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Press release from Business Wire

Clayton Williams Energy Announces 2012 Financial Results and Year-End Reserves

Thursday, February 21, 2013

Clayton Williams Energy Announces 2012 Financial Results and Year-End Reserves07:50 EST Thursday, February 21, 2013 MIDLAND, Texas (Business Wire) -- Clayton Williams Energy, Inc. (the “Company”) (NASDAQ:CWEI) today reported its financial results for the quarter and year ended December 31, 2012. HighlightsOil 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 Additions77% Oil and NGL and 58% Proved DevelopedFinancial 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 gain and 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.     CLAYTON WILLIAMS ENERGY, INC.CONSOLIDATED STATEMENTS OF OPERATIONS(Unaudited)(In thousands, except per share)                 Three Months EndedYear EndedDecember 31,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)         ASSETSDecember 31,December 31,   2012     2011   (Unaudited) CURRENT ASSETS 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 EndedYear EndedDecember 31,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 EndedYear EndedDecember 31,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 EndedYear EndedDecember 31,December 31,2012201120122011   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   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 a 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.             ActualPlannedExpendituresExpenditures2013Year EndedYear EndingPercentageDecember 31, 2012December 31, 2013of 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     GasSwaps:Bbls     PriceMMBtu (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             Natural GasNaturalTotal OilOilLiquidsGasEquivalents(a)Reserve Category(MBbls)(MBbls)(MMcf)(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   Clayton Williams Energy, Inc.Patti Hollums, 432-688-3419Director of Investor Relationse-mail: cwei@claytonwilliams.comwebsite: www.claytonwilliams.comorMichael L. Pollard, 432-688-3029Chief Financial Officer