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

EXHIBIT 99.1

CLAYTON WILLIAMS ENERGY, INC.

FINANCIAL GUIDANCE DISCLOSURES FOR 2012

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 the year ending December 31, 2012.  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 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, outcomes and other matters that we plan, expect, intend, assume, believe, budget, predict, forecast, project, estimate or anticipate (and other similar expressions) will, should, could or may occur in the future, including such matters as production of oil and gas, product prices, oil and gas reserves, drilling and completion results, capital expenditures, operating costs 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” superseded by topic 815-10 of the Financial Accounting Standards Board Accounting Standards Codification;

(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 and operating expenses related to Desta Drilling, L.P., a wholly-owned subsidiary of the Company which provides contract drilling services for the Company and third parties.

Summary of Estimates

The following table sets forth certain estimates being used to model our anticipated results of operations for the fiscal year ending December 31, 2012.  Each range of values provided represents the expected low and high estimates for such financial or operating factor.

	Estimated Ranges
	Year Ending
	December 31, 2012
(Dollars in thousands, except per unit data)
Average Daily Production:
Oil (Bbls)		10,850 to 11,050
Gas (Mcf)		22,000 to 24,000
Natural gas liquids (Bbls)		1,000 to 1,100
Total oil equivalents (BOE)		15,517 to 16,150
Price Differentials to NYMEX:
Oil		93% to 95%
Gas		120% to 140%
Natural gas liquids (based on oil)		40% to 50%
Other Costs and Expenses:
Production expenses:
Direct costs ($/BOE)	$	18.00 to 19.00
Production taxes (% of sales)		5% to 6%
General and Administrative:
Excluding non-cash compensation	$	28,000 to 30,000
Non-cash compensation	$	7,000 to 9,000
DD&A:
Oil and gas ($/BOE)	$	21.00 to 23.00
Other	$	5,000 to 7,000
Exploration costs:
Abandonments and impairments	$	2,000 to 4,000
Seismic and other	$	10,000 to 12,000
Interest expense (cash rates):
$350 million Senior Notes due 2019		7.75%
Bank credit facility		LIBOR plus (175 to 275 bps)
Effective Federal and State Income
Tax Rate:
Current		0%
Deferred		36%

Capital Expenditures

The following table sets forth, by area, our planned capital expenditures for the year ending December 31, 2012.

	Planned
	Expenditures		2012
	Year Ending		Percentage
	December 31, 2012		of Total
	(In thousands)
Drilling and Completion:
Permian Basin Area:
Delaware Basin	$	230,100		51	%
Other		86,600		20	%
Austin Chalk/Eagle Ford Shale		22,200		5	%
Other		9,700		2	%
		348,600		78	%
Leasing and seismic		80,700		18	%
Exploration and development		429,300		96	%
Facilities and other		20,200		4	%
Total capital expenditures	$	449,500		100	%

We currently plan to spend approximately $429.3 million on exploration and development activities during fiscal 2012 as compared to our previous estimate of $384.6 million.  Most of the $44.7 million increase in estimated expenditures relates to higher drilling and completion costs in the Delaware Basin due in part to our bearing a higher percentage of drilling and completion costs in wells in which Chesapeake elected not to participate for its 25% retained working interest.  Our actual expenditures during 2012 may vary significantly from these estimates since our plans for exploration and development activities may change during the remainder of the year.  Factors, such as changes in operating margins and the availability of capital resources could increase or decrease our actual expenditures during the remainder of fiscal 2012.

Accounting for Derivatives

The following summarizes information concerning our net positions in open commodity derivatives applicable to periods subsequent to June 30, 2012.  The settlement prices of commodity derivatives are based on NYMEX futures prices.

Swaps:

	Oil				Gas
	Bbls		Price		MMBtu (a)		Price
Production Period:
3rd Quarter 2012		757,000	$	90.30		-	$	-
4th Quarter 2012		702,000	$	90.40		-	$	-
2013		1,913,000	$	97.20		1,480,000	$	3.34
2014		600,000	$	99.30		-	$	-
		3,972,000				1,480,000
(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 table as cash flow hedges; 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) in our statement of operations.

Volumetric production payment

In March 2012, we entered into a volumetric production payment (“VPP”) with a third party.  Under the terms of the VPP, we conveyed a term overriding royalty interest covering approximately 725,000 barrels of oil equivalents (“BOE”) of estimated future oil and gas production from certain properties related to production months from March 2012 through December 2019.  The scheduled remaining volumes for production months from July 2012 through December 2019 are shown below.

	Oil		Gas
	Bbls		Mcf
Production Period:
3rd Quarter 2012		32,788		14,826
4th Quarter 2012		31,979		17,558
2013		116,941		33,619
2014		102,011		45,392
2015		88,954		60,218
2016		64,808		112,928
2017		56,785		96,792
2018		49,455		84,734
2019		43,820		72,874
		587,541		538,941