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Press release from Business Wire

Clayton Williams Energy Announces 2011 Financial Results and Year-End Reserves

Wednesday, February 22, 2012

Clayton Williams Energy Announces 2011 Financial Results and Year-End Reserves07:50 EST Wednesday, February 22, 2012 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, 2011, along with information about its proved oil and gas reserves as of December 31, 2011. Highlights2011 Cash Flow from Operations of $280 Million, up 34%Total Proved Reserves of 64.3 Million BOE, up 26%77% Oil and NGL and 61% Proved Developed384% of 2011 Production Replaced by Reserve AdditionsFinancial Results for Fiscal Year 2011 Net income attributable to Company stockholders for fiscal 2011 was $93.8 million, or $7.71 per share, as compared to net income of $36.9 million, or $3.04 per share, for fiscal 2010. Cash flow from operations for 2011 was $280 million as compared to $208.3 million for 2010. The key factors affecting the comparability of the two years were: Oil and gas sales increased $78.9 million in 2011 compared to 2010. Price variances accounted for $63.8 million of the increase and production variances accounted for the remaining $15.1 million. Average realized oil prices were $92.43 per barrel in 2011 versus $76.44 per barrel in 2010, and average realized gas prices were $5.30 per Mcf in 2011 versus $5.17 per Mcf in 2010. Although combined oil and gas production for 2011 remained relatively constant on a barrel of oil equivalent (“BOE”) basis compared to 2010, oil and NGL production accounted for 74% of total production in 2011 versus 67% in 2010. Oil production increased 10% compared to 2010, while gas production declined 20%. On a comparable basis, after giving effect to the sale of properties in North Louisiana in June 2010, oil and gas production in 2011 on a BOE basis was 4% higher than 2010. Gain on derivatives for 2011 was $47 million ($42.5 million gain on settled contracts and a $4.5 million non-cash mark-to-market gain) versus a gain in 2010 of $0.7 million ($9.9 million realized gain on settled contracts and a $9.2 million non-cash mark-to-market loss). See accompanying tables for additional information about the Company's accounting for derivatives. Production costs increased 22% to $101.1 million in 2011 from $83.1 million in 2010. Production costs excluding production taxes, referred to as lifting costs, accounted for $14.7 million of the increase due to a combination of more producing wells and rising costs of field services, and production taxes accounted for the remaining $3.3 million of the increase due to higher oil and gas sales. Exploration expenses related to abandonments and impairments were $20.8 million in 2011 compared to $9.1 million in 2010. The expense for 2011 includes a charge of $11.8 million for the abandonment of the Hamill Foundation #1, an exploratory well in Leon County, Texas targeting the Deep Bossier gas formation, and $5 million of leasehold impairments related to the abandonment of the well. Based on the results of a recent stimulation procedure, the Company determined that the well was uneconomic. Interest expense increased to $32.9 million in 2011 from $24.4 million in 2010 due primarily to the increase in the total aggregate principal amount of the Senior Notes from $225 million to $350 million. The Company also recorded a $5.5 million loss on early extinguishment of long-term debt related to the redemption of the 2013 Senior Notes in 2011. Net gain on sales of assets and impairment of inventory was a $14.1 million gain in 2011 compared to a gain of $1.9 million in 2010. 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 for 2011 were $41.6 million versus $35.6 million in 2010. Non-cash employee compensation related to non-equity incentive plans totaled $12.9 million in 2011 versus $13.9 million in 2010. Excluding non-cash employee compensation, general and administrative expenses increased to $28.7 million in 2011 versus $21.7 million in 2010 due to a combination of higher personnel costs and costs associated with the proposed merger with affiliated partnerships. Financial Results for the Fourth Quarter of 2011 Net loss attributable to Company stockholders for the fourth quarter of 2011 (“4Q11”) was $15.5 million, or $1.27 per share, as compared to a net loss of $5.3 million, or $.44 per share, for the fourth quarter of 2010 (“4Q10”). Cash flow from operations for 4Q11 was $104.8 million as compared to $54.1 million for 4Q10. The key factors affecting the comparability of the two quarters were: Oil and gas sales increased $16.3 million in 4Q11 versus 4Q10. Price variances accounted for $9.8 million of the increase while production variances accounted for the remaining $6.5 million. Average realized oil prices were $91.70 per barrel in 4Q11 versus $82.07 per barrel in 4Q10, and average realized gas prices were $4.91 per Mcf in 4Q11 versus $5.02 per Mcf in 4Q10. Combined oil and gas production for 4Q11 was 5% higher on a BOE basis than in 4Q10. Oil production increased 11% compared to 4Q10, while gas production declined 3%. Production costs increased 22% to $25.9 million in 4Q11 from $21.1 million in 4Q10. Production costs excluding production taxes, referred to as lifting costs, accounted for $4.1 million of the increase due to a combination of more producing wells and rising costs of field services, and production taxes accounted for the remaining $0.7 million of the increase due to higher oil and gas sales. Loss on derivatives for 4Q11 was $27.1 million ($77.5 million non-cash mark-to-market loss offset in part by a $50.4 million realized gain on settled contracts) versus a loss in 4Q10 of $26.6 million ($27 million non-cash mark-to-market loss net of a $0.4 million realized gain on settled contracts). See accompanying tables for additional information about the Company's accounting for derivatives. Exploration expenses related to abandonments and impairments were $18.5 million in 4Q11 compared to $2.9 million in 4Q10. The expense for 4Q11 includes charges related to the previously discussed abandonment of the Hamill Foundation #1. General and administrative expenses for 4Q11 were $18.9 million versus $12.8 million in 4Q10. Non-cash employee compensation related to non-equity incentive plans totaled $6.8 million in 4Q11 versus $5.8 million in 4Q10. Excluding non-cash employee compensation, general and administrative expenses increased to $12.1 million in 4Q11 versus $7 million in 4Q10 due to a combination of higher personnel costs and costs associated with the proposed merger with affiliated partnerships. Reserves The Company reported that its total estimated proved oil and gas reserves as of December 31, 2011 were 64.3 million barrels of oil equivalent (“MMBOE”), consisting of 49.5 million barrels of oil and NGL and 88.9 Bcf of natural gas. On a BOE basis, oil and NGL comprised 77% of total proved reserves at year-end 2011 versus 74% at year-end 2010. Proved developed reserves at year-end 2011 were 39.3 MMBOE, or 61% of total proved reserves, as compared to 34.5 MMBOE, or 68% of total proved reserves, at year-end 2010. 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 $1.4 billion for year-end 2011 as compared to $992 million for year-end 2010. 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 2011 on an MMBOE basis.       MMBOE   Total proved reserves, December 31, 2010   51.1 Extensions and discoveries 20.9 Revisions (2.1 ) Sales of reserves (0.2 ) Production   (5.4 )   Total proved reserves, December 31, 2011   64.3       The Company replaced 384% of its 2011 oil and gas production through extensions and discoveries. Most of the 20.9 MMBOE of reserve additions in 2011 were derived from growth through the drill bit in the Permian Basin drilling Wolfberry and Wolfbone wells. Oil and NGL accounted for 84% of the 2011 reserve additions. Revisions of prior year estimates resulted from a combination of 4.9 MMBOE of upward revisions related to the effects of higher commodity prices on economic limits of long-life properties and downward revisions of 7 MMBOE related primarily to changes in estimates based on well performance. 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 2011 were $96.19 per barrel of oil and $4.12 per MMBtu of natural gas, as compared to $79.43 per barrel and $4.38 per MMBtu for 2010. 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 $87.61 per barrel of oil and NGL and $5.31 per Mcf of natural gas for year-end 2011, as compared to $72.36 per barrel and $5.44 per Mcf for year-end 2010. 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, 2011 instead of the SEC mandated benchmark prices, the Company's PV-10 Value for year-end 2011 would have been $1.3 billion. 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,   2011     2010     2011     2010   REVENUES Oil and gas sales $ 104,728 $ 88,382 $ 405,216 $ 326,320 Natural gas services 300 279 1,408 1,631 Drilling rig services 446 - 4,060 - Gain on sales of assets   1,174     424     15,744     3,680   Total revenues   106,648     89,085     426,428     331,631     COSTS AND EXPENSES Production 25,862 21,134 101,099 83,146 Exploration: Abandonments and impairments 18,533 2,941 20,840 9,074 Seismic and other 76 2,051 5,363 6,046 Natural gas services 258 258 1,039 1,209 Drilling rig services 686 (6 ) 5,064 1,198 Depreciation, depletion and amortization 29,893 24,873 104,880 101,145 Impairment of property and equipment 896 - 10,355 11,908 Accretion of asset retirement obligations 680 670 2,757 2,623 General and administrative 18,882 12,802 41,560 35,588 Loss on sales of assets and impairment of inventory   1,249     227     1,666     1,750   Total costs and expenses   97,015     64,950     294,623     253,687   Operating income   9,633     24,135     131,805     77,944     OTHER INCOME (EXPENSE)   Interest expense (8,615 ) (6,009 ) (32,919 ) (24,402 ) Loss on early extinguishment of long-term debt - - (5,501 ) - Gain (loss) on derivatives (27,101 ) (26,567 ) 47,027 722 Other 2,039 492 5,553 3,308         Total other income (expense)   (33,677 )   (32,084 )   14,160     (20,372 )   Income (loss) before income taxes (24,044 ) (7,949 ) 145,965 57,572   Income tax (expense) benefit 8,551 2,626 (52,142 ) (20,634 )         NET INCOME (LOSS) $ (15,493 ) $ (5,323 ) $ 93,823   $ 36,938       Net income (loss) per common share: Basic $ (1.27 ) $ (0.44 ) $ 7.72   $ 3.04   Diluted $ (1.27 ) $ (0.44 ) $ 7.71   $ 3.04     Weighted average common shares outstanding: Basic   12,163     12,153     12,161     12,148   Diluted   12,163     12,153     12,162     12,148       CLAYTON WILLIAMS ENERGY, INC.CONSOLIDATED BALANCE SHEETS(In thousands)       ASSETS   December 31,December 31,   2011     2010   (Unaudited) CURRENT ASSETS Cash and cash equivalents $ 17,525 $ 8,720 Accounts receivable: Oil and gas sales 41,282 35,361 Joint interest and other, net 14,517 9,893 Affiliates 990 796 Inventory 44,868 39,218 Deferred income taxes 8,948 5,074 Assets held for sale - 8,762 Prepaids and other   14,813     5,997     142,943     113,821   PROPERTY AND EQUIPMENT Oil and gas properties, successful efforts method 2,103,085 1,707,252 Natural gas gathering and processing systems 26,040 18,153 Contract drilling equipment 75,956 58,486 Other   19,134     17,425   2,224,215 1,801,316 Less accumulated depreciation, depletion and amortization   (1,156,664 )   (1,034,227 ) Property and equipment, net   1,067,551     767,089     OTHER ASSETS Debt issue costs, net 11,644 8,323 Other   4,133     1,684     15,777     10,007     $ 1,226,271   $ 890,917     LIABILITIES AND STOCKHOLDERS' EQUITY   CURRENT LIABILITIES Accounts payable: Trade $ 98,645 $ 74,123 Oil and gas sales 37,409 28,920 Affiliates 1,501 1,251 Fair value of derivatives 5,633 7,224 Accrued liabilities and other   13,042     22,202     156,230     133,720     NON-CURRENT LIABILITIES Long-term debt 529,535 385,000 Deferred income taxes 134,209 78,035 Fair value of derivatives 494 3,409 Asset retirement obligations 40,794 40,444 Other   21,508     857     726,540     507,745     STOCKHOLDERS' EQUITY Preferred stock, par value $.10 per share - - Common stock, par value $.10 per share 1,216 1,215 Additional paid-in capital 152,515 152,290 Retained earnings   189,770     95,947   Total stockholders' equity   343,501     249,452     $ 1,226,271   $ 890,917       CLAYTON WILLIAMS ENERGY, INC.CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS(Unaudited)(In thousands)             Three Months EndedYear EndedDecember 31,December 31,   2011     2010     2011     2010       CASH FLOWS FROM OPERATING ACTIVITIES Net income (loss) $ (15,493 ) $ (5,323 ) $ 93,823 $ 36,938 Adjustments to reconcile net income (loss) to cash provided by operating activities: Depreciation, depletion and amortization 29,893 24,873 104,880 101,145 Impairment of property and equipment 896 - 10,355 11,908 Exploration costs 18,533 2,941 20,840 9,074 (Gain) loss on sales of assets and impairment of inventory, net 75 (197 ) (14,078 ) (1,930 ) Deferred income tax expense (benefit) (8,143 ) (3,001 ) 52,550 20,259 Non-cash employee compensation 6,762 5,832 12,866 13,898 Unrealized (gain) loss on derivatives 77,523 27,027 (4,506 ) 9,153 Accretion of asset retirement obligations 680 670 2,757 2,623 Amortization of debt issue costs 719 474 2,342 1,648 Loss on early extinguishment of long-term debt - - 5,501 -   Changes in operating working capital: Accounts receivable (11,507 ) (11,779 ) (10,739 ) (10,036 ) Accounts payable 12,007 13,897 7,551 19,144 Other   (7,185 )   (1,331 )   (4,095 )   (5,573 ) Net cash provided by operating activities   104,760     54,083     280,047     208,251     CASH FLOWS FROM INVESTING ACTIVITIES Additions to property and equipment (130,539 ) (77,014 ) (413,013 ) (285,655 ) Proceeds from sales of assets 1,436 1,546 13,902 77,216 Change in equipment inventory (8,149 ) 7,713 (5,305 ) 4,638 Other   (364 )   149     (497 )   18   Net cash used in investing activities   (137,616 )   (67,606 )   (404,913 )   (203,783 )   CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from long-term debt 103,000 - 547,710 - Repayments of long-term debt (88,656 ) - (411,500 ) (10,000 ) Premium on early extinguishment of long-term debt - - (2,765 ) - Proceeds from exercise of stock options   13     239     226     239   Net cash provided by (used in) financing activities   14,357     239     133,671     (9,761 )   NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS (18,499 ) (13,284 ) 8,805 (5,293 )   CASH AND CASH EQUIVALENTS Beginning of period 36,024 22,004 8,720 14,013         End of period $ 17,525   $ 8,720   $ 17,525   $ 8,720       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 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, 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     Year EndedDecember 31,December 31,   2011       2010     2011       2010     Net income (loss) $ (15,493 ) $ (5,323 ) $ 93,823 $ 36,938 Interest expense 8,615 6,009 32,919 24,402 Income tax (benefit) expense (8,551 ) (2,626 ) 52,142 20,634 Exploration: Abandonments and impairments 18,533 2,941 20,840 9,074 Seismic and other 76 2,051 5,363 6,046 Net (gain) loss on sales of assets and impairment of inventory 75 (197 ) (14,078 ) (1,930 ) Loss on early extinguishment of long-term debt - - 5,501 - Depreciation, depletion and amortization 29,893 24,873 104,880 101,145 Impairment of property and equipment 896 - 10,355 11,908 Accretion of asset retirement obligations 680 670 2,757 2,623 Non-cash employee compensation 6,762 5,832 12,866 13,898 Non-cash changes in fair value of derivatives 77,523 27,027 (4,506 ) 9,153         $ 119,009   $ 61,257   $ 322,862   $ 233,891       CLAYTON WILLIAMS ENERGY, INC.SUMMARY PRODUCTION AND PRICE DATA(Unaudited)             Three Months EndedYear EndedDecember 31,December 31,   2011   2010     2011   2010     Oil and Gas Production Data: Oil (MBbls) 997 900 3,727 3,375 Gas (MMcf) 2,025 2,085 8,594 10,750 Natural gas liquids (MBbls) 58 85 275 292 Total (MBOE) 1,393 1,333 5,434 5,459   Average Realized Prices (a): Oil ($/Bbl) $ 91.70 $ 82.07   $ 92.43 $ 76.44   Gas ($/Mcf) $ 4.91 $ 5.02   $ 5.30 $ 5.17   Natural gas liquids ($/Bbl) $ 54.76 $ 47.56   $ 53.37 $ 42.47     Gain (Loss) on Settled Derivative Contracts (a): ($ in thousands, except per unit) Oil: Net realized gain (loss) $ 45,343 $ (4,587 ) $ 23,354 $ (7,685 ) Per unit produced ($/Bbl) $ 45.48 $ (5.10 ) $ 6.27 $ (2.28 )   Gas: Net realized gain $ 5,079 $ 5,047 $ 19,167 $ 17,560 Per unit produced ($/Mcf) $ 2.51 $ 2.42 $ 2.23 $ 1.63   Average Daily Production: Oil (Bbls): Permian Basin Area: West Texas Andrews 2,696 2,390 2,643 1,806 West Texas Reeves 636 - 202 - West Texas Other 3,525 3,583 3,417 3,795 Austin Chalk/ Eagle Ford Shale 3,640 3,292 3,477 2,944 South Louisiana 271 447 399 559 Other   69   71     73   143   (b) Total   10,837   9,783     10,211   9,247     Natural Gas (Mcf): Permian Basin Area: West Texas Andrews 446 1,261 1,038 834 West Texas Other 9,763 12,305 11,266 12,834 Giddings Area: Austin Chalk/ Eagle Ford Shale 2,477 2,049 2,142 2,179 Cotton Valley Reef Complex 3,243 3,092 3,021 3,599 South Louisiana 5,314 3,010 4,970 5,265 Other   768   946     1,108   4,741   (b) Total   22,011   22,663     23,545   29,452     Natural Gas Liquids (Bbls): Permian Basin Area: West Texas Andrews 118 406 237 240 West Texas Other 225 193 224 200 Austin Chalk/ Eagle Ford Shale 224 231 212 237 South Louisiana 42 69 50 89 Other   21   25     30   34   (b) Total   630   924     753   800     Three Months EndedYear EndedDecember 31,December 31,   2011   2010     2011   2010     Oil and Gas Costs ($/BOE Produced): Production costs $ 18.57 $ 15.85 $ 18.60 $ 15.23 Production costs (excluding production taxes) $ 14.84 $ 12.42 $ 14.79 $ 12.03 Oil and gas depletion $ 20.76 $ 18.52 $ 18.72 $ 18.09   General and Administrative Expenses (in thousands): Excluding non-cash employee compensation $ 12,120 $ 6,970 $ 28,694 $ 21,690 Non-cash employee compensation (c)   6,762   5,832     12,866   13,898   Total $ 18,882 $ 12,802   $ 41,560 $ 35,588       (a) Hedging gains/losses are only included in the determination of the Company's average realized prices if the underlying derivative contracts are designated as cash flow hedges under applicable accounting standards. The Company did not designate any of its 2011 or 2010 derivative contracts as cash flow hedges. This means that the Company's derivatives for 2011 and 2010 have been marked-to-market through its statement of operations as other income/expense instead of through accumulated other comprehensive income on the Company's balance sheet. This also means that all realized gains/losses on these derivatives are reported in other income/expense instead of as a component of oil and gas sales.   (b) Other for 2010 includes production attributable to sold properties in North Louisiana as follows: Twelve months: Oil 71, Gas 3,581, NGL 8.   (c) Non-cash employee compensation relates to the Company's non-equity award plans.     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, 2011.   OilSwaps:Bbls (a)Price Production Period: 1st Quarter 2012 444,000 $ 95.70 2nd Quarter 2012 410,000 $ 95.70 3rd Quarter 2012 384,000 $ 95.70 4th Quarter 2012 362,000 $ 95.70 1,600,000     (a) Excludes oil hedges covering 393,863 barrels of oil for production months from January 2012 through May 2016 at a price of $91.15 per barrel. These hedges cover production related to a volumetric production payment to be granted in connection with the proposed acquisition by our wholly owned subsidiary, Southwest Royalties, Inc., of 24 limited partnerships of which it is the general partner.     CLAYTON WILLIAMS ENERGY, INC.PROVED RESERVES(Unaudited) The following table sets forth our estimated quantities of proved reserves as of December 31, 2011 and 2010, all of which are located in the United States.     Proved Reserves         NaturalTotal OilOil (a)GasEquivalents (b)Reserve Category(MBbls)(MMcf)(MBOE)   December 31, 2011: Developed 28,962 61,811 39,264 Undeveloped 20,574 27,065 25,085 Total Proved 49,536 88,876 64,349     December 31, 2010: Developed 24,570 59,409 34,472 Undeveloped 13,245 20,088 16,593 Total Proved 37,815 79,497 51,065     (a) Oil reserves include crude oil, condensate and natural gas liquids ("NGL"). (b) 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 $1.4 billion at December 31, 2011, as compared to $992 million at December 31, 2010. Average adjusted commodity prices used at December 31, 2011 and December 31, 2010 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 $87.61 per barrel of oil and NGL and $5.31 per Mcf of natural gas for 2011 and $72.36 per barrel of oil and NGL and $5.44 per Mcf of natural gas for 2010. 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,   2011     2010   (In thousands)   PV-10 Value, a non-GAAP financial measure $ 1,375,460 $ 991,748   Less present value, discounted at 10%, of: Estimated asset retirement obligations (29,520 ) (30,445 ) Estimated future income taxes (407,427 ) (276,865 )   Standardized measure of discounted future net cash flows,     a GAAP financial measure $ 938,513   $ 684,438   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