U.S. gallons. Gas volumes are expressed in millions of cubic feet (MMCF) at 60 degrees Fahrenheit and at the legal pressure base that prevails in the state in which the reserves are located. No adjustment of the individual gas volumes to a common pressure base has been made.

The future net revenue was discounted at an annual rate of 10.00 percent in accordance with the reporting requirements of the SEC. Future net revenue was also discounted at various secondary rates and is displayed as totals only. The future net revenue was discounted monthly. Capital costs were discounted at the time they occurred. No opinion is expressed by Williamson in this report as to a fair market value of the evaluated properties.

This report includes only those costs and revenues which are considered by Williams Energy to be directly attributable to individual leases and areas. There could exist other revenues, overhead costs, or other costs associated with Williams Energy or Warrior which are not included in this report. Such additional costs and revenues are outside the scope of this report. This report is not a financial statement for Williams Energy or Warrior and should not be used as the sole basis for any transaction concerning Williams Energy, Warrior, or the evaluated properties.

The reserves projections in this evaluation are based on the use of the available data and accepted industry engineering methods. Future changes in any operational or economic parameters or production characteristics of the evaluated properties could increase or decrease their reserves. Unforeseen changes in market demand or allowables set by various regulatory agencies could also cause actual production rates to vary from

those projected. The dates of first production for nonproducing properties were based on estimates by Williams Energy and the actual dates may vary from those estimated. Williamson reserves the right to alter any of the reserves projections and the associated economics included in this evaluation in any future evaluations based on additional data that may be acquired.

The operations of Williams Energy may be subject to various levels of governmental controls and regulations. These controls and regulations may include matters relating to land tenure, drilling, production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax and investment and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of reserves actually recovered and amounts of income actually received to differ significantly from the estimated quantities.

Williamson is an independent consulting firm and does not own any interests in the oil and gas properties covered by this report. No employee, officer, or director of Williamson is an employee, officer, or director of Williams Energy. Neither the employment of nor the compensation received by Williamson is contingent upon the values assigned to the properties covered by this report.

DATA SOURCES

All data utilized in the preparation of this report with respect to interests, reversionary status, oil and gas prices, gas categories, gas contract terms, operating expenses, investments, salvage values, abandonment costs, net profit interests, well information, and current operating conditions, as applicable, were provided by Williams Energy. Production data provided by Williams Energy were used where available. If

production data were not provided by Williams Energy, production data from public records were utilized. The production data were updated generally through September 2009 for operated properties and August 2009 for non-operated properties. All data have been reviewed for reasonableness and, unless obvious errors were detected, have been accepted as correct. It should be emphasized that revisions to the projections of reserves and economics included in this report may be required if the provided data are revised for any reason. No inspection of the properties was made, as this was not considered within the scope of this evaluation. No investigation was made of any environmental liabilities that might apply to the evaluated properties, and no costs are included for any possible related expenses.

Williams Energy represented to Williamson that it has, or can generate, the financial and operational capabilities to accomplish those projects evaluated by Williamson which require capital expenditures.

METHOD OF RESERVES DETERMINATION

The estimates of reserves contained in this report were determined by accepted industry methods and in accordance with the attached Definitions of Oil and Gas Reserves. Williamson utilized all methods and procedures that were deemed necessary to estimate the proved and probable reserves of Williams Energy, and considered those methods and procedures as appropriate for this purpose. Methods utilized in this report include extrapolation of historical production trends, analogy to similar properties, and volumetric calculations.

Where sufficient production history and other data were available, reserves for producing properties were determined by extrapolation of historical production trends. Analogy to similar properties or volumetric calculations were used for nonproducing

properties and those producing properties which lacked sufficient production history and other data to yield a definitive estimate of reserves. Reserves projections based on analogy are subject to change due to subsequent changes in the analogous properties or subsequent production from the evaluated properties. Volumetric calculations are often based upon limited log and/or core analysis data and incomplete reservoir fluid and formation rock data. Since these limited data must frequently be extrapolated over an assumed drainage area, subsequent production performance trends or material balance calculations may cause the need for significant revisions to the estimates of reserves.

PRICING

The hydrocarbon prices used in the preparation of this report are based on SEC price parameters using the average prices during the 12-month period prior to the effective date of this report, determined as unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements ~~as required by the SEC regulations.~~. Actual future prices may vary significantly from the prices required by SEC regulations; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report.

~~OIL~~

The price of $61.18 per barrel of NYMEX West Texas Intermediate oil was used as the effective date base oil price. Price adjustments applied to the NYMEX base price for each individual property for API gravity, any bonus paid, and the difference between NYMEX and posted oil prices were provided by Williams Energy as decimal multipliers.

After the effective date, prices were held constant for the life of the properties. No attempt has been made to account for oil price fluctuations which have occurred in the market subsequent to the effective date of this report.

~~GAS~~

The price of $3.833 per million British thermal units (MMBTU) for NYMEX Henry Hub gas was used as the effective date base gas price. Price adjustments applied to the NYMEX base price for each individual property for transportation and handling charges, and regional differences between NYMEX and spot prices were provided by Williams Energy as decimal multipliers. After the effective date, prices were held constant for the life of the properties unless Williams Energy indicated that changes were provided for by contract. All gas prices were applied to projected wellhead volumes.

~~NGL~~

The price of $61.18 per barrel of NYMEX West Texas Intermediate oil was used as the effective date base NGL price. Individual lease price adjustments for the differential between oil and NGL prices were also provided by Williams Energy as decimal multipliers for those properties that had NGL sales. After the effective date, prices were held constant for the life of the properties. No attempt has been made to account for the NGL price fluctuations which have occurred in the market subsequent to the effective date of this report.

Williams Energy furnished us with the above mentioned average prices in effect on December 31, 2009. These initial SEC hydrocarbon benchmark prices were determined using the 12-month average first-day-of-the-month cash commodity prices, as quoted by the Wall Street Journal, appropriate to the geographic area where the

hydrocarbons are sold. If the first day of the month fell on a non-trading day, the closing cash commodity price for the previous trading day was used. These benchmark prices are prior to the adjustments for differentials as described herein. The table below contains the “Average Benchmark Prices” and “WSJ Price Reference” used for the geographic areas included in the report.

The product prices that were actually used to determine the future gross revenue for each property reflect adjustments to the benchmark prices for gravity, quality, local conditions, gathering and transportation fees and/or distance from market, referred to herein as “differentials.” The differentials used in the preparation of this report were supplied to us by Williams Energy. The differentials furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by Williams Energy to determine these differentials.

In addition, the table below contains the Average Benchmark Prices adjusted for differentials and referred to herein as the “Average Realized Prices.” The average realized prices shown in the table below were determined from the total proved future gross revenue before production taxes and the total proved net reserves for the geographic area and presented in accordance with SEC disclosure requirements for each of the geographic areas included in the report.

Geographic Area	Product	WSJ Price Reference	Average Benchmark Prices	Average Realized Prices
North America
United States	Oil/Condensate	WTI Cushing	$61.18/Bbl	$57.86/Bbl
	NGL	WTI Cushing	$61.18/Bbl	$29.43/Bbl
	Gas	NG Henry Hub	$3.83/MMBTU	$3.75/MCF

The effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in our individual property evaluations.

PRICING STATEMENT

It should be emphasized that with the current economic uncertainties, fluctuation in market conditions could significantly change the economics of the properties included in this report.

OPERATING EXPENSES

Operating expenses were provided by Williams Energy and represented, when possible, the average of all recurring expenses which are billable to the working interest owners. These expenses included, but were not limited to, all direct operating expenses and any ad valorem taxes not deducted separately. These costs also include COPAS overhead and any overhead costs (general and administrative) which are billable to the working interest owners. Expenses for workovers, well stimulations, and other maintenance were not included in the operating expenses unless such work was expected on a recurring basis. Judgments for the exclusion of the nonrecurring expenses were made by Williams Energy. Separate operating expenses have been included for most leases/wells for either variable lifting costs per barrel of oil or gas treatment costs per MCF of gas. For new and developing properties where data were unavailable, operating expenses were estimated by Williams Energy. Operating costs were held constant for the life of the properties.

PRODUCTION AND AD VALOREM TAXES

State production taxes have been deducted at the rates provided by Williams Energy. The Gataga Gas Unit No. 5A, Vermejo (Ellenburger) Field, Loving County, Texas and certain wells in the Cotton Valley Reef Group have reduced gas severance tax rates. County ad valorem taxes provided by Williams Energy were deducted for those Williams

Energy-operated properties located in Texas. Any ad valorem taxes for properties in other states and nonoperated properties in Texas were represented by Williams Energy to be included in the operating expenses.

INVESTMENTS

All capital costs for drilling and completion of wells, recompletions to behind-pipe zones, restimulation, and other nonrecurring workover or operating costs have been deducted as applicable. These costs were provided by Williams Energy. No adjustments were made to account for the potential effect of inflation on these costs.

SALVAGE AND PROPERTY ABANDONMENT

Neither salvage values nor abandonment costs were provided by Williams Energy to be included in this evaluation.

JDS/chk

WILLIAMSON PETROLEUM CONSULTANTS, INC.

DEFINITIONS OF OIL AND GAS RESERVES(1)

Developed oil and gas reserves.

Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Undeveloped oil and gas reserves.

Undeveloped oil and gas reserves are reserves of any category 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.

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.

Proved oil and gas reserves. (2)

Proved oil and gas reserves are those quantities of oil and 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 — prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and

(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

(B) The project has been approved for development by all necessary parties and entities, including government entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-date-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Probable reserves

Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

(i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

(ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.

(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proves reserves.

(iv) See also paragraphs (iv) and (vi) below in Possible reserves.

Possible reserves.

Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

(i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.

(ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.

(iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

(iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.

(v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

(vi) Pursuant to paragraph (iii) in the previous Proved oil and gas reserves section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists of an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

(1)These definitions are from 17 CFR § 210.4-10 (Federal Register Dated December 31, 2008/Filed January 13, 2009.

(2)Williamson Petroleum Consultants, Inc. separates proved developed reserves into proved developed producing and proved developed nonproducing reserves. This is to identify proved developed producing reserves as those to be recovered from actively producing wells; proved developed nonproducing reserves as those to be recovered from wells or intervals within wells, which are completed but shut in waiting on equipment or pipeline connections, or wells where a relatively minor expenditure is required for recompletion to another zone.

Schedule 32

Exhibit 99.2

Southwest Royalties, Inc.

Estimated

Future Reserves and Income

Attributable to Certain

Leasehold and Royalty Interests

SEC Parameters

As of

December 31, 2009

\s\ William K. Fry		\s\ John E. Hamlin
William K. Fry, P.E.		John E. Hamlin, P.E.
TBPE License No. 97134		TBPE License No. 65319
Senior Petroleum Engineer		Managing Senior Vice President

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

[SEAL]

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS



TBPE REGISTERED ENGINEERING FIRM F-1580		FAX (713) 651-0849
1100 LOUISIANA SUITE 3800	HOUSTON, TEXAS 77002-~~5218~~5235	TELEPHONE (713) 651-9191

January 26, 2010

Southwest Royalties, Inc.

Claydesta Center

Six Desta Drive, Suite 3000

Midland, TX 79705

Gentlemen:

At your request, ~~we have~~Ryder Scott Company (Ryder Scott) has prepared an estimate of the proved and probable reserves, future production, and income attributable to certain leasehold and royalty interests of Southwest Royalties, Inc. (SWR), a wholly-owned subsidiary of Clayton Williams Energy, Inc. (CWEI)), as of December 31, 2009. The subject properties are located in the states of Alabama, Arkansas, Kansas, Louisiana, Mississippi, Montana, North Dakota, New Mexico, Oklahoma and Texas. The reserves and income data were estimated based on the definitions and disclosure guidelines ~~contained in~~of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). ~~The results of our~~Our third party study, completed on January 26, 2010~~, are~~ and presented herein, was prepared for public disclosure by CWEI in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations.

The properties evaluated by Ryder Scott account for a portion of CWEI’s total net proved reserves as of December 31, 2009. Based on information provided by CWEI, the ~~total proved reserves summarized in our report represent approximately 46.2~~third party estimate conducted by Ryder Scott addresses 48 percent of ~~their~~the total ~~consolidated~~ proved developed net liquid hydrocarbon reserves ~~on a barrel equivalent basis for their continuing operations, and~~ , 43 percent of the total ~~probable reserves summarized in our report~~proved developed net gas reserves, 39 percent of the total proved undeveloped net liquid hydrocarbon reserves, and 79 percent of the total proved undeveloped net gas reserves of CWEI. The properties evaluated by Ryder Scott represent 100 percent of ~~their~~CWEI’s total net probable reserves ~~on a barrel equivalent basis for their continuing operations~~as of December 31, 2009.

The estimated reserves and future net income amounts presented in this report, as of December 31, 2009, are related to hydrocarbon prices. The hydrocarbon prices used in the preparation of this report are based on the average prices during the 12-month period prior to the ending date of the period covered in this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements, as required by the SEC regulations. Actual future prices may vary significantly from the prices required by SEC regulations; therefore, volumes of reserves actually

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recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The results of this study are summarized below.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

SEC PARAMETERS

Estimated Net Reserves and Income Data

Certain Leasehold and Royalty Interests of

Southwest Royalties, Inc.

As of December 31, 2009

	Proved
	Developed						Total
	Producing		Non-Producing		Undeveloped		Proved
*Net Remaining Reserves*
Oil/Condensate – Barrels	6,767,137		1,157,123		1,565,134		9,489,394
Plant Products – Barrels	168,993		32,982		67,726		269,701
Gas – MMCF	24,300		6,175		4,136		34,611

*Income Data*
Future Gross Revenue	$	447,193,344	$	82,108,891	$	96,608,477	$	625,910,712
Deductions	193,528,031		36,272,270		48,813,695		278,613,996
Future Net Income (FNI)	$	253,665,313	$	45,836,621	$	47,794,782	$	347,296,716

Discounted FNI @ 10%	$	150,866,781	$	26,071,420	$	12,672,907	$	189,611,108

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

	Total
	Probable
	Undeveloped
*Net Remaining Reserves*
Oil/Condensate – Barrels	915,222
Gas – MMCF	5,027

*Income Data*
Future Gross Revenue	$	62,908,977
Deductions	37,536,145
Future Net Income (FNI)	$	25,372,832

Discounted FNI @ 10%	$	11,970,041

Liquid hydrocarbons are expressed in standard 42 gallon barrels. All gas volumes are reported on an “as sold” basis” expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located.

The estimates of the reserves, future production, and income attributable to properties in this report were prepared using the economic software package AriesTM System Petroleum Economic Evaluation Software, a copyrighted program of Halliburton. The program was used solely at the request of SWR. Ryder Scott has found this program to be generally acceptable, but notes that certain summaries and calculations may vary due to rounding and may not exactly match the sum of the properties being summarized. Furthermore, one line economic summaries may vary slightly from the more detailed cash flow projections of the same properties, also due to rounding. The rounding differences are not material.

The future gross revenue is after the deduction of production taxes. The deductions ~~comprise~~incorporate the normal direct costs of operating the wells, ad valorem taxes, recompletion costs, and development costs. Certain gas, oil and condensate processing and handling fees, including compression fees where applicable, are included as “operating” costs. The future net income is before the deduction of state and federal income taxes and general administrative overhead, and has not been adjusted for outstanding loans that may exist nor does it include any adjustment for cash on hand or undistributed income.

~~Liquid~~At the grand summary level, liquid hydrocarbon reserves account for approximately 81 percent ~~of the total future gross revenue from proved reserves~~ and gas reserves account for the remaining 19 percent of total future gross revenue from proved reserves. ~~Liquid~~Similarly, liquid hydrocarbon reserves account for approximately 76 percent ~~of the total future gross revenue from probable reserves~~ and gas reserves account for the remaining 24 percent of total future gross revenue from probable reserves.

The discounted future net income shown above was calculated using a discount rate of 10 percent per annum compounded monthly. Future net income was discounted at four other discount rates~~, which~~ that were also compounded monthly. These results are shown in summary form as follows.

	Discounted Future Net Income
	As of December 31, 2009
Discount Rate	Total		Total
Percent	Proved		Probable

6	$	229,156,406	$	15,992,902
9	$	197,988,031	$	12,858,153
12	$	175,048,656	$	10,385,600
15	$	157,378,469	$	8,406,071

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

The results shown above are presented for your information and should not be construed as our estimate of fair market value.

Reserves Included in This Report

The proved and probable reserves included herein conform to the definitions as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10 (a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “Petroleum Reserves Definitions” is included as an attachment to this report.

The various proved and probable reserve status categories are defined inunder the attachment ~~to this report titled~~entitled “Petroleum Reserves Definitions.”” in this report. The proved developed ~~proved~~ non-producing reserves included herein consist of the behind pipe category.

No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist. The proved and probable gas volumes included herein do not attribute gas consumed in operations as reserves.

While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may also increase or decrease from existing levels, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

Reserves are those estimated remaining quantities of petroleum that are anticipated to be economically producible, as of a given date, from known accumulations under defined conditions. All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. At SWR’s request, this report addresses only the proved and probable reserves attributable to the properties evaluated herein.

Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward. If deterministic methods are used, the SEC has defined reasonable certainty for proved reserves as a “high degree of confidence that the quantities will be recovered.” Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. The proved and probable reserves ~~and income quantities attributable to the different~~included herein were estimated using deterministic methods.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Proved reserve ~~classifications~~estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are ~~included herein have not been adjusted~~made to ~~reflect these varying degrees of risk associated~~the estimated ultimate recovery (EUR) with ~~them and thus are not comparable.~~time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.” Moreover, estimates of proved reserves may ~~increase or decrease~~be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical ~~risks. As a result, the estimates of oil and gas reserves have an intrinsic uncertainty. The~~or economic risks. Therefore, the proved reserves included in this report are~~, therefore,~~ estimates only and should not be construed as being exact quantities~~. They may or may not be actually recovered,~~; and if recovered, the revenues therefrom, and the actual costs related thereto, could be more or less than the estimated amounts.

SWR’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure, and leasing, the legal rights to produce hydrocarbons including drilling, and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax and ~~investment and~~ are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of proved and probable reserves actually recovered and amounts of proved and probable income actually received to differ significantly from the estimated quantities.

The estimates of proved and probable reserves presented herein were based upon a detailed study of the properties in which SWR owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included for potential ~~liability~~liabilities to restore and clean up damages, if any, caused by past operating practices.

Estimates of Reserves

~~In general,~~The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas, and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods or; (2) volumetric-based methods; and (3) analogy ~~were~~ . These methods may be used to singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserve evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate ~~the reserves included in this report; however, other methods were used in certain cases where~~ , the established or anticipated performance characteristics of the ~~data indicated such other methods were more appropriate in our opinion. The reserves estimated by the performance methods~~ reservoir being evaluated and the stage of development or producing maturity of the property.

In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserve quantities are estimated using the deterministic incremental approach, the

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

uncertainty for each discrete incremental quantity of the reserves is addressed by the reserve category assigned by the evaluator. Therefore, it is the categorization of reserve quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely than not to be achieved.” The SEC states that “probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.” The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.” All quantities of reserves within the same reserve category must meet the SEC definitions as noted above.

Estimates of reserves quantities and their associated reserve categories may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reserve categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.

The proved reserves for the properties included herein were estimated by performance methods or analogy. Approximately 88 percent of the proved producing reserves attributable to producing wells and/or reservoirs were estimated by performance methods. These performance methods include, but may not be limited to, decline curve analysis which utilized extrapolations of ~~various~~ historical production and pressure data available through September, 2009 in those cases where such data were considered to be definitive. ~~Reserves~~The data utilized in this analysis were supplied to Ryder Scott by SWR or obtained from public data sources and were ~~estimated by analogy in those cases~~considered sufficient for the purpose thereof. Approximately 12 percent of the proved producing reserves were estimated by analogy. The method of analogy was used where there were inadequate historical performance data to establish a definitive trend orand where the use of production performance data as a basis for the reserve estimates was considered to be inappropriate.

~~Reserves attributable to current~~ One hundred percent of the proved non-producing ~~well completions were predominantly estimated using production decline curve analysis. Reserves assigned to future completions were predominantly estimated by analogy to~~and undeveloped reserves ~~recovered from existing completions. We utilized all methods and procedures that we deemed necessary to estimate SWR’s proved~~ and one hundred percent of the probable reserves, included herein were estimated by the analogy method. The data utilized from the analogues and ~~we affirm that those methods and procedures~~the well data incorporated into our analysis that were available through September, 2009 were ~~appropriate~~considered sufficient for ~~this~~the purpose thereof.

To estimate economically recoverable proved and probable oil and gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data that cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved, and probable ~~and possible~~ reserves must be ~~demonstrated~~anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined ~~as of~~ . While it may reasonably be anticipated that the ~~effective date of~~future prices received for the ~~report.~~ sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

SWR has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In preparing our forecast of future proved and probable production and income, we have relied upon data furnished by SWR with respect to property interests owned, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, ad valorem and production taxes, recompletion and development costs, abandonment costs after salvage, product prices based on the SEC regulations, adjustments or differentials to product prices, geological structural and isochore maps, well logs, core analyses, and pressure measurements. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data supplied by SWR. We consider the factual data used in this report appropriate and sufficient for the purpose of preparing the estimates of reserves and future net revenues herein.

In summary, we consider the assumptions, data, methods and analytical procedures used in this report appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate to prepare the estimates of reserves herein. The proved and probable reserves included herein were determined in conformance with the United States Securities and Exchange Commission (SEC) Modernization of Oil and Gas Reporting; Final Rule, including all references to Regulation S-X and Regulation S-K, referred to herein collectively as the “SEC Regulations.” In our opinion, the proved and probable reserves presented in this report comply with the definitions, guidelines and disclosure requirements as required by the SEC regulations.

Future Production Rates

~~Our~~For wells currently on production, our forecasts of future production rates are based on historical performance ~~from wells now on production. Test data and other related information were used to estimate the anticipated initial production rates for those wells or locations that are not currently producing~~data. If no production decline trend has been established, future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied to depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating future production rates.

Test data and other related information were used to estimate the anticipated initial production rates for those wells or locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by SWR.

~~The future production rates from wells now on production may be more or less than estimated because of changes in market demand or allowables set by regulatory bodies.~~ Wells or locations that are not currently producing may start producing earlier or later than anticipated in our estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/or recompleting wells and/or constraints set by regulatory bodies.

The future production rates from wells currently on production or wells or locations that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Hydrocarbon Prices

~~As previously stated, the~~The hydrocarbon prices used herein are based on SEC price parameters using the average prices during the 12-month period prior to the ending date of the period covered in this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements. For ~~hydrocarbons~~hydrocarbon products sold under contract, the contract prices, including fixed and determinable escalations, exclusive of inflation adjustments, were used until expiration of the contract. Upon contract expiration, the prices were adjusted to the 12 -month unweighted arithmetic average as previously described. Product prices that were actually used for each property reflect adjustment from the above stated prices for gravity, quality, heating value, local conditions, transportation costs, and/or distance from market.

SWR furnished us with the above mentioned average prices in effect on December 31, 2009. These initial SEC hydrocarbon prices were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold. These benchmark prices are prior to the adjustments for differentials as described herein. The table below summarizes the “benchmark prices” and “price reference” used for the geographic areas included in the report.

The product prices that were actually used to determine the future gross revenue for each property reflect adjustments to the benchmark prices for gravity, quality, local conditions, gathering and transportation fees and/or distance from market, referred to herein as “differentials.” The differentials used in the preparation of this report were supplied to us by SWR. The differentials furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by SWR to determine these differentials.

In addition, the table below summarizes the net volume-weighted benchmark prices adjusted for differentials and referred to herein as the “average realized prices.” The average realized prices shown in the table below were determined from the total proved future gross revenue before production taxes and the total proved net reserves for the geographic area and presented in accordance with SEC disclosure requirements for each of the geographic areas included in the report.

Geographic Area	Product	Price Reference	Avg Benchmark Prices	Avg Realized Prices
North America
United States	Oil/Condensate	WTI Cushing	$61.18/Bbl	$55.56/Bbl
	NGLs	WTI Cushing	$61.18/Bbl	$35.05/Bbl
	Gas	Henry Hub	$3.87/MMBTU	$3.66/MCF

The effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in our individual property evaluations.

Costs

Operating costs for the leases and wells in this report are based on the operating expense reports of SWR and include only those costs directly applicable to the leases or wells. The operating costs include a portion of general and administrative costs allocated directly to the leases and wells. ~~When applicable for~~ For operated properties, the operating costs include an appropriate level of corporate general administrative and overhead costs. The operating costs for non-operated properties include the COPAS overhead costs that are allocated directly to the leases and wells under terms of operating agreements. Certain gas, oil and condensate processing and handling fees, including

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

compression fees where applicable, are included as “operating” costs. The operating costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the operating cost data used by SWR. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells.

Development costs were furnished to us by SWR and are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The development costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of these costs. SWR’s estimates of zero abandonment costs after salvage value for onshore properties were used in this report. Ryder Scott has not performed a detailed study of the abandonment costs or the salvage value and makes no warranty for SWR’s estimate.

~~Because of the direct relationship between volumes of~~ The proved non-producing and ~~probable undeveloped reserves and development plans, we include in~~ the proved and probable undeveloped ~~categories only~~ reserves ~~assigned to undeveloped locations that we~~in this report have been ~~assured will definitely be drilled and~~incorporated herein in accordance with SWR’s plans to develop these reserves ~~assigned~~as of December 31, 2009. The implementation of SWR’s development plans as presented to us and incorporated herein is subject to the approval process adopted by SWR’s management. As the ~~undeveloped portions~~result of ~~secondary projects which we have been assured will definitely be developed.~~ our inquires during the course of preparing this report, SWR has ~~assured us of their intent and ability to proceed with~~ informed us that the development activities included ~~in this report, and~~herein have been subjected to and received the internal approvals required by SWR’s management at the appropriate local, regional and/or corporate level. In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to SWR. Additionally, SWR has informed us that they are not aware of any legal, regulatory or, political or economic obstacles that would significantly alter their plans.

Current costs used by SWR were held constant throughout the life of the properties.

Standards of Independence and Professional Qualification

Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world for over seventy years. Ryder Scott is employee -owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have over eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any publicly -traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services.

Ryder Scott actively participates in industry -related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization.

We are independent petroleum engineers with respect to CWEI/SWR. Neither we nor any of our employees have any interest in the subject properties, and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties ~~which~~that were reviewed.

The results of this study, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical ~~person~~persons primarily responsible for overseeing, reviewing and approving the evaluation of the reserves information discussed in this report, are included as an attachment to this letter.

Terms of Usage

The results of our third party study, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by CWEI.

CWEI makes periodic filings on Form 10-K with the SEC under the 1934 Exchange Act. Furthermore, CWEI has certain registration statements filed with the SEC under the 1933 Securities Act into which any subsequently filed Form 10-K is incorporated by reference. We have ~~provided our written consent~~consented to ~~CWEI for~~the incorporation by reference in the registration statements on Form S-3 and Form S-8 of CWEI and to the references to our name as well as to the references to our third party report ~~in filings made by CWEI with the SEC. Our~~for CWEI, which appears in the December 31, 2009 annual report on Form 10-K of CWEI. Our written consent for such use is included as a separate exhibit to the filings made with the SEC by CWEI.

We have provided CWEI with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital version included in filings made by CWEI and the original signed report letter, the original signed report letter shall control and supersede the digital version.

The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

		Very truly yours,

		RYDER SCOTT COMPANY, L.P.
		TBPE Firm Registration No. F-1580

	\s\ William K. Fry

	William K. Fry, P.E.
	TBPE License No. 97134
	[SEAL]

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

	Senior Petroleum Engineer

	\s\ John E. Hamlin

	John E. Hamlin, P.E.
	TBPE License No. 65319
	[SEAL]
	Managing Senior Vice President

WKF/sm

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Professional Qualifications of Primary Technical Person

The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Mr. John E. Hamlin was the primary technical person responsible for overseeing the estimate of the reserves, future production, and income presented herein.

Mr. Hamlin, an employee of Ryder Scott Company L.P. (Ryder Scott) since 1979, is a Managing Senior Vice President and also serves as an Engineering Group Supervisor responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mr. Hamlin served in a number of engineering positions with Phillips Petroleum Corporation. For more information regarding Mr. Hamlin’s geographic and job specific experience, please refer to the Ryder Scott Company website at http://www.ryderscott.com/Experience/Employees.php.

Mr. Hamlin earned a Bachelor of Science degree in Petroleum Engineering from the University of Texas at Austin in 1975 and is a registered Professional Engineer in the State of Texas. He is also a member of the Society of Petroleum Engineers.

In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires a minimum of 15 hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Hamlin fulfills. As part of his 2009 continuing education hours, Mr. Hamlin attended an internally presented 9 hours of formalized training as well as a day long public forum relating to the definitions and disclosure guidelines contained in the United States Securities and Exchange Commission Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register. Mr. Hamlin attended an additional 24 hours of formalized in-house training as well as an additional 4 hours of formalized external training during 2009 covering such topics as the SPE/WPC/AAPG/SPEE Petroleum Resources Management System, reservoir engineering, geoscience and petroleum economics evaluation methods, procedures and software and ethics for consultants.

Based on his educational background, professional training and more than 33 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Hamlin has attained the professional qualifications as a Reserves Estimator and Reserves Auditor set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

PREAMBLE

On January 14, 2009, the United States Securities and Exchange Commission (“the Commission”) published the “Modernization of Oil and Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA). The “Modernization of Oil and Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule 4-10 of Regulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifies Industry Guide 2 in Regulation S-K. The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to Regulation S-X and Regulation S-K, shall be referred to herein collectively as the “SEC Regulations”. The SEC Regulations take effect with all filings made with the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010. Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10 (a) for the complete definitions, as the following definitions, descriptions and explanations rely wholly or in part on excerpts from the original document (direct passages excerpted from the aforementioned SEC document are denoted in italics herein).

Reserves are those quantities of petroleum which are anticipated to be commercially recovered from known accumulations from a given date forward under defined conditions. All reserve estimates involve some degree of uncertainty. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. Under the SEC Regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in documents publicly filed with the ~~Commission~~SEC. The SEC Regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any document publicly filed with the ~~Commission~~SEC unless such information is required to be disclosed in the document by foreign or state law as noted in §229.102 (5).

Reserves estimates will generally be revised as additional geologic or engineering data become available or as economic conditions change.

Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples of such methods are pressure maintenance, cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as petroleum technology continues to evolve.

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RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §229.4-10(a) (26) defines reserves as follows:

Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

PROVED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §229.4-10(a) (22) defines proved oil and gas reserves as follows:

Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and 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—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and

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(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

PROBABLE RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §229.4-10(a) (18) defines probable oil and gas reserves as follows:

Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.

(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

(iv) See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.

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RESERVES STATUS DEFINITIONS AND GUIDELINES

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

and

PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)

Sponsored and Approved by:

SOCIETY OF PETROLEUM ENGINEERS (SPE),

WORLD PETROLEUM COUNCIL (WPC)

AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)

SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)

Reserves status categories define the development and producing status of wells and reservoirs.

DEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §229.4-10(a) (6) defines developed oil and gas reserves as follows:

Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Developed Producing (SPE-PRMS Definitions)

While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-classified according to the guidance contained in the SPE-PRMS as Producing or Non-Producing.

Developed Producing Reserves

Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate.

Improved recovery reserves are considered producing only after the improved recovery project is in operation.

Developed Non-Producing

Developed Non-Producing Reserves include shut-in and behind-pipe reserves.

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Shut-In

Shut-in Reserves are expected to be recovered from:

(1) completion intervals which are open at the time of the estimate but which have not yet started producing;

(2) wells which were shut-in for market conditions or pipeline connections; or

(3) wells not capable of production for mechanical reasons.

Behind-Pipe

Behind-pipe Reserves are expected to be recovered from zones in existing wells which will require additional completion work or future re-completion prior to start of production.

In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

UNDEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §229.4-10(a) (31) defines undeveloped oil and gas reserves as follows:

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

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Clayton Williams Energy (CWEI) Inactive CORRESPCorrespondence with SEC