MIDLAND, Texas--(BUSINESS WIRE)--

Clayton Williams Energy, Inc. (the “Company”) (CWEI) today reported its financial results for the quarter and year ended December 31, 2014.

Highlights

Fiscal 2014

• Oil and Gas Production of 5.8 Million BOE, up 21% pro forma
• Adjusted Net Income¹ (non-GAAP) of $56.4 million
• EBITDA² (non-GAAP) of $299.3 million, up 18%

Year-End 2014

• Total Proved Reserves of 75.4 Million BOE
• 405% of 2014 Production Replaced by Reserve Additions
• 83% Oil and NGL and 56% Proved Developed

Financial Results for Fiscal Year 2014

The Company reported net income for fiscal 2014 of $43.9 million, or $3.61 per share, as compared to a net loss of $24.9 million, or $2.04 per share, for fiscal 2013. Adjusted net income¹ (non-GAAP) for 2014 was $56.4 million, or $4.63 per share, as compared to $35 million, or $2.88 per share, for 2013. Cash flow from operations for 2014 was $258.1 million as compared to $220.6 million for 2013. EBITDA² (non-GAAP) for 2014 was $299.3 million as compared to $254.7 million for 2013. The 2014 period included non-cash, pre-tax charges totaling $12 million to write down the carrying value of certain proved properties to their estimated fair value.

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

• The Company sold all of its interests in certain non-core Austin Chalk/Eagle Ford assets in March 2014 and sold 95% of its Andrews County Wolfberry assets in April 2013. As a result, reported oil and gas production, revenues and operating costs for the quarter and year ended December 31, 2014 are not comparable to reported amounts for periods in 2013. See accompanying tables for additional information about the Company’s oil and gas production related to these sold assets.
• Oil and gas sales, excluding amortized deferred revenues, increased $19.4 million in 2014 compared to 2013. Production variances accounted for an increase of $50.3 million, and price variances accounted for a decrease of $30.9 million. Average realized oil prices were $86.81 per barrel in 2014 versus $95.05 per barrel in 2013, average realized gas prices were $4.35 per Mcf in 2014 versus $3.59 per Mcf in 2013, and average realized natural gas liquids (“NGL”) prices were $32.17 per barrel in 2014 versus $33.26 per barrel in 2013. Oil and gas sales in 2014 also include $7.7 million of amortized deferred revenue versus $8.7 million in 2013 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 asset sales discussed above, oil, gas and NGL production for 2014 on a barrel of oil equivalent (“BOE”) basis increased 10% compared to 2013 with oil production increasing 14% to 11,490 barrels per day, gas production decreasing 5% to 16,167 Mcf per day, and NGL production increasing 10% to 1,603 barrels per day. Oil and NGL production accounted for 83% of total production in 2014 versus 80% in 2013. See accompanying tables for additional information about the Company’s oil and gas production.
• After giving effect to the asset sales, total production per BOE increased 21% in 2014 as compared to 2013, with oil production increasing 2,457 barrels per day (27%), gas production decreasing 206 Mcf per day (1%) and NGL production increasing 260 barrels per day (19%).
• Production costs decreased 3% to $105.3 million in 2014 from $108.4 million in 2013 due primarily to a reduction in operating costs associated with the Austin Chalk/Eagle Ford and Andrews County Wolfberry sales, offset in part by increased production taxes related to the increase in oil and gas sales.
• Gain on derivatives for 2014 was $4.8 million (including a $7.1 million gain on settled contracts) versus a loss in 2013 of $8.7 million (net of a $0.7 million gain on settled contracts). See accompanying tables for additional information about the Company's accounting for derivatives.
• Interest expense increased to $50.9 million in 2014 from $43.1 million in 2013 due primarily to the issuance in October 2013 of $250 million aggregate principal amount of 7.75% Senior Notes due 2019.
• We recorded a provision for impairment of property and equipment during 2014 of $12 million related to certain non-core properties located in the Permian Basin and North Dakota to reduce the carrying value of these properties to their estimated fair values. During 2013, we recorded an impairment of property and equipment of $89.8 million related to the transaction to monetize our Andrews County Wolfberry assets and certain non-core Permian Basin properties to reduce the carrying value of those properties to their estimated fair values.
• We recorded exploration expense related to abandonment and impairment costs during 2014 of $20.6 million compared to $5.9 million in 2013. The expense for 2014 includes a charge of $8.6 million related to unproved leasehold impairments in California and $2.4 million for the abandonment of an exploratory well in South Louisiana.
• General and administrative (“G&A”) expenses for 2014 were $34.5 million versus $33.3 million in 2013. Changes in compensation expense attributable to the Company’s APO reward plans accounted for a net increase of $2.5 million ($4.6 million in 2014 versus $2.1 million in 2013) offset by lower professional costs in 2014.

Financial Results for the Fourth Quarter of 2014

The Company reported a net loss for the fourth quarter of 2014 (“4Q14”) of $4.3 million, or $0.35 per share, as compared to net income of $6.4 million, or $0.53 per share, for the fourth quarter of 2013 (“4Q13”). Adjusted net income¹ (non-GAAP) for 4Q14 was $4 million, or $0.33 per share, as compared to $7.7 million, or $0.64 per share, for 4Q13. Cash flow from operations for 4Q14 was $46.4 million as compared to $66.7 million for 4Q13. EBITDA² (non-GAAP) for 4Q14 was $62.8 million as compared to $70.7 million for 4Q13.

The key factors affecting the comparability of financial results for 4Q14 versus 4Q13 were:

• Oil and gas sales, excluding amortized deferred revenues, decreased $16.6 million in 4Q14 versus 4Q13. Price variances accounted for a $27.6 million decrease, and production variances accounted for an $11 million increase. Average realized oil prices were $68.04 per barrel in 4Q14 versus $92.03 per barrel in 4Q13, average realized gas prices were $3.86 per Mcf in 4Q14 versus $3.68 per Mcf in 4Q13, and average realized NGL prices were $25.90 per barrel in 4Q14 versus $35.73 per barrel in 4Q13. Oil and gas sales in 4Q14 also include $1.9 million of amortized deferred revenue versus $2.1 million in 4Q13 attributable to a VPP. Reported production and related average realized sales prices exclude volumes associated with the VPP.
• Before giving effect to the sale of certain Austin Chalk/Eagle Ford assets in March 2014, oil, gas and NGL production per BOE increased 11% in 4Q14 as compared to 4Q13, with oil production increasing 10% to 11,967 barrels per day, gas production increasing 12% to 17,478 Mcf per day, and NGL production increasing 13% to 1,641 barrels per day. Oil and NGL production accounted for approximately 82% of the Company's total BOE production in 4Q14 versus 83% in 4Q13. See accompanying tables for additional information about the Company’s oil and gas production.
• After giving effect to the asset sale, oil, gas and NGL production per BOE increased 17% in 4Q14 as compared to 4Q13, with oil production increasing 1,837 barrels per day (18%), gas production increasing 1,978 Mcf per day (13%) and NGL production increasing 217 barrels per day (15%).
• Production costs increased 12% to $28.3 million in 4Q14 from $25.2 million in 4Q13 due primarily to increased costs attributable to incremental wells on production and increased well maintenance, offset in part by reductions in production taxes due to the decrease in oil and gas sales.
• Gain on derivatives for 4Q14 was $8.5 million (including an $11.9 million gain on settled contracts) versus a gain in 4Q13 of $1.2 million (including a $2.1 million gain on settled contracts). See accompanying tables for additional information about the Company's accounting for derivatives.
• We recorded a provision for impairment of property and equipment during 4Q14 of $8.6 million related to certain non-core properties located in the Permian Basin and North Dakota to reduce the carrying value of these properties to their estimated fair values.
• We recorded exploration expense related to abandonment and impairment costs during 4Q14 of $11.9 million compared to $2.9 million in 4Q13. The expense for 4Q14 includes a charge of $8.6 million related to unproved leasehold impairments in California and $2.4 million for the abandonment of an exploratory well in South Louisiana.
• G&A expenses for 4Q14 were $0.5 million versus $12.9 million for 4Q13. Changes in compensation expense attributable to the Company’s APO reward plans accounted for a net decrease of $10.8 million ($7.8 million credit in 4Q14 versus $3 million expense in 4Q13). The credit in 4Q14 resulted from reversals of previously accrued compensation expense due primarily to lower product prices. The remaining decrease was attributable primarily to lower professional costs in 4Q14 than in 4Q13.

¹ See “Computation of Adjusted Net Income (non-GAAP)” below for an explanation of how the Company calculates and uses adjusted net income (non-GAAP) and for a reconciliation of net income (loss) (GAAP) to adjusted net income (non-GAAP).

² See “Computation of EBITDA (non-GAAP)” below for an explanation of how the Company calculates and uses EBITDA (non-GAAP) and for a reconciliation of net income (loss) (GAAP) to EBITDA (non-GAAP).

Balance Sheet and Liquidity

As of December 31, 2014, total long-term debt was $704.7 million, consisting of $105 million of secured debt under a revolving credit facility and $599.7 million of 7.75% Senior Notes due 2019. The borrowing base established by the banks under the credit facility was $600 million at December 31, 2014, and the aggregate lender commitment was $500 million. Liquidity, consisting of cash plus funds available on the bank credit facility, totaled $417.1 million.

The credit facility previously contained a leverage ratio covenant that limited the Company’s consolidated indebtedness to 4.0 times annual consolidated EBITDA. The Company’s leverage ratio at December 31, 2014 was in compliance with the covenant at 2.4 times. In February 2015, the credit facility was amended to temporarily redefine the leverage ratio to limit consolidated senior debt to 2.5 times consolidated EBITDA and to add a consolidated interest coverage ratio of 1.5 times consolidated EBITDA. These temporary amendments apply to each quarterly period from January 1, 2015 through June 30, 2016.

To limit its exposure to any further declines in oil prices for the remainder of 2015, the Company entered into commodity swaps in February 2015 covering 1,737,000 barrels of oil production from May 2015 through December 2015 at an average price of $55.65 per barrel.

Reserves

The Company reported that its total estimated proved oil and gas reserves as of December 31, 2014 were 75.4 million barrels of oil equivalent (“MMBOE”), consisting of 53.9 million barrels of oil, 8.9 million barrels of NGL and 75.6 Bcf of natural gas. On a BOE basis, oil and NGL comprised 83% of total proved reserves at year-end 2014 versus 82% at year-end 2013. Proved developed reserves at year-end 2014 were 42.2 MMBOE, or 56% of total proved reserves, versus 38.3 MMBOE, or 55% of total proved reserves, at year-end 2013. 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”) remained unchanged at $1.4 billion for year-end 2014 compared to year-end 2013. See accompanying tables for a reconciliation of PV-10 (a non-GAAP financial measure) to standardized measure of discounted future net cash flows (a GAAP financial measure).

The following table summarizes the changes in total proved reserves during 2014 on an MMBOE basis.

			MMBOE
Total proved reserves, December 31, 2013			70.0
Extensions and discoveries			23.3
Revisions			(10.1	)
Sales of reserves			(2.0	)
Production			(5.8	)
Total proved reserves, December 31, 2014			75.4

The Company replaced 405% of its 2014 oil and gas production through extensions and discoveries. Most of the 23.3 MMBOE of reserve additions in 2014 are attributable to the Company's Eagle Ford and Delaware Basin programs. Oil and NGL accounted for 91.4% of the 2014 reserve additions.

The 10.1 MMBOE of net downward revisions in proved reserves resulted from a combination of (1) reclassifications of 4.9 MMBOE of proved undeveloped reserves to probable reserves due solely to the SEC 5-year development rule, (2) other net downward revisions of 4.8 MMBOE related primarily to proved undeveloped reserves associated with vertical locations in Reeves County, Texas originally assigned prior to the Company’s conversion to horizontal drilling in this area, and (3) downward revisions of 0.4 MMBOE related to the effects of lower 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 2014 were $94.99 per barrel of oil and $4.35 per MMBtu of natural gas, as compared to $96.78 per barrel and $3.67 per MMBtu for 2013. 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 $90.48 per barrel of oil, $31.54 per barrel of NGL and $4.27 per Mcf of natural gas for year-end 2014, as compared to $94.88 per barrel of oil, $31.63 per barrel of NGL and $3.59 per Mcf of natural gas for year-end 2013.

Scheduled Conference Call

The Company will host a conference call to discuss these results and other forward-looking items today, February 26th at 1:30 p.m. CT (2:30 p.m. ET). The dial-in conference number is: 877-868-1835, conference ID 89149363. The replay will be available from 3:30 p.m. CT (4:30 p.m. ET) on February 26th until March 5th at 855-859-2056, conference ID 89149363.

To access the conference call via Internet webcast, please go to the "Investors" section of the Company’s website at www.claytonwilliams.com and click on the webcast link. 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.

CLAYTON WILLIAMS ENERGY, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
(In thousands, except per share)
			Three Months Ended December 31,											Year Ended December 31,
			2014					2013						2014					2013
REVENUES
Oil and gas sales			$	86,961				$	103,804					$	418,330				$	399,950
Midstream services				1,369					1,592						6,705					4,965
Drilling rig services				5,590					4,916						28,028					17,812
Other operating revenues				753					1,955						15,393					6,488
Total revenues				94,673					112,267						468,456					429,215
COSTS AND EXPENSES
Production				28,290					25,151						105,296					108,405
Exploration:
Abandonments and impairments				11,895					2,907						20,647					5,887
Seismic and other				359					365						2,314					3,906
Midstream services				564					498						2,212					1,816
Drilling rig services				4,264					3,586						19,232					16,290
Depreciation, depletion and amortization				42,114					41,039						154,356					150,902
Impairment of property and equipment				8,621					—						12,027					89,811
Accretion of asset retirement obligations				939					1,034						3,662					4,203
General and administrative				544					12,878						34,524					33,279
Other operating expenses				327					232						2,547					2,101
Total costs and expenses				97,917					87,690						356,817					416,600
Operating income (loss)				(3,244	)				24,577						111,639					12,615
OTHER INCOME (EXPENSE)
Interest expense				(12,932	)				(12,973	)					(50,907	)				(43,079	)
Gain (loss) on derivatives				8,504					1,188						4,789					(8,731	)
Other				773					(102	)					3,047					1,905
Total other expense				(3,655	)				(11,887	)					(43,071	)				(49,905	)
Income (loss) before income taxes				(6,899	)				12,690						68,568					(37,290	)
Income tax (expense) benefit				2,632					(6,265	)					(24,687	)				12,428
NET INCOME (LOSS)			$	(4,267	)			$	6,425					$	43,881				$	(24,862	)
Net income (loss) per common share:
Basic			$	(0.35	)			$	0.53					$	3.61				$	(2.04	)
Diluted			$	(0.35	)			$	0.53					$	3.61				$	(2.04	)
Weighted average common shares outstanding:
Basic				12,170					12,165						12,167					12,165
Diluted				12,170					12,165						12,167					12,165

CLAYTON WILLIAMS ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(In thousands)
ASSETS
			December 31,					December 31,
			2014					2013
CURRENT ASSETS			(Unaudited)
Cash and cash equivalents			$	28,016				$	26,623
Accounts receivable:
Oil and gas sales				36,526					39,268
Joint interest and other, net				14,550					17,121
Affiliates				322					264
Inventory				42,087					39,183
Deferred income taxes				6,911					7,581
Fair value of derivatives				—					2,518
Prepaids and other				4,208					5,753
				132,620					138,311
PROPERTY AND EQUIPMENT
Oil and gas properties, successful efforts method				2,684,913					2,403,277
Pipelines and other midstream facilities				59,542					54,800
Contract drilling equipment				122,751					96,270
Other				20,915					20,620
				2,888,121					2,574,967
Less accumulated depreciation, depletion and amortization				(1,539,237	)				(1,375,860	)
Property and equipment, net				1,348,884					1,199,107
OTHER ASSETS
Debt issue costs, net				12,712					12,785
Investments and other				16,669					16,534
				29,381					29,319
			$	1,510,885				$	1,366,737
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable:
Trade			$	93,650				$	75,872
Oil and gas sales				41,328					37,834
Affiliates				717					874
Fair value of derivatives				—					208
Accrued liabilities and other				20,658					21,607
				156,353					136,395
NON-CURRENT LIABILITIES
Long-term debt				704,696					639,638
Deferred income taxes				164,599					140,809
Asset retirement obligations				45,697					49,981
Deferred revenue from volumetric production payment				23,129					29,770
Accrued compensation under non-equity award plans				17,866					15,469
Other				751					892
				956,738					876,559
STOCKHOLDERS’ EQUITY
Preferred stock, par value $.10 per share				—					—
Common stock, par value $.10 per share				1,216					1,216
Additional paid-in capital				152,686					152,556
Retained earnings				243,892					200,011
Total stockholders' equity				397,794					353,783
			$	1,510,885				$	1,366,737

CLAYTON WILLIAMS ENERGY, INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
(In thousands)
			Three Months Ended December 31,											Year Ended December 31,
			2014					2013						2014					2013
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)			$	(4,267	)			$	6,425					$	43,881				$	(24,862	)
Adjustments to reconcile net income (loss) to cash provided by operating activities:
Depreciation, depletion and amortization				42,114					41,039						154,356					150,902
Impairment of property and equipment				8,621					—						12,027					89,811
Abandonments and impairments				11,895					2,907						20,647					5,887
Gain on sales of assets and impairment of inventory, net				(69	)				(1,497	)					(9,138	)				(3,024	)
Deferred income tax expense (benefit)				(2,859	)				4,651						24,460					(14,042	)
Non-cash employee compensation				(8,582	)				2,404						1,397					(3,493	)
(Gain) loss on derivatives				(8,504	)				(1,188	)					(4,789	)				8,731
Cash settlements of derivatives				11,876					2,054						7,099					690
Accretion of asset retirement obligations				939					1,034						3,662					4,203
Amortization of debt issue costs and original issue discount				701					985						3,030					3,266
Amortization of deferred revenue from volumetric production payment				(1,853	)				(2,107	)					(7,708	)				(8,746	)
Changes in operating working capital:
Accounts receivable				6,689					(6,975	)					5,255					(7,163	)
Accounts payable				1,022					16,800						4,561					12,740
Other				(11,347	)				163						(619	)				5,676
Net cash provided by operating activities				46,376					66,695						258,121					220,576
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to property and equipment				(110,505	)				(80,111	)					(422,473	)				(288,133	)
Proceeds from volumetric production payment				257					298						1,067					1,332
Proceeds from sales of assets				(105	)				61,858						104,529					259,799
Increase in equipment inventory				(11,541	)				(6,544	)					(1,886	)				(726	)
Other				91					(146	)					(234	)				(1,315	)
Net cash used in investing activities				(121,803	)				(24,645	)					(318,997	)				(29,043	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt				72,617					225,335						102,139					268,335
Repayments of long-term debt				—					(264,000	)					(40,000	)				(444,000	)
Proceeds from exercise of stock options				—					29						130					29
Net cash provided by (used in) financing activities				72,617					(38,636	)					62,269					(175,636	)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS				(2,810	)				3,414						1,393					15,897
CASH AND CASH EQUIVALENTS
Beginning of period				30,826					23,209						26,623					10,726
End of period			$	28,016				$	26,623					$	28,016				$	26,623

CLAYTON WILLIAMS ENERGY, INC.
COMPUTATION OF ADJUSTED NET INCOME (NON-GAAP)
(Unaudited)
(In thousands, except per share)
Adjusted net income 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 a tool for operating trends analysis and industry comparisons. Adjusted net income is not an alternative to net income (loss) presented in conformity with GAAP.
The Company defines adjusted net income as net income (loss) before changes in fair value of derivatives, abandonments and impairments of property and equipment, net gain on sales of assets and impairment of inventory, amortization of deferred revenue from volumetric production payment, certain non-cash and unusual items and the impact on taxes of the adjustments for each period presented.
The following table is a reconciliation of net income (loss) (GAAP) to adjusted net income (non-GAAP):
			Three Months Ended											Year Ended
			December 31,											December 31,
			2014					2013						2014					2013
Net income (loss)			$	(4,267	)			$	6,425					$	43,881				$	(24,862	)
(Gain) loss on derivatives				(8,504	)				(1,188	)					(4,789	)				8,731
Cash settlements of derivatives				11,876					2,054						7,099					690
Abandonments and impairments				11,895					2,907						20,647					5,887
Impairment of property and equipment				8,621					—						12,027					89,811
Gain on sales of assets and impairment of inventory				(69	)				(1,497	)					(9,138	)				(3,024	)
Amortization of deferred revenue from volumetric production payment				(1,853	)				(2,107	)					(7,708	)				(8,746	)
Non-cash employee compensation				(8,582	)				2,404						1,397					(3,493	)
Tax impact (a)				(5,106	)				(1,270	)					(7,033	)				(29,947	)
Adjusted net income			$	4,011				$	7,728					$	56,383				$	35,047
Adjusted earnings per share:
Diluted			$	0.33				$	0.64					$	4.63				$	2.88
Weighted average common shares outstanding:
Diluted				12,170					12,165						12,167					12,165
Effective tax rates				38.2	%				49.4	%					36.0	%				33.3	%
_______
(a) The tax impact is computed utilizing the Company’s effective tax rate on the adjustments for each period presented.

CLAYTON WILLIAMS ENERGY, INC.
COMPUTATION OF EBITDA (NON-GAAP)
(Unaudited)
(In thousands)
EBITDA 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. EBITDA 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 Company defines EBITDA as net income (loss) before interest expense, income taxes, exploration costs, net gain 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.
The following table reconciles net income (loss) to EBITDA:
			Three Months Ended December 31,											Year Ended December 31,
			2014					2013						2014					2013
Net income (loss)			$	(4,267	)			$	6,425					$	43,881				$	(24,862	)
Interest expense				12,932					12,973						50,907					43,079
Income tax expense (benefit)				(2,632	)				6,265						24,687					(12,428	)
Exploration:
Abandonments and impairments				11,895					2,907						20,647					5,887
Seismic and other				359					365						2,314					3,906
Net gain on sales of assets and impairment of inventory				(69	)				(1,497	)					(9,138	)				(3,024	)
Depreciation, depletion and amortization				42,114					41,039						154,356					150,902
Impairment of property and equipment				8,621					—						12,027					89,811
Accretion of asset retirement obligations				939					1,034						3,662					4,203
Amortization of deferred revenue from volumetric production payment				(1,853	)				(2,107	)					(7,708	)				(8,746	)
Non-cash employee compensation				(8,582	)				2,404						1,397					(3,493	)
(Gain) loss on derivatives				(8,504	)				(1,188	)					(4,789	)				8,731
Cash settlements of derivatives				11,876					2,054						7,099					690
EBITDA (a)			$	62,829				$	70,674					$	299,342				$	254,656
The following table reconciles net cash provided by operating activities to EBITDA:
Net cash provided by operating activities			$	46,376				$	66,695					$	258,121				$	220,576
Changes in operating working capital				3,636					(9,988	)					(9,197	)				(11,253	)
Seismic and other				359					365						2,314					3,906
Current income tax provision				227					1,614						227					1,614
Cash interest expense				12,231					11,988						47,877					39,813
			$	62,829				$	70,674					$	299,342				$	254,656
______
(a) In March 2014, the company sold interests in certain non-core Austin Chalk/Eagle Ford assets. Revenue, net of direct expenses, associated with the sold properties for the three months ended December 31, 2013 was $4.8 million, and for the year ended December 31, 2014 and 2013 was $2.5 million and $23.2 million, respectively. In April 2013, the Company sold 95% of its Andrews County Wolfberry assets. Revenue, net of direct expenses, associated with the sold properties for the year ended December 31, 2013 was $8.7 million.

CLAYTON WILLIAMS ENERGY, INC.
SUMMARY PRODUCTION AND PRICE DATA
(Unaudited)
			Three Months Ended December 31,										Year Ended December 31,
			2014				2013						2014				2013
Oil and Gas Production Data:
Oil (MBbls)				1,101				997						4,194				3,692
Gas (MMcf)				1,608				1,435						5,901				6,188
Natural gas liquids (MBbls)				151				133						585				532
Total (MBOE)				1,520				1,369						5,763				5,255
Total (BOE/d)				16,521				14,883						15,788				14,399
Average Realized Prices (a) (b):
Oil ($/Bbl)			$	68.04			$	92.03					$	86.81			$	95.05
Gas ($/Mcf)			$	3.86			$	3.68					$	4.35			$	3.59
Natural gas liquids ($/Bbl)			$	25.90			$	35.73					$	32.17			$	33.26
Gain (Loss) on Settled Derivative Contracts (b):
($ in thousands, except per unit)
Oil:
Cash settlements paid			$	11,876			$	2,142					$	7,099			$	1,162
Per unit produced ($/Bbl)			$	10.79			$	2.15					$	1.69			$	0.31
Gas:
Cash settlements paid			$	—			$	(89	)				$	—			$	(472	)
Per unit produced ($/Mcf)			$	—			$	(0.06	)				$	—			$	(0.08	)
Average Daily Production:
Oil (Bbls):
Permian Basin Area:
Delaware Basin				2,730				2,843						3,224				2,127
Other (c)				3,162				3,843						3,286				3,952
Austin Chalk (c)				1,915				2,392						2,033				2,581
Eagle Ford Shale (c)				3,785				1,354						2,529				1,136
Other				375				405						418				319
Total				11,967				10,837						11,490				10,115
Natural Gas (Mcf):
Permian Basin Area:
Delaware Basin				2,615				2,129						2,671				1,720
Other (c)				7,209				7,167						6,932				7,963
Austin Chalk (c)				1,706				2,057						1,766				2,043
Eagle Ford Shale (c)				766				86						464				78
Other				5,182				4,159						4,334				5,149
Total				17,478				15,598						16,167				16,953
Natural Gas Liquids (Bbls):
Permian Basin Area:
Delaware Basin				366				369						449				316
Other (c)				846				809						820				880
Austin Chalk (c)				203				228						189				223
Eagle Ford Shale (c)				169				20						111				19
Other				57				20						34				20
Total				1,641				1,446						1,603				1,458
BOE:
Permian Basin Area:
Delaware Basin				3,532				3,567						4,118				2,730
Other (c)				5,209				5,847						5,261				6,159
Austin Chalk (c)				2,402				2,963						2,517				3,145
Eagle Ford Shale (c)				4,082				1,388						2,717				1,168
Other				1,296				1,118						1,175				1,197
Total				16,521				14,883						15,788				14,399
Oil and Gas Costs ($/BOE Produced):
Production costs			$	18.61			$	18.37					$	18.27			$	20.63
Production costs (excluding production taxes)			$	15.71			$	14.39					$	14.57			$	16.75
Oil and gas depletion			$	25.93			$	27.78					$	24.73			$	26.13
______

(a) Oil and gas sales includes $1.9 million for the three months ended December 31, 2014, $2.1 million for the three months ended December 31, 2013, $7.7 million for the year ended December 31, 2014, and $8.7 million for the year ended December 31, 2013 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 24,469 barrels of oil and 11,784 Mcf of gas for the three months ended December 31, 2014, 28,045 barrels of oil and 10,030 Mcf of gas for the three months ended December 31, 2013, 102,011 barrels of oil and 45,392 Mcf of gas for the year ended December 31, 2014 and 116,941 barrels of oil and 33,619 Mcf of gas for the year ended December 31, 2013 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 2014 or 2013 derivative contracts as cash flow hedges. This means that the Company's derivatives for 2014 and 2013 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) Following is a recap of the average daily production related to interests in producing properties sold by the Company effective March 2014 (non-core Austin Chalk/Eagle Ford) and April 2013 (Andrews County Wolfberry).

			Three Months Ended December 31,				Year Ended December 31,
			2013				2014			2013
Average Daily Production:
Austin Chalk/Eagle Ford:
Oil (Bbls)			707				93			773
Natural gas (Mcf)			98				11			121
NGL (Bbls)			22				3			25
Total (BOE)			745				98			818
Andrews County Wolfberry:
Oil (Bbls)			—				—			403
Natural gas (Mcf)			—				—			447
NGL (Bbls)			—				—			88
Total (BOE)			—				—			566

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 2015, as compared to our actual expenditures in 2014.

			Actual Expenditures Year Ended December 31, 2014					Planned Expenditures Year Ending December 31, 2015					2015 Percentage of Total Planned Expenditures
			(In thousands)
Drilling and Completion
Permian Basin Area:
Delaware Basin			$	152,200				$	34,200				32	%
Other				26,800					11,900				11	%
Austin Chalk/Eagle Ford Shale				160,200					26,400				25	%
Other				8,900					4,900				4	%
				348,100					77,400				72	%
Leasing and seismic				56,200					30,000				28	%
Exploration and development			$	404,300				$	107,400				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, all of which were entered into in February 2015, applicable to periods subsequent to December 31, 2014. The settlement prices of commodity derivatives are based on NYMEX futures prices.

Swaps:
				Oil
				Bbls			Price
Production Period:
2nd Qtr 2015				448,000			$	55.65
3rd Qtr 2015				697,000			$	55.65
4th Qtr 2015				592,000			$	55.65
				1,737,000

CLAYTON WILLIAMS ENERGY, INC.

PROVED RESERVES

(Unaudited)

The following table sets forth our estimated quantities of proved reserves as of December 31, 2014 and 2013, 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, 2014:
Developed				29,059				4,668				51,072				42,239
Undeveloped				24,808				4,299				24,503				33,191
Total Proved				53,867				8,967				75,575				75,430
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
_____
(a) Natural gas reserves have been converted to oil equivalents at the rate of six Mcf to one barrel of oil.

PV-10 remained unchanged at $1.4 billion at December 31, 2014, compared to December 31, 2013. Commodity prices used at December 31, 2014 and December 31, 2013 were based on the 12-month weighted average of the first-day-of-the-month prices from January through December of the respective years and averaged $94.99 per barrel of oil and $4.35 per MMBtu of natural gas for 2014 and $96.78 per barrel of oil and $3.67 per MMBtu for 2013. 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 of $90.48 per barrel of oil, $31.54 per barrel of NGL and $4.27 per Mcf of natural gas for 2014 and $94.88 per barrel of oil, $31.63 per barrel of NGL and $3.59 per Mcf of natural gas for 2013.

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,
			2014					2013
			(In thousands)
PV-10, a non-GAAP financial measure			$	1,379,979				$	1,380,948
Less present value, discounted at 10%, of:
Estimated asset retirement obligations				(34,452	)				(38,518	)
Estimated future income taxes				(412,614	)				(415,507	)
Standardized measure of discounted future net cash flows, a GAAP financial measure			$	932,913				$	926,923