- 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, 2010

¨	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		¨ 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).
	¨ 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 12,145,536 shares of Common Stock, $.10 par value, of the registrant outstanding as of August 9, 2010.

CLAYTON WILLIAMS ENERGY, INC.

TABLE OF CONTENTS

PART I. FINANCIAL INFORMATION
		Page

Item 1.	Financial Statements

	Consolidated Balance Sheets as of June 30, 2010
	and December 31, 2009	3

	Consolidated Statements of Operations for the three months and six months
	ended June 30, 2010 and 2009	5

	Consolidated Statement of Stockholders’ Equity for the six months
	ended June 30, 2010	6

	Consolidated Statements of Cash Flows for the six months
	ended June 30, 2010 and 2009	7

	Notes to Consolidated Financial Statements	8

Item 2.	Management’s Discussion and Analysis of Financial
	Condition and Results of Operations	23

Item 3.	Quantitative and Qualitative Disclosures About Market Risks	38

Item 4.	Controls and Procedures	40


PART II. OTHER INFORMATION
Item 1A.	Risk Factors	41

Item 6.	Exhibits	42

	Signatures	43

PART I. FINANCIAL INFORMATION

Item 1 - Financial Statements

CLAYTON WILLIAMS ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

ASSETS
	June 30,			December 31,
	2010			2009
	(Unaudited)
CURRENT ASSETS
Cash and cash equivalents	$	10,375		$	14,013
Accounts receivable:
Oil and gas sales		25,861			28,721
Joint interest and other, net		4,281			6,669
Affiliates		638			624
Inventory		40,488			43,068
Deferred income taxes		817			1,362
Fair value of derivatives		16,264			-
Assets held for sale		7,411			7,411
Prepaids and other		4,555			1,729
		110,690			103,597
PROPERTY AND EQUIPMENT
Oil and gas properties, successful efforts method		1,565,365			1,579,664
Natural gas gathering and processing systems		18,399			17,816
Contract drilling equipment		48,348			41,533
Other		17,761			16,550
		1,649,873			1,655,563
Less accumulated depreciation, depletion and amortization		(979,985	)		(985,517	)
Property and equipment, net		669,888			670,046

OTHER ASSETS
Debt issue costs, net		4,592			4,874
Fair value of derivatives		8,128			4,427
Other		1,768			1,660
		14,488			10,961
	$	795,066		$	784,604

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

CLAYTON WILLIAMS ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

LIABILITIES AND STOCKHOLDERS’ EQUITY
	June 30,		December 31,
	2010		2009
	(Unaudited)
CURRENT LIABILITIES
Accounts payable:
Trade	$	53,415	$	47,211
Oil and gas sales		15,746		18,063
Affiliates		1,055		1,097
Fair value of derivatives		-		5,907
Accrued liabilities and other		15,629		11,995
		85,845		84,273
NON-CURRENT LIABILITIES
Long-term debt		356,000		395,000
Deferred income taxes		70,306		54,065
Other		40,002		38,991
		466,308		488,056
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 – 12,145,536 shares in 2010
and 2009		1,215		1,215
Additional paid-in capital		152,051		152,051
Retained earnings		89,647		59,009
		242,913		212,275
	$	795,066	$	784,604

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

CLAYTON WILLIAMS ENERGY, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(In thousands, except per share)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2010			2009			2010			2009
REVENUES
Oil and gas sales	$	76,918		$	57,206		$	155,960		$	108,002
Natural gas services		452			1,355			955			2,939
Drilling rig services		-			1,462			-			6,681
Gain on sales of assets		113			480			399			663
Total revenues		77,483			60,503			157,314			118,285

COSTS AND EXPENSES
Production		20,567			18,296			41,494			37,359
Exploration:
Abandonments and impairments		2,891			4,505			5,769			16,917
Seismic and other		974			1,388			2,634			5,658
Natural gas services		306			1,211			654			2,622
Drilling rig services		419			2,911			1,081			9,997
Depreciation, depletion and amortization		25,437			26,186			51,049			62,651
Impairment of property and equipment		11,114			32,068			11,114			32,068
Accretion of abandonment obligations		647			748			1,294			1,466
General and administrative		7,832			6,256			14,056			10,784
Loss on sales of assets and impairment
of inventory		1,443			396			1,443			3,845
Total costs and expenses		71,630			93,965			130,588			183,367

Operating income (loss)		5,853			(33,462	)		26,726			(65,082	)

OTHER INCOME (EXPENSE)
Interest expense		(6,244	)		(5,736	)		(12,353	)		(11,174	)
Gain (loss) on derivatives		20,983			(21,770	)		31,284			(19,260	)
Other		1,016			826			1,844			1,727
Total other income (expense)		15,755			(26,680	)		20,775			(28,707	)

Income (loss) before income taxes		21,608			(60,142	)		47,501			(93,789	)
Income tax (expense) benefit		(7,645	)		21,943			(16,863	)		34,321
NET INCOME (LOSS)		13,963			(38,199	)		30,638			(59,468	)
Less income attributable to
noncontrolling interest, net of tax		-			(409	)		-			(1,455	)

NET INCOME (LOSS) attributable to Clayton
Williams Energy, Inc.	$	13,963		$	(38,608	)	$	30,638		$	(60,923	)

Net income (loss) per common share attributable to
Clayton Williams Energy, Inc. stockholders:
Basic	$	1.15		$	(3.18	)	$	2.52		$	(5.02	)
Diluted	$	1.15		$	(3.18	)	$	2.52		$	(5.02	)

Weighted average common shares outstanding:
Basic		12,146			12,142			12,146			12,132
Diluted		12,146			12,142			12,146			12,132

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

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, 2009		12,146	$	1,215	$	152,051	$	59,009
Net income		-		-		-		30,638
BALANCE,
June 30, 2010		12,146	$	1,215	$	152,051	$	89,647

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

CLAYTON WILLIAMS ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In thousands)

	Six Months Ended
	June 30,
	2010			2009
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	30,638		$	(59,468	)
Adjustments to reconcile net income (loss) to cash
provided by operating activities:
Depreciation, depletion and amortization		51,049			62,651
Impairment of property and equipment		11,114			32,068
Exploration costs		5,769			16,917
Loss on sales of assets and impairment of inventory, net		1,044			3,182
Deferred income tax expense (benefit)		16,863			(34,321	)
Non-cash employee compensation		5,079			627
Unrealized (gain) loss on derivatives		(25,871	)		18,907
Amortization of debt issue costs		774			624
Accretion of abandonment obligations		1,294			1,466

Changes in operating working capital:
Accounts receivable		5,234			10,579
Accounts payable		(3,403	)		(16,626	)
Other		(2,907	)		3,264
Net cash provided by operating activities		96,677			39,870

CASH FLOWS FROM INVESTING ACTIVITIES
Additions to property and equipment		(135,528	)		(69,082	)
Proceeds from sales of assets		73,011			670
Change in equipment inventory		1,300			(12,594	)
Other		(98	)		(97	)
Net cash used in investing activities		(61,315	)		(81,103	)

CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt		-			25,200
Repayments of long-term debt		(39,000	)		(9,375	)
Proceeds from exercise of stock options		-			152
Net cash provided by (used in) financing activities		(39,000	)		15,977

NET DECREASE IN CASH AND CASH EQUIVALENTS		(3,638	)		(25,256	)

CASH AND CASH EQUIVALENTS
Beginning of period		14,013			41,199
End of period	$	10,375		$	15,943

SUPPLEMENTAL DISCLOSURES
Cash paid for interest, net of amounts capitalized	$	11,735		$	11,354

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

CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2010

(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 demand for petroleum products, foreign supply of oil and gas, the establishment of and compliance with production quotas by oil exporting countries, trading activities in commodities futures markets, the strength of the U.S. dollar, weather conditions, the price and availability of alternative fuels, and overall economic conditions, both foreign and domestic.

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, 2010 and for the interim periods ended June 30, 2010 and 2009 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, 2010.

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, 2009.

Adopted Accounting Pronouncement

In June 2009, the FASB issued accounting guidance on the consolidation of variable interest entities (“VIEs”). This new guidance revises previous guidance by replacing the quantitative-based risks and rewards calculation for determining which enterprise, if any, has a controlling financial interest in a VIE with a qualitative approach focused on identifying which enterprise has both the power to direct the activities of the VIE that most significantly impacts the entity’s economic performance and has the obligation to absorb losses or the right to receive benefits that could be significant to the entity. In addition, this guidance requires reconsideration of whether an entity is a VIE when any changes in facts and circumstances occur such that the holders of the equity investment at risk, as a group, lose the power from voting rights or similar rights of those investments to direct the activities of the entity that most significantly impact the entity’s economic performance. It also requires ongoing assessments of whether an enterprise is the primary beneficiary of a VIE and additional disclosures about an enterprise’s involvement in variable interest entities. This guidance is effective for fiscal years beginning after November 15, 2009. Our adoption of the new guidance during the first quarter of 2010 did not have a material effect on our consolidated financial statements.

3.	Long-Term Debt

Long-term debt consists of the following:

	June 30,		December 31,
	2010		2009
	(In thousands)
7¾% Senior Notes due 2013	$	225,000	$	225,000
Secured bank credit facility, due May 2012		131,000		170,000
	$	356,000	$	395,000

7¾% Senior Notes due 2013

In July 2005, we issued $225 million of aggregate principal amount of 7¾% Senior Notes due 2013 (“Senior Notes”). The 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.

We may redeem some or all of the Senior Notes at redemption prices (expressed as percentages of principal amount) equal to 101.938% for the twelve-month period beginning on August 1, 2010, and 100% beginning on August 1, 2011 or for any period thereafter, in each case plus accrued and unpaid interest.

The Indenture 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 Indenture) exceeds 2.5 to 1 for the four most recently completed fiscal quarters. However, this restriction does not prevent us from borrowing funds under the revolving credit facility provided that our outstanding balance on the facility does not exceed the greater of $150 million and 30% of Adjusted Consolidated Net Tangible Assets (as defined in the Indenture). These covenants are subject to a number of important exceptions and qualifications as described in the Indenture. We were in compliance with these covenants at June 30, 2010.

Secured Bank Credit Facility

We have a revolving credit facility with a syndicate of banks based on a borrowing base determined by the banks. The borrowing base, which is based, in part, on the discounted present value of future net revenues 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) pledge additional collateral, (2) prepay the principal amount of the loans in an amount sufficient to eliminate the excess, or (3) prepay the excess in six equal monthly installments. In April 2010, the borrowing base was increased by the banks from $250 million to $300 million. After allowing for an outstanding letter of credit totaling $25,000, we had $169 million available under the credit facility at June 30, 2010.

The revolving credit facility is collateralized by substantially all of our assets, including at least 80% 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, interest under the revolving credit facility is determined by reference to (1) LIBOR plus an applicable margin between 2% and 3% per annum or (2) the greatest of (A) the prime rate, (B) the federal funds rate plus .5% or (C) one-month LIBOR plus 1% plus, in any of (A), (B) or (C), an applicable margin between 1.125% and 2.125% per annum. We also pay a commitment fee on the unused portion of the revolving credit facility equal to .5%. Interest and fees are payable quarterly, except that interest on LIBOR-based tranches are due at maturity of each tranche but no less frequently 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, 2010 was 3%.

The revolving credit facility contains financial covenants that are computed quarterly. One financial covenant requires us to 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 3.5 to 1 for any fiscal quarter ending on or prior to December 31, 2010, 3.25 to 1 for any fiscal quarter ending on or after March 31, 2011 through December 31, 2011, and 3 to 1 for any fiscal quarter thereafter. The computations of 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, 2010.

4.	Other Non-Current Liabilities

Other non-current liabilities consist of the following:

	June 30,		December 31,
	2010		2009
	(In thousands)
Abandonment obligations	$	39,266	$	38,412
Other		736		579
	$	40,002	$	38,991

Changes in abandonment obligations for the six months ended June 30, 2010 and 2009 are as follows:

	Six Months Ended
	June 30,
	2010			2009
	(In thousands)
Beginning of period	$	38,412		$	31,737
Additional abandonment obligations from new properties		993			945
Sales or abandonments of properties		(1,113	)		(47	)
Revisions of previous estimates		(320	)		2,219
Accretion expense		1,294			1,466
End of period	$	39,266		$	36,320

5.	Compensation Plans

Stock-Based Compensation

We presently have options outstanding under a stock option plan for independent directors covering 24,000 shares of common stock. As of June 30, 2010, the options had a weighted average exercise price of $26.66 per share (ranging from $12.14 per share to $41.74 per share), a weighted average remaining contractual term of 4 years, and an aggregate intrinsic value of $371,040 (based on a market price at June 30, 2010 of $42.12 per share). No options were granted during the six months ended June 30, 2010 or 2009, and options to purchase 27,638 shares of common stock were exercised during the six months ended June 30, 2009 (intrinsic value - $541,772).

Non-Equity Award Plans

The Compensation Committee of the Board of Directors has adopted an after-payout (“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 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 authorized the formation of 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 four specified areas, each of which established a quarterly bonus amount equal to 7% 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 August 1, 2008. Under these four awards, 100% of the quarterly bonus amount is payable on a current basis to the participants, and the full vesting dates for future amounts payable under the plan for three of the awards is May 5, 2013 and under one award is November 4, 2011.

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

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

We recognize compensation expense related to the APO Partnerships based on the estimated fair value of the economic interests conveyed to the participants, based upon Level 3 inputs. Estimated compensation expense applicable to the APO Reward Plan and SWR Reward Plan is recognized over the vesting periods, which range from

two years to five years. We recorded compensation expense of $5.1 million for the six months ended June 30, 2010 and $2 million for the six months ended June 30, 2009 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, 2010. The settlement prices of commodity derivatives are based on NYMEX futures prices.

Swaps:

	Oil				Gas
	Bbls		Price		MMBtu (a)		Price
Production Period:
3rd Quarter 2010		522,000	$	76.40		1,750,000	$	6.80
4th Quarter 2010		480,000	$	76.24		1,680,000	$	6.80
2011		1,656,000	$	84.38		6,420,000	$	7.07
		2,658,000				9,850,000

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

In March 2009, we terminated certain fixed-priced oil swaps covering 157,000 barrels at a price of $57.35 from July 2010 through December 2010, resulting in an aggregate loss of approximately $636,000, which will be paid to the counterparty monthly as the applicable contracts are settled.

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. We report our fair value of derivatives as either a net current asset or liability or a net non-current asset or liability in our consolidated balance sheets. Cash flow is only impacted to the extent the actual derivative contract is settled by making or receiving a payment to or from the counterparty. 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. For the six months ended June 30, 2009, the Company reported a $19.3 million net loss on derivatives, consisting of an $18.9 million loss related to changes in mark-to-market valuations and a $353,000 realized loss for settled contracts.

Effect of Derivative Instruments on the Consolidated Balance Sheets

	Fair Value of Derivative Instruments as of June 30, 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	$ 16,264	Current	$ -
	Non-current	8,128	Non-current	-
Total		$ 24,392		$ -

	Fair Value of Derivative Instruments as of December 31, 2009
	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	$ 5,907
	Non-current	4,427	Non-current	-
Total		$ 4,427		$ 5,907

Gross to Net Presentation Reconciliation of Derivative Assets and Liabilities

	June 30, 2010
	Assets			Liabilities
	(In thousands)
Fair value of derivatives – gross presentation	$	31,703		$	7,311
Effects of netting arrangements		(7,311	)		(7,311	)
Fair value of derivatives – net presentation	$	24,392		$	-

	December 31, 2009
	Assets			Liabilities
	(In thousands)
Fair value of derivatives – gross presentation	$	20,105		$	21,585
Effects of netting arrangements		(15,678	)		(15,678	)
Fair value of derivatives – net presentation	$	4,427		$	5,907

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

Effect of Derivative Instruments on the Consolidated Statements of Operations

	Amount of Gain or (Loss) Recognized in Earnings
		Six Months Ended
	Location of Gain or (Loss)	June 30,
	Recognized in Earnings	2010	2009
		(In thousands)
Derivatives not designated as
hedging instruments:

Commodity derivatives	Other income (expense) -
	Gain (loss) on derivatives	$ 31,284	$ (19,260)
Total		$ 31,284	$ (19,260)

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 secured bank credit facility was estimated to have a fair value approximating the carrying amount since the interest rate is generally market sensitive. The estimated fair value of our Senior Notes at June 30, 2010 and December 31, 2009 was approximately $219.9 million and $198 million respectively, based on market valuations.

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

Level 1 -

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

Level 2 -

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

Level 3 -

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

The only financial assets and liabilities measured on a recurring basis at June 30, 2010 and December 31, 2009 were commodity derivatives. Information regarding these assets and liabilities is summarized below:

	June 30,		December 31,
	2010		2009
	Significant Other		Significant Other
	Observable Inputs		Observable Inputs
Description	(Level 2)		(Level 2)
	(In thousands)
Assets:
Fair value of commodity derivatives	$	24,392	$	4,427
Total assets	$	24,392	$	4,427

Liabilities:
Fair value of commodity derivatives	$	-	$	5,907
Total liabilities	$	-	$	5,907

8.	Income Taxes

Our effective federal and state income tax expense rate for the six months ended June 30, 2010 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 2005 currently remain subject to examination by appropriate taxing authorities. None of our income tax returns are under examination at this time.

9.	Desta Drilling

We formed a joint venture in 2006 with Lariat Services, Inc. (“Lariat”) to construct, own and operate 12 new drilling rigs. Initially, we referred to this joint venture as Larclay JV, but in June 2009, we changed the legal name of the operating entity in the joint venture to Desta Drilling, LP (“Desta Drilling”). In order to assure the availability of drilling rigs for our exploration and development activities, we provided credit support to permit Desta Drilling to finance the construction of the 12 drilling rigs and related equipment, consisting of (1) a subordinated loan of $4.6 million to finance excess construction costs, (2) a limited guaranty to the secured lender in the original amount of $19.5 million, and (3) a drilling contract that expired in 2009 under which we were obligated to use the drilling rigs or pay idle rig rates. During the term of the drilling contract, we paid Desta Drilling $24.4 million in idle rig fees. We and Lariat also made cash advances to Desta Drilling in the form of subordinated loans of $7.5 million each to provide additional financial support. Lariat was designated as the operator of the rigs and provided all management services on behalf of Desta Drilling.

Initially, we and Lariat each owned a 50% equity interest in Desta Drilling, but effective April 15, 2009, we entered into an agreement with Lariat whereby Lariat assigned to us their 50% equity interest (the “Assignment”). The Assignment from Lariat also included all of Lariat’s right, title and interest in the subordinated loans previously made by Lariat to Desta Drilling. As consideration for the Assignment, CWEI assumed all of the obligations and liabilities of Lariat relating to Desta Drilling from and after the effective date, including Lariat’s obligations as operator of Desta Drilling’s rigs. Upon consummation of the Assignment, CWEI contributed all of the subordinated loans to Desta Drilling’s capital. In August 2009, we repaid in full all amounts outstanding under the secured term loan of Desta Drilling with borrowings of approximately $27.2 million under our revolving credit facility. All of the assets of Desta Drilling were pledged as collateral under our revolving credit facility.

Upon consummation of the Assignment, we adopted a plan of disposition whereby we committed to sell eight of the 12 drilling rigs owned by Desta Drilling. The plan of disposition met the criteria under applicable accounting standards for the designated assets to be classified as held for sale. We are required to value the designated assets at the lower of their carrying value or fair value, less cost to sell, as of the date the plan of disposition was adopted. To estimate the fair value of the drilling rigs and related equipment owned by Desta Drilling on the measurement date of April 15, 2009, we used a weighting of the market approach and the discounted cash flow approach. Level 3 inputs used in the determination of discounted cash flow included estimated rig utilization rates, gross profits from drilling operations, future capital costs required for equipment replacements, useful lives for the equipment and discount rates. We weighted the values obtained through the market approach by 67% and the values obtained through the discounted cash flow approach by 33% to give greater emphasis to the lack of demand for drilling equipment on the measurement date. We estimated the fair value of the designated assets to be approximately $18.8 million and recorded a related charge for impairment of property and equipment of approximately $32.1 million in our statement of operations during the second quarter of 2009. Under applicable accounting standards, this plan of disposition did not qualify for discontinued operations reporting.

In December 2009, we modified the prior plan of disposition established in April 2009. Based on improved oil prices, we escalated our developmental drilling program and put six of the drilling rigs previously held for sale back to work and transferred their estimated fair value of $11.4 million to property and equipment. Assets held for sale at June 30, 2010 and December 31, 2009 consist of the remaining two 2,000 horsepower drilling rigs at a combined estimated fair value of $7.4 million.

10.	Purchases and Sales of Assets and Impairments of Inventory

Net gains and losses on sales of assets and impairments of inventory for the six months ended June 30, 2010 and June 30, 2009 are as follows:

	Six Months Ended
	June 30,
	2010			2009
	(In thousands)

Gain on sales of assets	$	399		$	663

Loss on sales of assets and impairment
of inventory:
Loss on sales of assets		(1,443	)		(455	)
Impairment of inventory		-			(3,390	)
		(1,443	)		(3,845	)

Net loss	$	(1,044	)	$	(3,182	)

In June 2010, we sold our interests in 22 operated and 76 non-operated producing wells in North Louisiana for net proceeds of $73.1 million, after giving effect to customary closing adjustments and the allocation of approximately $2 million of proceeds to applicable APO Partnerships (see Note 5), resulting in a loss on the sale of approximately $1.4 million during the second quarter of 2010. Proceeds from the sale were used to repay indebtedness under our revolving credit facility. The assets that were sold in this transaction represented substantially all of our proved oil and gas properties in North Louisiana but did not meet the criteria for treatment as discontinued operations under applicable accounting standards.

Also in June 2010, we acquired from a group of private investors an undivided 14% working interest in 36 Wolfberry operated wells in Andrews County, Texas for $9.6 million, after customary closing adjustments. This purchase increased our working interest in these 36 wells to 100%. In addition to the oil and gas reserves attributable to the acquired interests, the Company increased its stake in approximately 5,700 gross acres under lease in this area from 86% to 100%.

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. In 2009, we recorded a $3.4 million non-cash impairment of inventory to reduce the carrying cost to its fair market value at June 30, 2009.

11.	Oil and Gas Properties

The following sets forth the capitalized costs for oil and gas properties as of June 30, 2010 and December 31, 2009.

	June 30,			December 31,
	2010			2009
	(In thousands)
Proved properties	$	1,531,514		$	1,532,508
Unproved properties		33,851			47,156
Total capitalized costs		1,565,365			1,579,664
Accumulated depreciation, depletion and amortization		(934,343	)		(945,047	)
Net capitalized costs	$	631,022		$	634,617

12.	Impairment of Property and Equipment

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 $5.5 million in 2010 and $15 million in 2009, respectively, and charged these impairments to exploration costs in the accompanying statements of operations.

We also recorded an impairment of proved properties of $11.1 million relating to a non-core area in the Permian Basin to reduce the carrying value of those properties to their estimated fair value at June 30, 2010.

In the second quarter of 2009, we recorded a charge for impairment of property and equipment of approximately $32.1 million in our statement of operations related to a plan of disposition to sell eight of the twelve drilling rigs operated by Desta Drilling (see Note 9).

13.	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, 2010 and 2009.

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

Net income (loss) attributable to
Clayton Williams Energy, Inc	$	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

Net income (loss) attributable to
Clayton Williams Energy, Inc	$	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

For the Three Months Ended
June 30, 2009
(Unaudited)				Contract			Intercompany			Consolidated
(In thousands)	Oil and Gas			Drilling			Eliminations			Total

Revenues	$	59,042		$	8,327		$	(6,866	)	$	60,503
Depreciation, depletion and amortization (a)		25,881			33,284			(911	)		58,254
Other operating expenses (b)		40,417			1,197			(5,903	)		35,711
Interest expense		5,388			348			-			5,736
Other (income) expense		20,944			-			-			20,944
Income (loss) before income taxes		(33,588	)		(26,502	)		(52	)		(60,142	)

Income tax (expense) benefit		12,669			9,274			-			21,943
Net income (loss)		(20,919	)		(17,228	)		(52	)		(38,199	)
Less income attributable to
noncontrolling interest, net of tax		-			(409	)		-			(409	)

Net income (loss) attributable to
Clayton Williams Energy, Inc	$	(20,919	)	$	(17,637	)	$	(52	)	$	(38,608	)

Total assets	$	816,564		$	44,709		$	-		$	861,273
Additions to property and equipment	$	20,358		$	2,190		$	-		$	22,548

For the Six Months Ended
June 30, 2009
(Unaudited)				Contract			Intercompany			Consolidated
(In thousands)	Oil and Gas			Drilling			Eliminations			Total

Revenues	$	111,604		$	17,513		$	(10,832	)	$	118,285
Depreciation, depletion and amortization (a)		60,872			36,022			(2,175	)		94,719
Other operating expenses (b)		93,300			3,890			(8,542	)		88,648
Interest expense		10,293			881			-			11,174
Other (income) expense		17,533			-			-			17,533
Income (loss) before income taxes		(70,394	)		(23,280	)		(115	)		(93,789	)

Income tax (expense) benefit		26,179			8,142			-			34,321
Net income (loss)		(44,215	)		(15,138	)		(115	)		(59,468	)
Less income attributable to
noncontrolling interest, net of tax		-			(1,455	)		-			(1,455	)

Net income (loss) attributable to
Clayton Williams Energy, Inc	$	(44,215	)	$	(16,593	)	$	(115	)	$	(60,923	)

Total assets	$	816,564		$	44,709		$	-		$	861,273
Additions to property and equipment	$	55,047		$	2,190		$	-		$	57,237

(a) Includes impairment of property and equipment.

(b)

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

14.	Guarantor Financial Information

In July 2005, CWEI (“Issuer”) issued $225 million of Senior Notes (see Note 3). All of the Issuer’s wholly-owned and active subsidiaries which have jointly and severally, irrevocably and unconditionally guaranteed the performance and payment when due of all obligations under the Senior Notes are referred to as “Guarantor Subsidiaries” in the following condensed consolidating financial statements. Prior to August 2009, neither Desta Drilling nor WCEP, LLC, the general partner of West Coast Energy Properties, L.P., an affiliated limited partnership, were guarantors of the Senior Notes, but in August 2009, Desta Drilling became a guarantor of the Senior Notes. As a result, we have reclassified the condensed consolidating financial statements for the three months and six months ended June 30, 2009 in this Note 14 to include the accounts of Desta Drilling in the Guarantor Subsidiaries column and to reflect only the accounts of WCEP, LLC in the Non-Guarantor Subsidiary column.

The financial information which follows sets forth our condensed consolidating financial statements as of and for the periods indicated.

Condensed Consolidating Balance Sheet

June 30, 2010

(Unaudited)					Non-
(Dollars in thousands)			Guarantor		Guarantor		Adjustments/
	Issuer		Subsidiaries		Subsidiary		Eliminations			Consolidated

Current assets	$	188,916	$	143,566	$	1,161	$	(222,953	)	$	110,690
Property and equipment, net		329,526		334,144		6,218		-			669,888
Investments in subsidiaries		113,235		-		-		(113,235	)		-
Other assets		14,353		135		-		-			14,488
Total assets	$	646,030	$	477,845	$	7,379	$	(336,188	)	$	795,066

Current liabilities	$	155,912	$	152,713	$	173	$	(222,953	)	$	85,845
Non-current liabilities:
Long-term debt		356,000		-		-		-			356,000
Other		47,817		62,353		141		(3	)		110,308
		403,817		62,353		141		(3	)		466,308

Stockholders’ equity		86,301		262,779		7,065		(113,232	)		242,913

Total liabilities and
stockholders’ equity	$	646,030	$	477,845	$	7,379	$	(336,188	)	$	795,066

Condensed Consolidating Balance Sheet

December 31, 2009

(Dollars in thousands)					Non-
			Guarantor		Guarantor		Adjustments/
	Issuer		Subsidiaries		Subsidiary		Eliminations			Consolidated

Current assets	$	205,950	$	146,443	$	920	$	(249,716	)	$	103,597
Property and equipment, net		326,149		337,566		6,331		-			670,046
Investments in subsidiaries		112,018		-		-		(112,018	)		-
Other assets		10,348		613		-		-			10,961
Total assets	$	654,465	$	484,622	$	7,251	$	(361,734	)	$	784,604

Current liabilities	$	153,505	$	180,357	$	127	$	(249,716	)	$	84,273
Non-current liabilities:
Long-term debt		395,000		-		-		-			395,000
Other		31,039		61,883		136		(2	)		93,056
		426,039		61,883		136		(2	)		488,056

Stockholders’ equity		74,921		242,382		6,988		(112,016	)		212,275

Total liabilities and
stockholders' equity	$	654,465	$	484,622	$	7,251	$	(361,734	)	$	784,604

Condensed Consolidating Statement of Operations

Three Months Ended June 30, 2010

(Unaudited)						Non-
(In thousands)				Guarantor		Guarantor		Adjustments/
	Issuer			Subsidiaries		Subsidiary		Eliminations			Consolidated
Total revenue	$	46,973		$	30,516	$	174	$	(180	)	$	77,483
Costs and expenses		50,062			21,604		144		(180	)		71,630
Operating income (loss)		(3,089	)		8,912		30		-			5,853
Other income (expense)		14,148			1,573		34		-			15,755
Income tax (expense) benefit		(7,645	)		-		-		-			(7,645	)

Net income (loss)	$	3,414		$	10,485	$	64	$	-		$	13,963

Condensed Consolidating Statement of Operations

Six Months Ended June 30, 2010

(Unaudited)						Non-
(In thousands)				Guarantor		Guarantor		Adjustments/
	Issuer			Subsidiaries		Subsidiary		Eliminations			Consolidated
Total revenue	$	94,989		$	62,316	$	353	$	(344	)	$	157,314
Costs and expenses		88,119			42,487		326		(344	)		130,588
Operating income (loss)		6,870			19,829		27		-			26,726
Other income (expense)		17,711			2,994		70		-			20,775
Income tax (expense) benefit		(16,863	)		-		-		-			(16,863	)

Net income (loss)	$	7,718		$	22,823	$	97	$	-		$	30,638

Condensed Consolidating Statement of Operations

Three Months Ended June 30, 2009

(Unaudited)							Non-
(In thousands)				Guarantor			Guarantor			Adjustments/
	Issuer			Subsidiaries			Subsidiary			Eliminations			Consolidated
Total revenue	$	34,094		$	33,380		$	147		$	(7,118	)	$	60,503
Costs and expenses		46,624			54,011			397			(7,067	)		93,965
Operating income (loss)		(12,530	)		(20,631	)		(250	)		(51	)		(33,462	)
Other income (expense)		(27,770	)		1,052			38			-			(26,680	)
Income tax (expense) benefit		21,943			-			-			-			21,943
Noncontrolling interest,
net of tax		(409	)		-			-			-			(409	)

Net income (loss)	$	(18,766	)	$	(19,579	)	$	(212	)	$	(51	)	$	(38,608	)

Condensed Consolidating Statement of Operations

Six Months Ended June 30, 2009

(Unaudited)							Non-
(In thousands)				Guarantor			Guarantor			Adjustments/
	Issuer			Subsidiaries			Subsidiary			Eliminations			Consolidated
Total revenue	$	67,633		$	61,745		$	267		$	(11,360	)	$	118,285
Costs and expenses		110,443			83,554			615			(11,245	)		183,367
Operating income (loss)		(42,810	)		(21,809	)		(348	)		(115	)		(65,082	)
Other income (expense)		(30,669	)		1,888			74			-			(28,707	)
Income tax (expense) benefit		34,321			-			-			-			34,321
Noncontrolling interest,
net of tax		(1,455	)		-			-			-			(1,455	)

Net income (loss)	$	(40,613	)	$	(19,921	)	$	(274	)	$	(115	)	$	(60,923	)

Condensed Consolidating Statement of Cash Flows

Six Months Ended June 30, 2010

(Unaudited)							Non-
(In thousands)				Guarantor			Guarantor			Adjustments/
	Issuer			Subsidiaries			Subsidiary			Eliminations			Consolidated
Operating activities	$	47,044		$	45,919		$	187		$	3,527		$	96,677
Investing activities		(40,269	)		(17,471	)		(48	)		(3,527	)		(61,315	)
Financing activities		(10,491	)		(28,554	)		45			-			(39,000	)
Net increase (decrease) in
cash and cash equivalents		(3,716	)		(106	)		184			-			(3,638	)

Cash at the beginning of
the period		11,839			1,344			830			-			14,013

Cash at end of the period	$	8,123		$	1,238		$	1,014		$	-		$	10,375

Condensed Consolidating Statement of Cash Flows

Six Months Ended June 30, 2009

(Unaudited)							Non-
(In thousands)				Guarantor			Guarantor			Adjustments/
	Issuer			Subsidiaries			Subsidiary			Eliminations			Consolidated
Operating activities	$	47,424		$	(9,871	)	$	167		$	2,150		$	39,870
Investing activities		(106,413	)		27,505			(45	)		(2,150	)		(81,103	)
Financing activities		33,188			(17,211	)		-			-			15,977
Net increase (decrease) in
cash and cash equivalents		(25,801	)		423			122			-			(25,256	)

Cash at the beginning of
the period		35,381			5,054			764			-			41,199

Cash at end of the period	$	9,580		$	5,477		$	886		$	-		$	15,943

15.	Subsequent Events

We have evaluated events and transactions that occurred after the balance sheet date of June 30, 2010. We did not have any subsequent events that would require recognition in the financial statements or disclosures in these notes to the consolidated financial statements.

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, 2009. 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 or may occur in the future are forward-looking statements. These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events. 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, 2009 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, many of which are beyond our control, incident to the exploration for and development, production and marketing of oil and gas. These risks include, but are not limited to:

• the possibility of unsuccessful exploration and development drilling activities;

• our ability to replace and sustain production;

•

commodity price volatility;

•

domestic and worldwide economic conditions;

•

the availability of capital on economic terms to fund our capital expenditures and acquisitions;

•

our level of indebtedness;

•

the impact of the current economic recession on our business operations, financial condition and ability to raise capital;

•

declines in the value of our oil and gas properties resulting in a decrease in our borrowing base under our credit facility and impairments;

•

the ability of financial counterparties to perform or fulfill their obligations under existing agreements;

•

the uncertainty inherent in estimating proved oil and gas reserves and in projecting future rates of production and timing of development expenditures;

•

drilling and other operating risks;

•

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, 2009 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.

Should one or more of the risks or uncertainties described above or elsewhere in our Form 10-K for the year ended December 31, 2009 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. 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.

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

Overview

We are an independent oil and natural gas exploration, development, acquisition, and production company. Our basic business model is to increase shareholder value by finding and developing oil and gas reserves through exploration and development activities, and selling the production from those reserves at a profit. To be successful, we must, over time, be able to find oil and gas reserves and then sell the resulting production at a price that is sufficient to cover our finding costs, operating expenses, administrative costs and interest expense, plus offer us a return on our capital investment. From time to time, we may also acquire producing properties if we believe the acquired assets offer us the potential for reserve growth through additional developmental or exploratory drilling activities.

For most of 2008, the oil and gas industry was strong, with oil and gas prices and drilling activities at high levels. In 2009, the business environment was drastically altered due to the global financial crisis that escalated in the second half of 2008. In response to the negative effects of the recession on our operational model, we suspended our developmental drilling program in the Permian Basin and in the Austin Chalk (Trend) in late 2008 and turned our business focus toward preserving short-term liquidity and conserving capital resources. By the end of the second quarter of 2009, operating margins on oil-prone properties had begun to improve somewhat due to a combination of higher oil prices and lower costs of field services caused by decreased demand for those services. Since most of our developmental drilling locations are oil-prone, we elected to resume drilling developmental oil wells primarily in Andrews County, Texas in the Permian Basin and Burleson and Robertson Counties, Texas in the Austin Chalk (Trend). In connection with the return to drilling activities in these areas, we have taken the following actions which we believe will enhance the development of these core areas:

•	Entered into agreements with selected service providers to fix unit costs covering approximately 90% of the drilling and completion services provided by third parties through the second quarter of 2011;

•	Improved drilling efficiencies by acquiring the noncontrolling interest in Desta Drilling, giving us full control over the management and operation of drilling services;

•	Purchased casing and tubing for more than 175 wells at discounts to then-current market prices; and

•	Entered into derivative contracts for most of our estimated proved developed oil production for 2010 and 2011 at average prices of $76.50 and $84.38 per barrel, respectively.

We currently plan to spend approximately $315.4 million on exploration and development activities in fiscal 2010. By comparison, we spent $138.3 million in fiscal 2009 on exploration and development activities. We continue to evaluate and manage our portfolio of assets and monitor the extent to which changes in commodity prices could affect our financial liquidity. We believe we are taking appropriate actions to position our business for long-term growth and sustainability.

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 2010 and the outlook for the remainder of 2010.

•	Our oil and gas sales for the second quarter increased $19.7 million, or 34%, from 2009 due substantially to increases in prices for both oil and gas.

•	Our oil and gas production for the second quarter of 2010 was 6% lower on a barrel of oil equivalent (“BOE”) basis than in the comparable period in 2009. Our oil production increased 13% compared to the second quarter of 2009 while gas production declined 27%.

•

We recorded a $21 million net gain on derivatives in the second quarter of 2010, 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. For the same period in 2009, we reported a $21.8 million net loss on derivatives consisting of a $20.3 million loss for changes in mark-to-market valuations and a $1.5 million realized loss 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.

•	We recorded a non-cash charge of $11.1 million for impairment of property and equipment to reduce the carrying value of certain non-core oil and gas properties in the Permian Basin to their estimated fair market value at June 30, 2010.

•	During the second quarter of 2010, we decreased borrowings under our revolving credit facility by $39 million from $170 million at December 31, 2009 to $131 million at June 30, 2010 due primarily to proceeds received from the sale of properties in North Louisiana.

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 Austin Chalk (Trend). We currently plan to spend approximately $315.4 million on exploration and development activities during fiscal 2010, of which approximately 96% is 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.

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. 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 $86.1 million in the Permian Basin during the first half of 2010 on drilling and completion activities and $3.1 million on seismic and leasing activities. In addition, we spent $9.6 million to acquire an undivided 14% working interest in 36 Wolfberry operated wells in Andrews County, Texas. We drilled 41 gross (38.1 net) operated wells in the Permian Basin and conducted various remedial operations on other wells in the first half of 2010. We currently plan to spend approximately $210.7 million on drilling and completion activities and $14.2 million for seismic and leasing activities in the Permian Basin during fiscal 2010. Our activities are expected to be concentrated in the following areas.

Andrews County - Wolfberry

We have a large acreage block in Andrews County, Texas on which we have identified more than 200 potential locations for Wolfberry wells. A Wolfberry well is a well that commingles production from the Spraberry and Wolfcamp formations. We spent approximately $65.7 million in the Andrews County – Wolfberry on drilling and completion activities during the first half of 2010. We currently plan to continue using five of our rigs to drill and complete approximately 50 additional wells during the remainder of the year at an estimated cost of $104 million, net to our working interest.

Fuhrman-Mascho Field

We also resumed a drilling program in the Fuhrman-Mascho Field in Andrews County, Texas beginning in July 2009. In fiscal 2010, we plan to drill and complete approximately 14 wells at an estimated cost of $4.1 million, net to our working interest.

New Mexico

We currently plan to drill additional development wells in Eddy County, New Mexico targeting the Yeso, San Andres and Grayburg formations. In fiscal 2010, we plan to drill and complete approximately 15 wells at an estimated cost of $6.6 million, net to our working interest.

Austin Chalk (Trend)

Prior to 1998, we concentrated our drilling activities in an oil-prone area we refer to as the Austin Chalk (Trend) in Robertson, Burleson, Brazos, Lee, Milam and Leon Counties, Texas. 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. We believe that 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.

We spent $28.9 million in the Austin Chalk (Trend) area during the first half of 2010 and we plan to use three of our rigs to drill and complete approximately 18 additional wells in the remainder of the year at an estimated cost of $35 million, net to our working interest.

Eagle Ford Shale

The Eagle Ford Shale is a formation immediately beneath the Austin Chalk (Trend) formation. In February 2010, we completed our first Eagle Ford Shale well, the Broesche Unit #1 in Burleson County. This well was drilled to a total vertical depth of 7,580 feet with a 4,880 foot lateral and was completed with a 9 stage frac. In June 2010, we completed the Smalley-Robinson Unit #1 in Burleson County which was drilled to total vertical depth of 7,020 feet with a 5,500 foot lateral and was completed with a 13 stage frac. We are continuing to evaluate the production data from both wells and may drill additional wells in order to determine if an Eagle Ford Shale drilling program is economically viable.

South Louisiana

In the first quarter of 2010, we successfully drilled and completed the State Lease 17378 #4, a developmental well in Plaquemines Parish. During the second quarter of 2010, we also drilled and are currently completing the State Lease 19964 #1, an exploratory well in Plaquemines Parish. We plan to spend $8.7 million in fiscal 2010 in connection with the drilling and completion of these two wells, of which $5 million was incurred in the first half of 2010.

East Texas Bossier

We have an extensive acreage position in East Texas targeting the prolific deep Bossier sands which are encountered at depths ranging from 14,000 to 22,000 feet in this area. Exploration for deep Bossier gas sands in this area is in its early stages and involves a high degree of risk. The geological structures are complex, and limited drilling activity offers minimal subsurface control. Deep Bossier wells are expensive to drill, with completed wells costing approximately $18 million each. 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.

Depressed natural gas prices have limited our opportunities to participate in drilling new gas wells, and we will continue to be very selective until we believe gas prices are more favorable. We spent $1.6 million in the East Texas Bossier area during the first half of 2010 primarily for seismic and leasing activities.

Known Trends and Uncertainties

We currently have enough in-fill drilling locations within our Austin Chalk (Trend) area to sustain drilling throughout the remainder of 2010, but our ability to continue developmental drilling beyond 2010 is uncertain. During the first quarter of 2010, we drilled a step-out well in Lee County, Texas to determine the viability of expanding our Austin Chalk (Trend) developmental drilling program to the southwest of our core properties. Depending on the results of our on-going evaluation of this well’s production performance, we may be able to extend our Austin Chalk (Trend) drilling program into 2011 and subsequent years. In addition, we are continuing efforts to identify other opportunities for growth in the Austin Chalk (Trend) area, including the addition of reserves and production through improved technology, acquisitions of proved reserves, and participation agreements with industry partners.

The Andrews County – Wolfberry developmental drilling program is very sensitive to oil prices and drilling costs. We believe that the steps we have taken to (1) fix unit costs with selected service providers, (2) improve drilling efficiencies through Desta Drilling, and (3) purchase casing and tubing at discounts to current market prices, will enable us to continue drilling in this area through mid-year 2011 as long as oil prices remain at or near current levels. Our ability to sustain an economically viable drilling program in the Andrews-Wolfberry area beyond mid-year 2011 is uncertain. In order to continue drilling in this area, 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 not be able to continue developmental drilling in this area.

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.

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,
	2010			2009
Oil and Gas Production Data:
Oil (MBbls)		808			716
Gas (MMcf)		2,807			3,856
Natural gas liquids (MBbls)		60			59
Total (MBOE)		1,336			1,418

Average Realized Prices (a) :
Oil ($/Bbl)	$	74.27		$	56.55
Gas ($/Mcf)	$	5.14		$	3.84
Natural gas liquids ($/Bbl)	$	40.13		$	24.53

Gain (Loss) on Settled Derivative Contracts (a) :
($ in thousands, except per unit)
Oil: Net realized loss	$	(1,249	)	$	(4,572	)
Per unit produced ($/Bbl)	$	(1.55	)	$	(6.39	)
Gas: Net realized gain	$	4,964		$	3,088
Per unit produced ($/Mcf)	$	1.77		$	.80

Average Daily Production:
Oil (Bbls):
Permian Basin		5,390			4,058
Austin Chalk (Trend)		2,835			2,742
North Louisiana		137			273
South Louisiana		435			701
Other		82			94
Total		8,879			7,868

Gas (Mcf):
Permian Basin		13,263			15,432
Austin Chalk (Trend)		1,810			2,412
North Louisiana		5,747			11,445
South Louisiana		4,930			7,699
Cotton Valley Reef Complex		4,072			3,781
Other		1,024			1,605
Total		30,846			42,374

Natural Gas Liquids (Bbls):
Permian Basin		356			248
Austin Chalk (Trend)		185			290
North Louisiana		26			37
South Louisiana		86			60
Other		6			13
Total		659			648

(Continued)

	Three Months Ended
	June 30,
	2010		2009
Exploration Costs (in thousands):
Abandonment and impairment costs:
North Louisiana	$	739	$	848
South Louisiana		1,148		85
Permian Basin		-		309
East Texas Bossier		735		1,917
Utah		44		558
Mississippi		4		-
Other		221		788
Total		2,891		4,505

Seismic and other		974		1,388
Total exploration costs	$	3,865	$	5,893

Depreciation, Depletion and Amortization (in thousands):
Oil and gas depletion	$	24,813	$	25,671
Contract drilling depreciation		454		305
Other depreciation		170		210
Total DD&A	$	25,437	$	26,186

Oil and Gas Costs ($/BOE Produced):
Production costs	$	15.39	$	12.90
Production costs (excluding production taxes)	$	12.25	$	10.16
Oil and gas depletion	$	18.57	$	18.10

Net Wells Drilled (b) :
Exploratory Wells		1.1		1.2
Developmental Wells		26.3		5.9

	Six Months Ended
	June 30,
	2010			2009
Oil and Gas Production Data:
Oil (MBbls)		1,560			1,467
Gas (MMcf)		6,135			8,469
Natural gas liquids (MBbls)		117			112
Total (MBOE)		2,700			2,991

Average Realized Prices (a) :
Oil ($/Bbl)	$	75.10		$	46.55
Gas ($/Mcf)	$	5.48		$	4.25
Natural gas liquids ($/Bbl)	$	43.08		$	23.78

Gain (Loss) on Settled Derivative Contracts (a) :
($ in thousands, except per unit)
Oil: Net realized loss	$	(2,871	)	$	(4,839	)
Per unit produced ($/Bbl)	$	(1.84	)	$	(3.30	)
Gas: Net realized gain	$	8,283		$	4,486
Per unit produced ($/Mcf)	$	1.35		$	.53

(Continued)

	Six Months Ended
	June 30,
	2010		2009
Average Daily Production:
Oil (Bbls):
Permian Basin		5,151		4,256
Austin Chalk (Trend)		2,717		2,942
North Louisiana		142		271
South Louisiana		530		548
Other		79		88
Total		8,619		8,105

Gas (Mcf):
Permian Basin		13,586		15,553
Austin Chalk (Trend)		2,169		2,718
North Louisiana		7,225		12,989
South Louisiana		6,213		10,132
Cotton Valley Reef Complex		3,802		4,026
Other		900		1,372
Total		33,895		46,790

Natural Gas Liquids (Bbls):
Permian Basin		314		238
Austin Chalk (Trend)		228		299
North Louisiana		15		19
South Louisiana		83		52
Other		6		11
Total		646		619

Exploration Costs (in thousands):
Abandonment and impairment costs:
North Louisiana	$	1,748	$	1,108
South Louisiana		1,148		813
Permian Basin		13		764
East Texas Bossier		2,248		10,784
Utah		64		2,332
Mississippi		327		311
Other		221		805
Total		5,769		16,917

Seismic and other		2,634		5,658
Total exploration costs	$	8,403	$	22,575

Depreciation, Depletion and Amortization (in thousands):
Oil and gas depletion	$	49,401	$	60,433
Contract drilling depreciation		1,307		1,779
Other depreciation		341		439
Total DD&A	$	51,049	$	62,651

Oil and Gas Costs ($/BOE Produced):
Production costs	$	15.37	$	12.49
Production costs (excluding production taxes)	$	12.22	$	10.44
Oil and gas depletion	$	18.30	$	20.20

Net Wells Drilled (b) :
Exploratory Wells		2.2		1.4
Developmental Wells		52.6		11.9

(a) No derivatives were designated as cash flow hedges in 2010 or 2009. All gains or losses on settled derivatives were included in other income (expense) - gain (loss) on derivatives.
(b) Excludes wells being drilled or completed at the end of each period.

Operating Results – Three-Month Periods

The following discussion compares our results for the three months ended June 30, 2010 to the comparative period in 2009. Unless otherwise indicated, references to 2010 and 2009 within this section refer to the respective quarterly period.

Oil and gas operating results

Oil and gas sales in 2010 increased $19.7 million, or 34%, from 2009. Price variances accounted for an increase of $18.9 million while production variances accounted for the remaining $800,000 increase. Production in 2010 (on a BOE basis) was 6% lower than 2009, despite additions from our developmental drilling programs. Oil production increased 13% in 2010 from 2009 while gas production decreased 27% in 2010 from 2009. Most of the decrease in gas production from 2009 levels was attributed to a combination of normal production declines from existing wells and the loss of production related to the sale of certain properties in North Louisiana in June 2010. In 2010, our realized oil price was 31% higher than 2009, and our realized gas price was 34% 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 12% in 2010 as compared to 2009 due primarily to increases in the cost of oilfield services and to an increase in production taxes caused by increases in commodity prices. After giving effect to a 6% decrease in oil and gas production on a BOE basis, production costs per BOE increased 19% from $12.90 per BOE in 2009 to $15.39 per BOE in 2010.

Oil and gas depletion expense decreased $900,000 from 2009 to 2010, of which production variances accounted for a $1.5 million decrease, offset by a $600,000 increase due to rate variances. On a BOE basis, depletion expense increased 3% from $18.10 per BOE in 2009 to $18.57 per BOE in 2010. 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.

We recorded a provision for impairment of property and equipment of $11.1 million during 2010 for certain non-core oil and gas properties in the Permian Basin to reduce the carrying value of those properties to their estimated fair value at June 30, 2010.

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 2010, we charged to expense $3.9 million of exploration costs, as compared to $5.9 million in 2009.

At June 30, 2010, our capitalized unproved oil and gas properties totaled $33.9 million, of which approximately $20.7 million was attributable to unproved acreage. Therefore, our results of operations in future periods may be adversely affected by abandonments and impairments related to unproved oil and gas properties.

Contract Drilling Services

Until April 15, 2009, CWEI owned a 50% equity interest in a joint venture that we have historically referred to as Larclay JV and which we now refer to as Desta Drilling. Effective April 15, 2009, CWEI acquired the remaining 50% equity interest in Desta Drilling. As primary beneficiary of Desta Drilling’s expected cash flows, prior to April 15, 2009, we fully consolidated the accounts of Desta Drilling in our financial statements and accounted for the equity interest owned by Lariat as a noncontrolling interest.

We utilize drilling rigs owned by Desta Drilling to drill wells in our exploration and development activities. Since April 2009, Desta Drilling has worked exclusively for CWEI. As a result, all drilling services revenues received by Desta Drilling subsequent to April 2009, along with the related drilling services costs, have been eliminated in our consolidated statements of operations.

General and Administrative

General and administrative (“G&A”) expenses increased 25% from $6.3 million in 2009 to $7.8 million in 2010. Employee compensation expense related to non-equity incentive plans was $3 million in 2010 compared to $1.3 million in 2009. Excluding employee compensation related to non-equity incentive plans, G&A expenses decreased from $5 million in 2009 to $4.8 million in 2010.

Interest expense

Interest expense increased 9% from $5.7 million in 2009 to $6.2 million in 2010 primarily due to higher average levels of debt. The average daily principal balance outstanding under our revolving credit facility for 2010 was $180.6 million compared to $116.5 million for 2009. Increased borrowings on our revolving credit facility accounted for a $388,000 increase in interest expense, while higher interest rates and fees resulted in an increase of approximately $225,000. In addition, interest expense associated with Desta Drilling’s secured term loan was $303,000 in 2009. In August 2009, we repaid all of Desta Drilling’s debt.

Gain/loss on derivatives

We did not designate any derivative contracts in 2010 or 2009 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 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 to mark our derivative positions to their fair value at June 30, 2010 and a $3.7 million realized gain on settled contracts. For the three months ended June 30, 2009, we reported a $21.8 million net loss on derivatives, consisting of a $20.3 million non-cash loss to mark our derivative positions to their fair value at June 30, 2009 and a $1.5 million realized loss on settled contracts. Because oil and gas prices are volatile, and because we do not account for our derivatives as cash flow hedges, the effect of mark-to-market valuations on our gain/loss on derivatives can cause significant volatility in our results of operations.

Gain/loss on sales of assets and impairment of inventory

We recorded a net loss of $1.3 million on sales of assets and impairment of inventory compared to a net gain of $84,000 in 2009. The 2010 loss related primarily to the sale of our interests in 22 operated and 76 non-operated producing wells in North Louisiana for net proceeds of $73.1 million, after giving effect to customary closing adjustments and the allocation of approximately $2 million of proceeds to applicable APO Partnerships. The 2009 gain was related to a $480,000 gain on the sale of a property offset by a $396,000 loss related to the write-down of inventory to its estimated market value at June 30, 2009.

Income tax expense

Our estimated effective income tax rate in 2010 of 35.4% 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, 2010 to the comparative period in 2009. Unless otherwise indicated, references to 2010 and 2009 within this section refer to the respective six-month period.

Oil and gas operating results

Oil and gas sales in 2010 increased $48 million, or 44%, from 2009. Price variances accounted for an increase of $54.4 million while production variances accounted for a $6.4 million decrease. Production in 2010 (on a BOE basis) was 10% lower than 2009, despite additions from our developmental drilling programs. Oil production increased 6% in 2010 from 2009 while gas production decreased 28% in 2010 from 2009. Most of the decrease in gas production from 2009 levels was attributed to a combination of normal production declines from existing wells and the loss of production related to the sale of certain properties in North Louisiana in June 2010. In 2010, our realized oil price was 61% higher than 2009, and our realized gas price was 29% 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 11% in 2010 as compared to 2009 due primarily to higher production taxes caused by increases in commodity prices and the cost of oilfield services. After giving effect to a 10% decrease in oil and gas production on a BOE basis, production costs per BOE increased 23% from $12.49 per BOE in 2009 to $15.37 per BOE in 2010.

Oil and gas depletion expense decreased $11 million from 2009 to 2010, of which production variances accounted for a $5.9 million decrease and rate variances accounted for a $5.1 million decrease. On a BOE basis, depletion expense decreased 9% from $20.20 per BOE in 2009 to $18.30 per BOE in 2010 due to a decrease in production volumes and a combination of lower depletable costs and higher estimated reserve quantities in 2010 compared to the 2009 period. In fiscal 2009, we reduced our carrying value of proved properties by $27 million under applicable accounting standards relating to impairments of proved properties primarily in South Louisiana relating to well performance. 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 2010, we charged to expense $8.4 million of exploration costs, as compared to $22.6 million in 2009.

Contract Drilling Services

General and Administrative

G&A expenses increased 30% from $10.8 million in 2009 to $14.1 million in 2010. Employee compensation expense related to non-equity incentive plans was $5.1 million in 2010 compared to $2 million in 2009. Excluding employee compensation related to non-equity incentive plans, G&A expenses increased from $8.8 million in 2009 to $9 million in 2010.

Interest expense

Interest expense increased 11% from $11.2 million in 2009 to $12.4 million in 2010 primarily due to higher average levels of debt. The average daily principal balance outstanding under our revolving credit facility for 2010 was $186.5 million compared to $106.2 million for 2009. Increased borrowings on our revolving credit facility accounted for an $897,000 increase in interest expense, while higher interest rates and fees resulted in an increase of approximately $666,000. In addition, interest expense associated with Desta Drilling’s secured term loan was $725,000 in 2009, and capitalized interest for 2010 was $178,000 compared to $465,000 in 2009. In August 2009, we repaid all of Desta Drilling’s debt.

Gain/loss on derivatives

We did not designate any derivative contracts in 2010 or 2009 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 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 to mark our derivative positions to their fair value at June 30, 2010 and a $5.4 million realized gain on settled contracts. For the six months ended June 30, 2009, we reported a $19.3 million net loss on derivatives, consisting of an $18.9 million non-cash loss to mark our derivative positions to their fair value at June 30, 2009 and a $353,000 realized loss on settled contracts. Because oil and gas prices are volatile, and because we do not account for our derivatives as cash flow hedges, the effect of mark-to-market valuations on our gain/loss on derivatives can cause significant volatility in our results of operations.

Gain/loss on sales of assets and impairment of inventory

We recorded a net loss of $1 million on sales of assets and impairment of inventory compared to a net loss of $3.2 million in 2009. The 2010 loss related primarily to the sale of our interests in 22 operated and 76 non-operated producing wells in North Louisiana for net proceeds of $73.1 million, after giving effect to customary closing adjustments and the allocation of approximately $2 million of proceeds to applicable APO Partnerships. The 2009 loss was related primarily to the write-down of inventory to its estimated market value at June 30, 2009.

Income tax expense

Our estimated effective income tax rate in 2010 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.

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, the effects of product prices on cash flow can be mitigated through the use of commodity derivatives.

The Indenture governing the issuance of our 7¾% Senior Notes due 2013 contains covenants that restrict our ability to incur indebtedness. We currently have, and expect to have in 2010, the ability under the Indenture to incur indebtedness as needed in 2010 to fund our exploration and development activities.

Capital expenditures

We incurred expenditures for exploration and development activities of $140.4 million during the first six months of 2010 and we currently plan to spend $315.4 million for fiscal 2010. The following table summarizes, by area, our actual expenditures for exploration and development activities for the first half of 2010 and our planned expenditures for the year ending December 31, 2010.

	Actual		Planned
	Expenditures		Expenditures		2010
	Six Months Ended		Year Ended		Percentage
	June 30, 2010		December 31, 2010		of Total
	(In thousands)
Permian Basin	$	98,800	$	224,900		71	%
Austin Chalk (Trend)/ Eagle Ford Shale		32,100		74,200		24	%
South Louisiana		5,000		8,700		3	%
California		700		2,000		1	%
Other		3,800		5,600		1	%
	$	140,400	$	315,400		100	%

Our actual expenditures during fiscal 2010 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 the ultimate level of expenditures during the remainder of fiscal 2010.

Our expenditures for exploration and development activities for the six months ended June 30, 2010 totaled $140.4 million, of which approximately 95% 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 2010. 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 2010, 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 six months ended June 30, 2010 increased $57 million, or 143%, as compared to the corresponding period in 2009 due primarily to a 44% increase in oil and gas sales caused by higher commodity prices.

Credit facility

We have a revolving credit facility with a syndicate of banks led by JPMorgan Chase Bank, N.A. We have historically relied on the revolving credit facility for both our short-term liquidity (working capital) and our long-term financial needs. The funds available to us at any time under the revolving credit facility are limited to the amount of the borrowing base determined by the banks. 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 banks redetermine the borrowing base under the revolving credit facility on a semi-annual basis, in May and November. In addition, we or the banks may 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) pledge additional collateral, (2) prepay the principal amount of the loans in an amount sufficient to eliminate the excess, or (3) prepay the excess in six equal monthly installments. In April 2010, the banks increased our borrowing base from $250 million to $300 million.

The revolving credit facility is collateralized by substantially all of our assets, including at least 80% of the adjusted engineered value (as defined in the revolving credit facility) of our oil and gas interests evaluated in determining the borrowing base for the revolving credit facility. The obligations under the revolving credit facility are guaranteed by each of our domestic subsidiaries, excluding WCEP, LLC.

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, (3) exclude current maturities of loans under the revolving credit facility, if any, and (4) 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 generally accepted accounting principles (“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 increased from $19.3 million at December 31, 2009 to $24.8 million at June 30, 2010. After giving effect to the adjustments, our working capital computed for loan compliance purposes was $177.6 million at June 30, 2010, as compared to $104.4 million at December 31, 2009. The following table reconciles our GAAP working capital to the working capital computed for loan compliance purposes at June 30, 2010 and December 31, 2009.

	June 30,			December 31,
	2010			2009
	(In thousands)
Working capital per GAAP	$	24,845		$	19,324
Add funds available under the revolving credit facility		168,975			79,196
Exclude fair value of derivatives classified as current assets or current liabilities		(16,264	)		5,907
Working capital per loan covenant	$	177,556		$	104,427

The revolving credit facility also prohibits the ratio of our consolidated funded indebtedness to consolidated EBITDAX (the “Leverage Ratio”) (determined as of the end of each fiscal quarter for the then most-recently ended four fiscal quarters) from being greater than (1) 3.5 to 1 for any fiscal quarter ending on or prior to December 31, 2010, (2) 3.25 to 1 for any fiscal quarter ending on or after March 31, 2011 through December 31, 2011 and (3) 3 to 1 for any fiscal quarter thereafter.

We were in compliance with all financial and non-financial covenants at June 30, 2010. 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 loan agreement 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., BNP Paribas, Union Bank, N.A., Bank of Scotland, Natixis, Compass Bank, Bank of Texas, N.A., The Frost National Bank, Keybank, N.A., and UBS Loan Finance, LLC.

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, 2010, 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 in 2010, we decreased indebtedness outstanding under the revolving credit facility by $39 million. At June 30, 2010, we had $131 million of borrowings outstanding under the revolving credit facility, leaving $169 million available on the facility after allowing for an outstanding letter of credit totaling $25,000. In April 2010, the borrowing base established by the banks was increased to $300 million. The revolving credit facility matures in May 2012.

7¾% Senior Notes due 2013

In July 2005, we issued, in a private placement, $225 million of aggregate principal amount of Senior Notes. The 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.

We may redeem some or all of the Senior Notes at redemption prices (expressed as percentages of principal amount) equal to 101.938% for the twelve-month period beginning on August 1, 2010, and 100% beginning on August 1, 2011, for any period thereafter, in each case plus accrued and unpaid interest.

The Indenture governing the Senior Notes contains covenants that restrict the ability of us and our subsidiaries 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 Indenture) exceeds 2.5 to 1 for the four most recently completed fiscal quarters. However, this restriction does not prevent us from borrowing funds under the revolving credit facility provided that our outstanding balance on the facility does not exceed the greater of $150 million and 30% of Adjusted Consolidated Net Tangible Assets (as defined in the Indenture). Based on our PV-10 Value at December 31, 2009, this alternative to the EBITDAX coverage test would not be available since our outstanding borrowings under the revolving credit facility currently exceed the maximum permitted. We currently have, and expect to have in 2010, sufficient EBITDAX coverage under the Indenture to permit us to borrow funds as needed in 2010 to fund our exploration and development activities. These covenants are subject to a number of important exceptions and qualifications as described in the Indenture. We were in compliance with these covenants at June 30, 2010.

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 may adversely affect our financial condition and results of operations, and may also reduce the amount of net oil and gas reserves that we can produce economically. Any reduction in reserves, including reductions due to price fluctuations, can reduce the borrowing base under our revolving credit facility and adversely affect our liquidity and our ability to obtain capital for our exploration and development activities. Similarly, any improvements in oil and gas prices can have a favorable impact on our financial condition, results of operations and capital resources. Based on December 31, 2009 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 2009 would reduce our gross revenues for the year ending December 31, 2010 by $8.6 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:
3rd Quarter 2010		522,000	$	76.40		1,750,000	$	6.80
4th Quarter 2010		480,000	$	76.24		1,680,000	$	6.80
2011		1,656,000	$	84.38		6,420,000	$	7.07
		2,658,000				9,850,000

(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 $7.2 million.

Interest Rates

We are exposed to interest rate risk on our long-term debt with a variable interest rate. At June 30, 2010, our fixed rate debt had a carrying value of $225 million and an approximate fair value of $220 million, based on current market quotes. 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 $6 million. Based on our outstanding variable rate indebtedness at June 30, 2010 of $131 million, a change in interest rates of 100-basis points would affect annual interest payments by $1.3 million.

Item 4 - Controls and Procedures

Disclosure Controls and Procedures

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

With respect to our disclosure controls and procedures:

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

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

•

It is the conclusion of our chief executive officer and our chief financial officer 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, 2010 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1A - Risk Factors

In evaluating all forward-looking statements, you should specifically consider various factors that may cause actual results to vary from those contained in the forward-looking statements. Our risk factors are included in our Annual Report on Form 10-K for the year ended December 31, 2009, as filed with the U.S. Securities and Exchange Commission on March 12, 2010 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.

The recent adoption of derivatives legislation by the United States Congress could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.

The United States Congress recently adopted comprehensive financial reform legislation that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The new legislation was signed into law by the President on July 21, 2010 and requires the Commodities Futures Trading Commission (the “CFTC”) and the SEC to promulgate rules and regulations implementing the new legislation within 360 days from the date of enactment. The CFTC has also proposed regulations to set position limits for certain futures and option contracts in the major energy markets, although it is not possible at this time to predict whether or when the CFTC will adopt those rules or include comparable provisions in its rulemaking under the new legislation. The financial reform legislation may also require us to comply with margin requirements and with certain clearing and trade-execution requirements in connection with our derivative activities, although the application of those provisions to us is uncertain at this time. The financial reform legislation may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty. The new legislation and any new regulations could significantly increase the cost of derivative contracts (including requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks that we encounter, reduce our ability to monetize or restructure existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the legislation was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on us, our financial condition, and results of operations.

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††

**10.1		Eighth Amendment to Amended and Restated Credit Agreement dated April 29, 2010, filed as Exhibit 10.1 to our Current Report on Form 8-K filed with the Commission on May 5, 2010††

*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

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

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 9, 2010	By:	/s/ L. Paul Latham
			L. Paul Latham
			Executive Vice President and Chief
			Operating Officer

Date:	August 9, 2010	By:	/s/ Mel G. Riggs
			Mel G. Riggs
			Senior Vice President and Chief Financial
			Officer

INDEX TO EXHIBITS

Exhibits 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††

**10.1		Eighth Amendment to Amended and Restated Credit Agreement dated April 29, 2010, filed as Exhibit 10.1 to our Current Report on Form 8-K filed with the Commission on May 5, 2010††

*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