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 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 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.






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Clayton Williams Energy, Inc.

















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

PROVEDNet Reserves to the

Evaluated Interests:Oil/Condensate, MBBL
7,090.555
293.531
2,389.076
9,773.161NGL, MBBL
1,126.627
2.600
111.916
1,241.144Gas, MMCF
39,828.266
421.470
1,106.806
41,356.543Future Net Revenue, M$:Undiscounted
328,496.031
9,367.857
65,199.016
403,062.938Discounted 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





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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.




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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





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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.




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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.






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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











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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










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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








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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.  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.




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







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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

PricesNorth AmericaUnited States
Oil/Condensate
WTI Cushing
$61.18/Bbl
$57.86/BblNGL
WTI Cushing
$61.18/Bbl
$29.43/BblGas
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








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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





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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




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DEFINITIONS OF OIL AND GAS RESERVES1





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.






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(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.











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





2Williamson 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.





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