Exhibit 99.1

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

MIDLAND, Texas--(BUSINESS WIRE)--February 22, 2012--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.

Highlights

• 2011 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 Developed
• 384% of 2011 Production Replaced by Reserve Additions

Financial 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.

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.
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.

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.

CONTACT:
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