FORM 10-K

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1996

[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from __________________ to _________________

Commission File Number 0-20838

CLAYTON WILLIAMS ENERGY, INC.
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(Exact name of registrant as specified in its charter)

Delaware 75-2396863
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(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)

Six Desta Drive - Suite 6500
Midland, Texas 79705-5510
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(Address of principal executive offices) (Zip code)

Issuer's telephone number, including area code: (915) 682-6324
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Securities registered pursuant to Section 12(b) of the Act:

None

Securities registered pursuant to Section 12(g) of the Act:

Common Stock - $.10 Par Value
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(Title of Class)

Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days.

Yes X No
----- -----

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

The aggregate market value of the outstanding Common Stock, $.10 par
value, of the registrant held by non-affiliates of the registrant as of March
18, 1997, based on the closing price as quoted on the Nasdaq National Market
as of the close of business on said date, was $61,217,000.

There were 8,945,389 shares of Common Stock, $.10 par value, of the
registrant outstanding as of March 18, 1997.

Documents incorporated by reference:

(1) The information required by Part III of Form 10-K is found in the
registrant's definitive Proxy Statement which will be filed with the
Commission not later than April 30, 1997. Such portions of the
registrant's definitive Proxy Statement are incorporated herein by
reference.

PART I

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

Certain statements in this Form 10-K under "Item 1. Business," "Item 3.
Legal Proceedings," "Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations," and elsewhere in this Form
10-K constitute "forward-looking statements" within the meaning of the
Private Securities Litigation Reform Act of 1995 ( the "Reform Act"). Such
forward-looking statements involve known and unknown risks, uncertainties,
and other factors which may cause the actual results, performance, or
achievements of Clayton Williams Energy, Inc. and its subsidiaries (the
"Company") to be materially different from any future results, performance,
or achievements expressed or implied by such forward-looking statements.
Such factors include, among others, the following: the volatility of oil and
gas prices, the Company's drilling results, the Company's ability to replace
short-lived reserves, the availability of capital resources, the reliance
upon estimates of proved reserves, operating hazards and uninsured risks,
competition, government regulation, the ability of the Company to implement
its business strategy, and other factors referenced in this Form 10-K.

ITEM 1 - BUSINESS

SPECIAL NOTE: CERTAIN STATEMENTS SET FORTH BELOW UNDER THIS CAPTION
CONSTITUTE "FORWARD-LOOKING STATEMENTS" WITHIN THE MEANING OF THE REFORM ACT.
SEE "SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS" FOR ADDITIONAL
FACTORS RELATING TO SUCH STATEMENTS.

GENERAL

Clayton Williams Energy, Inc. and its subsidiaries (the "Company") are
primarily engaged in the exploration for and development and production of
oil and natural gas. The Company commenced operations in May 1993 following
the consolidation into the Company (the "Consolidation") of substantially all
of the oil and gas and gas gathering operations previously conducted by
various companies controlled by Clayton W. Williams, Jr. (collectively, the
"Williams Companies") and the completion of the Company's initial public
offering of Common Stock (the "Initial Public Offering").

Since 1988, the Company and its predecessors have concentrated their
drilling activities in the Cretaceous Trend (the "Trend"), which extends from
South Texas through East Texas, Louisiana and other southern states and
includes the Austin Chalk, Buda, and Georgetown formations. The Company
believes that it is one of the leaders in horizontal drilling in the Trend.
From January 1, 1990 through December 31, 1996, the Company drilled or
participated in 234 gross (186.4 net) horizontal wells in the Trend. The
Company also has operations in the Jalmat Field located in southeastern New
Mexico and in the Texas Gulf Coast. As of December 31, 1996, the Company had
estimated proved reserves totaling 8,507 MBbls of oil and 35.8 Bcf of gas
with $160.7 million of estimated future net revenues before income taxes
(discounted at 10%). The Company held interests in 460 gross (334.3 net) oil
and gas wells and owned leasehold interests in approximately 191,440 gross
(126,093 net) undeveloped acres.

During 1996, the Company added 4,096 MBOE of estimated proved reserves
through extensions and discoveries, substantially all of which were derived
from Trend drilling activities. Reserve additions for 1996 were 131% of
production for the same period, while production for 1996 was approximately
5% higher on an MBOE basis than in 1995.

The following discussion sets forth the Company's present plans for
drilling and exploration activities in 1997. The Company's ability to carry
out such plans will be largely dependent upon oil and gas prices, drilling
results, and the availability of funds to finance its planned expenditures.
See "ITEM 7 -MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS."

1997 DRILLING AND EXPLORATION ACTIVITIES

TREND DRILLING ACTIVITIES

The Company's business strategy is to increase reserves and production
through exploration and development of its oil and gas properties,
concentrating its efforts in the Trend. During 1997, the Company plans to
continue the development of a 117,000 net acre lease block (the "North
Giddings Block") which the Company has assembled in the updip area of the
Giddings Field in east central Texas. The North Giddings Block is located in
the northern area of the Giddings Field in Burleson, Robertson and Milam
Counties, Texas, where the Austin Chalk formation is encountered at depths
ranging from 5,500 feet to 7,000 feet. Beginning in August, 1996, the
Company has drilled six wells in the southern portion of the North Giddings
Block. Initial production results from several of these wells have not met
the Company's expectations. The Company is presently evaluating these
results to determine if the diminished production performance is attributable
to technical problems or reservoir quality. The Company is modifying its
completion techniques for wells drilled in this area.

To enhance its Trend drilling activities, the Company has entered into
agreements to acquire an interest in acreage north of the North Giddings
Block. The terms of these agreements generally provide that the Company must
drill successful wells on this acreage in order both to earn the acreage
drilled and maintain its right to continue drilling. Approximately 56,000
net acres are covered by these agreements.

If evaluation of the wells in the southern portion of the North Giddings
Block and the Company's drilling results on its newly acquired Trend acreage
are not favorable, the Company may reduce its level of drilling activities in
the Trend for 1997.

COTTON VALLEY EXPLORATORY PROJECT

The Company believes, based on initial 2-D seismic surveys, that a portion
of the North Giddings Block is on-trend with the Cotton Valley pinnacle reef
play. Successful wells have been drilled in the Cotton Valley formation,
which is encountered below the Trend formations, approximately 24 miles
northeast of the North Giddings Block. The Company has planned an exploration
project in three phases (the "Cotton Valley Exploratory Project") to explore
for potential reserves in this formation. The first phase is a proprietary
3-D seismic survey covering portions of the North Giddings Block. The second
phase is the interpretation of the seismic data to delineate any drilling
opportunities in the Cotton Valley formation. The third phase would be the
exploratory drilling of any delineated prospects. The Company has expanded
the acreage initially projected to be covered by the seismic survey from
20,000 to 50,000 net acres while increasing the estimated cost of the survey
from $3.1 million to $4 million, including interpretation. The Company began
the survey in December 1996 and anticipates completion during the third
quarter of 1997. Any drilling resulting from the survey is expected to begin
in the fourth quarter of 1997. The Company is continuing to evaluate
opportunities to expand the area covered by the survey, which could increase
its cost. See "PRINCIPAL AREAS OF OPERATIONS - COTTON VALLEY EXPLORATORY
PROJECT."

OTHER EXPLORATION ACTIVITIES

The Company anticipates expanding its 1997 drilling activities to include
newly acquired areas in east and south Texas, Louisiana and Mississippi, all
of which will be outside the Trend. These activities will be largely
exploratory in nature. The Company anticipates spending approximately $8
million in these areas during 1997, a substantial portion of which will be
for seismic and leasing activities.

PRINCIPAL AREAS OF OPERATIONS

THE TREND

The Company's current production of oil and gas in the Trend is derived
principally from the Austin Chalk formation in the Giddings Field. At
December 31, 1996, the Company had interests in 224 gross (167.5 net)
producing wells in the Giddings Field, including 155 horizontal and 69
vertical wells. For the year ended December 31, 1996, the Company's daily
net production in the Giddings Field averaged approximately 5,394 Bbls of oil
and 8,149 Mcf of gas. The Company drilled 25 wells in the Giddings Field
during 1996, all of which were completed as productive wells. The Company
operates 82% of its wells in the Giddings Field. Since May 1994, the Company
has concentrated its Trend drilling activities in the North Giddings Block.
Wells producing from the Austin Chalk formation in this updip portion of the
Giddings Field are more prone to produce oil than gas.

The Company also has production from an area of the Trend located in south
central Texas near Pearsall. The Company discontinued drilling activities in
the Pearsall area in 1993 and has no plans to resume drilling activities in
this area. For the year ended December 31, 1996, the Company's daily net
production from wells located in the Pearsall area averaged approximately 377
Bbls of oil and 484 Mcf of gas. The Company operates 98% of its wells in the
Pearsall area.

The Company's wells in the Austin Chalk formation are routinely subjected
to cyclic water stimulation. Cyclic water stimulation involves pumping large
volumes of water at high injection rates into a well, shutting-in the well
for ten days to two weeks, and then returning the well to production. Water
is pumped into the reservoir in several stages and is absorbed into the
micro-pore spaces of the rock, thereby displacing oil into the fractures
where it may be more readily produced and, in some cases, extending the
fracture system. The Company has used the cyclic water stimulation method
since 1987. The Company generally uses this treatment technique during the
well completion process and repeats the process 12 to 18 months after a well
has been placed in production. During 1996, 29 horizontal wells received an
initial treatment and 14 horizontal wells received a subsequent treatment.

JALMAT FIELD

The Jalmat Field, which is located in Lea County, New Mexico, was
discovered in 1935. The Company has working interests in 132 gross (106.7
net) producing wells, all of which are operated by the Company and are
located on approximately 8,023 net acres. Following the Company's acquisition
of the Jalmat Field properties in 1988, a major recompletion and workover
program was commenced. This program included recompletion of both existing
and temporarily abandoned wells, and the use of hydraulic fracture
stimulation on wells in the Jalmat Field. Through December 31, 1996, 57 gross
(46.1 net) gas wells have been successfully recompleted. For the year ended
December 31, 1996, the Company's average daily production from this field was
112 Bbls of oil and 3,820 Mcf of gas. The Company has 18 proved undeveloped
drilling locations available to drill in the future. Depending upon gas
prices, the Company may conduct activities on certain of these locations in
1997.

TEXAS GULF COAST

The Company owns interests in 26 gross (8.3 net) wells in Wharton and
Matagorda Counties in the Gulf Coast region of Texas. These wells were
acquired through two acquisitions in 1994 and are operated by third parties.
The Company's daily net production from this area during the year ended
December 31, 1996 averaged approximately 74 Bbls of oil and 1,220 Mcf of gas.
During 1997, the Company plans to participate in drilling one development
well and recompleting one existing well in Wharton County.

COTTON VALLEY EXPLORATORY PROJECT

The Company has begun to conduct a 3-D seismic survey in its North
Giddings Block to determine if seismic features indicating the presence of
pinnacle reefs can be identified in the Cotton Valley Haynesville formation.
As opposed to Trend formations, which are encountered at depths of 5,000 to
7,000 feet in this area, the Cotton Valley formation is encountered at depths
of 15,000 to 16,000 feet. The northern edge of the North Giddings Block is
approximately 24 miles southwest of the nearest current Cotton Valley
production. The presence of favorable 3-D seismic data provides no assurance
of success with respect to any subsequent drilling activities. Approximately
half of the wells drilled northeast of the North Giddings Block in search of
Cotton Valley pinnacle reefs have been productive. The Company believes that
all such wells have been drilled based on 3-D seismic surveys. The Company
estimates that a completed Cotton Valley pinnacle reef well would cost at
least $4,500,000. The Company's current policy is to limit its annual Cotton
Valley Exploratory Project expenditures to not more than 25% of its planned
annual capital expenditures. However, the Company may modify this policy
depending upon certain factors, including the Company's financial position,
exploratory drilling success, technological advances, drilling activities
conducted by third parties and current and anticipated product prices.

OTHER

The Company is presently evaluating certain opportunities for exploration
activities in geological provinces outside the Trend to which the Company can
apply its technical expertise. During 1997, the Company may acquire leases,
conduct seismic surveys, and drill exploratory wells in connection with one
or more of these projects. The projects presently under consideration are
located in east and south Texas, Louisiana and Mississippi.

MARKETS

GENERAL

The prices received by the Company for its oil, gas and natural gas
liquids production depend on many factors beyond the Company's control,
including domestic and foreign political conditions, the overall level of
supply of and demand for oil, gas and natural gas liquids, the price of
imports of oil and gas, weather conditions, the price and availability of
alternative fuels, the proximity and capacity of gas pipelines and other
transportation facilities and overall economic conditions. Future decreases
in the prices of oil and gas could have an adverse effect on the Company's
proved reserves, revenues, profitability and cash flow. As a result of these
factors, the Company engages in price hedging activities from time to time in
order to realize commodity prices which it believes are favorable under the
circumstances. See "ITEM 7 -MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS -- HEDGING TRANSACTIONS."

OIL SALES

Most oil purchasers periodically publish price bulletins to inform
producers of the base price for various grades and locations of crude oil.
These bulletins establish what is known in the oil and gas industry as the
"posted price." The posted price applicable to most of the Company's oil
production is generally $1 to $2 per barrel lower than the price quoted on
the New York Mercantile Exchange ("NYMEX") for spot West Texas Intermediate
("WTI") contracts since the oil purchaser must bear the cost to physically
gather, transport and store the purchased crude oil.

Substantially all of the Company's oil production from the Trend is sold
to Plains Marketing and Transportation, Inc. ("Plains") under two separate
contracts, both of which expire December 31, 1997. The Giddings Field
production is sold at a price based on the higher of (i) the average NYMEX
price for WTI, less an agreed-upon deduction, or (ii) the average monthly
posted price of Koch Oil Company

("Koch") for WTI, plus a variable bonus determined by formula. The Pearsall
area production is sold at a price based on the higher of (i) the average
monthly posted price of Koch for WTI, plus a variable bonus determined by
formula and (ii) the average monthly posted price of EOTT Energy Corp., plus
an agreed-upon bonus.

Oil from the Jalmat Field is sold to Plains under a month-to-month
contract. This production is sold at a price equal to Pride's average monthly
posted price for WTI, less an agreed upon deduction.

The Company believes that the loss of Plains as a purchaser of the
Company's oil production would not have a material adverse effect on its
results of operations due to the availability of other purchasers in the
areas.

GAS SALES

Casinghead gas from the Giddings area is dedicated to Aquila Southwest
Pipeline Corporation ("Aquila") under terms which require Aquila to pay the
Company based on the best terms it is offering in the area. Pursuant to this
dedication, the Company and Aquila have entered into a Gas Purchase Contract and
a Processing Agreement, both of which expire in September of 1997.
Substantially all of the Company's gas production from the Giddings Field is
sold under these Contracts. Both the Gas Contract and the Processing Agreement
provide for pricing formulae which are generally market responsive. Gas
produced in Robertson County is sold to Austin Chalk Natural Gas Marketing
Services under a Gas Contract expiring on December 31, 2002 and providing a
price which is generally market responsive.

During 1996, the Company sold substantially all of its gas production from
the Jalmat Field to Sid Richardson Gasoline, Ltd. ("Richardson") under a
contract which expires October 31, 2004. The price received by the Company for
residue gas sold pursuant to this contract is based upon proceeds received by
Richardson less a service fee and is generally market responsive. The Company
also shares in the proceeds received by Richardson for liquids extracted from
the Company's gas. Although the Company is currently selling its residue gas to
Richardson, it has the right to make sales to any other third party.

A substantial portion of the Company's gas production from the Pearsall area
is sold to a subsidiary of the Company under two long-term contracts.

During 1996, Aquila purchased 52% and Richardson purchased 13% of the
Company's gas production. If Aquila and Richardson cease purchasing gas from
the Company, the Company believes that it would be able to replace such
purchasers, although no assurance can be given as to the prices it would be
able to obtain from other parties; however, the loss of Richardson as a
purchaser in the Jalmat Field could result in curtailed production due to the
type of pipeline facilities otherwise available in the area.

NATURAL GAS SERVICES

The Company owns an interest in and operates seven gas gathering systems
and three gas processing plants in the states of Texas and Mississippi. These
natural gas service facilities consist of interests in approximately 70 miles
of pipeline, two amine treating plants, one liquids extraction plant and
three compressor stations. The Company does not derive a significant portion
of its consolidated operating income from natural gas services and does not
consider this business to be a strategic part of its business plan.

COMPETITION

Competition in all areas of the Company's operations is intense. The oil
and gas industry as a whole also competes with other industries in supplying
the energy and fuel requirements of industrial,

commercial and individual consumers. Major and independent oil and gas
companies and oil and gas syndicates actively bid for desirable oil and gas
properties, as well as for the equipment and labor required to operate and
develop such properties. A number of the Company's competitors have financial
resources and acquisition, exploration and development budgets that are
substantially greater than those of the Company, which may adversely affect
the Company's ability to compete with these companies. Such companies may be
able to pay more for productive oil and gas properties and exploratory
prospects and to define, evaluate, bid for and purchase a greater number of
properties and prospects than the Company's financial or human resources
permit.

REGULATION

The Company's oil and gas exploration, production and related operations are
subject to extensive rules and regulations promulgated by federal, state and
local agencies. Failure to comply with such rules and regulations can result in
substantial penalties. The regulatory burden on the oil and gas industry
increases the Company's cost of doing business and affects its profitability.
Because such rules and regulations are frequently amended or reinterpreted, the
Company is unable to predict the future cost or impact of complying with such
laws.

The State of Texas and many other states require permits for drilling
operations, drilling bonds and reports concerning operations and impose other
requirements relating to the exploration and production of oil and gas. Such
states also have statutes or regulations addressing conservation matters,
including provisions for the unitization or pooling of oil and gas
properties, the establishment of maximum rates of production from oil and gas
wells and the spacing, plugging and abandonment of such wells. The statutes
and regulations of certain states limit the rate at which oil and gas can be
produced from the Company's properties.

The Federal Energy Regulatory Commission ("FERC") regulates interstate
natural gas transportation rates and service conditions. Such regulation
affects the marketing of gas produced by the Company and the revenues
received by the Company for sales of such production. Since the mid-1980s,
FERC Orders have fundamentally restructured interstate pipeline sales and
transportation services, including the unbundling by interstate pipeline of
the sales, transportation, storage and other components of the city-gate
sales services such pipelines previously performed. These regulatory
measures may ultimately enhance the Company's ability to market and transport
its gas, although it may also subject the Company to greater competition,
more restrictive pipeline imbalance tolerances and greater penalties if those
tolerances are violated.

The FERC has recently announced several important transportation-related
policy statements and proposed rule changes, including policy statements on
how interstate natural gas pipelines can recover the cost of new pipeline
facilities and policy statements on alternatives to its traditional
cost-of-service ratemaking methodology (including criteria to be used in
evaluating proposals to charge market-based rates for the transportation of
natural gas). In addition, the FERC is reconsidering its regulations
regarding releases of firm interstate natural gas pipeline capacity. While
the Company cannot predict exactly how FERC actions might impact the
Company's natural gas sales, it does not believe it will be treated
materially differently than other natural gas producers and marketers with
which it competes.

Sales of oil and natural gas liquids by the Company are not regulated and
are made at market prices. The price the Company receives from the sale of
those products is affected by the cost of transporting the products to
market. Effective as of January 1, 1995, the FERC implemented regulations
establishing an indexing system for transportation rates for oil pipelines,
which, generally, would index such rate to inflation, subject to certain
conditions and limitations. These regulations could increase the cost of
transporting oil and natural gas liquids by pipeline, although the most
recent adjustment generally decreased rates. The Company is not able to
predict with any certainty what effect, if any, these

regulations will have on it, but, other factors being equal, the regulations
may, over time, tend to increase transportation costs or reduce wellhead
prices for oil and natural gas liquids.

ENVIRONMENTAL MATTERS

Operations of the Company pertaining to oil and gas exploration,
production and related activities are subject to numerous and constantly
changing federal, state and local laws governing the discharge of materials
into the environment or otherwise relating to environmental protection.
Numerous governmental agencies issue regulations to implement and enforce
such laws which are often difficult and costly to comply with and which carry
substantial civil and criminal penalties for failure to comply. These laws
and regulations may require the acquisition of certain permits prior to or in
connection with drilling activities, restrict or prohibit the types,
quantities and concentration of substances that can be released into the
environment in connection with drilling and production, restrict or prohibit
drilling activities that could impact wetlands, endangered or threatened
species or other protected areas or natural resources, require some degree of
remedial action to mitigate pollution from former operations, such as pit
cleanups and plugging abandoned wells, and impose substantial liabilities for
pollution resulting from the Company's operations. Such laws and regulations
may substantially increase the cost of exploring for, developing, producing
or processing oil and gas and may prevent or delay the commencement or
continuation of a given project and thus generally could have a material
adverse effect upon the capital expenditures, earnings, or competitive
position of the Company. Management of the Company believes it is in
substantial compliance with current applicable environmental laws and
regulations, and the cost of compliance with such laws and regulations has
not been material and is not expected to be material during the next fiscal
year. Nevertheless, changes in existing environmental laws and regulations or
in the interpretations thereof could have a significant impact on the
operating costs of the Company, as well as the oil and gas industry in
general. For instance, legislation has been proposed in Congress from time to
time that would reclassify certain oil and gas production wastes as
"hazardous wastes," which reclassification would make exploration and
production wastes subject to much more stringent handling, disposal and
clean-up requirements. State initiatives to further regulate the disposal of
oil and gas wastes and naturally occurring radioactive materials could have a
similar impact on the Company.

The Comprehensive Environmental Response, Compensation, and Liability Act
("CERCLA"), also known as the "Superfund" law, imposes liability, without
regard to fault or the legality of the original conduct, on certain classes
of persons that are considered to have contributed to the release of a
"hazardous substance" into the environment. These persons include the owner
or operator of the disposal site or the site where the release occurred and
companies that disposed or arranged for the disposal of the hazardous
substances at the site where the release occurred. Under CERClA, such persons
may be subject to joint and several liability for the costs of cleaning up
the hazardous substances that have been released into the environment and for
damages to natural resources, and it is not uncommon for neighboring
landowners and other third parties to file claims for personal injury and
property damage allegedly caused by the hazardous substances released into
the environment. The Company is able to control directly the operation of
only those wells with respect to which it acts as operator. Notwithstanding
the Company's lack of direct control over wells operated by others, the
failure of an operator other than the Company to comply with applicable
environmental regulations may, in certain circumstances, be attributed to the
Company. Management of the Company believes that it has no material
commitments for capital expenditures to comply with existing environmental
requirements.

The Oil Pollution Act ("OPA") imposes a variety of requirements on
"responsible parties" (E.G., owners, operators, lessees and permittees) for
oil and gas onshore and offshore facilities, pipelines, and vessels related
to the prevention of oil spills and imposes liability for damages resulting
from such spills in waters of the United States. OPA requirements include the
assignment of liability to each responsible party for oil spill removal costs
and a variety of public and private damages from oil spills, and the
preparation of oil spill contingency plans. Failure to comply with ongoing
requirements or inadequate cooperation in a spill event may subject a
responsible party to civil or criminal enforcement actions.

State water discharge regulations and federal waste discharge permitting
requirements adopted pursuant to the Federal Water Pollution Control Act
prohibit or are expected to prohibit, within the next several months, the
discharge of produced water and sand, and some other substances related to
the oil and gas industry, to coastal waters. Although the costs to comply
with zero discharge mandates under state or federal law may be significant,
the entire industry will experience similar costs and the Company believes
that these costs will not have a material adverse impact on the Company's
financial condition and operations.

TITLE TO PROPERTIES

As is customary in the oil and gas industry, the Company performs a
minimal title investigation before acquiring undeveloped properties. A title
opinion is obtained prior to the commencement of drilling operations on such
properties. The Company has obtained title opinions on substantially all of
its producing properties and believes that it has satisfactory title to such
properties in accordance with standards generally accepted in the oil and gas
industry. The Company's properties are subject to customary royalty
interests, liens incident to operating agreements, liens for current taxes
and other burdens which the Company believes do not materially interfere with
the use of or affect the value of such properties. Substantially all of the
Company's oil and gas properties are currently mortgaged to secure borrowings
under the Company's secured bank credit facility and may be mortgaged under
any future credit facilities entered into by the Company.

OPERATIONAL HAZARDS AND INSURANCE

The Company's operations are subject to the usual hazards incident to the
drilling and production of oil and gas, such as blowouts, cratering,
explosions, uncontrollable flows of oil, gas or well fluids, fires and
pollution and other environmental risks. These hazards can cause personal
injury and loss of life, severe damage to and destruction of property and
equipment, pollution or environmental damage and suspension of operation.

The Company maintains insurance of various types to cover its operations.
The limits provided under its general liability policies total $32 million.
In addition, the Company maintains operator's extra expense coverage which
provides for care, custody and control of selected wells during drilling
operations. The occurrence of a significant adverse event, the risks of
which are not fully covered by insurance, could have a material adverse
effect on the Company's financial condition and results of operations.
Moreover, no assurances can be given that the Company will be able to
maintain adequate insurance in the future at rates it considers reasonable.

EMPLOYEES

At December 31, 1996, the Company had approximately 100 full-time
employees. None of the Company's employees is subject to a collective
bargaining agreement. The Company considers its relations with its employees
to be good.

OFFICES

The Company leases approximately 40,000 square feet of office space in
Midland, Texas and approximately 1,400 square feet of office space in
Houston, Texas.

ITEM 2 - PROPERTIES

The Company's properties consist primarily of oil and gas wells and its
ownership in leasehold acreage, both developed and undeveloped. At December
31, 1996, the Company had interests in 460 gross (334.3 net) oil and gas
wells and owned leasehold interests in 191,440 gross (126,093 net)
undeveloped acres.

RESERVES

The following table sets forth certain information as of December 31, 1996
with respect to the Company's estimated proved oil and gas reserves and the
present value of estimated future net revenues therefrom, discounted at 10%
("PV-10 Value").

PROVED PROVED
DEVELOPED UNDEVELOPED TOTAL
--------- ----------- -----
Oil (Mbbls). . . . . . . . . . . . . . 7,199 1,308 8,507
Gas (Mmcf) . . . . . . . . . . . . . . 30,496 5,302 35,798
MBOE . . . . . . . . . . . . . . . . . 12,282 2,192 14,474
PV-10 Value:
Before income taxes. . . . . . . . . $145,679 $14,991 $160,670
After income taxes . . . . . . . . . $135,713

The following table sets forth certain information as of December 31, 1996
regarding the Company's proved oil and gas reserves in each of its principal
producing areas.

PROVED RESERVES
----------------------------
PERCENTAGE OF
TOTAL OIL PERCENT OF PV-10 VALUE PV-10 VALUE
OIL GAS EQUIVALENT TOTAL OIL BEFORE BEFORE
AREA OR FIELD (MBBLS) (MMCF) (MBOE) EQUIVALENT INCOME TAXES INCOME TAXES
- ------------- ------- ------ ------ ---------- ------------ ------------
(in thousands)

Trend . . . . . . . . 7,854 13,467 10,099 69.8% $119,542 74.4%
Jalmat. . . . . . . . 338 15,102 2,855 19.7 24,914 15.5
Texas Gulf Coast. . . 122 2,787 587 4.1 8,555 5.3
Other . . . . . . . . 193 4,442 933 6.4 7,659 4.8
----- ------ ------ ----- -------- -----
Total . . . . . . . . 8,507 35,798 14,474 100.0% $160,670 100.0%
----- ------ ------ ----- -------- -----
----- ------ ------ ----- -------- -----

The estimates as of December 31, 1996 of proved reserves, future net
revenues from proved reserves and the PV-10 Value before income taxes set
forth in this Form 10-K were based on a report prepared by Williamson
Petroleum Consultants, Inc. (the "Independent Engineers"). For purposes of
preparing such estimates, the Independent Engineers reviewed production data
through October 31, 1996 for properties representing 85% of the estimated
present value of the Company's proved developed producing reserves and
through earlier dates for the balance of the Company's properties. In order
to calculate the proved reserve estimates as of December 31, 1996, the
Independent Engineers assumed that production for each of the Company's
properties since the date of the last production data reviewed was in
accordance with the production decline curve for such property.

In accordance with applicable guidelines of the Commission, the
estimates of the Company's proved reserves and future net revenues therefrom
set forth herein are made using oil and gas sales prices estimated to be in
effect as of the date of such reserve estimates and are held constant
throughout the life of the properties. Estimated quantities of proved
reserves and future net revenues therefrom are affected by changes in oil and
gas prices. Oil and gas prices increased substantially from December 31,
1995 to December 31, 1996, resulting in significant increases in the
Company's estimated future net revenues and,

to a lesser extent, increases in estimated reserve quantities. The weighted
average of the sales prices utilized for the purposes of estimating the
Company's proved reserves and the future net revenues therefrom as of
December 31, 1996 were $25.01 per Bbl of oil and $3.63 per Mcf of gas, as
compared to $18.57 per Bbl and $2.07 per Mcf as of December 31, 1995.
Subsequent to December 31, 1996, oil and gas prices have declined, but are
expected to remain volatile. The Company estimates that a $1 decline in the
price per Bbl of oil would result in a $5.5 million reduction in PV-10 Value
(before income taxes), and that a $.25 decline in the price per Mcf of gas
would result in a $5.3 million reduction in PV-10 Value (before income taxes).

Also in accordance with Commission guidelines, the estimates of the
Company's proved reserves and future net revenues therefrom are made using
current lease and well operating costs estimated by the Company. Lease
operating expenses for oil wells operated by the Company in the Austin Chalk,
Buda and Georgetown formations were estimated using a combination of fixed
and variable-by-volume costs consistent with the Company's experience in
operating such wells. For purposes of calculating future net revenues and
PV-10 Value, operating costs exclude accounting and administrative overhead
expenses attributable to the Company's working interest in wells operated by
it under joint operating agreements, but include administrative costs
associated with production offices.

The Independent Engineers report relies upon various assumptions,
including assumptions required by the Commission as to oil and gas prices,
drilling and operating expenses, capital expenditures, taxes and availability
of funds. The process of estimating oil and gas reserves is complex,
requiring significant decisions and assumptions in the evaluation of
available geological, geophysical, engineering and economic data for each
reservoir. As a result, such estimates are inherently imprecise. Actual
future production, oil and gas prices, revenues, taxes, development
expenditures, operating expenses and quantities of recoverable oil and gas
reserves may vary substantially. Any significant variance in these
assumptions could materially affect the estimated quantity and value of
reserves set forth herein. In addition, the Company's reserves may be subject
to downward or upward revision based upon production history, results of
future development and exploration, prevailing oil and gas prices and other
factors, many of which are beyond the Company's control. Actual production,
revenues, taxes, development expenditures and operating expenses with respect
to the Company's reserves will likely vary from the estimates used, and such
variances may be material.

Approximately 15% of the Company's total proved reserves at December 31,
1996 were undeveloped, which are by their nature less certain. Recovery of
such reserves will require significant capital expenditures and successful
drilling operations. The reserve data set forth in the Independent Engineers'
report as of December 31, 1996 assumes, based on the Company's estimates,
that aggregate capital expenditures by the Company of approximately $12.5
million through 1999 will be required to develop such reserves. Although cost
and reserve estimates attributable to the Company's oil and gas reserves have
been prepared in accordance with industry standards, no assurance can be
given that the estimated costs are accurate, that development will occur as
scheduled or that the results will be as estimated.

The PV-10 Value referred to herein should not be construed as the
current market value of the estimated oil and gas reserves attributable to
the Company's properties. In accordance with applicable requirements of the
Commission, the PV-10 Value from proved reserves is generally based on prices
and costs as of the date of the estimate, whereas actual future prices and
costs may be materially higher or lower. Actual future net revenues also will
be affected by changes in consumption and changes in governmental regulations
or taxation. The timing of actual future net revenues from proved reserves,
and thus their actual present value, will be affected by the timing of both
the production and the incurrence of expenses in connection with development
and production of oil and gas properties. In addition, the 10% discount
factor, which is required by the Commission to be used in calculating
discounted future net revenues for reporting purposes, is not necessarily the
most appropriate discount factor based on interest

rates in effect from time to time and risks associated with the Company or
the oil and gas industry in general.

The Company must develop or acquire new oil and gas reserves to replace
those being depleted by production. Without successful drilling and
exploration or acquisition activities, the Company's reserves and revenues
will decline rapidly. In particular, the Company's producing properties in
the Trend are characterized by a high initial production rate, followed by a
steep decline in production. The Company's properties in the Trend may be
susceptible to hydrocarbon drainage from production on adjacent properties by
other operators, particularly from horizontal wells. The Company has a
relatively low reserve-to-production ratio of approximately 4.6 years (based
upon the estimated quantities of proved oil and gas reserves as of December
31, 1996, divided by production volumes for 1996). Accordingly, the Company
believes that its future success will depend to a significant extent upon the
results of its exploration and development program. See "ITEM 7 -
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS."

Since January 1, 1996, the Company has not filed an estimate of its net
proved oil and gas reserves with any federal authority or agency other than
the Commission.

EXPLORATION AND DEVELOPMENT ACTIVITIES

The Company drilled, or participated in the drilling of, the following
numbers of wells during the periods indicated.

YEAR ENDED DECEMBER 31,
---------------------------------------------
1996 1995 1994
----------- ------------- ------------
Gross Net Gross Net Gross Net
----- --- ----- --- ----- ---
DEVELOPMENT WELLS:
Oil 23 20.9 24 21.0 14 11.7
Gas - - 1 .5 2 1.5
Dry - - - - - -
---- ----- ---- ----- ---- ----
Total 23 20.9 25 21.5 16 13.2
---- ----- ---- ----- ---- ----
---- ----- ---- ----- ---- ----
EXPLORATORY WELLS:
Oil 4 4.0 2 2.0 4 2.9
Gas - - - - 1 1.0
Dry 2 .6 - - 5 2.7
---- ----- ---- ----- ---- ----
Total 6 4.6 2 2.0 10 6.6
---- ----- ---- ----- ---- ----
---- ----- ---- ----- ---- ----
TOTAL WELLS:
Oil 27 24.9 26 23.0 18 14.6
Gas - - 1 .5 3 2.5
Dry 2 .6 - - 5 2.7
---- ----- ---- ----- ---- ----
Total 29 25.5 27 23.5 26 19.8
---- ----- ---- ----- ---- ----
---- ----- ---- ----- ---- ----

The information contained in the foregoing table should not be considered
indicative of future drilling performance, nor should it be assumed that
there is any necessary correlation between the number of productive wells
drilled and the amount of oil and gas that may ultimately be recovered by the
Company.

The Company does not own any drilling rigs and all of its drilling
activities are conducted by independent contractors on a day rate basis under
standard drilling contracts. At March 1, 1997, the Company had three
drilling rigs under contract in the Giddings area.

PRODUCTIVE WELL SUMMARY

The following table sets forth certain information regarding the Company's
ownership as of December 31, 1996, of productive wells in the areas indicated.

OIL GAS TOTAL
------------ ----------- -----------
GROSS NET GROSS NET GROSS NET
----- --- ----- --- ----- ---
Trend . . . . . . . . . 250 190.0 22 16.0 272 206.0
Jalmat. . . . . . . . . 37 30.0 95 76.7 132 106.7
Texas Gulf Coast. . . . 1 .4 25 7.9 26 8.3
Other . . . . . . . . . 14 10.7 16 2.6 30 13.3
--- ----- --- ----- --- -----
Total . . . . . . . 302 231.1 158 103.2 460 334.3
--- ----- --- ----- --- -----
--- ----- --- ----- --- -----

The Company seeks to act as operator of the wells in which it owns a
significant interest. As operator of a well, the Company is able to manage
drilling and production operations as well as other matters affecting the
production and sale of oil and gas. In addition, the Company receives fees
from other working interest owners for the operation of the wells. At
December 31, 1996, the Company was the operator of 373 wells, or
approximately 81% of the 460 total wells in which it has a working interest.
Production from these operated wells represented approximately 92% of the
Company's total net production for 1996.

VOLUMES, PRICES AND PRODUCTION COSTS

The following table sets forth certain information regarding the production
volumes of, average sales prices received from, and average production costs
associated with the Company's sales of oil and gas for the periods indicated.

YEAR ENDED DECEMBER 31,
----------------------------
1996 1995 1994
---- ---- ----
OIL AND GAS PRODUCTION DATA:
Oil (MBbls) . . . . . . . . . . . . . 2,203 1,831 1,709
Gas (MMcf). . . . . . . . . . . . . . 5,584 6,845 8,369
Total (MBOE). . . . . . . . . . . . . 3,134 2,972 3,104

AVERAGE OIL AND GAS SALES PRICE (1):
Oil ($/Bbl) . . . . . . . . . . . . . $20.85 $17.35 $15.72
Gas ($/Mcf)(2). . . . . . . . . . . . $ 2.65 $ 1.77 $ 1.98

AVERAGE PRODUCTION COSTS
Lease operations ($/BOE)(3) . . . . . $ 4.71 $ 4.55 $ 4.12
- --------------
(1) Includes effects of hedging transactions.
(2) Includes natural gas liquids.
(3) Includes direct lifting costs (labor, repairs and maintenance,
materials and supplies), workover costs and the administrative
costs of production offices, insurance and property and severance
taxes.

DEVELOPMENT, EXPLORATION AND ACQUISITION EXPENDITURES

The following table sets forth certain information regarding the costs
incurred by the Company in its development, exploration and acquisition
activities during the periods indicated.

YEAR ENDED DECEMBER 31,
-------------------------------
1996 1995 1994
------- ------- -------
(IN THOUSANDS)
Property Acquisitions:
Proved . . . . . . . . . . . . $ 1,375 $ - $10,199
Unproved . . . . . . . . . . . 5,002 2,254 2,325
Developmental Costs. . . . . . . 20,931 16,823 13,136
Exploratory Costs. . . . . . . . 6,306 1,407 5,699
------- ------- -------
Total Capital Expenditures . . . $33,614 $20,484 $31,359
------- ------- -------
------- ------- -------

ACREAGE

The following table sets forth certain information regarding the
Company's developed and undeveloped leasehold acreage as of December 31, 1996
in the areas indicated. Acreage in which the Company's interest is limited to
royalty, overriding royalty and similar interests is excluded.

DEVELOPED UNDEVELOPED TOTAL
---------------- ----------------- -----------------
GROSS NET GROSS NET GROSS NET
------- ------ ------- ------- ------- -------

Trend. . . . . . . . . 95,474 82,733 100,112 82,527 195,586 165,260
Jalmat . . . . . . . . 9,481 8,023 - - 9,481 8,023
Texas Gulf Coast . . . 8,617 3,941 562 163 9,179 4,104
Other. . . . . . . . . 16,897 2,503 90,766 43,403 107,663 45,906
------- ------ ------- ------- ------- -------
Total . . . . . . 130,469 97,200 191,440 126,093 321,909 223,293
------- ------ ------- ------- ------- -------
------- ------ ------- ------- ------- -------

ITEM 3 - LEGAL PROCEEDINGS

The Company is a defendant in a suit styled The State of Texas, et al v.
Union Pacific Resources Company et al, presently pending in Lee County,
Texas. The suit attempts to establish a class action consisting of
unidentified royalty and working interest owners throughout the State of
Texas. Among other things, the plaintiffs are seeking actual and exemplary
damages for alleged violation of various statutes relating to common carriers
and common purchasers of crude oil including discrimination in the purchase
of oil by giving preferential treatment to defendants' own oil and conspiring
to keep the posted price or sales price of oil below market value. A general
denial has been filed. Because the Company is neither a common purchaser nor
common carrier of oil, management of the Company believes there is no merit
to the allegations as they relate to the Company or its operations.

In addition, the Company is a defendant or codefendant in minor lawsuits
that have arisen in the ordinary course of business. While the outcome of
these lawsuits cannot be predicted with certainty, management does not expect
any of these to have a material adverse effect on the Company's consolidated
financial condition or results of operations.

ITEM 4 - SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

No matter was submitted to a vote of the security holders of the
Registrant during the fourth quarter of its fiscal year ended December 31,
1996.

PART II

ITEM 5 - MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED STOCKHOLDER
MATTERS

The Company's Common Stock is quoted on the Nasdaq National Market under
the symbol "CWEI". As of December 31, 1996, there were approximately 1,700
beneficial and record stockholders. The following table sets forth, for the
periods indicated, the high and low sales prices for the Common Stock, as
reported on the Nasdaq National Market:

High Low
---- ---
Year Ended December 31, 1996:

Fourth Quarter. . . . . . . . . . . $ 17 7/8 $ 9 5/8
Third Quarter . . . . . . . . . . . 12 7 3/8
Second Quarter. . . . . . . . . . . 10 7/8 3 3/4
First Quarter . . . . . . . . . . . 4 3/8 2 5/8

Year Ended December 31, 1995:

Fourth Quarter. . . . . . . . . . . $ 3 3/8 $ 2
Third Quarter . . . . . . . . . . . 3 5/8 2 3/8
Second Quarter. . . . . . . . . . . 4 3/4 2 3/4
First Quarter . . . . . . . . . . . 6 1/2 3 3/4

The quotations in the table above reflect inter-dealer prices without
retail markups, markdowns or commissions. On March 18, 1997, the last
reported sale price for the Common Stock on the Nasdaq National Market was
$13 3/8.

The Company has not paid any cash dividends on its Common Stock, and the
Board of Directors does not anticipate paying any cash dividends in the
foreseeable future. The terms of the Company's secured bank credit facility
and subordinated debt facility limit the payment of cash dividends by the
Company during any fiscal year to a maximum of 50% of the Company's net
income during such period, assuming compliance with other terms thereof.
Subject to the restrictions imposed by the Company's lenders, future dividend
policy will depend on a number of factors, including future earnings, capital
requirements, the financial condition and future prospects of the Company and
such other factors as the Board of Directors may deem relevant.

ITEM 6 - SELECTED FINANCIAL DATA

The following table sets forth selected consolidated financial data for
the Company as of the dates and for the periods indicated. The consolidated
financial data for each of the years in the five-year period ended December
31, 1996 was derived from audited financial statements of the Company. The
data set forth in this table should be read in conjunction with "Management's
Discussion and Analysis of Financial Condition and Results of Operations" and
the Consolidated Financial Statements.

YEAR ENDED DECEMBER 31,
-------------------------------------------------
1996 1995 1994 1993 1992
------ ------ ------ ------ ------
(IN THOUSANDS, EXCEPT PER SHARE DATA)

STATEMENT OF OPERATIONS DATA:
Revenues:
Oil and gas sales. . . . . . . $60,610 $43,883 $ 43,617 $ 55,041 $ 60,134
Natural gas services . . . . . 4,281 5,388 5,868 4,554 5,159
------- ------- -------- -------- --------
Total revenues . . . . . . . 64,891 49,271 49,485 59,595 65,293
------- ------- -------- -------- --------
Costs and expenses:
Lease operations . . . . . . . 14,776 13,533 12,775 12,788 13,459
Exploration. . . . . . . . . . 1,633 1,555 7,139 6,198 4,365
Natural gas services . . . . . 3,437 3,714 3,510 2,518 2,746
Depreciation, depletion and
amortization. . . . . . . . . 23,758 25,110 25,248 26,751 28,769
Impairment of property and
equipment (1) . . . . . . . . 1,186 10,259 - - -
General and administrative . . 3,266 3,708 5,659 6,876 5,416
------- ------- -------- -------- --------
Total costs and expenses . . 48,056 57,879 54,331 55,131 54,755
------- ------- -------- -------- --------
Operating income (loss). . . 16,835 (8,608) (4,846) 4,464 10,538
------- ------- -------- -------- --------
Other income (expense):
Interest expense . . . . . . . (3,440) (5,493) (4,461) (4,003) (6,807)
Other income (expense) (2) . . 335 6,022 759 149 (740)
------- ------- -------- -------- --------
Total other income
(expense) . . . . . . . . . (3,105) 529 (3,702) (3,854) (7,547)
------- ------- -------- -------- --------
Income (loss) before income
taxes . . . . . . . . . . . . . 13,730 (8,079) (8,548) 610 2,991
Income tax expense (3) . . . . . - - - 207 1,017
------- ------- -------- -------- --------
Net income (loss). . . . . . . . $13,730 $(8,079) $(8,548) $ 403 $ 1,974
------- ------- -------- -------- --------
------- ------- -------- -------- --------
Net income (loss) per
common share. . . . . . . . . . $ 1.77 $ (1.31) $ (1.50) $ .09 $ .62
------- ------- -------- -------- --------
------- ------- -------- -------- --------
Weighted average common
shares outstanding. . . . . . . 7,775 6,165 5,700 4,700 3,200
------- ------- -------- -------- --------
------- ------- -------- -------- --------

OTHER DATA:
Net cash provided by operating
activities . . . . . . . . . . $40,306 $24,203 $23,672 $ 29,716 $ 27,795
EBITDAX (4) . . . . . . . . . . 43,412 28,316 27,541 37,413 43,672
EBITDAX per share . . . . . . . 5.58 4.59 4.83 7.96 13.65

DECEMBER 31,
-----------------------------
1996 1995 1994
------ ------ ------
(IN THOUSANDS)
BALANCE SHEET DATA:
Working capital (deficit). . . . . . . . . . . . . . $ (3,422) $(13,717) $(12,269)
Total assets . . . . . . . . . . . . . . . . . . . . 103,598 93,161 111,746
Long-term debt . . . . . . . . . . . . . . . . . . . 18,000 33,538 49,147
Stockholders' equity . . . . . . . . . . . . . . . . 66,214 34,996 38,926

____________

(1) The Company adopted the provisions of Statement of Financial Accounting
Standards No. 121 "Accounting for Impairment of Long-Lived Assets"
effective October 1, 1995.
(2) The 1995 period includes a $6 million non-recurring gain on sale of the
Company's two principal gas gathering and processing systems.
(3) Prior to the Consolidation, income taxes were computed at the applicable
federal statutory rate.
(4) EBITDAX refers to earnings before income taxes, interest expense,
depreciation, depletion and amortization, impairment of property and
equipment, exploration costs, and other income (expense). EBITDAX is a
financial measure commonly used in the Company's industry and should not
be considered in isolation or as a substitute for net income, cash flow
provided by operating activities or other income or cash flow data
prepared in accordance with generally accepted accounting principles or as
a measure of a company's profitability or liquidity.

ITEM 7 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS

The following discussion is intended to assist in understanding the
Company's historical consolidated financial position at December 31, 1996, 1995
and 1994, and results of operations and cash flows for each of the three years
in the period ended December 31, 1996. The Company's historical Consolidated
Financial Statements and notes thereto included elsewhere in this Form 10-K
contain detailed information that should be referred to in conjunction with the
following discussion.

OVERVIEW

The Company commenced operations in May 1993, following the Consolidation
and completion of the Company's Initial Public Offering. Since 1988, the Company
and its predecessors have concentrated their drilling activities in the Trend.
Oil and gas production in the Trend is generally characterized by a high initial
production rate, followed by a steep rate of decline. In order to maintain its
oil and gas reserve base, production levels and cash flow from operations, the
Company must maintain or increase its level of drilling activity and achieve
comparable or improved results from such activities.

The Company follows the successful efforts method of accounting for its oil
and gas properties, whereby costs of productive wells, developmental dry holes
and productive leases are capitalized and amortized using the unit-of-production
method based on estimated proved reserves. Costs of unproved properties are
initially capitalized. Those properties with significant acquisition costs are
periodically assessed and any impairment in value is charged to expense. The
amount of impairment recognized on unproved properties which are not
individually significant is determined by amortizing the costs of such
properties within appropriate groups based on the Company's historical
experience, acquisition dates and average lease terms. Exploration costs,
including geological and geophysical expenses and delay rentals, are charged to
expense as incurred. Exploratory drilling costs, including the cost of
stratigraphic test wells, are initially capitalized but charged to expense if
and when the well is determined to be unsuccessful.

Results of Operations

The following table sets forth certain operating information of the Company
for the periods presented:

Year Ended December 31,
------------------------
1996 1995 1994
---- ---- ----
Oil and Gas Production Data:
Oil (MBbls) . . . . . . . . . . . . . 2,203 1,831 1,709
Gas (MMcf). . . . . . . . . . . . . . 5,584 6,845 8,369
Total (MBOE) (1). . . . . . . . . . . 3,134 2,972 3,104

Average Oil and Gas Sales Prices (2):
Oil ($/Bbl) . . . . . . . . . . . . . $20.85 $17.35 $15.72
Gas ($/Mcf) . . . . . . . . . . . . . $ 2.65 $ 1.77 $ 1.98

Operating Costs and Expenses ($/BOE Produced):
Lease operations. . . . . . . . . . . $ 4.71 $ 4.55 $ 4.12
Oil and gas depletion . . . . . . . . $ 7.32 $ 8.16 $ 7.81
General and administrative. . . . . $ 1.04 $ 1.25 $ 1.82

Net Wells Drilled:
Horizontal Wells. . . . . . . . . . . 24.4 23.5 16.2
Vertical Wells. . . . . . . . . . . . 1.1 -- 3.6

- -------------
(1) Gas is converted to barrel of oil equivalents (BOE) at the ratio of six
Mcf of gas to one Bbl of oil.
(2) Includes effects of hedging transactions.

1996 COMPARED TO 1995

REVENUES

Oil and gas sales increased 38% from $43.9 million in 1995 to $60.6
million in 1996 due primarily to a 20% increase in oil production, a 20%
increase in oil prices (net of hedging losses), and a 50% increase in gas
prices. These benefits were offset in part by an 18% decline in gas
production since most of the wells drilled since 1995 have been predominately
oil wells. Production from wells completed subsequent to December 31, 1995
accounted for approximately 37% of total oil production for the 1996 period,
which more than offset the effects of steep production declines from
previously existing Trend wells.

Revenues from natural gas services decreased 20% from $5.4 million in 1995
to $4.3 million in 1996 due primarily to the sale of the Company's two
principal gas gathering and processing systems in August 1995, and offset in
part by additional revenues generated in 1996 related to a gas plant and
three gathering systems acquired in the first quarter of 1996.

COSTS AND EXPENSES

Lease operations expenses increased 10% from $13.5 million in 1995 to
$14.8 million in 1996 while production on a BOE basis increased 5%, resulting
in an increase in lease operations expenses on a BOE basis from $4.55 per BOE
in 1995 to $4.71 per BOE in 1996. Such increase was due primarily to higher
production taxes resulting from the increase in oil and gas sales prices in
1996 as compared to 1995.

Although exploration costs were relatively insignificant in 1996 and 1995,
the Company expects exploration costs to increase significantly during 1997
due to the initiation of the Cotton Valley Exploratory Project and other
exploration activities outside the Trend. To date, the Company has

committed to spend approximately $4 million to conduct and evaluate a 3-D
seismic survey covering approximately 50,000 acres in the North Giddings
Block in 1997. The Company may continue to expand the area covered by the
survey and may drill one or more exploratory wells on any prospects which
result from such survey. In addition, the Company plans to spend
approximately $8 million on other exploration activities, a significant
portion of which will be classified as exploration costs. Because the
Company follows the successful efforts method of accounting, the Company's
results of operations may be adversely affected during any accounting period
in which such costs are incurred and expensed.

Depreciation, depletion and amortization ("DD&A") expense decreased 5%
from $25.1 million in 1995 to $23.8 million in 1996 due primarily to a 10%
decline in the Company's average depletion rate per BOE, offset in part by a
5% increase in production on a BOE basis. Under the successful efforts
method of accounting, costs of oil and gas properties are amortized on a
unit-of-production method based on estimated proved reserves. The lower
depletion rate is attributable to a combination of higher proved reserves
resulting from both newly completed wells and higher product prices, and
lower depletable costs resulting from the impairment of certain producing
properties in October 1995 and June 1996 pursuant to Statement of Financial
Accounting Standards No. 121, "Accounting for Impairment of Long-Lived
Assets" ("SFAS 121"). As a result, the average depletion rate declined from
$8.16 per BOE in 1995 to $7.32 per BOE in 1996.

The Company recorded a provision for impairment of property and equipment
of $1.2 million during the second quarter of 1996 in accordance with SFAS
121, as compared to a $10.3 million provision made during the fourth quarter
of 1995 upon the adoption of SFAS 121.

General and administrative ("G&A") expenses decreased 11% from $3.7
million in 1995 to $3.3 million in 1996. Certain cost reduction measures
implemented beginning in March 1994 were fully realized during 1995.
Accordingly, the Company does not expect G&A expenses to continue to decrease
as they have in recent years.

Costs of natural gas services decreased 8% from $3.7 million in 1995 to
$3.4 million in 1996 due primarily to the sale of the Company's two principal
gas gathering and processing systems in August 1995, and offset in part by
additional costs incurred in 1996 related to a gas plant and three gathering
systems acquired during the first quarter of 1996.

INTEREST EXPENSE AND OTHER

Interest expense decreased 38% from $5.5 million in 1995 to $3.4 million
in 1996 due primarily to lower average levels of indebtedness on the
Company's secured bank credit facility (the "Credit Facility") and, to a
lesser extent, lower average interest rates. The average daily principal
balance outstanding on such facility in 1996 was $36.9 million compared to
$52.3 million in 1995. The effective annual interest rate on bank debt in
1996 was 9.4% compared to 10.6% in 1995. Proceeds from the sales of assets
in August 1995 and January 1996 and the sale of common stock through a
shareholder rights offering in September 1995, which aggregated approximately
$15 million, were used to reduce bank indebtedness and contributed largely to
the reduction in interest expense in 1996 as compared to 1995. In addition,
the Company used $17 million of proceeds from the sale of common stock to
further reduce bank debt in November 1996. As a result, the Company
anticipates interest expense in 1997 to be lower than 1996.

Other income decreased from $6 million in 1995 to $335,000 in 1996. In
August 1995, XCEL Gas Company, a general partnership in which the Company
owned a 77% interest, sold its interest in a gas gathering system, and the
Company sold its 43% interest in the El Campo gas processing system, for
aggregate net proceeds of $7.7 million, resulting in a combined gain on sale
of property and equipment of $6 million, net to the Company.

1995 COMPARED TO 1994

REVENUES

Oil and gas sales increased 1% from $43.6 million in 1994 to $43.9 million
in 1995 due primarily to higher oil prices, the benefit of which was largely
eliminated by the effects of lower gas prices and a 4% decline in oil and gas
production. Although production from wells completed after December 31, 1994
accounted for 33% of the Company's 1995 production, these additions were more
than offset by characteristically steep production declines from previously
existing Trend wells. Average prices received for oil production increased
10% while average gas prices declined 11%.

Revenues from natural gas services decreased 8% from $5.9 million in 1994
to $5.4 million in 1995, despite the sale in August 1995 of the Company's two
principal gas gathering and processing systems, since one of the systems sold
was acquired effective January 1995 and did not contribute to revenues in
1994.

COSTS AND EXPENSES

Lease operations expenses increased 5% from $12.8 million in 1994 to $13.5
million in 1995 despite a 4% decline in BOE production. On a BOE basis, lease
operations expenses increased from $4.12 per BOE to $4.55 per BOE. Operating
expenses of Trend wells are generally lower on a BOE basis in the early
stages of production since a large portion of the operating expenses are
fixed in nature and do not vary with production volume. As production volumes
decline, operating expenses per BOE typically increase. In addition, during
1995, the Company conducted most of its drilling activity in the updip area
of the Trend where the reservoir pressures are lower. Generally, this
requires wells to be converted from flowing wells to electric-powered pumping
units at an earlier stage of production, which increases the lifting costs
associated with the updip wells.

Effective October 1, 1995, the Company adopted SFAS 121, and recorded a
$10.3 million non-cash provision for impairment of certain producing assets.
Substantially all of the impaired assets are located in the Pearsall Field in
the Trend.

DD&A expense remained constant from 1994 to 1995, despite a 4% decline in
production, due to slightly higher amortization rates per BOE. Under the
successful efforts method of accounting, costs of oil and gas properties are
amortized on a unit-of-production method based on estimated proved reserves.
The effects on amortization rates of a 15% downward revision of estimated
proved reserves at December 31, 1994 were substantially offset by the
adoption of SFAS 121, which reduced DD&A rates on the impaired properties.

G&A expenses decreased 35% from $5.7 million in 1994 to $3.7 million in
1995. Since March 1994, the Company has reduced its overhead by implementing
certain cost reduction measures, including the closing of its San Antonio
office, the elimination or reduction of certain professional services, and
the control of personnel costs through staff and wage reductions and employee
benefit cost controls. The benefit of these measures was fully realized in
1995.

Exploration costs decreased 77% from $7.1 million in 1994 to $1.6 million
in 1995 due primarily to provisions for dry hole costs, impairments of
unproved properties and seismic expenses in 1994 related to the Company's
acreage in the Sabine Area of the Trend, its Argentina venture and its West
and North Central Texas 3-D seismic program which did not recur in 1995.

Costs of natural gas services increased 6% from $3.5 million in 1994 to
$3.7 million in 1995 despite the sale in August 1995 of the Company's two
principal gas gathering and processing systems. The

reduction in costs related to the assets sold was more than offset by the
fact that one of the systems sold was acquired effective January 1995 and did
not contribute to costs in 1994.

INTEREST EXPENSE AND OTHER

Interest expense increased 22% from $4.5 million in 1994 to $5.5 million in
1995 due primarily to higher average interest rates on the Credit Facility. The
effective annual interest rate on bank debt during 1995 was 10.6% compared to
8.7% in 1994. Proceeds from the sale of certain natural gas gathering and
processing systems in August 1995 and the sale of Common Stock pursuant to a
rights offering in September 1995 resulted in a slight reduction in average
levels of bank debt in 1995. The average daily principal balance outstanding on
bank debt during 1995 was $52.3 million compared to $52.6 million in 1994.

Other income increased from $800,000 in 1994 to $6 million in 1995. In
August 1995, the Company sold certain gas gathering assets for aggregate net
proceeds of $7.7 million, resulting in a combined gain on sale of property and
equipment of $6 million, net to the Company.

1994 COMPARED TO 1993

REVENUES

Oil and gas sales decreased 21% from $55 million in 1993 to $43.6 million
in 1994 due to a combination of lower oil and gas production and lower
product prices. Oil and gas production on a BOE basis decreased 14% from
1993. Trend wells drilled in 1994 accounted for 12% of 1994 oil and gas
production, while 1994 acquisitions contributed 2%, both of which were more
than offset by the steep production declines which are characteristic of
Trend wells. In addition, prices received for oil and gas production also
declined during 1994 by 10% and 8%, respectively, accounting for
approximately one-third of the 21% decrease in oil and gas sales.

Revenues from natural gas services increased 28% from $4.6 million in 1993
to $5.9 million in 1994 due primarily to additional revenues generated in
1994 from the Company's Mentone gas treatment facility which was completed in
August 1993 and additional revenues generated through third party gas
marketing arrangements originating in December 1993.

COSTS AND EXPENSES

Lease operations expenses remained relatively constant in 1994 as compared
to 1993 despite a 14% decline in BOE production. On a BOE basis, lease
operations expenses increased from $3.54 per BOE to $4.12 per BOE. Operating
expenses of Trend wells are generally lower on a BOE basis in the early stages
of production since a large portion of the operating expenses are fixed in
nature and do not vary with production volume. As production volumes decline,
operating expenses per BOE generally increase. In addition, during 1994, the
Company conducted most of its drilling activity in the updip area of the Trend
where the reservoir pressures are lower. Generally, this requires wells to be
converted from flowing wells to electric-powered pumping units at an earlier
stage of production, which increases the lifting costs associated with the updip
wells.

DD&A expense decreased 6% from $26.8 million in 1993 to $25.2 million in
1994 due to a 14% decline in BOE production which was offset in part by
higher amortization rates per BOE. Under the successful efforts method of
accounting, costs of oil and gas properties are amortized on a
unit-of-production method based on estimated proved reserves. Quantities of
estimated proved reserves were revised downward by 15% on a BOE basis during
1994, contributing to an increase in the depletion rate for the fourth
quarter of 1994 to $9.11 per BOE compared to $7.81 per BOE for the entire
1994 year.

G&A expenses decreased 17% from $6.9 million in 1993 to $5.7 million in
1994 despite the incurrence of $601,000 of G&A expenses attributable to the
Company's Argentina venture in 1994. In March 1994, and again in January
1995, the Company implemented certain cost reduction measures, including the
elimination of three senior level positions, in order to reduce overhead and
conserve financial resources. The Company reduced professional fees
significantly during 1994. In addition, the Company closed its San Antonio
office and consolidated all exploration and production functions, other than
field operations, into its corporate headquarters in Midland.

Exploration costs increased 15% from $6.2 million in 1993 to $7.1 million
in 1994 due primarily to increases in provisions for dry holes and
impairments of unproved properties, offset in part by reductions in seismic
expenses. During 1994, the Company recorded provisions for impairments of
other unproved acreage totaling $2.6 million, the most significant of which
was attributable to the Sabine area of the Trend. In addition, the Company
recorded a provision for dry holes and abandonments of $2.5 million related
to an unsuccessful exploration venture in the Colhue Huapi area of Argentina
and expensed $1.4 million of seismic costs, dry hole costs and leasehold
impairments related to a 3-D seismic program in West and North Central Texas
initiated in 1993. By comparison, the 1993 exploration costs included $2.4
million of dry hole costs related to the unsuccessful results of two
exploratory wells, $1.9 million of leasehold impairments (primarily related
to the Sabine area of the Trend) and $1.5 million of seismic costs related to
the West and North Central Texas 3-D program.

Costs of natural gas services increased 40% from $2.5 million in 1993 to
$3.5 million in 1994 due primarily to the third party gas marketing
arrangements discussed under "Revenues" above. Since these arrangements are
typically characterized by low gross profit margins, the percentage increase
in costs was disproportionately higher than the associated percentage
increase in revenues.

INTEREST EXPENSE AND OTHER

Interest expense increased 13% from $4 million in 1993 to $4.5 million in
1994 due to higher average interest rates during 1994, offset in part by
lower average levels of bank indebtedness. The effective annual interest rate
on bank debt during 1994 was 8.7% compared to 7.6% in 1993. The average daily
principal balance outstanding on bank debt during 1994 was $52.6 million
compared to $54.1 million in 1993.

Included in other income during 1994 was a $600,000 gain related to a
favorable ruling in a legal proceeding for which a loss provision had been
recorded in 1992.

LIQUIDITY AND CAPITAL RESOURCES

OVERVIEW

The Company's primary financial resource is its oil and gas reserves. In
accordance with the terms of the Credit Facility, the banks establish a
borrowing base, as derived from the estimated value of the Company's oil and
gas properties, against which the Company may borrow funds as needed to
supplement its internally generated cash flow as a source of financing for
its capital expenditure program. Product prices, over which the Company has
very limited control, have a significant impact on such estimated value and
thereby on the Company's borrowing availability under the Credit Facility.
Within the confines of product pricing, the Company must be able to find and
develop or acquire oil and gas reserves in a cost effective manner in order
to generate sufficient financial resources through internal means to complete
the financing of its capital expenditure program.

The following discussion sets forth the Company's current plans for
capital expenditures in 1997, and the expected capital resources needed to
finance such plans.

CAPITAL EXPENDITURES

During 1997, the Company plans to drill up to 36 net wells in the Trend,
most of which will be in the North Giddings Block, and some of which will be
on acreage acquired through agreements with industry participants whereby the
Company will earn acreage by drilling successful wells. The Company
anticipates spending approximately $42 million in the Trend during 1997.

The Company has also committed to spend approximately $4 million in 1997
to conduct and evaluate a proprietary 3-D seismic survey covering a portion
of its acreage in connection with the Cotton Valley Exploratory Project and
may spend additional amounts to expand the area covered by the survey to
include other portions of the North Giddings Block and to begin drilling one
or more exploratory wells on any prospects delineated by such survey.

The Company plans to spend approximately $8 million in connection with
other exploration projects in areas outside the Trend. These activities will
be largely exploratory in nature, and will involve substantial expenditures
for seismic and leasing activities.

Substantially all of the planned 1997 activity is discretionary. This
allows the Company to make adjustments to its level of capital and
exploratory expenditures based upon such factors as the availability of
capital resources, product prices and drilling results. Thus, if the
Company's ability or desire to conduct the planned activities is diminished
or enhanced by any of these factors, the Company can modify its expenditures
accordingly. The Company's current policy is to limit its annual Cotton
Valley Exploratory Project expenditures to not more than 25% of its planned
annual capital expenditures. However, the Company may modify this policy
depending upon certain factors, including the Company's financial position,
exploratory drilling success, technological advances, drilling activities
conducted by third parties and current and anticipated product prices.

The Company does not have any specified amounts of capital expenditures
designated for acquisitions of proven properties in 1997. However, the
Company plans to actively seek and evaluate acquisition opportunities and
will commit only to those acquisitions which the Company can adequately
finance through internal and external sources.

CAPITAL RESOURCES

CREDIT FACILITY

The Credit Facility provides for a revolving loan facility in an amount
not to exceed the lesser of the borrowing base, as established by the banks,
or the elected borrowing limit, as determined by the Company. Based on its
expected needs for 1997, the Company elected a borrowing limit of $35 million
effective December 31, 1996, leaving $17 million of funds available at that
date. The borrowing base is scheduled for redetermination in May 1997, at
which time the Company may elect a higher borrowing limit, if such an
increase in borrowing capacity is both needed and available. The Company
intends to use such borrowing capacity, together with internally generated
funds, to (i) finance its 1997 planned capital expenditure program in the
Trend, (ii) conduct and evaluate the proprietary 3-D seismic survey as a part
of the Cotton Valley Exploratory Project, and (iii) conduct certain other
exploration projects presently under consideration.

WORKING CAPITAL AND CASH FLOW

During 1996, the Company generated cash flow from operating activities of
$40.3 million and received proceeds from the sales of common stock and assets
of $20.9 million. During the same period, the Company spent $33.1 million on
capital expenditures and repaid $26.9 million on the Credit Facility.

The Company's working capital deficit decreased from $13.7 million at
December 31, 1995 to $3.4 million at December 31, 1996 due primarily to a
reduction in current portion of long-term debt. The Credit Facility in
effect at December 31, 1995 required monthly prepayments of $950,000, while
the present Credit Facility does not require any prepayment as long as the
advances are less than the borrowing base.

Based on present levels of planned drilling and exploration activities,
the Company will spend approximately $54 million on such activities in 1997
as compared to approximately $34 million in 1996. As a result, the Company
anticipates that outstanding advances on its Credit Facility will increase
during 1997.

The Company believes that the funds available under the Credit Facility
and cash provided by operations will be adequate to fund the Company's
operations and projected capital and exploratory expenditures during 1997.
However, because future cash flows and the availability of borrowings are
subject to a number of variables, such as the level of production from
existing wells, the Company's success in locating and producing new reserves,
prevailing prices of oil and gas, and the uncertainty with respect to the
amount of funds which may ultimately be required to finance the Cotton Valley
Exploratory Project, there can be no assurance that the Company's capital
resources will be sufficient to sustain the Company's exploratory and
development activities. If such capital resources are insufficient, the
Company may be required to cease or delay such activities.

INFLATION AND CHANGES IN PRICES

The Company's revenues and the value of its oil and gas properties have
been and will continue to be affected by changes in oil and gas prices. The
Company's ability to maintain adequate borrowing capacity and to obtain
additional capital on attractive terms is also substantially dependent on oil
and gas prices. Oil and gas prices are subject to significant seasonal and
other fluctuations that are beyond the Company's ability to control or
predict. In an attempt to manage this price risk, the Company from time to
time engages in hedging transactions.

Although certain of the Company's costs and expenses are affected by the
level of inflation, inflation did not have a significant effect on the
Company's results of operations during 1996.

HEDGING TRANSACTIONS

From time to time, the Company has utilized hedging transactions with
respect to a portion of its oil and gas production to achieve a more
predictable cash flow, as well as to reduce its exposure to price
fluctuations. While the use of these hedging arrangements limits the downside
risk of price declines, such use may also limit any benefits which may be
derived from price increases.

The Company uses various financial instruments, such as swaps and collars,
whereby monthly settlements are based on differences between the prices
specified in the instruments and the settlement prices of certain futures
contracts quoted on the NYMEX or certain other indices. Generally, when the
applicable settlement price is less than the price specified in the contract,
the Company receives a settlement from the counterparty based on the
difference. Similarly, when the applicable settlement price is higher than
the specified price, the Company pays the counterparty based on the
difference. The instruments utilized by the Company differ from futures
contracts in that there is not a contractual obligation which requires or
allows for the future physical delivery of the hedged products.

Presently, the Company does not have any open positions in swap, collar or
other financial hedging arrangements. However, the Company may enter into
various hedging arrangements in the future in order to realize commodity
prices which it considers favorable under the circumstances.

ITEM 8 - FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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

ITEM 9 - CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE

None.

PART III

ITEM 10 - DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

The Information required by this Item is incorporated herein by reference
to the Company's definitive proxy statement which will be filed with the
Commission within 120 days after December 31, 1996.

ITEM 11 - EXECUTIVE COMPENSATION

The information required by this Item is incorporated herein by reference
to the Company's definitive proxy statement which will be filed with the
Commission within 120 days after December 31, 1996.

ITEM 12 - SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The information required by this Item is incorporated herein by reference
to the Company's definitive proxy statement which will be filed with the
Commission within 120 days after December 31, 1996.

ITEM 13 - CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

The information required by this Item is incorporated herein by reference
to the Company's definitive proxy statement which will be filed with the
Commission within 120 days after December 31, 1996.

PART IV

ITEM 14 - EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K

FINANCIAL STATEMENTS AND SCHEDULES

For a list of the consolidated financial statements filed as part of this
Form 10-K, see the Index to Consolidated Financial Statements on page F-1.

No financial statement schedules are required to be filed as a part of this
Form 10-K.

REPORTS ON FORM 8-K

No reports on Form 8-K were filed during the quarter ended December 31,
1996.

EXHIBITS

EXHIBIT
UMBER DESCRIPTION OF EXHIBIT
- ------- --------------------------------------------------------------------

**3.1 Second Restated Certificate of Incorporation of the Company, filed
as an exhibit to the Form S-2 Registration Statement, Registration
No. 333-13441

**3.2 Bylaws of the Company, filed as an exhibit to the Form S-1
Registration Statement, Registration No. 33-43350

**10.1 Fifth Restated Loan Agreement dated as of July 18, 1996, among Clayton
Williams Energy, Inc., Warrior Gas Co., CWEI Acquisitions, Inc., Bank
One, Texas, N.A., Banque Paribas and the First National Bank of
Chicago, filed as an exhibit to the June 30, 1996 Form 10-Q

*10.2 First Amendment to Fifth Restated Loan Agreement dated December 31,
1996, among Clayton Williams Energy, Inc., Warrior Gas Co., CWEI
Acquisitions, Inc., Bank One, Texas, N.A., Banque Paribas and the
First National Bank of Chicago

**10.3 1993 Stock Compensation Plan, filed as an exhibit to the Form S-8
Registration Statement, Registration No. 33-68318

**10.4 First Amendment to 1993 Stock Compensation Plan, filed as an exhibit
to the December 31, 1995 Form 10-K

**10.5 Second Amendment to the 1993 Stock Compensation Plan, filed as an
exhibit to the Form S-8 Registration Statement, Registration No. 33-
68318

**10.6 Outside Directors Stock Option Plan, filed as an exhibit to the Form
S-8 Registration Statement, Registration No. 33-68316

**10.7 First Amendment to Outside Directors Stock Option Plan, filed as an
exhibit to the December 31, 1995 Form 10-K

**10.8 Bonus Incentive Plan, filed as an exhibit to the Form S-8 Registration
Statement, Registration No. 33-68320

EXHIBIT
UMBER DESCRIPTION OF EXHIBIT
- ------- --------------------------------------------------------------------

**10.9 Amended and Restated 401(k) Plan & Trust, filed as an exhibit to the
December 31, 1995 Form 10-K

**10.10 Second Amendment to Amended and Restated 401(k) Plan & Trust, filed as
an exhibit to the December 31, 1995 Form 10-K

**10.11 Third Amendment to Amended and Restated 401(k) Plan & Trust, filed as
an exhibit to the December 31, 1995 Form 10-K

**10.12 Outside Directors Stock Compensation Plan, filed as an exhibit to the
Form S-8 Registration Statement, Registration No. 33-92832

**10.13 First Amendment to Outside Directors Stock Compensation Plan, filed as
an exhibit to the December 31, 1995 Form 10-K

*10.14 Second Amendment to Outside Directors Stock Compensation Plan

**10.15 Executive Incentive Stock Compensation Plan, filed as an exhibit to
the Form S-8 Registration Statement, Registration No. 33-92834

*10.16 First Amendment to Executive Incentive Stock Compensation Plan

**10.17 Consolidation Agreement dated May 13, 1993 among Clayton Williams
Energy, Inc., Warrior Gas Co. and the Williams Entities, filed as an
exhibit to the Form S-1 Registration Statement, Registration No. 33-
43350

**10.18 Agreement dated April 23, 1993 between the Company and Robert C. Lyon,
filed as an exhibit to the Form S-1 Registration Statement,
Registration No. 33-43350

**10.19 Service Agreement effective October 1, 1995 among Clayton Williams
Energy, Inc. and certain Williams Entities, filed as an exhibit to the
December 31, 1995 Form 10-K

*21 Subsidiaries of the Registrant

*23.1 Consent of Arthur Andersen LLP

*23.2 Consent of Williamson Petroleum Consultants, Inc.

*24.1 Power of Attorney

*24.2 Certified copy of resolution of Board of Directors of Clayton Williams
Energy, Inc. authorizing signature pursuant to Power of Attorney

*27 Financial Data Schedules

- -------------
* Filed herewith
** Incorporated by reference to the filing indicated

SIGNATURES

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

CLAYTON WILLIAMS ENERGY, INC.
(Registrant)

By:/s/ CLAYTON W. WILLIAMS, JR. *
----------------------------------
Clayton W. Williams, Jr.
Chairman of the Board, President
and Chief Executive Officer

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

Signature Title Date
--------- ----- ----

/s/ CLAYTON W. WILLIAMS, JR. * Chairman of the Board, March 24, 1997
- ------------------------------- President and Chief Executive
Clayton W. Williams, Jr. Officer and Director

/s/ L. PAUL LATHAM Executive Vice President, March 24, 1997
- ------------------------------- Chief Operating Officer and
L. Paul Latham Director

/s/ MEL G. RIGGS * Senior Vice President - March 24, 1997
- ------------------------------- Finance, Secretary, Treasurer,
Mel G. Riggs Chief Financial Officer and Director

/s/ STANLEY S. BEARD * Director March 24, 1997
- -------------------------------
Stanley S. Beard

/s/ WILLIAM P. CLEMENTS, JR. * Director March 24, 1997
- -------------------------------
William P. Clements, Jr.

/s/ ROBERT L. PARKER * Director March 24, 1997
- -------------------------------
Robert L. Parker

* By: /s/ L. PAUL LATHAM
- -------------------------------
L. Paul Latham
ATTORNEY-IN-FACT

CLAYTON WILLIAMS ENERGY, INC.

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

PAGE
----

Report of Independent Public Accountants . . . . . . . . F-2

Consolidated Balance Sheets. . . . . . . . . . . . . . . F-3

Consolidated Statements of Operations. . . . . . . . . . F-4

Consolidated Statements of Stockholders' Equity. . . . . F-5

Consolidated Statements of Cash Flows. . . . . . . . . . F-6

Notes to Consolidated Financial Statements . . . . . . . F-7

F-1

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To the Board of Directors of
Clayton Williams Energy, Inc.:

We have audited the accompanying consolidated balance sheets of Clayton
Williams Energy, Inc. as of December 31, 1996 and 1995, and the related
consolidated statements of operations, stockholders' equity and cash flows
for each of the three years in the period ended December 31, 1996. These
financial statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based
on our audits.

We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements.
An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Clayton Williams Energy,
Inc. as of December 31, 1996 and 1995, and the results of its operations and
cash flows for each of the three years in the period ended December 31, 1996,
in conformity with generally accepted accounting principles.

As discussed in Note 8, effective October 1, 1995, the Company adopted
Statement of Financial Accounting Standards No. 121 "Accounting for
Impairment of Long-Lived Assets and Long-Lived Assets to Be Disposed Of."

ARTHUR ANDERSEN LLP

Dallas, Texas
March 6, 1997

F-2

CLAYTON WILLIAMS ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(DOLLARS IN THOUSANDS)

ASSETS

DECEMBER 31,
-------------------
1996 1995
-------- --------
CURRENT ASSETS
Cash and cash equivalents. . . . . . . . . . . . $ 2,479 $ 1,303
Accounts receivable:
Trade, net. . . . . . . . . . . . . . . . . . 1,876 1,184
Affiliates. . . . . . . . . . . . . . . . . . 92 738
Oil and gas sales . . . . . . . . . . . . . . 10,440 6,615
Inventory. . . . . . . . . . . . . . . . . . . . 518 505
Other. . . . . . . . . . . . . . . . . . . . . . 557 565
-------- --------
15,962 10,910
-------- --------
PROPERTY AND EQUIPMENT
Oil and gas properties, successful
efforts method . . . . . . . . . . . . . . . . . 354,532 325,268
Natural gas gathering and processing
systems. . . . . . . . . . . . . . . . . . . . 7,655 6,951
Other. . . . . . . . . . . . . . . . . . . . . . 9,547 9,460
-------- --------
371,734 341,679
Less accumulated depreciation, depletion
and amortization . . . . . . . . . . . . . . . (284,173) (259,533)
-------- --------
Property and equipment, net . . . . . . . . . 87,561 82,146
-------- --------
OTHER ASSETS . . . . . . . . . . . . . . . . . . . 75 105
-------- --------
$103,598 $ 93,161
-------- --------
-------- --------

LIABILITIES AND STOCKHOLDERS' EQUITY

CURRENT LIABILITIES
Accounts payable:
Trade . . . . . . . . . . . . . . . . . . . . $ 10,233 $ 6,911
Affiliates. . . . . . . . . . . . . . . . . . 615 346
Oil and gas sales . . . . . . . . . . . . . . 7,454 4,813
Current maturities of long-term debt . . . . . . 112 11,509
Accrued liabilities and other. . . . . . . . . . 970 1,048
-------- --------
19,384 24,627
-------- --------
LONG-TERM DEBT . . . . . . . . . . . . . . . . . . 18,000 33,538
-------- --------
COMMITMENTS AND CONTINGENCIES. . . . . . . . . . . - -
-------- --------
STOCKHOLDERS' EQUITY:
Preferred stock, par value $.10 per share;
authorized - 3,000,000 shares; issued and
outstanding - none. . . . . . . . . . . . . . . - -
Common stock, par value $.10 per share;
authorized - 15,000,000 shares; issued and
outstanding - 8,927,658 shares in 1996 and
7,409,664 shares in 1995. . . . . . . . . . . . 893 741
Additional paid-in capital . . . . . . . . . . . 70,248 52,912
Retained deficit . . . . . . . . . . . . . . . . (4,927) (18,657)
-------- --------
66,214 34,996
-------- --------
$103,598 $ 93,161
-------- --------
-------- --------

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

F-3

CLAYTON WILLIAMS ENERGY, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share)

YEAR ENDED DECEMBER 31,
---------------------------
1996 1995 1994
------ ------ ------
REVENUES
Oil and gas sales. . . . . . . . . $60,610 $43,883 $43,617
Natural gas services . . . . . . . 4,281 5,388 5,868
------- ------- -------
Total revenues. . . . . . . . . 64,891 49,271 49,485
------- ------- -------

COSTS AND EXPENSES
Lease operations . . . . . . . . . 14,776 13,533 12,775
Exploration. . . . . . . . . . . . 1,633 1,555 7,139
Natural gas services . . . . . . . 3,437 3,714 3,510
Depreciation, depletion and
amortization . . . . . . . . . . . 23,758 25,110 25,248
Impairment of property and
equipment . . . . . . . . . . . . 1,186 10,259 -
General and administrative . . . . 3,266 3,708 5,659
------- ------- -------
Total costs and expenses. . . . 48,056 57,879 54,331
------- ------- -------
Operating income (loss) . . . . 16,835 (8,608) (4,846)
------- ------- -------
OTHER INCOME (EXPENSE)
Interest expense . . . . . . . . . (3,440) (5,493) (4,461)
Other. . . . . . . . . . . . . . . 335 6,022 759
------- ------- -------
Total other income (expense). . (3,105) 529 (3,702)
------- ------- -------
INCOME (LOSS) BEFORE INCOME TAXES. . 13,730 (8,079) (8,548)
------- ------- -------
INCOME TAX EXPENSE
Current. . . . . . . . . . . . . . - - -
Deferred . . . . . . . . . . . . . - - -
------- ------- -------
Total income tax expense. . . . - - -
------- ------- -------
NET INCOME (LOSS). . . . . . . . . . $13,730 $(8,079) $(8,548)
------- ------- -------
------- ------- -------
Net income (loss) per common
share . . . . . . . . . . . . . . . $ 1.77 $ (1.31) $ (1.50)
------- ------- -------
------- ------- -------
Weighted average common shares
outstanding . . . . . . . . . . . . 7,775 6,165 5,700
------- ------- -------
------- ------- -------

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

F-4

CLAYTON WILLIAMS ENERGY, INC.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(In thousands)

COMMON STOCK
--------------- ADDITIONAL
NO. OF PAR PAID-IN RETAINED
SHARES VALUE CAPITAL DEFICIT TOTAL
------ ----- ---------- -------- -----

BALANCE, December 31, 1993 . . . 5,700 $ 570 $48,934 $ (2,030) $ 47,474

Net loss. . . . . . . . . . . . - - - (8,548) (8,548)
------ ----- ------- -------- --------
BALANCE, December 31, 1994 . . . 5,700 570 48,934 (10,578) 38,926

Sale of stock through rights
offering, net of offering
costs. . . . . . . . . . . . . 1,599 160 3,648 - 3,808
Issuance of stock through
compensation plans . . . . . . 111 11 330 - 341
Net loss. . . . . . . . . . . . - - - (8,079) (8,079)
------ ----- ------- -------- --------
BALANCE, December 31, 1995 . . . 7,410 $ 741 $52,912 $(18,657) $ 34,996

Sale of stock through secondary
public offering, net of offering
costs. . . . . . . . . . . . . 1,428 143 16,874 - 17,017
Issuance of stock through
compensation plans . . . . . . 90 9 462 - 471
Net income. . . . . . . . . . . - - - 13,730 13,730
------ ----- ------- -------- --------
BALANCE, December 31, 1996 . . . 8,928 $ 893 $70,248 $ (4,927) $ 66,214
------ ----- ------- -------- --------
------ ----- ------- -------- --------

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

F-5

CLAYTON WILLIAMS ENERGY, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)

Year Ended December 31,
---------------------------------
1996 1995 1994
--------- --------- ---------

CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss). . . . . . . . . . . . . . . . . . $ 13,730 $ (8,079) $ (8,548)
Adjustments to reconcile net income (loss) to cash
provided by operating activities:
Depreciation, depletion and amortization . . . . 23,758 25,110 25,248
Impairment of property and equipment . . . . . . 1,186 10,259 -
Exploration costs. . . . . . . . . . . . . . . . 597 1,472 6,227
Gain on sales of property and equipment. . . . . (293) (5,978) (11)
Other. . . . . . . . . . . . . . . . . . . . . . 445 341 -
Changes in operating working capital:
Accounts receivable. . . . . . . . . . . . . . . (3,871) 121 2,964
Accounts payable . . . . . . . . . . . . . . . . 4,824 737 (2,197)
Other. . . . . . . . . . . . . . . . . . . . . . (70) 220 (11)
--------- --------- ---------
Net cash provided by operating activities. . 40,306 24,203 23,672
--------- --------- ---------

CASH FLOWS FROM INVESTING ACTIVITIES
Additions to property and equipment. . . . . . . . . (33,100) (20,433) (35,330)
Proceeds from sales of property and equipment. . . . 3,862 7,950 880
--------- --------- ---------
Net cash used in investing activities. . . . (29,238) (12,483) (34,450)
--------- --------- ---------

CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt . . . . . . . . . . . . - - 17,200
Repayments of long-term debt . . . . . . . . . . . . (26,935) (15,656) (5,942)
Proceeds from sale of common stock . . . . . . . . . 17,043 3,808 -
--------- --------- ---------
Net cash provided by (used in) financing
activities. . . . . . . . . . . . . . . . . (9,892) (11,848) 11,258
--------- --------- ---------

NET INCREASE (DECREASE) IN CASH AND
CASH EQUIVALENTS . . . . . . . . . . . . . . . . . . 1,176 (128) 480
CASH AND CASH EQUIVALENTS
Beginning of period. . . . . . . . . . . . . . . . 1,303 1,431 951
--------- --------- ---------
End of period. . . . . . . . . . . . . . . . . . . $ 2,479 $ 1,303 $ 1,431
--------- --------- ---------
--------- --------- ---------

SUPPLEMENTAL DISCLOSURES
Cash paid for interest, net of amounts
capitalized. . . . . . . . . . . . . . . . . . . . $ 3,434 $ 5,613 $ 4,860
--------- --------- ---------
--------- --------- ---------

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

F-6

CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. ORGANIZATION AND PRESENTATION

Clayton Williams Energy, Inc. (the "Company"), a Delaware corporation, was
incorporated in September 1991 for the purpose of consolidating and continuing
certain operations previously conducted by affiliates of Clayton W. Williams,
Jr. ("Mr. Williams"). Concurrent with the completion of the initial public
offering of the Company's common stock on May 26, 1993, these operations were
consolidated, and the Company succeeded to most of the oil and gas properties,
exploration and development operations and the natural gas gathering and
marketing operations of Mr. Williams and his affiliates.

The Company is primarily engaged in the exploration for and development
and production of oil and natural gas in South and East Texas, Southeastern
New Mexico and the Texas Gulf Coast.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

ESTIMATES AND ASSUMPTIONS
The preparation of financial statements in conformity with generally
accepted accounting principles requires management of the Company to make
estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the date of
the financial statements and the reported amounts of revenues and expenses
during the reporting period. Actual results could differ from those estimates.

PRINCIPLES OF CONSOLIDATION
The consolidated financial statements include the accounts of Clayton
Williams Energy, Inc. and its subsidiaries (collectively, the "Company"). The
Company accounts for its interests in joint ventures and partnerships (all of
which are undivided) using the proportionate consolidation method, whereby its
share of assets, liabilities, revenues and expenses are consolidated with other
operations. All significant intercompany transactions and balances associated
with the consolidated operations have been eliminated.

OIL AND GAS PROPERTIES
The Company follows the successful efforts method of accounting for its
oil and gas properties, whereby costs of productive wells, developmental dry
holes and productive leases are capitalized and amortized using the
unit-of-production method based on estimated proved reserves. Sales proceeds
from sales of individual properties are credited to property costs. No gain
or loss is recognized until the entire amortization base is sold or abandoned.

Costs of acquisition of leaseholds are capitalized. Unproved oil and gas
properties with significant acquisition costs are periodically assessed and any
impairment in value is charged to exploration costs. The amount of impairment
recognized on unproved properties which are not individually significant is
determined by amortizing the costs of such properties within appropriate groups
based on the Company's historical experience, acquisition dates and average
lease terms. The costs of unproved properties which are determined to hold
proved reserves are transferred to proved oil and gas properties.

Exploration costs, including geological and geophysical expenses and delay
rentals, are charged to expense as incurred. Exploratory drilling costs,
including the cost of stratigraphic test wells, are initially capitalized but
charged to exploration expense if and when the well is determined to be
unsuccessful.

NATURAL GAS AND OTHER PROPERTY AND EQUIPMENT
Natural gas gathering and processing systems consist primarily of gas
gathering pipelines, compressors and gas processing plants. Other property and
equipment consists primarily of field

F-7

CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

equipment and facilities, office equipment, leasehold improvements and
vehicles. Major renewals and betterments are capitalized while the costs of
repairs and maintenance are charged to expense as incurred. The costs of
assets retired or otherwise disposed of and the applicable accumulated
depreciation are removed from the accounts, and any gain or loss is included
in other income in the accompanying consolidated statements of operations.

Depreciation of natural gas gathering and processing systems and other
property and equipment is computed on the straight-line method over the
estimated useful lives of the assets, which range from 3 to 32 years.

VALUATION OF PROPERTY AND EQUIPMENT
The Company follows the provisions of Statement of Financial Accounting
Standards No. 121 "Accounting for Impairment of Long-Lived Assets" ("SFAS 121")
which requires that the Company's long-lived assets, including its oil and gas
properties, be assessed for potential impairment in their carrying values
whenever events or changes in circumstances indicate such impairment may have
occurred.

INCOME TAXES
The Company follows the asset and liability method prescribed by Statement
of Financial Accounting Standards No. 109 "Accounting for Income Taxes" ("SFAS
109"). Under this method of accounting for income taxes, deferred tax assets
and liabilities are recognized for the future tax consequences attributable to
differences between the financial statement carrying amounts of existing assets
and liabilities and their respective tax bases. Deferred tax assets and
liabilities are measured using enacted tax rates expected to apply to taxable
income in the years in which those temporary differences are expected to be
recovered or settled. Under SFAS 109, the effect on deferred tax assets and
liabilities of a change in enacted tax rates is recognized in income in the
period that includes the enactment date.

INVENTORY
Inventory consists primarily of tubular goods and other well equipment
which the Company plans to utilize in its ongoing exploration and development
activities and is carried at the lower of cost or market value.

CAPITALIZATION OF INTEREST
Interest costs associated with maintaining the Company's inventory of
unproved oil and gas properties are capitalized. During the years ended
December 31, 1996, 1995 and 1994, the Company capitalized interest totaling
approximately $68,000, $85,000 and $192,000, respectively.

STATEMENTS OF CASH FLOWS
The Company considers all highly liquid investments with original
maturities of three months or less to be cash equivalents.

NET INCOME (LOSS) PER COMMON SHARE
Net income (loss) per common share is based on the weighted average number
of common and common equivalent shares, if dilutive, outstanding during each
period. Common stock equivalents were not included in the computation of net
income (loss) per share in 1995 or 1994 since the effect was anti-dilutive.

STOCK-BASED COMPENSATION
The Company accounts for stock-based compensation utilizing the intrinsic
value method prescribed by Accounting Principles Board Opinion No. 25
("APB 25"), "Accounting for Stock Issued to Employees."

F-8

CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENT (CONTINUED)

REVENUE RECOGNITION AND GAS BALANCING
The Company utilizes the sales method of accounting for natural gas revenues
whereby revenues are recognized based on the amount of gas sold to purchasers.
The amount of gas sold may differ from the amount to which the Company is
entitled based on its revenue interests in the properties. The Company had no
significant imbalance positions at December 31, 1996, 1995 or 1994.

3. LONG-TERM DEBT

Long-term debt consists of the following:

DECEMBER 31,
-----------------
1996 1995
------- -------
(IN THOUSANDS)
Secured Bank Credit Facility (matures July 31, 1999):
Revolving loan . . . . . . . . . . . . . . . . . . . $18,000 $17,000
Term loan. . . . . . . . . . . . . . . . . . . . . . - 27,825
Other . . . . . . . . . . . . . . . . . . . . . . . . . 112 222
------- -------
18,112 45,047
Less current maturities . . . . . . . . . . . . . . . . 112 11,509
------- -------
$18,000 $33,538
------- -------
------- -------

Aggregate maturities of long-term debt at December 31, 1996 are as follows:
1997 - $112,000; 1998 - $0; and 1999 - $18,000,000.

SECURED BANK CREDIT FACILITY
The Company's secured bank credit facility provides for a revolving loan
facility in an amount not to exceed the lesser of the borrowing base, as
established by the banks, or the elected borrowing limit, as determined by the
Company. At December 31, 1996, the elected borrowing limit was $35 million, and
the available credit on the revolving facility was $17 million. The borrowing
base is scheduled to be redetermined in May 1997 and at least semi-annually
thereafter; however, the Company or the banks may request a borrowing base
redetermination at any other time during the year. Any redetermination will be
made at the discretion of the banks. If, at any time, outstanding advances plus
letters of credit exceed the borrowing base, the Company will be required to (i)
pledge additional collateral, (ii) prepay the excess in not more than five equal
monthly installments or (iii) elect to convert the entire amount of the facility
to a term obligation based on amortization formulas set forth in the loan
agreement. Substantially all of the Company's oil and gas properties are
pledged to secure advances under the secured bank credit facility.

All outstanding balances on the secured bank credit facility may be
designated, at the Company's option, as either "Base Rate Loans" or "Eurodollar
Loans" (as defined in the agreement), provided that not more than two Eurodollar
traunches may be outstanding at any time. Base Rate Loans will bear interest at
the fluctuating Base Rate plus a Base Rate Margin ranging from 0% to 3/8% per
annum, depending on levels of outstanding advances and letters of credit.
Eurodollar Loans will bear interest at the LIBOR rate for a fixed period of time
elected by the Company plus a Eurodollar Margin ranging from 1% to 1.75% per
annum. At December 31, 1996, all of the Company's indebtedness under this
facility consisted of Eurodollar Loans at 7.1%.

In addition, the Company pays the banks a commitment fee equal to 1/4% per
annum on the unused portion of the revolving loan commitment. Interest on the
revolving loan and commitment fees are payable quarterly, and all outstanding
principal and interest will be due July 1, 1999.

F-9

CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENT (CONTINUED)

4. STOCKHOLDERS' EQUITY

In September 1995, the Company received $3,808,000, net of offering costs of
$93,000, from the sale of 1,598,971 shares of common stock at a price of $2.44
per share pursuant to a registered rights offering made to stockholders of
record on August 18, 1995. Proceeds from the offering were used to repay
indebtedness on the secured bank credit facility.

In November 1996, the Company received $17,017,000, net of underwriters
discounts and other offering costs totaling $1,541,000, from the sale of
1,427,500 shares of common stock to the public at a price of $13.00. Proceeds
from the offering were used to repay indebtedness on the secured bank credit
facility.

Subsequent to December 31, 1996, the Company's Board of Directors authorized
the Company to spend up to $2 million to repurchase shares of its common stock
on the open market to be held as treasury stock. Through March 20, 1997, the
Company had purchased 70,000 shares at a cost of $1,115,000.

5. STOCK COMPENSATION PLANS

1993 PLAN
The Company has reserved 898,200 shares of common stock for issuance under
the 1993 Stock Compensation Plan ("1993 Plan"). The 1993 Plan provides for the
issuance of nonqualified stock options with an exercise price which is not less
than the market value of the Company's common stock on the date of grant. All
options granted through December 31, 1996 expire 10 years from the date of grant
and become exercisable at 25% per year beginning one year from the date of
grant.

The following table reflects activity in the 1993 Plan for 1996, 1995 and
1994.

1996 1995 1994
------------------- ------------------ ------------------
Weighted Weighted Weighted
Average Average Average
Shares Price Shares Price Shares Price
------- -------- ------- -------- ------- --------

Beginning of year . . . . . . . 151,601 $ 2.45 149,101 $7.25 276,937 $15.75
Granted (a) . . . . . . . . . 321,500 $11.03 149,101 $2.38 149,101 $ 7.25
Exercised . . . . . . . . . . (10,410) $ 2.38 - - - -
Forfeited . . . . . . . . . . (3,925) $ 2.82 (18,540) $7.25 (33,785) $15.75
Cancelled (b) . . . . . . . . - - (128,061) $7.25 (243,152) $15.75
------- -------- --------
End of year . . . . . . . . . . 458,766 $ 8.46 151,601 $2.45 149,101 $7.25
------- -------- --------
------- -------- --------

Exercisable . . . . . . . . . . 104,449 $ 2.47 75,800 $2.45 37,275 $7.25
------- -------- --------
------- -------- --------
Issuable (c). . . . . . . . . . 439,434 146,599 149,099
------- -------- --------
------- -------- --------

--------------
(a) The Company granted options to purchase 121,500 shares in March 1996 at
an option price of $3.25 per share and 200,000 shares in December 1996
at an option price of $15.75 per share.
(b) During 1994, the Company offered participants the opportunity to exchange
options issued in 1993 at $15.75 per share for a lesser number of options
with an exercise price of $7.25 per share. In 1995, the Company offered
to exchange substantially all of the options issued in 1994 with an
exercise price of $7.25 per share for new options with an exercise price
of $2.38 per share.
(c) At December 31, 1995 and 1994, the Company had 298,200 shares reserved
for issuance under the 1993 Plan.

F-10

CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

DIRECTORS PLAN
The Company has reserved 86,300 shares of common stock for issuance under
the Outside Directors Stock Option Plan ("Directors Plan"). Since inception of
the Directors Plan, the Company has issued options covering 12,000 shares of
common stock (3,000 per year from 1993 through 1996) at option prices ranging
from $3.25 to $15.75 per share. All options expire 10 years from the date of
grant and are fully exercisable upon issuance. At December 31, 1996, options to
purchase 12,000 shares were outstanding, and 74,300 shares remain available for
future grants.

BONUS INCENTIVE PLAN
The Company has reserved 115,500 shares of common stock for issuance under
the Bonus Incentive Plan. The plan provides that the Board of Directors each
year may award bonuses in cash, common stock of the Company, or a combination
thereof. To date, no bonuses in cash or stock have been awarded under this
plan.

STOCK COMPENSATION PLANS
In May 1995, the Company's Board of Directors adopted two stock compensation
plans, one for selected officers and one for outside directors of the Company,
permitting the Company to pay all or part of selected executives' salaries and
all outside director's fees in shares of common stock in lieu of cash. The
Company reserved an aggregate of 650,000 shares of common stock for issuance
under these plans. During 1996 and 1995, the Company issued Mr. Williams 67,785
and 101,663 shares, respectively, of common stock in lieu of cash compensation
aggregating $384,000 and $312,000, respectively, and issued 11,581 and 9,030
shares, respectively, to three outside directors in lieu of cash compensation
aggregating $61,000 and $29,000, respectively. The amounts of such compensation
are included in general and administrative expense in the accompanying
consolidated financial statements. Effective January 1, 1997, the Company
terminated the outside directors stock compensation plan.

SUPPLEMENTAL DISCLOSURE
In October 1995, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards No. 123 ("SFAS 123"), "Accounting for Stock-
Based Compensation." SFAS 123 establishes a fair value method and disclosure
standards for stock-based employee compensation arrangements, such as stock
option plans. As permitted by SFAS 123, the Company has elected to continue
following the provisions of APB 25 for such stock-based compensation, under
which no compensation expense has been recognized. Had compensation expense for
these plans been determined consistent with SFAS 123, the Company's net income
(loss) and net income (loss) per share would have been as follows:

1996 1995
-----------------------
(In thousands, except per share)
Net income (loss):
As reported. . . . . . . . . . . . $13,730 $(8,079)
Pro forma. . . . . . . . . . . . . $13,558 $(8,170)

Net income (loss) per share:
As reported. . . . . . . . . . . . $ 1.77 $ (1.31)
Pro forma. . . . . . . . . . . . . $ 1.74 $ (1.33)

SFAS 123 requires the use of option valuation models which were generally
developed for use in estimating the fair value of traded options which have no
vesting restrictions, are fully transferrable and

F-11

CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

generally have shorter life expectancies. These valuation models also
require the input of highly subjective assumptions, including the expected
stock price volatility. Because the Company's stock option plans have
characteristics significantly different from those of traded options, and
because changes in the subjective input assumptions can materially affect the
fair value estimate, in management's opinion, the existing models do not
necessarily provide a reliable single measure of the fair value of its
employee stock options.

For purposes of the above pro forma disclosures, the fair value of each
option grant is estimated as of the date of grant using the Black-Scholes option
pricing model with the following weighted average assumptions for grants in 1996
and 1995, respectively: risk-free interest rates of 5.8%; dividend yields of
0%; volatility factors of the expected market price of the Company's common
stock of .561 and .411; and a life expectancy of each option of 5.1 and 4.8
years.

6. TRANSACTIONS WITH AFFILIATES

During the periods presented, the Company and various entities controlled
by Mr. Williams provided certain general and administrative services to one
another. General and administrative expenses in the accompanying financial
statements are net of charges by the Company to affiliates for services
aggregating $615,000, $772,000 and $855,000 for the years ended December 31,
1996, 1995 and 1994, respectively, and include charges to the Company by
affiliates for rents and services aggregating $235,000, $289,000 and $512,000
for the years ended December 31, 1996, 1995 and 1994, respectively.

Prior to October 1995, the Company owned a 90% interest in the Mentone gas
plant constructed in 1993 to process gas from two wells in Loving County,
Texas pursuant to a long-term contract. The two wells were substantially
owned by entities controlled by Mr. Williams. Because the plant and the
wells are largely dependent upon each other for their economic viability, the
Company and the entities controlled by Mr. Williams contributed their
respective interests in the plant and wells to a partnership effective
October, 1995. After recoupment of certain workover costs borne by the
original well owners, the Partnership was dissolved in 1996, and the Company
received an undivided 45% interest in the wells, proportionately reduced to
the original well owners' interests, and retained a 45% interest in the plant.

Accounts receivable from affiliates and accounts payable to affiliates
include, among other things, amounts for charges whereby the Company is the
operator of certain wells in which affiliates own an interest. These charges
are on terms which are consistent with the terms offered to unaffiliated
third parties which own interests in wells operated by the Company.

7. COMMITMENTS AND CONTINGENCIES

LEASES
The Company leases office space from affiliates and nonaffiliates under
noncancelable operating leases. Rental expense pursuant to the office leases
amounted to $398,000, $453,000 and $489,000 for the years ended December 31,
1996, 1995 and 1994, respectively. Included in property and equipment are
assets under capital leases aggregating $133,000, $233,000 and $528,000 net of
accumulated depreciation, at December 31, 1996, 1995 and 1994, respectively.

F-12

CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Future minimum payments under noncancelable leases at December 31, 1996, are
as follows:

CAPITAL OPERATING
LEASES LEASES
-------- ---------
(IN THOUSANDS)

1997. . . . . . . . . . . . . . . . . $ 118 $ 530
1998. . . . . . . . . . . . . . . . . - 117
1999. . . . . . . . . . . . . . . . . - 3
-------- -------
Total minimum lease payments. . . 118 $ 650
-------
-------
Less amount representing interest . . (6)
--------
Present value of net minimum
lease payments . . . . . . . . . $ 112
--------
--------

CONCENTRATION OF CREDIT RISK
The Company's revenues are derived principally from uncollateralized sales
to customers in the oil and gas industry. The concentration of credit risk in a
single industry affects the Company's overall exposure to credit risk because
customers may be similarly affected by changes in economic and other conditions.
The Company has not experienced significant credit losses on such receivables.

FORWARD SALES TRANSACTIONS
The Company accounts for forward sale and put option arrangements as hedging
activities and, accordingly, gains and losses are included in oil and gas
revenues in the period the hedged production is sold. Included in oil and gas
revenues are net losses totaling $1,156,000 in 1996 (comprised of losses of
$1,299,000 partially offset by gains of $143,000), $342,000 in 1995 (comprised
of losses of $426,000 partially offset by gains of $84,000) and $78,000 in 1994
(comprised of losses of $238,000 partially offset by gains of $160,000). At
December 31, 1996, none of the Company's future oil and gas production was
subject to hedging arrangements.

LEGAL PROCEEDINGS
In April 1994, the Fifth Circuit Court of Appeals reversed a judgment
against the Company for approximately $600,000 in damages. The case was settled
with no damages being assessed against the Company. Accordingly, the Company
reversed the previously recorded loss provision, resulting in the recognition of
$600,000 of other income during 1994.

The Company is a defendant in a suit styled The State of Texas, et al v.
Union Pacific Resources Company et al, presently pending in Lee County, Texas.
The suit attempts to establish a class action consisting of unidentified royalty
and working interest owners throughout the State of Texas. Among other things,
the plaintiffs are seeking actual and exemplary damages for alleged violation of
various statutes relating to common carriers and common purchasers of crude oil
including discrimination in the purchase of oil by giving preferential treatment
to defendants' own oil and conspiring to keep the posted price or sales price of
oil below market value. A general denial has been filed. Because the Company is
neither a common purchaser nor common carrier of oil, management of the Company
believes there is no merit to the allegations as they relate to the Company or
its operations.

The Company is involved in various legal proceedings arising in the normal
course of its business, including actions for which insurance coverage is
available. While the ultimate results of these proceedings cannot be predicted
with certainty, the Company does not believe that the outcome of any of these
matters will have, individually or in the aggregate, a material adverse effect
on its financial

F-13

CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

condition; however, they could have a material impact on results of
operations in an annual or interim period.

8. IMPAIRMENT OF PROPERTY AND EQUIPMENT

Effective October 1, 1995, the Company adopted SFAS 121 and recorded a
provision for impairment of property and equipment totaling $10.3 million, of
which $9.1 million related to proved oil and gas properties and $1.2 million
related to gas gathering and processing systems. Substantially all of the
impaired assets are located in the Pearsall Field of South Texas.

During 1996, the Company recorded an additional provision for impairment
under SFAS 121 of $1.2 million resulting from a revision in reserve estimates
subsequent to December 31, 1995, attributable to a proved undeveloped
location in the Texas Gulf Coast area.

9. SALES OF ASSETS

In August 1995, XCEL Gas Company, a general partnership in which the
Company owns a 77% interest, sold its interest in a gas gathering system, and
the Company sold its 43% interest in the El Campo gas processing system, for
aggregate net proceeds of $7.7 million, resulting in a combined gain on sale
of property and equipment of $6.0 million, net to the Company. The Company
used the proceeds from these sales to repay indebtedness on the secured bank
credit facility.

In January 1996, the Company sold its rights to the Buda and Georgetown
formations under approximately 28,000 net acres in Robertson County, Texas
for $3.5 million. The net proceeds were used to repay indebtedness on the
secured bank credit facility. No gain or loss was recognized on the sale.

10. INCOME TAXES

Since the Consolidation discussed in Note 1, the Company has incurred net
losses for financial reporting purposes aggregating $4.9 million and has
recognized cumulative tax losses of approximately $36 million which can be
carried forward and used to offset future taxable income. Tax loss
carryforwards begin to expire in 2008. Due to the uncertainty of realizing
the related future benefits from tax loss carryforwards, valuation allowances
have been recorded to the extent net deferred tax assets exceed net deferred
tax liabilities at December 31, 1996, 1995 and 1994.

The tax effected temporary differences and tax loss carryforwards which
comprise net deferred tax assets and liabilities are as follows:

DECEMBER 31,
-------------------------------
1996 1995 1994
-------- -------- --------
(IN THOUSANDS)
Deferred tax assets (liabilities):
Depreciable and depletable
property . . . . . . . . . . $(10,216) $ (4,030) $ (6,153)
Tax loss carryforwards. . . . 12,737 11,305 10,533
Other . . . . . . . . . . . . 929 912 1,057
Valuation allowance . . . . . (3,450) (8,187) (5,437)
-------- -------- --------
Net deferred tax asset
(liability). . . . . . . . $ - $ - $ -
-------- -------- --------
-------- -------- --------

F-14

CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

The reduction in the valuation allowance from $8,187,000 at December 31,
1995 to $3,450,000 at December 31, 1996 is due to the expected future
improvement in financial results of the Company based on its reduced debt
levels and improved operating results. All of the difference between the
statutory income tax rate and the effective income tax rate is attributable
to the change in the valuation allowance.

11. TERMINATION OF ARGENTINA VENTURE

During 1994, the Company conducted certain exploration activities in the
Colhue Huapi area of Argentina pursuant to an exploration agreement with CAPEX
S.A. This agreement obligated the Company to drill a minimum of six wells by
March 1, 1995, as extended, or pay a contract termination fee of $437,500 per
well for each well not drilled. The Company drilled two of the six obligation
wells, and based upon its evaluation of the drilling results, elected not to
drill any additional wells in the area. In February 1995, the Company sold its
entire interest in the Argentina venture to Occidental Petrolera de Argentina,
Ltd. for $100,000 and secured a release from all drilling commitments and
obligations under the original agreement, including any obligation to pay
termination fees. The 1994 results of operations include exploration costs of
$2,481,000 and general and administrative expenses of $601,000 attributable to
the Argentina venture. Results of operations in 1995 from this venture were
insignificant.

12. COSTS OF OIL AND GAS PROPERTIES

The following table sets forth certain information with respect to costs
incurred in connection with the Company's oil and gas producing activities:

YEAR ENDED DECEMBER 31,
----------------------------
1996 1995 1994
-------- -------- --------
(IN THOUSANDS)
Property acquisitions:
Proved. . . . . . . . . . . $ 1,375 $ - $10,199
Unproved. . . . . . . . . . 5,002 2,254 2,325
Developmental costs . . . . . . 20,931 16,823 13,136
Exploratory costs . . . . . . . 6,306 1,407 5,699
-------- -------- --------
$33,614 $20,484 $31,359
-------- -------- --------
-------- -------- --------

The following table sets forth the capitalized costs for oil and gas
properties:

DECEMBER 31,
--------------------
1996 1995
--------- --------
(IN THOUSANDS)

Proved properties . . . . . . . . . . . . $ 349,752 $ 318,179
Unproved properties . . . . . . . . . . . 4,780 7,089
--------- ---------
Total capitalized costs . . . . . . . . . 354,532 325,268
Accumulated depreciation, depletion and
amortization. . . . . . . . . . . . . . (269,961) (246,034)
--------- ---------
Net capitalized costs . . . . . . . . $ 84,571 $ 79,234
--------- ---------
--------- ---------

F-15

13. OIL AND GAS RESERVE INFORMATION (UNAUDITED)

The estimates of proved oil and gas reserves utilized in the preparation
of the consolidated financial statements were prepared by independent
petroleum engineers. Such estimates are in accordance with guidelines
established by the Securities and Exchange Commission and the Financial
Accounting Standards Board, which require that reserve reports be prepared
under economic and operating conditions existing at the registrant's year end
with no provision for price and cost escalations except by contractual
arrangements. The Company's reserves are substantially located onshore in
the United States.

The Company emphasizes that reserve estimates are inherently imprecise.
Accordingly, the estimates are expected to change as more current information
becomes available. In addition, a portion of the Company's proved reserves
is undeveloped, which increases the imprecision inherent in estimating
reserves which may ultimately be produced.

The following table sets forth proved oil and gas reserves together with
the changes therein (oil in MBbls, gas in MMcf, gas converted to MBOE at one
MBbl per six MMcf):

DECEMBER 31,
---------------------------------------------------------------------------------
1996 1995 1994
------------------------- ------------------------- --------------------------
Oil Gas MBOE Oil Gas MBOE Oil Gas MBOE
------- ------- ------- ------- ------- -------- ------ ------- --------

Proved reserves
Beginning of period . . . . . . . 5,963 39,496 12,546 5,304 46,691 13,086 5,671 59,418 15,574
Revisions . . . . . . . . . . . . 457 (2,359) 64 98 (914) (54) (403) (11,565) (2,329)
Extensions and discoveries. . . . 4,077 113 4,096 2,392 564 2,486 1,321 676 1,433
Purchases of minerals-in-place. . 213 4,132 902 - - - 424 6,531 1,512
Production. . . . . . . . . . . . (2,203) (5,584) (3,134) (1,831) (6,845) (2,972) (1,709) (8,369) (3,104)
------- ------- ------- ------- ------- ------- ------- -------- -------
End of period . . . . . . . . . . 8,507 35,798 14,474 5,9633 9,496 12,546 5,304 46,691 13,086
------- ------- ------- ------- ------- ------- ------- -------- -------
------- ------- ------- ------- ------- ------- ------- -------- -------
Proved developed reserves
Beginning of period . . . . . . . 5,381 31,668 10,659 4,635 38,505 11,052 4,702 43,366 11,930
------- ------- ------- ------- ------- ------- ------- -------- -------
------- ------- ------- ------- ------- ------- ------- -------- -------
End of period . . . . . . . . . . 7,199 30,496 12,282 5,381 31,668 10,659 4,635 38,505 11,052
------- ------- ------- ------- ------- ------- ------- -------- -------
------- ------- ------- ------- ------- ------- ------- -------- -------

The standardized measure of discounted future net cash flows relating to
proved reserves was as follows:

DECEMBER 31,
-------------------------------
1996 1995 1994
-------- -------- --------
(IN THOUSANDS)

Future cash inflows . . . . . . $342,576 $191,191 $165,043
Future costs:
Production. . . . . . . . . (93,359) (55,626) (52,020)
Development . . . . . . . . (15,543) (9,295) (8,280)
Income taxes. . . . . . . . (50,508) (9,875) -
-------- -------- --------
Future net cash flows . . . . . 183,166 116,395 104,743
10% discount factor . . . . . . (47,453) (27,565) (30,533)
-------- -------- --------
Standardized measure of
discounted future net cash
flows. . . . . . . . . . . . . $135,713 $ 88,830 $ 74,210
-------- -------- --------
-------- -------- --------

F-16

CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Changes in the standardized measure of discounted future net cash flows
relating to proved reserves were as follows:
YEAR ENDED DECEMBER 31,
------------------------------
1996 1995 1994
-------- -------- --------
(IN THOUSANDS)

Standardized measure, beginning of period . . $ 88,830 $ 74,210 $ 89,897
Net changes in sales prices, net of
production costs . . . . . . . . . . . . . . 56,812 12,515 (9,926)
Revisions of quantity estimates . . . . . . . 811 (383) (12,917)
Accretion of discount . . . . . . . . . . . . 8,883 7,421 9,072
Changes in future development costs,
including development costs incurred
that reduced future development costs. . . . 5,713 3,777 10,415
Changes in timing and other . . . . . . . . . (887) (3,460) (2,196)
Net change in income taxes. . . . . . . . . . (24,957) - 819
Extensions and discoveries. . . . . . . . . . 38,703 25,100 9,479
Sales, net of production costs. . . . . . . . (45,834) (30,350) (30,842)
Purchases of minerals-in-place. . . . . . . . 7,639 - 10,409
-------- -------- --------
Standardized measure, end of period . . . . . $135,713 $ 88,830 $ 74,210
-------- -------- --------
-------- -------- --------

F-17

INDEX TO EXHIBITS

EXHIBIT SEQUENTIAL
NUMBER DESCRIPTION OF EXHIBIT PAGE NUMBER
- -------- -------------------------------------------------------- -----------
10.2 First Amendment to Fifth Restated Loan Agreement dated
December 31, 1996, among Clayton Williams Energy, Inc.,
Warrior Gas Co., CWEI Acquisitions, Inc., Bank One,
Texas, N.A., Banque Paribas and the First National Bank
of Chicago

10.14 Second Amendment to Outside Directors Stock Compensation
Plan

10.16 First Amendment to Executive Incentive Stock Compensation
Plan

21 Subsidiaries of the Registrant

23.1 Consent of Arthur Andersen LLP

23.2 Consent of Williamson Petroleum Consultants, Inc.

24.1 Power of Attorney

24.2 Certified copy of resolution of Board of Directors of
Clayton Williams Energy, Inc. authorizing signature
pursuant to Power of Attorney

27 Financial Data Schedules