EXHIBIT 99.1

CLAYTON WILLIAMS ENERGY, INC.

FINANCIAL GUIDANCE DISCLOSURES FOR 2003

Overview

Clayton Williams Energy, Inc. and its subsidiaries have prepared this document to provide public disclosure of certain financial and operating estimates in order to permit the preparation of models to forecast our operating results for each quarter during the year ending December 31, 2003.  These estimates are based on information available to us as of the date of this filing, and actual results may vary materially from these estimates.  We do not undertake any obligation to update these estimates as conditions change or as additional information becomes available.

The estimates provided in this document are based on assumptions that we believe are reasonable.  Until our results of operations for this period have been finally compiled and released, all of the estimates and assumptions set forth herein 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 document that address activities, events or developments that we expect, project, believe or anticipate will or may occur in the future, or may have occurred through the date of this filing, including such matters as production of oil and gas, product prices, oil and gas reserves, drilling and completion results, capital expenditures and other such matters, are forward-looking statements.  Such forward-looking statements involve known and unknown risks, uncertainties, and other factors that may cause our actual results, performance, or achievements to be materially different from the 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 unpredictable nature of our exploratory drilling results; the reliance upon estimates of proved reserves; operating hazards and uninsured risks; competition; government regulation; and other factors referenced in filings made by us with the Securities and Exchange Commission.

As a matter of policy, we do not attempt to predict:

(a)production which may be obtained through future exploratory drilling;

(b)dry hole and abandonment costs that may result from future exploratory drilling;

(c)the effects of Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities”;

(d)gains or losses from sales of property and equipment unless the sale has been consummated prior to the filing of financial guidance; and

(e)capital expenditures related to completion activities on exploratory wells or acquisitions of proved properties until the expenditures are estimable and likely to occur.

As discussed in “Capital Expenditures”, a significant portion of our 2003 planned exploration and development expenditures relate to exploratory prospects.  Exploratory prospects involve a higher degree of risk than development prospects.  To offset the higher risk, we generally strive to achieve a higher reserve potential and rate of return on investments in exploratory prospects.  Actual results from our exploratory drilling activities, when ultimately reported, may have a material impact on the estimates of oil and gas production and exploration costs stated in this guidance.

Summary of Estimates

The following table sets forth certain estimates being used by us to model our anticipated results of operations for each quarter during the fiscal year ending December 31, 2003.  When a single value is provided, such value represents the mid-point of the approximate range of estimates.  Otherwise, each range of values provided represents the expected low and high estimates for such financial or operating factor.

	Year Ending December 31, 2003
	Actual First Quarter			Estimated Second Quarter	Estimated Third Quarter	Estimated Fourth Quarter
	(Dollars in thousands, except per unit data)
Average Daily Production:
Gas (Mcf)	76,622			65,250 to 71,250	51,750 to 57,750	44,000 to 50,000
Oil (Bbls)	4,144			3,850 to 4,050	3,625 to 3,825	3,400 to 3,600
Natural gas liquids (Bbls)	544			450 to 550	430 to 530	400 to 500
Total gas equivalents (Mcfe)	104,750			91,050 to 98,850	76,080 to 83,880	66,800 to 74,600
Differentials:
Gas ($/Mcf)	$	(.36	)	$(.20) to $(.40)	$(.20) to $(.40)	$(.20) to $(.40)
Oil ($/Bbl)	$	(1.24	)	$(.75) to $(1.25)	$(.75) to $(1.25)	$(.75) to $(1.25)
Natural gas liquids ($/Bbl)	$	(9.06	)	$(8.00) to $(12.00)	$(8.00) to $(12.00)	$(8.00) to $(12.00)
Costs Variable by Production ($/Mcfe):
Lease operating expenses (including production taxes)	$	.80		$.75 to $1.00	$.85 to $1.10	$.90 to $1.20
DD&A – Oil and gas properties	$	1.08		$1.10 to $1.30	$1.10 to $1.30	$1.10 to $1.30
Other Revenues (Expenses):
Natural gas services:
Revenues	$	2,048		$1,450 to $1,550	$1,450 to $1,550	$1,450 to $1,550
Operating costs	$	(1,940	)	$(1,350) to $(1,450)	$(1,350) to $(1,450)	$(1,350) to $(1,450)
Exploration costs:
Abandonments and impairments	$	(4,462	)	$(500) to $(1,500)	$(500) to $(1,500)	$(500) to $(1,500)
Seismic and other	$	(2,352	)	$(1,600) to $(2,400)	$(1,600) to $(2,400)	$(1,600) to $(2,400)
DD&A – Other	$	(347	)	$(325) to $(375)	$(325) to $(375)	$(325) to $(375)
General and administrative	$	(1,740	)	$(2,100) to $(2,300)	$(2,100) to $(2,300)	$(2,300) to $(2,500)
Interest expense	$	(992	)	$(900) to $(1,000)	$(700) to $(800)	$(600) to $(700)
Income Tax Rate:
Current	1		%	1%	1%	1%
Deferred	34		%	34%	34%	34%
Weighted Average SharesOutstanding (in thousands):
Basic	9,303			9,300 to 9,400	9,300 to 9,400	9,300 to 9,400
Diluted	9,433			9,400 to 9,500	9,400 to 9,500	9,400 to 9,500

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Capital Expenditures

We presently plan to spend approximately $62.6 million on exploration and development activities during 2003, of which $15.9 million has been incurred through March 31, 2003.  The following table sets forth, by area, certain information about our planned exploration and development activities for 2003.

	Actual Expenditures Three Months Ended March 31, 2003		Total Planned Expenditures Year Ended December 31, 2003		Percentage of Total
	(In thousands)
South Louisiana	$	8,000	$	36,900	59	%
Cotton Valley Reef Complex	6,100		13,200		21	%
Mississippi	1,100		4,600		7	%
Other	700		7,900		13	%
	$	15,900	$	62,600	100	%

We have decided to accelerate the repayment of our bank debt by slowing the pace of our drilling activity. By reducing our level of bank debt, we will improve our debt-to-equity ratio and may preserve our capital resources for future exploration activities.  Since our last financial guidance in February 2003, we have reduced our estimates of planned expenditures for 2003 by a net of $11.1 million, consisting primarily of (i) reductions of $11.7 million in south Louisiana and $5 million in Mississippi, and (ii) additions of $3.9 million in the Cotton Valley Reef Complex area, as follows:

South Louisiana.  Since south Louisiana comprises the majority of our discretionary exploration drilling, we have reduced drilling in this area by $11.7 million. Even with this reduction, south Louisiana will still account for 59% of our planned exploration and development activities for 2003.

Mississippi.  Under the terms of an exploration agreement we signed with an industry participant in 2002, we paid $5.3 million to acquire 21,500 net acres in the Black Warrior Basin of Mississippi and obtained an option to pay an additional $5 million in 2003 to retain our interest in the acreage.  In March 2003, we amended the agreement to exchange a firm commitment to pay $3.8 million for the $5 million option payment.  For financial reporting purposes, we reported the firm commitment of $3.8 million as a liability at December 31, 2002 and reflected the cost as a capital expenditure in 2002.  Accordingly, we have reduced our 2003 estimates of capital expenditures by $5 million.

Cotton Valley Reef Complex.  We have increased our planned expenditures by $3.9 million in this area to provide for estimated completion costs on the Muse-Patranella Gas Unit #1 and costs to increase the capacity of the gas plant that processes most of our Cotton Valley Reef Complex gas production.

Approximately 80% of the actual and planned expenditures shown in the preceding table relate to exploratory prospects.  Exploratory prospects involve a higher degree of risk than developmental prospects.  To offset the higher risk, we generally strive to achieve a higher reserve potential and rate of return on investments in exploratory prospects.  You need to be aware that actual expenditures during 2003 may be substantially higher or lower than these estimates as our plans for exploration and development activities change during the year.  We do not attempt to forecast our success rate on exploratory drilling.  Accordingly, these current estimates do not include any costs we may incur to complete our successful exploratory wells and construct the required production facilities for these wells.  Also, we are actively searching for other opportunities to increase our oil and gas reserves, including the evaluation of new prospects for exploratory and developmental drilling activities and potential acquisitions of proved oil and

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gas reserves.  Other factors, such as prevailing product prices and the availability of capital resources, could also increase or decrease the ultimate level of expenditures during 2003.

Recent Drilling Activities

The following table summarizes certain information concerning our drilling activities from January 1, 2003 through the date of this report.  This information excludes immaterial drilling activities, such as wells drilled in non-core areas and small interests in non-operated properties.

Spud Date	Well Name	County or Parish	Approximate Depth	Current Status
Cotton Valley Reef Complex
Jan 2003	Muse-Patranella Gas Unit #1	Robertson, TX	17,000	Attempting completion
South Louisiana
March 2003	State Lease 17521 #1	Plaquemines, LA	2,000	Dry
March 2003	State Lease 17569 #1	Plaquemines, LA	12,500	Dry
April 2003	State Lease 3279 #1	Plaquemines, LA	13,400	In progress

Supplementary Information

Oil and Gas Production

The following table summarizes, by area, our estimated daily net production for each quarter during the year ending December 31, 2003.  These estimates represent the approximate mid-point of the estimated production range.

	Daily Net Production for 2003
	Actual First Quarter	Estimated Second Quarter	Estimated Third Quarter	Estimated Fourth Quarter
Gas (Mcf):
Austin Chalk (Trend)	4,210	3,417	2,914	2,449
Cotton Valley Reef Complex	51,400	45,970	35,595	29,911
Louisiana	17,488	14,969	13,166	11,828
New Mexico/West Texas	1,700	1,963	1,425	1,315
Other	1,824	1,931	1,650	1,497
	76,622	68,250	54,750	47,000
Oil (Bbls):
Austin Chalk (Trend)	2,817	2,663	2,494	2,359
Louisiana	621	573	508	463
New Mexico/West Texas	654	649	659	614
Other	52	65	64	64
	4,144	3,950	3,725	3,500
Natural Gas Liquids (Bbls):
Austin Chalk (Trend)	262	255	243	240
New Mexico/West Texas	136	184	177	150
Other	146	61	60	60
	544	500	480	450

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Accounting for Derivatives

The following summarizes information concerning our net positions in open commodity derivatives as of March 31, 2003.

	Oil Swaps			Gas Swaps
	Bbls	Average Price		MMBtu (a)	Average Price
Production Period:
2nd Quarter 2003	240,000	$	24.67	1,010,000	$	3.52
3rd Quarter 2003	120,000	$	24.20	1,810,000	$	3.58
4th Quarter 2003	80,000	$	24.20	1,720,000	$	3.80
Year 2003 (b)	440,000	$	24.46	4,540,000	$	3.65

(a)One MMBtu equals one Mcf at a Btu factor of 1,000.

(b)Based on current estimates, approximately 45% and 30% of our oil and gas production, respectively, for the remainder of 2003 is subject to commodity derivatives.

In addition, we have terminated our positions in certain other derivatives contracts at a net loss of $2.3 million, net of tax, that will be realized into earnings in the second quarter of 2003, as amounts are reclassified out of accumulated other comprehensive income.  In April 2003, we also terminated fixed-price gas contracts that will result in a $2.4 million loss to be recorded as other expense in the second quarter of 2003.

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