8-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

Date of Report (Date of earliest event reported):  August 29, 2011

CLAYTON WILLIAMS ENERGY, INC.

(Exact name of Registrant as specified in its charter)

Delaware	001-10924	75-2396863
(State or other jurisdiction of	(Commission File	(I.R.S. Employer
incorporation or organization)	Number)	Identification Number)

6 Desta Drive, Suite 6500, Midland, Texas	79705-5510
(Address of principal executive offices)	(Zip code)

Registrant's Telephone Number, including area code:   (432) 682-6324

Not applicable

(Former name, former address and former fiscal year, if changed since last report)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

¨           Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

¨           Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

¨Pre-commencement communications pursuant to Rule 14d-2 (b) under the Exchange Act (17 CFR 240.14d-2 (b))

¨Pre-commencement communications pursuant to Rule 13e-4 (c) under the Exchange Act (17 CFR 240.13e-4 (c))

Item 7.01 -                      Regulation FD Disclosure

The Company hereby incorporates by reference into this Item 7.01 of Form 8-K the Financial Guidance Disclosures for 2011 attached as Exhibit 99.1.  This Exhibit 99.1 is being furnished to provide public disclosure of the Company’s estimates to permit preparation of financial models of the Company’s operating results for each quarter during the Company’s fiscal year ending December 31, 2011.  The Company cautions users of this information that the estimates provided in this Exhibit 99.1 are based on information available to the Company as of the date of this filing, and actual results may vary materially from these estimates.  The Company does not undertake any obligation to update these estimates as conditions change or as additional information becomes available.

Item 9.01 -                      Financial Statements and Exhibits

(d)         Exhibits

The following exhibit is provided as part of the information furnished under Item 7.01 of this report.

Exhibit
Number	Description
99.1	Clayton Williams Energy, Inc. Financial Guidance Disclosures for 2011

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereto duly authorized.

CLAYTON WILLIAMS ENERGY, INC.

Date:	August 29, 2011	By:	/s/ Mel G. Riggs
			Mel G. Riggs
			Executive Vice President and Chief
			Operating Officer

Date:	August 29, 2011	By:	/s/ Michael L. Pollard
			Michael L. Pollard
			Senior Vice President and Chief Financial
			Officer

EX-99.1

EXHIBIT 99.1

CLAYTON WILLIAMS ENERGY, INC.

FINANCIAL GUIDANCE DISCLOSURES FOR 2011

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, 2011.  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, 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 expenses related to Desta Drilling, L.P., a wholly-owned subsidiary of the Company which provides contract drilling services for the Company.

Summary of Estimates

The following table sets forth actual and certain estimates being used by us to model our anticipated results of operations for each quarter during the fiscal year ending December 31, 2011.  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, 2011
	Actual			Actual			Estimated		Estimated
	First Quarter			Second Quarter			Third Quarter		Fourth Quarter
	(Dollars in thousands, except per unit data)
Average Daily Production:
Oil (Bbls)		9,989			9,736		9,425 to 9,625		10,250 to 10,450
Gas (Mcf)		23,478			24,846		20,500 to 24,500		19,500 to 23,500
Natural gas liquids (Bbls)		922			802		750 to 850		750 to 850
Total oil equivalents (BOE)		14,824			14,679		13,592 to 14,558		14,250 to 15,217
Differentials:
Oil (Bbls)	$	(5.17	)	$	(2.49	)		$(3.50) to $(4.50)		$(3.50) to $(4.50)
Gas (Mcf)	$	1.04		$	1.18			$0.15 to $0.45		$0.15 to $0.45
Natural gas liquids (Bbls)	$	(45.76	)	$	(45.40	)		$(42.00) to $(48.00)		$(42.00) to $(48.00)
Costs Variable by Production ($/BOE):
Production expenses (excluding
production taxes) (a)	$	14.67		$	15.61			$14.75 to $15.75		$14.75 to $15.75
DD&A – Oil and gas properties	$	17.46		$	18.31			$17.50 to $18.50		$17.50 to $18.50
Other Revenues (Expenses):
Natural gas services:
Revenues	$	409		$	365			$450 to $550		$450 to $550
Operating costs	$	(263	)	$	(285	)		$(300) to $(500)		$(300) to $(500)
Exploration costs:
Abandonments and impairments	$	(877	)	$	(174	)		$(250) to $(750)		$(250) to $(750)
Seismic and other	$	(1,278	)	$	(2,167	)		$(500) to $(2,500)		$(500) to $(2,500)
DD&A – Other (b)	$	(193	)	$	(153	)		$(250) to $(350)		$(250) to $(350)
General and administrative (b) (c)	$	(5,025	)	$	(5,405	)		$(5,100) to $(5,300)		$(5,900) to $(6,100)
Interest expense	$	(6,412	)	$	(9,175	)		$(9,200) to $(9,400)		$(8,800) to $(9,000)
Other income (expense)	$	1,087		$	1,900			$(450) to $(550)		$(450) to $(550)
Gain (loss) on sales of assets, net	$	13,376		$	842			-		-
Effective Federal and State Income
Tax Rate:
Current		0	%		0	%		0%		0%
Deferred		36	%		36	%		36%		36%
Weighted Average Shares Outstanding
(In thousands):
Basic		12,156			12,162			12,162		12,162
Diluted		12,156			12,163			12,163		12,163
(a) Our current guidance for production expenses excludes production taxes. Historically, production taxes have ranged from 5% to 6 % of oil and gas sales.
(b) Excludes amounts derived from Desta Drilling, L.P.
(c) Excludes non-cash employee compensation.

Oil and Gas Production

We have revised downward our expected oil and gas production for the remainder of 2011 in connection with the shift in capital spending to the Reeves County Wolfbone play.  Since our last guidance in May 2011, we have reduced the planned rig count in Andrews County from 3 rigs to 1 and have dropped both rigs previously allocated to the Austin Chalk in order to allocate resources to our Wolfbone play.  In addition, estimated production from the Andrews Wolfberry play was revised downward due to continuing frac delays and revisions in production based on well performance.

Capital Expenditures

The following table sets forth, by area, our actual expenditures for exploration and development activities for the first six months of 2011 and our planned expenditures for the year ending December 31, 2011.

	Actual		Planned
	Expenditures		Expenditures		2011
	Six Months Ended		Year Ended		Percentage
	June 30, 2011		December 31, 2011		of Total
	(In thousands)
Permian Basin Area:
West Texas - Reeves	$	44,300	$	188,400		49	%
West Texas - Andrews		77,300		112,300		29	%
West Texas - Other		13,700		17,700		5	%
Giddings Area:
Austin Chalk/Eagle Ford Shale		25,900		41,400		11	%
Deep Bossier		200		13,800		3	%
South Louisiana		3,400		6,800		2	%
Other		3,700		4,600		1	%
	$	168,500	$	385,000		100	%

We currently plan to spend approximately $385 million on exploration and development activities in fiscal 2011, as compared to $439.4 million reported in our Form 10-Q for the second quarter of 2011.  Substantially all of these cost reductions relate to our planned activities in the Reeves County Wolfbone play and are based on several factors, including a reduction in the total number of wells that we expect to be able to drill in the area during the remainder of the year and an increase in the estimated number of those wells in which we will own a 75% net working interest versus 100%.  These reductions were partially offset by an increase in the estimated cost to drill and complete each of the Wolfbone wells from $3.8 million to $4.2 million as a result of changes in the planned frac design.

We are also purchasing two drilling rigs for our Desta Drilling fleet at a cost of approximately $15.3 million, of which approximately $8 million was spent during the second quarter of 2011.  In addition, we plan to spend approximately $15 million during the remainder of 2011 to begin constructing a gas gathering and treating system to facilitate the transportation and marketing of our Wolfbone oil and gas production in Reeves County.

Our actual expenditures during fiscal 2011 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 2011.  Based on these current estimates, approximately 94% of our planned expenditures for exploration and development activities for fiscal 2011 will relate to developmental prospects, as compared to approximately 95% in fiscal 2010.

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, 2011.  These estimates represent the approximate mid-point of the estimated production range.

	Daily Net Production for 2011
	Actual		Actual		Estimated		Estimated
	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
Oil (Bbls):
Permian Basin Area:
West Texas - Andrews		2,607		2,585		2,744		3,014
West Texas - Reeves		-		11		141		1,087
West Texas - Other		3,570		3,095		3,217		3,010
Austin Chalk/Eagle Ford Shale		3,329		3,335		2,978		3,011
South Louisiana		414		493		380		163
Other		69		217		65		65
Total		9,989		9,736		9,525		10,350
Gas (Mcf):
Permian Basin Area:
West Texas - Andrews		1,588		1,719		2,011		2,207
West Texas - Reeves		7		25		-		-
West Texas - Other		12,333		10,457		10,272		9,690
Giddings Area:
Austin Chalk/Eagle Ford Shale		1,940		2,177		2,195		2,190
Cotton Valley Reef Complex		2,953		2,931		2,435		2,315
South Louisiana		3,149		6,134		4,576		4,087
Other		1,508		1,403		1,011		1,011
Total		23,478		24,846		22,500		21,500
Natural Gas Liquids (Bbls):
Permian Basin Area:
West Texas - Andrews		364		368		344		355
West Texas - Other		255		151		195		184
Austin Chalk/Eagle Ford Shale		226		183		196		196
Other		77		100		65		65
Total		922		802		800		800

Accounting for Derivatives

The following summarizes information concerning our net positions in open commodity derivatives applicable to periods subsequent to June 30, 2011.  The settlement prices of commodity derivatives are based on NYMEX futures prices.

Swaps:

	Oil				Gas
	Bbls		Price		MMBtu (a)		Price
Production Period:
3rd Quarter 2011		547,000	$	83.78		1,560,000	$	7.07
4th Quarter 2011		729,000	$	87.56		1,500,000	$	7.07
2012		2,649,000	$	95.75		-	$	-
2013		1,189,000	$	99.92		-	$	-
		5,114,000				3,060,000
(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.