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, 2009

¨	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 (§232.405 of this chapter) 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 12,143,536 shares of Common Stock, $.10 par value, of the registrant outstanding as of August 4, 2009.

CLAYTON WILLIAMS ENERGY, INC

TABLE OF CONTENTS

PART I.  FINANCIAL INFORMATION
		Page
Item 1.	Financial Statements
	Consolidated Balance Sheets as of June 30, 2009
	and December 31, 2008	3
	Consolidated Statements of Operations for the three months and six months
	ended June 30, 2009 and 2008	5
	Consolidated Statement of Equity for the six months
	ended June 30, 2009	6
	Consolidated Statements of Cash Flows for the six months
	ended June 30, 2009 and 2008	7
	Notes to Consolidated Financial Statements	8
Item 2.	Management’s Discussion and Analysis of Financial
	Condition and Results of Operations	25
Item 3.	Quantitative and Qualitative Disclosures About Market Risks	44
Item 4.	Controls and Procedures	46
PART II.  OTHER INFORMATION
Item 1A.	Risk Factors	47
Item 4.	Submission of Matters to a Vote of Security Holders	48
Item 6.	Exhibits	49
	Signatures	50

2

CLAYTON WILLIAMS ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

ASSETS
	June 30,			December 31,
	2009			2008
	(Unaudited)
CURRENT ASSETS
Cash and cash equivalents	$	15,943		$	41,199
Accounts receivable:
Oil and gas sales		23,223			26,009
Joint interest and other, net		6,229			14,349
Affiliates		554			227
Inventory		32,396			20,052
Deferred income taxes		3,637			3,637
Assets held for sale		18,750			-
Prepaids and other		18,386			20,011
		119,118			125,484
PROPERTY AND EQUIPMENT
Oil and gas properties, successful efforts method		1,564,547			1,526,473
Natural gas gathering and processing systems		17,816			17,816
Contract drilling equipment		26,465			91,151
Other		15,869			14,954
		1,624,697			1,650,394
Less accumulated depreciation, depletion and amortization		(890,043	)		(840,366	)
Property and equipment, net		734,654			810,028
OTHER ASSETS
Debt issue costs, net		5,671			6,225
Other		1,830			1,672
		7,501			7,897
	$	861,273		$	943,409

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

3

CLAYTON WILLIAMS ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

LIABILITIES AND EQUITY
	June 30,		December 31,
	2009		2008
	(Unaudited)
CURRENT LIABILITIES
Accounts payable:
Trade	$	36,603	$	67,189
Oil and gas sales		26,817		24,702
Affiliates		1,518		1,627
Current maturities of long-term debt		18,750		18,750
Fair value of derivatives		17,626		-
Accrued liabilities and other		11,264		10,609
		112,578		122,877
NON-CURRENT LIABILITIES
Long-term debt		355,550		347,225
Deferred income taxes		86,087		120,414
Fair value of derivatives		1,281		-
Other		37,034		32,617
		479,952		500,256
COMMITMENTS AND CONTINGENCIES
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 – 12,143,536 shares in 2009
and 12,115,898 shares in 2008		1,214		1,212
Additional paid-in capital		152,028		137,046
Retained earnings		115,501		176,424
Total Clayton Williams Energy, Inc. stockholders’ equity		268,743		314,682
Noncontrolling interest, net of tax		-		5,594
Total equity		268,743		320,276
	$	861,273	$	943,409

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

4

CLAYTON WILLIAMS ENERGY, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(In thousands, except per share)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2009			2008			2009			2008
REVENUES
Oil and gas sales	$	57,206		$	134,291		$	108,002		$	253,210
Natural gas services		1,355			3,553			2,939			6,091
Drilling rig services		1,462			12,703			6,681			27,535
Gain on sales of assets		480			40,721			663			41,290
Total revenues		60,503			191,268			118,285			328,126
COSTS AND EXPENSES
Production		18,296			21,925			37,359			42,504
Exploration:
Abandonments and impairments		4,505			1,933			16,917			2,230
Seismic and other		1,388			1,562			5,658			5,237
Natural gas services		1,211			3,244			2,622			5,759
Drilling rig services		2,911			9,923			9,997			21,040
Depreciation, depletion and amortization		26,186			24,974			62,651			55,247
Impairment of property and equipment		32,068			-			32,068			-
Accretion of abandonment obligations		748			485			1,466			1,015
General and administrative		6,256			7,944			10,784			11,392
Loss on sales of assets and inventory
write-downs		396			277			3,845			286
Total costs and expenses		93,965			72,267			183,367			144,710
Operating income (loss)		(33,462	)		119,001			(65,082	)		183,416
OTHER INCOME (EXPENSE)
Interest expense		(5,736	)		(6,077	)		(11,174	)		(13,523	)
Loss on derivatives		(21,770	)		(148,587	)		(19,260	)		(194,696	)
Other		826			3,014			1,727			3,669
Total other income (expense)		(26,680	)		(151,650	)		(28,707	)		(204,550	)
Loss before income taxes		(60,142	)		(32,649	)		(93,789	)		(21,134	)
Income tax benefit		21,943			11,642			34,321			7,420
NET LOSS		(38,199	)		(21,007	)		(59,468	)		(13,714	)
Less income attributable to
noncontrolling interest, net of tax		(409	)		(164	)		(1,455	)		(278	)
NET LOSS attributable to Clayton
Williams Energy, Inc.	$	(38,608	)	$	(21,171	)	$	(60,923	)	$	(13,992	)
Net loss per common share attributable to
Clayton Williams Energy, Inc. stockholders:
Basic	$	(3.18	)	$	(1.75	)	$	(5.02	)	$	(1.19	)
Diluted	$	(3.18	)	$	(1.75	)	$	(5.02	)	$	(1.19	)
Weighted average common shares outstanding:
Basic		12,142			12,111			12,132			11,749
Diluted		12,142			12,111			12,132			11,749

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

5

CLAYTON WILLIAMS ENERGY, INC.

CONSOLIDATED STATEMENT OF EQUITY

(Unaudited)

(In thousands)

	Clayton Williams Energy, Inc. Stockholders’ Equity
	Common Stock				Additional
	No. of		Par		Paid-In		Retained			Noncontrolling
	Shares		Value		Capital		Earnings			Interest
BALANCE,
December 31, 2008		12,116	$	1,212	$	137,046	$	176,424		$	5,594
Net income (loss)		-		-		-		(60,923	)		1,455
Stock options exercised		28		2		150		-			-
Acquisition of noncontrolling
interest		-		-		14,832		-			(7,049	)
BALANCE,
June 30, 2009		12,144	$	1,214	$	152,028	$	115,501		$	-

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

6

CLAYTON WILLIAMS ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In thousands)

	Six Months Ended
	June 30,
	2009			2008
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss	$	(59,468	)	$	(13,714	)
Adjustments to reconcile net loss to cash
provided by operating activities:
Depreciation, depletion and amortization		62,651			55,247
Impairment of property and equipment		32,068			-
Exploration costs		16,917			2,230
(Gain) loss on sales of assets and inventory write-downs, net		3,182			(41,004	)
Deferred income tax benefit		(34,321	)		(7,752	)
Non-cash employee compensation		627			1,910
Unrealized loss on derivatives		18,907			145,621
Settlements on derivatives with financing elements		-			24,789
Amortization of debt issue costs		624			785
Accretion of abandonment obligations		1,466			1,015
Changes in operating working capital:
Accounts receivable		10,579			(19,662	)
Accounts payable		(16,626	)		398
Other		3,264			(442	)
Net cash provided by operating activities		39,870			149,421
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to property and equipment		(69,082	)		(118,500	)
Proceeds from sales of assets		670			114,049
Change in equipment inventory		(12,594	)		(6,777	)
Other		(97	)		785
Net cash used in investing activities		(81,103	)		(10,443	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt		25,200			4,000
Repayments of long-term debt		(9,375	)		(128,925	)
Proceeds from exercise of stock options		152			15,884
Settlements on derivatives with financing elements		-			(24,789	)
Net cash provided by (used in) financing activities		15,977			(133,830	)
NET INCREASE (DECREASE) IN CASH AND
CASH EQUIVALENTS		(25,256	)		5,148
CASH AND CASH EQUIVALENTS
Beginning of period		41,199			12,344
End of period	$	15,943		$	17,492
SUPPLEMENTAL DISCLOSURES
Cash paid for interest, net of amounts capitalized	$	11,354		$	13,123

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

7

CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2009

(Unaudited)

1. Nature of Operations

Clayton Williams Energy, Inc. (a Delaware corporation) (“CWEI”) and its subsidiaries (collectively, the “Company”) 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.  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 the Company’s oil and gas production is sold under short-term contracts which are market-sensitive.  Accordingly, the Company’s financial condition, 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 the control of the Company.  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 requires management of the Company 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 Clayton Williams Energy, Inc., and its wholly-owned subsidiaries.  The Company also accounts for its undivided interests in oil and gas limited partnerships using the proportionate consolidation method.  Under this method, the Company consolidates its proportionate share of assets, liabilities, revenues and expenses of these limited partnerships utilizing accounting policies followed by the Company.  Less than 5% of the Company’s 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, the Company's unaudited consolidated financial statements as of June 30, 2009 and for the interim periods ended June 30, 2009 and 2008 include all adjustments which are necessary for a fair presentation in accordance with accounting principles generally accepted in the United States.  These interim results are not necessarily indicative of the results to be expected for the year ending December 31, 2009.

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 the Company's Form 10-K for the year ended December 31, 2008.

Effective April 15, 2009, the Company acquired the remaining 50% equity ownership in the contract drilling joint venture the Company formed in 2006 with Lariat Services, Inc. ("Lariat").  The Company has historically referred to this joint venture as Larclay JV until June 2009 when it changed the legal name of the operating entity in the joint venture to Desta Drilling, LP.  Desta Drilling, LP (formerly Larclay JV) is referred to in these notes to consolidated financial statements as “Desta Drilling”.  Desta Drilling is now a wholly-owned subsidiary of the Company.

8

Adopted Accounting Pronouncements

Effective January 1, 2009, the Company adopted Statement of Financial Accounting Standards (“SFAS”) No. 160, “Noncontrolling Interests in Consolidated Financial Statements - an amendment of ARB No. 51” (“SFAS 160”).  Noncontrolling interests (previously referred to as minority interests) are ownership interests in a consolidated subsidiary held by parties other than the parent.  SFAS 160 requires that noncontrolling interests be clearly identified and reported as a component of equity in the parent’s balance sheet.  SFAS 160 also requires that the amount of net income or loss attributable to the parent and the noncontrolling interest be presented separately on the face of the consolidated statement of operations.  The presentations of noncontrolling interest in the Company’s consolidated financial statements, as required by SFAS 160, have been applied retrospectively to prior periods.

Effective January 1, 2009, the Company adopted SFAS Statement No. 161, “Disclosures about Derivative Instruments and Hedging Activities, an amendment of Financial Accounting Standards Board (“FASB”) Statement No. 133” (“SFAS 161”). This statement is intended to improve transparency in financial reporting by requiring enhanced disclosures of an entity’s derivative instruments and hedging activities and their effects on the entity’s financial position, financial performance, and cash flows. SFAS 161 applies to all derivative instruments within the scope of SFAS No. 133, “Accounting for Derivatives and Hedging Activities” (“SFAS 133”) as well as related hedged items, bifurcated derivatives, and non-derivative instruments that are designated and qualify as hedging instruments. The adoption of SFAS 161 did not have a material effect on the Company’s financial statements, other than disclosures.

Effective January 1, 2009, the Company adopted SFAS No. 141R, “Business Combinations” (“SFAS 141R”).  SFAS 141R requires most identifiable assets, liabilities, noncontrolling interests, and goodwill acquired in a business combination to be recorded at “fair value.” The Statement applies to all business combinations, including combinations among mutual entities and combinations by contract alone. Under SFAS 141R, all business combinations will be accounted for by applying the acquisition method.  The adoption of SFAS 141R did not have a material impact on the Company’s financial statements.

Effective January 1, 2009, the Company adopted SFAS No. 157, “Fair Value Measurements (as amended)” (“SFAS 157”), for nonfinancial assets and liabilities that are measured at fair value on a nonrecurring basis (see Note 8).  SFAS 157 defines fair value, establishes a framework for measuring fair value when an entity is required to use a fair value measure for recognition or disclosure purposes and expands the disclosures about fair value measures.  The Company had previously adopted SFAS 157 for financial assets and liabilities that are measured at fair value and for nonfinancial assets and liabilities that are measured at fair value on a recurring basis.

Effective April 1, 2009, the Company adopted FASB Staff Position No. FAS 157-4, “Determining Fair Value When the Volume or Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly” (“FSP 157-4”). FSP 157-4 provides additional guidance for estimating fair value in accordance with SFAS 157 when the volume and level of activity for the asset or liability have significantly decreased and requires that companies provide interim and annual disclosures of the inputs and valuation techniques used to measure fair value. FSP 157-4 is effective for interim and annual reporting periods ending after June 15, 2009 and is to be applied prospectively.  The adoption of FSP 157-4 did not have a material impact on the Company’s financial statements, other than additional disclosures.

Effective April 1, 2009, the Company adopted SFAS No. 165, “Subsequent Events” (“SFAS 165”), which establishes principles and requirements for disclosure of subsequent events.   It establishes the period after the balance sheet date during which events or transactions are to be evaluated for potential disclosure.  It also establishes the circumstances under which an entity shall recognize events or transactions occurring after the balance sheet date. The adoption of SFAS 165 did not have a material impact on the Company’s disclosure of subsequent events.

9

3. Recent Accounting Pronouncements

In June 2009, the FASB issued SFAS No. 168, “The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles, a replacement of FASB Statement No. 162” (“SFAS 168”).  SFAS 168 became effective for the Company on July 1, 2009.  SFAS 168 establishes the FASB Accounting Standards Codification as the source of authoritative accounting principles recognized by the FASB to be applied by nongovernmental entities in the preparation of financial statements in conformity with generally accepted accounting principles (“GAAP”).  SFAS 168 is not expected to change GAAP and is not expected to have a material impact on the Company’s financial statements.

In December 2008, the SEC released Final Rule, “Modernization of Oil and Gas Reporting”. The new disclosure requirements include provisions that permit the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes. The new requirements also will allow companies to disclose their probable and possible reserves to investors. In addition, the new disclosure requirements require companies to: (1) report the independence and qualifications of its reserves preparer or auditor, (2) file reports when a third party is relied upon to prepare reserves estimates or conducts a reserves audit, and (3) report oil and gas reserves using an average price based upon the prior 12-month period rather than year-end prices. The new disclosure requirements are effective for financial statements for fiscal years ending on or after December 31, 2009. The effect of adopting the SEC rule has not been determined, but it is not expected to have a significant effect on the Company’s reported financial position or results of operations.

4. Long-Term Debt

Long-term debt consists of the following:

	June 30,			December 31,
	2009			2008
	(In thousands)
7¾% Senior Notes due 2013	$	225,000		$	225,000
Secured bank credit facility, due May 2012		119,300			94,100
Secured term loan of Desta Drilling, due June 2011		30,000			39,375
Subordinated notes of Desta Drilling(a)		-			7,500
		374,300			365,975
Less current maturities(b)		(18,750	)		(18,750	)
	$	355,550		$	347,225

(a)      Note payable to Lariat Services Inc. by Desta Drilling that was converted to equity in April 2009 (see Note 10).

(b)      Amounts in both periods relate to the current portion of the term loan of Desta Drilling.

7¾% Senior Notes due 2013

In July 2005, the Company issued, in a private placement, $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, beginning February 1, 2006.

The Company may redeem some or all of the Senior Notes at redemption prices (expressed as percentages of principal amount) equal to 103.875% for the twelve-month period beginning on August 1, 2009, 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.

10

The Indenture governing the Senior Notes contains covenants that restrict the ability of the Company and its 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 the Company 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 the Company from borrowing funds under the revolving credit facility provided that the Company’s 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.  The Company was in compliance with these covenants at June 30, 2009.

Secured Bank Credit Facility

The Company has a revolving credit facility with a syndicate of banks based on a borrowing base determined by the banks.  The borrowing base, which is based 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.  The Company or the banks may also request an unscheduled borrowing base redetermination at any other time during the year.  If, at any time, the borrowing base is less than the amount of outstanding credit exposure under the revolving credit facility, the Company 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 May 2009, the borrowing base was affirmed at $250 million.  After allowing for outstanding letters of credit totaling $804,000, the Company had $129.9 million available under the credit facility at June 30, 2009.

The revolving credit facility is collateralized by substantially all of the Company’s assets, including at least 80% of the adjusted engineered value (as defined in the revolving credit facility) of the Company’s 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, excluding Desta Drilling.

In May 2009, the usage-based pricing formulas under the revolving credit facility were amended.  The Eurodollar rate margin was increased to a range of 2% to 3% from a range of 1.5% to 2.25%.  The alternate base rate margin was increased to a range of 1.125% to 2.125% from a range of .25% to 1%.  The Company also pays a commitment fee on the unused portion of the revolving credit facility which increased to a flat rate of .5% from a range of .375% to .5%.  Interest and fees are payable no less often than quarterly.  The effective annual interest rate on borrowings under the revolving credit facility, excluding bank fees and amortization of debt issue costs, for the six months ended June 30, 2009 was 2.4%.

The revolving credit facility contains financial covenants that are computed quarterly.  One financial covenant requires the Company to maintain a ratio of current assets to current liabilities of at least 1 to 1.  Another financial covenant, which was amended in May 2009, prohibits the ratio of the Company’s 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.  Prior to the amendment, this ratio could not exceed 3 to 1.  The computations of current assets, current liabilities, EBITDAX and indebtedness are defined in the loan agreement.  The Company was in compliance with all financial and non-financial covenants at June 30, 2009.

Secured Term Loan of Desta Drilling

In 2006, Desta Drilling (formerly referred to as Larclay JV, see Note 10) obtained a $75 million secured term loan facility from a lender to finance the construction and equipping of 12 new drilling rigs.  The Desta Drilling term loan is secured by substantially all of Desta Drilling’s assets.  As additional credit support, the Company granted the lender a limited guaranty in the original amount of $19.5 million.  The maximum obligation under the guaranty reduces by 10% on April 1 of each year, beginning April 1, 2008.  At June 30, 2009, the maximum obligation of the Company under the guaranty was approximately $15.8 million.

11

The Desta Drilling term loan bears interest at a floating rate based on a LIBOR average, plus 3.25%, and provides for monthly principal and interest payments sufficient to retire the principal balance by 35% in the first year, 25% in each of the next two years, and 15% in the fourth year.  The term loan prohibits Desta Drilling from making any cash distributions to its partners until the balance on the term loan is fully repaid.  At June 30, 2009, the effective annual interest rate on the Desta Drilling term loan was 3.9%.

5. Other Non-Current Liabilities

Other non-current liabilities consist of the following:

	June 30,		December 31,
	2009		2008
	(In thousands)
Abandonment obligations	$	36,320	$	31,737
Other taxes payable		144		144
Other		570		736
	$	37,034	$	32,617

Changes in abandonment obligations for the six months ended June 30, 2009 and 2008 are as follows:

	Six Months Ended
	June 30,
	2009			2008
	(In thousands)
Beginning of period	$	31,737		$	30,994
Additional abandonment obligations from new wells		945			228
Sales of properties		(47	)		(1,784	)
Revisions of previous estimates		2,219			(1,391	)
Accretion expense		1,466			1,015
End of period	$	36,320		$	29,062

6. Compensation Plans

Stock-Based Compensation

The Company has reserved 1,798,200 shares of common stock for issuance under the 1993 Stock Compensation Plan (“1993 Plan”).  The 1993 Plan provides for the issuance of nonqualified stock options with an exercise price which is not less than the market value of the Company’s common stock on the date of grant.  The Company issues new shares, not repurchased shares, to option holders that exercise stock options under the 1993 Plan.  At June 30, 2009, no options were outstanding under this plan, and 101,766 shares remain available for issuance.

The Company has reserved 86,300 shares of common stock for issuance under the Outside Directors Stock Option Plan (“Directors Plan”).  Since the inception of the Directors Plan, the Company has issued options covering 52,000 shares of common stock at option prices ranging from $3.25 to $41.74 per share.  All outstanding options expire 10 years from the grant date and are fully exercisable upon issuance.  At June 30, 2009, 26,000 options were outstanding under this plan.  Effective January 1, 2009, the Company’s Board of Directors suspended the grant of options under the Director’s Plan.

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The following table sets forth certain information regarding the Company’s stock option plans as of and for the six months ended June 30, 2009.

						Weighted
				Weighted		Average
				Average		Remaining		Aggregate
				Exercise		Contractual		Intrinsic
	Shares			Price		Term		Value(a)
Outstanding at January 1, 2009		53,638		$	15.20
Exercised (b)		(27,638	)	$	5.50
Outstanding at June 30, 2009		26,000		$	25.52		4.7	$	51,620
Vested at June 30, 2009		26,000		$	25.52		4.7	$	51,620
Exercisable at June 30, 2009		26,000		$	25.52		4.7	$	51,620
(a) Based on closing price at June 30, 2009 of $18.87 per share.
(b) Cash received for options exercised totaled $152,000.

The following table summarizes information with respect to options outstanding at June 30, 2009, all of which are currently exercisable.

	Outstanding and Exercisable Options
			Weighted
		Weighted	Average
		Average	Remaining
		Exercise	Life in
	Shares	Price	Years
Range of exercise prices:
$10.00 - $19.74	8,000	$          12.42	2.4
$22.90 - $41.74	18,000	$          31.34	5.7
	26,000	$          25.52	4.7

The following table presents certain information regarding stock-based compensation amounts for the six months ended June 30, 2009 and 2008.

	Six Months Ended
	June 30,
	2009		2008
	(In thousands, except per share)
Weighted average grant date fair value of options granted per share	$	-	$	23.06
Intrinsic value of options exercised	$	542	$	20,344
Stock-based employee compensation expense	$	-	$	92
Tax benefit		-		(32	)
Net stock-based employee compensation expense	$	-	$	60

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 the Company’s drilling and acquisition programs.  The Compensation Committee’s objective in adopting this plan is to further align the interests of the participants with those of the Company 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 the Company and the participants to which the Company contributes a portion of its economic interest in wells drilled or acquired within certain areas.  Generally, the Company pays all costs to acquire, drill and produce applicable wells and receives all revenues until it has recovered all of its 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 the Company’s economic interests in specified wells drilled or

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acquired by the Company subsequent to October 2002 are subject to the APO incentive plan.  The Company records its allocable share of the assets, liabilities, revenues, expenses and oil and gas reserves of these APO Partnerships in its consolidated financial statements.

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 the Company’s working interest in specified areas where the Company is 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 pursuant to which the Company pays participants a bonus equal to a portion of APO cash flows received by the Company from its 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.  In May 2008, the Company granted awards under the APO Reward Plan in three 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 May 5, 2008.  Under these three awards, 100% of the quarterly bonus amount is payable on a current basis to the participants, and the full vesting date for future amounts payable under the plan is May 5, 2013.

In January 2007, the Company 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.

The Company recognizes compensation expense related to APO Partnerships based on the estimated fair value of the economic interests conveyed to the participants.  Estimated compensation expense applicable to the APO Reward Plan and SWR Reward Plan is recognized over the five-year vesting period.  The Company recorded compensation expense of $2 million for the six months ended June 30, 2009 and $1.9 million for the six months ended June 30, 2008 in connection with all non-equity award plans.

7. Derivatives

Commodity Derivatives

From time to time, the Company utilizes commodity derivatives, consisting of swaps, floors and collars, to attempt to optimize the price received for its oil and gas production.  When using swaps to hedge oil and natural gas production, the Company receives a fixed price for the respective commodity and pays a floating market price as defined in each contract (generally NYMEX futures prices), resulting in a net amount due to or from the counterparty.  In floor transactions, the Company receives 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 the Company receives the fixed price and pays the market price.  If the market price is between the call and the put strike prices, no payments are due from either party.  Commodity derivatives are settled monthly as the contract production periods mature.

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The following summarizes information concerning the Company’s net positions in open commodity derivatives applicable to periods subsequent to June 30, 2009.  The settlement prices of commodity derivatives are based on NYMEX futures prices.

Swaps:

	Gas				Oil
	MMBtu (a)		Price		Bbls		Price
Production Period:
3rd Quarter 2009		1,450,000	$	5.47		440,000	$	48.13
4th Quarter 2009		1,850,000	$	5.47		400,000	$	46.15
2010		7,540,000	$	6.80		327,000	$	53.30
2011		6,420,000	$	7.07		-	$	-
		17,260,000				1,167,000
(a) One MMBtu equals one Mcf at a Btu factor of 1,000.

Accounting For Derivatives

The Company accounts for its derivatives in accordance with SFAS 133.  The Company did not designate any of its 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 the Company’s statements of operations.  The Company reports its fair value of derivatives as either a net current asset or liability or a net non-current asset or liability in its 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, 2009, the Company reported a $19.3 million net loss on derivatives, consisting of a $18.9 million loss related to changes in mark-to-market valuations and a $353,000 realized loss for settled contracts.  For the six months ended June 30, 2008, the Company reported a $194.7 million net loss on derivatives, consisting of a $145.6 million loss related to changes in mark-to-market valuations and a $49.1 million realized loss on settled contracts.

Effect of Derivative Instruments on the Consolidated Balance Sheets

	Liability Derivatives
	Balance Sheet	June 30, 2009
	Location	Fair Value
		(In thousands)
Derivatives not designated as
hedging instruments under	Current liabilities -
SFAS 133:	Fair value of derivatives	$	17,626
Commodity contracts	Non-current liabilities -
	Fair value of derivatives		1,281
Total		$	18,907

Gross to Net Presentation Reconciliation of Derivative Assets and Liabilities

	June 30, 2009
	Assets			Liabilities
	(In thousands)
Fair value of derivatives – gross presentation	$	16,052		$	34,959
Effects of netting arrangements		(16,052	)		(16,052	)
Fair value of derivatives – net presentation	$	-		$	18,907

All of the Company’s derivatives are with JPMorgan Chase Bank, N.A., which has a credit rating of AA- as determined by a nationally recognized statistical ratings organization.  The Company has elected to net the outstanding positions with this counterparty between current and noncurrent assets or liabilities.

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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	2009	2008
		(In thousands)
Derivatives not designated as
hedging instruments under
SFAS 133:
Commodity contracts	Other income (expense) -
	Loss on derivatives	$ (19,260)	$ (194,696)
Total		$ (19,260)	$ (194,696)

8. 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 the Company’s 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 the Company’s Senior Notes at June 30, 2009 and December 31, 2008 was approximately $163.1 million and $126 million respectively, based on market quotes.

Determination of Fair Value

The Company has adopted SFAS 157.  SFAS 157 defines fair value, establishes a framework for measuring fair value, 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.

In accordance with SFAS 157, the Company categorizes its 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, defined by SFAS 157 and 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 fair value of derivative contracts are measured using Level 2 inputs, and are determined by either market prices on an active market for similar assets or by prices quoted by a broker or other market-corroborated prices.

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The estimated fair values of assets and liabilities included in the accompanying consolidated balance sheet at June 30, 2009 are summarized below.  At December 31, 2008, the Company had closed all of its then existing commodity and interest derivatives.

Assets and liabilities measured at fair value on a recurring basis follow:

	Fair Value Measurements
	June 30, 2009
	Significant
	Other
	Observable
	Inputs
Description	(Level 2)
	(In thousands)
Liabilities:
Fair value of commodity derivatives	$         18,907
Total liabilities	$         18,907

Assets measured at fair value on a nonrecurring basis and the related losses recorded for the six months ended June 30, 2009 are as follows:

	Fair Value Measurements
	June 30, 2009
	Significant
	Other		Significant
	Observable		Unobservable
	Inputs		Inputs		Total
Description	(Level 2)		(Level 3)		Losses
	(In thousands)
Assets:
Inventory	$	13,541	$	-	$	3,390
Assets held for sale(a)		-		18,750		32,068
Long-lived assets held and used		14,819		-		12,015
Total assets	$	28,360	$	18,750	$	47,473
(a)For information about Level 3 inputs, see Note 11.

9. Income Taxes

The Company’s effective federal and state income tax benefit rate for the six months ended June 30, 2009 of 36.6% differed from the statutory federal rate of 35% due primarily to increases related to the effects of the Texas Margin Tax and tax benefits derived from excess statutory depletion deductions, offset in part by certain non-deductible expenses.

The Company and its subsidiaries file federal income tax returns with the United States Internal Revenue Service (“IRS”) and state income tax returns in various state tax jurisdictions.  The Company’s tax returns for fiscal years after 2004 currently remain subject to examination by appropriate taxing authorities.  None of the Company’s income tax returns are under examination at this time.

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Upon adoption of FASB Interpretation No. 48 “Accounting for Uncertainty in Income Taxes” - “An Interpretation of FASB Statement No. 109” (“FIN 48”), the Company recorded a liability for taxes payable related to unrecognized tax benefits arising from uncertain tax positions taken by the Company in previous periods.  A reconciliation of the changes in this tax liability as of June 30, 2009 is as follows:

	June 30,
	2009
	(In thousands)
Balance at beginning of period	$	144
Reductions for tax positions of prior years		-
Balance at end of period	$	144

No unrecognized tax benefits originated during the first six months of 2009.  All of the remaining unrecognized tax benefits at June 30, 2009 relate to tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductions.  Because of the impact of deferred tax accounting, the disallowance of the shorter deduction period would not affect the annual effective tax rate but would only accelerate the payment of taxes to the taxing authority or change the amount of deferred tax assets related to net operating loss carryforwards.

Tax liabilities recorded under FIN 48 are included in other non-current liabilities in the accompanying consolidated financial statements, and any interest and penalties accrued on unrecognized tax benefits, are recorded as interest expense in the accompanying statements of operations.  However, due to the Company’s net operating loss carryforwards, no interest or penalties have been accrued on the Company’s unrecognized tax benefits.

10. Investment in Desta Drilling

In April 2006, the Company formed a joint venture with Lariat to construct, own and operate 12 new drilling rigs.  The Company has historically referred to this joint venture as Larclay JV.  In June 2009, the Company changed the legal name of the operating entity in the joint venture to Desta Drilling, LP.  Desta Drilling, LP (formerly Larclay JV) is referred to in these notes to consolidated financial statements as “Desta Drilling”.  Until April 15, 2009, the Company and Lariat each owned a 50% equity interest in Desta Drilling.  Since inception of this joint venture, the Company has made advances structured as subordinated loans to Desta Drilling totaling $12.1 million, $4.6 million to finance excess construction costs and $7.5 million to finance the Company’s 50% share of working capital assessments made by Desta Drilling.  Lariat also advanced Desta Drilling $7.5 million for its 50% share of working capital assessments.  The Company is also a limited guarantor under the Desta Drilling term loan described in Note 4.

In connection with the formation of Desta Drilling, the Company entered into a three-year drilling contract with Desta Drilling assuring the availability of its drilling rigs for use in the ordinary course of the Company’s exploration and development drilling program throughout the term of the drilling contract.  The drilling contract, which is pledged as collateral to secure the Desta Drilling term loan, expires on the earlier of December 31, 2009 or the termination and liquidation of Desta Drilling.  The drilling contract provides for the Company to contract for each drilling rig on a well-by-well basis at then current market rates.  If a drilling rig is not needed by the Company at any time during the term of the contract, Desta Drilling may contract with other operators for the use of such drilling rig, subject to certain restrictions.  If a drilling rig is idle, the contract requires the Company to pay Desta Drilling an idle rig rate ranging from $8,100 per day to $10,300 per day (plus crew labor expenses, if applicable), depending on the size of the drilling rig.  At June 30, 2009, the Company’s maximum potential obligation to pay idle rig rates over the remaining term of the drilling contract, excluding any crew labor expenses, totals approximately $12.3 million.  The Company paid $15.4 million for idle rig fees during the six months ended June 30, 2009.

Effective April 15, 2009, the Company acquired the remaining 50% equity interest in Desta Drilling pursuant to an agreement with Lariat dated March 13, 2009 (the “Assignment”).  The Assignment from Lariat to the Company 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, the Company 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.  

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Upon consummation of the Assignment, the Company contributed all of the subordinated loans to Desta Drilling’s capital.

Prior to the effective date of the Assignment, the Company met the definition of the primary beneficiary of Desta Drilling’s expected cash flows under FIN 46R.  Accordingly, the Company fully consolidated the accounts of Desta Drilling in its consolidated financial statements and accounted for the equity interest owned by Lariat as a noncontrolling interest.  Upon consummation of the Assignment, the Company accounted for the related transactions in accordance with SFAS 160 by recording a non-cash increase in additional paid-in capital of $14.8 million, consisting of the contribution to equity of $7.8 million of principal and accrued interest on subordinated loans obtained from Lariat and the conversion to equity of the $7 million cumulative balance in the noncontrolling interest account attributable to the equity interests acquired from Lariat.

11. Impairment of Property and Equipment

Upon consummation of the Assignment discussed in Note 10, the Company adopted a plan of disposition whereby it would commit to sell eight of the 12 drilling rigs owned by Desta Drilling.  The plan of disposition meets the criteria under SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets (as amended)” (“SFAS 144”) for the designated assets to be classified as held for sale.  SFAS 144 requires the Company 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.  The Company estimates the fair value of the designated assets to be approximately $18.8 million.  As a result, the Company has reclassified the estimated fair value of the designated assets to “Assets Held for Sale” in its balance sheet, and has recorded a related charge for impairment of property and equipment of approximately $32.1 million in its statement of operations for the second quarter of 2009.  Under EITF 03-13, “Applying the Conditions in Paragraph 42 of FASB Statement No. 144 in Determining Whether to Report Discontinued Operations”, the Company has determined that this plan of disposition does not qualify for discontinued operations reporting.

To estimate the fair value of the drilling rigs and related equipment owned by Desta Drilling on the measurement date of April 15, 2009 in accordance with SFAS 157, the Company used a weighting of the market approach and the discounted cash flow approach.  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.  The Company 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.

12. Oil and Gas Properties

The following sets forth the capitalized costs for oil and gas properties as of June 30, 2009 and December 31, 2008.

	June 30,			December 31,
	2009			2008
	(In thousands)
Proved properties	$	1,479,961		$	1,435,718
Unproved properties		84,586			90,755
Total capitalized costs		1,564,547			1,526,473
Accumulated depreciation, depletion and amortization		(851,928	)		(791,507	)
Net capitalized costs	$	712,619		$	734,966

13. Sales of Assets and Inventory Write-downs

The Company recorded a net loss of $3.2 million on sales of assets and inventory write-downs during the six months ended June 30, 2009 related primarily to the write-down of inventory to its estimated market value.

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14. Segment Information

In accordance with SFAS No. 131 “Disclosures about Segments of an Enterprise and Related Information” (“SFAS 131”), the Company has two reportable operating segments, which are oil and gas exploration and production and contract drilling services.

The following tables present selected financial information regarding the Company’s operating segments for the three-month and six-month periods ended June 30, 2009 and 2008.

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

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For the Three Months Ended
June 30, 2008
(Unaudited)				Contract			Intercompany			Consolidated
(In thousands)	Oil and Gas			Drilling			Eliminations			Total
Revenues	$	178,076		$	16,874		$	(3,682	)	$	191,268
Depreciation, depletion and amortization (a)		22,860			2,623			(509	)		24,974
Other operating expenses (b)		37,235			12,753			(2,695	)		47,293
Interest expense		5,136			941			-			6,077
Other (income) expense		145,573			-			-			145,573
Income (loss) before income taxes		(32,728	)		557			(478	)		(32,649	)
Income tax (expense) benefit		11,891			(249	)		-			11,642
Net income (loss)		(20,837	)		308			(478	)		(21,007	)
Less income attributable to
noncontrolling interest, net of tax		-			(164	)		-			(164	)
Net income (loss) attributable to
Clayton Williams Energy, Inc.	$	(20,837	)	$	144		$	(478	)	$	(21,171	)
Total assets	$	826,711		$	95,304		$	(9,574	)	$	912,441
Additions to property and equipment	$	93,395		$	608		$	(478	)	$	93,525

For the Six Months Ended
June 30, 2008
(Unaudited)				Contract			Intercompany			Consolidated
(In thousands)	Oil and Gas			Drilling			Eliminations			Total
Revenues	$	300,102		$	34,037		$	(6,013	)	$	328,126
Depreciation, depletion and amortization (a)		50,848			5,233			(834	)		55,247
Other operating expenses (b)		68,050			25,761			(4,348	)		89,463
Interest expense		11,488			2,035			-			13,523
Other (income) expense		191,027			-			-			191,027
Income (loss) before income taxes		(21,311	)		1,008			(831	)		(21,134	)
Income tax (expense) benefit		7,927			(507	)		-			7,420
Net income (loss)		(13,384	)		501			(831	)		(13,714	)
Less income attributable to
noncontrolling interest, net of tax		-			(278	)		-			(278	)
Net income (loss) attributable to
Clayton Williams Energy, Inc.	$	(13,384	)	$	223		$	(831	)	$	(13,992	)
Total assets	$	826,711		$	95,304		$	(9,574	)	$	912,441
Additions to property and equipment	$	148,826		$	617		$	(831	)	$	148,612

(a)Includes impairment of property and equipment.

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

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15. Guarantor Financial Information

In July 2005, Clayton Williams Energy, Inc. (“Issuer”) issued $225 million of Senior Notes (see Note 4).  Other than West Coast Energy Properties GP, LLC (“WCEP LLC”), the general partner of West Coast Energy Properties, L.P., an affiliated limited partnership, and Desta Drilling (formerly Larclay JV, see Note 10), all of the Issuer’s wholly-owned and active subsidiaries (“Guarantor Subsidiaries”) have jointly and severally, irrevocably and unconditionally guaranteed the performance and payment when due of all obligations under the Senior Notes.  Desta Drilling and WCEP LLC have not guaranteed the Senior Notes and are referred to in this Note 15 as Non-Guarantor Entities.

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

Condensed Consolidating Balance Sheet

June 30, 2009

(Unaudited)					Non-
(Dollars in thousands)			Guarantor		Guarantor		Adjustments/
	Issuer		Subsidiaries		Entities		Eliminations			Consolidated
Current assets	$	207,538	$	211,306	$	28,695	$	(328,421	)	$	119,118
Property and equipment, net		382,490		328,380		23,784		-			734,654
Investments in subsidiaries		72,082		-		-		(72,082	)		-
Other assets		7,004		381		168		(52	)		7,501
Total assets	$	669,114	$	540,067	$	52,647	$	(400,555	)	$	861,273
Current liabilities	$	152,771	$	267,670	$	20,559	$	(328,422	)	$	112,578
Non-current liabilities:
Long-term debt		344,300		-		11,250		-			355,550
Fair value of derivatives		1,281		-		-		-			1,281
Other		62,366		60,629		126		-			123,121
		407,947		60,629		11,376		-			479,952
Equity		108,396		211,768		20,712		(72,133	)		268,743
Total liabilities and
equity	$	669,114	$	540,067	$	52,647	$	(400,555	)	$	861,273

Condensed Consolidating Balance Sheet

December 31, 2008

(Dollars in thousands)					Non-
			Guarantor		Guarantor		Adjustments/
	Issuer		Subsidiaries		Entities		Eliminations			Consolidated
Current assets	$	178,349	$	173,636	$	15,749	$	(242,250	)	$	125,484
Property and equipment, net		388,189		345,327		76,512		-			810,028
Investments in subsidiaries		72,082		-		-		(72,082	)		-
Other assets		19,629		372		211		(12,315	)		7,897
Total assets	$	658,249	$	519,335	$	92,472	$	(326,647	)	$	943,409
Current liabilities	$	83,288	$	253,627	$	28,212	$	(242,250	)	$	122,877
Non-current liabilities:
Long-term debt		319,100		-		40,225		(12,100	)		347,225
Other		95,619		57,301		114		(3	)		153,031
		414,719		57,301		40,339		(12,103	)		500,256
Equity		160,242		208,407		23,921		(72,294	)		320,276
Total liabilities and
equity	$	658,249	$	519,335	$	92,472	$	(326,647	)	$	943,409

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Condensed Consolidating Statement of Operations

Three Months Ended June 30, 2009

(Unaudited)						Non-
(In thousands)				Guarantor		Guarantor			Adjustments/
	Issuer			Subsidiaries		Entities			Eliminations			Consolidated
Total revenue	$	34,094		$	25,054	$	8,473		$	(7,118	)	$	60,503
Costs and expenses		46,624			19,532		34,876			(7,067	)		93,965
Operating income (loss)		(12,530	)		5,522		(26,403	)		(51	)		(33,462	)
Other income (expense)		(27,770	)		1,400		(310	)		-			(26,680	)
Income tax (expense) benefit		21,943			-		-			-			21,943
Noncontrolling interest,
net of tax		(409	)		-		-			-			(409	)
Net income (loss)	$	(18,766	)	$	6,922	$	(26,713	)	$	(51	)	$	(38,608	)

Condensed Consolidating Statement of Operations

Six Months Ended June 30, 2009

(Unaudited)						Non-
(In thousands)				Guarantor		Guarantor			Adjustments/
	Issuer			Subsidiaries		Entities			Eliminations			Consolidated
Total revenue	$	67,633		$	44,233	$	17,779		$	(11,360	)	$	118,285
Costs and expenses		110,443			43,642		40,527			(11,245	)		183,367
Operating income (loss)		(42,810	)		591		(22,748	)		(115	)		(65,082	)
Other income (expense)		(30,669	)		2,769		(807	)		-			(28,707	)
Income tax (expense) benefit		34,321			-		-			-			34,321
Noncontrolling interest,
net of tax		(1,455	)		-		-			-			(1,455	)
Net income (loss)	$	(40,613	)	$	3,360	$	(23,555	)	$	(115	)	$	(60,923	)

Condensed Consolidating Statement of Operations

Three Months Ended June 30, 2008

(Unaudited)							Non-
(In thousands)				Guarantor			Guarantor			Adjustments/
	Issuer			Subsidiaries			Entities			Eliminations			Consolidated
Total revenue	$	127,281		$	51,269		$	17,217		$	(4,499	)	$	191,268
Costs and expenses		39,800			20,972			15,516			(4,021	)		72,267
Operating income (loss)		87,481			30,297			1,701			(478	)		119,001
Other income (expense)		(141,834	)		(8,912	)		(904	)		-			(151,650	)
Income tax benefit		11,642			-			-			-			11,642
Noncontrolling interest,
net of tax		(164	)		-			-			-			(164	)
Net income (loss)	$	(42,875	)	$	21,385		$	797		$	(478	)	$	(21,171	)

Condensed Consolidating Statement of Operations

Six Months Ended June 30, 2008

(Unaudited)							Non-
(In thousands)				Guarantor			Guarantor			Adjustments/
	Issuer			Subsidiaries			Entities			Eliminations			Consolidated
Total revenue	$	207,513		$	93,242		$	34,580		$	(7,209	)	$	328,126
Costs and expenses		79,671			40,100			31,317			(6,378	)		144,710
Operating income (loss)		127,842			53,142			3,263			(831	)		183,416
Other income (expense)		(190,103	)		(12,490	)		(1,957	)		-			(204,550	)
Income tax benefit		7,420			-			-			-			7,420
Noncontrolling interest,
net of tax		(278	)		-			-			-			(278	)
Net income (loss)	$	(55,119	)	$	40,652		$	1,306		$	(831	)	$	(13,992	)

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Condensed Consolidating Statement of Cash Flows

Six Months Ended June 30, 2009

(Unaudited)							Non-
(In thousands)				Guarantor			Guarantor			Adjustments/
	Issuer			Subsidiaries			Entities			Eliminations			Consolidated
Operating activities	$	47,424		$	(13,800	)	$	4,096		$	2,150		$	39,870
Investing activities		(106,413	)		(2,357	)		29,817			(2,150	)		(81,103	)
Financing activities		33,188			15,932			(33,143	)		-			15,977
Net increase (decrease) in
cash and cash equivalents		(25,801	)		(225	)		770			-			(25,256	)
Cash at the beginning of
the period		35,381			1,810			4,008			-			41,199
Cash at end of the period	$	9,580		$	1,585		$	4,778		$	-		$	15,943

Condensed Consolidating Statement of Cash Flows

Six Months Ended June 30, 2008

(Unaudited)							Non-
(In thousands)				Guarantor			Guarantor			Adjustments/
	Issuer			Subsidiaries			Entities			Eliminations			Consolidated
Operating activities	$	72,828		$	72,085		$	3,675		$	833		$	149,421
Investing activities		37,709			(46,480	)		(839	)		(833	)		(10,443	)
Financing activities		(103,553	)		(25,166	)		(5,111	)		-			(133,830	)
Net increase (decrease) in
cash and cash equivalents		6,984			439			(2,275	)		-			5,148
Cash at the beginning of
the period		5,325			1,288			5,731			-			12,344
Cash at end of the period	$	12,309		$	1,727		$	3,456		$	-		$	17,492

16. Subsequent Events

 The Company has evaluated events and transactions that occurred after the balance sheet date of June 30, 2009 through August 10, 2009, the date the financial statements were available to be issued.  On August 10, 2009, Desta Drilling became a guarantor subsidiary by irrevocably and unconditionally guarantying the performance and payment when due of all obligations under the Senior Notes.

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

The following discussion is intended to provide information relevant to an understanding of our financial condition, changes in our financial condition and our results of operations and cash flows and should be read in conjunction with our consolidated financial statements and notes thereto included elsewhere in this Form 10-Q and in our Form 10-K for the year ended December 31, 2008.

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, 2008.

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;

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• 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, 2008.

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, 2008 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.

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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 economic climate in the domestic oil and gas industry was suitable for our business model.  Until the second half of 2008, oil and gas prices were favorable and provided us with the economic incentives necessary to assume the risks we face in our search for oil and gas reserves despite higher drilling, completion and operating expenses.

During the second half of 2008, global economies began to experience a significant slowdown sparked by a near-collapse in worldwide financial markets.  This slowdown continued to intensify into 2009 and is currently being viewed by many economists as the most severe recession in United States history, second only to the Great Depression.  The United States government has taken significant steps to support the financial markets and stimulate the economy in an effort to slow or reverse the downward spiral of economic indicators, but the success of these measures and the duration of the current recession cannot be predicted.

Reduced demand for energy caused by the current recession has resulted in a significant deterioration in oil and gas prices, which in turn has led to a significant reduction in drilling activity throughout the oil and gas industry.  The prices we pay for field services generally lag behind the declines in oil and gas prices.  As a result, we have experienced reductions in operating margins during the last half of 2008 and into the first six months of 2009.  The effects of lower operating margins on our business are significant since they reduce our cash flow from operations and diminish the present value of our oil and gas reserves.  These factors have an adverse effect on our ability to access the capital resources we need to grow our reserve base.  Lower operating margins also offer us less incentive to assume the drilling risks that are inherent in our business.

During the second quarter of 2009, operating margins improved somewhat due to a combination of higher oil prices and lower rates for field services caused by decreased demand for those services.  Since most of our developmental drilling locations are oil-prone, we have elected to resume drilling developmental oil wells in the Permian Basin and the Austin Chalk (Trend) during the last half of 2009.  As a result, we now plan to spend approximately $113.8 million on exploration and development activities in fiscal 2009, an increase of $35.3 million over our previous estimate.  By comparison, we spent $372.7 million in fiscal 2008 on exploration and development activities.

We continue to monitor the impact of the recession on our business, including the extent to which changes in commodity prices could affect our financial liquidity.  While we believe we are taking appropriate actions to preserve our short-term liquidity, a prolonged recession of this magnitude could negatively impact our long-term liquidity, financial position and results of operations.

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 2009 and the outlook for the remainder of 2009.

·   Our oil and gas sales for the second quarter decreased $77.1 million, or 57%, from 2008 due substantially to decreases in prices for both oil and gas.

·   Our oil and gas production for the second quarter of 2009 was 2% lower on a barrel of oil equivalent (“BOE”) basis than in the comparable period in 2008.  Our oil production was 2% higher than the second quarter of 2008, while gas production dropped 8% compared to the 2008 period.

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·   Effective April 15, 2009, we acquired the remaining 50% equity ownership in the contract drilling joint venture we formed in 2006 with Lariat Services, Inc. (“Lariat”).  We have historically referred to this joint venture as Larclay JV.  In June 2009, we changed the legal name of the operating entity in the joint venture to Desta Drilling, LP.  Desta Drilling, LP is referred to in this Form 10-Q as “Desta Drilling”.

·   Concurrent with obtaining 100% control of Desta Drilling, we adopted a plan of disposition to sell eight of Desta Drilling’s 12 drilling rigs.  As a result, we recorded a $32.1 million impairment of property and equipment to write-down the rigs to their estimated fair value of $18.8 million and designated the rigs as “Assets Held for Sale” in the accompanying consolidated balance sheet.

·   We recorded a $21.8 million net loss on derivatives in the second quarter of 2009, 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.

·   During the second quarter of 2009, we increased borrowings under our revolving credit facility by $25.2 million from $94.1 million at December 31, 2008 to $119.3 million at June 30, 2009 in order to partially finance additions to property and equipment.

·   At June 30, 2009, our capitalized unproved oil and gas properties totaled $84.6 million, of which approximately $37.4 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.

Recent Exploration and Development Activities

Overview

The current economic recession has caused us to significantly reduce the level of developmental drilling pending an improvement in product prices and operating margins.  Approximately 70% of the $58.1 million spent on exploration and development activities during the first half of 2009 was applicable to exploratory prospects.  These prospects were primarily in areas where we have invested significant capital in acreage and seismic data, or were prospects for which we had made drilling commitments to joint owners in the wells.  Due to recent improvements in operating margins attributable to higher oil prices and lower costs for field services, we have elected to resume drilling developmental oil wells in the Permian Basin and the Austin Chalk (Trend) during the last half of 2009.  As a result, we now plan to spend approximately $113.8 million on exploration and development activities during 2009, of which approximately 54% 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) encouraged high levels of current 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.

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We spent $14.3 million in the Permian Basin during the first half of 2009 on drilling and completion activities and $400,000 was spent on seismic and leasing activities.  We drilled 9 gross (8.8 net) operated wells in the Permian Basin and conducted various remedial operations on other wells in 2009.  In response to recent improvements in operating margins, we have begun a drilling program in Andrews County targeting the Wolfcamp/Spraberry formations and currently have two of our drilling rigs employed in this program with plans to add one additional rig before year-end.  We currently plan to spend approximately $44 million on drilling and completion activities in the Permian Basin in fiscal 2009.

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, 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.  The existing spacing between some of our wells in this area affords us the opportunity to tap additional oil and gas reserves by drilling new wells between existing wells, a technique referred to as in-fill drilling.  These in-fill wells are considered lower risk as compared to exploratory wells and until recently, offered more attractive rates of return.

We spent $200,000 in the Austin Chalk (Trend) area during the first half of 2009.  In response to recent improvements in operating margins, we have resumed our in-fill drilling program in the Austin Chalk (Trend) and currently have one of our drilling rigs employed in this program with plans to add one additional rig before year-end.  We currently plan to spend approximately $14.8 million on drilling and completion activities in the Austin Chalk (Trend) in fiscal 2009.

South Louisiana

We participated in the drilling of the State Lease 18669 #1, an exploratory well in Plaquemines Parish (West Lake Washington prospect) in 2008.  The well was completed as a producer in June 2009.  We own a 50% non-operated working interest in this well.

We have abandoned the drilling of the Miami Corp #1, an exploratory well in Bayou Sale field on our Liger prospect in St. Mary Parish, due to down hole mechanical problems.  We have moved the drilling rig approximately 20 feet north of the current location and are drilling the Miami Corp #2 as a replacement well.  We have modified the drilling plan to address the problems encountered in the first well, and will target the same formation in the lower Miocene sands at an approximate depth of 17,500 feet.  We will own a 50% working interest in any production established by this well.  At June 30, 2009, we had incurred drilling costs aggregating $15.5 million in connection with these wells.

We spent $20.2 million in South Louisiana during the first half of 2009 on exploration and development activities, of which $18.4 million was spent on drilling and completion activities and $1.8 million was spent on seismic and leasing activities.  We currently plan to spend $24.4 million for fiscal 2009, of which $21.7 million relates to drilling and completion activities and the remaining $2.7 million relates to seismic and leasing activities.

North Louisiana

In 2005, we began a drilling program in North Louisiana targeting the Cotton Valley/Gray and Bossier formations.  In this area, the Cotton Valley/Gray formations are encountered at depths ranging from 8,000 to 12,000 feet, and the Bossier formation is encountered at depths ranging from 11,000 to 15,500 feet.  

To date, we have drilled 18 wells on our Terryville prospect and have completed 16 as producers.  On our Ruston prospect, we have completed four wells as producers.  We spent $3.2 million in North Louisiana during the first half of 2009 on exploration and development activities, of which $2.9 million was spent on drilling and completion activities and $300,000 was spent on seismic and leasing activities.  We currently plan to spend $4.6 million for fiscal 2009 in this area.

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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 if the deep Bossier sand will be commercially productive is to drill wells to the targeted structures.

We have drilled the Sunny Unit #1, a 17,300-foot exploratory well in Burleson County, Texas to the deep Bossier formation, and have completed the well in the middle Bossier sands.  The well was recently tested at a rate of 5,400 Mcf per day at 5,500 psi on a 13/64-inch choke, but due to the absence of a suitable gas market in the area, the well is currently shut-in while we determine which, if any, of the various marketing alternatives are economically viable.  At June 30, 2009, we had incurred drilling costs of approximately $18.4 million on this well (100% working interest).

We spent $15 million in the East Texas Bossier area during the first half of 2009 on exploration and development activities, of which $7 million was spent on drilling and completion activities and $8 million was spent on seismic and leasing activities.  We currently plan to spend approximately $18.7 million for fiscal 2009, of which $7.9 million relates to drilling and completion activities and the remaining $10.8 million relates to seismic and leasing activities.

Utah

In 2008, we participated in the drilling of the Ron Lamb 31A-4-1, a 12,670-foot exploratory well in which we own a 33% non-operated working interest. The well was drilled in the central Overthrust area in Sanpete County, Utah targeting the oil-prone Navajo sandstone formation. We temporarily abandoned this well in the first quarter of 2009 and recorded a pre-tax charge of approximately $1.6 million for drilling and leasehold impairments related to this well in the first six months of 2009. Plans to participate in the drilling of a third exploratory well in this area have been deferred until 2010.

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Supplemental Information

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

	Three Months Ended
	June 30,
	2009			2008
Oil and Gas Production Data:
Gas (MMcf)		3,856			4,177
Oil (MBbls)		716			703
Natural gas liquids (MBbls)		59			41
Total (MBOE)		1,418			1,440
Average Realized Prices (a):
Gas ($/Mcf)	$	3.84		$	11.07
Oil ($/Bbl)	$	56.55		$	121.51
Natural gas liquids ($/Bbl)	$	24.53		$	63.63
Gain (Loss) on Settled Derivative Contracts (a):
($ in thousands, except per unit)
Gas:Net realized gain (loss)	$	3,088		$	(10,287	)
Per unit produced ($/Mcf)	$	.80		$	(2.46	)
Oil:Net realized loss	$	(4,572	)	$	(23,348	)
Per unit produced ($/Bbl)	$	(6.39	)	$	(33.21	)
Average Daily Production:
Gas (Mcf):
Permian Basin		15,432			14,284
North Louisiana		11,445			15,233
South Louisiana		7,699			7,347
Austin Chalk (Trend)		2,412			2,133
Cotton Valley Reef Complex		3,781			6,277
Other		1,605			627
Total		42,374			45,901
Oil (Bbls):
Permian Basin		4,058			3,568
North Louisiana		273			386
South Louisiana		701			105
Austin Chalk (Trend)		2,742			3,575
Other		94			91
Total		7,868			7,725
Natural Gas Liquids (Bbls):
Permian Basin		248			153
North Louisiana		37			5
South Louisiana		60			41
Austin Chalk (Trend)		290			241
Other		13			11
Total		648			451

(Continued)

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	Three Months Ended
	June 30,
	2009		2008
Exploration Costs (in thousands):
Abandonment and impairment costs:
North Louisiana	$	848	$	1,865
South Louisiana		85		-
Permian Basin		309		-
East Texas Bossier		1,917		-
Utah		558		-
Other		788		68
Total		4,505		1,933
Seismic and other		1,388		1,562
Total exploration costs	$	5,893	$	3,495
Depreciation, Depletion and Amortization (in thousands):
Oil and gas depletion	$	25,671	$	22,598
Contract drilling depreciation		305		2,115
Other depreciation		210		261
Total DD&A	$	26,186	$	24,974
Oil and Gas Costs ($/BOE Produced):
Production costs	$	12.90	$	15.23
Oil and gas depletion	$	18.10	$	15.69
Net Wells Drilled (b):
Exploratory Wells		1.2		1.0
Developmental Wells		5.9		22.7

	Six Months Ended
	June 30,
	2009			2008
Oil and Gas Production Data:
Gas (MMcf)		8,469			9,725
Oil (MBbls)		1,467			1,387
Natural gas liquids (MBbls)		112			99
Total (MBOE)		2,991			3,107
Average Realized Prices (a):
Gas ($/Mcf)	$	4.25		$	9.81
Oil ($/Bbl)	$	46.55		$	109.05
Natural gas liquids ($/Bbl)	$	23.78		$	58.47
Gain (Losses) on Settled Derivative Contracts (a):
($ in thousands, except per unit)
Gas:     Net realized gain (loss)	$	4,486		$	(11,171	)
Per unit produced ($/Mcf)	$	.53		$	(1.15	)
Oil:       Net realized loss	$	(4,839	)	$	(36,254	)
Per unit produced ($/Bbl)	$	(3.30	)	$	(26.14	)

(Continued)

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	Six Months Ended
	June 30,
	2009		2008
Average Daily Production:
Natural Gas (Mcf):
Permian Basin		15,553		14,665
North Louisiana		12,989		14,611
South Louisiana		10,132		15,405
Austin Chalk (Trend)		2,718		2,333
Cotton Valley Reef Complex		4,026		5,857
Other		1,372		563
Total		46,790		53,434
Oil (Bbls):
Permian Basin		4,256		3,532
North Louisiana		271		365
South Louisiana		548		545
Austin Chalk (Trend)		2,942		3,104
Other		88		75
Total		8,105		7,621
Natural Gas Liquids (Bbls):
Permian Basin		238		185
North Louisiana		19		3
South Louisiana		52		89
Austin Chalk (Trend)		299		258
Other		11		9
Total		619		544
Exploration Costs (in thousands):
Abandonment and impairment costs:
Permian Basin	$	764	$	-
North Louisiana		1,108		2,162
South Louisiana		813		-
East Texas Bossier		10,784		-
Utah		2,332		-
Other		1,116		68
Total		16,917		2,230
Seismic and other		5,658		5,237
Total exploration costs	$	22,575	$	7,467
Depreciation, Depletion and Amortization (in thousands):
Oil and gas depletion	$	60,433	$	50,339
Contract drilling depreciation		1,779		4,400
Other depreciation		439		508
Total DD&A	$	62,651	$	55,247
Oil and Gas Costs ($/BOE Produced):
Production costs	$	12.49	$	13.68
Oil and gas depletion	$	20.20	$	16.20
Net Wells Drilled (b):
Exploratory Wells		1.4		2.7
Developmental Wells		11.9		35.7
(a)No derivatives were designated as cash flow hedges in 2009 or 2008. 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.

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Operating Results – Three-Month Periods

The following discussion compares our results for the three months ended June 30, 2009 to the comparative period in 2008.  Unless otherwise indicated, references to 2009 and 2008 within this section refer to the respective quarterly period.

Oil and gas operating results

Oil and gas sales in 2009 decreased $77.1 million, or 57%, from 2008.  Price variances accounted for substantially all of this decrease.  Production in 2009 (on a BOE basis) was 2% lower than 2008, despite significant additions from our developmental drilling programs.  Oil production increased 2% in 2009 from 2008 and gas production decreased 8% in 2009 from 2008.  In 2009, our realized oil price was 53% lower than 2008, while our realized gas price was 65% lower.  Historically, the markets for oil and gas have been volatile, and they are likely to continue to be volatile.

Production costs, consisting of lease operating expenses, production taxes and other miscellaneous marketing costs, decreased 17% in 2009 as compared to 2008 due primarily to effects lower commodity prices had on production taxes and the overall reduction in oilfield service costs.  After giving effect to a 2% decrease in oil and gas production on a BOE basis, production costs per BOE decreased 15% from $15.23 per BOE in 2008 to $12.90 per BOE in 2009.

Oil and gas depletion expense increased $3.1 million from 2008 to 2009, of which rate variances accounted for a $3.4 million increase and production variances accounted for a $300,000 decrease.  On a BOE basis, depletion expense increased 15% from $15.69 per BOE in 2008 to $18.10 per BOE in 2009 due to a combination of higher depletable costs and lower estimated reserve quantities in 2009 compared to the 2008 period.  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 2009, we charged to expense $5.9 million of exploration costs, as compared to $3.5 million in 2008.

At June 30, 2009, our capitalized unproved oil and gas properties totaled $84.6 million, of which approximately $37.4 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.

We plan to spend approximately $113.8 million on exploration and development activities in fiscal 2009, of which approximately 46% is expected to be allocated to exploration activities.  Since exploratory drilling involves a high degree of risk, it is likely that a significant portion of the costs we incur in 2009 will be charged to exploration costs.  However, we cannot predict our success rates and, accordingly, cannot predict our exploration costs related to abandonment and impairment costs.

Contract Drilling Services

In 2006, we formed a joint venture with Lariat Services, Inc. (“Lariat”) to construct, own, and operate 12 new drilling rigs.  Until April 15, 2009, we owned a 50% equity interest in this joint venture that we have historically referred to as Larclay JV and which we now refer to as Desta Drilling.  As primary beneficiary of Desta Drilling’s expected cash flows under FIN 46R, 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.  Effective April 15, 2009, we acquired the remaining 50% equity interest in Desta Drilling.

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We utilize drilling rigs owned by Desta Drilling to drill wells in our exploration and development activities.  In 2006 we entered into a three-year drilling contract with Desta Drilling under which we contract for each drilling rig on a well-by-well basis at then current market rates.  If a drilling rig is not needed by us at any time during the term of the contract, which expires December 31, 2009, we are obligated to pay Desta Drilling an idle rig rate ranging from $8,100 per day to $10,300 per day (plus crew labor expenses, if applicable), depending on the size of the drilling rig, for each rig that is not being utilized.  In 2009, we paid Desta Drilling $97,000 for drilling services and $8.2 million for idle rig charges as compared to $7.9 million and $427,000, respectively, in 2008.

All intercompany transactions are eliminated in consolidation to the extent of our equity ownership in Desta Drilling.  Accordingly, consolidated contract drilling revenues and contract drilling services costs may vary significantly based on our equity ownership and the percentage of revenues derived from CWEI.  Contract drilling revenues in 2009, after eliminations, decreased 88% to $1.5 million from $12.7 million in 2008 due to a combination of reduced drilling activity and an increase in the percentage of revenues derived from CWEI.  For the same reasons, contract drilling services costs in 2009, after eliminations, decreased 71% to $2.9 million from $9.9 million in 2008.

In April 2009, we adopted a plan of disposition to sell eight of the 12 drilling rigs owned by Desta Drilling.  As a result, we recorded a $32.1 million impairment of property and equipment to write-down the rigs to their estimated fair value of $18.8 million and designated the rigs as “Assets Held for Sale” in the accompanying consolidated balance sheet.

General and Administrative

General and administrative (“G&A”) expenses decreased 21% from $7.9 million in 2008 to $6.3 million in 2009.  Excluding employee compensation related to non-equity incentive plans, G&A expenses decreased from $6.4 million in 2008 to $5 million in 2009 due in part to a one-time charge in 2008 for cash bonuses paid to employees relating to the sale of certain properties in South Louisiana and a decrease in professional fees.  Employee compensation expense related to non-equity incentive plans was $1.3 million in 2009 compared to $1.5 million in 2008.

Interest expense

Interest expense decreased 6% from $6.1 million in 2008 to $5.7 million in 2009 primarily due to lower interest rates and lower average levels of debt.  The average daily principal balance outstanding under our revolving credit facility for 2009 was $116.5 million compared to $94.1 million for 2008.  Increases on our revolving credit facility accounted for a $236,000 increase in interest expense, while lower interest rates resulted in a decrease of approximately $527,000.  In addition, capitalized interest for 2009 was $144,000 compared to $907,000 in 2008, and interest expense associated with Desta Drilling’s term loan during 2009 was $303,000 compared to $941,000 in 2008.

Gain/loss on derivatives

We did not designate any derivative contracts in 2009 or 2008 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, 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.  For the three months ended June 30, 2008, we reported a $148.6 million net loss on derivatives, consisting of a $113.6 million non-cash loss to mark our derivative positions to their fair value at June 30, 2008 and a $35 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.

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Gain/loss on sales of assets and inventory write-downs

We recorded a net gain of $84,000 on sales of assets and inventory write-downs for the second quarter of 2009 related to the sale of a property offset by the write-down of inventory to its estimated market value at June 30, 2009.  In 2008, we recorded a net gain of $40.4 million on sales of property and equipment, which included a $33.1 million gain on the sale of properties in South Louisiana and $5.7 million of gains on the sales of two drilling rigs and a surplus well servicing unit.

Income tax expense

Our estimated effective income tax benefit rate in 2009 of 36.5% differed from the statutory federal rate of 35% due primarily to increases related to the effects of the Texas Margin Tax and tax benefits derived from excess statutory depletion deductions, offset in part by the effects of certain non-deductible expenses.

Operating Results – Six-Month Periods

The following discussion compares our results for the six months ended June 30, 2009 to the comparative period in 2008.  Unless otherwise indicated, references to 2009 and 2008 within this section refer to the respective six-month period.

Oil and gas operating results

Oil and gas sales in 2009 decreased $145.2 million, or 57%, from 2008.  Price variances accounted for a $144 million decrease, and production variances accounted for a $1.2 million decrease.  Production in 2009 (on a BOE basis) was 4% lower than 2008.  Oil production increased 6% and gas production decreased 13% in 2009 from 2008.  In 2009, our realized oil price and our realized gas price were both 57% lower than 2008.  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, decreased 12% in 2009 as compared to 2008 due primarily to the effects lower commodity prices had on production taxes.  After giving effect to a 4% decrease in oil and gas production on a BOE basis, production costs per BOE decreased 9% from $13.68 per BOE in 2008 to $12.49 per BOE in 2009.

Oil and gas depletion expense increased $10.1 million from 2008 to 2009, of which rate variances accounted for a $12 million increase and production variances accounted for a $1.9 million decrease.  On a BOE basis, depletion expense increased 25% from $16.20 per BOE in 2008 to $20.20 per BOE in 2009 due to a combination of higher depletable cost basis and higher depletion rates caused by lower estimated reserves.  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 2009, we charged to expense $22.6 million of exploration costs, as compared to $7.5 million in 2008.

At June 30, 2009, our capitalized unproved oil and gas properties totaled $84.6 million, of which approximately $37.4 million was attributable to unproved acreage.  Unproved properties are subject to a valuation impairment to the extent the carrying cost of a prospect exceeds its estimated fair value.  Therefore, our results of operations in future periods may be adversely affected by unproved property impairments.

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We plan to spend approximately $113.8 million on exploration and development activities in 2009, of which approximately 46% is expected to be allocated to exploration activities.  Since exploratory drilling involves a high degree of risk, it is likely that a significant portion of the costs we incur in 2009 will be charged to exploration costs. However, we cannot predict our success rates and, accordingly, cannot predict our exploration costs related to abandonment and impairment costs.

Contract Drilling Services

In 2006, we formed a joint venture with Lariat to construct, own, and operate 12 new drilling rigs.  Until April 15, 2009, we owned a 50% equity interest in this joint venture that we refer to as Desta Drilling (formerly Larclay JV).  As primary beneficiary of Desta Drilling’s expected cash flows under FIN 46R, 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.  Effective April 15, 2009, we acquired the remaining 50% equity interest in Desta Drilling.

We utilize drilling rigs owned by Desta Drilling to drill wells in our exploration and development activities.  In 2006 we entered into a three-year drilling contract with Desta Drilling under which we contract for each drilling rig on a well-by-well basis at then current market rates.  If a drilling rig is not needed by us at any time during the term of the contract, which expires December 31, 2009, we are obligated to pay Desta Drilling an idle rig rate ranging from $8,100 per day to $10,300 per day (plus crew labor expenses, if applicable), depending on the size of the drilling rig, for each rig that is not being utilized.  In 2009, we paid Desta Drilling $859,000 for drilling services and $15.4 million for idle rig charges as compared to $12.9 million and $427,000, respectively, in 2008.

All intercompany transactions are eliminated in consolidation to the extent of our equity ownership in Desta Drilling.  Accordingly, consolidated contract drilling revenues and contract drilling services costs may vary significantly based on our equity ownership and the percentage of revenues derived from CWEI.  Contract drilling revenues in 2009, after eliminations, decreased 76% to $6.7 million from $27.5 million in 2008 due to a combination of reduced drilling activity and an increase in the percentage of revenues derived from CWEI.  For the same reasons, contract drilling services costs in 2009, after eliminations, decreased 52% to $10 million from $21 million in 2008.

In April 2009, we adopted a plan of disposition to sell eight of the 12 drilling rigs owned by Desta Drilling.  As a result, we recorded a $32.1 million impairment of property and equipment to write-down the rigs to their estimated fair value of $18.8 million and designated the rigs as “Assets Held for Sale” in the accompanying consolidated balance sheet.

General and Administrative

G&A expenses decreased 5% from $11.4 million in 2008 to $10.8 million in 2009.  Excluding employee compensation related to non-equity incentive plans, G&A expenses decreased from $9.5 million in 2008 to $8.8 million in 2009 due in part to a one-time charge in 2008 for cash bonuses paid to employees relating to the sale of certain properties in South Louisiana and a decrease in professional fees.  Employee compensation expense related to non-equity incentive plans was $2 million in 2009 compared to $1.9 million in 2008.

Interest expense

Interest expense decreased 17% from $13.5 million in 2008 to $11.2 million in 2009 due to a combination of reduced debt levels and lower interest rates. Debt reductions accounted for $887,000 of the decrease, while lower interest rates resulted in a decrease of approximately $1.3 million.  The average daily principal balance outstanding under our revolving credit facility for 2009 was $106.2 million compared to $134.3 million for 2008.  During 2008, we received approximately $114 million from the sale of assets and used the net proceeds to reduce indebtedness outstanding under our revolving credit facility.  In addition, capitalized interest for 2009 was $465,000 compared to $1.7 million in 2008, and interest expense associated with Desta Drilling’s term loan during 2009 was $725,000 compared to $2 million in 2008.

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Gain/loss on derivatives

We did not designate any derivative contracts in 2009 or 2008 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, 2009, we reported a $19.3 million net loss on derivatives, consisting of a $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.  For the six months ended June 30, 2008, we reported a $194.7 million net loss on derivatives, consisting of a $145.6 million non-cash loss to mark our derivative positions to their fair value at June 30, 2008 and a $49.1 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 inventory write-downs

We recorded a net loss of $3.2 million on sales of assets and inventory write-downs for 2009 related primarily to the write-down of inventory to its estimated market value at June 30, 2009.  In 2008, we recorded a net gain on sales of property and equipment of $41 million, which included a $33.1 million gain on sales of properties in South Louisiana and $5.7 million of gains on the sales of two drilling rigs and a surplus well servicing unit.

Income tax expense

Our effective income tax benefit rate in 2009 of 36.6% differed from the statutory federal rate of 35% due primarily to increases related to the effects of the recently-enacted Texas Margin Tax and tax benefits derived from statutory depletion deductions, offset by the effects of certain non-deductible expenses.

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 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.

During the last half of 2008, the economic climate in the oil and gas industry experienced a rapid adverse change.  Oil and gas prices have fallen drastically, yet reductions in the cost of field services have lagged behind the decline in oil and gas prices.  As a result, we have experienced reductions in operating margins and have realized downward revisions in our proved reserves.  The effects of lower operating margins on our business are significant since they reduce our cash flow from operations and diminish the estimated present value of our oil and gas reserves.  These factors have an adverse affect on our ability to access the capital resources we need to grow our reserve base.  Downward revisions in estimated proved reserves can adversely affect the amount of funds we can borrow on the credit facility.  Lower operating margins also offer us less incentive to assume the drilling risks that are inherent in our business.  In response to decreases in product prices and the resulting effect on our operating margins, we have reduced our level of capital spending for 2009 as compared to 2008.  Currently, we plan to spend approximately $113.8 million on exploration and development activities in fiscal 2009 as compared to $372.7 million spent in fiscal 2008.

The Indenture governing the issuance of our 7¾% Senior Notes due 2013 contains covenants that restrict our ability to borrow money.  Based on current product prices, we do not expect these covenants to significantly limit our ability to borrow under the revolving credit facility.  However, these covenants could limit our ability to borrow funds in future periods if product prices deteriorate further and remain low for an extended period of time.

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We are monitoring the impact of the recession on our business, including the extent to which lower commodity prices could affect our financial liquidity.  While we believe we are taking appropriate actions to preserve our short-term liquidity, a prolonged recession of this magnitude could negatively impact our long-term liquidity, financial position and results of operations.

Capital expenditures

We incurred expenditures for exploration and development activities of $58.1 million during the first six months of 2009 and have increased our estimates for planned expenditures for fiscal 2009 from $78.5 million to $113.8 million.  Most of the increase is attributable to additional planned developmental drilling in the Permian Basin and the Austin Chalk (Trend) as a result of recent improvements in operating margins for oil production.  The following table summarizes, by area, our actual expenditures for exploration and development activities for the first half of 2009 and our planned expenditures for the year ending December 31, 2009.

	Actual		Planned
	Expenditures		Expenditures		Year 2009
	Six Months Ended		Year Ending		Percentage
	June 30, 2009		December 31, 2009		of Total
	(In thousands)
Permian Basin	$	14,700	$	44,000		39	%
South Louisiana		20,200		24,400		21	%
East Texas Bossier		15,000		18,700		16	%
Austin Chalk (Trend)		200		14,800		13	%
Utah/California		4,100		6,700		6	%
North Louisiana		3,200		4,600		4	%
Other		700		600		1	%
	$	58,100	$	113,800		100	%

Our actual expenditures during fiscal 2009 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.  Other factors, such as prevailing product prices and the availability of capital resources, could also increase or decrease the ultimate level of expenditures during the remainder of fiscal 2009.

Approximately 46% of the 2009 planned expenditures relate to exploratory prospects.  Exploratory prospects involve a higher degree of risk than developmental prospects.  To offset the higher risk, we generally strive to achieve a higher reserve potential and rate of return on investments in exploratory prospects.  We do not attempt to forecast our success rate on exploratory drilling.  Accordingly, these current estimates do not include costs we may incur to complete any future successful exploratory wells and construct the required production facilities for these wells.  We are also actively searching for other opportunities to increase our oil and gas reserves, including the evaluation of new prospects for exploratory and developmental drilling activities and potential acquisitions of proved oil and gas properties.  We cannot predict our drilling success on exploratory prospects, and our future results of operations and financial condition could be adversely affected by unsuccessful exploratory drilling results.

Our expenditures for exploration and development activities for the six months ended June 30, 2009 totaled $58.1 million, of which approximately 70% was on exploratory prospects. 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 the sale of assets.

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During 2009, we increased our inventory of tubing, casing, pumping units and other equipment to be used in our on-going exploration and development activities by $12.3 million.  In addition, we have placed firm orders for similar equipment inventory totaling approximately $26 million, which is currently expected to be filled during the third quarter of 2009.  We plan to use cash flow from operating activities and funds available to us under the revolving credit facility to finance the purchase of this equipment.

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, 2009 decreased $109.6 million, or 73.3%, as compared to the corresponding period in 2008 due primarily to a 57% drop in oil and gas sales caused by lower commodity prices.  The decrease was offset in part by an approximate $4 million increase in operating cash flow attributable to Desta Drilling.  All of Desta Drilling’s cash flow is dedicated to the repayment of its term loan facility.

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.  On May 20, 2009, the borrowing was affirmed at $250 million.  The next scheduled redetermination is in November 2009.

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 material domestic subsidiaries, excluding Desta Drilling.

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 traunches are due at maturity of each traunche 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, 2009 was 2.4%.

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.

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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 $2.6 million at December 31, 2008 to $6.5 million at June 30, 2009.  After giving effect to the adjustments, our working capital computed for loan compliance purposes was $147.1 million at June 30, 2009, as compared to $170.9 million at December 31, 2008.  The following table reconciles our GAAP working capital to the working capital computed for loan compliance purposes at June 30, 2009 and December 31, 2008.

	June 30,			December 31,
	2009			2008
	(In thousands)
Working capital per GAAP	$	6,540		$	2,607
Add funds available under the revolving credit facility		129,896			155,096
Exclude fair value of derivatives classified as current assets or current liabilities		17,626			-
Exclude current assets and current liabilities of Desta Drilling		(6,950	)		13,205
Working capital per loan covenant	$	147,112		$	170,908

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, 2009.  However, our increased leverage and reduced liquidity may result in our failing 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.

We are permitted to make a one-time investment in Desta Drilling (the “Investment”) for the purpose of repaying amounts outstanding under the Desta Drilling term loan, provided that concurrently with such Investment, among other things (1) Desta Drilling grants a security interest in substantially all of its assets to the collateral agent under the revolving credit facility and (2) we pledge our equity interests in Desta Drilling to the administrative agent under the revolving credit facility.  If we make the Investment, Desta Drilling will become a subsidiary for all purposes under the revolving credit facility and therefore covenants under the revolving credit facility applicable to our subsidiaries will be applicable to Desta Drilling.

The lending group under the revolving credit facility includes the following institutions:  JPMorgan Chase Bank, N.A., Union Bank of California, N.A., Bank of Scotland, BNP Paribas, Fortis Capital Corp., Guaranty Bank, Natixis, Bank of Texas, N.A., and Frost Bank.

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, 2009, 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 2009, we increased indebtedness outstanding under the revolving credit facility by $25.2 million.  At June 30, 2009, we had $119.3 million of borrowings outstanding under the revolving credit facility, leaving $129.9 million available on the facility after allowing for outstanding letters of credit totaling $804,000.  At August 4, 2009, we had $141.2 million of borrowings under the revolving credit facility, leaving $108 million available on the facility.  The revolving credit facility matures in May 2012.

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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 103.875% for the twelve-month period beginning on August 1, 2009, 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).  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, 2009.

Desta Drilling Term Loan

In April 2006, Desta Drilling (formerly Larclay JV) obtained a $75 million secured term loan facility from a lender to finance the construction and equipping of 12 new drilling rigs.  The Desta Drilling term loan is secured by substantially all of Desta Drilling’s assets.  As additional credit support, we granted the lender a limited guaranty in the original amount of $19.5 million.  The maximum obligation under the guaranty reduces by 10% on April 1 of each year, beginning April 1, 2008.  At June 30, 2009, our maximum obligation under the guaranty was approximately $15.8 million.  Although we are not obligated under the Desta Drilling term loan except to the extent of the guaranty, we fully consolidate the accounts of Desta Drilling.

The Desta Drilling term loan bears interest at a floating rate based on a LIBOR average, plus 3.25%, and provides for monthly principal and interest payments sufficient to retire the principal balance by 35% in the first year, 25% in each of the next two years, and 15% in the fourth year.  The term loan prohibits Desta Drilling from making any cash distributions to us until the balance on the term loan is fully repaid.  The outstanding balance on the Desta Drilling term loan at June 30, 2009 was $30 million.

We have made advances structured as subordinated loans to Desta Drilling totaling $12.1 million, $4.6 million to finance excess construction costs and $7.5 million to finance our 50% share of working capital assessments made by Desta Drilling.  Lariat also advanced Desta Drilling $7.5 million for its 50% share of working capital assessments.

In connection with the formation of Desta Drilling, we entered into a three-year drilling contract with Desta Drilling assuring the availability of its drilling rigs for use in the ordinary course of our exploration and development drilling program throughout the term of the drilling contract.  The drilling contract, which is pledged as collateral to secure the Desta Drilling term loan, expires on the earlier of December 31, 2009 or the termination and liquidation of Desta Drilling.  The drilling contract provides that we contract for each drilling rig on a well-by-well basis at then current market rates.  If a drilling rig is not needed by us at any time during the term of the contract, Desta Drilling may contract with other operators for the use of such drilling rig, subject to certain restrictions.  If a drilling rig is idle, the contract requires us to pay Desta Drilling an idle rig rate ranging from $8,100 per day to $10,300 per day (plus crew labor expenses, if applicable), depending on the size of the drilling rig.

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During most of 2008, the drilling rigs owned by Desta Drilling were being utilized primarily by Lariat and us in our respective drilling programs.  The material deterioration in oil and gas prices, which began in the second half of 2008 and continued into 2009, resulted in a significant reduction in drilling activity throughout the oil and gas industry.  As a result, all of Desta Drilling’s rigs were idle during most of the second quarter of 2009.  However, in response to recent improvements in operating margins for oil production, we have resumed drilling developmental oil wells in the Permian Basin and the Austin Chalk (Trend) and are currently utilizing three of Desta Drilling’s rigs.  Our maximum remaining obligation for idle rig charges under the drilling contract at June 30, 2009 is $12.3 million.  We believe that the payments we will make to Desta Drilling for the remainder of 2009, either through idle rig charges or contract drilling services, will provide Desta Drilling with adequate cash flow to meet its debt service obligations under the term loan through 2009.  If most of its drilling rigs remain idle beyond 2009, and Desta Drilling is not able to meet its debt service obligations under the term loan, we may be required under the guaranty to make debt service payments on the term loan on behalf of Desta Drilling in an aggregate amount up to the maximum obligation under the guaranty, which is currently $15.8 million.

Effective April 15, 2009, we acquired the remaining 50% equity interest in Desta Drilling pursuant to an agreement with Lariat dated March 13, 2009 (the “Assignment”).  As a result of the transactions contemplated by the Assignment, we now own 100% of Desta Drilling.  In connection with the Assignment, we 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 the drilling rigs owned by Desta Drilling.  The assignment from Lariat includes all of Lariat’s right, title and interest in the subordinated loans previously advanced by Lariat to Desta Drilling.

Immediately upon consummation of the Assignment, we contributed all of the subordinated notes issued by Desta Drilling in the aggregate principal amount of $19.6 million and all accrued and unpaid interest on the notes to the capital of Desta Drilling, and we adopted a plan of disposition whereby Desta Drilling would commit to sell eight of its 12 drilling rigs.  The plan of disposition meets the criteria under SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets (as amended)” (“SFAS 144”) for the designated assets to be classified as held for sale.  SFAS 144 requires us 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.  We estimate the fair value of the designated assets to be approximately $18.8 million.  As a result, we reclassified the estimated fair value of the designated assets to “Assets Held for Sale” in our consolidated balance sheet and recorded a related charge for impairment of property and equipment of $32.1 million in our consolidated statement of operations for the second quarter of 2009.

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.

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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, 2008 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 2008 would reduce our gross revenues for the year ending December 31, 2009 by $11.7 million.

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

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

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The following summarizes information concerning our net positions in open commodity derivatives applicable to periods subsequent to June 30, 2009.  The settlement prices of commodity derivatives are based on NYMEX futures prices.

Swaps:

	Gas				Oil
	MMBtu (a)		Price		Bbls		Price
Production Period:
3rd Quarter 2009		1,450,000	$	5.47		440,000	$	48.13
4th Quarter 2009		1,850,000	$	5.47		400,000	$	46.15
2010		7,540,000	$	6.80		327,000	$	53.30
2011		6,420,000	$	7.07		-	$	-
		17,260,000				1,167,000
(a) One MMBtu equals one Mcf at a Btu factor of 1,000.

In March 2009, we terminated certain fixed-priced oil swaps covering 332,000 barrels at a price of $57.35 from January 2010 through December 2010, resulting in an aggregate loss of approximately $1.3 million, which will be paid to the counterparty monthly as the applicable contracts are settled.

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 $21.9 million.

Interest Rates

We are exposed to interest rate risk on our long-term debt with a variable interest rate.  At June 30, 2009, our fixed rate debt had a carrying value of $225 million and an approximate fair value of $163.1 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 $5 million.  Based on our outstanding variable rate indebtedness at June 30, 2009 of $149.3 million, a change in interest rates of 100 basis points would affect annual interest payments by $1.5 million.

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Item 4 -                 Controls and Procedures

Disclosure Controls and Procedures

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

With respect to our disclosure controls and procedures:

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

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

·   It is the conclusion of our chief executive 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, 2009 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II.  OTHER INFORMATION

Item 1A -              Risk Factors

In evaluating all forward-looking statements, you should specifically consider various factors that may cause actual results to vary from those contained in the forward-looking statements.  Our risk factors are included in our Annual Report on Form 10-K for the year ended December 31, 2008, as filed with the U.S. Securities and Exchange Commission on March 16, 2009 and available at www.sec.gov.  Following are additional risk factors that could affect our financial performance or could cause actual results to differ materially from estimates contained in our forward-looking statements.

Certain U.S. federal income tax deductions currently available with respect to oil and gas exploration and development may be eliminated as a result of future legislation.

The Proposed Fiscal Year 2010 Budget includes proposed legislation that would, if enacted into law, make significant changes to United States tax laws, including the elimination of certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. These changes include, but are not limited to:  (1) the repeal of the percentage depletion allowance for oil and natural gas properties, (2) the elimination of current deductions for intangible drilling and development costs, (3) the elimination of the deduction for certain domestic production activities, and (4) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether any such changes will be enacted or how soon any such changes could become effective.  The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could eliminate certain tax deductions that are currently available with respect to oil and gas exploration and development, and any such change could negatively affect our financial condition and results of operations.

The adoption of climate change legislation by Congress could result in increased operating costs and reduced demand for the oil and natural gas we produce.

On June 26, 2009, the U.S. House of Representatives approved adoption of the “American Clean Energy and Security Act of 2009,” also known as the “Waxman-Markey cap-and-trade legislation” or ACESA.  The purpose of ACESA is to control and reduce emissions of “greenhouse gases,” or “GHGs,” in the United States.  GHGs are certain gases, including carbon dioxide and methane, that may be contributing to warming of the Earth’s atmosphere and other climatic changes.  ACESA would establish an economy-wide cap on emissions of GHGs in the United States and would require an overall reduction in GHG emissions of 17% (from 2005 levels) by 2020, and by over 80% by 2050.  Under ACESA, most sources of GHG emissions would be required to obtain GHG emission “allowances” corresponding to their annual emissions of GHGs.  The number of emission allowances issued each year would decline as necessary to meet ACESA’s overall emission reduction goals.  As the number of GHG emission allowances declines each year, the cost or value of allowances is expected to escalate significantly.  The net effect of ACESA will be to impose increasing costs on the combustion of carbon-based fuels such as oil, refined petroleum products, and natural gas.

The U.S. Senate has begun work on its own legislation for controlling and reducing emissions of GHGs in the United States.  If the Senate adopts GHG legislation that is different from ACESA, the Senate legislation would need to be reconciled with ACESA and both chambers would be required to approve identical legislation before it could become law.  President Obama has indicated that he is in support of the adoption of legislation to control and reduce emissions of GHGs through an emission allowance permitting system that results in fewer allowances being issued each year but that allows parties to buy, sell and trade allowances as needed to fulfill their GHG emission obligations.  Although it is not possible at this time to predict whether or when the Senate may act on climate change legislation or how any bill approved by the Senate would be reconciled with ACESA, any laws or regulations that may be adopted to restrict or reduce emissions of GHGs would likely require us to incur increased operating costs, and could have an adverse effect on demand for the oil and natural gas we produce.

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The adoption of derivatives legislation by Congress could have an adverse impact on our ability to hedge risks associated with our business.

Congress is currently considering legislation to impose restrictions on certain transactions involving derivatives, which could affect the use of derivatives in hedging transactions. ACESA contains provisions that would prohibit private energy commodity derivative and hedging transactions.  ACESA would expand the power of the Commodity Futures Trading Commission, or CFTC, to regulate derivative transactions related to energy commodities, including oil and natural gas, and to mandate clearance of such derivative contracts through registered derivative clearing organizations.  Under ACESA, the CFTC’s expanded authority over energy derivatives would terminate upon the adoption of general legislation covering derivative regulatory reform. The Chairman of the CFTC has announced that the CFTC intends to conduct hearings to determine whether to set limits on trading and positions in commodities with finite supply, particularly energy commodities, such as crude oil, natural gas and other energy products.  The CFTC also is evaluating whether position limits should be applied consistently across all markets and participants.  In addition, the Treasury Department recently has indicated that it intends to propose legislation to subject all OTC derivative dealers and all other major OTC derivative market participants to substantial supervision and regulation, including by imposing conservative capital and margin requirements and strong business conduct standards.  Derivative contracts that are not cleared through central clearinghouses and exchanges may be subject to substantially higher capital and margin requirements.  Although it is not possible at this time to predict whether or when Congress may act on derivatives legislation or how any climate change bill approved by the Senate would be reconciled with ACESA, any laws or regulations that may be adopted that subject us to additional capital or margin requirements relating to, or to additional restrictions on, our trading and commodity positions could have an adverse effect on our ability to hedge risks associated with our business or on the cost of our hedging activity.

Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

Congress is currently considering legislation to amend the federal Safe Drinking Water Act to require the disclosure of chemicals used by the oil and gas industry in the hydraulic fracturing process.  Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into rock formations to stimulate natural gas production.  Sponsors of bills currently pending before the Senate and House of Representatives have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies.  The proposed legislation would require the reporting and public disclosure of chemicals used in the fracturing process, which could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater.  In addition, these bills, if adopted, could establish an additional level of regulation at the federal level that could lead to operational delays or increased operating costs and could result in additional regulatory burdens that could make it more difficult to perform hydraulic fracturing and increase our costs of compliance and doing business.

Item 4 -                 Submission of Matters to a Vote of Security Holders

On May 6, 2009, we held our Annual Meeting of Stockholders to (a) elect two directors to the Board of Directors for a term of three years, and (b) advise on the selection of KPMG LLP as our independent auditors for 2009.  At such meeting Ted Gray, Jr. and Mel G. Riggs were elected as directors, and stockholders advised that KPMG LLP should be selected as our independent auditors for 2009.

The following is a summary of the votes cast at the Annual Meeting:

	Results of Voting	Votes For	Withheld
1.	Election of Directors
	Ted Gray, Jr.	8,520,791	2,931,567
	Mel G. Riggs	9,499,548	1,952,810
		Votes For	Against	Abstentions
2.	Advisory vote on the selection of KPMG LLP	11,420,759	28,575	3,024

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Item 6 -                 Exhibits

Exhibits

**3.1	Second Restated Certificate of Incorporation of the Company, filed as Exhibit 3.1 to our Form S-2 Registration Statement, Commission File No. 333-13441
**3.2	Certificate of Amendment of Second Restated Certificate of Incorporation of Clayton Williams Energy, Inc., filed as Exhibit 3.1 to our Form 10-Q for the period ended September 30, 2000††
**3.3	Corporate Bylaws of Clayton Williams Energy, Inc., as amended, filed as Exhibit 3.1 to our Current Report on Form 8-K filed with the Commission on March 14, 2008††
**4.1	Indenture, dated 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	Sixth Amendment to Amended and Restated Credit Facility, dated May 20, 2009, filed as Exhibit 10.1 to our Current Report on Form 8-K filed with the Commission on April 17, 2009. ††
**10.2	Term Loan and Security Agreement, dated April 21, 2006, among Larclay, L.P., GE Business Financial Services, Inc. (successor to Merrill Lynch Capital), as Administrative Agent, and the Lenders named therein filed as Exhibit 10.2 to our Current Report on Form 8-K filed with the Commission on April 17, 2009. ††
**10.3	Letter Agreement regarding Term Loan and Security Agreement, dated February 28, 2007, between Larclay, L.P. and GE Business Financial Services, Inc. (successor to Merrill Lynch Capital) filed as Exhibit 10.3 to our Current Report on Form 8-K filed with the Commission on April 17, 2009. ††
**10.4	Seventh Amendment to Amended and Restated Credit Facility, dated May 20, 2009, filed as Exhibit 10.1 to our Current Report on Form 8-K filed with the Commission on May 26, 2009. ††
*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

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CLAYTON WILLIAMS ENERGY, INC.

SIGNATURES

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

CLAYTON WILLIAMS ENERGY, INC.

Date:	August 7, 2009	By:	/s/ L. Paul Latham
			L. Paul Latham
			Executive Vice President and Chief
			Operating Officer

Date:	August 7, 2009	By:	/s/ Mel G. Riggs
			Mel G. Riggs
			Senior Vice President and Chief Financial
			Officer

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