Clayton Williams Energy (CWEI) 8-K Clayton Williams Energy Announces 2010 Financial Results and Year-End Reserves

Exhibit 99.1

Clayton Williams Energy Announces 2010 Financial Results and Year-End Reserves

MIDLAND, Texas--(BUSINESS WIRE)--February 24, 2011--Clayton Williams Energy, Inc. (the “Company”) (NASDAQ:CWEI) today reported its financial results for the quarter and year ended December 31, 2010, along with information about its proved oil and gas reserves as of December 31, 2010.

Highlights

• 2010 Cash Flow from Operations of $208.3 Million, up 99%
• Total Proved Reserves of 51.1 Million BOE, up 52%
• 74% Oil and NGL and 68% Proved Developed
• 425% of 2010 Production Replaced by Reserve Additions

Financial Results for Fiscal Year 2010

Net income attributable to Company stockholders for fiscal 2010 was $36.9 million, or $3.04 per share, as compared to a net loss of $117.4 million, or $9.67 per share, for fiscal 2009. Cash flow from operations for 2010 was $208.3 million as compared to $104.7 million for 2009. The key factors affecting the comparability of the two years were:

• Oil and gas sales increased $84 million in 2010 compared to 2009. Price variances accounted for $76.7 million of the increase and production variances accounted for the remaining $7.3 million. Average realized oil prices were $76.44 per barrel in 2010 versus $57.37 per barrel in 2009, and average realized gas prices were $5.17 per Mcf in 2010 versus $4.35 per Mcf in 2009. Combined oil and gas production for 2010 was 5% lower on a barrel of oil equivalent (“BOE”) basis than in the comparable period in 2009. Oil production increased 18% compared to 2009 while gas production declined 33%. On a comparable basis, after giving effect to the sale of properties in North Louisiana in June 2010, oil and gas production in 2010 on a BOE basis was 5% higher than 2009.
• Gain on derivatives for 2010 was $0.7 million ($9.9 million realized gain on settled contracts and a $9.2 million non-cash mark-to-market loss) versus a loss in 2009 of $17.4 million ($15.9 million realized loss on settled contracts and a $1.5 million non-cash mark-to-market loss). See accompanying tables for additional information about the Company’s accounting for derivatives.
• Exploration costs, including seismic costs, exploratory dry hole costs, and unproved acreage impairments, totaled $15.1 million in 2010 versus $87 million in 2009.
• Non-cash impairments of property and equipment were $11.9 million in 2010 versus $59.1 million in 2009. The 2010 impairments related primarily to certain non-core oil and gas properties in the Permian Basin.
• General and administrative expenses for 2010 were $35.6 million versus $20.7 million in 2009. Most of the increase related to non-cash employee compensation related to non-equity incentive plans totaling $13.9 million in 2010 versus $1.4 million in 2009.

Financial Results for the Fourth Quarter of 2010

Net loss attributable to Company stockholders for the fourth quarter of 2010 (“4Q10”) was $5.3 million, or $.44 per share, as compared to a net loss of $42.9 million, or $3.53 per share, for the fourth quarter of 2009 (“4Q09”). Cash flow from operations for 4Q10 was $54.1 million as compared to $35.6 million for 4Q09. The key factors affecting the comparability of the two quarters were:

• Oil and gas sales increased $13.5 million in 4Q10 versus 4Q09. Price variances accounted for an $8.5 million increase while production variances accounted for the remaining $5 million. Average realized oil prices were $82.07 per barrel in 4Q10 versus $72.78 per barrel in 4Q09, and average realized gas prices were $5.02 per Mcf in 4Q10 versus $5.20 per Mcf in 4Q09. Combined oil and gas production for 4Q10 was 5% lower on a BOE basis than in 4Q09. Oil production increased 22% compared to 4Q09, while gas production declined 42%. On a comparable basis, after giving effect to the sale of properties in North Louisiana in June 2010, oil and gas production in 4Q10 on a BOE basis was 7% higher than 4Q09. Oil and gas production in 4Q10 was lower than guidance estimates due primarily to operational delays in getting wells stimulated and placed into production and due to lower than expected production from two gas wells in South Louisiana.
• Loss on derivatives for 4Q10 was $26.6 million ($27 million non-cash mark-to-market loss net of a $0.4 million realized gain on settled contracts) versus a loss in 4Q09 of $2.9 million ($9.7 million realized loss on settled contracts net of $6.8 million non-cash mark-to-market gain). See accompanying tables for additional information about the Company’s accounting for derivatives.
• Exploration costs, including seismic costs, exploratory dry hole costs, and unproved acreage impairments, totaled $5 million in 4Q10 versus $39.4 million in 4Q09.
• Non-cash impairments of property and equipment were $27.1 million in 4Q09 versus no comparable impairments in 4Q10.
• General and administrative expenses for 4Q10 were $12.8 million versus $5.9 million in 4Q09. Most of the increase related to non-cash employee compensation related to non-equity incentive plans totaling $5.8 million in 4Q10 versus $0.5 million in 4Q09.

Reserves

The Company reported that its total estimated proved oil and gas reserves as of December 31, 2010 were 51.1 million barrels of oil equivalent (MMBOE), consisting of 37.8 million barrels of oil and NGL and 79.5 Bcf of natural gas. On a BOE basis, oil and NGL comprised 74% of total proved reserves at year-end 2010 versus 62% at year-end 2009. Proved developed reserves at year-end 2010 were 34.5 MMBOE, or 68% of total proved reserves, as compared to 28.6 MMBOE, or 85% of total proved reserves, at year-end 2009. The present value of estimated future net cash flows from total proved reserves, before deductions for estimated future income taxes and asset retirement obligations, discounted at 10%, (referred to as “PV-10 Value”) totaled $992 million for year-end 2010 as compared to $460.4 million for year-end 2009. For a reconciliation of PV-10 Value (a non-GAAP measure) to standardized measure of discounted future net cash flows, see accompanying tables.

The following table summarizes the changes in total proved reserves during 2010 on an MMBOE basis.

	MMBOE
Total proved reserves, December 31, 2009	33.6
Extensions and discoveries	23.2
Revisions	2.3
Purchases of reserves	.3
Sales of reserves	(2.9	)
Production	(5.4	)
Total proved reserves, December 31, 2010	51.1

The Company replaced 425% of its 2010 oil and gas production through extensions and discoveries. Most of the 23.2 MMBOE of reserve additions in 2010 were derived from organic drill bit growth in the Company’s core acreage positions in the Permian Basin and the Austin Chalk. Oil and NGL accounted for 82% of the 2010 reserve additions.

Revisions of prior year estimates resulted from a combination of 6 MMBOE of upward revisions related to the effects of higher commodity prices on economic limits of long-life properties and downward revisions of 3.7 MMBOE related to changes in estimates based on well performance and downgrades of certain proved undeveloped reserves to probable due to a provision that requires proved undeveloped reserves to be developed within five years from their date of origin.

SEC guidelines require that the Company’s estimated proved reserves and related PV-10 Values be determined using benchmark commodity prices equal to the unweighted arithmetic average of the first-day-of-the-month price for the 12-month period prior to the effective date of each reserve estimate. The benchmark averages for 2010 were $79.43 per barrel of oil and $4.38 per MMBtu of natural gas, as compared to $61.18 per barrel and $3.83 per MMBtu for 2009. These benchmark prices were further adjusted for quality, energy content, transportation fees and other price differentials specific to the Company’s properties, resulting in an average adjusted price over the remaining life of the proved reserves of $72.36 per barrel of oil and NGL and $5.44 per Mcf of natural gas for year-end 2010, as compared to $54.81 per barrel and $3.71 per Mcf for year-end 2009.

Commodity prices have a significant impact on proved oil and gas reserves and their related PV-10 Value. Using strip prices as of December 31, 2010 instead of the SEC mandated benchmark prices, the Company’s PV-10 Value for year-end 2010 would have been $1.2 billion.

Scheduled Conference Call

The Company will host a conference call to discuss these results and other forward-looking items, February 24^th at 1:30 p.m. CT (2:30 p.m. ET). The dial-in conference number is: 800-901-5213, passcode 30708570. The replay will be available for one week at 888-286-8010, passcode 25083498.

To access the conference call via Internet webcast, please go to the Investor Relations section of the Company’s website at www.claytonwilliams.com and click on “Live Webcast.” Following the live webcast, the call will be archived for a period of 90 days on the Company’s website.

Clayton Williams Energy, Inc. is an independent energy company located in Midland, Texas.

This release contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical or current facts, 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 or may occur in the future are forward-looking statements. These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events. The Company cautions that its future natural gas and liquids production, revenues, cash flows, liquidity, plans for future operations, expenses, outlook for oil and natural gas prices, timing of capital expenditures and other forward-looking statements are subject to all of the risks and uncertainties, many of which are beyond our control, incident to the exploration for and development, production and marketing of oil and gas.

These risks include, but are not limited to, the possibility of unsuccessful exploration and development drilling activities, our ability to replace and sustain production, commodity price volatility, domestic and worldwide economic conditions, the availability of capital on economic terms to fund our capital expenditures and acquisitions, our level of indebtedness, the impact of the current economic recession on our business operations, financial condition and ability to raise capital, declines in the value of our oil and gas properties resulting in a decrease in our borrowing base under our credit facility and impairments, the ability of financial counterparties to perform or fulfill their obligations under existing agreements, the uncertainty inherent in estimating proved oil and gas reserves and in projecting future rates of production and timing of development expenditures, drilling and other operating risks, lack of availability of goods and services, regulatory and environmental risks associated with drilling and production activities, the adverse effects of changes in applicable tax, environmental and other regulatory legislation, and other risks and uncertainties are described in the Company's filings with the Securities and Exchange Commission. The Company undertakes no obligation to publicly update or revise any forward-looking statements.

CLAYTON WILLIAMS ENERGY, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
(In thousands, except per share)
			Three Months Ended						Year Ended
			December 31,						December 31,
				2010			2009			2010			2009
REVENUES
	Oil and gas sales		$	88,382		$	74,900		$	326,320		$	242,338
	Natural gas services			279			1,568			1,631			6,146
	Drilling rig services			-			-			-			6,681
	Gain on sales of assets			424			48			3,680			796
		Total revenues		89,085			76,516			331,631			255,961
COSTS AND EXPENSES
	Production			21,134			19,671			83,146			76,288
	Exploration:
		Abandonments and impairments		2,941			37,732			9,074			78,798
		Seismic and other		2,051			1,633			6,046			8,189
	Natural gas services			258			1,382			1,209			5,348
	Drilling rig services			(6	)		(53	)		1,198			10,848
	Depreciation, depletion and amortization			24,873			36,954			101,145			129,658
	Impairment of property and equipment			-			27,072			11,908			59,140
	Accretion of abandonment obligations			670			830			2,623			3,120
	General and administrative			12,802			5,919			35,588			20,715
	Loss on sales of assets and impairment of inventory			227			2,148			1,750			5,282
		Total costs and expenses		64,950			133,288			253,687			397,386
		Operating income (loss)		24,135			(56,772	)		77,944			(141,425	)
OTHER INCOME (EXPENSE)
	Interest expense			(6,009	)		(6,058	)		(24,402	)		(23,758	)
	Gain (loss) on derivatives			(26,567	)		(2,879	)		722			(17,416	)
	Other			492			892			3,308			2,543
		Total other income (expense)		(32,084	)		(8,045	)		(20,372	)		(38,631	)
Income (loss) before income taxes				(7,949	)		(64,817	)		57,572			(180,056	)
Income tax (expense) benefit				2,626			21,925			(20,634	)		64,096
NET INCOME (LOSS)				(5,323	)		(42,892	)		36,938			(115,960	)
	Less income attributable to noncontrolling interest, net of tax			-			-			-			(1,455	)
NET INCOME (LOSS) attributable to Clayton Williams Energy, Inc.			$	(5,323	)	$	(42,892	)	$	36,938		$	(117,415	)
Net income (loss) per common share attributable to
Clayton Williams Energy, Inc. stockholders:
	Basic		$	(0.44	)	$	(3.53	)	$	3.04		$	(9.67	)
	Diluted		$	(0.44	)	$	(3.53	)	$	3.04		$	(9.67	)
Weighted average common shares outstanding:
	Basic			12,153			12,144			12,148			12,138
	Diluted			12,153			12,144			12,148			12,138

CLAYTON WILLIAMS ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(In thousands)
ASSETS
			December 31,			December 31,
				2010			2009
			(Unaudited)
CURRENT ASSETS
	Cash and cash equivalents		$	8,720		$	14,013
	Accounts receivable:
		Oil and gas sales		35,361			28,721
		Joint interest and other, net		9,893			6,669
		Affiliates		796			624
	Inventory			39,218			43,068
	Deferred income taxes			5,074			1,362
	Assets held for sale			8,762			7,411
	Prepaids and other			5,997			1,729
				113,821			103,597
PROPERTY AND EQUIPMENT
	Oil and gas properties, successful efforts method			1,707,252			1,579,664
	Natural gas gathering and processing systems			18,153			17,816
	Contract drilling equipment			58,486			41,533
	Other			17,425			16,550
				1,801,316			1,655,563
	Less accumulated depreciation, depletion and amortization			(1,034,227	)		(985,517	)
		Property and equipment, net		767,089			670,046
OTHER ASSETS
	Debt issue costs, net			8,323			4,874
	Fair value of derivatives			-			4,427
	Other			1,684			1,660
				10,007			10,961
			$	890,917		$	784,604
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
	Accounts payable:
		Trade	$	74,123		$	47,211
		Oil and gas sales		28,920			18,063
		Affiliates		1,251			1,097
	Fair value of derivatives			7,224			5,907
	Accrued liabilities and other			22,202			11,995
				133,720			84,273
NON-CURRENT LIABILITIES
	Long-term debt			385,000			395,000
	Deferred income taxes			78,035			54,065
	Fair value of derivatives			3,409			-
	Other			41,301			38,991
				507,745			488,056
STOCKHOLDERS' EQUITY
	Preferred stock, par value $.10 per share			-			-
	Common stock, par value $.10 per share			1,215			1,215
	Additional paid-in capital			152,290			152,051
	Retained earnings			95,947			59,009
		Total stockholders' equity		249,452			212,275
			$	890,917		$	784,604

CLAYTON WILLIAMS ENERGY, INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
(In thousands)
			Three Months Ended						Year Ended
			December 31,						December 31,
				2010			2009			2010			2009
CASH FLOWS FROM OPERATING ACTIVITIES
	Net income (loss)		$	(5,323	)	$	(42,892	)	$	36,938		$	(115,960	)
	Adjustments to reconcile net income (loss) to cash
	provided by operating activities:
	Depreciation, depletion and amortization			24,873			36,954			101,145			129,658
	Impairment of property and equipment			-			27,072			11,908			59,140
	Exploration costs			2,941			37,732			9,074			78,798
	(Gain) loss on sales of assets and impairment of inventory, net			(197	)		2,100			(1,930	)		4,486
	Deferred income tax expense (benefit)			(2,626	)		(22,049	)		20,634			(64,220	)
	Non-cash employee compensation			5,832			481			13,898			1,434
	Unrealized (gain) loss on derivatives			27,027			(6,834	)		9,153			1,480
	Amortization of debt issue costs			474			295			1,648			1,458
	Accretion of abandonment obligations			670			830			2,623			3,120
	Changes in operating working capital:
	Accounts receivable			(11,779	)		(8,206	)		(10,036	)		4,571
	Accounts payable			13,897			6,485			19,144			(19,590	)
	Other			(1,706	)		3,595			(5,948	)		20,336
		Net cash provided by operating activities		54,083			35,563			208,251			104,711
CASH FLOWS FROM INVESTING ACTIVITIES
	Additions to property and equipment			(77,014	)		(43,300	)		(285,655	)		(142,623	)
	Proceeds from sales of assets			1,546			46			77,216			729
	Change in equipment inventory			7,713			(807	)		4,638			(26,675	)
	Other			149			80			18			(29	)
		Net cash used in investing activities		(67,606	)		(43,981	)		(203,783	)		(168,598	)
CASH FLOWS FROM FINANCING ACTIVITIES
	Proceeds from long-term debt			-			-			-			75,900
	Repayments of long-term debt			-			-			(10,000	)		(39,375	)
	Proceeds from exercise of stock options			239			24			239			176
		Net cash provided by (used in) financing activities		239			24			(9,761	)		36,701
NET DECREASE IN CASH
AND CASH EQUIVALENTS				(13,284	)		(8,394	)		(5,293	)		(27,186	)
CASH AND CASH EQUIVALENTS
	Beginning of period			22,004			22,407			14,013			41,199
	End of period		$	8,720		$	14,013		$	8,720		$	14,013

CLAYTON WILLIAMS ENERGY, INC.
COMPUTATION OF EBITDAX
(Unaudited)
(In thousands)
EBITDAX is presented as a supplemental non-GAAP financial measure because of its wide acceptance by financial analysts, investors, debt holders, banks, rating agencies and other financial statement users as an indication of an entity's ability to meet its debt service obligations and to internally fund its exploration and development activities.
The Company defines EBITDAX as net income (loss) before interest expense, income taxes, exploration costs, (gain)/loss on sales of assets and impairment of inventory and all non-cash items in the Company's statements of operations, including depreciation, depletion and amortization, impairment of property and equipment, accretion of abandonment obligations, certain employee compensation and changes in fair value of derivatives. EBITDAX is not an alternative to net income (loss) or cash flow from operating activities, or any other measure of financial performance presented in conformity with GAAP.
The following table reconciles net income (loss) to EBITDAX:
			Three Months Ended						Year Ended
			December 31,						December 31,
				2010			2009			2010			2009
Net income (loss)			$	(5,323	)	$	(42,892	)	$	36,938		$	(115,960	)
	Interest expense			6,009			6,058			24,402			23,758
	Income tax (benefit) expense			(2,626	)		(21,925	)		20,634			(64,096	)
	Exploration:
		Abandonments and impairments		2,941			37,732			9,074			78,798
		Seismic and other		2,051			1,633			6,046			8,189
	(Gain) loss on sales of assets and impairment of inventory			(197	)		2,100			(1,930	)		4,486
	Depreciation, depletion and amortization			24,873			36,954			101,145			129,658
	Impairment of property and equipment			-			27,072			11,908			59,140
	Accretion of abandonment obligations			670			830			2,623			3,120
	Non-cash employee compensation			5,832			481			13,898			1,434
	Non-cash changes in fair value of derivatives			27,027			(6,834	)		9,153			1,480
			$	61,257		$	41,209		$	233,891		$	130,007

Clayton Williams Energy, Inc.
Summary Production and Price Data
(Unaudited)
				Three Months Ended						Year Ended
				December 31,						December 31,
				2010			2009			2010			2009
Average Daily Production:
	Oil (Bbls):
		Permian Basin			5,973			4,534			5,601			4,142
		Austin Chalk/ Eagle Ford Shale			3,292			2,476			2,944			2,734
		North Louisiana			-			182			71			238
		South Louisiana			447			722			559			649
		Other			71			86			72			86
			Total		9,783			8,000			9,247			7,849
	Natural Gas (Mcf):
		Permian Basin			13,566			13,499			13,668			14,739
		Giddings Area:
		Austin Chalk/ Eagle Ford Shale			2,049			2,204			2,179			2,485
		Cotton Valley Reef Complex			3,092			3,872			3,599			3,960
		North Louisiana			-			9,302			3,581			11,325
		South Louisiana			3,010			8,398			5,265			9,851
		Other			946			1,638			1,160			1,336
			Total		22,663			38,913			29,452			43,696
	Natural gas liquids (Bbls):
		Permian Basin			599			237			440			241
		Austin Chalk/ Eagle Ford Shale			231			267			237			288
		North Louisiana			-			23			8			22
		South Louisiana			69			173			89			98
		Other			25			7			26			9
			Total		924			707			800			658
Total Production:
	Oil (MBbls)				900			736			3,375			2,865
	Natural Gas (MMcf)				2,085			3,580			10,750			15,949
	Natural gas liquids (MBbls)				85			65			292			240
	Total (MBOE)				1,333			1,398			5,459			5,763
Average Realized Prices (a):
	Oil ($/Bbl)			$	82.07		$	72.78		$	76.44		$	57.37
	Gas ($/Mcf)			$	5.02		$	5.20		$	5.17		$	4.35
	Natural gas liquids ($/Bbl)			$	47.56		$	41.97		$	42.47		$	30.83
Gain (Loss) on settled derivative contracts (a):
	($ in thousands, except per unit)
	Oil:
	Net realized loss			$	(4,587	)	$	(12,013	)	$	(7,685	)	$	(25,713	)
	Per unit produced ($/Bbl)			$	(5.10	)	$	(16.32	)	$	(2.28	)	$	(8.97	)
	Gas:
	Net realized gain			$	5,047		$	2,299		$	17,560		$	9,777
	Per unit produced ($/Mcf)			$	2.42		$	0.64		$	1.63		$	0.61
(a)	Hedging gains/losses are only included in the determination of the Company's average realized prices if the underlying derivative contracts are designated as cash flow hedges under applicable accounting standards. The Company did not designate any of its 2010 or 2009 derivative contracts as cash flow hedges. This means that the Company's derivatives for 2010 and 2009 have been marked-to-market through its statement of operations as other income/expense instead of through accumulated other comprehensive income on the Company's balance sheet. This also means that all realized gains/losses on these derivatives are reported in other income/expense instead of as a component of oil and gas sales.

Clayton Williams Energy, Inc.
Summary of Open Commodity Derivatives
(Unaudited)
The following summarizes information concerning the Company’s net positions in open commodity derivatives applicable to periods subsequent to December 31, 2010.
		Oil			Gas
Swaps:		Bbls	Price		MMBtu (a)	Price
	Production Period:
	1st Quarter 2011	657,000	$	83.74	1,710,000	$	7.07
	2nd Quarter 2011	632,000	$	83.71	1,650,000	$	7.07
	3rd Quarter 2011	547,000	$	83.78	1,560,000	$	7.07
	4th Quarter 2011	540,000	$	83.78	1,500,000	$	7.07
	2012	1,170,000	$	90.65	-	$	-
		3,546,000			6,420,000
(a) One MMBtu equals one Mcf at a Btu factor of 1,000.

CLAYTON WILLIAMS ENERGY, INC.
PROVED RESERVES
(Unaudited)
The following table sets forth our estimated quantities of proved reserves as of December 31, 2010 and 2009, all of which are located in the United States.
		Proved Reserves
			Natural	Total Oil
		Oil (a)	Gas	Equivalents (b)
Reserve Category		(MBbls)	(MMcf)	(MBOE)
December 31, 2010:
	Developed	24,570	59,409	34,472
	Undeveloped	13,245	20,088	16,593
	Total Proved	37,815	79,497	51,065
December 31, 2009:
	Developed	16,779	70,840	28,586
	Undeveloped	4,174	5,263	5,051
	Total Proved	20,953	76,103	33,637
(a)	Oil reserves include crude oil, condensate and natural gas liquids ("NGL").
(b)	Natural gas reserves have been converted to oil equivalents at the rate of six Mcf to one barrel of oil.

The present value of future net cash flows from proved reserves, before deductions for estimated future income taxes and asset retirement obligations, discounted at 10% ("PV-10 Value"), totaled $992 million at December 31, 2010, as compared to $460.4 million at December 31, 2009. Average adjusted commodity prices used at December 31, 2010 and December 31, 2009 were based on the 12-month weighted average of the first-day-of-the-month prices from January through December of the respective years, which for the Company averaged $72.36 per barrel of oil and NGL and $5.44 per Mcf of natural gas for 2010 and $54.81 per barrel of oil and NGL and $3.71 per Mcf of natural gas for 2009.

PV-10 Value is a non-GAAP financial measure that we believe is useful as a supplemental disclosure to the standardized measure of discounted future net cash flows, a GAAP financial measure. While the standardized measure of discounted future net cash flows is dependent on the unique tax situation of each entity, PV-10 Value is based on prices and discount factors that are consistent for all entities and can be used within the industry and by securities analysts to evaluate proved reserves on a more comparable basis. The following table reconciles PV-10 Value to standardized measure of discounted future net cash flows.

		As of December 31,
		2010			2009
		(In thousands)
PV-10 Value, a non-GAAP financial measure		$	991,748		$	460,386
Less present value, discounted at 10%, of:
	Estimated asset retirement obligations		(30,445	)		(29,338	)
	Estimated future income taxes		(276,865	)		(66,775	)
Standardized measure of discounted future net cash flows,
a GAAP financial measure		$	684,438		$	364,273

CONTACT:
Clayton Williams Energy, Inc.
Patti Hollums, 432-688-3419
Director of Investor Relations
e-mail: cwei@claytonwilliams.com
website: www.claytonwilliams.com
or
Michael L. Pollard, 432-688-3029
Chief Financial Officer