Clayton Williams Energy (CWEI) 8-K Clayton Williams Energy Announces 2012 Financial Results and Year-end Reserves

Exhibit 99.1

CLAYTON WILLIAMS ENERGY ANNOUNCES 2012 FINANCIAL RESULTS AND YEAR-END RESERVES

Midland, Texas, February 21, 2013 (BUSINESS WIRE) - Clayton Williams Energy, Inc. (the “Company”) (NASDAQ-CWEI) today reported its financial results for the quarter and year ended December 31, 2012.

Highlights

• Oil and Gas Production of 5.6 Million BOE, up 3%

• Total Proved Reserves of 75.4 Million BOE, up 17%

• 365% of 2012 Production Replaced by Reserve Additions

• 77% Oil and NGL and 58% Proved Developed

Financial Results for Fiscal Year 2012

Net income attributable to Company stockholders for fiscal 2012 was $35.1 million, or $2.89 per share, as compared to net income of $93.8 million, or $7.71 per share, for fiscal 2011. Cash flow from operations for 2012 was $189.2 million as compared to $280 million for 2011. The key factors affecting the comparability of the two years were:

• Oil and gas sales, excluding amortized deferred revenues, decreased $10.4 million in 2012 compared to 2011. Price variances accounted for a decrease of $25.6 million, and production variances accounted for a $15.2 million increase. Average realized oil prices were $90.97 per barrel in 2012 versus $92.43 per barrel in 2011, and average realized gas prices were $3.59 per Mcf in 2012 versus $5.30 per Mcf in 2011. Oil and gas sales in 2012 also includes $8.3 million of amortized deferred revenue attributable to a volumetric production payment (“VPP”) granted effective March 1, 2012 in connection with the mergers of 24 Southwest Royalties, Inc. limited partnerships ("SWR mergers"). Reported production and related average realized sales prices exclude volumes associated with the VPP.

• Oil and gas production for 2012 on a barrel of oil equivalent (“BOE”) basis was 3% higher compared to 2011. Oil production increased 3% compared to 2011, while gas production declined 6%. Oil and natural gas liquids ("NGL") production accounted for 76% of total production in 2012 versus 74% in 2011.

• Production costs increased 24% to $125 million in 2012 from $101.1 million in 2011 due to a combination of an increase in the number of producing wells, higher costs of field services, including salt water disposal costs, and higher property taxes on Texas properties resulting from rising appraisal values.

• Gain on derivatives for 2012 was $14.4 million ($17.8 million non-cash mark-to-market gain and a $3.4 million realized loss on settled contracts) versus a gain in 2011 of $47 million ($4.5 million non-cash mark-to-market gainand a $42.5 million realized gain on settled contracts). Cash settlements in 2011 included $50 million from the early termination of

contracts covering oil production for 2012 and 2013. See accompanying tables for additional information about the Company's accounting for derivatives.

• Depreciation, depletion and amortization expense increased 36% to $142.7 million in 2012 versus $104.9 million in 2011 due primarily to a 27% increase in the average depletion rate per BOE of production. Most of the increase in depletion rate related to downward revisions in proved reserves in the Company's Andrews County Wolfberry play.

• Exploration expenses related to abandonments and impairments were $4.2 million in 2012 compared to $20.8 million in 2011.

• Interest expense increased to $38.7 million in 2012 from $32.9 million in 2011 due primarily to the increase in the revolving credit facility from an average daily principal balance of $113.4 million in 2011 to $349.1 million in 2012.

• Net gain on sales of assets and impairment of inventory was a $463,000 gain in 2012 compared to a gain of $14.1 million in 2011. In 2011, the Company sold two 2,000 horsepower drilling rigs and related equipment for a gain of $13.2 million.

• General and administrative expenses ("G&A") for 2012 were $30.5 million versus $41.6 million in 2011. Non-cash employee compensation from incentive compensation plans accounted for a credit to expense of $404,000 in 2012 versus $12.9 million expense in 2011. Excluding non-cash employee compensation, G&A increased to $30.9 million in 2012 versus $28.7 million in 2011. The 2012 period included $2 million of non-recurring donations to charitable and 527 organizations.

Financial Results for the Fourth Quarter of 2012

Net income attributable to Company stockholders for the fourth quarter of 2012 (“4Q12”) was $1.7 million, or $0.14 per share, as compared to a net loss of $15.5 million, or $1.27 per share, for the fourth quarter of 2011 (“4Q11”). Cash flow from operations for 4Q12 was $31.3 million as compared to $104.8 million for 4Q11. The key factors affecting the comparability of financial results for 4Q12 versus 4Q11 were:

• Oil and gas sales, excluding amortized deferred revenues, decreased $12.1 million in 4Q12 versus 4Q11. Production variances accounted for a $9.5 million decrease, and price variances accounted for a $2.6 million decrease. Average realized oil prices were $85.86 per barrel in 4Q12 versus $91.70 per barrel in 4Q11, and average realized gas prices were $4.02 per Mcf in 4Q12 versus $4.91 per Mcf in 4Q11. Oil and gas sales in 4Q12 also includes $2.4 million of amortized deferred revenue attributable to the VPP. Reported production and related average realized sales prices exclude volumes associated with the VPP.

• Oil and gas production for 4Q12 was 1% lower on a BOE basis compared to 4Q11. Oil production decreased 7% compared to 4Q11 and gas production declined 5%. Oil and NGL production accounted for 77% of total Company's BOE production in 4Q12 versus 76% in 4Q11.

• Production costs increased 20% to $31 million in 4Q12 from $25.9 million in 4Q11 due to a combination of an increase in the number of producing wells, higher costs of field services,

including salt water disposal costs, and higher property taxes on Texas properties resulting from rising appraisal values.

• Gain on derivatives for 4Q12 was $4.6 million ($3 million non-cash mark-to-market gain and $1.6 million realized gain on settled contracts) versus a loss in 4Q11 of $27.1 million ($77.5 million non-cash mark-to-market loss offset by a $50.4 million realized gain on settled contracts). Cash settlements in 4Q11 included $50 million from the early termination of contracts covering oil production for 2012 and 2013. See accompanying tables for additional information about the Company's accounting for derivatives.

• Depreciation, depletion and amortization expense increased 31% to $39.2 million in 4Q12 versus $29.9 million in 4Q11 due primarily to a 25% increase in the average depletion rate per BOE of production. Most of the increase in depletion rate related to downward revisions in proved reserves in the Company's Andrews County Wolfberry play.

• G&A expenses were $5.4 million in 4Q12 versus $18.9 million in 4Q11. Non-cash employee compensation expense from incentive compensation plans accounted for a $2.6 million credit to expense in 4Q12 versus $6.8 million expense in 4Q11. Excluding non-cash employee compensation expense, G&A expenses decreased to $8 million in 4Q12 from $12.1 million in 4Q11. The 2011 period included $2.5 million of additional personnel costs related to discretionary bonuses and $1 million of costs related to the SWR mergers.

Reserves

The Company reported that its total estimated proved oil and gas reserves as of December 31, 2012 were 75.4 million barrels of oil equivalent (“MMBOE”), consisting of 49.1 million barrels of oil, 9.2 million barrels of NGL and 102.3 Bcf of natural gas. On a BOE basis, oil and NGL comprised 77% of total proved reserves at year-end 2012 and 2011. Proved developed reserves at year-end 2012 were 43.4 MMBOE, or 58% of total proved reserves, as compared to 39.3 MMBOE, or 61% of total proved reserves, at year-end 2011. 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 $1.3 billion for year-end 2012 as compared to $1.4 billion for year-end 2011. 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 2012 on an MMBOE basis.

	MMBOE
Total proved reserves, December 31, 2011	64.3
Extensions and discoveries	20.5
Purchases of reserves	3.5
Revisions	(6.6)
Sales of reserves	(0.7)
Production	(5.6)
Total proved reserves, December 31, 2012	75.4

The Company replaced 365% of its 2012 oil and gas production through extensions and discoveries. Most of the 20.5 MMBOE of reserve additions in 2012 were derived from growth through the drill bit in the Permian Basin drilling Wolfberry and Wolfbone wells. Oil and NGL accounted for 82% of the 2012 reserve additions.

Revisions of prior year estimates resulted from a combination of downward revisions of 4.3 MMBOE related primarily to changes in estimates based on well performance and 2.3 MMBOE of downward revisions related to the effects of lower commodity prices on economic limits of long-life properties. Substantially all of the downward performance revisions were attributable to the Company's Andrews County Wolfberry program.

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 2012 were $94.71 per barrel of oil and $2.75 per MMBtu of natural gas, as compared to $96.19 per barrel and $4.12 per MMBtu for 2011. 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 $90.45 per barrel of oil, $43.74 per barrel of NGL and $3.70 per Mcf of natural gas for year-end 2012, as compared to $91.35 per barrel of oil, $51.19 per barrel of NGL and $5.31 per Mcf of natural gas for year-end 2011.

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, 2012 instead of the SEC mandated benchmark prices, the Company's PV-10 Value for year-end 2012 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 today, February 21st at 1:30 p.m. CT (2:30 p.m. ET).  The dial-in conference number is: 877-868-1835, passcode 10745333.  The replay will be available for one week at 855-859-2056, passcode 10745333. 

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.

Contact:

Patti HollumsMichael L. Pollard

Director of Investor RelationsChief Financial Officer

(432) 688-3419(432) 688-3029

e-mail: cwei@claytonwilliams.com

website: www.claytonwilliams.com

TABLES AND SUPPLEMENTAL INFORMATION FOLLOW . . .

CLAYTON WILLIAMS ENERGY, INC. CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited) (In thousands, except per share)
	Three Months Ended December 31,						Year Ended December 31,
	2012			2011			2012			2011
REVENUES
Oil and gas sales	$	95,027		$	104,728		$	403,143		$	405,216
Midstream services	669			300			1,974			1,408
Drilling rig services	4,380			446			15,858			4,060
Other	1,534			1,174			2,077			15,744
Total revenues	101,610			106,648			423,052			426,428
COSTS AND EXPENSES
Production	31,013			25,862			124,950			101,099
Exploration:
Abandonments and impairments	1,930			18,533			4,222			20,840
Seismic and other	6,146			76			11,591			5,363
Midstream services	272			258			1,228			1,039
Drilling rig services	5,259			686			17,423			5,064
Depreciation, depletion and amortization	39,201			29,893			142,687			104,880
Impairment of property and equipment	233			896			5,944			10,355
Accretion of asset retirement obligations	1,068			680			3,696			2,757
General and administrative	5,352			18,882			30,485			41,560
Other	548			1,249			1,033			1,666
Total costs and expenses	91,022			97,015			343,259			294,623
Operating income	10,588			9,633			79,793			131,805
OTHER INCOME (EXPENSE)
Interest expense	(10,847		)	(8,615		)	(38,664		)	(32,919		)
Loss on early extinguishment of long-term debt	—			—			—			(5,501		)
Gain (loss) on derivatives	4,592			(27,101		)	14,448			47,027
Other	795			2,039			1,534			5,553
Total other income (expense)	(5,460		)	(33,677		)	(22,682		)	14,160
Income (loss) before income taxes	5,128			(24,044		)	57,111			145,965
Income tax (expense) benefit	(3,450		)	8,551			(22,008		)	(52,142		)
NET INCOME (LOSS)	$	1,678		$	(15,493	)	$	35,103		$	93,823
Net income (loss) per common share:
Basic	$	0.14		$	(1.27	)	$	2.89		$	7.72
Diluted	$	0.14		$	(1.27	)	$	2.89		$	7.71
Weighted average common shares outstanding:
Basic	12,164			12,163			12,164			12,161
Diluted	12,164			12,163			12,164			12,162

CLAYTON WILLIAMS ENERGY, INC. CONSOLIDATED BALANCE SHEETS (In thousands) ASSETS
	December 31,			December 31,
	2012			2011
CURRENT ASSETS	(Unaudited)
Cash and cash equivalents	$	10,726		$	17,525
Accounts receivable:
Oil and gas sales	32,371			41,282
Joint interest and other, net	16,767			14,517
Affiliates	353			990
Inventory	41,703			44,868
Deferred income taxes	8,560			8,948
Fair value of derivatives	7,495			—
Prepaids and other	6,495			14,813
	124,470			142,943
PROPERTY AND EQUIPMENT
Oil and gas properties, successful efforts method	2,570,803			2,103,085
Pipelines and other midstream facilities	49,839			26,040
Contract drilling equipment	91,163			75,956
Other	20,245			19,134
	2,732,050			2,224,215
Less accumulated depreciation, depletion and amortization	(1,311,692		)	(1,156,664		)
Property and equipment, net	1,420,358			1,067,551
OTHER ASSETS
Debt issue costs, net	10,259			11,644
Fair value of derivatives	4,236			—
Investments and other	15,261			4,133
	29,756			15,777
	$	1,574,584		$	1,226,271
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable:
Trade	$	73,026		$	98,645
Oil and gas sales	32,146			37,409
Affiliates	164			1,501
Fair value of derivatives	—			5,633
Accrued liabilities and other	15,578			13,042
	120,914			156,230
NON-CURRENT LIABILITIES
Long-term debt	809,585			529,535
Deferred income taxes	155,830			134,209
Fair value of derivatives	—			494
Asset retirement obligations	51,477			40,794
Deferred revenue from volumetric production payment	37,184			—
Accrued compensation under non-equity award plans	20,058			20,757
Other	920			751
	1,075,054			726,540
STOCKHOLDERS’ EQUITY
Preferred stock, par value $.10 per share	—			—
Common stock, par value $.10 per share	1,216			1,216
Additional paid-in capital	152,527			152,515
Retained earnings	224,873			189,770
Total stockholders' equity	378,616			343,501
	$	1,574,584		$	1,226,271

CLAYTON WILLIAMS ENERGY, INC. CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) (In thousands)
	Three Months Ended December 31,						Year ended December 31,
	2012			2011			2012			2011
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	1,678		$	(15,493	)	$	35,103		$	93,823
Adjustments to reconcile net income (loss) to cash provided by operating activities:
Depreciation, depletion and amortization	39,201			29,893			142,687			104,880
Impairment of property and equipment	233			896			5,944			10,355
Exploration costs	1,930			18,533			4,222			20,840
(Gain) loss on sales of assets and impairment of inventory, net	(405		)	75			(463		)	(14,078		)
Deferred income tax expense (benefit)	3,450			(8,143		)	22,008			52,550
Non-cash employee compensation	(2,604		)	6,762			(404		)	12,866
Unrealized (gain) loss on derivatives	(3,041		)	77,523			(17,858		)	(4,506		)
Accretion of asset retirement obligations	1,068			680			3,696			2,757
Amortization of debt issue costs and original issue discount	967			719			2,554			2,342
Loss on early extinguishment of long-term debt	—			—			—			5,501
Amortization of deferred revenue from volumetric production payment	(2,433		)	—			(8,295		)	—
Changes in operating working capital:
Accounts receivable	149			(11,507		)	7,299			(10,739		)
Accounts payable	(3,614		)	12,007			(9,386		)	7,551
Other	(5,240		)	(7,185		)	2,115			(4,095		)
Net cash provided by operating activities	31,339			104,760			189,222			280,047
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to property and equipment	(88,039		)	(130,539		)	(526,521		)	(413,013		)
Proceeds from volumetric production payment	447			—			45,479			—
Proceeds from sales of assets	2,911			1,436			3,778			13,902
(Increase) decrease in equipment inventory	1,249			(8,149		)	1,313			(5,305		)
Other	113			(364		)	(82		)	(497		)
Net cash used in investing activities	(83,319		)	(137,616		)	(476,033		)	(404,913		)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt	40,000			102,344			280,000			547,710
Repayments of long-term debt	—			(88,000		)	—			(411,500		)
Premium on early extinguishment of long-term debt	—			—			—			(2,765		)
Proceeds from exercise of stock options	12			13			12			226
Net cash provided by financing activities	40,012			14,357			280,012			133,671
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	(11,968		)	(18,499		)	(6,799		)	8,805
CASH AND CASH EQUIVALENTS
Beginning of period	22,694			36,024			17,525			8,720
End of period	$	10,726		$	17,525		$	10,726		$	17,525

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, net (gain) loss on sales of assets and impairment of inventory, loss on early extinguishment of long-term 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 asset retirement obligations, amortization of deferred revenue from volumetric production payment, 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 December 31,						Year ended December 31,
	2012			2011			2012			2011
Net income (loss)	$	1,678		$	(15,493	)	$	35,103		$	93,823
Interest expense	10,847			8,615			38,664			32,919
Income tax expense (benefit)	3,450			(8,551		)	22,008			52,142
Exploration:
Abandonments and impairments	1,930			18,533			4,222			20,840
Seismic and other	6,146			76			11,591			5,363
Net (gain) loss on sales of assets and impairment of inventory	(405		)	75			(463		)	(14,078		)
Loss on early extinguishment of long-term debt	—			—			—			5,501
Depreciation, depletion and amortization	39,201			29,893			142,687			104,880
Impairment of property and equipment	233			896			5,944			10,355
Accretion of asset retirement obligations	1,068			680			3,696			2,757
Amortization of deferred revenue from volumetric production payment	(2,433		)	—			(8,295		)	—
Non-cash employee compensation	(2,604		)	6,762			(404		)	12,866
Unrealized (gain) loss on derivatives	(3,041		)	77,523			(17,858		)	(4,506		)
	$	56,070		$	119,009		$	236,895		$	322,862

CLAYTON WILLIAMS ENERGY, INC. SUMMARY PRODUCTION AND PRICE DATA (Unaudited)
	Three Months Ended December 31,				Year Ended December 31,
	2012		2011		2012			2011
Oil and Gas Production Data:
Oil (MBbls)	932		997		3,821			3,727
Gas (MMcf)	1,918		2,025		8,072			8,594
Natural gas liquids (MBbls)	129		58		433			275
Total (MBOE)	1,381		1,393		5,599			5,434
Average Realized Prices (a) (b):
Oil ($/Bbl)	$	85.86	$	91.70	$	90.97		$	92.43
Gas ($/Mcf)	$	4.02	$	4.91	$	3.59		$	5.30
Natural gas liquids ($/Bbl)	$	36.35	$	54.76	$	38.95		$	53.37
Gain (Loss) on Settled Derivative Contracts (b):
($ in thousands, except per unit)
Oil:
Net realized gain (loss)	$	1,551	$	45,343	$	(3,410	)	$	23,354
Per unit produced ($/Bbl)	$	1.66	$	45.48	$	(0.89	)	$	6.27
Gas:
Net realized gain	$	—	$	5,079	$	—		$	19,167
Per unit produced ($/Mcf)	$	—	$	2.51	$	—		$	2.23
Average Daily Production:
Oil (Bbls):
Permian Basin Area:
Delaware Basin	1,897		636		1,656			202
Other	5,042		6,221		5,369			6,060
Austin Chalk/Eagle Ford Shale	2,951		3,640		3,074			3,477
Other	240		340		341			472
Total	10,130		10,837		10,440			10,211
Natural Gas (Mcf):
Permian Basin Area:
Delaware Basin	1,297		—		910			—
Other	11,832		10,209		12,560			12,304
Austin Chalk/Eagle Ford Shale	2,135		2,477		2,034			2,142
Other	5,584		9,325		6,551			9,099
Total	20,848		22,011		22,055			23,545
Natural Gas Liquids (Bbls):
Permian Basin Area:
Delaware Basin	319		—		168			—
Other	711		343		693			461
Austin Chalk/Eagle Ford Shale	344		224		267			212
Other	28		63		55			80
Total	1,402		630		1,183			753
(Continued)

CLAYTON WILLIAMS ENERGY, INC. SUMMARY PRODUCTION AND PRICE DATA (Unaudited)
	Three Months Ended December 31,					Year Ended December 31,
	2012			2011		2012			2011
Oil and Gas Costs ($/BOE Produced):
Production costs	$	22.46		$	18.57	$	22.32		$	18.60
Production costs (excluding production taxes)	$	19.12		$	14.84	$	18.70		$	14.79
Oil and gas depletion	$	25.92		$	20.76	$	23.84		$	18.72
General and Administrative Expenses (in thousands):
Excluding non-cash employee compensation	$	7,956		$	12,120	$	30,889		$	28,694
Non-cash employee compensation(c)	(2,604		)	6,762		(404		)	12,866
Total	$	5,352		$	18,882	$	30,485		$	41,560
______

(a) Oil and gas sales for 2012 includes $2.4 million for the three months ended December 31, 2012 and $8.3 million for the year ended December 31, 2012 of amortized deferred revenue attributable to the volumetric production payment (“VPP”) effective March 1, 2012. The calculation of average realized sales prices for 2012 excludes production of 31,979 barrels of oil and 17,558 Mcf of gas for the three months ended December 31, 2012 and 109,733 barrels of oil and 49,558 Mcf of gas for the year ended December 31, 2012 associated with the VPP.

(b) 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 2012 or 2011 derivative contracts as cash flow hedges. This means that the Company's derivatives for 2012 and 2011 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.

(c) Non-cash employee compensation relates to the Company’s non-equity award plans.

CLAYTON WILLIAMS ENERGY, INC.

SUMMARY OF EXPLORATION AND DEVELOPMENT EXPENDITURES

(Unaudited)

The following table summarizes, by area, our planned expenditures for exploration and development activities during 2013, as compared to our actual expenditures in 2012.

	Actual Expenditures Year Ended December 31, 2012		Planned Expenditures Year Ending December 31, 2013		2013 Percentage of Total
	(In thousands)
Drilling and Completion
Permian Basin Area:
Delaware Basin	$	227,900	$	80,200	36	%
Other	87,200		28,400		12	%
Austin Chalk/Eagle Ford Shale	27,400		71,300		32	%
Other	11,900		11,700		5	%
	354,400		191,600		85	%
Leasing and seismic	82,400		34,000		15	%
Exploration and development	$	436,800	$	225,600	100	%

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, 2012.
	Oil			Gas
Swaps:	Bbls	Price		MMBtu (a)	Price
Production Period:
1st Quarter 2013	665,000	$	93.70	400,000	$	3.34
2nd Quarter 2013	648,000	$	93.94	390,000	$	3.34
3rd Quarter 2013	300,000	$	104.60	360,000	$	3.34
4th Quarter 2013	300,000	$	104.60	330,000	$	3.34
2014	600,000	$	99.30	—	$	—
	2,513,000			1,480,000
_____

(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, 2012 and 2011, all of which are located in the United States.
	Proved Reserves
Reserve Category	Oil (MBbls)	Natural Gas Liquids (MBbls)	Natural Gas (MMcf)	Total Oil Equivalents (a) (MBOE)
December 31, 2012:
Developed	27,641	5,044	64,013	43,354
Undeveloped	21,478	4,138	38,323	32,003
Total Proved	49,119	9,182	102,336	75,357
December 31, 2011:
Developed	26,198	2,764	61,811	39,264
Undeveloped	18,721	1,853	27,065	25,085
Total Proved	44,919	4,617	88,876	64,349
_____

(a) 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 $1.3 billion at December 31, 2012, as compared to $1.4 billion at December 31, 2011. Average adjusted commodity prices used at December 31, 2012 and December 31, 2011 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 $90.45 per barrel of oil, $43.74 per barrel of NGL and $3.70 per Mcf of natural gas for 2012 and $91.35 per barrel of oil, $51.19 per barrel of NGL and $5.31 per Mcf of natural gas for 2011.
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,
	2012			2011
	(In thousands)
PV-10 Value, a non-GAAP financial measure	$	1,309,415		$	1,375,460
Less present value, discounted at 10%, of:
Estimated asset retirement obligations	(38,750		)	(29,520		)
Estimated future income taxes	(330,834		)	(407,427		)
Standardized measure of discounted future net cash flows,
a GAAP financial measure	$	939,831		$	938,513