CWEI Clayton Williams Energy, Inc.

Clayton Williams Energy, Inc. (NASDAQ-NMS: CWEI) today filed a Form 8-K with the Securities and Exchange Commission to provide financial guidance disclosures for the year ending December 31, 2011. This guidance was furnished to provide public disclosure of the estimates being used by the Company to model its anticipated results of operations for the periods presented.

A copy of these disclosures accompanies this release or may be obtained electronically by accessing the Company’s website at www.claytonwilliams.com.

Revised Plans for Capital Spending in 2011

The Company now plans to spend $385 million in fiscal 2011 on exploration and development activities, a reduction of $54 million from estimates reported in the Company’s Form 10-Q for the second quarter of 2011. Substantially all of these cost reductions relate to the Company’s planned activities in its Reeves County Wolfbone play and are based on several factors, including a reduction in the total number of wells that the Company expects to be able to drill in the area during the remainder of the year and an increase in the estimated number of those wells in which the Company will own a 75% net working interest versus 100%. These reductions were partially offset by an increase in the estimated cost to drill and complete each of its Wolfbone wells from $3.8 million to $4.2 million as a result of changes in the planned frac design.

Oil and Gas Production

The Company has also revised downward its expected oil and gas production for the remainder of 2011 in connection with the shift in capital spending to the Reeves County Wolfbone play. Since its last guidance in May 2011, the Company has reduced the planned rig count in Andrews County from 3 rigs to 1 and has dropped both rigs previously allocated to the Austin Chalk in order to allocate resources to its Wolfbone play. In addition, estimated production from the Andrews Wolfberry play was revised downward due to continuing frac delays and revisions in production based on well performance.

Oil and Gas Hedge Positions

In August 2011, the Company added hedges of 1.683 million barrels of oil at fixed NYMEX-WTI prices as follows: 4th quarter of 2011 – 189,000 at $98.35; 2012 – 785,000 at $100.75; and 2013 – 709,000 at $102.10. Combined with its other oil hedges, the Company’s cumulative positions and average fixed NYMEX-WTI prices are as follows: 3rd quarter 2011 – 547,000 at $83.78; 4th quarter 2011 – 729,000 at $87.56; 2012 – 2,649,000 at $95.75; and 2013 – 1,189,000 at $99.92. As a percentage of the Company’s estimated production from existing wells, these volumes cover approximately 100% through 2012 and 50% of 2013. In addition, the Company has approximately 3 million MMBtu of natural gas hedged for the remainder of 2011 at $7.07.

“We are watching very closely the economic climate in the US and Europe and the related effects of those factors on the oil markets,” stated Clayton W. Williams, Jr., Chairman, President and Chief Executive Officer of the Company. “Lower spending levels will obviously slow down our production growth somewhat, but cuts in discretionary spending also help us keep our debt levels in check as we guide our company through uncertain times.”

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 oil and natural gas 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 environment 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.

FINANCIAL GUIDANCE DISCLOSURES FOR 2011

Overview

Clayton Williams Energy, Inc. and its subsidiaries have prepared this document to provide public disclosure of certain financial and operating estimates in order to permit the preparation of models to forecast our operating results for each quarter during the year ending December 31, 2011. These estimates are based on information available to us as of the date of this filing, and actual results may vary materially from these estimates. We do not undertake any obligation to update these estimates as conditions change or as additional information becomes available.

The estimates provided in this document are based on assumptions that we believe are reasonable. Until our actual results of operations for these periods have been compiled and released, all of the estimates and assumptions set forth herein constitute “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, included in this document 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, could or may occur in the future, including such matters as production of oil and gas, product prices, oil and gas reserves, drilling and completion results, capital expenditures, operating costs and other such matters, are forward-looking statements. Such forward-looking statements involve known and unknown risks, uncertainties, and other factors that may cause our actual results, performance, or achievements to be materially different from the results, performance, or achievements expressed or implied by such forward-looking statements. Such factors include, among others, the following: the volatility of oil and gas prices; the unpredictable nature of our exploratory drilling results; the reliance upon estimates of proved reserves; operating hazards and uninsured risks; competition; government regulation; and other factors referenced in filings made by us with the Securities and Exchange Commission.

As a matter of policy, we generally do not attempt to provide guidance on:

(a) production which may be obtained through future exploratory drilling;

(b) dry hole and abandonment costs that may result from future exploratory drilling;

(c) the effects of Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities” superseded by topic 815-10 of the Financial Accounting Standards Board Accounting Standards Codification;

(d) gains or losses from sales of property and equipment unless the sale has been consummated prior to the filing of financial guidance;

(e) capital expenditures related to completion activities on exploratory wells or acquisitions of proved properties until the expenditures are estimable and likely to occur; and

(f) revenues and expenses related to Desta Drilling, L.P., a wholly-owned subsidiary of the Company which provides contract drilling services for the Company.

Summary of Estimates

The following table sets forth actual and certain estimates being used by us to model our anticipated results of operations for each quarter during the fiscal year ending December 31, 2011. When a single value is provided, such value represents the mid-point of the approximate range of estimates. Otherwise, each range of values provided represents the expected low and high estimates for such financial or operating factor. See “Supplementary Information.”

  Year Ending December 31, 2011 Actual   Actual   Estimated   Estimated First Quarter Second Quarter Third Quarter Fourth Quarter (Dollars in thousands, except per unit data) Average Daily Production: Oil (Bbls) 9,989 9,736 9,425 to 9,625 10,250 to 10,450 Gas (Mcf) 23,478 24,846 20,500 to 24,500 19,500 to 23,500 Natural gas liquids (Bbls) 922 802 750 to 850 750 to 850 Total oil equivalents (BOE) 14,824 14,679 13,592 to 14,558 14,250 to 15,217   Differentials: Oil (Bbls) $ (5.17 ) $ (2.49 ) $(3.50) to $(4.50) $(3.50) to $(4.50) Gas (Mcf) $ 1.04 $ 1.18 $0.15 to $0.45 $0.15 to $0.45 Natural gas liquids (Bbls) $ (45.76 ) $ (45.40 ) $(42.00) to $(48.00) $(42.00) to $(48.00)   Costs Variable by Production ($/BOE): Production expenses (excluding production taxes) (a) $ 14.67 $ 15.61 $14.75 to $15.75 $14.75 to $15.75 DD&A – Oil and gas properties $ 17.46 $ 18.31 $17.50 to $18.50 $17.50 to $18.50   Other Revenues (Expenses): Natural gas services: Revenues $ 409 $ 365 $450 to $550 $450 to $550 Operating costs $ (263 ) $ (285 ) $(300) to $(500) $(300) to $(500) Exploration costs: Abandonments and impairments $ (877 ) $ (174 ) $(250) to $(750) $(250) to $(750) Seismic and other $ (1,278 ) $ (2,167 ) $(500) to $(2,500) $(500) to $(2,500) DD&A – Other (b) $ (193 ) $ (153 ) $(250) to $(350) $(250) to $(350) General and administrative (b) (c) $ (5,025 ) $ (5,405 ) $(5,100) to $(5,300) $(5,900) to $(6,100) Interest expense $ (6,412 ) $ (9,175 ) $(9,200) to $(9,400) $(8,800) to $(9,000) Other income (expense) $ 1,087 $ 1,900 $(450) to $(550) $(450) to $(550) Gain (loss) on sales of assets, net $ 13,376 $ 842 - -     Effective Federal and State Income

Tax Rate:

Current 0 % 0 % 0 % 0 % Deferred 36 % 36 % 36 % 36 %   Weighted Average Shares Outstanding (In thousands): Basic 12,156 12,162 12,162 12,162 Diluted 12,156 12,163 12,163 12,163  

 

(a) Our current guidance for production expenses excludes production taxes. Historically, production taxes have ranged from 5% to 6% of oil and gas sales.(b) Excludes amounts derived from Desta Drilling, L.P.(c) Excludes non-cash employee compensation.

Oil and Gas Production

We have revised downward our expected oil and gas production for the remainder of 2011 in connection with the shift in capital spending to the Reeves County Wolfbone play. Since our last guidance in May 2011, we have reduced the planned rig count in Andrews County from 3 rigs to 1 and have dropped both rigs previously allocated to the Austin Chalk in order to allocate resources to our Wolfbone play. In addition, estimated production from the Andrews Wolfberry play was revised downward due to continuing frac delays and revisions in production based on well performance.

Capital Expenditures

The following table sets forth, by area, our actual expenditures for exploration and development activities for the first six months of 2011 and our planned expenditures for the year ending December 31, 2011.

      Actual Planned Expenditures Expenditures 2011 Six Months Ended Year Ended Percentage June 30, 2011 December 31, 2011 of Total (In thousands) Permian Basin Area: West Texas - Reeves $ 44,300 $ 188,400 49 % West Texas - Andrews 77,300 112,300 29 % West Texas - Other 13,700 17,700 5 % Giddings Area: Austin Chalk/Eagle Ford Shale 25,900 41,400 11 % Deep Bossier 200 13,800 3 % South Louisiana 3,400 6,800 2 % Other   3,700   4,600 1 % $ 168,500 $ 385,000 100 %  

We currently plan to spend approximately $385 million on exploration and development activities in fiscal 2011, as compared to $439.4 million reported in our Form 10-Q for the second quarter of 2011. Substantially all of these cost reductions relate to our planned activities in the Reeves County Wolfbone play and are based on several factors, including a reduction in the total number of wells that we expect to be able to drill in the area during the remainder of the year and an increase in the estimated number of those wells in which we will own a 75% net working interest versus 100%. These reductions were partially offset by an increase in the estimated cost to drill and complete each of the Wolfbone wells from $3.8 million to $4.2 million as a result of changes in the planned frac design.

We are also purchasing two drilling rigs for our Desta Drilling fleet at a cost of approximately $15.3 million, of which approximately $8 million was spent during the second quarter of 2011. In addition, we plan to spend approximately $15 million during the remainder of 2011 to begin constructing a gas gathering and treating system to facilitate the transportation and marketing of our Wolfbone oil and gas production in Reeves County.

Our actual expenditures during fiscal 2011 may be substantially higher or lower than these estimates since our plans for exploration and development activities may change during the year. Other factors, such as prevailing product prices and the availability of capital resources, could also increase or decrease the ultimate level of expenditures during fiscal 2011. Based on these current estimates, approximately 94% of our planned expenditures for exploration and development activities for fiscal 2011 will relate to developmental prospects, as compared to approximately 95% in fiscal 2010.

Supplementary Information

Oil and Gas Production

The following table summarizes, by area, our actual and estimated daily net production for each quarter during the year ending December 31, 2011. These estimates represent the approximate mid-point of the estimated production range.

  Daily Net Production for 2011 Actual   Actual   Estimated   Estimated First Quarter Second Quarter Third Quarter Fourth Quarter Oil (Bbls): Permian Basin Area: West Texas - Andrews 2,607 2,585 2,744

3,014

West Texas - Reeves - 11 141 1,087 West Texas - Other 3,570 3,095 3,217 3,010 Austin Chalk/Eagle Ford Shale 3,329 3,335 2,978 3,011 South Louisiana 414 493 380 163 Other 69 217 65 65 Total 9,989 9,736 9,525

10,350

  Gas (Mcf): Permian Basin Area: West Texas - Andrews 1,588 1,719 2,011 2,207 West Texas - Reeves 7 25 - - West Texas - Other 12,333 10,457 10,272 9,690 Giddings Area: Austin Chalk/Eagle Ford Shale 1,940 2,177 2,195 2,190 Cotton Valley Reef Complex 2,953 2,931 2,435 2,315 South Louisiana 3,149 6,134 4,576 4,087 Other 1,508 1,403 1,011 1,011 Total 23,478 24,846 22,500 21,500   Natural Gas Liquids (Bbls): Permian Basin Area: West Texas - Andrews 364 368 344 355 West Texas - Other 255 151 195 184 Austin Chalk/Eagle Ford Shale 226 183 196 196 Other 77 100 65 65 Total 922 802 800 800  

Accounting for Derivatives

The following summarizes information concerning our net positions in open commodity derivatives applicable to periods subsequent to June 30, 2011. The settlement prices of commodity derivatives are based on NYMEX futures prices.

Swaps:

  Oil   Gas Bbls   Price MMBtu (a)   Price Production Period: 3rd Quarter 2011 547,000 $ 83.78 1,560,000 $ 7.07 4th Quarter 2011 729,000 $ 87.56 1,500,000 $ 7.07

2012

2,649,000 $ 95.75 - $ -

2013

1,189,000 $ 99.92 - $ - 5,114,000 3,060,000  

(a) One MMBtu equals one Mcf at a Btu factor of 1,000.

We did not designate any of the derivatives shown in the preceding table as cash flow hedges; therefore, all changes in the fair value of these contracts prior to maturity, plus any realized gains or losses at maturity, will be recorded as other income (expense) in our statement of operations.