Clayton Williams Energy (CWEI) 8-K Clayton Williams Energy Announces 2013 Financial Results

Exhibit 99.1

CLAYTON WILLIAMS ENERGY ANNOUNCES 2013 FINANCIAL RESULTS

AND YEAR-END RESERVES

Midland, Texas, February 20, 2014 (BUSINESS WIRE) - Clayton Williams Energy, Inc. (the “Company”) (NYSE-CWEI) today reported its financial results for the quarter and year ended December 31, 2013.

Highlights

• 2013 Oil and Gas Production of 5.3 Million BOE, up 8% pro forma

• Total Proved Reserves of 70 Million BOE

• 526% of 2013 Production Replaced by Reserve Additions

• 82% Oil and NGL and 55% Proved Developed

• Total Debt down 21% to $640 Million

Financial Results for Fiscal Year 2013

Net loss attributable to Company stockholders for fiscal 2013 was $24.9 million, or $2.04 per share, as compared to net income of $35.1 million, or $2.89 per share, for fiscal 2012. Cash flow from operations for 2013 was $214.9 million as compared to $189.2 million for 2012. The 2013 period included non-cash, pre-tax charges totaling $89.8 million to write down the carrying value of certain proved properties to their estimated fair value. The Company's adjusted net income, excluding the non-recurring charge, was $33.5 million.

The key factors affecting the comparability of the two years were:

• In April 2013, the Company sold 95% of its oil and gas reserves, leasehold interests and facilities located in Andrews County, Texas for $215.2 million, subject to customary closing adjustments. As a result, reported oil and gas production, revenues and operating costs for the quarter and year ended December 31, 2013 are not comparable to reported amounts for periods in 2012.

• Oil and gas sales, excluding amortized deferred revenues, decreased $3.6 million in 2013 compared to 2012. Production variances accounted for a decrease of $15.6 million, and price variances accounted for a $12 million increase. Average realized oil prices were $95.05 per barrel in 2013 versus $90.97 per barrel in 2012, average realized gas prices were flat at $3.59 per Mcf in 2013 and 2012, and average realized natural gas liquids (“NGL”) prices were $33.26 per barrel in 2013 versus $38.95 per barrel in 2012. Oil and gas sales in 2013 also include $8.7 million of amortized deferred revenue versus $8.3 million in 2012 attributable to a volumetric production payment (“VPP”). Reported production and related average realized sales prices exclude volumes associated with the VPP.

• Before giving effect to the Andrews sale discussed above, oil, gas and NGL production for 2013 on a barrel of oil equivalent (“BOE”) basis declined 6% compared to 2012 with oil production decreasing 3% to 10,115 barrels per day, gas production decreasing 23% to

16,953 Mcf per day, and NGL production increasing 23% to 1,458 barrels per day. Oil and NGL production accounted for 80% of total production in 2013 versus 76% in 2012. See accompanying tables for additional information about the Company's oil and gas production.

• After giving effect to the Andrews sale, oil, gas and NGL production per BOE increased 8% in 2013 as compared to 2012, with oil production increasing 1,141 barrels per day, gas production decreasing 3,933 Mcf per day and NGL production increasing 580 barrels per day.

• Production costs decreased 13% to $108.4 million in 2013 from $125 million in 2012 due primarily to a reduction in costs associated with the Andrews sale, lower salt water disposal costs and other cost savings resulting from infrastructure improvements in Reeves County.

• Loss on derivatives for 2013 was $8.7 million (net of a $0.7 milliongain on settled contracts) versus a gain in 2012 of $14.4 million (net of a $3.4 millionloss on settled contracts). See accompanying tables for additional information about the Company's accounting for derivatives.

• Interest expense increased to $43.1 million in 2013 from $38.7 million in 2012 due primarily to the issuance in October 2013 of $250 million aggregate principal amount of 7.75% Senior Notes due 2019.

• General and administrative (“G&A”) expenses for 2013 were $33.3 million versus $30.5 million in 2012. Higher personnel and professional costs in 2013 accounted for an increase of approximately $4.8 million, which was partially offset by a reduction in costs related to $2 million of non-recurring donations reported in 2012.

Financial Results for the Fourth Quarter of 2013

Net income attributable to Company stockholders for the fourth quarter of 2013 (“4Q13”) was $6.4 million, or $0.53 per share, as compared to net income of $1.7 million, or $0.14 per share, for the fourth quarter of 2012 (“4Q12”). Cash flow from operations for 4Q13 was $61 million as compared to $31.3 million for 4Q12.

The key factors affecting the comparability of financial results for 4Q13 versus 4Q12 were:

• Oil and gas sales, excluding amortized deferred revenues, increased $9.1 million in 4Q13 versus 4Q12. Price variances accounted for a $5.6 million increase, and production variances accounted for a $3.5 million increase. Average realized oil prices were $92.03 per barrel in 4Q13 versus $85.86 per barrel in 4Q12, average realized gas prices were $3.68 per Mcf in 4Q13 versus $4.02 per Mcf in 4Q12, and average realized NGL prices were $35.73 per barrel in 4Q13 versus $36.35 per barrel in 4Q12. Oil and gas sales in 4Q13 also include $2.1 million of amortized deferred revenue versus $2.4 million in 4Q12 attributable to a VPP. Reported production and related average realized sales prices exclude volumes associated with the VPP.

• Before giving effect to the Andrews sale, oil, gas and NGL production per BOE declined 1% in 4Q13 as compared to 4Q12, with oil production increasing 7% to 10,837 barrels per day, gas production decreasing 25% to 15,598 Mcf per day, and NGL production increasing 3%

to 1,446 barrels per day. Oil and NGL production accounted for approximately 83% of the Company's total BOE production in 4Q13 versus 77% in 4Q12. See accompanying tables for additional information about the Company's oil and gas production.

• After giving effect to the Andrews sale, oil, gas and NGL production per BOE increased 16% in 4Q13 as compared to 4Q12, with oil production increasing 2,261 barrels per day, gas production decreasing 3,576 Mcf per day and NGL production increasing 435 barrels per day.

• Production costs decreased 19% to $25.2 million in 4Q13 from $31 million in 4Q12, due primarily to a reduction in costs associated with the Andrews sale, lower salt water disposal costs and other cost savings resulting from infrastructure improvements in Reeves County.

• Gain on derivatives for 4Q13 was $1.2 million (net of a $2.1 milliongain on settled contracts) versus a gain in 4Q12 of $4.6 million (net of a $1.6 million gain on settled contracts). See accompanying tables for additional information about the Company's accounting for derivatives.

• Interest expense increased to $13 million in 4Q13 from $10.8 million in 4Q12 due primarily to the issuance in October 2013 of $250 million aggregate principal amount of 7.75% Senior Notes due 2019.

• G&A expenses for 4Q13 were $12.9 million versus $5.4 million for 4Q12. Compensation expense related to the Company’s APO reward plans accounted for a charge of $3 million in 4Q13 as compared to a credit for reversal of previously accrued compensation of $2.1 million in 4Q12. The remaining $2.4 million increase was attributable primarily to higher professional costs in 4Q13 than in 4Q12.

Capitalization and Liquidity

As of December 31, 2013, the Company's liquidity, consisting of cash plus funds available on its bank credit facility, totaled $397 million versus $132 million of liquidity at December 31, 2012. This three-fold increase resulted from a combination of previously reported asset sales and the issuance in October 2013 of $250 million of 7.75% Senior Notes due 2019.

Total long-term debt at December 31, 2013 was $640 million, consisting of $40 million of secured debt under the bank credit facility and $600 million of 7.75% Senior Notes due 2019, versus total long-term debt of $810 million at December 31, 2012, consisting of $460 million of secured debt under the bank credit facility and $350 million of 7.75% Senior Notes due 2019. The Company's leverage ratio, expressed as the ratio of total long-term debt to EBITDAX, improved from 3.4x to 2.5x.

Reserves

The Company reported that its total estimated proved oil and gas reserves as of December 31, 2013 were 70 million barrels of oil equivalent (“MMBOE”), consisting of 48.7 million barrels of oil, 8.5 million barrels of NGL and 77.2 Bcf of natural gas. On a BOE basis, oil and NGL comprised 82% of total proved reserves at year-end 2013 versus 77%at year-end2012. Proved developed

reserves at year-end 2013 were 38.3 MMBOE, or 55% of total proved reserves, versus 43.4 MMBOE, or 58% of total proved reserves, at year-end 2012. 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”) totaled $1.4 billion for year-end 2013 versus $1.3 billion for year-end 2012. See accompanying tables for a reconciliation of PV-10 (a non-GAAP measure) to standardized measure of discounted future net cash flows.

The following table summarizes the changes in total proved reserves during 2013 on an MMBOE basis.

	MMBOE
Total proved reserves, December 31, 2012	75.4
Extensions and discoveries	27.7
Revisions	(0.9	)
Sales of reserves	(26.9	)
Production	(5.3	)
Total proved reserves, December 31, 2013	70.0

The Company replaced 526% of its 2013 oil and gas production through extensions and discoveries. Most of the 27.7 MMBOE of reserve additions in 2013 are attributable to the Company's Andrews County Wolfberry, Delaware Basin and Giddings Eagle Ford programs. Oil and NGL accounted for 87% of the 2013 reserve additions.

Revisions of prior year estimates resulted from a combination of downward revisions of 1.5 MMBOE related primarily to well performance, offset in part by upward revisions of 0.6 MMBOE which were attributable to the effects of higher commodity prices on the estimated quantities of proved reserves.

SEC guidelines require that the Company's estimated proved reserves and related PV-10 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 2013 were $96.78 per barrel of oil and $3.67 per MMBtu of natural gas, as compared to $94.71 per barrel and $2.75 per MMBtu for 2012. 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 $94.88 per barrel of oil, $31.63 per barrel of NGL and $3.59 per Mcf of natural gas for year-end 2013, as compared to $90.45 per barrel of oil, $0.04 per barrel of NGL and $3.70 per Mcf of natural gas for year-end 2012.

Commodity prices have a significant impact on proved oil and gas reserves and their related PV-10. Using strip prices as of December 31, 2013 instead of the SEC mandated benchmark prices, the Company's PV-10 for year-end 2013 would have been $1 billion.

Scheduled Conference Call

The Company will host a conference call to discuss these results and other forward-looking items today, February 20th at 1:30 p.m. CT (2:30 p.m. ET).  The dial-in conference number is: 877-868-1835, passcode 14542157.  The replay will be available for one week at 855-859-2056, passcode 14542157. 

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 30 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,
	2013			2012			2013			2012
REVENUES
Oil and gas sales	$	103,804		$	95,027		$	399,950		$	403,143
Midstream services	1,592			669			4,965			1,974
Drilling rig services	4,916			4,380			17,812			15,858
Other operating revenues	1,955			1,534			6,488			2,077
Total revenues	112,267			101,610			429,215			423,052
COSTS AND EXPENSES
Production	25,151			31,013			108,405			124,950
Exploration:
Abandonments and impairments	2,907			1,930			5,887			4,222
Seismic and other	365			6,146			3,906			11,591
Midstream services	498			272			1,816			1,228
Drilling rig services	3,586			5,259			16,290			17,423
Depreciation, depletion and amortization	41,039			39,201			150,902			142,687
Impairment of property and equipment	—			233			89,811			5,944
Accretion of asset retirement obligations	1,034			1,068			4,203			3,696
General and administrative	12,878			5,352			33,279			30,485
Other operating expenses	232			548			2,101			1,033
Total costs and expenses	87,690			91,022			416,600			343,259
Operating income	24,577			10,588			12,615			79,793
OTHER INCOME (EXPENSE)
Interest expense	(12,973		)	(10,847		)	(43,079		)	(38,664		)
Gain (loss) on derivatives	1,188			4,592			(8,731		)	14,448
Other	(102		)	795			1,905			1,534
Total other expense	(11,887		)	(5,460		)	(49,905		)	(22,682		)
Income (loss) before income taxes	12,690			5,128			(37,290		)	57,111
Income tax (expense) benefit	(6,265		)	(3,450		)	12,428			(22,008		)
NET INCOME (LOSS)	$	6,425		$	1,678		$	(24,862	)	$	35,103
Net income (loss) per common share:
Basic	$	0.53		$	0.14		$	(2.04	)	$	2.89
Diluted	$	0.53		$	0.14		$	(2.04	)	$	2.89
Weighted average common shares outstanding:
Basic	12,165			12,164			12,165			12,164
Diluted	12,165			12,164			12,165			12,164

CLAYTON WILLIAMS ENERGY, INC. CONSOLIDATED BALANCE SHEETS (In thousands) ASSETS
	December 31,			December 31,
	2013			2012
CURRENT ASSETS	(Unaudited)
Cash and cash equivalents	$	26,623		$	10,726
Accounts receivable:
Oil and gas sales	39,268			32,371
Joint interest and other, net	17,121			16,767
Affiliates	264			353
Inventory	39,183			41,703
Deferred income taxes	7,581			8,560
Fair value of derivatives	2,518			7,495
Prepaids and other	5,753			6,495
	138,311			124,470
PROPERTY AND EQUIPMENT
Oil and gas properties, successful efforts method	2,403,277			2,570,803
Pipelines and other midstream facilities	54,800			49,839
Contract drilling equipment	96,270			91,163
Other	20,620			20,245
	2,574,967			2,732,050
Less accumulated depreciation, depletion and amortization	(1,375,860		)	(1,311,692		)
Property and equipment, net	1,199,107			1,420,358
OTHER ASSETS
Debt issue costs, net	12,785			10,259
Fair value of derivatives	—			4,236
Investments and other	16,534			15,261
	29,319			29,756
	$	1,366,737		$	1,574,584
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable:
Trade	$	75,872		$	73,026
Oil and gas sales	37,834			32,146
Affiliates	874			164
Fair value of derivatives	208			—
Accrued liabilities and other	21,607			15,578
	136,395			120,914
NON-CURRENT LIABILITIES
Long-term debt	639,638			809,585
Deferred income taxes	140,809			155,830
Asset retirement obligations	49,981			51,477
Deferred revenue from volumetric production payment	29,770			37,184
Accrued compensation under non-equity award plans	15,469			20,058
Other	892			920
	876,559			1,075,054
STOCKHOLDERS’ EQUITY
Preferred stock, par value $.10 per share	—			—
Common stock, par value $.10 per share	1,216			1,216
Additional paid-in capital	152,556			152,527
Retained earnings	200,011			224,873
Total stockholders' equity	353,783			378,616
	$	1,366,737		$	1,574,584

CLAYTON WILLIAMS ENERGY, INC. CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) (In thousands)
	Three Months Ended December 31,						Year Ended December 31,
	2013			2012			2013			2012
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	6,425		$	1,678		$	(24,862	)	$	35,103
Adjustments to reconcile net income (loss) to cash provided by operating activities:
Depreciation, depletion and amortization	41,039			39,201			150,902			142,687
Impairment of property and equipment	—			233			89,811			5,944
Exploration costs	2,907			1,930			5,887			4,222
Gain on sales of assets and impairment of inventory, net	(1,497		)	(405		)	(3,024		)	(463		)
Deferred income tax expense (benefit)	4,651			3,450			(14,042		)	22,008
Non-cash employee compensation	2,404			(2,604		)	(3,493		)	(404		)
(Gain) loss on derivatives	(1,188		)	(4,592		)	8,731			(14,448		)
Cash settlements of derivatives	2,054			1,551			690			(3,410		)
Accretion of asset retirement obligations	1,034			1,068			4,203			3,696
Amortization of debt issue costs and original issue discount	985			967			3,266			2,554
Amortization of deferred revenue from volumetric production payment	(2,107		)	(2,433		)	(8,746		)	(8,295		)
Changes in operating working capital:
Accounts receivable	(6,975		)	149			(7,163		)	7,299
Accounts payable	16,800			(3,614		)	12,740			(9,386		)
Other	(5,502		)	(5,240		)	11			2,115
Net cash provided by operating activities	61,030			31,339			214,911			189,222
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to property and equipment	(80,111		)	(88,039		)	(288,133		)	(526,521		)
Proceeds from volumetric production payment	298			447			1,332			45,479
Proceeds from sales of assets	61,858			2,911			259,799			3,778
(Increase) decrease in equipment inventory	(6,544		)	1,249			(726		)	1,313
Other	(146		)	113			(1,315		)	(82		)
Net cash used in investing activities	(24,645		)	(83,319		)	(29,043		)	(476,033		)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt	231,000			40,000			274,000			280,000
Repayments of long-term debt	(264,000		)	—			(444,000		)	—
Proceeds from exercise of stock options	29			12			29			12
Net cash provided by (used in) financing activities	(32,971		)	40,012			(169,971		)	280,012
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	3,414			(11,968		)	15,897			(6,799		)
CASH AND CASH EQUIVALENTS
Beginning of period	23,209			22,694			10,726			17,525
End of period	$	26,623		$	10,726		$	26,623		$	10,726

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, 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,
	2013			2012			2013			2012
Net income (loss)	$	6,425		$	1,678		$	(24,862	)	$	35,103
Interest expense	12,973			10,847			43,079			38,664
Income tax expense (benefit)	6,265			3,450			(12,428		)	22,008
Exploration:
Abandonments and impairments	2,907			1,930			5,887			4,222
Seismic and other	365			6,146			3,906			11,591
Net gain on sales of assets and impairment of inventory	(1,497		)	(405		)	(3,024		)	(463		)
Depreciation, depletion and amortization	41,039			39,201			150,902			142,687
Impairment of property and equipment	—			233			89,811			5,944
Accretion of asset retirement obligations	1,034			1,068			4,203			3,696
Amortization of deferred revenue from volumetric production payment	(2,107		)	(2,433		)	(8,746		)	(8,295		)
Non-cash employee compensation	2,404			(2,604		)	(3,493		)	(404		)
(Gain) loss on derivatives	(1,188		)	(4,592		)	8,731			(14,448		)
Cash settlements of derivatives	2,054			1,551			690			(3,410		)
EBITDAX (a)	$	70,674		$	56,070		$	254,656		$	236,895
______

(a) In April 2013, the Company sold 95% of its interests in certain properties in Andrews County, Texas. Revenue, net of direct expenses, associated with the sold properties for the three months ended December 31, 2012 were $7 million and the year ended December 31, 2013 and 2012 were $8.7 million and $45.8 million, respectively.

CLAYTON WILLIAMS ENERGY, INC.

SUMMARY PRODUCTION AND PRICE DATA

(Unaudited)

	Three Months Ended December 31,					Year Ended December 31,
	2013			2012		2013			2012
Oil and Gas Production Data:
Oil (MBbls)	997			932		3,692			3,821
Gas (MMcf)	1,435			1,918		6,188			8,072
Natural gas liquids (MBbls)	133			129		532			433
Total (MBOE)	1,369			1,381		5,255			5,599
Average Realized Prices (a) (b):
Oil ($/Bbl)	$	92.03		$	85.86	$	95.05		$	90.97
Gas ($/Mcf)	$	3.68		$	4.02	$	3.59		$	3.59
Natural gas liquids ($/Bbl)	$	35.73		$	36.35	$	33.26		$	38.95
Gain (Loss) on Settled Derivative Contracts (b):
($ in thousands, except per unit)
Oil:
Net realized gain (loss)	$	2,142		$	1,551	$	1,162		$	(3,410	)
Per unit produced ($/Bbl)	$	2.15		$	1.66	$	0.31		$	(0.89	)
Gas:
Net realized loss	$	(89	)	$	—	$	(472	)	$	—
Per unit produced ($/Mcf)	$	(0.06	)	$	—	$	(0.08	)	$	—
Average Daily Production:
Oil (Bbls):
Permian Basin Area:
Delaware Basin	2,843			1,897		2,127			1,656
Other (c)	3,843			5,042		3,952			5,369
Austin Chalk	2,392			2,639		2,581			2,728
Eagle Ford Shale	1,354			312		1,136			346
Other	405			240		319			341
Total	10,837			10,130		10,115			10,440
Natural Gas (Mcf):
Permian Basin Area:
Delaware Basin	2,129			1,297		1,720			910
Other (c) (d)	7,167			11,832		7,963			12,560
Austin Chalk	2,057			2,133		2,043			2,029
Eagle Ford Shale	86			2		78			5
Other	4,159			5,584		5,149			6,551
Total	15,598			20,848		16,953			22,055
Natural Gas Liquids (Bbls):
Permian Basin Area:
Delaware Basin	369			319		316			168
Other (c) (d)	809			711		880			693
Austin Chalk	228			344		223			267
Eagle Ford Shale	20			—		19			—
Other	20			28		20			55
Total	1,446			1,402		1,458			1,183
(Continued)

CLAYTON WILLIAMS ENERGY, INC.

SUMMARY PRODUCTION AND PRICE DATA

(Unaudited)

	Three Months Ended December 31,				Year Ended December 31,
	2013		2012		2013		2012
Oil and Gas Costs ($/BOE Produced):
Production costs	$	18.37	$	22.46	$	20.63	$	22.32
Production costs (excluding production taxes)	$	14.39	$	19.12	$	16.75	$	18.70
Oil and gas depletion	$	27.78	$	25.92	$	26.13	$	23.84
______

(a) Oil and gas sales includes $2.1 million for the three months ended December 31, 2013, $2.4 million for the three months ended December 31, 2012, $8.7 million for the year ended December 31, 2013, and $8.3 million for the year ended December 31, 2012 of amortized deferred revenue attributable to a volumetric production payment (“VPP”) transaction effective March 1, 2012. The calculation of average realized sales prices excludes production of 28,045 barrels of oil and 10,030 Mcf of gas for the three months ended December 31, 2013, 31,979 barrels of oil and 17,558 Mcf of gas for the three months ended December 31, 2012, 116,941 barrels of oil and 33,619 Mcf of gas for the year ended December 31, 2013 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 2013 or 2012 derivative contracts as cash flow hedges. This means that the Company's derivatives for 2013 and 2012 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) In April 2013, the Company sold 95% of its interest in certain properties in Andrews County, Texas. Following is a recap of the average daily production related to the sold interest for periods prior to April 1, 2013.

	Three Months Ended December 31,	Year Ended December 31,
	2012	2013	2012
Average Daily Production:
Oil (Bbls)	1,554	403	1,869
Natural gas (Mcf)	1,674	447	1,615
NGL (Bbls)	391	88	393
Total (Boe)	2,224	566	2,531

(d) Prior to 2013, certain purchasers of the Company's casinghead gas accounted for the value of extracted NGL in the price paid for gas production at the wellhead. During the quarter ended March 31, 2013, the Company began separating these products, when possible. Had these incremental NGL volumes been reported separately during the three months and year ended December 31, 2012, the Company estimates that its reported natural gas volumes would have decreased by 2,200 Mcf/day and that its reported NGL volumes would have increased by 600 BOE/day during each of the 2012 periods.

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 2014, as compared to our actual expenditures in 2013.

	Actual Expenditures Year Ended December 31, 2013		Planned Expenditures Year Ending December 31, 2014		2014 Percentage of Total
	(In thousands)
Drilling and Completion
Permian Basin Area:
Delaware Basin	$	109,600	$	165,200	44	%
Other	39,800		11,300		3	%
Austin Chalk/Eagle Ford Shale	64,200		155,500		41	%
Other	9,300		3,800		1	%
	222,900		335,800		89	%
Leasing and seismic	52,100		40,400		11	%
Exploration and development	$	275,000	$	376,200	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, 2013.

	Oil
Swaps:	Bbls	Price
Production Period:
1st Quarter 2014	606,000	$	96.74
2nd Quarter 2014	560,600	$	96.81
3rd Quarter 2014	530,200	$	96.87
4th Quarter 2014	503,200	$	96.92
	2,200,000

CLAYTON WILLIAMS ENERGY, INC. PROVED RESERVES (Unaudited)
The following table sets forth our estimated quantities of proved reserves as of December 31, 2013 and 2012, 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, 2013:
Developed	25,989	4,293	47,839	38,255
Undeveloped	22,676	4,194	29,340	31,760
Total Proved	48,665	8,487	77,179	70,015
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
_____

(a) Natural gas reserves have been converted to oil equivalents at the rate of six Mcf to one barrel of oil.

PV-10 totaled $1.4 billion at December 31, 2013, versus $1.3 billion at December 31, 2012. The benchmark averages for 2013 were $96.78 per barrel of oil and $3.67 per MMBtu of natural gas, as compared to $94.71 per barrel and $2.75 per MMBtu for 2012. These benchmark prices were further adjusted for quality, energy content, transportation fees and other price differentials specific to the Company's properties, resulting in average adjusted commodity prices. Average adjusted commodity prices used at December 31, 2013 and December 31, 2012 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 $94.88 per barrel of oil, $31.63 per barrel of NGL and $3.59 per Mcf of natural gas for 2013 and $90.45 per barrel of oil, $43.74 per barrel of NGL and $3.70 per Mcf of natural gas for 2012.
PV-10 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 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 to standardized measure of discounted future net cash flows.
	As of December 31,
	2013			2012
	(In thousands)
PV-10, a non-GAAP financial measure	$	1,380,948		$	1,309,415
Less present value, discounted at 10%, of:
Estimated asset retirement obligations	(38,518		)	(38,750		)
Estimated future income taxes	(415,507		)	(330,834		)
Standardized measure of discounted future net cash flows,
a GAAP financial measure	$	926,923		$	939,831