Clayton Williams Energy (CWEI) 8-K Regulation FD Disclosure

EXHIBIT 99.1

CLAYTON WILLIAMS ENERGY, INC.

FINANCIAL GUIDANCE DISCLOSURES FOR 2006

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, 2006.  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 generally 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.

Our estimated capital expenditures for 2006 include $7.2 million of projected completion costs on 6 net wells in North Louisiana and 5 net wells in South Louisiana that are classified as exploratory wells under SEC guidelines but are likely to be productive and require the expenditure of completion costs.  Accordingly, we have included estimated production from these wells in our estimates of oil and gas production for 2006.

As discussed in “Capital Expenditures”, a significant portion of our 2006 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, 2006.  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 finncial or operating factor.  See “Supplemental Information.”

	Year Ending December 31, 2006
	Actual			Actual			Estimated		Estimated
	First Quarter			Second Quarter			Third Quarter		Fourth Quarter
	(Dollars in thousands, except per unit data)
Average Daily Production:
Gas (Mcf)	38,478			44,132			43,500 to 47,500		44,000 to 48,000
Oil (Bbls)	6,167			6,099			5,950 to 6,150		6,300 to 6,500
Natural gas liquids (Bbls)	533			549			550 to 600		475 to 525
Total gas equivalents (Mcfe)	78,678			84,020			82,500 to 88,000		84,650 to 90,150
Differentials:
Gas ($/Mcf)	$	(1.88	)	$	(.04	)	$(.40) to $(.70)		$(.40) to $(.70)
Oil ($/Bbl)	$	(3.47	)	$	(3.92	)	$(3.50) to $(4.00)		$(3.50) to $(4.00)
Natural gas liquids ($/Bbl)	$	(24.58	)	$	(33.14	)	$(22.00) to (28.00)		$	(22.00) to $(28.00)
Costs Variable by Production ($/Mcfe):
Production expenses (including production taxes)	$	2.11		$	2.08		$1.95 to $2.15		$1.95 to $2.15
DD&A — Oil and gas properties	$	1.97		$	1.98		$1.85 to $2.15		$1.85 to $2.15
Other Revenues (Expenses):
Natural gas services:
Revenues	$	3,196		$	2,789		$2,750 to $2,850		$2,750 to $2,850
Operating costs	$	(2,829	)	$	(2,261	)	$	(2,350) to $(2,450)	$	(2,350) to $(2,450)
Exploration costs:
Abandonments and impairments	$	(12,843	)	$	(3,329	)	$	(1,000) to $(3,000)	$	(1,000) to $(3,000)
Seismic and other	$	(3,101	)	$	(2,587	)	$	(2,600) to $(3,400)	$	(2,600) to $(3,400)
DD&A — Other	$	(729	)	$	(827	)	$(800) to $(850)		$(800) to $(850)
General and administrative	$	(4,067	)	$	(4,252	)	$	(3,550) to $(3,750)	$	(4,850) to $(5,050)
Interest expense	$	(4,339	)	$	(4,961	)	$	(5,400) to $(5,600)	$	(5,850) to $(6,050)
Other income (expense)	$	618		$	450		$250 to $350		$250 to $350
Effective Federal and State Income
Tax Rate:
Current	0		%	0		%	0%		0%
Deferred	35		%	15		%	35%		35%
Weighted Average Shares Outstanding (in thousands):
Basic	10,841			10,850			10,850 to 10,900		10,850 to 10,900
Diluted	11,351			11,286			11,400 to 11,600		11,400 to 11,600

Capital Expenditures

The following table sets forth, by area, certain information about our planned exploration and development activities for 2006.

	Total Planned Expenditures Year Ended December 31, 2006		Percentage of Total
	(In thousands)
South Louisiana	$	97,800	46	%
North Louisiana	48,000		22	%
East Texas (Bossier)	21,000		10	%
Permian Basin	26,600		12	%
Utah/Montana	8,700		4	%
Austin Chalk (Trend)	6,400		3	%
Other	5,400		3	%
	$	213,900	100	%

Approximately 85% of the planned expenditures shown in the preceding table relate to exploratory prospects, including $7.2 million of completion costs on exploratory wells to be drilled in North Louisiana and South Louisiana that are classified as exploratory wells but are likely to be productive and require the expenditure of completion costs.  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 2006 may be substantially higher or lower than these estimates since our plans for exploration and development activities may 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 properties.  Other factors, such as prevailing product prices and the availability of capital resources, could also increase or decrease the ultimate level of expenditures during 2006.

Supplementary Information

Oil and Gas Production

The following table summarizes, by area, our actual and estimated daily net production for each quarter during the year ending December 31, 2006.  These estimates represent the approximate mid-point of the estimated production range.

	Daily Net Production for 2006
	Actual	Actual	Estimated	Estimated
	First Quarter	Second Quarter	Third Quarter	Fourth Quarter
Gas (Mcf):
Permian Basin	13,824	15,744	14,533	13,555
Louisiana	9,466	15,428	18,065	20,457
Austin Chalk (Trend)	3,261	2,757	2,707	2,620
Cotton Valley Reef Complex	11,439	9,723	9,859	9,087
Other	488	480	348	293
	38,478	44,132	45,512	46,012
Oil (Bbls):
Permian Basin	3,216	3,274	3,108	3,000
Louisiana	1,079	933	1,087	1,609
Austin Chalk (Trend)	1,828	1,833	1,788	1,729
Other	44	59	65	65
	6,167	6,099	6,048	6,403
Natural Gas Liquids (Bbls):
Permian Basin	262	227	217	196
Austin Chalk (Trend)	258	265	260	250
Other	13	57	98	54
	533	549	575	500

Production for Louisiana for the year 2006 includes approximately 800 MMcfe of estimated production from 11 net exploratory wells in Louisiana that are classified as exploratory wells but are likely to be productive.  We have also included the completion costs for these wells in our estimated costs of exploration and development activities for 2006.

Production estimates above do not include net production attributable to our 5% investment in an affiliated limited partnership that acquired certain producing oil and gas assets in August 2006.

Accounting for Derivatives

The following summarizes information concerning our net positions in open commodity derivatives applicable to periods subsequent to June 30, 2006.  The settlement prices of commodity derivatives are based on NYMEX futures prices.

Collars:

	Gas					Oil
	MMBtu (a)	Floor		Ceiling		Bbls	Floor		Ceiling
Production Period:
3rd Quarter 2006	456,000	$	4.00	$	5.21	150,000	$	23.00	$	25.32
4th Quarter 2006	456,000	$	4.00	$	5.21	150,000	$	23.00	$	25.32
2007	1,831,000	$	4.00	$	5.18	562,000	$	23.00	$	25.20
2008	1,279,000	$	4.00	$	5.15	392,000	$	23.00	$	25.07
	4,022,000					1,254,000

Swaps:

	Gas			Oil
	MMBtu (a)	Price		Bbls	Price
Production Period:
3rd Quarter 2006	—	$	—	75,000	$	71.60
4th Quarter 2006	1,050,000	$	10.03	75,000	$	71.60
2007	5,350,000	$	10.23	600,000	$	72.55
2008	3,660,000	$	9.53	—	$	—
	10,060,000			750,000

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

Subsequent to June 30, 2006, we closed certain fixed-price oil swaps covering 300,000 barrels from January 2007 through December 2007 at a price of $80.45 per barrel, resulting in an aggregate loss of approximately $2.4 million.

Interest Rates

The following summarizes information concerning our net positions in open interest rate swaps applicable to periods subsequent to June 30, 2006.

	Principal		Libor
	Balance		Rates
Period:
July 1, 2006 to November 1, 2006	$	55,000,000	4.29	%
November 1, 2006 to November 1, 2007	$	50,000,000	5.19	%
November 1, 2007 to November 1, 2008	$	45,000,000	5.73	%

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).