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

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

MIDLAND, Texas--(BUSINESS WIRE)-- Clayton Williams Energy, Inc. (the "Company") (NAS: CWEI) today reported its financial results for the quarter and year ended December 31, 2012.

Highlights

• Oil 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 Additions

• 77% Oil and NGL and 58% Proved Developed

Financial 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.

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.