News Column

Clayton Williams Energy Announces 2013 Financial Results and Year-End Reserves

February 20, 2014

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

Highlights

  • 2013 Oil and Gas Production of 5.3 Million BOE, up 8% pro forma
  • Total Proved Reserves of 70 Million BOE
  • 526% of 2013 Production Replaced by Reserve Additions
  • 82% Oil and NGL and 55% Proved Developed
  • Total Debt down 21% to $640 Million

    Financial Results for Fiscal Year 2013

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

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

  • In April 2013, the Company sold 95% of its oil and gas reserves, leasehold interests and facilities located in Andrews County, Texas for $215.2 million, subject to customary closing adjustments. As a result, reported oil and gas production, revenues and operating costs for the quarter and year ended December 31, 2013 are not comparable to reported amounts for periods in 2012.
  • Oil and gas sales, excluding amortized deferred revenues, decreased $3.6 million in 2013 compared to 2012. Production variances accounted for a decrease of $15.6 million, and price variances accounted for a $12 million increase. Average realized oil prices were $95.05 per barrel in 2013 versus $90.97 per barrel in 2012, average realized gas prices were flat at $3.59 per Mcf in 2013 and 2012, and average realized natural gas liquids (“NGL”) prices were $33.26 per barrel in 2013 versus $38.95 per barrel in 2012. Oil and gas sales in 2013 also include $8.7 million of amortized deferred revenue versus $8.3 million in 2012 attributable to a volumetric production payment (“VPP”). Reported production and related average realized sales prices exclude volumes associated with the VPP.
  • Before giving effect to the Andrews sale discussed above, oil, gas and NGL production for 2013 on a barrel of oil equivalent (“BOE”) basis declined 6% compared to 2012 with oil production decreasing 3% to 10,115 barrels per day, gas production decreasing 23% to 16,953 Mcf per day, and NGL production increasing 23% to 1,458 barrels per day. Oil and NGL production accounted for 80% of total production in 2013 versus 76% in 2012. See accompanying tables for additional information about the Company's oil and gas production.
  • After giving effect to the Andrews sale, oil, gas and NGL production per BOE increased 8% in 2013 as compared to 2012, with oil production increasing 1,141 barrels per day, gas production decreasing 3,933 Mcf per day and NGL production increasing 580 barrels per day.
  • Production costs decreased 13% to $108.4 million in 2013 from $125 million in 2012 due primarily to a reduction in costs associated with the Andrews sale, lower salt water disposal costs and other cost savings resulting from infrastructure improvements in Reeves County.
  • Loss on derivatives for 2013 was $8.7 million (net of a $0.7 million gain on settled contracts) versus a gain in 2012 of $14.4 million (net of a $3.4 million loss on settled contracts). See accompanying tables for additional information about the Company's accounting for derivatives.
  • Interest expense increased to $43.1 million in 2013 from $38.7 million in 2012 due primarily to the issuance in October 2013 of $250 million aggregate principal amount of 7.75% Senior Notes due 2019.
  • General and administrative (“G&A”) expenses for 2013 were $33.3 million versus $30.5 million in 2012. Higher personnel and professional costs in 2013 accounted for an increase of approximately $4.8 million, which was partially offset by a reduction in costs related to $2 million of non-recurring donations reported in 2012.

    Financial Results for the Fourth Quarter of 2013

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

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

  • Oil and gas sales, excluding amortized deferred revenues, increased $9.1 million in 4Q13 versus 4Q12. Price variances accounted for a $5.6 million increase, and production variances accounted for a $3.5 million increase. Average realized oil prices were $92.03 per barrel in 4Q13 versus $85.86 per barrel in 4Q12, average realized gas prices were $3.68 per Mcf in 4Q13 versus $4.02 per Mcf in 4Q12, and average realized NGL prices were $35.73 per barrel in 4Q13 versus $36.35 per barrel in 4Q12. Oil and gas sales in 4Q13 also include $2.1 million of amortized deferred revenue versus $2.4 million in 4Q12 attributable to a VPP. Reported production and related average realized sales prices exclude volumes associated with the VPP.
  • Before giving effect to the Andrews sale, oil, gas and NGL production per BOE declined 1% in 4Q13 as compared to 4Q12, with oil production increasing 7% to 10,837 barrels per day, gas production decreasing 25% to 15,598 Mcf per day, and NGL production increasing 3% to 1,446 barrels per day. Oil and NGL production accounted for approximately 83% of the Company's total BOE production in 4Q13 versus 77% in 4Q12. See accompanying tables for additional information about the Company's oil and gas production.
  • After giving effect to the Andrews sale, oil, gas and NGL production per BOE increased 16% in 4Q13 as compared to 4Q12, with oil production increasing 2,261 barrels per day, gas production decreasing 3,576 Mcf per day and NGL production increasing 435 barrels per day.
  • Production costs decreased 19% to $25.2 million in 4Q13 from $31 million in 4Q12, due primarily to a reduction in costs associated with the Andrews sale, lower salt water disposal costs and other cost savings resulting from infrastructure improvements in Reeves County.
  • Gain on derivatives for 4Q13 was $1.2 million (net of a $2.1 million gain on settled contracts) versus a gain in 4Q12 of $4.6 million (net of a $1.6 million gain on settled contracts). See accompanying tables for additional information about the Company's accounting for derivatives.
  • Interest expense increased to $13 million in 4Q13 from $10.8 million in 4Q12 due primarily to the issuance in October 2013 of $250 million aggregate principal amount of 7.75% Senior Notes due 2019.
  • G&A expenses for 4Q13 were $12.9 million versus $5.4 million for 4Q12. Compensation expense related to the Company’s APO reward plans accounted for a charge of $3 million in 4Q13 as compared to a credit for reversal of previously accrued compensation of $2.1 million in 4Q12. The remaining $2.4 million increase was attributable primarily to higher professional costs in 4Q13 than in 4Q12.

    Capitalization and Liquidity

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

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

    Reserves

    The Company reported that its total estimated proved oil and gas reserves as of December 31, 2013 were 70 million barrels of oil equivalent (“MMBOE”), consisting of 48.7 million barrels of oil, 8.5 million barrels of NGL and 77.2 Bcf of natural gas. On a BOE basis, oil and NGL comprised 82% of total proved reserves at year-end 2013 versus 77% at year-end 2012. Proved developed reserves at year-end 2013 were 38.3 MMBOE, or 55% of total proved reserves, versus 43.4 MMBOE, or 58% of total proved reserves, at year-end 2012. The present value of estimated future net cash flows from total proved reserves, before deductions for estimated future income taxes and asset retirement obligations, discounted at 10%, (referred to as “PV-10”) totaled $1.4 billion for year-end 2013 versus $1.3 billion for year-end 2012. See accompanying tables for a reconciliation of PV-10 (a non-GAAP measure) to standardized measure of discounted future net cash flows.

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

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


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

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

    SEC guidelines require that the Company's estimated proved reserves and related PV-10 be determined using benchmark commodity prices equal to the unweighted arithmetic average of the first-day-of-the-month price for the 12-month period prior to the effective date of each reserve estimate. The benchmark averages for 2013 were $96.78 per barrel of oil and $3.67 per MMBtu of natural gas, as compared to $94.71 per barrel and $2.75 per MMBtu for 2012. These benchmark prices were further adjusted for quality, energy content, transportation fees and other price differentials specific to the Company's properties, resulting in an average adjusted price over the remaining life of the proved reserves of $94.88 per barrel of oil, $31.63 per barrel of NGL and $3.59 per Mcf of natural gas for year-end 2013, as compared to $90.45 per barrel of oil, $43.74 per barrel of NGL and $3.70 per Mcf of natural gas for year-end 2012.

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

    Scheduled Conference Call

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

    To access the conference call via Internet webcast, please go to the Investor Relations section of the Company's website at www.claytonwilliams.com and click on “Live Webcast.” Following the live webcast, the call will be archived for a period of 30 days on the Company's website.

    Clayton Williams Energy, Inc. is an independent energy company located in Midland, Texas.

    This release contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934.All statements, other than statements of historical or current facts, that address activities, events, outcomes and other matters that we plan, expect, intend, assume, believe, budget, predict, forecast, project, estimate or anticipate (and other similar expressions) will, should or may occur in the future are forward-looking statements.These forward-looking statements are based on management's current belief, based on currently available information, as to the outcome and timing of future events.The Company cautions that its future natural gas and liquids production, revenues, cash flows, liquidity, plans for future operations, expenses, outlook for oil and natural gas prices, timing of capital expenditures and other forward-looking statements are subject to all of the risks and uncertainties, many of which are beyond our control, incident to the exploration for and development, production and marketing of oil and gas.

    These risks include, but are not limited to, the possibility of unsuccessful exploration and development drilling activities, our ability to replace and sustain production, commodity price volatility, domestic and worldwide economic conditions, the availability of capital on economic terms to fund our capital expenditures and acquisitions, our level of indebtedness, the impact of the current economic recession on our business operations, financial condition and ability to raise capital, declines in the value of our oil and gas properties resulting in a decrease in our borrowing base under our credit facility and impairments, the ability of financial counterparties to perform or fulfill their obligations under existing agreements, the uncertainty inherent in estimating proved oil and gas reserves and in projecting future rates of production and timing of development expenditures, drilling and other operating risks, lack of availability of goods and services, regulatory and environmental risks associated with drilling and production activities, the adverse effects of changes in applicable tax, environmental and other regulatory legislation, and other risks and uncertainties are described in the Company's filings with the Securities and Exchange Commission.The Company undertakes no obligation to publicly update or revise any forward-looking statements.

     
     
    CLAYTON WILLIAMS ENERGY, INC.
    CONSOLIDATED STATEMENTS OF OPERATIONS
    (Unaudited)
    (In thousands, except per share)
                   
    Three Months EndedYear Ended
    December 31,December 31,
      2013     2012     2013     2012  
    REVENUES
    Oil and gas sales $ 103,804 $ 95,027 $ 399,950 $ 403,143
    Midstream services 1,592 669 4,965 1,974
    Drilling rig services 4,916 4,380 17,812 15,858
    Other operating revenues   1,955     1,534     6,488     2,077  
    Total revenues   112,267     101,610     429,215     423,052  
     
    COSTS AND EXPENSES
    Production 25,151 31,013 108,405 124,950
    Exploration:
    Abandonments and impairments 2,907 1,930 5,887 4,222
    Seismic and other 365 6,146 3,906 11,591
    Midstream services 498 272 1,816 1,228
    Drilling rig services 3,586 5,259 16,290 17,423
    Depreciation, depletion and amortization 41,039 39,201 150,902 142,687
    Impairment of property and equipment 233 89,811 5,944
    Accretion of asset retirement obligations 1,034 1,068 4,203 3,696
    General and administrative 12,878 5,352 33,279 30,485
    Other operating expenses   232     548     2,101     1,033  
    Total costs and expenses   87,690     91,022     416,600     343,259  
    Operating income   24,577     10,588     12,615     79,793  
     
    OTHER INCOME (EXPENSE)
    Interest expense (12,973 ) (10,847 ) (43,079 ) (38,664 )
    Gain (loss) on derivatives 1,188 4,592 (8,731 ) 14,448
    Other   (102 )   795     1,905     1,534  
    Total other expense   (11,887 )   (5,460 )   (49,905 )   (22,682 )
    Income (loss) before income taxes 12,690 5,128 (37,290 ) 57,111
    Income tax (expense) benefit   (6,265 )   (3,450 )   12,428     (22,008 )
    NET INCOME (LOSS) $ 6,425   $ 1,678   $ (24,862 ) $ 35,103  
     
    Net income (loss) per common share:
    Basic $ 0.53   $ 0.14   $ (2.04 ) $ 2.89  
    Diluted $ 0.53   $ 0.14   $ (2.04 ) $ 2.89  
    Weighted average common shares outstanding:
    Basic   12,165     12,164     12,165     12,164  
    Diluted   12,165     12,164     12,165     12,164  
     
     
    CLAYTON WILLIAMS ENERGY, INC.
    CONSOLIDATED BALANCE SHEETS
    (In thousands)
     
    ASSETS
        December 31,     December 31,
      2013     2012  
    CURRENT ASSETS (Unaudited)
     
    Cash and cash equivalents $ 26,623 $ 10,726
    Accounts receivable:
    Oil and gas sales 39,268 32,371
    Joint interest and other, net 17,121 16,767
    Affiliates 264 353
    Inventory 39,183 41,703
    Deferred income taxes 7,581 8,560
    Fair value of derivatives 2,518 7,495
    Prepaids and other   5,753     6,495  
      138,311     124,470  
    PROPERTY AND EQUIPMENT
    Oil and gas properties, successful efforts method 2,403,277 2,570,803
    Pipelines and other midstream facilities 54,800 49,839
    Contract drilling equipment 96,270 91,163
    Other   20,620     20,245  
    2,574,967 2,732,050
    Less accumulated depreciation, depletion and amortization   (1,375,860 )   (1,311,692 )
    Property and equipment, net   1,199,107     1,420,358  
     
    OTHER ASSETS
    Debt issue costs, net 12,785 10,259
    Fair value of derivatives 4,236
    Investments and other   16,534     15,261  
      29,319     29,756  
    $ 1,366,737   $ 1,574,584  
     
    LIABILITIES AND STOCKHOLDERS' EQUITY
    CURRENT LIABILITIES
    Accounts payable:
    Trade $ 75,872 $ 73,026
    Oil and gas sales 37,834 32,146
    Affiliates 874 164
    Fair value of derivatives 208
    Accrued liabilities and other   21,607     15,578  
      136,395     120,914  
    NON-CURRENT LIABILITIES
    Long-term debt 639,638 809,585
    Deferred income taxes 140,809 155,830
    Asset retirement obligations 49,981 51,477
    Deferred revenue from volumetric production payment 29,770 37,184
    Accrued compensation under non-equity award plans 15,469 20,058
    Other   892     920  
      876,559     1,075,054  
     
    STOCKHOLDERS’ EQUITY
    Preferred stock, par value $.10 per share
    Common stock, par value $.10 per share 1,216 1,216
    Additional paid-in capital 152,556 152,527
    Retained earnings   200,011     224,873  
    Total stockholders' equity   353,783     378,616  
    $ 1,366,737   $ 1,574,584  
     
     
    CLAYTON WILLIAMS ENERGY, INC.
    CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
    (Unaudited)
    (In thousands)
     
        Three Months Ended     Year Ended
    December 31,December 31,
      2013         2012     2013         2012  
    CASH FLOWS FROM OPERATING ACTIVITIES
    Net income (loss) $ 6,425 $ 1,678 $ (24,862 ) $ 35,103
    Adjustments to reconcile net income (loss) to cash provided by operating activities:
    Depreciation, depletion and amortization 41,039 39,201 150,902 142,687
    Impairment of property and equipment 233 89,811 5,944
    Exploration costs 2,907 1,930 5,887 4,222
    Gain on sales of assets and impairment of inventory, net (1,497 ) (405 ) (3,024 ) (463 )
    Deferred income tax expense (benefit) 4,651 3,450 (14,042 ) 22,008
    Non-cash employee compensation 2,404 (2,604 ) (3,493 ) (404 )
    (Gain) loss on derivatives (1,188 ) (4,592 ) 8,731 (14,448 )
    Cash settlements of derivatives 2,054 1,551 690 (3,410 )
    Accretion of asset retirement obligations 1,034 1,068 4,203 3,696
    Amortization of debt issue costs and original issue discount 985 967 3,266 2,554
    Amortization of deferred revenue from volumetric production payment (2,107 ) (2,433 ) (8,746 ) (8,295 )
    Changes in operating working capital:
    Accounts receivable (6,975 ) 149 (7,163 ) 7,299
    Accounts payable 16,800 (3,614 ) 12,740 (9,386 )
    Other   (5,502 )   (5,240 )   11     2,115  
    Net cash provided by operating activities   61,030     31,339     214,911     189,222  
    CASH FLOWS FROM INVESTING ACTIVITIES
    Additions to property and equipment (80,111 ) (88,039 ) (288,133 ) (526,521 )
    Proceeds from volumetric production payment 298 447 1,332 45,479
    Proceeds from sales of assets 61,858 2,911 259,799 3,778
    (Increase) decrease in equipment inventory (6,544 ) 1,249 (726 ) 1,313
    Other   (146 )   113     (1,315 )   (82 )
    Net cash used in investing activities   (24,645 )   (83,319 )   (29,043 )   (476,033 )
    CASH FLOWS FROM FINANCING ACTIVITIES
    Proceeds from long-term debt 231,000 40,000 274,000 280,000
    Repayments of long-term debt (264,000 ) (444,000 )
    Proceeds from exercise of stock options   29     12     29     12  
    Net cash provided by (used in) financing activities   (32,971 )   40,012     (169,971 )   280,012  
    NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 3,414 (11,968 ) 15,897 (6,799 )
    CASH AND CASH EQUIVALENTS
    Beginning of period   23,209     22,694     10,726     17,525  
    End of period $ 26,623   $ 10,726   $ 26,623   $ 10,726  
     
     

    CLAYTON WILLIAMS ENERGY, INC.

    COMPUTATION OF EBITDAX

    (Unaudited)

    (In thousands)

    EBITDAX is presented as a supplemental non-GAAP financial measure because of its wide acceptance by financial analysts, investors, debt holders, banks, rating agencies and other financial statement users as an indication of an entity's ability to meet its debt service obligations and to internally fund its exploration and development activities.

    The Company defines EBITDAX as net income (loss) before interest expense, income taxes, exploration costs, net (gain) loss on sales of assets and impairment of inventory, and all non-cash items in the Company's statements of operations, including depreciation, depletion and amortization, impairment of property and equipment, accretion of asset retirement obligations, amortization of deferred revenue from volumetric production payment, certain employee compensation and changes in fair value of derivatives. EBITDAX is not an alternative to net income (loss) or cash flow from operating activities, or any other measure of financial performance presented in conformity with GAAP.

    The following table reconciles net income (loss) to EBITDAX:

        Three Months Ended     Year Ended
    December 31,December 31,
      2013         2012     2013         2012  
     
    Net income (loss) $ 6,425 $ 1,678 $ (24,862 ) $ 35,103
    Interest expense 12,973 10,847 43,079 38,664
    Income tax expense (benefit) 6,265 3,450 (12,428 ) 22,008
    Exploration:
    Abandonments and impairments 2,907 1,930 5,887 4,222
    Seismic and other 365 6,146 3,906 11,591
    Net gain on sales of assets and impairment of inventory (1,497 ) (405 ) (3,024 ) (463 )
    Depreciation, depletion and amortization 41,039 39,201 150,902 142,687
    Impairment of property and equipment 233 89,811 5,944
    Accretion of asset retirement obligations 1,034 1,068 4,203 3,696
    Amortization of deferred revenue from volumetric production payment (2,107 ) (2,433 ) (8,746 ) (8,295 )
    Non-cash employee compensation 2,404 (2,604 ) (3,493 ) (404 )
    (Gain) loss on derivatives (1,188 ) (4,592 ) 8,731 (14,448 )
    Cash settlements of derivatives   2,054     1,551     690     (3,410 )
    EBITDAX (a) $ 70,674   $ 56,070   $ 254,656   $ 236,895  
    ______
    (a)   In April 2013, the Company sold 95% of its interests in certain properties in Andrews County, Texas. Revenue, net of direct expenses, associated with the sold properties for the three months ended December 31, 2012 were $7 million and the year ended December 31, 2013 and 2012 were $8.7 million and $45.8 million, respectively.
     
     
    CLAYTON WILLIAMS ENERGY, INC.
    SUMMARY PRODUCTION AND PRICE DATA
    (Unaudited)
     
        Three Months Ended     Year Ended
    December 31,December 31,
    2013     20122013     2012
    Oil and Gas Production Data:
    Oil (MBbls) 997 932 3,692 3,821
    Gas (MMcf) 1,435 1,918 6,188 8,072
    Natural gas liquids (MBbls) 133 129 532 433
    Total (MBOE) 1,369 1,381 5,255 5,599
     
    Average Realized Prices (a) (b):
    Oil ($/Bbl) $ 92.03   $ 85.86 $ 95.05   $ 90.97  
    Gas ($/Mcf) $ 3.68   $ 4.02 $ 3.59   $ 3.59  
    Natural gas liquids ($/Bbl) $ 35.73   $ 36.35 $ 33.26   $ 38.95  
     
    Gain (Loss) on Settled Derivative Contracts (b):
    ($ in thousands, except per unit)
    Oil:
    Net realized gain (loss) $ 2,142 $ 1,551 $ 1,162 $ (3,410 )
    Per unit produced ($/Bbl) $ 2.15 $ 1.66 $ 0.31 $ (0.89 )
    Gas:
    Net realized loss $ (89 ) $ $ (472 ) $
    Per unit produced ($/Mcf) $ (0.06 ) $ $ (0.08 ) $
     
    Average Daily Production:
    Oil (Bbls):
    Permian Basin Area:
    Delaware Basin 2,843 1,897 2,127 1,656
    Other (c) 3,843 5,042 3,952 5,369
    Austin Chalk 2,392 2,639 2,581 2,728
    Eagle Ford Shale 1,354 312 1,136 346
    Other   405     240   319     341  
    Total   10,837     10,130   10,115     10,440  
     
    Natural Gas (Mcf):
    Permian Basin Area:
    Delaware Basin 2,129 1,297 1,720 910
    Other (c) (d) 7,167 11,832 7,963 12,560
    Austin Chalk 2,057 2,133 2,043 2,029
    Eagle Ford Shale 86 2 78 5
    Other   4,159     5,584   5,149     6,551  
    Total   15,598     20,848   16,953     22,055  
     
    Natural Gas Liquids (Bbls):
    Permian Basin Area:
    Delaware Basin 369 319 316 168
    Other (c) (d) 809 711 880 693
    Austin Chalk 228 344 223 267
    Eagle Ford Shale 20 19
    Other   20     28   20     55  
    Total   1,446     1,402   1,458     1,183  
     
    Oil and Gas Costs ($/BOE Produced):
    Production costs $ 18.37 $ 22.46 $ 20.63 $ 22.32
    Production costs (excluding production taxes) $ 14.39 $ 19.12 $ 16.75 $ 18.70
    Oil and gas depletion $ 27.78 $ 25.92 $ 26.13 $ 23.84
    ______
    (a)   Oil and gas sales includes $2.1 million for the three months ended December 31, 2013, $2.4 million for the three months ended December 31, 2012, $8.7 million for the year ended December 31, 2013, and $8.3 million for the year ended December 31, 2012 of amortized deferred revenue attributable to a volumetric production payment (“VPP”) transaction effective March 1, 2012. The calculation of average realized sales prices excludes production of 28,045 barrels of oil and 10,030 Mcf of gas for the three months ended December 31, 2013, 31,979 barrels of oil and 17,558 Mcf of gas for the three months ended December 31, 2012, 116,941 barrels of oil and 33,619 Mcf of gas for the year ended December 31, 2013 and 109,733 barrels of oil and 49,558 Mcf of gas for the year ended December 31, 2012 associated with the VPP.
     
    (b) Hedging gains/losses are only included in the determination of the Company's average realized prices if the underlying derivative contracts are designated as cash flow hedges under applicable accounting standards. The Company did not designate any of its 2013 or 2012 derivative contracts as cash flow hedges. This means that the Company's derivatives for 2013 and 2012 have been marked-to-market through its statement of operations as other income/expense instead of through accumulated other comprehensive income on the Company's balance sheet. This also means that all realized gains/losses on these derivatives are reported in other income/expense instead of as a component of oil and gas sales.
     
    (c) In April 2013, the Company sold 95% of its interest in certain properties in Andrews County, Texas. Following is a recap of the average daily production related to the sold interest for periods prior to April 1, 2013.
        Three Months Ended       Year Ended
    December 31,December 31,
    20122013     2012
    Average Daily Production:    
    Oil (Bbls) 1,554 403 1,869
    Natural gas (Mcf) 1,674 447 1,615
    NGL (Bbls) 391 88 393
    Total (Boe) 2,224 566 2,531
    (d)   Prior to 2013, certain purchasers of the Company's casinghead gas accounted for the value of extracted NGL in the price paid for gas production at the wellhead. During the quarter ended March 31, 2013, the Company began separating these products, when possible. Had these incremental NGL volumes been reported separately during the three months and year ended December 31, 2012, the Company estimates that its reported natural gas volumes would have decreased by 2,200 Mcf/day and that its reported NGL volumes would have increased by 600 BOE/day during each of the 2012 periods.
     
     

    CLAYTON WILLIAMS ENERGY, INC.

    SUMMARY OF EXPLORATION AND DEVELOPMENT EXPENDITURES

    (Unaudited)

    The following table summarizes, by area, our planned expenditures for exploration and development activities during 2014, as compared to our actual expenditures in 2013.

        Actual

    Expenditures

    Year Ended

    December 31, 2013

        Planned

    Expenditures

    Year Ending

    December 31, 2014

        2014

    Percentage

    of Total

    (In thousands)
    Drilling and Completion
    Permian Basin Area:
    Delaware Basin $ 109,600 $ 165,200 44 %
    Other 39,800 11,300 3 %
    Austin Chalk/Eagle Ford Shale 64,200 155,500 41 %
    Other   9,300   3,800 1 %
    222,900 335,800 89 %
    Leasing and seismic   52,100   40,400 11 %
    Exploration and development $ 275,000 $ 376,200 100 %
     
     

    CLAYTON WILLIAMS ENERGY, INC.

    SUMMARY OF OPEN COMMODITY DERIVATIVES

    (Unaudited)

    The following summarizes information concerning the Company’s net positions in open commodity derivatives applicable to periods subsequent to December 31, 2013.

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

    CLAYTON WILLIAMS ENERGY, INC.

    PROVED RESERVES

    (Unaudited)

    The following table sets forth our estimated quantities of proved reserves as of December 31, 2013 and 2012, all of which are located in the United States.

        Proved Reserves
        Natural Gas     Natural     Total Oil
    OilLiquidsGas

    Equivalents (a)

    Reserve Category(MBbls)(MBbls)(MMcf)(MBOE)
     
    December 31, 2013:
    Developed 25,989 4,293 47,839 38,255
    Undeveloped 22,676 4,194 29,340 31,760
    Total Proved 48,665 8,487 77,179 70,015
     
    December 31, 2012:
    Developed 27,641 5,044 64,013 43,354
    Undeveloped 21,478 4,138 38,323 32,003
    Total Proved 49,119 9,182 102,336 75,357
    _____
    (a)   Natural gas reserves have been converted to oil equivalents at the rate of six Mcf to one barrel of oil.
     
     


    PV-10 totaled $1.4 billion at December 31, 2013, versus $1.3 billion at December 31, 2012. The benchmark averages for 2013 were $96.78 per barrel of oil and $3.67 per MMBtu of natural gas, as compared to $94.71 per barrel and $2.75 per MMBtu for 2012. These benchmark prices were further adjusted for quality, energy content, transportation fees and other price differentials specific to the Company's properties, resulting in average adjusted commodity prices. Average adjusted commodity prices used at December 31, 2013 and December 31, 2012 were based on the 12-month weighted average of the first-day-of-the-month prices from January through December of the respective years, which for the Company averaged $94.88 per barrel of oil, $31.63 per barrel of NGL and $3.59 per Mcf of natural gas for 2013 and $90.45 per barrel of oil, $43.74 per barrel of NGL and $3.70 per Mcf of natural gas for 2012.

    PV-10 is a non-GAAP financial measure that we believe is useful as a supplemental disclosure to the standardized measure of discounted future net cash flows, a GAAP financial measure. While the standardized measure of discounted future net cash flows is dependent on the unique tax situation of each entity, PV-10 is based on prices and discount factors that are consistent for all entities and can be used within the industry and by securities analysts to evaluate proved reserves on a more comparable basis. The following table reconciles PV-10 to standardized measure of discounted future net cash flows.

        As of December 31,
      2013       2012  
    (In thousands)
    PV-10, a non-GAAP financial measure $ 1,380,948 $ 1,309,415
    Less present value, discounted at 10%, of:
    Estimated asset retirement obligations (38,518 ) (38,750 )
    Estimated future income taxes   (415,507 )   (330,834 )
    Standardized measure of discounted future net cash flows, a GAAP financial measure $ 926,923   $ 939,831  





    Clayton Williams Energy, Inc.

    Patti Hollums, 432-688-3419

    Director of Investor Relations

    e-mail: cwei@claytonwilliams.com

    website: www.claytonwilliams.com

    or

    Michael L. Pollard, 432-688-3029

    Chief Financial Officer


    Source: Clayton Williams Energy, Inc.


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