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. 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 based on economic parameters
and operating conditions considered applicable as of December 31, 2009. This
evaluation may be used in disclosure to the Securities and Exchange Commission
and is an annual update of the evaluated properties. 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
 
  Williamson
Petroleum Consultants, Inc. F-81 9.93.76<06l>02.15.10
   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.
 
 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. 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.
 
 OIL
PRICING
 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
PRICING
 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
PRICING
 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.
 
 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.
F-81                                                                                                                                 9.9376<06d>02.15.10
   Williamson
Petroleum Consultants, Inc.
 
 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.
 
 (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.