- Quarterly Report (10-Q)

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 June 30, 2011

¨	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 ¨ 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 ¨		Accelerated filer x

Non-accelerated filer ¨		Smaller reporting company ¨

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

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

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CLAYTON WILLIAMS ENERGY, INC.

TABLE OF C ONTENTS

		Page
PART I. FINANCIAL INFORMATION

Item 1.	Financial Statements

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

	Consolidated Statements of Operations for the three months and six months ended June 30, 2011 and 2010	5

	Consolidated Statement of Stockholders’ Equity for the six months ended June 30, 2011	6

	Consolidated Statements of Cash Flows for the six months ended June 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	36

Item 4.	Controls and Procedures	38


PART II. OTHER INFORMATION
Item 1A.	Risk Factors	39

Item 6.	Exhibits	39

	Signatures	42

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PART I. FINANCIAL INFORMATION

Item 1 - Financial Statements

CLAYTON WILLIAMS ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

ASSETS

	June 30,			December 31,
	2011			2010
	(Unaudited)
CURRENT ASSETS
Cash and cash equivalents	$	18,079		$	8,720
Accounts receivable:
Oil and gas sales	35,626			35,361
Joint interest and other, net	7,757			9,893
Affiliates	600			796
Inventory	34,732			39,218
Deferred income taxes	3,808			5,074
Assets held for sale	—			8,762
Prepaids and other	16,532			5,997
	117,134			113,821
PROPERTY AND EQUIPMENT
Oil and gas properties, successful efforts method	1,873,222			1,707,252
Natural gas gathering and processing systems	18,439			18,153
Contract drilling equipment	72,930			58,486
Other	18,512			17,425
	1,983,103			1,801,316
Less accumulated depreciation, depletion and amortization	(1,092,607		)	(1,034,227		)
Property and equipment, net	890,496			767,089

OTHER ASSETS
Debt issue costs, net	13,064			8,323
Other	1,938			1,684
	15,002			10,007
	$	1,022,632		$	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

	June 30,		December 31,
	2011		2010
	(Unaudited)
CURRENT LIABILITIES
Accounts payable:
Trade	$	63,242	$	74,123
Oil and gas sales	38,212		28,920
Affiliates	1,683		1,251
Fair value of derivatives	11,712		7,224
Accrued liabilities and other	29,384		22,202
	144,233		133,720
NON-CURRENT LIABILITIES
Long-term debt	448,347		385,000
Deferred income taxes	96,106		78,035
Fair value of derivatives	7,990		3,409
Other	41,498		41,301
	593,941		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	130,740		95,947
	284,458		249,452
	$	1,022,632	$	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						Six Months Ended
	June 30,						June 30,
	2011			2010			2011			2010
REVENUES
Oil and gas sales	$	105,804		$	76,918		$	200,736		$	155,960
Natural gas services	365			452			774			955
Drilling rig services	2,425			—			2,685			—
Gain on sales of assets	949			113			14,521			399
Total revenues	109,543			77,483			218,716			157,314

COSTS AND EXPENSES
Production	26,133			20,567			50,953			41,494
Exploration:
Abandonments and impairments	174			2,891			1,051			5,769
Seismic and other	2,167			974			3,445			2,634
Natural gas services	285			306			548			654
Drilling rig services	1,919			419			2,705			1,081
Depreciation, depletion and amortization	25,342			25,437			49,086			51,049
Impairment of property and equipment	4,424			11,114			4,424			11,114
Accretion of abandonment obligations	697			647			1,371			1,294
General and administrative	3,037			7,832			15,536			14,056
Loss on sales of assets and impairment of inventory	107			1,443			303			1,443
Total costs and expenses	64,285			71,630			129,422			130,588

Operating income	45,258			5,853			89,294			26,726

OTHER INCOME (EXPENSE)
Interest expense	(9,175		)	(6,244		)	(15,587		)	(12,353		)
Loss on early extinguishment of long-term debt	—			—			(4,594		)	—
Gain (loss) on derivatives	28,187			20,983			(18,158		)	31,284
Other	1,900			1,016			2,987			1,844
Total other income (expense)	20,912			15,755			(35,352		)	20,775

Income before income taxes	66,170			21,608			53,942			47,501
Income tax expense	(23,502		)	(7,645		)	(19,149		)	(16,863		)
NET INCOME	$	42,668		$	13,963		$	34,793		$	30,638

Net income per common share:
Basic	$	3.51		$	1.15		$	2.86		$	2.52
Diluted	$	3.51		$	1.15		$	2.86		$	2.52

Weighted average common shares outstanding:
Basic	12,162			12,146			12,159			12,146
Diluted	12,163			12,146			12,159			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	—	—		—		34,793
Issuance of stock through compensation plans, including income tax benefits	8	1		212		—
BALANCE,
June 30, 2011	12,163	$	1,216	$	152,502	$	130,740

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)

	Six Months Ended
	June 30,
	2011			2010
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	34,793		$	30,638
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation, depletion and amortization	49,086			51,049
Impairment of property and equipment	4,424			11,114
Exploration costs	1,051			5,769
(Gain) loss on sales of assets and impairment of inventory, net	(14,218		)	1,044
Deferred income tax expense	19,149			16,863
Non-cash employee compensation	4,963			5,079
Unrealized (gain) loss on derivatives	9,069			(25,871		)
Accretion of abandonment obligations	1,371			1,294
Amortization of debt issue costs	1,130			774
Loss on early extinguishment of long-term debt	4,594			—

Changes in operating working capital:
Accounts receivable	2,067			5,234
Accounts payable	974			(3,403		)
Other	1,271			(2,907		)
Net cash provided by operating activities	119,724			96,677

CASH FLOWS FROM INVESTING ACTIVITIES
Additions to property and equipment	(180,281		)	(135,528		)
Proceeds from sales of assets	12,105			73,011
Change in equipment inventory	4,783			1,300
Other	(110		)	(98		)
Net cash used in investing activities	(163,503		)	(61,315		)

CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt	341,855			—
Repayments of long-term debt	(286,165		)	(39,000		)
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	53,138			(39,000		)

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	9,359			(3,638		)

CASH AND CASH EQUIVALENTS
Beginning of period	8,720			14,013
End of period	$	18,079		$	10,375

SUPPLEMENTAL DISCLOSURES
Cash paid for interest, net of amounts capitalized	$	1,754		$	11,735

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

June 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 June 30, 2011 and for the interim periods ended June 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 accounting principles generally accepted in the United States 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:

	June 30,		December 31,
	2011		2010
	(In thousands)
7.75% Senior Notes due 2019, net of unamortized original issue discount of $488	$	349,512	$	—
7¾% Senior Notes due 2013	81,835		225,000
Revolving credit facility, due November 2015	17,000		160,000
	$	448,347	$	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. The remaining $81.8 million of 2013 Senior Notes were called at par and redeemed in full on August 1, 2011.

In March 2011, we issued $300 million of aggregate principal amount of 7.75% Senior Notes due 2019 (“2019 Senior Notes”, and together with the 2013 Senior Notes, the “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 Indentures governing the 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 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 Indentures) does not exceed certain ratios specified in the Indentures governing the Senior Notes. These covenants are subject to a number of important exceptions and qualifications as described in the Indentures. We were in compliance with these covenants at June 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 June 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 million, we had $329 million available under the revolving credit facility at June 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 six months ended June 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 loan agreement. We were in compliance with all financial and non-financial covenants at June 30, 2011.

4. Other Non-Current Liabilities

Other non-current liabilities consist of the following:

	June 30,		December 31,
	2011		2010
	(In thousands)
Abandonment obligations	$	40,641	$	40,444
Other	857		857
	$	41,498	$	41,301

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

	Six Months Ended
	June 30,
	2011			2010
	(In thousands)
Beginning of period	$	40,444		$	38,412
Additional abandonment obligations from new properties	863			993
Sales or abandonments of properties	(2,037		)	(1,113		)
Revisions of previous estimates	—			(320		)
Accretion expense	1,371			1,294
End of period	$	40,641		$	39,266

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 June 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 3.5 years, and an aggregate intrinsic value of $234,000 (based on a market price at June 30, 2011 of $60.05 per share). No options were granted during the six months ended June 30, 2011 or 2010, and options to purchase 8,000 shares of common stock were exercised during the six months ended June 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.

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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.

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. In June 2011, the Compensation Committee of the Board of Directors approved the creation of three APO Reward Plans as successors to three existing plans. The creation of the new plans modified the existing plans resulting in a one-time adjustment to reverse a portion of the previously accrued compensation expense. We recorded a gain of $2.4 million for the three months ended June 30, 2011 and a $3.1 million charge for compensation expense for the three months ended June 30, 2010 in connection with all non-equity award plans. We recorded compensation expense of $5 million for the six months ended June 30, 2011 and $5.1 million for the six months ended June 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 June 30, 2011, including contracts entered into subsequent to June 30, 2011. The settlement prices of commodity derivatives are based on NYMEX futures prices.

Swaps:

	Oil			Gas
	Bbls	Price		MMBtu (a)	Price
Production Period:
3 rd Quarter 2011	547,000	$	83.78	1,560,000	$	7.07
4 th Quarter 2011	729,000	$	87.56	1,500,000	$	7.07
2012	2,649,000	$	95.75	—	$	—
2013	1,189,000	$	99.92	—	$	—
	5,114,000			3,060,000

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

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 June 30, 2011, we reported a $28.2 million net gain on derivatives, consisting of a $35.6 million non-cash gain related to changes in mark-to-market valuations and a $7.4 million realized loss for settled contracts. For the three months ended June 30, 2010, we reported a $21 million net gain on derivatives, consisting of a $17.3 million non-cash gain related to changes in mark-to-market valuations and a $3.7 million realized gain for settled contracts. For the six months ended June 30, 2011, we reported an $18.2 million net loss on derivatives, consisting of a $9.1 million non-cash loss related to changes in mark-to-market valuations and a $9.1 million realized loss for settled contracts. For the six months ended June 30, 2010, we reported a $31.3 million net gain on derivatives, consisting of a $25.9 million non-cash gain related to changes in mark-to-market valuations and a $5.4 million realized gain for settled contracts.

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Effect of Derivative Instruments on the Consolidated Balance Sheets

	Fair Value of Derivative Instruments as of June 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	$	—	Current	$	11,712
	Non-current	—		Non-current	7,990
Total		$	—		$	19,702

	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

	June 30, 2011
	Assets			Liabilities
	(In thousands)
Fair value of derivatives — gross presentation	$	7,918		$	27,620
Effects of netting arrangements	(7,918		)	(7,918		)
Fair value of derivatives — net presentation	$	—		$	19,702

	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

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.

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Effect of Derivative Instruments on the Consolidated Statements of Operations

	Amount of Gain or (Loss) Recognized in Earnings
	Three Months Ended							Six Months Ended
Location of Gain or (Loss)	June 30, 2011							June 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	$	(7,371	)	$	35,558	$	28,187	$	(9,089	)	$	(9,069	)	$	(18,158	)
Total	$	(7,371	)	$	35,558	$	28,187	$	(9,089	)	$	(9,069	)	$	(18,158	)

	Amount of Gain or (Loss) Recognized in Earnings
	Three Months Ended						Six Months Ended
Location of Gain or (Loss)	June 30, 2010						June 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	$	3,714	$	17,269	$	20,983	$	5,413	$	25,871	$	31,284
Total	$	3,714	$	17,269	$	20,983	$	5,413	$	25,871	$	31,284

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 June 30, 2011, our fixed rate debt maturing 2013 had a carrying value of $81.8 million and an approximate fair value of $81.8 million, based on current market quotes. At June 30, 2011, our fixed rate debt maturing 2019 had a carrying value of $349.5 million and an approximate fair value of $340.4 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 liabilities measured on a recurring basis at June 30, 2011 and December 31, 2010 were commodity derivatives. Information regarding these liabilities is summarized below:

	June 30,		December 31,
	2011		2010
	Significant Other		Significant Other
	Observable Inputs		Observable Inputs
Description	(Level 2)		(Level 2)
	(In thousands)
Liabilities:
Fair value of commodity derivatives	$	19,702	$	10,633
Total liabilities	$	19,702	$	10,633

8. Income Taxes

Our effective federal and state income tax expense rate for the six months ended June 30, 2011 of 35.5% 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 six months ended June 30, 2011 and June 30, 2010 are as follows:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2011			2010			2011			2010
	(In thousands)						(In thousands)
Gain on sales of assets	$	949		$	113		$	14,521		$	399

Loss on sales of assets and impairment of inventory:
Loss on sales of assets	(107		)	(1,443		)	(122		)	(1,443		)
Impairment of inventory	—			—			(181		)	—
	(107		)	(1,443		)	(303		)	(1,443		)

Net gain (loss)	$	842		$	(1,330	)	$	14,218		$	(1,044	)

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. Proceeds from the sale consisted of $11 million cash and an $11 million promissory note due December 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 June 30, 2011 and December 31, 2010.

	June 30,			December 31,
	2011			2010
	(In thousands)
Proved properties	$	1,800,348		$	1,655,217
Unproved properties	72,874			52,035
Total capitalized costs	1,873,222			1,707,252
Accumulated depreciation, depletion and amortization	(1,035,300		)	(983,119		)
Net capitalized costs	$	837,922		$	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 aggregating $4.4 million in 2011 and $11.1 million in 2010, respectively. These impairments were related to non-core areas in the Permian Basin to reduce the carrying values of those properties to their estimated fair value at June 30, 2011 and 2010, respectively.

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 $249,000 in 2011 and $5.5 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 six-month periods ended June 30, 2011 and 2010.

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

Revenues	$	107,118		$	12,634		$	(10,209	)	$	109,543
Depreciation, depletion and amortization (a)	29,081			2,967			(2,282		)	29,766
Other operating expenses (b)	32,531			10,775			(8,787		)	34,519
Interest expense	9,175			—			—			9,175
Other (income) expense	(30,087		)	—			—			(30,087		)
Income (loss) before income taxes	66,418			(1,108		)	860			66,170

Income tax (expense) benefit	(23,626		)	124			—			(23,502		)

Net income (loss)	$	42,792		$	(984	)	$	860		$	42,668

Total assets	$	972,459		$	50,068		$	105		$	1,022,632
Additions to property and equipment	$	81,544		$	13,170		$	—		$	94,714

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

Revenues	$	216,031		$	24,793		$	(22,108	)	$	218,716
Depreciation, depletion and amortization (a)	52,565			5,822			(4,877		)	53,510
Other operating expenses (b)	73,064			20,184			(17,336		)	75,912
Interest expense	15,587			—			—			15,587
Other (income) expense	32,987			(13,222		)	—			19,765
Income (loss) before income taxes	41,828			12,009			105			53,942

Income tax (expense) benefit	(14,946		)	(4,203		)	—			(19,149		)

Net income (loss)	$	26,882		$	7,806		$	105		$	34,793

Total assets	$	972,459		$	50,068		$	105		$	1,022,632
Additions to property and equipment	$	168,231		$	14,723		$	—		$	182,954

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

Revenues	$	77,483		$	8,410		$	(8,410	)	$	77,483
Depreciation, depletion and amortization (a)	36,097			2,495			(2,041		)	36,551
Other operating expenses (b)	34,373			6,642			(5,936		)	35,079
Interest expense	6,241			3			—			6,244
Other (income) expense	(21,999		)	—			—			(21,999		)
Income (loss) before income taxes	22,771			(730		)	(433		)	21,608

Income tax (expense) benefit	(7,900		)	255			—			(7,645		)

Net income (loss)	$	14,871		$	(475	)	$	(433	)	$	13,963

Total assets	$	757,998		$	37,078		$	(10	)	$	795,066
Additions to property and equipment	$	82,906		$	4,021		$	—		$	86,927

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

Revenues	$	157,314		$	14,383		$	(14,383	)	$	157,314
Depreciation, depletion and amortization (a)	60,857			4,833			(3,527		)	62,163
Other operating expenses (b)	67,236			11,248			(10,059		)	68,425
Interest expense	12,350			3			—			12,353
Other (income) expense	(33,128		)	—			—			(33,128		)
Income (loss) before income taxes	49,999			(1,701		)	(797		)	47,501

Income tax (expense) benefit	(17,458		)	595			—			(16,863		)

Net income (loss)	$	32,541		$	(1,106	)	$	(797	)	$	30,638

Total assets	$	757,998		$	37,078		$	(10	)	$	795,066
Additions to property and equipment	$	138,000		$	7,579		$	—		$	145,579

(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

In March 2011, we entered into an agreement with Chesapeake Exploration, L.L.C. (“Chesapeake”) where we can earn a 75% interest in leases held by Chesapeake in southern Reeves County, Texas. We have a one-year commitment to drill 20 wells prior to March 1, 2012. If we fail to do so, the agreement will terminate, and we will be required to pay Chesapeake an aggregate amount equal to $15 million less $750,000 for each well drilled in compliance with the agreement. Following satisfaction of our initial drilling obligations, we have the right, but not the obligation to drill at least 20 additional wells each year during the remaining four years of the term of the agreement. If we fail to drill 20 wells during any year after expiration of the initial drilling period, the 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. Costs of drilling and completing subsequent wells drilled shall be borne 75% by us and 25% by Chesapeake. We have currently spud 13 of the 20 wells we are committed to drill prior to March 1, 2012, reducing our contingent liability to $5.3 million.

As of June 30, 2011, we had $47.9 million in non-cancellable orders for tubular goods. In April 2011, we made a 50% down payment of $8.2 million to purchase two drilling rigs for our Desta Drilling fleet. The remaining payment will be made during the third quarter of 2011.

14. Subsequent Events

We have evaluated events and transactions that occurred after the balance sheet date of June 30, 2011. On August 1, 2011, we redeemed in full the remaining $81.8 million of 2013 Senior Notes at par. We did not have any other subsequent events that would require recognition in the consolidated financial statements or disclosures in these notes to the consolidated financial statements.

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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 second quarter of 2011 and the outlook for the remainder of 2011.

· Our oil and gas sales increased $28.9 million, or 38%, from 2010. Price variances accounted for an increase of $25.2 million while, production variances accounted for the remaining $3.7 million increase.

· Our oil production increased 10% compared to 2010 while gas production declined 19%. Our combined oil and gas production for the second quarter of 2011 remained constant on a barrel of oil equivalent (“BOE”) basis compared to the same period in 2010. On a comparable basis, after giving effect to the sale of properties in North Louisiana in June 2010, total oil and gas production in 2011 (on a BOE basis) was 8% higher than 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 27% or $5.6 million for the second quarter of 2011 compared to the second quarter of 2010. Production costs excluding production taxes, referred to as lifting costs, accounted for $4.5 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 $1.1 million of the increase due to higher oil and gas sales.

· We recorded a $28.2 million net gain on derivatives in the second quarter of 2011, consisting of a $35.6 million non-cash gain for changes in mark-to-market valuations and a $7.4 million realized loss on settled contracts. For the same period in 2010, we reported a $21 million net gain on derivatives consisting of a $17.3 million non-cash gain for changes in mark-to-market valuations and a $3.7 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.

· Interest expense increased to $9.2 million in the second quarter of 2011 compared to $6.2 million in the second quarter of 2010 due primarily to the increase in the total aggregate principal amount of our Senior Notes from $225 million to $431.8 million.

· Non-cash impairments of property and equipment were $4.4 million in the second quarter of 2011 compared to $11.1 million in the second quarter of 2010. The 2011 impairment related to certain non-core oil and gas properties in the Permian Basin.

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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 $439.4 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 $109.3 million in the Permian Basin during the first half of 2011 on drilling and completion activities and $26 million on seismic and leasing activities. We drilled and completed 45 gross (36.8 net) operated wells in the Permian Basin and conducted various remedial operations on other wells during the first half of 2011. We currently plan to spend approximately $368.6 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 $19.8 million on drilling and completion activities and $24.5 million for leasing activities in the Wolfbone play during the first half of 2011. We plan to spend approximately $197.5 million on drilling and completion activities and $39.5 million on leasing activities in the Wolfbone play during fiscal 2011. To date, we have accumulated approximately 20,000 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. If we fail to do so, the farm-in agreement will terminate, and we will be required to pay Chesapeake an aggregate amount equal to $15 million less $750,000 for each carried well we drilled in compliance with the farm-in agreement prior to March 1, 2012. 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 have currently spud 13 of the first 20 carried wells we are required to drill prior to March 1, 2012, reducing our contingent liability to $5.3 million. We are currently utilizing seven rigs in this area and plan to increase the rig count to 11 rigs during 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 $76.2 million on Wolfberry drilling and completion activities and approximately $1.1 million on seismic and leasing activities during the first half of 2011, and currently plan to spend approximately $113.9 million on drilling and leasing activities in this area during fiscal 2011. We currently have three rigs drilling Wolfberry wells but we plan to reduce the rig count down to one during 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 eight 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 half of 2011, we spent approximately $26.1 million in the Giddings Area on drilling and leasing activities and currently plan to spend approximately $59.3 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 two of our drilling rigs in the Giddings Area to drill dual opposed or dual stacked lateral horizontal wells in the Austin Chalk and plan to reduce the rig count to one during the remainder of 2011.

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 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. We believe that the reserve potential from this well justifies the exploration risks despite current price levels of natural gas.

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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 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. 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. We are constructing two additional drilling rigs which are expected to be operational during the third quarter of 2011.

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
	June 30,
	2011			2010
Oil and Gas Production Data:
Oil (MBbls)	886			808
Gas (MMcf)	2,261			2,807
Natural gas liquids (MBbls)	73			60
Total (MBOE)	1,336			1,336

Average Realized Prices (a):
Oil ($/Bbl)	$	100.07		$	74.27
Gas ($/Mcf)	$	5.56		$	5.14
Natural gas liquids ($/Bbl)	$	57.16		$	40.13

Gain (Loss) on Settled Derivative Contracts (a): ($ in thousands, except per unit)
Oil: Net realized loss	$	(11,919	)	$	(1,249	)
Per unit produced ($/Bbl)	$	(13.45	)	$	(1.55	)
Gas: Net realized gain	$	4,548		$	4,964
Per unit produced ($/Mcf)	$	2.01		$	1.77

Average Daily Production :
Oil (Bbls):
Permian Basin	5,680			5,390
Austin Chalk/Eagle Ford Shale	3,335			2,835
South Louisiana	493			435
Other(b)	228			219
Total	9,736			8,879

Gas (Mcf):
Permian Basin	12,176			13,263
Giddings Area:
Austin Chalk/Eagle Ford Shale	2,177			1,810
Cotton Valley Reef Complex	2,931			4,072
South Louisiana	6,134			4,930
Other(b)	1,428			6,771
Total	24,846			30,846

Natural Gas Liquids (Bbls):
Permian Basin	519			356
Austin Chalk/Eagle Ford Shale	183			185
South Louisiana	60			86
Other(b)	40			32
Total	802			659

(Continued)

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	Three Months Ended
	June 30,
	2011			2010
Exploration Costs (in thousands):
Abandonment and impairment costs:
South Louisiana	$	174		$	1,148
Deep Bossier	—			735
Other	—			1,008
Total	174			2,891

Seismic and other	2,167			974
Total exploration costs	$	2,341		$	3,865

Depreciation, Depletion and Amortization (in thousands):
Oil and gas depletion	$	24,464		$	24,813
Contract drilling depreciation	685			454
Other depreciation	193			170
Total DD&A	$	25,342		$	25,437

Oil and Gas Costs ($/BOE Produced):
Production costs	$	19.56		$	15.39
Production costs (excluding production taxes)	$	15.61		$	12.25
Oil and gas depletion	$	18.31		$	18.57

General and Administrative Expenses (in thousands):
Excluding non-cash employee compensation	$	5,475		$	4,763
Non-cash employee compensation(c)	(2,438		)	3,069
Total	$	3,037		$	7,832

Net Wells Drilled (d):
Exploratory Wells	—			1.1
Developmental Wells	22.7			26.3

	Six Months Ended
	June 30,
	2011			2010
Oil and Gas Production Data:
Oil (MBbls)	1,785			1,560
Gas (MMcf)	4,374			6,135
Natural gas liquids (MBbls)	156			117
Total (MBOE)	2,670			2,700

Average Realized Prices (a):
Oil ($/Bbl)	$	94.47		$	75.10
Gas ($/Mcf)	$	5.40		$	5.48
Natural gas liquids ($/Bbl)	$	52.47		$	43.08

Gain (Loss) on Settled Derivative Contracts (a): ($ in thousands, except per unit)
Oil: Net realized loss	$	(18,697	)	$	(2,871	)
Per unit produced ($/Bbl)	$	(10.47	)	$	(1.84	)
Gas: Net realized gain	$	9,608		$	8,283
Per unit produced ($/Mcf)	$	2.20		$	1.35

(Continued)

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	Six Months Ended
	June 30,
	2011		2010
Average Daily Production :
Oil (Bbls):
Permian Basin	5,927		5,151
Austin Chalk/Eagle Ford Shale	3,333		2,717
South Louisiana	454		530
Other(b)	148		221
Total	9,862		8,619
Gas (Mcf):
Permian Basin	13,043		13,586
Giddings Area:
Austin Chalk/Eagle Ford Shale	2,060		2,169
Cotton Valley Reef Complex	2,942		3,802
South Louisiana	4,650		6,213
Other(b)	1,471		8,125
Total	24,166		33,895
Natural Gas Liquids (Bbls):
Permian Basin	568		314
Austin Chalk/Eagle Ford Shale	205		228
South Louisiana	52		83
Other(b)	37		21
Total	862		646

Exploration Costs (in thousands):
Abandonment and impairment costs:
South Louisiana	$	706	$	1,148
Permian Basin	—		13
Deep Bossier	—		2,248
Other	345		2,360
Total	1,051		5,769
Seismic and other	3,445		2,634
Total exploration costs	$	4,496	$	8,403

Depreciation, Depletion and Amortization (in thousands):
Oil and gas depletion	$	47,755	$	49,401
Contract drilling depreciation	945		1,307
Other depreciation	386		341
Total DD&A	$	49,086	$	51,049

Oil and Gas Costs ($/BOE Produced):
Production costs	$	19.08	$	15.37
Production costs (excluding production taxes)	$	15.14	$	12.22
Oil and gas depletion	$	17.89	$	18.30

General and Administrative Expenses (in thousands):
Excluding non-cash employee compensation	$	10,573	$	8,977
Non-cash employee compensation(c)	4,963		5,079
Total	$	15,536	$	14,056
Net Wells Drilled (d):
Exploratory Wells	0.5		2.2
Developmental Wells	49.8		52.6

(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: Three months: Oil 137, Gas 5,747, NGL 26 and Six Months: Oil 142, Gas 7,225, NGL 15.
(c)	Non-cash employee compensation relates to the Company’s non-equity award plans. In June 2011, the Compensation Committee of the Board of Directors approved the creation of three APO Reward Plans as successors to three existing plans. The creation of the new plans modified the existing plans resulting in a one-time adjustment to reverse a portion of the previously accrued compensation expense.
(d)	Excludes wells being drilled or completed at the end of each period.

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Operating Results — Three-Month Periods

The following discussion compares our results for the three months ended June 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 $28.9 million, or 38%, from 2010 primarily due to price variances of $25.2 million. The remaining increase of $3.7 million was due to production variances including a $6.5 million increase due to oil offset by a $2.8 million decrease due to gas. Oil production increased 10% in 2011 from 2010 while gas production decreased 19% in 2011 from 2010. Combined oil and gas production in 2011 (on a BOE basis) was unchanged compared to 2010. On a comparable basis, after giving effect to the sale of properties in North Louisiana in June 2010, combined oil and gas production for 2011 increased 8% (on a BOE basis) from 2010. Oil and gas production for 2011 was lower than expected due primarily to completion delays and disruptions in production caused by wildfires in our Permian Basin Wolfberry play. These production shortfalls were partially offset by higher than anticipated oil and gas production from our Austin Chalk and South Louisiana areas. In 2011, our realized oil price was 35% higher than 2010, and our realized gas price was 8% 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 27% 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 27% in 2011 as compared to 2010. Lifting costs per BOE increased from $12.25 per BOE in 2010 to $15.61 per BOE in 2011.

Oil and gas depletion expense decreased $348,000 from 2010 to 2011, primarily due to rate variances . On a BOE basis, depletion expense decreased 1% from $18.57 per BOE in 2010 to $18.31 per BOE in 2011. The 2011 depletion rate per BOE dropped from 2010 due primarily to higher estimated reserve quantities 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 $2.3 million of exploration costs, as compared to $3.9 million in 2010.

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 $4.8 million from $7.8 million in 2010 to $3 million in 2011. Excluding non-cash employee compensation expense, G&A increased 15% from $4.8 million in 2010 to $5.5 million in 2011 due primarily to higher personnel costs. Non-cash employee compensation expense related to non-equity incentive plans for 2011 was a gain of $2.4 million as compared to an expense of $3.1 million in 2010. In June 2011, we created three APO Reward Plans as successors to three existing plans. The creation of the new plans modified the existing plans resulting in a one-time adjustment to reverse a portion of the previously accrued compensation expense.

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Interest expense

Interest expense increased 47% from $6.2 million in 2010 to $9.2 million in 2011 due primarily to a $6.5 million increase in interest expense related to the issuances in March and April 2011 of $350 million of Senior Notes which was partially offset by a $2.8 million decrease since we redeemed $143.2 million of our 2013 Senior Notes in March 2011. The interest expense on our revolver also declined by $1.1 million primarily due to decreased borrowings which declined from an average daily principal balance of $180.6 million in 2010 compared to $33.8 million in 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 $28.2 million net gain on derivatives, consisting of a $35.6 million non-cash gain to mark our derivative positions to their fair value at June 30, 2011 and a $7.4 million realized loss on settled contracts. For 2010, we reported a $21 million net gain on derivatives, consisting of a $17.3 million non-cash gain to mark our derivative positions to their fair value at June 30, 2010 and a $3.7 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 $842,000 on sales of assets and impairment of inventory in 2011 compared to a net loss of $1.3 million in 2010. The 2011 gain related primarily to the sale of certain interests in two prospects in South Louisiana. The 2010 loss related primarily to the sale of our interests in 22 operated and 76 non-operated producing wells in North Louisiana.

Income tax expense

Our estimated effective income tax rate in 2011 of 35.5% 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.

Operating Results — Six-Month Periods

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

Oil and gas operating results

Oil and gas sales in 2011 increased $44.8 million, or 29%, from 2010 primarily due to price variances of $35.8 million. The remaining increase of $9 million was due to production variances including a $19 million increase due to higher oil production offset by a $10 million decrease in gas production. Production in 2011 (on a BOE basis) was 1% lower than 2010. Oil production increased 14% in 2011 from 2010 while gas production decreased 29% in 2011 from 2010. On a comparable basis, after giving effect to the sale of properties in North Louisiana in June 2010, combined oil and gas production for 2011 increased 9% (on a BOE basis) from 2010. In 2011, our realized oil price was 26% higher than 2010, and our realized gas price was 1% lower. 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 23% 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 23% in 2011 as compared to 2010. After giving effect to a 1% decrease in total oil and gas production on a BOE basis, lifting costs per BOE increased 24% from $12.22 per BOE in 2010 to $15.14 per BOE in 2011.

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Oil and gas depletion expense decreased $1.6 million from 2010 to 2011, of which rate variances accounted for a $1.1 million decrease and production variances accounted for the remaining $500,000 decrease. On a BOE basis, depletion expense decreased 2% from $18.30 per BOE in 2010 to $17.89 per BOE in 2011. The 2011 depletion rate per BOE dropped from 2010 due primarily to higher estimated reserve quantities 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 $4.5 million of exploration costs, as compared to $8.4 million in 2010.

Contract Drilling Services

General and Administrative

G&A expenses increased $1.4 million from $14.1 million in 2010 to $15.5 million in 2011. Employee compensation expense related to non-equity incentive plans was $5 million in 2011 compared to $5.1 million in 2010. Excluding employee compensation related to non-equity incentive plans, G&A expenses increased from $9 million in 2010 to $10.5 million in 2011 due primarily to higher personnel costs.

Interest expense

Interest expense increased 26% from $12.4 million in 2010 to $15.6 million in 2011 due primarily to a $7.5 million increase in interest expense related to the issuances in March and April 2011 of $350 million of Senior Notes which was partially offset by a $3.2 million decrease in interest expense after we redeemed $143.2 million of our 2013 Senior Notes in March 2011. The interest expense on our revolver also declined by $1.4 million primarily due to decreased borrowings which declined from an average daily principal balance of $186.5 million in 2010 compared to $96.1 million in 2011.

Loss on early extinguishment of long-term debt

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.

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 an $18.2 million net loss on derivatives, consisting of a $9.1 million non-cash loss to mark our derivative positions to their fair value at June 30, 2011 and a $9.1 million realized loss on settled contracts. For 2010, we reported a $31.3 million net gain on derivatives, consisting of a $25.9 million non-cash gain to mark our derivative positions to their fair value at June 30, 2010 and a $5.4 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.

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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 loss of $1 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 loss related primarily 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 Indentures governing the issuance of our Senior Notes contain covenants that restrict our ability to incur indebtedness. We currently have, and expect to have in 2011, the ability under the Indentures to incur indebtedness as needed in 2011 to fund our exploration and development activities.

Capital expenditures

We incurred expenditures for exploration and development activities of $168.5 million during the first half of 2011 and we currently plan to spend $439.4 million for fiscal 2011. The following table summarizes, by area, our actual expenditures for exploration and development activities for the first six months of 2011 and our planned expenditures for the year ending December 31, 2011.

	Actual		Planned
	Expenditures		Expenditures		2011
	Six Months Ended		Year Ended		Percentage
	June 30, 2011		December 31, 2011		of Total
	(In thousands)
Permian Basin:
Wolfbone	$	44,300	$	237,000	54	%
Wolfberry	77,300		113,900		26	%
Other	13,700		17,700		4	%
Giddings Area:
Austin Chalk/Eagle Ford Shale	25,900		45,500		10	%
Deep Bossier	200		13,800		3	%
South Louisiana	3,400		6,800		2	%
Other	3,700		4,700		1	%
	$	168,500	$	439,400	100	%

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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 first six months ended June 30, 2011 totaled $168.5 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 first six months ended June 30, 2011 increased $23 million, or 23.8%, as compared to the corresponding period in 2010 due primarily to a 29% 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 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 June 30, 2011.

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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 increased from $19.9 million at December 31, 2010 to a deficit of $27.1 million at June 30, 2011. After giving effect to the adjustments, our working capital computed for loan compliance purposes was $313.6 million at June 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 June 30, 2011 and December 31, 2010.

	June 30,			December 31,
	2011			2010
	(In thousands)
Working capital (deficit) per GAAP	$	(27,099	)	$	(19,899	)
Add funds available under the revolving credit facility	328,975			187,975
Exclude fair value of derivatives classified as current assets or current liabilities	11,712			7,224
Working capital per loan covenant	$	313,588		$	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.

We were in compliance with all financial and non-financial covenants at June 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 June 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 six months of 2011, we decreased indebtedness outstanding under the revolving credit facility by $143 million. At June 30, 2011, we had $17 million of borrowings outstanding under the revolving credit facility, leaving $329 million available on the facility after allowing for outstanding letters of credit totaling $4 million. The revolving credit facility matures in November 2015.

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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. The remaining $81.8 million of 2013 Senior Notes were called at par and redeemed in full on August 1, 2011.

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 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

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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.

Swaps:

	Oil			Gas
	Bbls	Price		MMBtu (a)	Price
Production Period:
3 rd Quarter 2011	547,000	$	83.78	1,560,000	$	7.07
4 th Quarter 2011	729,000	$	87.56	1,500,000	$	7.07
2012	2,649,000	$	95.75	—	$	—
2013	1,189,000	$	99.92	—	$	—
	5,114,000			3,060,000

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

We 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 $4.7 million.

Interest Rates

We are exposed to interest rate risk on our long-term debt with a variable interest rate. At June 30, 2011, our fixed rate debt maturing 2013 had a carrying value of $81.8 million and an approximate fair value of $81.8 million, based on current market quotes. At June 30, 2011, our fixed rate debt maturing 2019 had a carrying value of $349.5 million and an approximate fair value of $340.4 million. We estimate that the hypothetical change in the fair value of our long-term debt resulting from a 100-basis point change in interest rates would be approximately $20.7 million. Based on our outstanding variable rate indebtedness at June 30, 2011 of $17 million, a change in interest rates of 100-basis points would affect annual interest payments by $170,000.

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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

· 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 June 30, 2011 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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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.

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 July 20, 2005, among Clayton Williams Energy, Inc., the Subsidiary Guarantors and Wells Fargo Bank, National Association, as Trustee, filed as Exhibit 4.1 to our Current Report on Form 8-K filed with the Commission on July 22, 2005††

**4.	2	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.	3	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††

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**4.	4	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††

*10.	1	Second Amendment to Second Amended and Restated Credit Agreement dated May 17, 2011

**10.	2†	Amended and Restated Employment Agreement between Clayton Williams Energy, Inc. and Mel G. Riggs, effective as of June 1, 2011, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on June 7, 2011††

**10.	3†	Amended and Restated Employment Agreement between Clayton Williams Energy, Inc. and Michael L. Pollard, effective as of June 1, 2011, filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K filed with the Commission on June 7, 2011††

**10.	4†	Employment Agreement between Clayton Williams Energy, Inc. and Robert L. Thomas, effective as of June 1, 2011, filed as Exhibit 10.3 to the Company’s Current Report on Form 8-K filed with the Commission on June 7, 2011††

**10.	5†	CWEI Andrews Fee Reward Plan II dated June 28, 2011, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on June 30, 2011††

**10.	6†	CWEI Andrews University Reward Plan dated June 28, 2011, filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K filed with the Commission on June 30, 2011††

**10.	7†	CWEI Austin Chalk Reward Plan III dated June 28, 2011, filed as Exhibit 10.3 to the Company’s Current Report on Form 8-K filed with the Commission on June 30, 2011††

**10.	8†	CWEI Delaware Basin Reward Plan dated June 28, 2011, filed as Exhibit 10.4 to the Company’s Current Report on Form 8-K filed with the Commission on June 30, 2011††

**10.	9†	CWEI Andrews Samson Reward Plan II dated June 28, 2011, filed as Exhibit 10.5 to the Company’s Current Report on Form 8-K filed with the Commission on June 30, 2011††

**10.	10†	CWEI South Louisiana Reward Plan dated June 28, 2011, filed as Exhibit 10.6 to the Company’s Current Report on Form 8-K filed with the Commission on June 30, 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

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*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:	August 5, 2011	By:	/s/ Mel G. Riggs
			Mel G. Riggs
			Executive Vice President and Chief
			Operating Officer


Date:	August 5, 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 July 20, 2005, among Clayton Williams Energy, Inc., the Subsidiary Guarantors and Wells Fargo Bank, National Association, as Trustee, filed as Exhibit 4.1 to our Current Report on Form 8-K filed with the Commission on July 22, 2005††

**4	.2	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	.3	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	.4	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††

*10	.1	Second Amendment to Second Amended and Restated Credit Agreement dated May 17, 2011

**10	.2†	Amended and Restated Employment Agreement between Clayton Williams Energy, Inc. and Mel G. Riggs, effective as of June 1, 2011, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on June 7, 2011††

**10.	3†	Amended and Restated Employment Agreement between Clayton Williams Energy, Inc. and Michael L. Pollard, effective as of June 1, 2011, filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K filed with the Commission on June 7, 2011††

**10.	4†	Employment Agreement between Clayton Williams Energy, Inc. and Robert L. Thomas, effective as of June 1, 2011, filed as Exhibit 10.3 to the Company’s Current Report on Form 8-K filed with the Commission on June 7, 2011††

**10.	5†	CWEI Andrews Fee Reward Plan II dated June 28, 2011, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on June 30, 2011††

**10.	6†	CWEI Andrews University Reward Plan dated June 28, 2011, filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K filed with the Commission on June 30, 2011††

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**10	.7†	CWEI Austin Chalk Reward Plan III dated June 28, 2011, filed as Exhibit 10.3 to the Company’s Current Report on Form 8-K filed with the Commission on June 30, 2011††

**10	.8†	CWEI Delaware Basin Reward Plan dated June 28, 2011, filed as Exhibit 10.4 to the Company’s Current Report on Form 8-K filed with the Commission on June 30, 2011††

**10	.9†	CWEI Andrews Samson Reward Plan II dated June 28, 2011, filed as Exhibit 10.5 to the Company’s Current Report on Form 8-K filed with the Commission on June 30, 2011††

**10	.10†	CWEI South Louisiana Reward Plan dated June 28, 2011, filed as Exhibit 10.6 to the Company’s Current Report on Form 8-K filed with the Commission on June 30, 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