- Quarterly Report (10-Q)

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2011

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File Number 001-10924

CLAYTON WILLIAMS ENERGY, INC.

(Exact name of registrant as specified in its charter)

Delaware		75-2396863
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

Six Desta Drive - Suite 6500
Midland, Texas		79705-5510
(Address of principal executive offices)		(Zip code)

Registrant’s telephone number, including area code: (432) 682-6324

Not applicable

(Former name, former address and former fiscal year, if changed since last report)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. x Yes o No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). x Yes o No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer o		Accelerated filer x

Non-accelerated filer o		Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). o Yes x No

There were 12,162,536 shares of Common Stock, $.10 par value, of the registrant outstanding as of November 2, 2011.

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CLAYTON WILLIAMS ENERGY, INC.

TABLE OF CONTENTS

		Page
PART I. FINANCIAL INFORMATION

Item 1.	Financial Statements

	Consolidated Balance Sheets as of September 30, 2011 and December 31, 2010	3

	Consolidated Statements of Operations for the three months and nine months ended September 30, 2011 and 2010	5

	Consolidated Statement of Stockholders’ Equity for the nine months ended September 30, 2011	6

	Consolidated Statements of Cash Flows for the nine months ended September 30, 2011 and 2010	7

	Notes to Consolidated Financial Statements	8

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	21

Item 3.	Quantitative and Qualitative Disclosures About Market Risks	37

Item 4.	Controls and Procedures	38

PART II. OTHER INFORMATION

Item 1A.	Risk Factors	39

Item 6.	Exhibits	40

	Signatures	41

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PART I. FINANCIAL INFORMATION

Item 1 - Financial Statements

CLAYTON WILLIAMS ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

ASSETS

	September 30,			December 31,
	2011			2010
	(Unaudited)
CURRENT ASSETS
Cash and cash equivalents	$	36,024		$	8,720
Accounts receivable:
Oil and gas sales	34,399			35,361
Joint interest and other, net	10,155			9,893
Affiliates	728			796
Inventory	37,309			39,218
Deferred income taxes	3,439			5,074
Fair value of derivatives	42,642			—
Assets held for sale	—			8,762
Prepaids and other	16,970			5,997
	181,666			113,821
PROPERTY AND EQUIPMENT
Oil and gas properties, successful efforts method	2,001,354			1,707,252
Natural gas gathering and processing systems	23,619			18,153
Contract drilling equipment	71,851			58,486
Other	18,574			17,425
	2,115,398			1,801,316
Less accumulated depreciation, depletion and amortization	(1,126,137		)	(1,034,227		)
Property and equipment, net	989,261			767,089

OTHER ASSETS
Debt issue costs, net	11,683			8,323
Fair value of derivatives	28,754			—
Other	3,958			1,684
	44,395			10,007
	$	1,215,322		$	890,917

The accompanying notes are an integral part of these consolidated financial statements.

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CLAYTON WILLIAMS ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

LIABILITIES AND STOCKHOLDERS’ EQUITY

	September 30,		December 31,
	2011		2010
	(Unaudited)
CURRENT LIABILITIES
Accounts payable:
Trade	$	89,551	$	74,123
Oil and gas sales	35,612		28,920
Affiliates	2,048		1,251
Fair value of derivatives	—		7,224
Accrued liabilities and other	35,125		22,202
	162,336		133,720
NON-CURRENT LIABILITIES
Long-term debt	514,523		385,000
Deferred income taxes	137,374		78,035
Fair value of derivatives	—		3,409
Other	42,108		41,301
	694,005		507,745
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS’ EQUITY
Preferred stock, par value $.10 per share, authorized – 3,000,000 shares; none issued	—		—
Common stock, par value $.10 per share, authorized – 30,000,000 shares; issued and outstanding – 12,162,536 shares in 2011 and 12,154,536 shares in 2010	1,216		1,215
Additional paid-in capital	152,502		152,290
Retained earnings	205,263		95,947
	358,981		249,452
	$	1,215,322	$	890,917

The accompanying notes are an integral part of these consolidated financial statements.

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CLAYTON WILLIAMS ENERGY, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(In thousands, except per share)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2011			2010			2011			2010
REVENUES
Oil and gas sales	$	99,752		$	81,978		$	300,488		$	237,938
Natural gas services	334			397			1,108			1,352
Drilling rig services	929			—			3,614			—
Gain on sales of assets	49			2,857			14,570			3,256
Total revenues	101,064			85,232			319,780			242,546

COSTS AND EXPENSES
Production	24,284			20,518			75,237			62,012
Exploration:
Abandonments and impairments	1,256			364			2,307			6,133
Seismic and other	1,842			1,361			5,287			3,995
Natural gas services	233			297			781			951
Drilling rig services	1,673			123			4,378			1,204
Depreciation, depletion and amortization	25,901			25,223			74,987			76,272
Impairment of property and equipment	5,035			794			9,459			11,908
Accretion of abandonment obligations	706			659			2,077			1,953
General and administrative	7,142			8,730			22,678			22,786
Loss on sales of assets and impairment of inventory	114			80			417			1,523
Total costs and expenses	68,186			58,149			197,608			188,737

Operating income	32,878			27,083			122,172			53,809

OTHER INCOME (EXPENSE)
Interest expense	(8,717		)	(6,040		)	(24,304		)	(18,393		)
Loss on early extinguishment of long-term debt	(907		)	—			(5,501		)	—
Gain (loss) on derivatives	92,286			(3,995		)	74,128			27,289
Other	527			972			3,514			2,816
Total other income (expense)	83,189			(9,063		)	47,837			11,712

Income before income taxes	116,067			18,020			170,009			65,521
Income tax expense	(41,544		)	(6,397		)	(60,693		)	(23,260		)
NET INCOME	$	74,523		$	11,623		$	109,316		$	42,261

Net income per common share:
Basic	$	6.13		$	.96		$	8.99		$	3.48
Diluted	$	6.13		$	.96		$	8.99		$	3.48

Weighted average common shares outstanding:
Basic	12,163			12,146			12,160			12,146
Diluted	12,163			12,146			12,161			12,146

The accompanying notes are an integral part of these consolidated financial statements.

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CLAYTON WILLIAMS ENERGY, INC.

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY

(Unaudited)

(In thousands)

	Common Stock			Additional
	No. of	Par		Paid-In		Retained
	Shares	Value		Capital		Earnings
BALANCE,
December 31, 2010	12,155	$	1,215	$	152,290	$	95,947
Net income	—	—		—		109,316
Issuance of stock through compensation plans, including income tax benefits	8	1		212		—
BALANCE,
September 30, 2011	12,163	$	1,216	$	152,502	$	205,263

The accompanying notes are an integral part of these consolidated financial statements.

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CLAYTON WILLIAMS ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In thousands)

	Nine Months Ended
	September 30,
	2011			2010
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	109,316		$	42,261
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation, depletion and amortization	74,987			76,272
Impairment of property and equipment	9,459			11,908
Exploration costs	2,307			6,133
Gain on sales of assets and impairment of inventory, net	(14,153		)	(1,733		)
Deferred income tax expense	60,693			23,260
Non-cash employee compensation	6,104			8,066
Unrealized gain on derivatives	(82,029		)	(17,874		)
Accretion of abandonment obligations	2,077			1,953
Amortization of debt issue costs	1,623			1,174
Loss on early extinguishment of long-term debt	5,501			—

Changes in operating working capital:
Accounts receivable	768			1,743
Accounts payable	(4,456		)	5,247
Other	3,090			(4,242		)
Net cash provided by operating activities	175,287			154,168

CASH FLOWS FROM INVESTING ACTIVITIES
Additions to property and equipment	(282,474		)	(208,641		)
Proceeds from sales of assets	12,466			75,670
Change in equipment inventory	2,844			(3,075		)
Other	(133		)	(131		)
Net cash used in investing activities	(267,297		)	(136,177		)

CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt	445,366			—
Repayments of long-term debt	(323,500		)	(10,000		)
Premium on early extinguishment of long-term debt	(2,765		)	—
Proceeds from exercise of stock options	213			—
Net cash provided by (used in) financing activities	119,314			(10,000		)

NET INCREASE IN CASH AND CASH EQUIVALENTS	27,304			7,991

CASH AND CASH EQUIVALENTS
Beginning of period	8,720			14,013
End of period	$	36,024		$	22,004

SUPPLEMENTAL DISCLOSURES
Cash paid for interest, net of amounts capitalized	$	8,064		$	21,517

The accompanying notes are an integral part of these consolidated financial statements.

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2011

(Unaudited)

1. Nature of Operations

Clayton Williams Energy, Inc. (a Delaware corporation), is an independent oil and gas company engaged in the exploration for and development and production of oil and natural gas primarily in its core areas in Texas, Louisiana and New Mexico. Unless the context otherwise requires, references to “CWEI” mean Clayton Williams Energy, Inc., the parent company, and references to the “Company”, “we”, “us” or “our” mean Clayton Williams Energy, Inc. and its consolidated subsidiaries. Approximately 26% of the Company’s outstanding common stock is beneficially owned by Clayton W. Williams, Jr. (“Mr. Williams”), Chairman of the Board and Chief Executive Officer of the Company, and approximately 25% is owned by a partnership in which Mr. Williams’ adult children are limited partners.

Substantially all of our oil and gas production is sold under short-term contracts which are market-sensitive. Accordingly, our results of operations and capital resources are highly dependent upon prevailing market prices of, and demand for, oil and natural gas. These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond our control. These factors include the level of global supply and demand for oil and natural gas, market uncertainties, weather conditions, domestic governmental regulations and taxes, political and economic conditions in oil producing countries, price and availability of alternative fuels, and overall domestic and foreign economic conditions.

2. Presentation

The preparation of these consolidated financial statements in conformity with accounting principles generally accepted in the United States (“GAAP”) requires our management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ materially from those estimates.

The consolidated financial statements include the accounts of CWEI and its wholly-owned subsidiaries. We also account for our undivided interests in oil and gas limited partnerships using the proportionate consolidation method. Under this method, we consolidate our proportionate share of assets, liabilities, revenues and expenses of these limited partnerships. Less than 5% of our consolidated total assets and total revenues are derived from oil and gas limited partnerships. All significant intercompany transactions and balances associated with the consolidated operations have been eliminated.

In the opinion of management, our unaudited consolidated financial statements as of September 30, 2011 and for the interim periods ended September 30, 2011 and 2010 include all adjustments that are necessary for a fair presentation in accordance with GAAP. These interim results are not necessarily indicative of the results to be expected for the year ending December 31, 2011.

Certain information and footnote disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted in this Form 10-Q pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”). These consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto included in our Form 10-K for the year ended December 31, 2010.

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

3. Long-Term Debt

Long-term debt consists of the following:

	September 30,		December 31,
	2011		2010
	(In thousands)
7.75% Senior Notes due 2019, net of unamortized original issue discount of $477	$	349,523	$	—
7 3 / 4 % Senior Notes due 2013	—		225,000
Revolving credit facility, due November 2015	165,000		160,000
	$	514,523	$	385,000

Senior Notes

In July 2005, we issued $225 million of aggregate principal amount of 7¾% Senior Notes due 2013 (“2013 Senior Notes”). The 2013 Senior Notes were issued at face value and bear interest at 7¾% per year, payable semi-annually on February 1 and August 1 of each year, beginning February 1, 2006. In March 2011, we redeemed $143.2 million in aggregate principal amount of 2013 Senior Notes in a tender offer and recorded a $4.6 million loss on early extinguishment of long-term debt consisting of a $2.8 million premium and a $1.8 million write-off of debt issuance costs. On August 1, 2011, we called at par and redeemed in full the remaining $81.8 million of 2013 Senior Notes and recorded an additional $907,000 loss on early extinguishment of long-term debt during the third quarter of 2011 related to the write-off of debt issuance costs.

In March 2011, we issued $300 million of aggregate principal amount of 7.75% Senior Notes due 2019 (“2019 Senior Notes”). The 2019 Senior Notes were issued at face value and bear interest at 7.75% per year, payable semi-annually on April 1 and October 1 of each year, beginning October 1, 2011. In April 2011, we issued an additional $50 million aggregate principal amount of 2019 Senior Notes with an original issue discount of 1% or $500,000. We may redeem some or all of the 2019 Senior Notes at redemption prices (expressed as percentages of principal amount) equal to 103.875% for the twelve-month period beginning on April 1, 2015, and 101.938% beginning on April 1, 2016, and 100% beginning on April 1, 2017 or for any period thereafter, in each case plus accrued and unpaid interest.

The Indenture governing our 2019 Senior Notes contains covenants that restrict our ability to: (1) borrow money; (2) issue redeemable or preferred stock; (3) pay distributions or dividends; (4) make investments; (5) create liens without securing the 2019 Senior Notes; (6) enter into agreements that restrict dividends from subsidiaries; (7) sell certain assets or merge with or into other companies; (8) enter into transactions with affiliates; (9) guarantee indebtedness; and (10) enter into new lines of business. One such covenant provides that we may only incur indebtedness if the ratio of consolidated EBITDAX to consolidated interest expense (as these terms are defined in the Indenture governing the 2019 Senior Notes) does not exceed certain ratios specified in the Indenture governing the 2019 Senior Notes. These covenants are subject to a number of important exceptions and qualifications as described in the Indenture. We were in compliance with these covenants at September 30, 2011.

Revolving Credit Facility

We have a credit facility with a syndicate of banks that provides for a revolving line of credit of up to $500 million, limited to the amount of a borrowing base as determined by the banks. The borrowing base, which is based on the discounted present value of future net cash flows from oil and gas production, is redetermined by the banks semi-annually in May and November. We or the banks may also request an unscheduled borrowing base redetermination at other times during the year. If, at any time, the borrowing base is less than the amount of outstanding credit exposure under the revolving credit facility, we will be required to (1) provide additional security, (2) prepay the principal amount of the loans in an amount sufficient to eliminate the deficiency (or by a combination of such additional security and such prepayment eliminate such deficiency), or (3) prepay the deficiency in not more than five equal monthly installments plus accrued interest. The borrowing base was $350 million at September 30, 2011.

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

After allowing for outstanding letters of credit totaling $4.1 million, we had $181 million available under the revolving credit facility at September 30, 2011.

The revolving credit facility is collateralized primarily by 80% or more of the adjusted engineered value (as defined in the revolving credit facility) of our oil and gas interests evaluated in determining the borrowing base. The obligations under the revolving credit facility are guaranteed by each of CWEI’s material domestic subsidiaries.

At our election, annual interest rates under the revolving credit facility are determined by reference to (1) LIBOR plus an applicable margin between 2% and 3% per year or (2) if an alternate base rate loan, the greatest of (A) the prime rate, (B) the federal funds rate plus 0.5%, or (C) one-month LIBOR plus 1% plus, if any of (A), (B) or (C), an applicable margin between 1% and 2%. We also pay a commitment fee on the unused portion of the revolving credit facility at a flat rate of 0.5%. Interest and fees are payable no less often than quarterly. The effective annual interest rate on borrowings under the revolving credit facility, excluding bank fees and amortization of debt issue costs, for the nine months ended September 30, 2011 was 2.8%.

The revolving credit facility also contains various covenants and restrictive provisions which may, among other things, limit our ability to sell assets, incur additional indebtedness, make investments or loans and create liens. One such covenant requires that we maintain a ratio of consolidated current assets to consolidated current liabilities of at least 1 to 1. Another financial covenant prohibits the ratio of our consolidated funded indebtedness to consolidated EBITDAX (determined as of the end of each fiscal quarter for the then most-recently ended four fiscal quarters) from being greater than 4 to 1. The computations of consolidated current assets, current liabilities, EBITDAX and indebtedness are defined in the revolving credit facility. We were in compliance with all financial and non-financial covenants at September 30, 2011.

4. Other Non-Current Liabilities

Other non-current liabilities consist of the following:

	September 30,		December 31,
	2011		2010
	(In thousands)
Abandonment obligations	$	41,279	$	40,444
Other	829		857
	$	42,108	$	41,301

Changes in abandonment obligations for the nine months ended September 30, 2011 and 2010 are as follows:

	Nine Months Ended
	September 30,
	2011			2010
	(In thousands)
Beginning of period	$	40,444		$	38,412
Additional abandonment obligations from new properties	1,103			1,377
Sales or abandonments of properties	(2,346		)	(1,138		)
Revisions of previous estimates	1			(320		)
Accretion expense	2,077			1,953
End of period	$	41,279		$	40,284

Our asset retirement obligation is measured using primarily Level 3 inputs. The significant unobservable inputs to this fair value measurement include estimates of plugging, abandonment and remediation costs, inflation rate and well life. The inputs are calculated based on historical data as well as current estimated costs.

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

5. Compensation Plans

Stock-Based Compensation

We presently have options outstanding under a stock option plan for independent directors covering 7,000 shares of common stock. As of September 30, 2011, the options had a weighted average exercise price of $26.61 per share (ranging from $12.14 per share to $41.74 per share), a weighted average remaining contractual term of 3.3 years, and an aggregate intrinsic value of $113,390 (based on a market price at September 30, 2011 of $42.81 per share). No options were granted during the nine months ended September 30, 2011 or 2010, and options to purchase 8,000 shares of common stock were exercised during the nine months ended September 30, 2011 (with an intrinsic value of $524,420).

Non-Equity Award Plans

The Compensation Committee of the Board of Directors has adopted an after-payout (“APO”) incentive plan (the “APO Incentive Plan”) for officers, key employees and consultants who promote our drilling and acquisition programs. The Compensation Committee’s objective in adopting this plan is to further align the interests of the participants with ours by granting the participants an APO interest in the production developed, directly or indirectly, by the participants. The plan generally provides for the creation of a series of partnerships or participation arrangements, which are treated as partnerships for tax purposes (“APO Partnerships”), between us and the participants, to which we contribute a portion of our economic interest in wells drilled or acquired within certain areas. Generally, we pay all costs to acquire, drill and produce applicable wells and receive all revenues until we have recovered all of our costs, plus interest (“payout”). At payout, the participants receive 99% to 100% of all subsequent revenues and pay 99% to 100% of all subsequent expenses attributable to the economic interests that are subject to the APO Partnerships. Between 5% and 7.5% of our economic interests in specified wells drilled or acquired by us subsequent to October 2002 are subject to the APO Incentive Plan. We record our allocable share of the assets, liabilities, revenues, expenses and oil and gas reserves of these APO Partnerships in our consolidated financial statements. Participants in the APO Incentive Plan are immediately vested in all future amounts payable under the plan.

The Compensation Committee has also adopted an APO reward plan (the “APO Reward Plan”) which offers eligible officers, key employees and consultants the opportunity to receive bonus payments that are based on certain profits derived from a portion of our working interest in specified areas where we are conducting drilling and production enhancement operations. The wells subject to an APO Reward Plan are not included in the APO Incentive Plan. Likewise, wells included in the APO Incentive Plan are not included in the APO Reward Plan. Although conceptually similar to the APO Incentive Plan, the APO Reward Plan is a compensatory bonus plan through which we pay participants a bonus equal to a portion of the APO cash flows received by us from our working interest in wells in a specified area. Unlike the APO Incentive Plan, however, participants in the APO Reward Plan are not immediately vested in all future amounts payable under the plan. To date, we have granted awards under the APO Reward Plan in 13 specified areas, each of which established a quarterly bonus amount equal to 7% or 10% of the APO cash flow from wells drilled or recompleted in the respective areas after the effective date set forth in each plan, which dates range from January 1, 2007 to April 1, 2011. Under these 13 awards, the full vesting dates for future amounts payable under the plan for one award is November 4, 2011, three awards are August 9, 2012, three awards are May 5, 2013, and six awards are June 1, 2013.

In January 2007, we granted awards under the Southwest Royalties Reward Plan (the “SWR Reward Plan”), a one-time incentive plan which established a quarterly bonus amount for participants equal to the after-payout cash flow from a 22.5% working interest in one well. Under the plan, two-thirds of the quarterly bonus amount is payable to the participants until the full vesting date of October 25, 2011. After the full vesting date, the deferred portion of the quarterly bonus amount, with interest at 4.83% per year, as well as 100% of all subsequent quarterly bonus amounts, are payable to participants.

To continue as a participant in the APO Reward Plan or the SWR Reward Plan, participants must remain in the employment or service of the Company through the full vesting date established for each plan. The full vesting date may be accelerated in the event of a change of control or sale transaction, as defined in the plan documents.

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

We recognize compensation expense related to the APO Partnerships based on the estimated value of economic interests conveyed to the participants. Estimated compensation expense applicable to the APO Reward Plan and SWR Reward Plan is recognized over the vesting periods, which range from two years to five years. We recorded compensation expense of $1.1 million for the three months ended September 30, 2011 and $3 million for the three months ended September 30, 2010 in connection with all non-equity award plans. We recorded compensation expense of $6.1 million for the nine months ended September 30, 2011 and $8.1 million for the nine months ended September 30, 2010 in connection with all non-equity award plans.

6. Derivatives

Commodity Derivatives

From time to time, we utilize commodity derivatives in the form of swap contracts to attempt to optimize the price received for our oil and gas production. Under swap contracts, we receive a fixed price for the respective commodity and pay a floating market price as defined in each contract (generally NYMEX futures prices), resulting in a net amount due to or from the counterparty. Commodity derivatives are settled monthly as the contract production periods mature.

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

Swaps:

	Oil			Gas
	Bbls (a)	Price		MMBtu (b)	Price
Production Period:
4 th Quarter 2011	733,949	$	87.58	1,010,000	$	7.07
2012	107,506	$	91.15	—	$	—
2013	95,996	$	91.15	—	$	—
2014	85,772	$	91.15	—	$	—
2015	76,309	$	91.15	—	$	—
2016	28,280	$	91.15	—	$	—
	1,127,812			1,010,000

(a) In September 2011, we entered into oil hedges covering 398,812 barrels of oil for production months from December 2011 through May 2016. These hedges cover production related to a volumetric production payment in connection with the acquisition by our wholly owned subsidiary, Southwest Royalties, Inc., of the 24 limited partnerships of which it is the general partner. See Note 14.

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

In October 2011, we terminated substantially all of our existing 2012 and 2013 oil hedges for cash proceeds of $50 million. The terminated contracts covered 2,649,000 barrels of oil production for 2012 and 1,189,000 barrels for 2013. In addition, we terminated a hedge contract covering 490,000 MMBtu of gas production for December 2011 for cash proceeds of $1.6 million.

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Accounting For Derivatives

We did not designate any of our currently open commodity derivatives 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, are recorded as other income (expense) in our statements of operations. For the three months ended September 30, 2011, we reported a $92.3 million net gain on derivatives, consisting of a $91.1 million non-cash gain related to changes in mark-to-market valuations and a $1.2 million realized gain for settled contracts. For the three months ended September 30, 2010, we reported a $4 million net loss on derivatives, consisting of an $8 million non-cash loss related to changes in mark-to-market valuations and a $4 million realized gain for settled contracts. For the nine months ended September 30, 2011, we reported a $74.1 million net gain on derivatives, consisting of an $82 million non-cash gain related to changes in mark-to-market valuations and a $7.9 million realized loss for settled contracts. For the nine months ended September 30, 2010, we reported a $27.3 million net gain on derivatives, consisting of a $17.9 million non-cash gain related to changes in mark-to-market valuations and a $9.4 million realized gain for settled contracts.

Effect of Derivative Instruments on the Consolidated Balance Sheets

	Fair Value of Derivative Instruments as of September 30, 2011
	Asset Derivatives			Liability Derivatives
	Balance Sheet			Balance Sheet
	Location	Fair Value		Location	Fair Value
		(In thousands)			(In thousands)
Derivatives not designated as hedging instruments:

Commodity derivatives	Fair value of derivatives:			Fair value of derivatives:
	Current	$	42,642	Current	$	—
	Non-current	28,754		Non-current	—
Total		$	71,396		$	—

	Fair Value of Derivative Instruments as of December 31, 2010
	Asset Derivatives			Liability Derivatives
	Balance Sheet			Balance Sheet
	Location	Fair Value		Location	Fair Value
		(In thousands)			(In thousands)
Derivatives not designated as hedging instruments:

Commodity derivatives	Fair value of derivatives:			Fair value of derivatives:
	Current	$	—	Current	$	7,224
	Non-current	—		Non-current	3,409
Total		$	—		$	10,633

Gross to Net Presentation Reconciliation of Derivative Assets and Liabilities

	September 30, 2011
	Assets		Liabilities
	(In thousands)
Fair value of derivatives — gross presentation	$	71,396	$	—
Effects of netting arrangements	—		—
Fair value of derivatives — net presentation	$	71,396	$	—

	December 31, 2010
	Assets			Liabilities
	(In thousands)
Fair value of derivatives — gross presentation	$	16,051		$	26,684
Effects of netting arrangements	(16,051		)	(16,051		)
Fair value of derivatives — net presentation	$	—		$	10,633

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

All of our derivative contracts are with JPMorgan Chase Bank, N.A. We have elected to net the outstanding positions with this counterparty between current and non-current assets or liabilities.

Effect of Derivative Instruments on the Consolidated Statements of Operations

	Amount of Gain or (Loss) Recognized in Earnings
	Three Months Ended						Nine Months Ended
Location of Gain or (Loss)	September 30, 2011						September 30, 2011
Recognized in Earnings	Realized		Unrealized		Total		Realized			Unrealized		Total
	(In thousands)						(In thousands)
Derivatives not designated as hedging instruments:

Commodity derivatives:
Other income (expense) -
Gain (loss) on derivatives	$	1,188	$	91,098	$	92,286	$	(7,901	)	$	82,029	$	74,128
Total	$	1,188	$	91,098	$	92,286	$	(7,901	)	$	82,029	$	74,128

	Amount of Gain or (Loss) Recognized in Earnings
	Three Months Ended								Nine Months Ended
Location of Gain or (Loss)	September 30, 2010								September 30, 2010
Recognized in Earnings	Realized		Unrealized			Total			Realized		Unrealized		Total
	(In thousands)								(In thousands)
Derivatives not designated as hedging instruments:

Commodity derivatives:
Other income (expense) -
Gain (loss) on derivatives	$	4,003	$	(7,998	)	$	(3,995	)	$	9,416	$	17,873	$	27,289
Total	$	4,003	$	(7,998	)	$	(3,995	)	$	9,416	$	17,873	$	27,289

7. Financial Instruments

Cash and cash equivalents, receivables, accounts payable and accrued liabilities were each estimated to have a fair value approximating the carrying amount due to the short maturity of those instruments. Indebtedness under our revolving credit facility was estimated to have a fair value approximating the carrying amount since the interest rate is generally market sensitive. At September 30, 2011, our fixed rate debt maturing 2019 had a carrying value of $349.5 million and an approximate fair value of $290.5 million. At December 31, 2010, our fixed rate debt maturing 2013 had a fair market value of approximately $226 million.

Fair Value Measurements

We follow a framework for measuring fair value, which outlines a fair value hierarchy based on the quality of inputs used to measure fair value and enhances disclosure requirements for fair value measurements. Fair value is defined as the price at which an asset could be exchanged in a current transaction between knowledgeable, willing parties at the measurement date. Where available, fair value is based on observable market prices or parameters or derived from such prices or parameters. Where observable prices or inputs are not available, use of unobservable prices or inputs are used to estimate the current fair value, often using an internal valuation model. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the item being valued. We categorize our assets and liabilities recorded at fair value in the accompanying consolidated balance sheets based upon the level of judgment associated with the inputs used to measure their fair value.

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Hierarchical levels directly related to the amount of subjectivity associated with the inputs to fair valuation of these assets and liabilities, are as follows:

Level 1 - Inputs are unadjusted, quoted prices in active markets for identical assets or liabilities at the measurement date.

Level 2 - Inputs (other than quoted prices included in Level 1) are either directly or indirectly observable for the asset or liability through correlation with market data at the measurement date and for the duration of the instrument’s anticipated life.

Level 3 - Inputs reflect management’s best estimate of what market participants would use in pricing the asset or liability at the measurement date. Consideration is given to the risk inherent in the valuation technique and the risk inherent in the inputs to the model.

The only financial assets and liabilities measured on a recurring basis at September 30, 2011 and December 31, 2010 were commodity derivatives. Information regarding these liabilities is summarized below:

	September 30,		December 31,
	2011		2010
	Significant Other		Significant Other
	Observable Inputs		Observable Inputs
Description	(Level 2)		(Level 2)
	(In thousands)
Assets:
Fair value of commodity derivatives	$	71,396	$	—
Total assets	$	71,396	$	—

Liabilities:
Fair value of commodity derivatives	$	—	$	10,633
Total liabilities	$	—	$	10,633

8. Income Taxes

Our effective federal and state income tax expense rate for the nine months ended September 30, 2011 of 35.7% differed from the statutory federal rate of 35% due primarily to increases related to the effects of the Texas Margin Tax and certain non-deductible expenses, offset in part by tax benefits derived from excess statutory depletion deductions.

We file federal income tax returns with the United States Internal Revenue Service (“IRS”) and state income tax returns in various state tax jurisdictions. Our tax returns for fiscal years after 2006 currently remain subject to examination by appropriate taxing authorities. None of our income tax returns are under examination at this time.

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

9. Sales of Assets and Impairments of Inventory

Net gain (loss) on sales of assets and impairment of inventory for the three months and nine months ended September 30, 2011 and September 30, 2010 are as follows:

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2011			2010			2011			2010
	(In thousands)						(In thousands)
Gain on sales of assets	$	49		$	2,857		$	14,570		$	3,256

Loss on sales of assets and impairment of inventory:
Loss on sales of assets	(20		)	(80		)	(138		)	(1,523		)
Impairment of inventory	(94		)	—			(279		)	—
	(114		)	(80		)	(417		)	(1,523		)

Net gain (loss)	$	(65	)	$	2,777		$	14,153		$	1,733

During the second quarter of 2011, we sold certain interests in two prospects in South Louisiana and recorded a gain of $852,000. In February 2011, we sold two 2,000 horsepower drilling rigs and related equipment for $22 million of total consideration. In connection with the sale, we recorded a gain of $13.2 million during the first quarter of 2011.

We maintain an inventory of tubular goods and other well equipment for use in our exploration and development drilling activities. Inventory is carried at the lower of average cost or estimated fair market value. We categorize the measurement of fair value of inventory as Level 2 under applicable accounting standards. To determine estimated fair value of inventory, we subscribe to market surveys and obtain quotes from equipment dealers for similar equipment. We then correlate the data as needed to estimate the fair value of the specific items (or groups of similar items) in our inventory. If the estimated fair values for those specific items (or groups of similar items) in our inventory are less than the related average cost, a provision for impairment is made.

10. Oil and Gas Properties

The following sets forth the net capitalized costs for oil and gas properties as of September 30, 2011 and December 31, 2010.

	September 30,			December 31,
	2011			2010
	(In thousands)
Proved properties	$	1,934,392		$	1,655,217
Unproved properties	66,962			52,035
Total capitalized costs	2,001,354			1,707,252
Accumulated depreciation, depletion and amortization	(1,065,378		)	(983,119		)
Net capitalized costs	$	935,976		$	724,133

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

11. Impairment of Property and Equipment

We impair our long-lived assets, including oil and gas properties and contract drilling equipment, when estimated undiscounted future net cash flows of an asset are less than its carrying value. The amount of any such impairment is recognized based on the difference between the carrying value and the estimated fair value of the asset. We categorize the measurement of fair value of these assets as Level 3 inputs. We estimate the fair value of the impaired property by applying weighting factors to fair values determined under three different methods: discounted cash flow method, flowing daily production method and proved reserves per BOE method. We then assign applicable weighting factors based on the relevant facts and circumstances. We recorded provisions for impairment of proved properties triggered by a combination of well performance and lower reserve estimates due to performance and changes in oil and gas prices aggregating $9.5 million in 2011 relating to certain non-core areas in the Permian Basin and other non-core areas to reduce the carrying value of those properties to their estimated fair values. In 2010, we recorded a $11.9 million impairment relating to non-core areas in the Permian Basin and Wyoming due to a combination of well performance and lower estimated reserve quantities.

We impair our unproved oil and gas properties when we determine that a prospect’s carrying value exceeds its estimated fair value. We categorize the measurement of fair value of these assets as Level 3 inputs. Unproved properties are nonproducing and do not have estimable cash flow streams. Therefore, we estimate the fair value of individually significant prospects by obtaining, when available, information about recent market transactions in the vicinity of the prospects and adjust the market data as needed to give consideration to location of the prospects to known fields and reservoirs, the extent of geological and geophysical data on the prospects, the remaining terms of leases holding the acreage in the prospects, recent drilling results in the vicinity of the prospects, and other risk-related factors such as drilling and completion costs, estimated product prices and other economic factors. Individually insignificant prospects are grouped and impaired based on remaining lease terms and our historical experience with similar prospects. We recorded provisions for impairment of unproved properties aggregating $1.1 million in 2011 and $6 million in 2010, respectively, and charged these impairments to exploration costs in the accompanying statements of operations.

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

12. Segment Information

We have two reportable operating segments, which are oil and gas exploration and production and contract drilling services.

The following tables present selected financial information regarding our operating segments for the three-month and nine-month periods ended September 30, 2011 and 2010.

For the Three Months Ended
September 30, 2011
(Unaudited)				Contract			Intercompany			Consolidated
(In thousands)	Oil and Gas			Drilling			Eliminations			Total

Revenues	$	100,135		$	13,979		$	(13,050	)	$	101,064
Depreciation, depletion and amortization (a)	30,267			3,285			(2,616		)	30,936
Other operating expenses (b)	35,513			11,639			(9,902		)	37,250
Interest expense	8,717			—			—			8,717
Other (income) expense	(91,579		)	(327		)	—			(91,906		)
Income (loss) before income taxes	117,217			(618		)	(532		)	116,067

Income tax (expense) benefit	(41,760		)	216			—			(41,544		)

Net income (loss)	$	75,457		$	(402	)	$	(532	)	$	74,523

Total assets	$	1,166,492		$	59,997		$	(11,167	)	$	1,215,322
Additions to property and equipment	$	127,252		$	6,999		$	(532	)	$	133,719

For the Nine Months Ended
September 30, 2011
(Unaudited)				Contract			Intercompany			Consolidated
(In thousands)	Oil and Gas			Drilling			Eliminations			Total

Revenues	$	316,166		$	38,772		$	(35,158	)	$	319,780
Depreciation, depletion and amortization (a)	82,832			9,107			(7,493		)	84,446
Other operating expenses (b)	108,577			31,823			(27,238		)	113,162
Interest expense	24,304			—			—			24,304
Other (income) expense	(58,592		)	(13,549		)	—			(72,141		)
Income (loss) before income taxes	159,045			11,391			(427		)	170,009

Income tax (expense) benefit	(56,706		)	(3,987		)	—			(60,693		)

Net income (loss)	$	102,339		$	7,404		$	(427	)	$	109,316

Total assets	$	1,166,492		$	59,997		$	(11,167	)	$	1,215,322
Additions to property and equipment	$	303,537		$	13,563		$	(427	)	$	316,673

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the Three Months Ended
September 30, 2010
(Unaudited)				Contract			Intercompany			Consolidated
(In thousands)	Oil and Gas			Drilling			Eliminations			Total

Revenues	$	85,232		$	9,285		$	(9,285	)	$	85,232
Depreciation, depletion and amortization (a)	25,623			2,568			(2,174		)	26,017
Other operating expenses (b)	31,964			6,908			(6,740		)	32,132
Interest expense	6,039			1			—			6,040
Other (income) expense	3,023			—			—			3,023
Income (loss) before income taxes	18,583			(192		)	(371		)	18,020

Income tax (expense) benefit	(6,464		)	67			—			(6,397		)

Net income (loss)	$	12,119		$	(125	)	$	(371	)	$	11,623

Total assets	$	809,389		$	43,503		$	(6,705	)	$	846,187
Additions to property and equipment	$	66,976		$	4,063		$	(371	)	$	70,668

For the Nine Months Ended
September 30, 2010
(Unaudited)				Contract			Intercompany			Consolidated
(In thousands)	Oil and Gas			Drilling			Eliminations			Total

Revenues	$	242,546		$	23,668		$	(23,668	)	$	242,546
Depreciation, depletion and amortization (a)	86,480			7,401			(5,701		)	88,180
Other operating expenses (b)	99,200			18,549			(17,192		)	100,557
Interest expense	18,389			4			—			18,393
Other (income) expense	(30,105		)	—			—			(30,105		)
Income (loss) before income taxes	68,582			(2,286		)	(775		)	65,521

Income tax (expense) benefit	(24,060		)	800			—			(23,260		)

Net income (loss)	$	44,522		$	(1,486	)	$	(775	)	$	42,261

Total assets	$	809,389		$	43,503		$	(6,705	)	$	846,187
Additions to property and equipment	$	205,380		$	11,642		$	(775	)	$	216,247

(a) Includes impairment of property and equipment.

(b) Includes the following expenses: production, exploration, natural gas services, drilling rig services, accretion of abandonment obligations, general and administrative and loss on sales of assets and impairment of inventory.

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

13. Commitments

As of September 30, 2011, we had $35 million in non-cancellable orders for tubular goods.

14. Subsequent Events

We have evaluated events and transactions that occurred after the balance sheet date of September 30, 2011 and have determined that no events or transactions have occurred, other than these shown below, that would require recognition in the consolidated financial statements or disclosures in these notes to the consolidated financial statements.

· On October 28, 2011, our wholly owned subsidiary, Southwest Royalties, Inc. (“SWR”), entered into merger agreements with 24 limited partnerships of which SWR is the general partner (the “SWR Partnerships”) pursuant to which each of the SWR Partnerships that approves the merger will merge into SWR, and the partnership interests of the SWR Partnerships, other than those interests owned by SWR, will be converted into the right to receive cash. SWR will not receive any cash payment for its partnership interests in the SWR Partnerships; however, as a result of each merger, SWR will acquire 100% of the assets and liabilities of each SWR Partnership that approves the merger. Each of the mergers is subject to customary closing conditions, and approval by the limited partners of each of the SWR Partnerships. The merger consideration will be 100% cash, and is expected to be approximately $40.2 million in the aggregate. We expect to obtain the funds to finance the aggregate merger consideration by conveying a volumetric production payment (“VPP”) on certain properties acquired in the proposed mergers to a third party. The final terms of the VPP will not be determined until immediately prior to the closing of the mergers. The closing of the mergers is not conditioned on our receiving proceeds from the VPP or any other financing condition.

· In October 2011, we terminated substantially all of our existing 2012 and 2013 oil hedges for cash proceeds of $50 million. The terminated contracts covered 2,649,000 barrels of oil production for 2012 and 1,189,000 barrels for 2013. In addition, we terminated a hedge contract covering 490,000 MMBtu of gas production for December 2011 for cash proceeds of $1.6 million.

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Item 2 - Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion is intended to provide information relevant to an understanding of our financial condition, changes in our financial condition and our results of operations and cash flows and should be read in conjunction with our consolidated financial statements and notes thereto included elsewhere in this Form 10-Q and in our Form 10-K for the year ended December 31, 2010. Unless the context otherwise requires, references to “CWEI” mean Clayton Williams Energy, Inc., the parent company, and references to the “Company”, “we”, “us” or “our” mean Clayton Williams Energy, Inc. and its consolidated subsidiaries.

Forward-Looking Statements

The information in this Form 10-Q includes “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, could or may occur in the future are forward-looking statements. These forward-looking statements are based on management’s current expectations and belief, based on currently available information, as to the outcome and timing of future events and their effect on us. While management believes that these forward-looking statements are reasonable as and when made, there can be no assurance that future developments affecting us will be those that we anticipate. All statements concerning our expectations for future operating results are based on our forecasts for our existing operations and do not include the potential impact of any future acquisitions. Our forward-looking statements involve significant risks and uncertainties, many of which are beyond our control, and assumptions that could cause actual results to differ materially from our historical experience and our present expectations or projections. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements in our Form 10-K for the year ended December 31, 2010 and in this Form 10-Q.

Forward-looking statements appear in a number of places and include statements with respect to, among other things:

· estimates of our oil and gas reserves;

· estimates of our future oil and gas production, including estimates of any increases or decreases in production;

· planned capital expenditures and the availability of capital resources to fund those expenditures;

· our outlook on oil and gas prices;

· our outlook on domestic and worldwide economic conditions;

· our access to capital and our anticipated liquidity;

· our future business strategy and other plans and objectives for future operations;

· the impact of political and regulatory developments;

· our assessment of counterparty risks and the ability of our counterparties to perform their future obligations;

· estimates of the impact of new accounting pronouncements on earnings in future periods; and

· our future financial condition or results of operations and our future revenues and expenses.

We caution you that these forward-looking statements are subject to all of the risks and uncertainties, 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;

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· 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 past or future economic recessions 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 revolving 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;

· hurricanes and other weather conditions;

· 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

· the other risks described in our Form 10-K for the year ended December 31, 2010 and in this Form 10-Q.

Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data and the interpretation of that data by geological engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, these revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates are generally different from the quantities of oil and gas that are ultimately recovered.

As previously discussed, should one or more of the risks or uncertainties described above or elsewhere in the Form 10-K for the year ended December 31, 2010 and in this Form 10-Q occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We specifically disclaim all responsibility to publicly update or revise any information contained in a forward-looking statement or any forward-looking statement in its entirety after the date made, whether as a result of new information, future events or otherwise, except as required by law.

All forward-looking statements attributable to us are expressly qualified in their entirety by this cautionary statement.

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Overview

We are engaged in developmental drilling in two primary oil-prone regions, the Permian Basin and Giddings Area, where we have a significant inventory of developmental drilling opportunities. One core area of the Permian Basin is our Wolfberry drilling program. Also included in the Permian Basin is our emerging Bone Springs/Wolfcamp play (“Wolfbone”) located in the Delaware Basin on the western edge of the Permian Basin where we began a drilling program in the second quarter of 2011. We are also continuing to exploit our extensive acreage position in the Giddings Area of East Central Texas.

Key Factors to Consider

The following summarizes the key factors considered by management in the review of our financial condition and operating performance for the third quarter of 2011 and the outlook for the remainder of 2011.

· We recorded a $92.3 million net gain on derivatives in the third quarter of 2011, consisting of a $91.1 million non-cash gain for changes in mark-to-market valuations and a $1.2 million realized gain on settled contracts. For the same period in 2010, we reported a $4 million net loss on derivatives consisting of an $8 million non-cash loss for changes in mark-to-market valuations and a $4 million realized gain on settled contracts. Since we do not presently designate our derivatives as cash flow hedges under applicable accounting standards, we recognize the full effect of changing prices on mark-to-market valuations as a current charge or credit to our results of operations.

· Our oil and gas sales increased $17.8 million, or 22%, from 2010. Price variances accounted for an increase of $18.3 million, offset in part by a $500,000 decrease due to production variances.

· Our oil production increased 3% compared to 2010 while gas production declined 13%. Our combined oil and gas production for the third quarter of 2011 decreased 4% on a barrel of oil equivalent (“BOE”) basis compared to the same period in 2010. The increase in oil production and the decline in gas production are indicative of our current emphasis on the development of oil reserves in the Permian Basin.

· Production costs increased 18% or $3.8 million for the third quarter of 2011 compared to the third quarter of 2010. Production costs excluding production taxes, referred to as lifting costs, accounted for $2.8 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 $1 million of the increase due to higher oil and gas sales.

· Interest expense increased to $8.7 million in the third quarter of 2011 compared to $6 million in the third quarter of 2010 due primarily to the increase in the total aggregate principal amount of our Senior Notes from $225 million to $350 million.

· Non-cash impairments of property and equipment were $5 million in the third quarter of 2011 compared to $794,000 in the third quarter of 2010. The 2011 impairment related to certain non-core oil and gas properties in the Permian Basin and other non-core areas.

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Recent Exploration and Development Activities

Overview

Since the second quarter of 2009, we have been primarily committed to drilling developmental oil wells in the Permian Basin and the Giddings Area. We currently plan to spend approximately $407.7 million on exploration and development activities during fiscal 2011, with approximately 94% of these estimated expenditures expected to be spent on developmental drilling. We may increase or decrease our planned activities, depending upon drilling results, operating margins, the availability of capital resources, and other factors affecting the economic viability of such activities.

Core Areas

Permian Basin

The Permian Basin is a sedimentary basin in West Texas and Southeastern New Mexico known for its large oil and gas deposits from the Permian geologic period. The Permian Basin covers an area approximately 250 miles wide and 350 miles long and contains commercial accumulations of oil and gas in multiple stratigraphic horizons at depths ranging from 1,000 feet to over 25,000 feet. The Permian Basin is characterized by an extensive production history, mature infrastructure, long reserve life, multiple producing horizons and enhanced recovery potential. Although many fields in the Permian Basin have been heavily exploited in the past, higher product prices and improved technology (including deep horizontal drilling) continue to attract high levels of drilling and recompletion activities. We gained a significant position in the Permian Basin in 2004 when we acquired Southwest Royalties, Inc. This acquisition provided us with an inventory of potential drilling and recompletion activities.

We spent $204 million in the Permian Basin during the first nine months of 2011 on drilling and completion activities and $35.4 million on seismic and leasing activities. We drilled and completed 68 gross (57.6 net) operated wells in the Permian Basin and conducted various remedial operations on other wells during the first nine months of 2011. We currently plan to spend approximately $325.1 million on drilling and leasing activities in this area during fiscal 2011. Following is a discussion of our principal assets in the Permian Basin.

Wolfbone

We are actively growing our acreage position in the Wolfbone play located in the Delaware Basin on the western edge of the Permian Basin. A Wolfbone well is a well that commingles production from the Bone Springs and Wolfcamp formations which are typically encountered at depths of 8,000 to 13,000 feet. These Permian aged formations in the Delaware Basin are comprised of limestone and sandstone. We spent approximately $84.3 million on drilling and completion activities and $32.7 million for leasing activities in the Wolfbone play during the first nine months of 2011. We plan to spend approximately $150.9 million on drilling and completion activities and $37.2 million on leasing activities in the Wolfbone play during fiscal 2011. To date, we have accumulated approximately 46,000 net acres. In March 2011, we entered into a farm-in agreement with Chesapeake Exploration, L.L.C. (“Chesapeake”) in southern Reeves County, Texas. For each well that we drill in the farm-in area that meets certain specified requirements (each, a ‘‘carried well’’), Chesapeake will retain a 25% carried interest, bearing none of the costs to drill and complete a carried well, and we will earn an undivided 75% interest in 640 net acres within the farm-in area. If we drill 100 wells in the farm-in area during the five-year term, we will earn an undivided 75% interest in the entire farm-in area that has not otherwise been assigned to us during the term of the farm-in agreement. Under the farm-in agreement, we are obligated to drill or commence drilling operations on at least 20 carried wells prior to March 1, 2012. We have currently drilled enough wells to meet this obligation. Following satisfaction of our initial drilling obligations, we have the right, but not the obligation, to drill at least 20 additional carried wells each year during the remainder of the term of the farm-in agreement. If we fail to drill at least 20 carried wells during any year after expiration of the initial drilling period, the farm-in agreement will terminate without any liability to us. Excess wells drilled during any year may be applied towards our drilling obligations in the next year. We are currently utilizing nine rigs in this area and plan to keep the rig count at this level through the remainder of 2011.

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Wolfberry

One of our primary objectives in the Permian Basin is the drilling of Wolfberry wells in the Midland Basin. Wolfberry is a term applied to the combined production from the Spraberry and Wolfcamp formations, which are generally found at depths from 7,500 to 10,500 feet. These formations are comprised of a sequence of basinal, interbedded shales and carbonates. We spent approximately $97.2 million on Wolfberry drilling and completion activities and approximately $1.4 million on seismic and leasing activities during the first nine months of 2011, and currently plan to spend approximately $111.9 million on drilling and leasing activities in this area during fiscal 2011. We currently have two rigs drilling Wolfberry wells and plan to keep the rig count at this level through the remainder of 2011.

Fuhrman-Mascho Field

We resumed a drilling program in the Fuhrman-Mascho Field in Andrews County, Texas beginning in July 2009. Wells in the Fuhrman-Mascho Field produce from the San Andres formation, a reservoir comprised of fractured carbonate sediments found at a depth of approximately 4,300 feet. We currently plan to drill seven wells during the fourth quarter of 2011.

Giddings Area

Prior to 1998, we concentrated our drilling activities in an oil-prone area we refer to as the Giddings Area. Most of our wells in the Giddings Area were drilled as horizontal wells, many with multiple laterals in different producing horizons, including the Austin Chalk, Buda and Georgetown formations. Hydrocarbons are also encountered in the Giddings Area from other formations, including the Cotton Valley, Deep Bossier, Eagle Ford Shale and Taylor. During the first nine months of 2011, we spent approximately $43 million in the Giddings Area on drilling and leasing activities and currently plan to spend approximately $54.6 million on similar drilling activities in this area during fiscal 2011. Following is a discussion of our principal assets in the Giddings Area.

Austin Chalk

We have concentrated our recent drilling activities in the Giddings Area on the Austin Chalk formation, an upper Cretaceous geologic formation in the Gulf Coast region of the United States that stretches across numerous fields in Texas and Louisiana. The Austin Chalk formation is generally encountered at depths of 5,500 to 7,000 feet. Horizontal drilling is the primary technique used in the Austin Chalk formation to enhance productivity by intersecting multiple zones. Most of our wells in this area were drilled as horizontal wells, many with multiple laterals in different producing horizons, including the Austin Chalk, Buda and Georgetown formations. The existing spacing between some of our wells in this area affords us the opportunity to tap additional oil and gas reserves by drilling new wells between existing wells, a technique referred to as in-fill drilling. These in-fill wells are considered lower risk as compared to exploratory wells. We initiated a water frac program on certain wells in June 2011 to enhance productivity on certain wells. We are currently working one of our drilling rigs in the Giddings Area to drill a dual opposed or dual stacked lateral horizontal well in the Austin Chalk and plan to keep the rig count at this level through the remainder of 2011.

Eagle Ford Shale

The Eagle Ford Shale is a formation immediately beneath the Austin Chalk formation. During 2010, we drilled and completed four producing wells in Burleson and Lee Counties using various frac techniques with varying results. We are currently completing the Hosek #1 well in Wilson County and plan to drill another well in this area during the fourth quarter of 2011. Based on the results of these wells, we may drill several additional wells during 2012.

Deep Bossier

We have an extensive acreage position in the Giddings Area that is also prospective for Deep Bossier sands which are encountered at depths ranging from 14,000 to 22,000 feet. Exploration for Deep Bossier gas sands in this area involves a high degree of risk. The geological structures are complex, very little subsurface control exists, and wells are expensive to drill. Although seismic data is helpful in identifying possible sand accumulations, the only way to determine whether the Deep Bossier sand will be commercially productive is to drill wells to the targeted structures. We are currently drilling the Hamill Foundation #1, an 18,000-foot

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exploratory well in Leon County, Texas. This well targets a Deep Bossier sand that is offsetting and updip to our previously drilled Big Bill Simpson #1. The well is expected to cost approximately $ 10 million to drill to casing point.

South Louisiana

In the first quarter of 2011, we drilled the State Lease 19924 #1, an exploratory well in St. Mary Parish, Louisiana which was a dry hole. We have drilled the State Lease 19720 #1, an exploratory well in St. Mary Parish, Louisiana which is currently waiting on pipeline. In the third quarter of 2011, we drilled and completed the State Lease 19706 #1, a developmental well in Plaquemines Parish, Louisiana, which is currently waiting on pipeline. We have also spud the Pruitt ET AL #1 in the third quarter of 2011, an exploratory well in Acadia Parish, Louisiana. We plan to spend $6.8 million in fiscal 2011 in connection with drilling and leasing activities in South Louisiana.

Desta Drilling

We currently own and operate 12 drilling rigs that primarily work for us. In September 2011, we leased two additional rigs under long-term leases. We believe that owning our own rigs helps control our cost structure and provides us flexibility to take advantage of drilling opportunities on a timely basis.

Known Trends and Uncertainties

We have an extensive acreage position within the Permian Basin with a large portion of that acreage currently held by production. We are continuously seeking other opportunities for growth in the Permian Basin, and believe that our holdings in this region provide us with many viable possibilities for exploration and development activities beyond our current drilling programs.

Our developmental drilling programs are very sensitive to oil prices and drilling costs. We attempt to control costs through drilling efficiencies by the use of our own rigs, purchasing casing and tubing at periods when we believe prices are suitable and working with service providers to receive acceptable unit costs. We plan to continue these programs as long as oil prices remain favorable. In order to continue drilling in these areas, we must be able to realize an acceptable margin between our expected cash flow from new production and our cost to drill new wells. If any combination of falling oil prices and rising drilling costs occur in future periods, we may discontinue a program until margins return to acceptable levels.

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Supplemental Information

The following unaudited information is intended to supplement the consolidated financial statements included in this Form 10-Q with data that is not readily available from those statements.

	Three Months Ended
	September 30,
	2011			2010
Oil and Gas Production Data:
Oil (MBbls)	945			915
Gas (MMcf)	2,195			2,530
Natural gas liquids (MBbls)	61			90
Total (MBOE)	1,372			1,427

Average Realized Prices (a):
Oil ($/Bbl)	$	89.36		$	73.18
Gas ($/Mcf)	$	5.46		$	4.56
Natural gas liquids ($/Bbl)	$	54.36		$	36.88

Gain (Loss) on Settled Derivative Contracts (a):
($ in thousands, except per unit)
Oil: Net realized loss	$	(3,292	)	$	(227	)
Per unit produced ($/Bbl)	$	(3.48	)	$	(.25	)
Gas: Net realized gain	$	4,481		$	4,230
Per unit produced ($/Mcf)	$	2.04		$	1.67

Average Daily Production :
Oil (Bbls):
Permian Basin Area:
West Texas Andrews	2,768			2,246
West Texas Reeves	170			—
West Texas Other	3,384			3,846
Austin Chalk/Eagle Ford Shale	3,458			3,044
South Louisiana	413			727
Other	79			83
Total	10,272			9,946

Gas (Mcf):
Permian Basin Area:
West Texas Andrews	1,116			962
West Texas Reeves	27			—
West Texas Other	11,769			12,969
Giddings Area:
Austin Chalk/Eagle Ford Shale	1,958			2,325
Cotton Valley Reef Complex	2,955			3,708
South Louisiana	5,257			5,650
Other	777			1,886
Total	23,859			27,500

Natural Gas Liquids (Bbls):
Permian Basin Area:
West Texas Andrews	124			310
West Texas Other	242			225
Austin Chalk/Eagle Ford Shale	215			258
South Louisiana	56			119
Other	26			66
Total	663			978

(Continued)

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	Three Months Ended
	September 30,
	2011		2010
Exploration Costs (in thousands):
Abandonment and impairment costs:
South Louisiana	$	16	$	85
Deep Bossier	—		274
Permian Basin	642		5
Utah	221		—
Other	377		—
Total	1,256		364

Seismic and other	1,842		1,361
Total exploration costs	$	3,098	$	1,725

Depreciation, Depletion and Amortization (in thousands):
Oil and gas depletion	$	25,042	$	24,647
Contract drilling depreciation	669		393
Other depreciation	190		183
Total DD&A	$	25,901	$	25,223

Oil and Gas Costs ($/BOE Produced):
Production costs	$	17.70	$	14.38
Production costs (excluding production taxes)	$	13.84	$	11.37
Oil and gas depletion	$	18.25	$	17.27

General and Administrative Expenses (in thousands):
Excluding non-cash employee compensation	$	6,001	$	5,743
Non-cash employee compensation(c)	1,141		2,987
Total	$	7,142	$	8,730

Net Wells Drilled (d):
Exploratory Wells	1.0		—
Developmental Wells	25.9		24.0

	Nine Months Ended
	September 30,
	2011			2010
Oil and Gas Production Data:
Oil (MBbls)	2,730			2,475
Gas (MMcf)	6,569			8,665
Natural gas liquids (MBbls)	217			207
Total (MBOE)	4,042			4,126

Average Realized Prices (a):
Oil ($/Bbl)	$	92.70		$	74.39
Gas ($/Mcf)	$	5.42		$	5.21
Natural gas liquids ($/Bbl)	$	53.00		$	40.38

Gain (Loss) on Settled Derivative Contracts (a):
($ in thousands, except per unit)
Oil: Net realized loss	$	(21,989	)	$	(3,098	)
Per unit produced ($/Bbl)	$	(8.05	)	$	(1.25	)
Gas: Net realized gain	$	14,088		$	12,514
Per unit produced ($/Mcf)	$	2.14		$	1.44

(Continued)

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	Nine Months Ended
	September 30,
	2011		2010
Average Daily Production :
Oil (Bbls):
Permian Basin Area:
West Texas Andrews	2,625		1,609
West Texas Reeves	61		—
West Texas Other	3,378		3,860
Austin Chalk/Eagle Ford Shale	3,418		2,827
South Louisiana	440		596
Other(b)	78		174
Total	10,000		9,066
Gas (Mcf):
Permian Basin Area:
West Texas Andrews	1,237		690
West Texas Reeves	20		—
West Texas Other	11,754		13,012
Giddings Area:
Austin Chalk/Eagle Ford Shale	2,029		2,222
Cotton Valley Reef Complex	2,946		3,770
South Louisiana	4,854		6,024
Other(b)	1,222		6,022
Total	24,062		31,740
Natural Gas Liquids (Bbls):
Permian Basin Area:
West Texas Andrews	277		184
West Texas Other	223		204
Austin Chalk/Eagle Ford Shale	208		238
South Louisiana	54		95
Other(b)	33		37
Total	795		758

Exploration Costs (in thousands):
Abandonment and impairment costs:
South Louisiana	$	722	$	1,233
Permian Basin	642		18
Utah	221		64
Deep Bossier	—		2,522
Other	722		2,296
Total	2,307		6,133

Seismic and other	5,287		3,995
Total exploration costs	$	7,594	$	10,128

Depreciation, Depletion and Amortization (in thousands):
Oil and gas depletion	$	72,797	$	74,048
Contract drilling depreciation	1,614		1,700
Other depreciation	576		524
Total DD&A	$	74,987	$	76,272

Oil and Gas Costs ($/BOE Produced):
Production costs	$	18.61	$	15.03
Production costs (excluding production taxes)	$	14.77	$	11.97
Oil and gas depletion	$	18.01	$	17.95

General and Administrative Expenses (in thousands):
Excluding non-cash employee compensation	$	16,574	$	14,720
Non-cash employee compensation(c)	6,104		8,066
Total	$	22,678	$	22,786

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	Nine Months Ended
	September 30,
	2011	2010

Net Wells Drilled (d):
Exploratory Wells	1.5	2.2
Developmental Wells	75.7	76.6

(a) No derivatives were designated as cash flow hedges in the table above. All gains or losses on settled derivatives were included in other income (expense) - gain (loss) on derivatives.

(b) Other for 2010 includes production attributable to sold properties in North Louisiana as follows: Nine Months: Oil 94, Gas 4,790, NGL 10.

(d) Excludes wells being drilled or completed at the end of each period.

Operating Results — Three-Month Periods

The following discussion compares our results for the three months ended September 30, 2011 to the comparative period in 2010. Unless otherwise indicated, references to 2011 and 2010 within this section refer to the respective quarterly period.

Oil and gas operating results

Oil and gas sales in 2011 increased $17.8 million, or 22%, from 2010 primarily due to price variances of $18.3 million. The remaining decrease of $500,000 was due to production variances consisting of a $1.5 million decrease due to lower gas production and a $1 million increase due to higher oil production. Oil production increased 3% in 2011 from 2010 while gas production decreased 13% in 2011 from 2010. Combined oil and gas production in 2011 (on a BOE basis) decreased 4% compared to 2010. In 2011, our realized oil price was 22% higher than 2010, and our realized gas price was 20% higher. Historically, the markets for oil and gas have been volatile, and they are likely to continue to be volatile.

Production costs, consisting of lease operating expenses, production taxes and other miscellaneous marketing costs, increased 18% in 2011 as compared to 2010 due to a combination of more producing wells, rising costs of field services and increased production taxes on higher oil and gas sales. Production costs (excluding production taxes), referred to as lifting costs, increased 17% in 2011 as compared to 2010. Lifting costs per BOE increased from $11.37 per BOE in 2010 to $13.84 per BOE in 2011.

Oil and gas depletion expense increased $395,000 from 2010 to 2011 due to a $1.4 million increase related to rate variances, offset in part by a $1 million decrease related to volume variances . On a BOE basis, depletion expense increased 6% from $17.27 per BOE in 2010 to $18.25 per BOE in 2011. Depletion expense per BOE of oil and gas production is an operating metric that is indicative of our weighted average cost to find or acquire a unit of equivalent production. We may realize higher oil and gas depletion rates in future periods if our exploration and development activities result in higher finding costs.

Exploration costs

Since we follow the successful efforts method of accounting, our results of operations are adversely affected during any accounting period in which significant seismic costs, exploratory dry hole costs, and unproved acreage impairments are expensed. In 2011, we charged to expense $3.1 million of exploration costs, as compared to $1.7 million in 2010.

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Contract Drilling Services

We primarily utilize drilling rigs owned by Desta Drilling to drill wells in our exploration and development activities. Drilling services revenues received by Desta Drilling, along with the related drilling services costs pertaining to the net interest owned by CWEI have been eliminated in our consolidated statements of operations.

General and Administrative

General and Administrative (“G&A”) expenses decreased $1.6 million from $8.7 million in 2010 to $7.1 million in 2011. Excluding non-cash employee compensation expense related to non-equity incentive plans, G&A increased 4% from $5.7 million in 2010 to $6 million in 2011 due primarily to higher personnel costs and legal and professional fees. Non-cash employee compensation expense related to non-equity incentive plans for 2011 was $1.1 million as compared to $3 million in 2010.

Interest expense

Interest expense increased 44% from $6 million in 2010 to $8.7 million in 2011 due primarily to a $7.1 million increase in interest expense related to the issuances in March and April 2011 of $350 million of our 2019 Senior Notes which was partially offset by a $4.2 million decrease as a result of our redemption of $143.2 million of our 2013 Senior Notes in March 2011 and the remaining $81.8 million in August 2011. Interest expense associated with our revolving credit facility declined by $433,000 due primarily to decreased borrowings which declined from an average daily principal balance of $150.4 million in 2010 compared to $101.1 million in 2011.

Loss on early extinguishment of long-term debt

In September 2011, we recorded a $907,000 loss on early extinguishment of long-term debt consisting of the write-off of debt issuance costs related to the remaining $81.8 million in aggregate principal amount of 2013 Senior Notes we redeemed in August 2011.

Gain/loss on derivatives

We did not designate any derivative contracts in 2011 or 2010 as cash flow hedges; therefore all cash settlements and changes resulting from mark-to-market valuations have been recorded as gain/loss on derivatives. For 2011, we reported a $92.3 million net gain on derivatives, consisting of a $91.1 million non-cash gain to mark our derivative positions to their fair value at September 30, 2011 and a $1.2 million realized gain on settled contracts. For 2010, we reported a $4 million net loss on derivatives, consisting of an $8 million non-cash loss to mark our derivative positions to their fair value at September 30, 2010 and a $4 million realized gain on settled contracts. Because oil and gas prices are volatile, and because we do not account for our derivatives as cash flow hedges, the effect of mark-to-market valuations on our gain/loss on derivatives can cause significant volatility in our results of operations.

Gain/loss on sales of assets and impairment of inventory

We recorded a net loss of $65,000 on sales of assets and impairment of inventory in 2011 compared to a net gain of $2.8 million in 2010. The 2011 loss related primarily to the write-down of inventory to its estimated market value at September 30, 2011. The 2010 gain related primarily to the sale of our interest in a non-operated well and related leasehold interests in North Louisiana.

Income tax expense

Our estimated effective income tax rate in 2011 of 35.7% differed from the statutory federal rate of 35% due primarily to increases related to the effects of the Texas Margin Tax and certain non-deductible expenses, offset in part by tax benefits derived from excess statutory depletion deductions.

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Operating Results — Nine-Month Periods

The following discussion compares our results for the nine months ended September 30, 2011 to the comparative period in 2010. Unless otherwise indicated, references to 2011 and 2010 within this section refer to the respective nine-month period.

Oil and gas operating results

Oil and gas sales in 2011 increased $62.6 million, or 26%, from 2010 primarily due to price variances of $54.2 million. The remaining increase of $8.4 million related to production variances consisting of a $19.3 million increase due to higher oil production and a $10.9 million decrease due to lower gas production. Combined oil and gas production in 2011 (on a BOE basis) was 2% lower than 2010. Oil production increased 10% in 2011 from 2010 while gas production decreased 24% in 2011 from 2010. In 2011, our realized oil price was 25% higher than 2010, and our realized gas price was 4% higher. Historically, the markets for oil and gas have been volatile, and they are likely to continue to be volatile.

Production costs, consisting of lease operating expenses, production taxes and other miscellaneous marketing costs, increased 21% in 2011 as compared to 2010 due to a combination of more producing wells, rising costs of field services and increased production taxes on higher oil and gas sales. Production costs (excluding production taxes), referred to as lifting costs, increased 21% in 2011 as compared to 2010. After giving effect to a 2% decrease in total oil and gas production on a BOE basis, lifting costs per BOE increased 23% from $11.97 per BOE in 2010 to $14.77 per BOE in 2011.

Oil and gas depletion expense decreased $1.3 million from 2010 to 2011 due to a $1.5 million decrease related to production variances and a $200,000 increase due to rate variances. On a BOE basis, depletion expense increased from $17.95 per BOE in 2010 to $18.01 per BOE in 2011. The 2011 depletion rate per BOE increased from 2010 due primarily to lower depletable costs in 2011. Depletion expense per BOE of oil and gas production is an operating metric that is indicative of our weighted average cost to find or acquire a unit of equivalent production. We may realize higher oil and gas depletion rates in future periods if our exploration and development activities result in higher finding costs.

Exploration costs

Since we follow the successful efforts method of accounting, our results of operations are adversely affected during any accounting period in which significant seismic costs, exploratory dry hole costs, and unproved acreage impairments are expensed. In 2011, we charged to expense $7.6 million of exploration costs, as compared to $10.1 million in 2010.

Contract Drilling Services

General and Administrative

G&A expenses decreased $100,000 from $22.8 million in 2010 to $22.7 million in 2011. Excluding non-cash employee compensation expense related to non-equity incentive plans, G&A expenses increased from $14.7 million in 2010 to $16.6 million in 2011 due primarily to higher personnel costs and legal and professional fees. Non-cash employee compensation expense related to non-equity incentive plans was $6.1 million in 2011 compared to $8.1 million in 2010.

Interest expense

Interest expense increased 32% from $18.4 million in 2010 to $24.3 million in 2011 due primarily to a $14.6 million increase in interest expense related to the issuances in March and April 2011 of $350 million of our 2019

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Senior Notes which was partially offset by a $7.4 million decrease in interest expense after we redeemed $143.2 million of our 2013 Senior Notes in March 2011 and the remaining $81.8 million in August 2011. The interest expense on our revolver also declined by $1.9 million primarily due to decreased borrowings which declined from an average daily principal balance of $174.4 million in 2010 compared to $97.8 million in 2011.

Loss on early extinguishment of long-term debt

During the year, we redeemed $225 million in aggregate principal amount of 2013 Senior Notes in a tender offer in March 2011 and called the remaining balance in August 2011. We recorded a $5.5 million loss on early extinguishment of long-term debt consisting of a $2.8 million premium and a $2.7 million write-off of debt issuance costs.

Gain/loss on derivatives

We did not designate any derivative contracts in 2011 or 2010 as cash flow hedges; therefore all cash settlements and changes resulting from mark-to-market valuations have been recorded as gain/loss on derivatives. For 2011, we reported a $74.1 million net gain on derivatives, consisting of an $82 million non-cash gain to mark our derivative positions to their fair value at September 30, 2011 and a $7.9 million realized loss on settled contracts. For 2010, we reported a $27.3 million net gain on derivatives, consisting of a $17.9 million non-cash gain to mark our derivative positions to their fair value at September 30, 2010 and a $9.4 million realized gain on settled contracts. Because oil and gas prices are volatile, and because we do not account for our derivatives as cash flow hedges, the effect of mark-to-market valuations on our gain/loss on derivatives can cause significant volatility in our results of operations.

Gain/loss on sales of assets and impairment of inventory

We recorded a net gain of $14.2 million on sales of assets and impairment of inventory in 2011 compared to a net gain of $1.7 million in 2010. The 2011 gain related primarily to the sale of our two 2,000 horsepower drilling rigs and related equipment for a $13.2 million gain. The 2010 gain related primarily to the sale of our interest in a non-operated well and related leasehold interest in North Louisiana for a gain of $3.1 million, offset by a loss of $1.4 million related to the sale of our interests in 22 operated and 76 non-operated producing wells in North Louisiana.

Income tax expense

Liquidity and Capital Resources

Overview

Our primary financial resource is our base of oil and gas reserves. We pledge our producing oil and gas properties to a syndicate of banks led by JPMorgan Chase Bank, N.A. to secure our revolving credit facility. The banks establish a borrowing base, in part, by making an estimate of the collateral value of our oil and gas properties. We borrow funds on the revolving credit facility as needed to supplement our operating cash flow as a financing source for our capital expenditure program. Our ability to fund our capital expenditure program is dependent upon the level of product prices and the success of our exploration program in replacing our existing oil and gas reserves. If product prices decrease, our operating cash flow may decrease and the banks may require additional collateral or reduce our borrowing base, thus reducing funds available to fund our capital expenditure program. However, we may mitigate the effects of product prices on cash flow through the use of commodity derivatives.

The Indenture governing the issuance of our 2019 Senior Notes contains covenants that restrict our ability to incur indebtedness. We currently have, and expect to have in 2011, the ability under the Indenture to incur indebtedness as needed in 2011 to fund our exploration and development activities.

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Capital expenditures

We incurred expenditures for exploration and development activities of $297.4 million during the first nine months of 2011 and we currently plan to spend $407.7 million for fiscal 2011. The following table summarizes, by area, our actual expenditures for exploration and development activities for the first nine months of 2011 and our planned expenditures for the year ending December 31, 2011.

	Actual		Planned
	Expenditures		Expenditures		2011
	Nine Months Ended		Year Ended		Percentage
	September 30, 2011		December 31, 2011		of Total
	(In thousands)
Permian Basin Area:
West Texas Andrews	$	98,600	$	111,900	27	%
West Texas Reeves	117,000		188,100		46	%
West Texas Other	23,800		25,100		6	%
Giddings Area:
Austin Chalk/Eagle Ford Shale	43,000		54,600		13	%
Deep Bossier	4,600		14,500		4	%
South Louisiana	5,300		6,800		2	%
Other	5,100		6,700		2	%
	$	297,400	$	407,700	100	%

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 remainder of the year. Factors, such as changes in operating margins and the availability of capital resources, could also increase or decrease our actual expenditures during the remainder of fiscal 2011.

Our expenditures for exploration and development activities for the nine months ended September 30, 2011 totaled $297.4 million, of which approximately 96% was on developmental drilling. We financed these expenditures with cash flow from operating activities and advances under the revolving credit facility. Based on preliminary estimates, our internal cash flow forecasts indicate that the amount of funds available to us under our revolving credit facility, when combined with our anticipated operating cash flow, will be sufficient to finance our exploration and development activities and provide us with adequate liquidity through 2011. Although we believe the assumptions and estimates made in our forecasts are reasonable, these forecasts are inherently uncertain and the borrowing base may be less than expected, cash flow may be less than expected, or capital expenditures may be more than expected. In the event we lack adequate liquidity to finance our expenditures through 2011, we will consider options for obtaining alternative capital resources, including selling assets or accessing capital markets.

Cash flow provided by operating activities

Substantially all of our cash flow from operating activities is derived from the production of our oil and gas reserves. We use this cash flow to fund our on-going exploration and development activities in search of new oil and gas reserves. Variations in cash flow from operating activities may impact our level of exploration and development expenditures.

Cash flow provided by operating activities for the nine months ended September 30, 2011 increased $21.1 million, or 13.7%, as compared to the corresponding period in 2010 due primarily to a 26% increase in oil and gas sales caused by higher commodity prices.

Revolving credit facility

We have a credit facility with a syndicate of banks that provides for a revolving line of credit of up to $500 million, limited to the amount of a borrowing base as determined by the banks. We have historically relied on the revolving credit facility for both our short-term liquidity (working capital) and our long-term financial needs. As long

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as we have sufficient availability under the revolving credit facility to meet our obligations as they become due, we believe that we will have sufficient liquidity and will be able to fund any short-term working capital deficit.

The borrowing base, which is based on the discounted present value of future net cash flows from oil and gas production, is redetermined by the banks semi-annually in May and November. We or the banks may also request an unscheduled borrowing base redetermination at other times during the year. If, at any time, the borrowing base is less than the amount of outstanding credit exposure under the revolving credit facility, we will be required to (1) provide additional security, (2) prepay the principal amount of the loans in an amount sufficient to eliminate the deficiency (or by a combination of such additional security and such prepayment to eliminate such deficiency), or (3) prepay the deficiency in not more than five equal monthly installments plus accrued interest. The borrowing base was $350 million at September 30, 2011.

The revolving credit facility contains various covenants and restrictive provisions which may, among other things, limit our ability to sell assets, incur additional indebtedness, make investments or loans and create liens. One such covenant requires that we maintain a ratio of consolidated current assets to consolidated current liabilities (the “Consolidated Current Ratio”) of at least 1 to 1. In computing the Consolidated Current Ratio at any balance sheet date, we must (1) include the amount of funds available under this facility as a current asset, (2) exclude current assets and liabilities related to the fair value of derivatives (non-cash assets or liabilities), and (3) exclude current assets and liabilities attributable to vendor financing transactions, if any.

Working capital computed for loan compliance purposes differs from our working capital in accordance with GAAP. Since compliance with financial covenants is a material requirement under the credit facilities, we consider the loan compliance working capital to be useful as a measure of our liquidity because it includes the funds available to us under the revolving credit facility and is not affected by the volatility in working capital caused by changes in fair value of derivatives. Our GAAP reported working capital deficit was $19.9 million at December 31, 2010 compared to working capital of $19.3 million at September 30, 2011. After giving effect to the adjustments, our working capital computed for loan compliance purposes was $157.6 million at September 30, 2011, as compared to $175.3 million at December 31, 2010. The following table reconciles our GAAP working capital (deficit) to the working capital computed for loan compliance purposes at September 30, 2011 and December 31, 2010.

	September 30,			December 31,
	2011			2010
	(In thousands)
Working capital (deficit) per GAAP	$	19,330		$	(19,899	)
Add funds available under the revolving credit facility	180,950			187,975
Exclude fair value of derivatives classified as current assets or current liabilities	(42,642		)	7,224
Working capital per loan covenant	$	157,638		$	175,300

The revolving credit facility provides that the ratio of our consolidated funded indebtedness to consolidated EBITDAX (the “Leverage Ratio”) (determined as of the last end of each fiscal quarter for the then most-recently ended four fiscal quarters) from being greater than 4 to 1.

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We were in compliance with all financial and non-financial covenants at September 30, 2011. However, if we increase leverage and our liquidity is reduced, we may fail to comply with one or more of these covenants in the future. If we fail to meet any of these loan covenants, we would ask the banks to waive compliance, amend the revolving credit facility to allow us to become compliant or grant us sufficient time to obtain additional capital resources through alternative means. If a suitable arrangement could not be reached with the banks, the banks could accelerate the indebtedness and seek to foreclose on the pledged assets.

The lending group under the revolving credit facility includes the following institutions: JPMorgan Chase Bank, N.A., Bank of Scotland, Union Bank, N.A., BNP Paribas, Natixis, Compass Bank, The Frost National Bank, Keybank, N.A., UBS Loan Finance, LLC, The Royal Bank of Scotland plc, and Societe Generale.

From time to time, we engage in other transactions with lenders under the revolving credit facility. Such lenders or their affiliates may serve as counterparties to our commodity and interest rate derivative agreements. As of September 30, 2011, JPMorgan Chase Bank, N.A. was the only counterparty to our commodity derivative agreements. Our obligations under existing derivative agreements with our lenders are secured by the security documents executed by the parties under the revolving credit facility.

During the first nine months of 2011, we increased indebtedness outstanding under the revolving credit facility by $5 million. At September 30, 2011, we had $165 million of borrowings outstanding under the revolving credit facility, leaving $181 million available on the facility after allowing for outstanding letters of credit totaling $4.1 million. The revolving credit facility matures in November 2015.

Senior Notes

In July 2005, we issued $225 million of aggregate principal amount of 2013 Senior Notes. The 2013 Senior Notes were issued at face value and bear interest at 7¾% per year, payable semi-annually on February 1 and August 1 of each year, beginning February 1, 2006. In March 2011, we redeemed $143.2 million in aggregate principal amount of 2013 Senior Notes in a tender offer and recorded a $4.6 million loss on early extinguishment of long-term debt consisting of a $2.8 million premium and a $1.8 million write-off of debt issuance costs. On August 1, 2011, we called at par and redeemed in full the remaining $81.8 million of 2013 Senior Notes and recorded an additional $907,000 loss on early extinguishment of long-term debt related to the write-off of debt issuance costs.

In March 2011, we issued $300 million of aggregate principal amount of 2019 Senior Notes. The 2019 Senior Notes were issued at face value and bear interest at 7.75% per year, payable semi-annually on April 1 and October 1 of each year, beginning October 1, 2011. In April 2011, we issued an additional $50 million aggregate principal amount of 2019 Senior Notes with an original issue discount of 1% or $500,000. We may redeem some or all of the 2019 Senior Notes at redemption prices (expressed as percentages of principal amount) equal to 103.875% for the twelve-month period beginning on April 1, 2015, and 101.938% beginning on April 1, 2016, and 100% beginning on April 1, 2017 or for any period thereafter, in each case plus accrued and unpaid interest.

Alternative capital resources

Although our base of oil and gas reserves, as collateral for our revolving credit facility, has historically been our primary capital resource, we have in the past, and we believe we could in the future, use alternative capital resources, such as asset sales, vendor financing arrangements, and/or public or private issuances of common stock. We could also issue senior or subordinated debt or preferred stock in a public or a private placement if we choose to raise capital

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through either of these markets. While we believe we would be able to obtain funds through one or more of these alternatives, if needed, there can be no assurance that these capital resources would be available on terms acceptable to us.

Item 3 - Quantitative and Qualitative Disclosures About Market Risks

Our business is impacted by fluctuations in commodity prices and interest rates. The following discussion is intended to identify the nature of these market risks, describe our strategy for managing such risks, and to quantify the potential effect of market volatility on our financial condition and results of operations.

Oil and Gas Prices

Our financial condition, results of operations, and capital resources are highly dependent upon the prevailing market prices of, and demand for, oil and natural gas. These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond our control. These factors include the level of global demand for petroleum products, foreign supply of oil and gas, the establishment of and compliance with production quotas by oil-exporting countries, weather conditions, the price and availability of alternative fuels, and overall economic conditions, both foreign and domestic. We cannot predict future oil and gas prices with any degree of certainty. Sustained weakness in oil and gas prices have in the past and may in the future adversely affect our financial condition and results of operations, and may also reduce the amount of net oil and gas reserves that we can produce economically. Any reduction in reserves, including reductions due to price fluctuations, can reduce the borrowing base under our revolving credit facility and adversely affect our liquidity and our ability to obtain capital for our exploration and development activities. Similarly, any improvements in oil and gas prices can have a favorable impact on our financial condition, results of operations and capital resources. Based on December 31, 2010 reserve estimates, we project that a $1 decline in the price per Bbl of oil and a $.50 decline in the price per Mcf of gas from year end 2010 would reduce our gross revenues for the year ending December 31, 2011 by $9.9 million.

From time to time, we utilize commodity derivatives, consisting primarily of swaps, floors and collars to attempt to optimize the price received for our oil and natural gas production. When using swaps to hedge our oil and natural gas production, we receive a fixed price for the respective commodity and pay a floating market price as defined in each contract (generally NYMEX futures prices), resulting in a net amount due to or from the counterparty. When purchasing floors, we receive a fixed price (put strike price) if the market price falls below the put strike price for the respective commodity. If the market price is greater than the put strike price, no payments are due from either party. Costless collars are a combination of puts and calls, and contain a fixed floor price (put strike price) and ceiling price (call strike price). If the market price for the respective commodity exceeds the call strike price or falls below the put strike price, then we receive the fixed price and pay the market price. If the market price is between the call and the put strike prices, no payments are due from either party. The commodity derivatives we use differ from futures contracts in that there is not a contractual obligation that requires or permits the future physical delivery of the hedged products. We do not enter into commodity derivatives for trading purposes. In addition to commodity derivatives, we may, from time to time, sell a portion of our gas production under short-term contracts at fixed prices.

The decision to initiate or terminate commodity hedges is made by management based on its expectation of future market price movements. We have no set goals for the percentage of our production we hedge and we do not use any formulas or triggers in deciding when to initiate or terminate a hedge. If we enter into swaps or collars and the floating market price at the settlement date is higher than the fixed price or the fixed ceiling price, we will forego revenue we would have otherwise received. If we terminate a swap, collar or floor because we anticipate future increases in market prices, we may be exposed to downside risk that would not have existed otherwise.

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Swaps:

	Oil			Gas
	Bbls (a)	Price		MMBtu (b)	Price
Production Period:
4 th Quarter 2011	733,949	$	87.58	1,010,000	$	7.07
2012	107,506	$	91.15	—	$	—
2013	95,996	$	91.15	—	$	—
2014	85,772	$	91.15	—	$	—
2015	76,309	$	91.15	—	$	—
2016	28,280	$	91.15	—	$	—
	1,127,812			1,010,000

(a) In September 2011, we entered into oil hedges covering 398,812 barrels of oil for production months from December 2011 through May 2016. These hedges cover production related to a volumetric production payment in connection with the acquisition by our wholly owned subsidiary, Southwest Royalties, Inc., the of 24 limited partnerships of which it is the general partner. See Note 14.

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

We use a sensitivity analysis technique to evaluate the hypothetical effect that changes in the market value of oil and gas may have on the fair value of our commodity derivatives. A $1 per barrel change in the price of oil and a $.50 per MMBtu change in the price of gas would change the fair value of our commodity derivatives by approximately $5.4 million.

Interest Rates

We are exposed to interest rate risk on our long-term debt with a variable interest rate. At September 30, 2011, our fixed rate debt maturing 2019 had a carrying value of $349.5 million and an approximate fair value of $290.5 million. We estimate that a hypothetical change in the fair value of our long-term debt resulting from a 100-basis point change in interest rates would be approximately $15.1 million. Based on our outstanding variable rate indebtedness at September 30, 2011 of $165 million, a change in interest rates of 100-basis points would affect annual interest payments by $1.7 million.

Item 4 - Controls and Procedures

Disclosure Controls and Procedures

In September 2002, our Board of Directors adopted a policy designed to establish disclosure controls and procedures that are adequate to provide reasonable assurance that our management will be able to collect, process and disclose both financial and non-financial information, on a timely basis, in our reports to the SEC and other communications with our stockholders. Disclosure controls and procedures include all processes necessary to ensure that material information is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and is accumulated and communicated to our management, including our chief executive and chief financial officers, to allow timely decisions regarding required disclosures.

With respect to our disclosure controls and procedures:

· management has evaluated the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report;

· this evaluation was conducted under the supervision and with the participation of our management, including our chief executive and chief financial officers; and

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· it is the conclusion of our chief executive and chief financial officers that these disclosure controls and procedures are effective in ensuring that information that is required to be disclosed by the Company in reports filed or submitted with the SEC is recorded, processed, summarized and reported within the time periods specified in the rules and forms established by the SEC.

Changes in Internal Control Over Financial Reporting

No changes in internal control over financial reporting were made during the quarter ended September 30, 2011 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1A - Risk Factors

In evaluating all forward-looking statements, you should specifically consider various factors that may cause actual results to vary from those contained in the forward-looking statements. Our risk factors are included in our Annual Report on Form 10-K for the year ended December 31, 2010, as filed with the U.S. Securities and Exchange Commission on March 1, 2011, and available at www.sec.gov . Following is an additional risk factor that could affect our financial performance or could cause actual results to differ materially from estimates contained in our forward-looking statements.

Recently proposed rules regulating air emissions from oil and gas operations could cause us to incur increased capital expenditures and operating costs

On July 28, 2011, the Environmental Protection Agency (“EPA”) proposed rules that would establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, EPA’s proposed rule package includes New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds (“VOCs”) and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. EPA’s proposal would require the reduction of VOC emissions from oil and natural gas production facilities by mandating the use of “green completions” for hydraulic fracturing, which requires the operator to recover rather than vent the gas and natural gas liquids that come to the surface during completion of the fracturing process. The proposed rules also would establish specific requirements regarding emissions from compressors, dehydrators, storage tanks, and other production equipment. In addition, the rules would establish new leak detection requirements for natural gas processing plants. EPA will receive public comment and hold hearings regarding the proposed rules and must take final action on them by February 28, 2012. If finalized, these rules could require a number of modifications to our operations including the installation of new equipment. Compliance with such rules could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our business.

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Item 6 - Exhibits

Exhibits

**3.1		Second Restated Certificate of Incorporation of the Company, filed as Exhibit 3.1 to our Form S-2 Registration Statement, Commission File No. 333-13441

**3.2		Certificate of Amendment of Second Restated Certificate of Incorporation of Clayton Williams Energy, Inc., filed as Exhibit 3.1 to our Form 10-Q for the period ended September 30, 2000††

**3.3		Corporate Bylaws of Clayton Williams Energy, Inc., as amended, filed as Exhibit 3.1 to our Current Report on Form 8-K filed with the Commission on March 14, 2008††

**4.1		Indenture, dated March 16, 2011, among Clayton Williams Energy, Inc., the Guarantors named therein and Wells Fargo Bank, N.A., as Trustee, filed as Exhibit 4.1 to our Current Report on Form 8-K filed with the Commission on March 17, 2011††

**4.2		Registration Rights Agreement, dated as of March 16, 2011, by and among Clayton Williams Energy, Inc., the Guarantors named therein and the Initial Purchasers named therein, filed as Exhibit 4.2 to our Current Report on Form 8-K filed with the Commission on March 17, 2011††

**4.3		Registration Rights Agreement, dated as of April 29, 2011, by and among Clayton Williams Energy, Inc., the Guarantors named therein and the Initial Purchasers named therein, filed as Exhibit 4.2 to our Current Report on Form 8-K filed with the Commission on April 29, 2011††

*31.1		Certification by the President and Chief Executive Officer of the Company pursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934

*31.2		Certification by the Chief Financial Officer of the Company pursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934

***32.1		Certifications by the Chief Executive Officer and Chief Financial Officer of the Company pursuant to 18 U.S.C. § 1350

*101.INS		XBRL Instance Document

*101.SCH		XBRL Schema Document

*101.CAL		XBRL Calculation Linkbase Document

*101.DEF		XBRL Definition Linkbase Document

*101.LAB		XBRL Labels Linkbase Document

*101.PRE		XBRL Presentation Linkbase Document

* Filed herewith

** Incorporated by reference to the filing indicated

*** Furnished herewith

† Identifies an Exhibit that consists of or includes a management contract or compensatory plan or arrangement

†† Filed under our Commission File No. 001-10924

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CLAYTON WILLIAMS ENERGY, INC.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereto duly authorized.

		CLAYTON WILLIAMS ENERGY, INC.


Date:	November 4, 2011	By:	/s/ Mel G. Riggs
			Mel G. Riggs
			Executive Vice President and Chief Operating Officer


Date:	November 4, 2011	By:	/s/ Michael L. Pollard
			Michael L. Pollard
			Senior Vice President and Chief Financial Officer

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INDEX TO EXHIBITS

Exhibit No.		Description
**3.1		Second Restated Certificate of Incorporation of the Company, filed as Exhibit 3.1 to our Form S-2 Registration Statement, Commission File No. 333-13441

**3.2		Certificate of Amendment of Second Restated Certificate of Incorporation of Clayton Williams Energy, Inc., filed as Exhibit 3.1 to our Form 10-Q for the period ended September 30, 2000††

**3.3		Corporate Bylaws of Clayton Williams Energy, Inc., as amended, filed as Exhibit 3.1 to our Current Report on Form 8-K filed with the Commission on March 14, 2008††

**4.1		Indenture, dated March 16, 2011, among Clayton Williams Energy, Inc., the Guarantors named therein and Wells Fargo Bank, N.A., as Trustee, filed as Exhibit 4.1 to our Current Report on Form 8-K filed with the Commission on March 17, 2011††

**4.2		Registration Rights Agreement, dated as of March 16, 2011, by and among Clayton Williams Energy, Inc., the Guarantors named therein and the Initial Purchasers named therein, filed as Exhibit 4.2 to our Current Report on Form 8-K filed with the Commission on March 17, 2011††

**4.3		Registration Rights Agreement, dated as of April 29, 2011, by and among Clayton Williams Energy, Inc., the Guarantors named therein and the Initial Purchasers named therein, filed as Exhibit 4.2 to our Current Report on Form 8-K filed with the Commission on April 29, 2011††

*31.1		Certification by the President and Chief Executive Officer of the Company pursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934

*31.2		Certification by the Chief Financial Officer of the Company pursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934

***32.1		Certifications by the Chief Executive Officer and Chief Financial Officer of the Company pursuant to 18 U.S.C. § 1350

*101.INS		XBRL Instance Document

*101.SCH		XBRL Schema Document

*101.CAL		XBRL Calculation Linkbase Document

*101.DEF		XBRL Definition Linkbase Document

*101.LAB		XBRL Labels Linkbase Document

*101.PRE		XBRL Presentation Linkbase Document