EXHIBIT 99.1

CLAYTON WILLIAMS ENERGY, INC.

FINANCIAL GUIDANCE DISCLOSURES FOR 2004

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, 2004.  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 provide guidance on:

(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 2004 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, 2004.  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, 2004
	Estimated First Quarter	Estimated Second Quarter	Estimated Third Quarter	Estimated Fourth Quarter
	(Dollars in thousands, except per unit data )
Average Daily Production:
Gas (Mcf)	40,000 to 46,000	38,000 to 44,000	35,500 to 41,500	32,500 to 38,500
Oil (Bbls)	3,700 to 3,900	3,475 to 3,675	3,700 to 3,900	3,700 to 3,900
Natural gas liquids (Bbls)	550 to 650	525 to 625	600 to 700	600 to 700
Total gas equivalents (Mcfe)	65,500 to 73,300	62,000 to 69,800	61,300 to 69,100	58,300 to 66,100
Differentials:
Gas ($/Mcf)	$(.20) to $(.40)	$(.20) to $(.40)	$(.20) to $(.40)	$(.20) to $(.40)
Oil ($/Bbl)	$(.75) to $(1.25)	$(.75) to $(1.25)	$(.75) to $(1.25)	$(.75) to $(1.25)
Natural gas liquids ($/Bbl)	$(9.00) to $(13.00)	$(9.00) to $(13.00)	$(9.00) to $(13.00)	$(9.00) to $(13.00)
Costs Variable by Production ($/Mcfe):
Lease operating expenses (including production taxes)	$1.00 to $1.20	$1.05 to $1.25	$1.05 to $1.25	$1.10 to $1.30
DD&A – Oil and gas properties	$1.15 to $1.45	$1.15 to $1.45	$1.15 to $1.45	$1.15 to $1.45
Other Revenues (Expenses):
Natural gas services:
Revenues	$1,950 to $2,050	$1,950 to $2,050	$1,950 to $2,050	$1,950 to $2,050
Operating costs	$(1,850) to $(1,950)	$(1,850) to $(1,950)	$(1,850) to $(1,950)	$(1,850) to $(1,950)
Exploration costs:
Abandonments and impairments	$(1,000) to $(2,000)	$(1,000) to $(2,000)	$(1,000) to $(2,000)	$(1,000) to $(2,000)
Seismic and other	$(1,600) to $(2,400)	$(1,600) to $(2,400)	$(1,600) to $(2,400)	$(1,600) to $(2,400)
DD&A – Other	$(425) to $(475)	$(425) to $(475)	$(425) to $(475)	$(425) to $(475)
General and administrative	$(2,000) to $(2,200)	$(2,300) to $(2,500)	$(2,100) to $(2,300)	$(2,500) to $(2,700)
Interest expense	$(300) to $(350)	$(350) to $(400)	$(375) to $(425)	$(350) to $(400)
Other income (expense)	$25 to $50	$25 to $50	$25 to $50	$25 to $50
Income Tax Rate:
Current	2%	2%	2%	2%
Deferred	33%	33%	33%	33%
Weighted Average Shares Outstanding (in thousands):
Basic	9,350 to 9,450	9,350 to 9,450	9,350 to 9,450	9,350 to 9,450
Diluted	9,450 to 9,650	9,450 to 9,650	9,450 to 9,650	9,450 to 9,650

Capital Expenditures

The following table sets forth, by area, certain information about our planned exploration and development activities for 2004.

	Total Planned Expenditures Year Ended December 31, 2004		Percentage of Total
	(In thousands)
South Louisiana	$	51,900	69	%
Cotton Valley Reef Complex	7,500		10	%
Mississippi	7,200		10	%
New Mexico	3,400		4	%
Austin Chalk (Trend)	3,000		4	%
Other	2,600		3	%
	$	75,600	100	%

More than 90% of the 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.  Actual expenditures during 2004 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 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 2004.

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 insignificant drilling activities, such as wells drilled in non-core areas and small interests in non-operated properties.

Spud Date	Well Name (Prospect)	County or Parish	Approximate Depth (feet)	Current Status
Cotton Valley Reef Complex
Jan 2003	Muse-Patranella Gas Unit #1	Robertson, TX	17,000	Dry
South Louisiana
Mar 2003	State Lease 17521 #1 (Clio)	St. Mary, LA	2,000	Dry
Mar 2003	State Lease 17569 #1 (Auguste Bay)	Plaquemines, LA	12,500	Dry
Apr 2003	LL&E #1 - fka State Lease 3279 #1 (Floretta)	Plaquemines, LA	12,800	Producing
May 2003	Romere Pass #113	Plaquemines, LA	2,250	Producing
Aug 2003	Romere Pass #117	Plaquemines, LA	9,550	Producing
Sep 2003	Romere Pass #115	Plaquemines, LA	11,600	Producing
Oct 2003	State Lease 17378 #1 (Fleur)	Cameron, LA	18,000	Waiting on completion
Oct 2003	State Lease 17639 #1 (Neva)	Plaquemines, LA	8,500	Dry
Oct 2003	State Lease 17620 #1 (Pelican Point)	Plaquemines, LA	10,500	Waiting on pipeline
Oct 2003	State Lease 16656 #1 (Whiskey Bay)	Plaquemines, LA	12,300	Dry
Oct 2003	State Lease 17613 #1 (Top)	Jefferson, LA	13,200	Dry
Oct 2003	State Lease 17620 #2 (Pelican Point)	Plaquemines, LA	11,000	Dry
Dec 2003	State Lease 17642 #1 (Brusile)	Lafourche, LA	11,000	Dry
Dec 2003	State Lease 17707 #1 (Jones Point)	St. Charles, LA	12,500	Dry
Dec 2003	Allen Gautreaux #1 (King)	Acadia, LA	13,200	In progress
Feb 2004	Louisiana Fruit Co. #1 (Tiger Pass)	Plaquemines, LA	13,200	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, 2004.  These estimates represent the approximate mid-point of the estimated production range.

	Daily Net Production for 2004
	Estimated First Quarter	Estimated Second Quarter	Estimated Third Quarter	Estimated Fourth Quarter
Gas (Mcf):
Austin Chalk (Trend)	2,333	2,484	2,630	2,457
Cotton Valley Reef Complex	23,601	19,978	16,997	15,011
Louisiana	13,344	15,077	15,395	14,532
New Mexico/West Texas	1,833	1,725	1,837	1,946
Other	1,889	1,736	1,641	1,554
	43,000	41,000	38,500	35,500
Oil (Bbls):
Austin Chalk (Trend)	2,244	2,114	2,139	2,122
Louisiana	756	703	825	790
New Mexico/West Texas	733	692	771	823
Other	67	66	65	65
	3,800	3,575	3,800	3,800
Natural Gas Liquids (Bbls):
Austin Chalk (Trend)	328	311	367	341
New Mexico/West Texas	207	198	220	245
Louisiana	65	66	63	64
	600	575	650	650

The estimates shown in the preceding table include production that we expect to achieve (i) upon the completion of pipeline facilities for the State Lease 17620 #1 (Pelican Point), (ii) through developmental drilling planned for 2004 on existing acreage in New Mexico, and (iii) through a limited water frac program planned for 2004 on existing wells in the Austin Chalk (Trend).  The estimates do not include production, if any, that may be achieved through completion operations on the State Lease 17378 #1 (Fleur).

Accounting for Derivatives

The following summarizes information concerning our net positions in open commodity derivatives applicable to periods subsequent to December 31, 2003.

	Oil Swaps
	Bbls	Average Price
Production Period:
1st Quarter 2004	100,000	$	31.53
2nd Quarter 2004	150,000	$	31.53
3rd Quarter 2004	150,000	$	31.53
4th Quarter 2004	150,000	$	31.53
	550,000

	Gas Collars
	MMBtu (a)	Floor		Ceiling
Production Period:
1st Quarter 2004	3,200,000	$	4.50	$	7.04
2nd Quarter 2004	2,500,000	$	4.20	$	5.28
3rd Quarter 2004	2,220,000	$	4.20	$	5.28
4th Quarter 2004	690,000	$	4.20	$	5.28
	8,610,000

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

We did not designate any of the derivatives shown in the preceding tables as cash flow hedges under SFAS 133; therefore, all changes in the fair value of these contracts prior to maturity, plus any realized gains or losses at maturity, will be recorded as other income (expense).