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

EXHIBIT 99.1

CLAYTON WILLIAMS ENERGY, INC.

FINANCIAL GUIDANCE DISCLOSURES FOR 2007

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, 2007.  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 final results of operations for this period 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.

Our estimated capital expenditures for 2007 include projected completion costs on 5 wells in North Louisiana that are classified as exploratory wells under SEC guidelines but are expected to require the expenditure of completion costs.  We have also included estimated production aggregating approximately 0.7 Bcfe from these wells in our estimates of oil and gas production for 2007.

As discussed in “Capital Expenditures”, a significant portion of our 2007 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, 2007.  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 “Supplemental Information.”

	Year Ending December 31, 2007
	Estimated	Estimated	Estimated	Estimated
	First Quarter	Second Quarter	Third Quarter	Fourth Quarter
	(Dollars in thousands, except per unit data)
Average Daily Production:
Gas (Mcf)	45,000 to 49,000	46,500 to 50,500	45,500 to 49,500	43,500 to 47,500
Oil (Bbls)	5,500 to 5,700	5,275 to 5,475	5,200 to 5,400	5,025 to 5,225
Natural gas liquids (Bbls)	450 to 500	400 to 450	350 to 400	350 to 400
Total gas equivalents (Mcfe)	80,700 to 86,200	80,550 to 86,050	78,200 to 84,300	75,750 to 81,250
Differentials:
Gas ($/Mcf)	$(0.40) to $(0.70)	$(0.40) to $(0.70)	$(0.40) to $(0.70)	$(0.40) to $(0.70)
Oil ($/Bbl)	$(2.80) to $(3.40)	$(2.80) to $(3.40)	$(2.80) to $(3.40)	$(2.80) to $(3.40)
Natural gas liquids ($/Bbl)	$(22.00) to $(28.00)	$(22.00) to $(28.00)	$(22.00) to $(28.00)	$(22.00) to $(28.00)
Costs Variable by Production ($/Mcfe):
Production expenses (including production taxes)	$1.90 to $2.10	$2.00 to $2.20	$2.10 to $2.30	$2.15 to $2.35
DD&A – Oil and gas properties	$2.00 to $2.30	$2.00 to $2.30	$2.00 to $2.30	$2.00 to $2.30
Other Revenues (Expenses):
Natural gas services:
Revenues	$1,900 to $2,100	$1,900 to $2,100	$1,900 to $2,100	$1,900 to $2,100
Operating costs	$(1,750) to $(1,950)	$(1,750) to $(1,950)	$(1,750) to $(1,950)	$(1,750) to $(1,950)
Exploration costs:
Abandonments and impairments	$(1,000) to $(3,000)	$(1,000) to $(3,000)	$(1,000) to $(3,000)	$(1,000) to $(3,000)
Seismic and other	$(2,500) to $(3,500)	$(2,500) to $(3,500)	$(2,500) to $(3,500)	$(2,500) to $(3,500)
DD&A – Other	$(1,100) to $(1,300)	$(1,100) to $(1,300)	$(1,100) to $(1,300)	$(1,100) to $(1,300)
General and administrative	$(4,100) to $(4,300)	$(4,200) to $(4,400)	$(3,100) to $(3,300)	$(4,200) to $(4,400)
Interest expense	$(6,600) to $(6,800)	$(7,000) to $(7,200)	$(6,900) to $(7,100)	$(6,600) to $(6,900)
Other income (expense)	$250 to $350	$250 to $350	$250 to $350	$250 to $350
Effective Federal and State Income Tax Rate:
Current	0%	0%	0%	0%
Deferred	35%	35%	35%	35%
Weighted Average Shares Outstanding (in thousands):
Basic	10,850 to 10,900	10,850 to 10,900	10,850 to 10,900	10,850 to 10,900
Diluted	11,400 to 11,600	11,400 to 11,600	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 2007.

	Total
	Planned
	Expenditures
	Year Ended		Percentage
	December 31, 2007		of Total
	(In thousands)
East Texas (Bossier)	$	45,000	33	%
South Louisiana	36,300		26	%
North Louisiana	34,600		25	%
Permian Basin	10,400		7	%
Austin Chalk (Trend)	8,000		6	%
Utah	4,000		3	%
	$	138,300	100	%

Approximately 80% 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 2007 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 all 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 2007.

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, 2007.  These estimates represent the approximate mid-point of the estimated production range.

	Daily Net Production for 2007
	Estimated	Estimated	Estimated	Estimated
	First Quarter	Second Quarter	Third Quarter	Fourth Quarter
Gas (Mcf):
Permian Basin	12,800	11,934	11,185	10,630
Louisiana	24,144	27,264	27,728	26,859
Austin Chalk (Trend)	1,623	1,554	1,467	1,381
Cotton Valley Reef Complex	8,033	7,396	6,772	6,304
Other	400	352	348	326
	47,000	48,500	47,500	45,500
Oil (Bbls):
Permian Basin	2,767	2,660	2,555	2,489
Louisiana	1,133	1,077	1,120	1,043
Austin Chalk (Trend)	1,633	1,583	1,560	1,528
Other	67	55	65	65
	5,600	5,375	5,300	5,125
Natural Gas Liquids (Bbls):
Permian Basin	133	132	131	131
Louisiana	100	66	65	65
Austin Chalk (Trend)	220	216	179	179
Other	22	11	—	—
	475	425	375	375

Accounting for Derivatives

The following summarizes information concerning our net positions in open commodity derivatives applicable to periods subsequent to December 31, 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:
1st Quarter 2007	454,000	$	4.00	$	5.18	139,000	$	23.00	$	25.20
2nd Quarter 2007	459,000	$	4.00	$	5.18	141,000	$	23.00	$	25.20
3rd Quarter 2007	459,000	$	4.00	$	5.18	141,000	$	23.00	$	25.20
4th Quarter 2007	459,000	$	4.00	$	5.18	141,000	$	23.00	$	25.20
2008	1,279,000	$	4.00	$	5.15	392,000	$	23.00	$	25.07
	3,110,000					954,000

Swaps:

	Gas			Oil
	MMBtu (a)	Price		Bbls	Price
Production Period:
1st Quarter 2007	3,000,000	$	8.26	150,000	$	72.75
2nd Quarter 2007	2,600,000	$	8.16	—	$	—
3rd Quarter 2007	2,400,000	$	8.34	75,000	$	72.75
4th Quarter 2007	2,400,000	$	8.34	225,000	$	72.75
2008	6,000,000	$	8.16	720,000	$	65.60
	16,400,000			1,170,000

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

In July 2006, we terminated certain fixed-price oil swaps covering 300,000 barrels at a price of $80.45 per barrel, from January 2007 through December 2007, resulting in an aggregate loss of approximately $2.4 million, which will be paid to the counterparty monthly during 2007.

In January 2007, we also terminated certain fixed-price oil swaps covering 450,000 barrels at a price of $55.35 per barrel, from March 2007 through August 2007, resulting in an aggregate gain of approximately $7.8 million, which will be collected from the counterparty monthly during 2007.

Interest Rates

The following summarizes information concerning our net positions in open interest rate swaps applicable to periods subsequent to December 31, 2006.

	Principal		Fixed Libor
	Balance		Rates
Period:
January 1, 2007 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).