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, 1997

[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
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Commission File Number 0-20838
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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
incorporation or organization) Identification No.)

SIX DESTA DRIVE - SUITE 6500
MIDLAND, TEXAS 79705-5510
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(Address of principal executive offices) (Zip code)

Registrant's telephone number, including area code: (915) 682-6324

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
19, 1998, based on the closing price as quoted on the Nasdaq Stock Market's
National Market as of the close of business on said date, was $40,679,232.

There were 8,891,263 shares of Common Stock, $.10 par value, of the
registrant outstanding as of March 19, 1998.

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, 1998. 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 Section
27A of the Securities Act of 1933, as amended, and Section 21E of the
Securities Exchange Act of 1934, as amended. All statements, other than
statements of historical facts, included in this Form 10-K that address
activities, events or developments that Clayton Williams Energy, Inc. and its
subsidiaries (the "Company") expects, projects, believes or anticipates will
or may occur in the future, including such matters as oil and gas reserves,
future drilling and operations, future production of oil and gas, future net
cash flows, future capital expenditures and other such matters, are
forward-looking statements. Such forward-looking statements involve known and
unknown risks, uncertainties, and other factors which may cause the actual
results, performance, or achievements of 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." 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 has been one of the leaders in horizontal drilling in the
Trend. From January 1, 1990 through December 31, 1997, the Company drilled or
participated in 269 gross (218.7 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.

In 1997, the Company initiated several exploratory projects designed to
reduce its dependence on Trend drilling for future production and reserve
growth. These new areas include other formations in the vicinity of its core
properties in east central Texas, as well as south Texas, Louisiana and
Mississippi.

As of December 31, 1997, the Company had estimated proved reserves
totaling 8,410 MBbls of oil and 32.9 Bcf of gas with $99.9 million of
estimated future net revenues before income taxes (discounted at 10%). During
1997, the Company added 3,720 MBOE of estimated proved reserves through
extensions and discoveries, substantially all of which were derived from
Trend drilling activities. Reserve additions for 1997

were 99% of production for the same period, while production for 1997 was
approximately 20% higher on an MBOE basis than in 1996. The Company held
interests in 507 gross (373.7 net) oil and gas wells and owned leasehold
interests in approximately 359,079 gross (200,974 net) undeveloped acres at
December 31, 1997.

DRILLING AND EXPLORATION ACTIVITIES

Following is a discussion of the Company's significant drilling and
exploration activities during 1997, together with its plans for capital and
exploratory expenditures in 1998.

TREND DRILLING ACTIVITIES

The Company has assembled a 122,000 net acre lease block (the "North
Giddings Block") in the updip area of the Giddings Field in Burleson,
Robertson and Milam Counties, Texas where the Company has drilled 105 gross
(101.7 net) horizontal oil wells through December 31, 1997. In addition, the
Company has the right to earn acreage in this same area under two
continuous-drilling farm-in agreements covering approximately 52,000 net
acres, having drilled 5 gross (3.5 net) wells on this acreage in 1997.

The economic viability of the Company's Trend drilling activities is
highly dependent upon the price of oil expected to be realized during the
early years of a well's productive life due to high initial production rates
and steep decline rates which are characteristic of most Trend wells. Prior
to the recent deterioration in oil prices, the Company had planned to spend
approximately $18 million on Trend leasing and drilling activities in 1998,
as compared to $44.1 million in 1997. This reduction in planned expenditures
was attributable to a decrease in the number of Trend drilling locations that
could meet the Company's risk-adjusted economic parameters.

However, since oil prices are presently at their lowest levels in four
years, the Company plans to indefinitely suspend its Trend drilling
activities beginning in April 1998 pending an improvement in oil prices. The
suspension of Trend drilling activities for an extended period of time may
have a significant adverse effect on the Company's oil and gas production and
cash flows from operating activities in 1998 and future periods unless the
Company can offset the negative impact of such suspension through favorable
drilling results from its emerging exploration program or through
acquisitions of proved properties. See "MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS."

COTTON VALLEY EXPLORATORY PROJECT

During 1997, the Company completed a 3-D seismic survey covering
approximately 55,000 net acres in its North Giddings Block to explore for gas
reserves in the prolific Cotton Valley Pinnacle Reef play. As opposed to
Trend formations, which are encountered at depths of 5,500 to 7,000 feet in
this area, the Cotton Valley formation is encountered at depths of 15,000 to
16,000 feet. The Company has interpreted approximately one-third of the
survey and has identified 11 Cotton Valley Pinnacle Reef anomalies to date.
The northern edge of the North Giddings Block is approximately 24 miles
southwest of the nearest producing Cotton Valley Pinnacle Reef. Project
costs from inception of the project in 1996 through December 31, 1997 have
aggregated $4.6 million.

During 1998, the Company plans to spend approximately $9 million to
complete the interpretation of the seismic survey, extend and renew existing
leases as required, and drill an exploratory well to determine if the
identified reefs are gas-bearing. Drilling on an initial test well is
expected to begin in the second or third quarter of 1998. The Company has
revoked its previous policy of limiting expenditures on the Cotton Valley
Exploratory Project to 25% of its planned annual capital expenditures. This
policy change was necessitated by the Company's decision to suspend Trend
drilling activities in 1998 pending an improvement in oil prices. See "TREND
DRILLING ACTIVITIES."

OTHER EXPLORATION ACTIVITIES

Following is a discussion of other areas where the Company conducted
significant seismic, leasing and exploratory drilling activities in 1997,
together with its plans for 1998. During 1997, the Company spent an
aggregate of $3.7 million on seismic surveys and $10.1 million on leasing in
areas other than the Trend and the Cotton Valley Exploratory Project.
Presently, the Company plans to spend approximately $9 million in 1998 on
other exploration projects, substantially all of which are targeting gas
reserves due to currently depressed oil prices. However, the nature and
extent of exploration activities may change significantly during the year
depending upon several factors, including seismic interpretations, drilling
results, rig availability, product prices, and the availability of capital
resources.

GLEN ROSE
Beginning in 1997, the Company has assembled a 50,000 net acre lease block
in Grimes, Walker and Madison Counties, Texas and plans to drill a horizontal
exploratory well on this prospect in 1998. The Company believes that its
experience in horizontal drilling can be used to find and develop significant
gas reserves from the Glen Rose Limestone formation in this area. Depending
upon drilling results, the Company may drill one or more additional wells on
this prospect in 1998.

EAST TEXAS HORIZONTAL
The Company is presently evaluating an exploratory horizontal gas well in
the Haynesville Limestone formation in Freestone County, Texas. The
Company began drilling the well in January 1998, and completed drilling in
March 1998 after penetrating a total of 8,000 feet of the target formation
through two opposing laterals. Although initial indications are
disappointing, the Company has placed the well on production and may conduct
one or more stimulation procedures. In addition, the Company may attempt to
complete the well in shallower zones. If the well is ultimately determined
to be uneconomical, the Company will record a charge against earnings of
approximately $3.5 million in the period of such determination.

SOUTH TEXAS
During 1997, the Company completed a 3-D seismic survey covering
approximately 12,000 net acres in Duval County, Texas. During 1998, the
Company plans to drill an exploratory gas well to test one of the eight
Wilcox prospects generated by the survey. In addition, the Company initiated
a 3-D seismic survey in 1998 covering 3,150 net acres in Jim Hogg County,
Texas targeting the Queen City formation and may initiate a 3-D seismic
survey in Goliad County, Texas targeting the Wilcox formation.

LOUISIANA
During 1997, the Company drilled an exploratory well on its Mamou Prospect
in Evangeline Parish, Louisiana that was completed as a field discovery well
in the Upper Wilcox formation in March 1998. The Company plans to evaluate
geological and geophysical data on three other prospects generated in 1997
targeting the Sparta and Miocene formations to determine the nature and
extent of further exploration activities in these areas.

MISSISSIPPI
During 1997, the Company began a multi-pay exploration program targeting
hydrocarbons trapped by salt domes in Mississippi. The Company acquired
approximately 19,000 net acres based on 2-D seismic data, and conducted a 3-D
seismic survey on one of the salt domes. During 1998, the Company plans to
complete the leasing and seismic activities begun in 1997 and evaluate the
data to determine the nature and extent of further exploration activities in
Mississippi.

ACQUISITIONS OF PROVED PROPERTIES

Although no specified amounts of capital expenditures have been designated
for acquisitions of proven properties in 1998, the Company believes that the
purchase of long-lived oil and gas reserves would effectively compliment its
emerging exploration program. Therefore, the Company plans to actively seek
and evaluate acquisition opportunities during 1998.

PRINCIPAL PRODUCING AREAS

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, 1997, the Company had interests in 264 gross (201.1 net)
producing wells in the Giddings Field, including 192 horizontal and 72
vertical wells. For the year ended December 31, 1997, the Company's daily
net production in the Giddings Field averaged approximately 7,405 Bbls of oil
and 6,749 Mcf of gas. The Company drilled 35 wells in the Giddings Field
during 1997, 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'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 1997, 34 horizontal wells received an
initial treatment and 2 horizontal wells received a subsequent treatment.

JALMAT FIELD

The Company owns interests in 132 gross (106.7 net) operated wells in the
Jalmat Field, located in Lea County, New Mexico. For the year ended December
31, 1997, the Company's daily net production from this field averaged
approximately 101 Bbls of oil and 3,474 Mcf of gas.

TEXAS GULF COAST

The Company owns interests in 27 gross (10.8 net) non-operated wells in
Wharton and Matagorda Counties in the Gulf Coast region of Texas. The
Company's daily net production from this area during the year ended December
31, 1997 averaged approximately 83 Bbls of oil and 1,556 Mcf of gas.

MARKETING ARRANGEMENTS

The Company sells substantially all of its oil production under short-term
contracts based on prices quoted on the New York Mercantile Exchange
("NYMEX") for spot West Texas Intermediate ("WTI") contracts, less
agreed-upon deductions which vary by grade of crude oil. The majority of the
Company's gas production is sold under short-term contracts based on pricing
formulae which are generally market responsive.

The Company believes that the loss of any of its oil and gas purchasers
would not have a material adverse effect on its results of operations due to
the availability of other purchasers.

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 AND MARKETS

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.

The market for oil, gas and natural gas liquids produced by the Company
depends on factors beyond its 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.

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, which affect the
marketing of gas produced by the Company, as well as the revenues received by
the Company for sales of such production. Since the mid-1980s, the FERC has
issued a series of orders, culminating in Order Nos. 636, 636-A and 636-B
("Order 636"), that have significantly altered

the marketing and transportation of gas. Order 636 mandates a fundamental
restructuring of interstate pipeline sales and transportation services,
including the unbundling by interstate pipelines of the sales,
transportation, storage and other components of the city-gate sales services
such pipelines previously performed. One of the FERC's purposes in issuing
the orders is to increase competition within all phases of the gas industry.
Order 636 and subsequent FERC orders on rehearing have been appealed and are
pending judicial review. It is difficult to predict the ultimate impact of
the orders on the Company and its gas marketing efforts. Generally, Order 636
has eliminated or substantially reduced the interstate pipelines' traditional
role as wholesalers of natural gas, and has substantially increased
competition and volatility in natural gas markets. While significant
regulatory uncertainty remains, Order 636 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 associated penalties for violation of such
tolerances.

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. 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.

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, 1997, the Company had 109 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, 1997, the Company had interests in 507 gross (373.7 net) oil and gas
wells and owned leasehold interests in 359,079 gross (200,974 net)
undeveloped acres.

RESERVES

The following table sets forth certain information as of December 31, 1997
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)............................. 7,826 584 8,410
Gas (Mmcf).............................. 27,392 5,469 32,861
MBOE.................................... 12,392 1,495 13,887
PV-10 Value:
Before income taxes................... $94,831 $5,087 $99,918
After income taxes.................... $92,403

The following table sets forth certain information as of December 31, 1997
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................ 7,803 11,611 9,738 70.1% $73,687 73.7%
Jalmat............... 308 13,747 2,599 18.7 14,264 14.3
Texas Gulf Coast..... 165 4,521 919 6.6 9,688 9.7
Other................ 134 2,982 631 4.6 2,279 2.3
----- ------ ------ ----- ------- -----
Total.............. 8,410 32,861 13,887 100.0% $99,918 100.0%
----- ------ ------ ----- ------- -----
----- ------ ------ ----- ------- -----

The estimates as of December 31, 1997 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, 1997 for properties representing 84% 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, 1997, 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 decreased substantially from December 31, 1996 to December 31,
1997, resulting in significant decreases in the Company's estimated future
net revenues and, to a lesser extent, decreases 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, 1997 were $17.00 per Bbl of
oil and $2.33 per Mcf of gas, as compared to $25.01 per Bbl and $3.63 per Mcf
as of December 31, 1996. Subsequent to December 31, 1997, oil and gas prices
have continued to decline, and are expected to remain volatile. The Company
estimates that a $1 decline in the price per Bbl of oil would result in a
$5.9 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 $5.2 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 11% of the Company's total proved reserves at December 31,
1997 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, 1997 assumes, based on the Company's estimates,
that aggregate capital expenditures by the Company of approximately $6.8
million through 2000 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 3.7 years (based
upon the estimated quantities of proved oil and gas reserves as of December
31, 1997, divided by production volumes for 1997). The 1997 ratio is down
from 4.6 years at December 31, 1996 due to a combination of downward reserve
revisions caused primarily by lower product prices and higher than average
initial production rates on wells completed in 1997. Accordingly, the
Company believes that its future success will depend to a significant extent
upon the results of its emerging exploration program and, to a lesser extent,
acquisitions of proved properties. See "ITEM 7 - MANAGEMENT'S DISCUSSION AND
ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS."

Since January 1, 1997, 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,
------------------------------------------
1997 1996 1995
------------ ------------ ------------
GROSS NET GROSS NET GROSS NET
----- ---- ----- ---- ----- ----

DEVELOPMENT WELLS:
Oil..................... 33 28.0 23 20.9 24 21.0
Gas..................... 1 .2 - - 1 .5
Dry..................... - - - - - -
----- ---- ----- ---- ----- ----
Total................. 34 28.2 23 20.9 25 21.5
----- ---- ----- ---- ----- ----
----- ---- ----- ---- ----- ----

EXPLORATORY WELLS:
Oil..................... 8 7.5 4 4.0 2 2.0
Gas..................... - - - - - -
Dry..................... 5 1.9 2 .6 - -
----- ---- ----- ---- ----- ----
Total................. 13 9.4 6 4.6 2 2.0
----- ---- ----- ---- ----- ----
----- ---- ----- ---- ----- ----

TOTAL WELLS:
Oil..................... 41 35.5 27 24.9 26 23.0
Gas..................... 1 .2 - - 1 .5
Dry..................... 5 1.9 2 .6 - -
----- ---- ----- ---- ----- ----
Total................. 47 37.6 29 25.5 27 23.5
----- ---- ----- ---- ----- ----
----- ---- ----- ---- ----- ----

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 19, 1998, the Company had one drilling
rig under contract in the Trend.

PRODUCTIVE WELL SUMMARY

The following table sets forth certain information regarding the Company's
ownership as of December 31, 1997, of productive wells in the areas indicated.

OIL GAS TOTAL
------------- ------------- -------------
GROSS NET GROSS NET GROSS NET
----- ----- ----- ----- ----- -----

Trend..................... 289 223.6 23 16.1 312 239.7
Jalmat.................... 37 30.0 95 76.7 132 106.7
Texas Gulf Coast.......... 1 .4 26 10.4 27 10.8
Other..................... 19 12.9 17 3.6 36 16.5
----- ----- ----- ----- ----- -----
Total................... 346 266.9 161 106.8 507 373.7
----- ----- ----- ----- ----- -----
----- ----- ----- ----- ----- -----

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, 1997, the Company was the operator of 408 wells, or
approximately 80% of the 507 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 1997.

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,
--------------------------
1997 1996 1995
------ ------ ------

OIL AND GAS PRODUCTION DATA:
Oil (MBbls)............................ 2,903 2,203 1,831
Gas (MMcf)............................. 5,091 5,584 6,845
Total (MBOE)........................... 3,752 3,134 2,972

AVERAGE OIL AND GAS SALES PRICE (1):
Oil ($/Bbl)............................ $19.80 $20.85 $17.35
Gas ($/Mcf)(2)......................... $ 2.64 $ 2.65 $ 1.77

AVERAGE PRODUCTION COSTS
Lease operations ($/BOE)(3)............ $ 4.32 $ 4.71 $ 4.55

- ------------------
(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,
---------------------------
1997 1996 1995
------- ------- -------
(IN THOUSANDS)

Property Acquisitions:
Proved............................ $ - $ 1,375 $ -
Unproved.......................... 14,042 5,002 2,254
Developmental Costs................. 32,656 20,931 16,823
Exploratory Costs................... 13,813 6,306 1,407
------- ------- -------
Total............................. $60,511 $33,614 $20,484
------- ------- -------
------- ------- -------

ACREAGE

The following table sets forth certain information regarding the Company's
developed and undeveloped leasehold acreage as of December 31, 1997 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..................... 111,296 96,575 107,896 91,034 219,192 187,609
Jalmat.................... 9,481 8,023 - - 9,481 8,023
Texas Gulf Coast.......... 8,735 3,963 562 163 9,297 4,126
Other (a)................. 16,602 2,596 250,621 109,777 267,223 112,373
------- ------- ------- ------- ------- -------
Total................... 146,114 111,157 359,079 200,974 505,193 312,131
------- ------- ------- ------- ------- -------
------- ------- ------- ------- ------- -------

- -----------------------
(a) Net undeveloped acres are attributable to the following areas:
Glen Rose - 50,505; Mississippi - 18,771; Louisiana - 5,828;
Alabama - 13,596; Wyoming - 10,253; and other - 10,824.

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,
1997.

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 Stock Market's National
Market under the symbol "CWEI". As of December 31, 1997, there were
approximately 1,400 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 National Market:

High Low
--------- ---------

Year Ended December 31, 1997:
Fourth Quarter.................... $ 18 7/8 $ 12 1/2
Third Quarter..................... 17 1/4 9 7/8
Second Quarter.................... 15 3/4 10 1/2
First Quarter..................... 19 7/8 11 3/4

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

The quotations in the table above reflect inter-dealer prices without
retail markups, markdowns or commissions. On March 19, 1998, the last
reported sale price for the Common Stock on the National Market was $9 1/8.

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
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, 1997 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,
--------------------------------------------------
1997 1996 1995 1994 1993
------- ------- -------- -------- --------
STATEMENT OF OPERATIONS DATA: (IN THOUSANDS, EXCEPT PER SHARE DATA)

Revenues:
Oil and gas sales............................. $70,929 $60,610 $ 43,883 $ 43,617 $ 55,041
Natural gas services.......................... 4,559 4,281 5,388 5,868 4,554
------- ------- -------- -------- --------
Total revenues.............................. 75,488 64,891 49,271 49,485 59,595
------- ------- -------- -------- --------
Costs and expenses:
Lease operations.............................. 16,205 14,776 13,533 12,775 12,788
Exploration:
Abandonments and impairments................ 2,692 597 1,472 6,227 4,244
Seismic and other........................... 7,629 1,036 83 912 1,954
Natural gas services.......................... 3,955 3,437 3,714 3,510 2,518
Depreciation, depletion and amortization...... 31,273 23,758 25,110 25,248 26,751
Impairment of property and equipment (1)...... 236 1,186 10,259 - -
General and administrative.................... 4,181 3,266 3,708 5,659 6,876
------- ------- -------- -------- --------
Total costs and expenses.................... 66,171 48,056 57,879 54,331 55,131
------- ------- -------- -------- --------
Operating income (loss)..................... 9,317 16,835 (8,608) (4,846) 4,464
------- ------- -------- -------- --------
Other income (expense):
Interest expense.............................. (1,767) (3,440) (5,493) (4,461) (4,003)
Other income (expense) (2).................... 217 335 6,022 759 149
------- ------- -------- -------- --------
Total other income (expense)................ (1,550) (3,105) 529 (3,702) (3,854)
------- ------- -------- -------- --------
Income (loss) before income taxes............... 7,767 13,730 (8,079) (8,548) 610
Income tax expense (3).......................... - - - - 207
------- ------- -------- -------- --------
Net income (loss)............................... $ 7,767 $13,730 $ (8,079) $ (8,548) $ 403
------- ------- -------- -------- --------
------- ------- -------- -------- --------
Net income (loss) per common share:
Basic......................................... $ .87 $ 1.80 $ (1.31) $ (1.50) $ .09
------- ------- -------- -------- --------
------- ------- -------- -------- --------
Diluted....................................... $ .85 $ 1.76 $ (1.31) $ (1.50) $ .09
------- ------- -------- -------- --------
------- ------- -------- -------- --------
Weighted average common shares outstanding:
Basic......................................... 8,888 7,624 6,165 5,700 4,700
------- ------- -------- -------- --------
------- ------- -------- -------- --------
Diluted....................................... 9,094 7,800 6,165 5,700 4,700
------- ------- -------- -------- --------
------- ------- -------- -------- --------

OTHER DATA:
Net cash provided by operating activities....... $39,324 $40,306 $ 24,203 $ 23,672 $ 29,716
Discretionary cash flow (4):
Total......................................... $49,597 $40,307 $ 28,845 $ 23,839 $ 33,352
Per diluted common share...................... $ 5.45 $ 5.17 $ 4.68 $ 4.18 $ 7.10

DECEMBER 31,
------------------------------
1997 1996 1995
-------- -------- --------
(IN THOUSANDS)
BALANCE SHEET DATA:
Working capital (deficit).......................................... $ (6,369) $ (3,422) $(13,717)
Total assets....................................................... 134,562 103,598 93,161
Long-term debt..................................................... 35,700 18,000 33,538
Stockholders' equity............................................... 73,074 66,214 34,996

- ------------------

(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 two
principal gas gathering and processing systems.
(3) Prior to the Consolidation, income taxes were computed at the applicable
federal statutory rate.
(4) Discretionary cash flow refers to net income (loss) before exploration
costs, depreciation, depletion and amortization and impairments of property
and equipment.

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, 1997,
1996 and 1995, and results of operations and cash flows for each of the three
years in the period ended December 31, 1997. 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 has been required to maintain or increase its
level of drilling activity and achieve comparable or improved results from
such activities.

Beginning in 1997, the Company initiated several exploratory projects
designed to reduce its dependence on Trend drilling for future production and
reserve growth. These new areas include other formations in the vicinity of
its core properties in east central Texas, as well as south Texas, Louisiana
and Mississippi. During 1998, the Company plans to devote a substantial
portion of its capital expenditures to these new areas and also intends to
actively seek and evaluate opportunities to acquire proven properties. See
"LIQUIDITY AND CAPITAL RESOURCES - CAPITAL EXPENDITURES."

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,
---------------------------
1997 1996 1995
---- ---- ----

OIL AND GAS PRODUCTION DATA:
Oil (MBbls).................................. 2,903 2,203 1,831
Gas (MMcf)................................... 5,091 5,584 6,845
Total (MBOE) (1)............................. 3,752 3,134 2,972

AVERAGE OIL AND GAS SALES PRICES (2):
Oil ($/Bbl).................................. $19.80 $20.85 $17.35
Gas ($/Mcf).................................. $ 2.64 $ 2.65 $1.77

OPERATING COSTS AND EXPENSES ($/BOE PRODUCED):
Lease operations............................. $ 4.32 $ 4.71 $ 4.55
Oil and gas depletion........................ $ 8.10 $ 7.32 $ 8.16
General and administrative................... $ 1.11 $ 1.04 $ 1.25

NET WELLS DRILLED:
Horizontal Wells............................. 33.3 24.4 23.5
Vertical Wells............................... 4.3 1.1 -

(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.

1997 COMPARED TO 1996

REVENUES

Oil and gas sales increased 17% from $60.6 million in 1996 to $70.9
million in 1997 due primarily to a 32% increase in oil production. The
effect of higher oil production was partially offset by a 5% decrease in oil
prices and a 9% decline in gas production. Production from wells completed
subsequent to December 31, 1996 accounted for approximately 42% of total oil
production for the 1997 period, which more than offset the effects of steep
production declines from previously existing Trend wells. The Company plans
to discontinue Trend drilling in April 1998 pending an improvement in oil
prices, which have fallen to their lowest levels in four years. The
suspension of Trend drilling activities for an extended period of time may
adversely affect the Company's production and revenues in 1998.

COSTS AND EXPENSES

Lease operations expenses increased 9% from $14.8 million in 1996 to $16.2
million in 1997 while oil and gas production on a BOE basis increased 20%,
resulting in a decrease in lease operations expenses on a BOE basis from
$4.71 per BOE in 1996 to $4.32 per BOE in 1997. Higher initial rates of
production on several of the wells completed during 1997 contributed
materially to the decline in lease operations expenses per BOE.

Exploration costs increased from $1.6 million in 1996 to $10.3 million in
1997 due primarily to costs incurred during 1997 in connection with
exploration projects initiated during the fourth quarter of 1996. The
Company plans to spend approximately $17 million in 1998 on exploratory
prospects. 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 seismic costs, exploratory dry hole
costs, and unproved property impairments are expensed.

Depreciation, depletion and amortization ("DD&A") expense increased 32%
from $23.8 million in 1996 to $31.3 million in 1997 due primarily to a 20%
increase in oil and gas production on a BOE basis, combined with an 11%
increase in the Company's average depletion rate 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 average depletion rate per BOE was $8.10 in the 1997 period compared to
$7.32 in the 1996 period.

General and administrative ("G&A") expenses increased 27% from $3.3
million in 1996 to $4.2 million in 1997 due primarily to increased personnel
costs. In response to an increase in demand for skilled technical and
mangerial personnel in the oil and gas industry and an increase in the
Company's level of exploration and development activities, the Company has
hired additional personnel and increased salaries of existing personnel.

INTEREST EXPENSE

Interest expense decreased 47% from $3.4 million in 1996 to $1.8 million
in 1997 due primarily to lower average levels of indebtedness on the
Company's secured credit facility (the "Credit Facility") and, to a much
lesser extent, lower average interest rates. The average daily principal
balance outstanding on such facility during the 1997 period was $24 million
compared to $36.9 million in 1996. The effective annual interest rate on
bank debt, including bank fees, during the 1997 period was 8.7% compared to
9.4% in 1996

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.

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.

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 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.

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 1998, and the expected capital resources needed to
finance such plans.

CAPITAL EXPENDITURES

In April 1998, the Company plans to indefinitely suspend its Trend
drilling activities pending an improvement in oil prices, which have fallen
to their lowest levels in four years. Through the first quarter of 1998, the
Company will have spent approximately $3.5 million on Trend leasing and
drilling activities, and, depending on the duration of the suspension, may
spend up to $18 million in the Trend during 1998.

During 1998, the Company plans to spend approximately $9 million on the
Cotton Valley Exploratory Project to complete the interpretation of its 3-D
seismic survey, extend and renew existing leases as required, and drill an
exploratory well on one of the Cotton Valley Pinnacle Reef prospects
generated by such survey. In addition, the Company plans to spend $9 million
in 1998 on other exploration projects in south Texas, Louisiana and
Mississippi. The incurrence of such costs may adversely affect the Company's
results of operations in 1998 (see "RESULTS OF OPERATIONS - 1997 COMPARED TO
1996 - COSTS AND EXPENSES").

Substantially all of the planned 1998 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 does not have any specified amounts of capital expenditures
designated for acquisitions of proven properties in 1998. 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 that portion of the borrowing base determined by the Company to be the
elected borrowing limit. At December 31, 1997, the elected borrowing limit
was $50 million, and the available credit on the revolving facility was $14.3
million. The borrowing base is scheduled for redetermination in May 1998, 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 finance its 1998 planned capital expenditure program.

WORKING CAPITAL AND CASH FLOW

During 1997, the Company generated cash flow from operating activities of
$39.3 million and borrowed $17.7 million on the Credit Facility. During the
same period, the Company spent $56.2 million on capital expenditures and $1.5
million to acquire shares of its common stock for treasury.

The Company's working capital deficit increased from $3.4 million at
December 31, 1996 to $6.4 million at December 31, 1997 due primarily to a net
increase in current liabilities attributable to increased levels of drilling,
leasing and exploration activities. The Company applies most of its
available cash toward the repayment of the Credit Facility. Since all
outstanding indebtedness on the Credit Facility is classified as a noncurrent
liability, the timing of receipts and disbursements can cause reported
working capital to fluctuate as it did from December 31, 1996 to December 31,
1997. However, working capital will increase as funds are advanced on the
Credit Facility to finance the Company's capital expenditure program.

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 1998.
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 Company's
exploration program, 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 1998.

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.

The Company has entered into swap arrangements for 1,780,000 barrels of
oil production for the period from January 1998 through December 1998 at an
average price of $19.61. In addition, the Company has hedged 570,000 MMBtu
of its gas production from January 1998 through March 1998 under collar
arrangements with average floor prices of $2.92 and average ceiling prices of
$3.26, and has hedged 1,140,000 MMBtu from April 1998 through September 1998
at an average price of $2.08.

YEAR 2000 COMPLIANCE

The Company has developed a plan to ensure its systems are compliant with
the requirements to process transactions in the year 2000 and beyond. The
costs associated with final compliance are expected to be minimal.

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, 1997.

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, 1997.

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, 1997.

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, 1997.

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,
1997.

EXHIBITS

EXHIBIT
NUMBER 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, filed as an exhibit to the December
31, 1996 Form 10-K

**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

*10.9 First Amendment to Bonus Incentive Plan

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

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

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

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

**10.14 First Amendment to Executive Incentive Stock Compensation Plan,
filed as an exhibit to the December 31, 1996 Form 10-K

**10.15 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

**10.16 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

**10.17 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, filed as an exhibit to the December
31, 1996 Form 10-K

*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

*27.1 Financial Data Schedules for the year ended December 31, 1997

*27.2 Restated Financial Data Schedules for the years ended December 31,
1995 and 1996, and the quarters ended March 31, 1996, June 30, 1996
and September 30, 1996

*27.3 Restated Financial Data Schedules for the quarters ended March 31,
1996, June 30, 1996 and September 30, 1996

- -------------------

* 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 20, 1998
- -------------------------------- President and Chief Executive
Clayton W. Williams, Jr. Officer and Director

/s/ L. PAUL LATHAM Executive Vice President, March 20, 1998
- -------------------------------- Chief Operating Officer and
L. Paul Latham Director

/s/ MEL G. RIGGS * Senior Vice President - March 20, 1998
- -------------------------------- Finance, Secretary, Treasurer,
Mel G. Riggs Chief Financial Officer and Director

/s/ STANLEY S. BEARD * Director March 20, 1998
- --------------------------------
Stanley S. Beard

/s/ WILLIAM P. CLEMENTS, JR. * Director March 20, 1998
- --------------------------------
William P. Clements, Jr.

/s/ ROBERT L. PARKER * Director March 20, 1998
- --------------------------------
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, 1997 and 1996, and the related
consolidated statements of operations, stockholders' equity and cash flows
for each of the three years in the period ended December 31, 1997. 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, 1997 and 1996, and the results of its operations and
cash flows for each of the three years in the period ended December 31, 1997,
in conformity with generally accepted accounting principles.

As discussed in Note 9, 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
February 27, 1998

F-2

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

ASSETS

DECEMBER 31,
---------------------
1997 1996
-------- --------

CURRENT ASSETS
Cash and cash equivalents............................ $ 2,150 $ 2,479
Accounts receivable:
Trade, net.......................................... 4,197 1,876
Affiliates.......................................... 173 92
Oil and gas sales................................... 9,126 10,440
Inventory............................................ 2,530 518
Other................................................ 1,243 557
-------- --------
19,419 15,962
-------- --------
PROPERTY AND EQUIPMENT
Oil and gas properties, successful efforts method.... 412,352 354,532
Natural gas gathering and processing systems......... 7,869 7,655
Other 10,411 9,547
-------- --------
430,632 371,734
Less accumulated depreciation, depletion and
amortization....................................... (315,559) (284,173)
-------- --------
Property and equipment, net...................... 115,073 87,561
-------- --------
OTHER ASSETS.......................................... 70 75
-------- --------
$134,562 $103,598
-------- --------
-------- --------

LIABILITIES AND STOCKHOLDERS' EQUITY

CURRENT LIABILITIES
Accounts payable:
Trade............................................... $ 16,480 $ 10,233
Affiliates.......................................... 603 615
Oil and gas sales................................... 7,679 7,454
Current maturities of long-term debt................. 42 112
Accrued liabilities and other........................ 984 970
-------- --------
25,788 19,384
-------- --------
LONG-TERM DEBT........................................ 35,700 18,000
-------- --------
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 -
8,980,539 shares in 1997 and 8,927,658 shares
in 1996............................................. 898 893
Additional paid-in capital........................... 70,856 70,248
Retained earnings (deficit).......................... 2,840 (4,927)
-------- --------
74,594 66,214
Less treasury stock, at cost (95,000 shares in 1997) (1,520) -
-------- --------
73,074 66,214
-------- --------
$134,562 $103,598
-------- --------
-------- --------

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,
-------------------------------
1997 1996 1995
-------- ------- ------

REVENUES
Oil and gas sales.......................... $70,929 $60,610 $43,883
Natural gas services....................... 4,559 4,281 5,388
------- ------- -------
Total revenues............................ 75,488 64,891 49,271
------- ------- -------

COSTS AND EXPENSES
Lease operations........................... 16,205 14,776 13,533
Exploration:
Abandonments and impairments.............. 2,692 597 1,472
Seismic and other......................... 7,629 1,036 83
Natural gas services....................... 3,955 3,437 3,714
Depreciation, depletion and amortization... 31,273 23,758 25,110
Impairment of property and equipment....... 236 1,186 10,259
General and administrative................. 4,181 3,266 3,708
------- ------- -------
Total costs and expenses.................. 66,171 48,056 57,879
------- ------- -------
Operating income (loss)................... 9,317 16,835 (8,608)
------- ------- -------
OTHER INCOME (EXPENSE)
Interest expense........................... (1,767) (3,440) (5,493)
Other...................................... 217 335 6,022
------- ------- -------
Total other income (expense).............. (1,550) (3,105) 529
------- ------- -------
INCOME (LOSS) BEFORE INCOME TAXES........... 7,767 13,730 (8,079)
------- ------- -------
INCOME TAX EXPENSE
Current.................................... - - -
Deferred................................... - - -
------- ------- -------
Total income tax expense.................. - - -
------- ------- -------
NET INCOME (LOSS)........................... $ 7,767 $13,730 $(8,079)
------- ------- -------
------- ------- -------
Net income (loss) per common share:
Basic...................................... $ .87 $ 1.80 $(1.31)
------- ------- -------
------- ------- -------
Diluted.................................... $ .85 $ 1.76 $(1.31)
------- ------- -------
------- ------- -------

Weighted average common shares outstanding:
Basic...................................... 8,888 7,624 6,165
------- ------- -------
------- ------- -------
Diluted.................................... 9,094 7,800 6,165
------- ------- -------
------- ------- -------

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 RETAINED
NO. OF PAR PAID-IN EARNINGS TREASURY
SHARES VALUE CAPITAL (DEFICIT) STOCK TOTAL
------ ----- ------- --------- ----- -----

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

Repurchase of common stock
for treasury.................. - - - - (1,520) (1,520)
Issuance of stock through
compensation plans............ 53 5 608 - - 613
Net income...................... - - - 7,767 - 7,767
----- ---- ------- ------- ------- -------
BALANCE,
December 31, 1997.................. 8,981 $898 $70,856 $ 2,840 $(1,520) $73,074
----- ---- ------- ------- ------- -------
----- ---- ------- ------- ------- -------

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,
-----------------------------------
1997 1996 1995
------- -------- --------

CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss).................................... $7,767 $ 13,730 $ (8,079)
Adjustments to reconcile net income (loss) to cash
provided by operating activities:
Depreciation, depletion and amortization............ 31,273 23,758 25,110
Impairment of property and equipment................ 236 1,186 10,259
Exploration costs................................... 2,692 597 1,472
Gain on sales of property and equipment............. (155) (293) (5,978)
Other............................................... 582 445 341
Changes in operating working capital:
Accounts receivable................................. (1,088) (3,871) 121
Accounts payable.................................... 766 4,824 737
Other............................................... (2,749) (70) 220
------- -------- --------
Net cash provided by operating activities.......... 39,324 40,306 24,203
------- -------- --------

CASH FLOWS FROM INVESTING ACTIVITIES
Additions to property and equipment.................. (56,167) (33,100) (20,433)
Proceeds from sales of property and equipment........ 303 3,862 7,950
------- -------- --------
Net cash used in investing activities.............. (55,864) (29,238) (12,483)
------- -------- --------

CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt......................... 17,700 - -
Repayments of long-term debt......................... - (26,935) (15,656)
Repurchase of common stock for treasury.............. (1,520) - -
Proceeds from sale of common stock................... 31 17,043 3,808
------- -------- --------
Net cash provided by (used in) financing
activities........................................ 16,211 (9,892) (11,848)
------- -------- --------

NET INCREASE (DECREASE) IN CASH AND
CASH EQUIVALENTS..................................... (329) 1,176 (128)
CASH AND CASH EQUIVALENTS
Beginning of period.................................. 2,479 1,303 1,431
------- -------- --------
End of period........................................ $ 2,150 $ 2,479 $ 1,303
------- -------- --------
------- -------- --------

SUPPLEMENTAL DISCLOSURES
Cash paid for interest, net of amounts
capitalized........................................ $ 1,668 $ 3,434 $ 5,613
------- ------- --------
------- ------- --------

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 reportin g 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 individually 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 equipment and
facilities, office equipment, leasehold improvements and vehicles. Major
renewals and betterments are

F-7

CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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, 1997, 1996 and 1995, the Company capitalized interest
totaling approximately $346,000, $68,000 and $85,000, 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
The Company computes net income (loss) per common share in accordance
with Statement of Financial Accounting Standards No. 128 "Earnings Per
Share" ("SFAS 128"). Basic net income (loss) per common share is based on
the weighted average number of common shares outstanding during each
period. Diluted net income (loss) per share gives further effect to the
additional dilution, if any, related to outstanding employee stock
options.

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

F-8

CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (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 did not have any significant imbalance positions at December
31, 1997, 1996 or 1995.

3. LONG-TERM DEBT

Long-term debt consists of the following:

DECEMBER 31,
------------------
1997 1996
------- -------
(IN THOUSANDS)

Secured Bank Credit Facility (matures July 31, 1999)... $35,700 $18,000
Other.................................................. 42 112
------- -------
35,742 18,112
Less current maturities................................ 42 112
------- -------
$35,700 $18,000
------- -------
------- -------

Aggregate maturities of long-term debt at December 31, 1997 are as
follows: 1998 - $42,000; and 1999 - $35,700,000.

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 that portion of the borrowing base
determined by the Company to be the elected borrowing limit. At December
31, 1997, the elected borrowing limit was $50 million, and the available
credit on the revolving facility was $14.3 million. The borrowing base is
scheduled to be redetermined in May 1998 and at least semi-annually
thereafter; however, either 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 loan 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, 1997, all of the Company's indebtedness under the Credit
Facility consisted of $5.7 million of Base Rate Loans at a rate of 8.8%
and $30 million of Eurodollar Loans at a rate of 7.5%.

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 31, 1999.

The loan agreement requires the Company to maintain financial ratios
covering working capital, cash flow and net tangible assets. The Company
was in compliance with all covenants at December 31, 1997.

F-9

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

In January 1997, the Company's Board of Directors authorized the
Company to spend up to $2 million in 1997 to repurchase shares of its
common stock on the open market. As of December 31, 1997, the Company had
purchased 95,000 shares at a cost of $1,520,000.

5. EARNINGS PER SHARE

In 1997, the Company adopted SFAS 128, which changes the method of
computing and disclosing earnings per share for periods ending after
December 15, 1997. In accordance with SFAS 128, basic earnings per common
share was computed by dividing net income (loss) by the weighted average
number of shares of common stock outstanding during the period. Diluted
earnings per common share was computed by including the dilutive effect,
if any, of outstanding employee stock options utilizing the treasury stock
method. All prior periods have been restated to give effect to the
adoption of SFAS 128, the impact of which was immaterial. For all periods
presented, the differences between basic shares and diluted shares were
attributable to the dilutive effect of employee stock options.

6. 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, 1997
expire 10 years from the date of grant and become exercisable based on
varying vesting schedules.

F-10

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

The following table reflects activity in the 1993 Plan for 1997, 1996
and 1995.

1997 1996 1995
---------------------- ----------------------- -------------------------
WEIGHTED WEIGHTED WEIGHTED
AVERAGE AVERAGE AVERAGE
SHARES PRICE SHARES PRICE SHARES PRICE
------- --------- ------- -------- -------- --------

Beginning of year......... 458,766 $8.46 151,601 $2.45 149,101 $7.25
Granted (a).............. 210,700 $15.36 321,500 $11.03 149,101 $2.38
Exercised................ (12,791) $2.53 (10,410) $2.38 - -
Forfeited................ (24,406) $5.53 (3,925) $2.82 (18,540) $7.25
Cancelled (b)............ - - - - (128,061) $7.25
------- ------- -------
End of year............... 632,269 $10.99 458,766 $8.46 151,601 $2.45
------- ------- -------
------- ------- -------

Exercisable............... 194,357 $6.00 104,449 $2.47 75,800 $2.45
------- ------- -------
------- ------- -------
Issuable.................. 265,931 439,434 146,599(c)
------- ------- -------
------- ------- -------

- -------------------
(a) In addition to the reissuances described in note (b), the
Company granted new options as follows: 1997 - 48,700 shares at
$14.00 per share, 12,000 shares at $14.44 per share, and 150,000
shares at $15.88 per share; 1996 - 121,500 shares at $3.25 per
share and 200,000 shares at $15.75 per share; and 1995 - 21,040
shares at $2.38 per share.
(b) In 1995, the Company exchanged options to purchase 128,061
shares granted in 1994 at an option price of $7.25 per share for
an equal number of options at an option price of $2.38 per share.
(c) At December 31, 1995, the Company had 298,200 shares reserved for
issuance under the 1993 Plan.

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
15,000 shares of common stock (3,000 per year from 1993 through 1997) at
option prices ranging from $3.25 to $18.50 per share. All options expire
10 years from the date of grant and are fully exercisable upon issuance.
At December 31, 1997, options to purchase 15,000 shares were outstanding,
and 71,300 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. In November 1997, cash awards totaling
$31,500 and stock awards totaling 9,310 shares of common stock at a market
price of $16.00 per share were granted to certain employees and officers.
At December 31, 1997, 106,190 shares remain available for issuance 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
1997 and 1996, the Company issued Mr. Williams 30,808 and 67,785 shares,
respectively, of common stock in lieu of cash compensation aggregating
$421,000 and $384,000, respectively, and issued 690 and 11,581 shares,
respectively, to three outside directors in lieu of cash compensation
aggregating $12,000 and $61,000, respectively. The amounts of such
compensation are included in general and administrative expense in the
accompanying consolidated financial statements. The Company terminated
the outside directors stock compensation plan in January 1997.

F-11

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

SUPPLEMENTAL DISCLOSURE

In October 1995, the Financial Accounting Standards Board issued
Statement of Financial Accounting Standards No. 123 "Accounting for
Stock-Based Compensation" ("SFAS 123"). 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:

1997 1996 1995
------ ------- --------
(IN THOUSANDS, EXCEPT PER SHARE)

Net income (loss):
As reported......................... $7,767 $13,730 $(8,079)
Pro forma........................... $7,175 $13,558 $(8,170)

Net income (loss) per share:
Basic:
As reported........................ $ .87 $1.80 $(1.31)
Pro forma.......................... $ .81 $1.78 $(1.33)

Diluted:
As reported........................ $.85 $1.76 $(1.31)
Pro forma.......................... $.79 $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 transferable and 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 1997, 1996 and 1995, respectively: risk-free interest rates of
6.1%, 5.8% and 5.8%; dividend yields of 0%; volatility factors of the
expected market price of the Company's common stock of .575, .561 and .411;
and a life expectancy of each option of 7, 5.1 and 4.8 years.

7. 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 $684,000, $615,000 and $772,000 for the years ended December 31,
1997, 1996 and 1995, respectively, and include charges to the Company by
affiliates for rents and services aggregating $200,000, $235,000 and $289,000
for the years ended December 31, 1997, 1996 and 1995, 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

F-12

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

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.

8. 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 $337,000, $398,000 and $453,000 for the years ended December 31,
1997, 1996 and 1995, respectively. Included in property and equipment are
assets under capital leases aggregating $33,000, $133,000 and $233,000 net of
accumulated depreciation, at December 31, 1997, 1996 and 1995, respectively.

Future minimum payments under noncancelable leases at December 31,
1997, are as follows:

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

1998.............................................. $43 $ 506
1999.............................................. - 407
2000.............................................. - 349
Thereafter........................................ - 369
--- ------
Total minimum lease payments..................... 43 $1,631
------
------
Less amount representing interest................. (1)
---
Present value of net minimum lease payments...... $42
---
---

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.

HEDGING ACTIVITIES
From time to time, the Company utilizes forward sale and other
financial option arrangements, such as swaps and collars, to reduce price
risks on the sale of its oil and gas production. The Company accounts for
such arrangements as hedging activities and, accordingly, records all
realized gains and losses as oil and gas revenues in the period the hedged
production is sold. Included in oil and gas revenues are gains totaling
$252,000 in 1997, net losses totaling $1,156,000 in 1996 (comprised of
losses of $1,299,000 partially offset by gains of $143,000), and $342,000
in 1995 (comprised of losses of $426,000 partially offset by gains of
$84,000). As of December 31, 1997, the Company had entered into swap
arrangements for 1,780,000 barrels of oil production for the period from
January 1998 through December 1998 at an average price of $19.61. In
addition, the Company has hedged 570,000 MMBtu of its gas production from
January 1998 through March 1998 under collar arrangements with average
floor prices of $2.92 and average ceiling prices

F-13

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

of $3.26, and has hedged 1,140,000 MMBtu from April 1998 through September
1998 at an average price of $2.08.

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.

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

9. 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.

During 1997, the Company recorded an additional provision for impairment
under SFAS 121 of $236,000 attributable to certain minor-value properties.

10. SALES OF ASSETS

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 $6.0 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.

11. INCOME TAXES

Since the Consolidation discussed in Note 1, the Company has incurred net
income for financial reporting purposes aggregating $2.8 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

F-14

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

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, 1997, 1996 and 1995.

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

DECEMBER 31,
----------------------------------
1997 1996 1995
-------- -------- -------
(IN THOUSANDS)

Deferred tax assets (liabilities):
Depreciable and depletable property.... $(12,828) $(10,216) $(4,030)
Tax loss carryforwards................. 12,584 12,737 11,305
Other.................................. 936 929 912
Valuation allowance.................... (692) (3,450) (8,187)
-------- -------- -------
Net deferred tax asset (liability)... $ - $ - $ -
-------- -------- -------
-------- -------- -------

The reductions in the valuation allowances reported above are based on
improvements in financial results of the Company since 1995. All of the
differences between the statutory income tax rates and the effective income
tax rates are attributable to the change in the valuation allowance.

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,
-----------------------------------
1997 1996 1995
------- ------- -------
(IN THOUSANDS)

Property acquisitions:
Proved............................. $ - $ 1,375 $ -
Unproved........................... 14,042 5,002 2,254
Developmental costs................ 32,656 20,931 16,823
Exploratory costs.................. 13,813 6,306 1,407
------- ------- -------
Total........................... $60,511 $33,614 $20,484
------- ------- -------
------- ------- -------

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

DECEMBER 31,
-------------------------
1997 1996
--------- ---------
(IN THOUSANDS)

Proved properties.......................... $ 393,672 $ 349,752
Unproved properties........................ 18,680 4,780
--------- ---------
Total capitalized costs.................... 412,352 354,532
Accumulated depreciation, depletion and
amortization............................... (300,569) (269,961)
--------- ---------
Net capitalized costs..................... $ 111,783 $ 84,571
--------- ---------
--------- ---------

F-15

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

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):

YEAR ENDED DECEMBER 31,
-------------------------------------------------------------------------------------
1997 1996 1995
------------------------- ------------------------- --------------------------
Oil Gas MBOE Oil Gas MBOE Oil Gas MBOE
----- ------ ------ ----- ------ ------ ------ ------ ------

Proved reserves
Beginning of period 8,507 35,798 14,474 5,963 39,496 12,546 5,304 46,691 13,086
Revisions (726) 1,020 (556) 457 (2,359) 64 98 (914) (54)
Extensions and discoveries 3,532 1,134 3,721 4,077 113 4,096 2,392 564 2,486
Purchases of minerals-in-place - - - 213 4,132 902 - - -
Production (2,903) (5,091) (3,752) (2,203) (5,584) (3,134) (1,831) (6,845) (2,972)
----- ------ ------ ----- ------ ------ ------ ------ ------
End of period 8,410 32,861 13,887 8,507 35,798 14,474 5,963 39,496 12,546
----- ------ ------ ----- ------ ------ ------ ------ ------
----- ------ ------ ----- ------ ------ ------ ------ ------
Proved developed reserves
Beginning of period 7,199 30,496 12,282 5,381 31,668 10,659 4,635 38,505 11,052
----- ------ ------ ----- ------ ------ ------ ------ ------
----- ------ ------ ----- ------ ------ ------ ------ ------
End of period 7,826 27,392 12,392 7,199 30,496 12,282 5,381 31,668 10,659
----- ------ ------ ----- ------ ------ ------ ------ ------
----- ------ ------ ----- ------ ------ ------ ------ ------

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

DECEMBER 31,
--------------------------------------
1997 1996 1995
-------- -------- --------
(IN THOUSANDS)

Future cash inflows $219,528 $342,576 $191,191
Future costs:
Production (67,207) (93,359) (55,626)
Development (13,445) (15,543) (9,295)
Income taxes (10,445) (50,508) (9,875)
-------- -------- --------
Future net cash flows 128,431 183,166 116,395
10% discount factor (36,028) (47,453) (27,565)
-------- -------- --------
Standardized measure of discounted future net
cash flows $ 92,403 $135,713 $ 88,830
-------- -------- --------
-------- -------- --------

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,
--------------------------------------
1997 1996 1995
-------- -------- --------
(IN THOUSANDS)

Standardized measure, beginning of period $135,713 $ 88,830 $ 74,210
Net changes in sales prices, net of production
costs (49,024) 56,812 12,515
Revisions of quantity estimates (4,376) 811 (383)
Accretion of discount 16,067 8,883 7,421
Changes in future development costs, including
development costs incurred that reduced future
development costs 8,622 5,713 3,777
Changes in timing and other (874) (887) (3,460)
Net change in income taxes 17,442 (24,957) -
Extensions and discoveries 23,557 38,703 25,100
Sales, net of production costs (54,724) (45,834) (30,350)
Purchases of minerals-in-place - 7,639 -
-------- -------- --------
Standardized measure, end of period $ 92,403 $135,713 $ 88,830
-------- -------- --------
-------- -------- --------

F-17

INDEX TO EXHIBITS

EXHIBIT
NUMBER DESCRIPTION OF EXHIBIT
- ------- ------------------------------------------------------------------
10.9 First Amendment to Bonus Incentive Plan

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

27.1 Financial Data Schedules for the year ended December 31, 1997

27.2 Restated Financial Data Schedules for the years ended December 31,
1995 and 1996, and the quarters ended March 31, 1996, June 30,
1996 and September 30, 1996

27.3 Restated Financial Data Schedules for the quarters ended March 31,
1997, June 30, 1997 and September 30, 1997