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

EXHIBIT 99.1

CLAYTON WILLIAMS ENERGY, INC.

FINANCIAL GUIDANCE DISCLOSURES FOR 2008

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, 2008.  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 actual results of operations for these periods have been 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;

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

(f) revenues, expenses and minority interest related to our investment in Larclay JV.

As discussed in “Capital Expenditures”, approximately 27% of our planned 2008 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, 2008.  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.  See “Supplementary Information.”

	Year Ending December 31, 2008
	Actual			Actual			Estimated	Estimated
	First Quarter			Second Quarter			Third Quarter	Fourth Quarter
	(Dollars in thousands, except per unit data)
Average Daily Production:
Gas (Mcf)		60,967			45,901		45,800 to 49,800	49,000 to 53,000
Oil (Bbls)		7,516			7,725		8,725 to 8,925	9,850 to 10,050
Natural gas liquids (Bbls)		637			451		400 to 450	400 to 450
Total gas equivalents (Mcfe)		109,885			94,957		100,550 to 106,050	110,500 to 116,000
Differentials:
Gas (Mcf) (a)	$	0.99		$	0.71		$(0.35) to $(0.65)	$(0.35) to $(0.65)
Oil (Bbls)	$	(1.53	)	$	(2.47	)	$(2.75) to $(3.35)	$(2.75) to $(3.35)
Natural gas liquids (Bbls)	$	(37.90	)	$	(60.35	)	$(32.00) to $(38.00)	$(32.00) to $(38.00)
Costs Variable by Production ($/Mcfe):
Production expenses (including
production taxes)	$	2.06		$	2.54		$2.40 to $2.60	$2.35 to $2.55
DD&A – Oil and gas properties	$	2.77		$	2.62		$2.45 to $2.85	$2.45 to $2.85
Other Revenues (Expenses):
Natural gas services:
Revenues	$	2,538		$	3,553		$3,450 to $3,650	$3,450 to $3,650
Operating costs	$	(2,515	)	$	(3,244	)	$(3,150) to $(3,350)	$(3,150) to $(3,350)
Exploration costs:
Abandonments and impairments	$	(297	)	$	(1,933	)	$(1,000) to $(3,000)	$(1,000) to $(3,000)
Seismic and other	$	(3,675	)	$	(1,562	)	$(5,500) to $(7,500)	$(5,500) to $(7,500)
DD&A – Other (b)	$	(247	)	$	(261	)	$(250) to $(350)	$(250) to $(350)
General and administrative (b)	$	(3,211	)	$	(7,872	)	$(6,550) to $(6,750)	$(7,150) to $(7,350)
Interest expense (b)	$	(6,352	)	$	(5,136	)	$(4,700) to $(4,900)	$(5,500) to $(5,700)
Other income	$	655		$	3,014		$250 to $350	$250 to $350
Gain on sales of property and equipment, net	$	560		$	40,444		-	-
Effective Federal and State Income
Tax Rate:
Current		1%			1%		1%	1%
Deferred		36%			35%		36%	36%
Weighted Average Shares Outstanding
(In thousands):
Basic		11,387			12,111		12,100 to 12,200	12,100 to 12,200
Diluted		11,643			12,111		12,100 to 12,300	12,100 to 12,300
(a)Our actual realized gas price for the first and second quarter of 2008 was higher than the average NYMEX price for the same period due primarily to abnormal variances between NYMEX and daily spot prices for natural gas.  Since we cannot predict the likelihood that this condition will continue throughout the remainder of 2008, we are estimating differentials to be more in line with historical averages.
(b)Excludes amounts derived from Larclay JV.

Capital Expenditures

The following table sets forth, by area, certain information about our actual and planned exploration and development activities for 2008.

	Actual		Planned
	Expenditures		Expenditures		Year 2008
	Six Months Ended		Year Ending		Percentage
	June 30, 2008		December 31, 2008		of Total
	(In thousands)
Permian Basin	$	60,400	$	184,100		46	%
North Louisiana		34,600		83,400		21	%
Austin Chalk (Trend)		28,600		57,500		14	%
South Louisiana		17,000		35,700		9	%
East Texas Bossier		11,800		30,300		8	%
Utah/California		1,900		8,700		2	%
Other		400		1,000		-
	$	154,700	$	400,700		100	%

We have increased our estimates for planned exploration and development expenditures for fiscal 2008 by $56.2 million from $344.5 million to $400.7 million.  Most of the planned increase in capital spending relates to developmental drilling activities in the Permian Basin and North Louisiana and exploratory drilling activities in South Louisiana.

Our actual expenditures during fiscal 2008 may be substantially higher or lower than these estimates since our plans for exploration and development activities may change during the year.  Other factors, such as prevailing product prices and the availability of capital resources, could also increase or decrease the ultimate level of expenditures during fiscal 2008.

In 2008, we plan to allocate a majority of our capital resources to developmental drilling activities in oil-prone areas such as the Permian Basin and the Austin Chalk (Trend).  In addition, we plan to continue drilling developmental gas wells in North Louisiana, primarily on our Terryville prospect.  Based on these current estimates, approximately 73% of our expenditures for exploration and development activities for fiscal 2008 will relate to developmental prospects, as compared to approximately 49% in fiscal 2007.

Supplementary Information

Oil and Gas Production

The following table summarizes, by area, our actual or estimated daily net production for each quarter during the year ending December 31, 2008.  These estimates represent the approximate mid-point of the estimated production range.

	Daily Net Production for 2008
	Actual		Actual		Estimated		Estimated
	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
Gas (Mcf):
Permian Basin		15,562		14,284		14,272		14,712
North Louisiana		13,596		15,233		18,038		17,114
South Louisiana		23,552		7,347		7,685		11,739
Austin Chalk (Trend)		2,460		2,133		2,261		2,239
Cotton Valley Reef Complex		5,270		6,277		5,185		4,837
Other		527		627		359		359
Total		60,967		45,901		47,800		51,000
Oil (Bbls):
Permian Basin		3,494		3,568		4,141		4,946
North Louisiana		343		386		413		391
South Louisiana		985		105		348		446
Austin Chalk (Trend)		2,635		3,575		3,847		4,102
Other		59		91		76		65
Total		7,516		7,725		8,825		9,950
Natural Gas Liquids (Bbls):
Permian Basin		215		153		163		163
Austin Chalk (Trend)		272		241		229		229
Other		150		57		33		33
Total		637		451		425		425

Accounting for Derivatives

The following summarizes information concerning our net positions in open commodity derivatives applicable to periods subsequent to June 30, 2008.  The settlement prices of commodity derivatives are based on NYMEX futures prices.

Collar:

	Gas						Oil
	MMBtu (a)		Floor		Ceiling		Bbls		Floor		Ceiling
Production Period:
3rd Quarter 2008		419,000	$	4.00	$	5.15		128,000	$	23.00	$	25.07

Swaps:

	Gas				Oil
	MMBtu (a)		Price		Bbls		Price
Production Period:
3rd Quarter 2008		4,000,000	$	9.19		310,000	$	78.96
4th Quarter 2008		4,100,000	$	9.17		400,000	$	82.21
2009		3,600,000	$	9.33		1,440,000	$	85.30
		11,700,000				2,150,000
(a) One MMBtu equals one Mcf at a Btu factor of 1,000.

In July 2008, we terminated certain fixed-priced gas swaps covering 300,000 MMBtu at a price of $10.32 per MMBtu from August 2008 through October 2008, resulting in an aggregate loss of $585,000, which will be paid to the counterparty monthly as the applicable contracts are settled.

In September 2007, we terminated certain fixed-priced oil swaps covering 60,000 barrels at a price of $76.65 from July 2008 through December 2008, resulting in an aggregate loss of approximately $663,000, which will be paid to the counterparty monthly as the applicable contracts are settled.

Interest Rate

The following summarizes information concerning our interest rate swap applicable to periods subsequent to June 30, 2008.

Interest Rate Swap:

			Fixed
	Principal		Libor
	Balance		Rate
Period:
July 1, 2008 to November 3, 2008	$	45,000,000		5.73	%

In April 2008, we terminated our $100 million interest rate swap for a cash payment of $899,000.

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, are recorded as other income (expense) in our statement of operations.