Clayton Williams Energy (CWEI) 8-K Clayton Williams Energy Announces Second Quarter 2011 Financial Results

Exhibit 99.1

Clayton Williams Energy Announces Second Quarter 2011 Financial Results

MIDLAND, Texas--(BUSINESS WIRE)--July 28, 2011--Clayton Williams Energy, Inc. (the “Company”) (NASDAQ: CWEI) today reported its financial results for the second quarter of 2011 and its outlook for capital spending and production for the remainder of 2011.

Financial Results for the Second Quarter of 2011

Net income attributable to Company stockholders for the second quarter of 2011 (“2Q11”) was $42.7 million, or $3.51 per share, as compared to net income of $14 million, or $1.15 per share, for the second quarter of 2010 (“2Q10”). Cash flow from operations for 2Q11 was $86.4 million as compared to $66.3 million for 2Q10.

For the six months ended June 30, 2011, net income attributable to Company stockholders was $34.8 million, or $2.86 per share, as compared to a net income of $30.6 million, or $2.52 per share, for the same period in 2010. Cash flow from operations for the six-month period in 2011 was $119.7 million as compared to $96.7 million during the same period in 2010.

The key factors affecting the comparability of financial results for 2Q11 versus 2Q10 were:

• Oil and gas sales increased $28.9 million in 2Q11 versus 2Q10. Price variances accounted for $25.2 million of the increase and production variances accounted for the remaining $3.7 million. Average realized oil prices were $100.07 per barrel in 2Q11 versus $74.27 per barrel in 2Q10, and average realized gas prices were $5.56 per Mcf in 2Q11 versus $5.14 per Mcf in 2Q10.
• Oil production increased 10% in 2Q11 versus 2Q10 while gas production declined 19%. Oil and gas production per barrel of oil equivalent (“BOE”) was constant in 2Q11 as compared to 2Q10. Oil production increased to 886,000 barrels, or 9,736 barrels per day, as compared to 808,000 barrels, or 8,879 barrels per day, while gas production declined to 2.3 Bcf, or 24,846 Mcf per day as compared to 2.8 Bcf or 30,846 Mcf per day for 2Q10. On a comparable basis, after giving effect to the sale of properties in North Louisiana in June 2010, oil and gas production in 2Q11 on a BOE basis was 8% higher than 2Q10. The increase in oil production and the decline in gas production are indicative of the Company’s current emphasis on the development of oil reserves in the Permian Basin.
• Production costs increased 27% from $20.6 million in 2Q10 to $26.1 million in 2Q11 due to a combination of more producing wells, rising costs of field services and increased production taxes on higher oil and gas sales.
• Gain on derivatives for 2Q11 was $28.2 million ($35.6 million non-cash mark-to-market gain and a $7.4 million realized loss on settled contracts) versus a gain in 2Q10 of $21 million ($17.3 million non-cash mark-to-market gain and a $3.7 million realized gain on settled contracts). See accompanying tables for additional information about the Company’s accounting for derivatives.
• Interest expense increased to $9.2 million in 2Q11 compared to $6.2 million in 2Q10 due in part to the increase in the total aggregate principal amount of the Company’s Senior Notes.
• G&A expenses were $3 million in 2Q11 versus $7.8 million in 2Q10. Non-cash employee compensation expense from incentive compensation plans accounted for a $2.4 million credit to expense in 2Q11 versus a $3.1 million charge for 2Q10. Excluding non-cash employee compensation expense, G&A expenses increased 15% in 2Q11 compared to 2Q10.
• Non-cash impairments of property and equipment were $4.4 million in 2Q11 versus $11.1 million in 2Q10. The 2Q11 impairment related to certain non-core oil and gas properties in the Permian Basin.

Comparisons to Guidance

Oil and gas production for 2Q11 was 14,679 BOE per day, just slightly below the low end of the Company’s guidance range of 14,892 BOE per day and 5% below the mid-point of the guidance range of 15,375 BOE per day. Production shortfalls in Andrews County totaling approximately 1,000 BOE per day were partially offset by surplus production from other areas of approximately 300 BOE per day. Just over half of the Andrews County shortfall resulted from a combination of completion delays and production disruptions caused by wildfires. In addition, the pipelines carrying the Company’s natural gas production in this area is at maximum capacity, causing oil and gas production to be choked back due to high line pressures. The Company is considering various actions to alleviate this operating condition.

Outlook

The Company expects to provide an update to its financial guidance disclosures for 2011 in August. As a result of its shift in focus to the Reeves County Wolfbone play, the Company expects capital spending to increase and production to decrease from the existing guidance estimates.

Drilling and completion costs are expected to increase to a range of $440 million to $460 million, as compared to existing guidance of $410 million. The following factors contributed to the upward cost revision:

• Increase in the rig count in the Wolfbone play to 11 in the near term, from four rigs in the existing guidance, while reducing the rig count in the Andrews Wolfberry play from seven rigs to one rig, and reducing the rig count in the Austin Chalk area from two rigs to one rig;
• Increase in the estimated cost to drill and complete Wolfbone wells from $3.5 million to $4 million; and
• Current plans to incur approximately $10 million to begin construction of pipelines and infrastructure for gathering and disposition of produced oil, gas and water.

Near-term production estimates are expected to decrease as the Company’s drilling focus transitions from the Wolfberry play to the Wolfbone play. The Company’s share of production from initial Wolfbone wells is substantially less than its share of Wolfberry production due to the terms of a drill-to-earn farm-out agreement with Chesapeake Exploration which requires the Company to carry Chesapeake on specified wells in order to earn acreage. The effect of this structure is that the Company gives up a portion of its initial production in lieu of paying substantial upfront acreage costs.

Scheduled Conference Call

The Company will host a conference call to discuss these results and other forward-looking items today, July 28th at 1:30 pm CT (2:30 pm ET). The dial-in conference number is: 800-901-5213, passcode 66471213. The replay will be available for one week at 888-286-8010, passcode 92233345.

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						Six Months Ended
	June 30,						June 30,
	2011			2010			2011			2010
REVENUES
Oil and gas sales	$	105,804		$	76,918		$	200,736		$	155,960
Natural gas services		365			452			774			955
Drilling rig services		2,425			-			2,685			-
Gain on sales of assets		949			113			14,521			399
Total revenues		109,543			77,483			218,716			157,314
COSTS AND EXPENSES
Production		26,133			20,567			50,953			41,494
Exploration:
Abandonments and impairments		174			2,891			1,051			5,769
Seismic and other		2,167			974			3,445			2,634
Natural gas services		285			306			548			654
Drilling rig services		1,919			419			2,705			1,081
Depreciation, depletion and amortization		25,342			25,437			49,086			51,049
Impairment of property and equipment		4,424			11,114			4,424			11,114
Accretion of abandonment obligations		697			647			1,371			1,294
General and administrative		3,037			7,832			15,536			14,056
Loss on sales of assets and impairment of inventory		107			1,443			303			1,443
Total costs and expenses		64,285			71,630			129,422			130,588
Operating income		45,258			5,853			89,294			26,726
OTHER INCOME (EXPENSE)
Interest expense		(9,175	)		(6,244	)		(15,587	)		(12,353	)
Loss on early extinguishment of long-term debt		-			-			(4,594	)		-
Gain (loss) on derivatives		28,187			20,983			(18,158	)		31,284
Other		1,900			1,016			2,987			1,844
Total other income (expense)		20,912			15,755			(35,352	)		20,775
Income before income taxes		66,170			21,608			53,942			47,501
Income tax expense		(23,502	)		(7,645	)		(19,149	)		(16,863	)
NET INCOME	$	42,668		$	13,963		$	34,793		$	30,638
Net income per common share:
Basic	$	3.51		$	1.15		$	2.86		$	2.52
Diluted	$	3.51		$	1.15		$	2.86		$	2.52
Weighted average common shares outstanding:
Basic		12,162			12,146			12,159			12,146
Diluted		12,163			12,146			12,159			12,146

CLAYTON WILLIAMS ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(In thousands)
ASSETS
	June 30,			December 31,
	2011			2010
	(Unaudited)
CURRENT ASSETS
Cash and cash equivalents	$	18,079		$	8,720
Accounts receivable:
Oil and gas sales		30,629			35,361
Joint interest and other, net		7,757			9,893
Affiliates		600			796
Inventory		34,732			39,218
Deferred income taxes		3,808			5,074
Assets held for sale		-			8,762
Prepaids and other		16,532			5,997
		112,137			113,821
PROPERTY AND EQUIPMENT
Oil and gas properties, successful efforts method		1,873,222			1,707,252
Natural gas gathering and processing systems		18,439			18,153
Contract drilling equipment		72,930			58,486
Other		18,512			17,425
		1,983,103			1,801,316
Less accumulated depreciation, depletion and amortization		(1,092,607	)		(1,034,227	)
Property and equipment, net		890,496			767,089
OTHER ASSETS
Debt issue costs, net		13,064			8,323
Other		1,938			1,684
		15,002			10,007
	$	1,017,635		$	890,917
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable:
Trade	$	63,242		$	74,123
Oil and gas sales		33,215			28,920
Affiliates		1,683			1,251
Fair value of derivatives		11,712			7,224
Accrued liabilities and other		29,384			22,202
		139,236			133,720
NON-CURRENT LIABILITIES
Long-term debt		448,347			385,000
Deferred income taxes		96,106			78,035
Fair value of derivatives		7,990			3,409
Other		41,498			41,301
		593,941			507,745
STOCKHOLDERS' EQUITY
Preferred stock, par value $.10 per share		-			-
Common stock, par value $.10 per share		1,216			1,215
Additional paid-in capital		152,502			152,290
Retained earnings		130,740			95,947
Total stockholders' equity		284,458			249,452
	$	1,017,635		$	890,917

CLAYTON WILLIAMS ENERGY, INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
(In thousands)
			Three Months Ended						Six Months Ended
			June 30,						June 30,
			2011			2010			2011			2010
CASH FLOWS FROM OPERATING ACTIVITIES
	Net income		$	42,668		$	13,963		$	34,793		$	30,638
	Adjustments to reconcile net income to cash
	provided by operating activities:
	Depreciation, depletion and amortization			25,342			25,437			49,086			51,049
	Impairment of property and equipment			4,424			11,114			4,424			11,114
	Exploration costs			174			2,891			1,051			5,769
	(Gain) loss on sales of assets and impairment of inventory, net			(842	)		1,330			(14,218	)		1,044
	Deferred income tax expense			23,502			7,645			19,149			16,863
	Non-cash employee compensation			(2,438	)		3,069			4,963			5,079
	Unrealized (gain) loss on derivatives			(35,558	)		(17,269	)		9,069			(25,871	)
	Accretion of abandonment obligations			697			647			1,371			1,294
	Amortization of debt issue costs			562			439			1,130			774
	Loss on early extinguishment of long-term debt			-			-			4,594			-
	Changes in operating working capital:
	Accounts receivable			12,785			6,702			7,064			5,234
	Accounts payable			7,931			5,586			(4,023	)		(3,403	)
	Other			7,186			4,747			1,271			(2,907	)
		Net cash provided by operating activities		86,433			66,301			119,724			96,677
CASH FLOWS FROM INVESTING ACTIVITIES
	Additions to property and equipment			(97,288	)		(77,252	)		(180,281	)		(135,528	)
	Proceeds from sales of assets			1,103			72,532			12,105			73,011
	Change in equipment inventory			(5,733	)		(1,152	)		4,783			1,300
	Other			10			(3	)		(110	)		(98	)
		Net cash used in investing activities		(101,908	)		(5,875	)		(163,503	)		(61,315	)
CASH FLOWS FROM FINANCING ACTIVITIES
	Proceeds from long-term debt			48,855			-			341,855			-
	Repayments of long-term debt			(30,000	)		(65,000	)		(286,165	)		(39,000	)
	Premium on early extinguishment of long-term debt			-			-			(2,765	)		-
	Proceeds from exercise of stock options			187			-			213			-
		Net cash provided by (used in) financing activities		19,042			(65,000	)		53,138			(39,000	)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS				3,567			(4,574	)		9,359			(3,638	)
CASH AND CASH EQUIVALENTS
	Beginning of period			14,512			14,949			8,720			14,013
	End of period		$	18,079		$	10,375		$	18,079		$	10,375

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, loss on early extinguishment of debt 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 to EBITDAX:
			Three Months Ended						Six Months Ended
			June 30,						June 30,
			2011			2010			2011			2010
Net income			$	42,668		$	13,963		$	34,793		$	30,638
	Interest expense			9,175			6,244			15,587			12,353
	Income tax expense			23,502			7,645			19,149			16,863
	Exploration:
		Abandonments and impairments		174			2,891			1,051			5,769
		Seismic and other		2,167			974			3,445			2,634
	Net (gain) loss on sales of assets and impairment of inventory			(842	)		1,330			(14,218	)		1,044
	Loss on early extinguishment of debt			-			-			4,594			-
	Depreciation, depletion and amortization			25,342			25,437			49,086			51,049
	Impairment of property and equipment			4,424			11,114			4,424			11,114
	Accretion of abandonment obligations			697			647			1,371			1,294
	Non-cash employee compensation			(2,438	)		3,069			4,963			5,079
	Non-cash changes in fair value of derivatives			(35,558	)		(17,269	)		9,069			(25,871	)
			$	69,311		$	56,045		$	133,314		$	111,966

Clayton Williams Energy, Inc.
Summary Production and Price Data
(Unaudited)
				Three Months Ended							Six Months Ended
				June 30,							June 30,
				2011			2010				2011			2010
Oil and Gas Production Data:
	Oil (MBbls)				886			808				1,785			1,560
	Gas (MMcf)				2,261			2,807				4,374			6,135
	Natural gas liquids (MBbls)				73			60				156			117
	Total (MBOE)				1,336			1,336				2,670			2,700
Average Realized Prices (a):
	Oil ($/Bbl)			$	100.07		$	74.27			$	94.47		$	75.10
	Gas ($/Mcf)			$	5.56		$	5.14			$	5.40		$	5.48
	Natural gas liquids ($/Bbl)			$	57.16		$	40.13			$	52.47		$	43.08
Gain (Loss) on settled derivative contracts (a):
	($ in thousands, except per unit)
	Oil:
	Net realized loss			$	(11,919	)	$	(1,249	)		$	(18,697	)	$	(2,871	)
	Per unit produced ($/Bbl)			$	(13.45	)	$	(1.55	)		$	(10.47	)	$	(1.84	)
	Gas:
	Net realized gain			$	4,548		$	4,964			$	9,608		$	8,283
	Per unit produced ($/Mcf)			$	2.01		$	1.77			$	2.20		$	1.35
Average Daily Production:
	Oil (Bbls):
		Permian Basin			5,680			5,390				5,927			5,151
		Austin Chalk/ Eagle Ford Shale			3,335			2,835				3,333			2,717
		South Louisiana			493			435				454			530
		Other			228			219		(b)		148			221		(b)
			Total		9,736			8,879				9,862			8,619
	Natural Gas (Mcf):
		Permian Basin			12,176			13,263				13,043			13,586
		Giddings Area:
		Austin Chalk/ Eagle Ford Shale			2,177			1,810				2,060			2,169
		Cotton Valley Reef Complex			2,931			4,072				2,942			3,802
		South Louisiana			6,134			4,930				4,650			6,213
		Other			1,428			6,771		(b)		1,471			8,125		(b)
			Total		24,846			30,846				24,166			33,895
	Natural gas liquids (Bbls):
		Permian Basin			519			356				568			314
		Austin Chalk/ Eagle Ford Shale			183			185				205			228
		South Louisiana			60			86				52			83
		Other			40			32		(b)		37			21		(b)
			Total		802			659				862			646
				Three Months Ended							Six Months Ended
				June 30,							June 30,
					2011			2010				2011			2010
Oil and Gas Costs ($/BOE Produced):
	Production costs			$	19.56		$	15.39			$	19.08		$	15.37
	Production costs (excluding production taxes)			$	15.61		$	12.25			$	15.14		$	12.22
	Oil and gas depletion			$	18.31		$	18.57			$	17.89		$	18.30
General and Administrative Expenses (in thousands):
	Excluding non-cash employee compensation			$	5,475		$	4,763			$	10,573		$	8,977
	Non-cash employee compensation (c)				(2,438	)		3,069				4,963			5,079
	Total			$	3,037		$	7,832			$	15,536		$	14,056
(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 2011 or 2010 derivative contracts as cash flow hedges. This means that the Company's derivatives for 2011 and 2010 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.
(b)	Other for 2010 includes production attributable to sold properties in North Louisiana as follows: Three months: Oil 137, Gas 5,747, NGL 26 and Six months: Oil 142, Gas 7,225, NGL 15.
(c)	Non-cash employee compensation relates to the Company's non-equity award plans. In June 2011, the Compensation Committee of the Board of Directors approved the modification of certain existing reward plans. The impact of this modification resulted in a credit to expense of $2.4 million during 2Q11.

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 June 30, 2011.
		Oil			Gas
Swaps:		Bbls	Price		MMBtu (a)	Price
	Production Period:
	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	1,864,000	$	93.65	-	$	-
	2013	480,000	$	96.70	-	$	-
		3,431,000			3,060,000
(a)	One MMBtu equals one Mcf at a Btu factor of 1,000.

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