CLAYTON WILLIAMS ENERGY INC /DE - FORM 10-Q

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EX-31.2 - CERTIFICATION OF CFO - CLAYTON WILLIAMS ENERGY INC /DE	mel9300931_2.htm
EX-31.1 - CERTIFICATION OF CEO - CLAYTON WILLIAMS ENERGY INC /DE	clayton9300931_1.htm
EX-32.1 - CERTIFICATION OF CEO &AMP; CFO - CLAYTON WILLIAMS ENERGY INC /DE	claytonmel9300932_1.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)
x	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
	OF THE SECURITIES EXCHANGE ACT OF 1934
	For the quarterly period ended September 30, 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 November 4, 2009.

CLAYTON WILLIAMS ENERGY, INC.

TABLE OF CONTENTS

PART I. FINANCIAL INFORMATION
		Page

Item 1.	Financial Statements

	Consolidated Balance Sheets as of September 30, 2009
	and December 31, 2008	3

	Consolidated Statements of Operations for the three months and nine months
	ended September 30, 2009 and 2008	5

	Consolidated Statement of Equity for the nine months
	ended September 30, 2009	6

	Consolidated Statements of Cash Flows for the nine months
	ended September 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	42

Item 4.	Controls and Procedures	44


PART II. OTHER INFORMATION
Item 1A.	Risk Factors	45

Item 6.	Exhibits	47

	Signatures	48

PART I. FINANCIAL INFORMATION

Item 1 - Financial Statements

CLAYTON WILLIAMS ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

ASSETS
	September 30,			December 31,
	2009			2008
	(Unaudited)
CURRENT ASSETS
Cash and cash equivalents	$	22,407		$	41,199
Accounts receivable:
Oil and gas sales		21,986			26,009
Joint interest and other, net		5,533			14,349
Affiliates		289			227
Inventory		41,918			20,052
Deferred income taxes		3,637			3,637
Assets held for sale		18,750			-
Prepaids and other		1,796			20,011
		116,316			125,484
PROPERTY AND EQUIPMENT
Oil and gas properties, successful efforts method		1,570,175			1,526,473
Natural gas gathering and processing systems		17,884			17,816
Contract drilling equipment		27,800			91,151
Other		16,047			14,954
		1,631,906			1,650,394
Less accumulated depreciation, depletion and amortization		(920,687	)		(840,366	)
Property and equipment, net		711,219			810,028

OTHER ASSETS
Debt issue costs, net		5,188			6,225
Other		1,920			1,672
		7,108			7,897
	$	834,643		$	943,409

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

CLAYTON WILLIAMS ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

LIABILITIES AND EQUITY
	September 30,		December 31,
	2009		2008
	(Unaudited)
CURRENT LIABILITIES
Accounts payable:
Trade	$	32,653	$	67,189
Oil and gas sales		17,721		24,702
Affiliates		1,738		1,627
Current maturities of long-term debt		-		18,750
Fair value of derivatives		8,049		-
Accrued liabilities and other		7,699		10,609
		67,860		122,877
NON-CURRENT LIABILITIES
Long-term debt		395,000		347,225
Deferred income taxes		78,382		120,414
Fair value of derivatives		265		-
Other		37,993		32,617
		511,640		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		101,901		176,424
Total Clayton Williams Energy, Inc. stockholders’ equity		255,143		314,682
Noncontrolling interest, net of tax		-		5,594
Total equity		255,143		320,276
	$	834,643	$	943,409

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

CLAYTON WILLIAMS ENERGY, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(In thousands, except per share)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2009			2008			2009			2008
REVENUES
Oil and gas sales	$	59,436		$	128,335		$	167,438		$	381,545
Natural gas services		1,639			2,978			4,578			9,069
Drilling rig services		-			12,515			6,681			40,050
Gain on sales of assets		1,351			3,157			2,014			44,447
Total revenues		62,426			146,985			180,711			475,111

COSTS AND EXPENSES
Production		19,258			22,861			56,617			65,365
Exploration:
Abandonments and impairments		24,149			43,036			41,066			45,266
Seismic and other		898			5,993			6,556			11,230
Natural gas services		1,344			2,706			3,966			8,465
Drilling rig services		904			9,763			10,901			30,803
Depreciation, depletion and amortization		30,053			27,226			92,704			82,473
Impairment of property and equipment		-			9,985			32,068			9,985
Accretion of abandonment obligations		824			654			2,290			1,669
General and administrative		4,012			6,501			14,796			17,893
Loss on sales of assets and inventory
write-downs		555			134			4,400			420
Total costs and expenses		81,997			128,859			265,364			273,569

Operating income (loss)		(19,571	)		18,126			(84,653	)		201,542

OTHER INCOME (EXPENSE)
Interest expense		(6,526	)		(5,406	)		(17,700	)		(18,929	)
Gain (loss) on derivatives		4,723			132,710			(14,537	)		(61,986	)
Other		(76	)		2,030			1,651			5,699
Total other income (expense)		(1,879	)		129,334			(30,586	)		(75,216	)

Income (loss) before income taxes		(21,450	)		147,460			(115,239	)		126,326
Income tax (expense) benefit		7,850			(52,829	)		42,171			(45,409	)
NET INCOME (LOSS)		(13,600	)		94,631			(73,068	)		80,917
Less income attributable to
noncontrolling interest, net of tax		-			(2	)		(1,455	)		(280	)

NET INCOME (LOSS) attributable to Clayton
Williams Energy, Inc.	$	(13,600	)	$	94,629		$	(74,523	)	$	80,637

Net income (loss) per common share attributable to
Clayton Williams Energy, Inc. stockholders:
Basic	$	(1.12	)	$	7.81		$	(6.14	)	$	6.79
Diluted	$	(1.12	)	$	7.79		$	(6.14	)	$	6.72

Weighted average common shares outstanding:
Basic		12,144			12,114			12,136			11,874
Diluted		12,144			12,141			12,136			12,008

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

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)		-		-		-		(74,523	)		1,455
Stock options exercised		28		2		150		-			-
Acquisition of noncontrolling
interest		-		-		14,832		-			(7,049	)
BALANCE,
September 30, 2009		12,144	$	1,214	$	152,028	$	101,901		$	-

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

CLAYTON WILLIAMS ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In thousands)

	Nine Months Ended
	September 30,
	2009			2008
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	(73,068	)	$	80,917
Adjustments to reconcile net income (loss) to cash
provided by operating activities:
Depreciation, depletion and amortization		92,704			82,473
Impairment of property and equipment		32,068			9,985
Exploration costs		41,066			45,266
(Gain) loss on sales of assets and inventory write-downs, net		2,386			(44,027	)
Deferred income tax expense (benefit)		(42,171	)		44,881
Non-cash employee compensation		953			3,942
Unrealized (gain) loss on derivatives		8,314			(23,930	)
Settlements on derivatives with financing elements		-			40,260
Amortization of debt issue costs		1,163			1,049
Accretion of abandonment obligations		2,290			1,669

Changes in operating working capital:
Accounts receivable		12,777			(5,001	)
Accounts payable		(26,075	)		(10,374	)
Other		15,800			(4,054	)
Net cash provided by operating activities		68,207			223,056

CASH FLOWS FROM INVESTING ACTIVITIES
Additions to property and equipment		(99,808	)		(231,316	)
Proceeds from sales of assets		2,109			117,109
Change in equipment inventory		(25,868	)		(11,384	)
Other		(109	)		3,880
Net cash used in investing activities		(123,676	)		(121,711	)

CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt		75,900			5,500
Repayments of long-term debt		(39,375	)		(60,312	)
Proceeds from exercise of stock options		152			15,915
Settlements on derivatives with financing elements		-			(40,260	)
Net cash provided by (used in) financing activities		36,677			(79,157	)

NET INCREASE (DECREASE) IN CASH AND
CASH EQUIVALENTS		(18,792	)		22,188

CASH AND CASH EQUIVALENTS
Beginning of period		41,199			12,344
End of period	$	22,407		$	34,532

SUPPLEMENTAL DISCLOSURES
Cash paid for interest, net of amounts capitalized	$	21,826		$	22,239

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

CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2009

(Unaudited)

1.	Nature of Operations

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

Substantially all of our oil and gas production is sold under short-term contracts which are market-sensitive. Accordingly, our results of operations and capital resources are highly dependent upon prevailing market prices of, and demand for, oil and natural gas. These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond our control. These factors include the level of global demand for petroleum products, foreign supply of oil and gas, the establishment of and compliance with production quotas by oil exporting countries, trading activities in commodities futures markets, the strength of the U.S. dollar, weather conditions, the price and availability of alternative fuels, and overall economic conditions, both foreign and domestic.

2.	Presentation

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

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

In the opinion of management, our unaudited consolidated financial statements as of September 30, 2009 and for the interim periods ended September 30, 2009 and 2008 include all adjustments which are necessary for a fair presentation in accordance with GAAP. These interim results are not necessarily indicative of the results to be expected for the year ending December 31, 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 our Form 10-K for the year ended December 31, 2008.

Effective April 15, 2009, CWEI acquired the remaining 50% equity ownership in the contract drilling joint venture CWEI formed in 2006 with Lariat Services, Inc. (“Lariat”). We referred to this joint venture as Larclay JV until June 2009 when we 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.

Adopted Accounting Pronouncements

Effective July 1, 2009, we adopted SFAS No. 168, “The Financial Accounting Standards Board ("FASB") Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles, a replacement of FASB Statement No. 162” (“SFAS 168”) superseded by topic 105-10-5 of the FASB Accounting Standards Codification (“ASC”). SFAS 168 establishes the ASC 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 GAAP. Other than the manner in which new accounting guidance is referenced, the adoption did not have a material impact on our financial statements.

Effective January 1, 2009, we adopted Statement of Financial Accounting Standards (“SFAS”) No. 160, “Noncontrolling Interests in Consolidated Financial Statements - an amendment of ARB No. 51” (“SFAS 160”) (superseded by ASC topic 810-10-65). 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 our consolidated financial statements, as required by SFAS 160, have been applied retrospectively to prior periods.

Effective January 1, 2009, we adopted SFAS Statement No. 161, “Disclosures about Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133” (“SFAS 161”) (superseded by ASC topic 815-10-65). 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”) (superseded by ASC topic 815-10) 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 our financial statements, other than disclosures.

Effective January 1, 2009, we adopted SFAS No. 141R, “Business Combinations” (“SFAS 141R”) (superseded by ASC topic 805-10). 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 our financial statements.

Effective January 1, 2009, we adopted SFAS No. 157, “Fair Value Measurements (as amended)” (“SFAS 157”) (superseded by ASC topic 820-10), 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. We 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, we adopted SFAS No. 165, “Subsequent Events” (“SFAS 165”) (superseded by ASC topic 855-10-5), 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 our disclosure of subsequent events.

3.	Recent Accounting Pronouncements

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 our reported financial position or results of operations.

4.	Long-Term Debt

Long-term debt consists of the following:

	September 30,		December 31,
	2009		2008
	(In thousands)
7¾% Senior Notes due 2013	$	225,000	$	225,000
Secured bank credit facility, due May 2012(a)		170,000		94,100
Secured term loan of Desta Drilling, due June 2011(a)		-		39,375
Subordinated notes of Desta Drilling(b)		-		7,500
		395,000		365,975
Less current maturities(c)		-		(18,750	)
	$	395,000	$	347,225

(a) In August 2009, we repaid all of the secured term loan of Desta Drilling with borrowings under our secured bank credit facility due May 2012.

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

7¾% Senior Notes due 2013

In July 2005, we 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.

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 or for any period thereafter, in each case plus accrued and unpaid interest.

The Indenture governing the Senior Notes contains covenants that restrict our ability to: (1) borrow money; (2) issue redeemable or preferred stock; (3) pay distributions or dividends; (4) make investments; (5) create liens without securing the Senior Notes; (6) enter into agreements that restrict dividends from subsidiaries; (7) sell certain assets or merge with or into other companies; (8) enter into transactions with affiliates; (9) guarantee indebtedness; and (10) enter into new lines of business. One such covenant provides that we may only incur indebtedness if the ratio of consolidated EBITDAX to consolidated interest expense (as these terms are defined in the Indenture) exceeds 2.5 to 1 for the four most recently completed fiscal quarters. However, this restriction does not prevent us from borrowing funds under the revolving credit facility provided that our outstanding balance on the facility does not exceed the greater of $150 million and 30% of Adjusted Consolidated Net Tangible Assets (as defined in the Indenture). These covenants are subject to a number of important exceptions and qualifications as described in the Indenture. We were in compliance with these covenants at September 30, 2009.

Secured Bank Credit Facility

We have a revolving credit facility with a syndicate of banks based on a borrowing base determined by the banks. The borrowing base, which is based on the discounted present value of future net revenues from oil and gas production, is redetermined by the banks semi-annually in May and November. We or the banks may also request an unscheduled borrowing base redetermination at other times during the year. If, at any time, the borrowing base is less than the amount of outstanding credit exposure under the revolving credit facility, we will be required to (1) pledge additional collateral, (2) prepay the principal amount of the loans in an amount sufficient to eliminate the excess, or (3) prepay the excess in six equal monthly installments. In October 2009, the borrowing base was affirmed by the banks at $250 million. After allowing for outstanding letters of credit totaling $804,000, we had $79.2 million available under the credit facility at September 30, 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. The obligations under the revolving credit facility are guaranteed by each of CWEI’s material domestic subsidiaries.

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%. We also pay 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 nine months ended September 30, 2009 was 2.6%.

The revolving credit facility contains financial covenants that are computed quarterly. One financial covenant requires us 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 our consolidated funded indebtedness to consolidated EBITDAX (determined as of the end of each fiscal quarter for the then most-recently ended four fiscal quarters) from being greater than 3.5 to 1 for any fiscal quarter ending on or prior to December 31, 2010, 3.25 to 1 for any fiscal quarter ending on or after March 31, 2011 through December 31, 2011, and 3 to 1 for any fiscal quarter thereafter. 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. We were in compliance with all financial and non-financial covenants at September 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. In August 2009, we repaid in full all amounts outstanding under the secured term loan of Desta Drilling with borrowings of approximately $27.2 million under the revolving credit facility. All of the assets of Desta Drilling were pledged as collateral under our revolving credit facility.

5.	Other Non-Current Liabilities

Other non-current liabilities consist of the following:

	September 30,		December 31,
	2009		2008
	(In thousands)
Abandonment obligations	$	37,337	$	31,737
Other taxes payable		-		144
Other		656		736
	$	37,993	$	32,617

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

	Nine Months Ended
	September 30,
	2009			2008
	(In thousands)
Beginning of period	$	31,737		$	30,994
Additional abandonment obligations from new properties		1,239			975
Sales or abandonments of properties		(123	)		(1,833	)
Revisions of previous estimates		2,194			(1,401	)
Accretion expense		2,290			1,669
End of period	$	37,337		$	30,404

6.	Compensation Plans

Stock-Based Compensation

We have 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 our common stock on the date of grant. We issue new shares, not repurchased shares, to option holders that exercise stock options under the 1993 Plan. At September 30, 2009, no options were outstanding under this plan, and 101,766 shares remain available for issuance.

We have 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, CWEI 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 September 30, 2009, 26,000 options were outstanding under this plan. Effective January 1, 2009, the Board of Directors suspended the grant of options under the Directors Plan.

The following table sets forth certain information regarding our stock option plans as of and for the nine months ended September 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 September 30, 2009		26,000		$	25.52		4.4	$	176,210

Vested at September 30, 2009		26,000		$	25.52		4.4	$	176,210
Exercisable at September 30, 2009		26,000		$	25.52		4.4	$	176,210

(a) Based on closing price at September 30, 2009 of $30.12 per share.
(b) Cash received for options exercised totaled $152,000.

The following table summarizes information with respect to options outstanding at September 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	2.1
$22.90 - $41.74	18,000	$ 31.34	5.4
	26,000	$ 25.52	4.4

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

	Nine Months Ended
	September 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	$	20,423

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

The Compensation Committee has also authorized the formation of the APO Reward Plan which offers eligible officers, key employees and consultants the opportunity to receive bonus payments that are based on certain profits derived from a portion of our working interest in specified areas where we are conducting drilling and production enhancement operations. The wells subject to an APO Reward Plan are not included in the APO Incentive Plan. Likewise, wells included in the APO Incentive Plan are not included in the APO Reward Plan. Although conceptually similar to the APO Incentive Plan, the APO Reward Plan is a compensatory bonus plan through which we pay participants a bonus equal to a portion of the APO cash flows received by us from our working interest in wells in a specified area. Unlike the APO Incentive Plan, however, participants in the APO Reward Plan are not immediately vested in all future amounts payable under the plan. In May 2008, we 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, we granted awards under the Southwest Royalties Reward Plan (the “SWR Reward Plan”), a one-time incentive plan which established a quarterly bonus amount for participants equal to the after-payout cash flow from a 22.5% working interest in one well. Under the plan, two-thirds of the quarterly bonus amount is payable to the participants until the full vesting date of October 25, 2011. After the full vesting date, the deferred portion of the quarterly bonus amount, with interest at 4.83% per year, as well as 100% of all subsequent quarterly bonus amounts, are payable to participants.

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

We recognize compensation expense related to the APO Partnerships based on the estimated fair value of the economic interests conveyed to the participants. Estimated compensation expense applicable to the APO Reward Plan and SWR Reward Plan is recognized over the five-year vesting period. We recorded compensation expense of $2.3 million for the nine months ended September 30, 2009 and $3.9 million for the nine months ended September 30, 2008 in connection with all non-equity award plans.

7.	Derivatives

Commodity Derivatives

From time to time, we utilize commodity derivatives, consisting of swaps, floors and collars, to attempt to optimize the price received for our oil and gas production. When using swaps to hedge 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. In floor transactions, 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. Commodity derivatives are settled monthly as the contract production periods mature.

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

Swaps:

	Gas				Oil
	MMBtu (a)		Price		Bbls		Price
Production Period:
4th Quarter 2009		1,850,000	$	5.47		400,000	$	46.15
2010		7,540,000	$	6.80		2,204,000	$	76.50
2011		6,420,000	$	7.07		-	$	-
		15,810,000				2,604,000

(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.

Accounting For Derivatives

We did not designate any of our currently open commodity derivatives as cash flow hedges; therefore, all changes in the fair value of these contracts prior to maturity, plus any realized gains or losses at maturity, are recorded as other income (expense) in our statements of operations. We report our fair value of derivatives as either a net current asset or liability or a net non-current asset or liability in our consolidated balance sheets. Cash flow is only impacted to the extent the actual derivative contract is settled by making or receiving a payment to or from the counterparty. For the nine months ended September 30, 2009, we reported a $14.5 million net loss on derivatives, consisting of an $8.3 million non-cash loss related to changes in mark-to-market valuations and a $6.2 million realized loss for settled contracts. For the nine months ended September 30, 2008, we reported a $62 million net loss on derivatives, consisting of a $23.9 million non-cash gain related to changes in mark-to-market valuations and an $85.9 million realized loss on settled contracts.

Effect of Derivative Instruments on the Consolidated Balance Sheets

	Liability Derivatives
	Balance Sheet	September 30, 2009
	Location	Fair Value
Derivatives not designated as		(In thousands)
hedging instruments:
Commodity contracts	Current liabilities -
	Fair value of derivatives	$	8,049
	Non-current liabilities -
	Fair value of derivatives		265
Total		$	8,314

Gross to Net Presentation Reconciliation of Derivative Assets and Liabilities

	September 30, 2009
	Assets			Liabilities
	(In thousands)
Fair value of derivatives – gross presentation	$	15,757		$	24,071
Effects of netting arrangements		(15,757	)		(15,757	)
Fair value of derivatives – net presentation	$	-		$	8,314

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

Effect of Derivative Instruments on the Consolidated Statements of Operations

	Amount of Gain or (Loss) Recognized in Earnings
		Nine Months Ended
	Location of Gain or (Loss)	September 30,
	Recognized in Earnings	2009	2008
		(In thousands)
Derivatives not designated as
hedging instruments:
Commodity contracts	Other income (expense) -
	Loss on derivatives	$ (14,537)	$ (61,986)
Total		$ (14,537)	$ (61,986)

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 our secured bank credit facility was estimated to have a fair value approximating the carrying amount since the interest rate is generally market sensitive. The estimated fair value of our Senior Notes at September 30, 2009 and December 31, 2008 was approximately $193.5 million and $126 million respectively, based on market quotes.

Determination of Fair Value

We follow a framework for measuring fair value, which outlines a fair value hierarchy based on the quality of inputs used to measure fair value and enhances disclosure requirements for fair value measurements.

Fair value is defined as the price at which an asset could be exchanged in a current transaction between knowledgeable, willing parties at the measurement date. Where available, fair value is based on observable market prices or parameters or derived from such prices or parameters. Where observable prices or inputs are not available, use of unobservable prices or inputs are used to estimate the current fair value, often using an internal valuation model. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the item being valued.

We categorize our assets and liabilities recorded at fair value in the accompanying consolidated balance sheets based upon the level of judgment associated with the inputs used to measure their fair value. Hierarchical levels directly related to the amount of subjectivity associated with the inputs to fair valuation of these assets and liabilities, are as follows:

Level 1 -

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

Level 2 -

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

Level 3 -

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

The 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.

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

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

		Fair Value Measurements
		September 30, 2009
		Significant
		Other
		Observable
		Inputs
Description		(Level 2)
		(In thousands)
Liabilities:
Fair value of commodity derivatives		$ 8,314
Total liabilities		$ 8,314

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

	Fair Value Measurements
	September 30, 2009
	Significant
	Other		Significant
	Observable		Unobservable
	Inputs		Inputs		Total
Description	(Level 2)		(Level 3)		Losses
	(In thousands)
Assets:
Inventory	$	20,893	$	-	$	4,139
Assets held for sale(a)		-		18,750		32,068
Long-lived assets held and used		17,314		-		16,194
Total assets	$	38,207	$	18,750	$	52,401

(a) For information about Level 3 inputs, see Note 11.

9.	Income Taxes

Our effective federal and state income tax benefit rate for the nine months ended September 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.

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

We recorded a liability for taxes payable related to unrecognized tax benefits arising from uncertain tax positions taken by us in previous periods. A reconciliation of the changes in this tax liability as of September 30, 2009 is as follows:

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

No unrecognized tax benefits originated during the first nine months of 2009.

10.	Investment in Desta Drilling

In April 2006, CWEI formed a joint venture with Lariat to construct, own and operate 12 new drilling rigs. Initially, we 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 (formerly Larclay JV) is referred to in these notes to consolidated financial statements as “Desta Drilling”. Until April 15, 2009, CWEI and Lariat each owned a 50% equity interest in Desta Drilling. Until April 15, 2009, CWEI 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 its 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. CWEI was also a limited guarantor under the Desta Drilling term loan described in Note 4 until the Desta Drilling term loan was repaid in August 2009.

In connection with the formation of Desta Drilling, CWEI entered into a three-year drilling contract with Desta Drilling assuring the availability of the 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 expires on the earlier of December 31, 2009 or the termination and liquidation of Desta Drilling. The drilling contract provides for CWEI 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 CWEI 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 CWEI 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.

Effective April 15, 2009, CWEI 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 CWEI also included all of Lariat’s right, title and interest in the subordinated loans previously made by Lariat to Desta Drilling. As consideration for the Assignment, CWEI assumed all of the obligations and liabilities of Lariat relating to Desta Drilling from and after the effective date, including Lariat’s obligations as operator of Desta Drilling’s rigs. Upon consummation of the Assignment, CWEI contributed all of the subordinated loans to Desta Drilling’s capital.

Prior to the effective date of the Assignment, CWEI met the definition of the primary beneficiary of Desta Drilling’s expected cash flows. Accordingly, we fully consolidated the accounts of Desta Drilling in our consolidated financial statements and accounted for the equity interest owned by Lariat as a noncontrolling interest. Upon consummation of the Assignment, we accounted for the related transactions 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. Desta Drilling has worked exclusively for CWEI since the effective date of the Assignment. As a result, all drilling services revenue earned by Desta Drilling subsequent to April 2009, along with the related cost of drilling services, have been eliminated in consolidation.

11.	Impairment of Property and Equipment

Upon consummation of the Assignment discussed in Note 10, we adopted a plan of disposition whereby we committed to sell eight of the 12 drilling rigs owned by Desta Drilling. The plan of disposition met the criteria under applicable accounting standards for the designated assets to be classified as held for sale. We are required to value the designated assets at the lower of their carrying value or fair value, less cost to sell, as of the date the plan of disposition was adopted. We have estimated 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 balance sheet, and recorded a related charge for impairment of property and equipment of approximately $32.1 million in our statement of operations during the second quarter of 2009. Under applicable accounting standards, this plan of disposition did not qualify for discontinued operations reporting.

To estimate the fair value of the drilling rigs and related equipment owned by Desta Drilling on the measurement date of April 15, 2009 we used a weighting of the market approach and the discounted cash flow approach. Inputs used in the determination of discounted cash flow included estimated rig utilization rates, gross profits from drilling operations, future capital costs required for equipment replacements, useful lives for the equipment and discount rates. We weighted the values obtained through the market approach by 67% and the values obtained through the discounted cash flow approach by 33% to give greater emphasis to the lack of demand for drilling equipment on the measurement date.

12.	Oil and Gas Properties

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

	September 30,			December 31,
	2009			2008
	(In thousands)
Proved properties	$	1,506,699		$	1,435,718
Unproved properties		63,476			90,755
Total capitalized costs		1,570,175			1,526,473
Accumulated depreciation, depletion and amortization		(881,409	)		(791,507	)
Net capitalized costs	$	688,766		$	734,966

13.	Sales of Assets and Inventory Write-downs

We recorded a net loss of $2.4 million on sales of assets and inventory write-downs during the nine months ended September 30, 2009 related primarily to the write-down of inventory to its estimated market value.

14.	Segment Information

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

The following tables present selected financial information regarding our operating segments for the three-month and nine-month periods ended September 30, 2009 and 2008.

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

Revenues	$	62,426		$	4,596		$	(4,596	)	$	62,426
Depreciation, depletion and amortization (a)		29,661			982			(590	)		30,053
Other operating expenses (b)		52,988			3,214			(4,258	)		51,944
Interest expense		5,917			609			-			6,526
Other (income) expense		(4,647	)		-			-			(4,647	)
Income (loss) before income taxes		(21,493	)		(209	)		252			(21,450	)

Income tax (expense) benefit		7,777			73			-			7,850
Net income (loss)		(13,716	)		(136	)		252			(13,600	)
Less income attributable to
noncontrolling interest, net of tax		-			-			-			-

Net income (loss) attributable to
Clayton Williams Energy, Inc.	$	(13,716	)	$	(136	)	$	252		$	(13,600	)

Total assets	$	792,143		$	42,950		$	(450	)	$	834,643
Additions to property and equipment	$	31,323		$	122		$	-		$	31,445

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

Revenues	$	174,030		$	22,109		$	(15,428	)	$	180,711
Depreciation, depletion and amortization (a)		90,533			37,004			(2,765	)		124,772
Other operating expenses (b)		146,287			7,104			(12,799	)		140,592
Interest expense		16,210			1,490			-			17,700
Other (income) expense		12,886			-			-			12,886
Income (loss) before income taxes		(91,886	)		(23,489	)		136			(115,239	)

Income tax (expense) benefit		33,956			8,215			-			42,171
Net income (loss)		(57,930	)		(15,274	)		136			(73,068	)
Less income attributable to
noncontrolling interest, net of tax		(2,910	)		1,455			-			(1,455	)

Net income (loss) attributable to
Clayton Williams Energy, Inc.	$	(60,840	)	$	(13,819	)	$	136		$	(74,523	)

Total assets	$	792,143		$	42,950		$	(450	)	$	834,643
Additions to property and equipment	$	86,370		$	2,312		$	-		$	88,682

For the Three Months Ended
September 30, 2008
(Unaudited)				Contract			Intercompany			Consolidated
(In thousands)	Oil and Gas			Drilling			Eliminations			Total

Revenues	$	134,290		$	16,708		$	(4,013	)	$	146,985
Depreciation, depletion and amortization (a)		35,077			2,699			(565	)		37,211
Other operating expenses (b)		81,744			12,991			(3,087	)		91,648
Interest expense		4,515			891			-			5,406
Other (income) expense		(134,740	)		-			-			(134,740	)
Income (loss) before income taxes		147,694			127			(361	)		147,460

Income tax (expense) benefit		(53,212	)		383			-			(52,829	)
Net income (loss)		94,482			510			(361	)		94,631
Less income (loss) attributable to
noncontrolling interest, net of tax		2			(4	)		-			(2	)

Net income (loss) attributable to
Clayton Williams Energy, Inc.	$	94,484		$	506		$	(361	)	$	94,629

Total assets	$	869,251		$	87,794		$	(8,241	)	$	948,804
Additions to property and equipment	$	125,919		$	1,066		$	(361	)	$	126,624

For the Nine Months Ended
September 30, 2008
(Unaudited)				Contract			Intercompany			Consolidated
(In thousands)	Oil and Gas			Drilling			Eliminations			Total

Revenues	$	434,392		$	50,745		$	(10,026	)	$	475,111
Depreciation, depletion and amortization (a)		85,925			7,932			(1,399	)		92,458
Other operating expenses (b)		149,794			38,752			(7,435	)		181,111
Interest expense		16,003			2,926			-			18,929
Other (income) expense		56,287			-			-			56,287
Income (loss) before income taxes		126,383			1,135			(1,192	)		126,326

Income tax (expense) benefit		(45,285	)		(124	)		-			(45,409	)
Net income (loss)		81,098			1,011			(1,192	)		80,917
Less income (loss) attributable to
noncontrolling interest, net of tax		151			(431	)		-			(280	)

Net income (loss) attributable to
Clayton Williams Energy, Inc.	$	81,249		$	580		$	(1,192	)	$	80,637

Total assets	$	869,251		$	87,794		$	(8,241	)	$	948,804
Additions to property and equipment	$	274,745		$	1,683		$	(1,192	)	$	275,236

(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 assets and inventory write-downs.

15.	Guarantor Financial Information

In July 2005, CWEI (“Issuer”) issued $225 million of Senior Notes (see Note 4). All of the Issuer’s wholly-owned and active subsidiaries which have jointly and severally, irrevocably and unconditionally guaranteed the performance and payment when due of all obligations under the Senior Notes are referred to as “Guarantor Subsidiaries” in the following condensed consolidating financial statements. Prior to August 2009, neither Desta Drilling nor WCEP, LLC, the general partner of West Coast Energy Properties, L.P., an affiliated limited partnership, were guarantors of the Senior Notes, but in August 2009, Desta Drilling became a guarantor of the Senior Notes. As a

result, we have reclassified the condensed consolidating financial statements prior to September 30, 2009 in this Note 15 to include the accounts of Desta Drilling in the Guarantor Subsidiaries column and to reflect only the accounts of WCEP, LLC in the Non-Guarantor Subsidiary column.

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

Condensed Consolidating Balance Sheet

September 30, 2009

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

Current assets	$	204,975	$	256,621	$	848	$	(346,128	)	$	116,316
Property and equipment, net		364,640		340,189		6,390		-			711,219
Investments in subsidiaries		98,875		-		-		(98,875	)		-
Other assets		7,216		392		-		(500	)		7,108
Total assets	$	675,706	$	597,202	$	7,238	$	(445,503	)	$	834,643

Current liabilities	$	134,338	$	279,001	$	107	$	(345,586	)	$	67,860
Non-current liabilities:
Long-term debt		395,000		-		-		-			395,000
Fair value of derivatives		265		-		-		-			265
Other		54,964		61,282		131		(2	)		116,375
		450,229		61,282		131		(2	)		511,640

Equity		91,139		256,919		7,000		(99,915	)		255,143
Total liabilities and
equity	$	675,706	$	597,202	$	7,238	$	(445,503	)	$	834,643

Condensed Consolidating Balance Sheet

December 31, 2008

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

Current assets	$	178,349	$	188,538	$	847	$	(242,250	)	$	125,484
Property and equipment, net		388,189		415,220		6,619		-			810,028
Investments in subsidiaries		72,082		-		-		(72,082	)		-
Other assets		19,629		583		-		(12,315	)		7,897
Total assets	$	658,249	$	604,341	$	7,466	$	(326,647	)	$	943,409

Current liabilities	$	83,288	$	281,734	$	105	$	(242,250	)	$	122,877
Non-current liabilities:
Long-term debt		319,100		40,225		-		(12,100	)		347,225
Other		95,619		57,302		113		(3	)		153,031
		414,719		97,527		113		(12,103	)		500,256

Equity		160,242		225,080		7,248		(72,294	)		320,276
Total liabilities and
equity	$	658,249	$	604,341	$	7,466	$	(326,647	)	$	943,409

Condensed Consolidating Statement of Operations

Three Months Ended September 30, 2009

(Unaudited)							Non-
(In thousands)				Guarantor			Guarantor			Adjustments/
	Issuer			Subsidiaries			Subsidiary			Eliminations			Consolidated
Total revenue	$	38,094		$	24,549		$	173		$	(390	)	$	62,426
Costs and expenses		61,527			20,677			183			(390	)		81,997
Operating income (loss)		(23,433	)		3,872			(10	)		-			(19,571	)
Other income (expense)		(2,618	)		(1,058	)		1,797			-			(1,879	)
Income tax (expense) benefit		7,850			-			-			-			7,850
Noncontrolling interest,
net of tax		-			-			-			-			-

Net income (loss)	$	(18,201	)	$	2,814		$	1,787		$	-		$	(13,600	)

Condensed Consolidating Statement of Operations

Nine Months Ended September 30, 2009

(Unaudited)							Non-
(In thousands)				Guarantor			Guarantor			Adjustments/
	Issuer			Subsidiaries			Subsidiary			Eliminations			Consolidated
Total revenue	$	105,727		$	75,463		$	440		$	(919	)	$	180,711
Costs and expenses		171,970			93,514			799			(919	)		265,364
Operating income (loss)		(66,243	)		(18,051	)		(359	)		-			(84,653	)
Other income (expense)		(33,287	)		2,592			109			-			(30,586	)
Income tax (expense) benefit		42,171			-			-			-			42,171
Noncontrolling interest,
net of tax		(1,455	)		-			-			-			(1,455	)

Net income (loss)	$	(58,814	)	$	(15,459	)	$	(250	)	$	-		$	(74,523	)

Condensed Consolidating Statement of Operations

Three Months Ended September 30, 2008

(Unaudited)						Non-
(In thousands)				Guarantor		Guarantor		Adjustments/
	Issuer			Subsidiaries		Subsidiary		Eliminations			Consolidated
Total revenue	$	82,492		$	68,681	$	325	$	(4,513	)	$	146,985
Costs and expenses		91,875			40,970		166		(4,152	)		128,859
Operating income (loss)		(9,383	)		27,711		159		(361	)		18,126
Other income (expense)		124,799			4,457		78		-			129,334
Income tax (expense) benefit		(52,829	)		-		-		-			(52,829	)
Noncontrolling interest,
net of tax		(2	)		-		-		-			(2	)
Net income (loss)	$	62,585		$	32,168	$	237	$	(361	)	$	94,629

Condensed Consolidating Statement of Operations

Nine Months Ended September 30, 2008

(Unaudited)							Non-
(In thousands)				Guarantor			Guarantor		Adjustments/
	Issuer			Subsidiaries			Subsidiary		Eliminations			Consolidated
Total revenue	$	290,005		$	195,960		$	868	$	(11,722	)	$	475,111
Costs and expenses		171,546			112,064			489		(10,530	)		273,569
Operating income (loss)		118,459			83,896			379		(1,192	)		201,542
Other income (expense)		(65,304	)		(10,068	)		156		-			(75,216	)
Income tax (expense) benefit		(45,409	)		-			-		-			(45,409	)
Noncontrolling interest,
net of tax		(280	)		-			-		-			(280	)
Net income (loss)	$	7,466		$	73,828		$	535	$	(1,192	)	$	80,637

Condensed Consolidating Statement of Cash Flows

Nine Months Ended September 30, 2009

(Unaudited)							Non-
(In thousands)				Guarantor			Guarantor			Adjustments/
	Issuer			Subsidiaries			Subsidiary			Eliminations			Consolidated
Operating activities	$	51,471		$	14,569		$	17		$	2,150		$	68,207
Investing activities		(145,698	)		24,228			(56	)		(2,150	)		(123,676	)
Financing activities		76,819			(40,138	)		(4	)		-			36,677
Net increase (decrease) in
cash and cash equivalents		(17,408	)		(1,341	)		(43	)		-			(18,792	)

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

Cash at end of the period	$	17,973		$	3,713		$	721		$	-		$	22,407

Condensed Consolidating Statement of Cash Flows

Nine Months Ended September 30, 2008

(Unaudited)							Non-
(In thousands)				Guarantor			Guarantor			Adjustments/
	Issuer			Subsidiaries			Subsidiary			Eliminations			Consolidated
Operating activities	$	133,386		$	87,516		$	755		$	1,399		$	223,056
Investing activities		(27,240	)		(92,769	)		(303	)		(1,399	)		(121,711	)
Financing activities		(81,010	)		1,853			-			-			(79,157	)
Net increase (decrease) in
cash and cash equivalents		25,136			(3,400	)		452			-			22,188

Cash at the beginning of
the period		5,325			6,886			133			-			12,344

Cash at end of the period	$	30,461		$	3,486		$	585		$	-		$	34,532

16.	Subsequent Events

We have evaluated events and transactions that occurred after the balance sheet date of September 30, 2009 through November 6, 2009, the date the financial statements were available to be issued. We did not have any subsequent events that would require recognition in the financial statements or disclosures in these notes to the consolidated financial statements.

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

The following discussion is intended to provide information relevant to an understanding of our financial condition, changes in our financial condition and our results of operations and cash flows and should be read in conjunction with our consolidated financial statements and notes thereto included elsewhere in this Form 10-Q and in our Form 10-K for the year ended December 31, 2008. Unless the context otherwise requires, references to “CWEI” mean Clayton Williams Energy, Inc., the parent company, and references to the “Company”, “we”, “us” or “our” mean Clayton Williams Energy, Inc. and its consolidated subsidiaries.

Forward-Looking Statements

The information in this Form 10-Q includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical or current facts, that address activities, events, outcomes and other matters that we plan, expect, intend, assume, believe, budget, predict, forecast, project, estimate or anticipate (and other similar expressions) will, should or may occur in the future are forward-looking statements. These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements in our Form 10-K for the year ended December 31, 2008, in our Form 10-Qs for the quarterly periods ended March 31, 2009 and June 30, 2009 and in this Form 10-Q.

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

• estimates of our oil and gas reserves;

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

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

• our outlook on oil and gas prices;

• our outlook on domestic and worldwide economic conditions;

• our access to capital and our anticipated liquidity;

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

• the impact of political and regulatory developments;

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

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

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

We caution you that these forward-looking statements are subject to all of the risks and uncertainties, many of which are beyond our control, incident to the exploration for and development, production and marketing of oil and gas. These risks include, but are not limited to:

• the possibility of unsuccessful exploration and development drilling activities;

• our ability to replace and sustain production;

•

commodity price volatility;

•

domestic and worldwide economic conditions;

•

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

•

our level of indebtedness;

•

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

•

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

•

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

•

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

•

drilling and other operating risks;

•

hurricanes and other weather conditions;

•

lack of availability of goods and services;

•

regulatory and environmental risks associated with drilling and production activities;

•

the adverse effects of changes in applicable tax, environmental and other regulatory legislation; and

•

the other risks described in our Form 10-K for the year ended December 31, 2008, in our Form 10-Qs for the quarterly periods ended March 31, 2009 and June 30, 2009 and in this Form 10-Q.

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

Should one or more of the risks or uncertainties described above or elsewhere in our Form 10-K for the year ended December 31, 2008, in our Form 10-Qs for the quarterly periods ended March 31, 2009 and June 30, 2009 or in this Form 10-Q occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. We specifically disclaim all responsibility to publicly update or revise any information contained in a forward-looking statement or any forward-looking statement in its entirety.

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

Overview

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

For most of 2008, the 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 of field services during the last half of 2008 and the first quarter of 2009 remained relatively high despite declines in oil and gas prices. As a result, we experienced reductions in operating margins during the last half of 2008 and into the first quarter 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 on oil-prone properties 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 remainder of 2009. As a result, we now plan to spend approximately $131.1 million on exploration and development activities in fiscal 2009, an increase of $17.3 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 third quarter of 2009 and the outlook for the remainder of 2009.

·	Our oil and gas sales for the third quarter decreased $68.9 million, or 54%, from 2008 due substantially to decreases in prices for both oil and gas.

·	Our oil and gas production for the third quarter of 2009 was 5% lower on a barrel of oil equivalent (“BOE”) basis than in the comparable period in 2008. Our oil production was 12% lower than the third quarter of 2008, and gas production remained relatively constant compared to the 2008 period.

We recorded a $4.7 million net gain on derivatives in the third quarter of 2009, consisting of a $10.6 million non-cash gain for changes in mark-to-market valuations and a $5.9 million realized loss on settled contracts. For the same period in 2008, we reported a $132.7 million net gain on derivatives, consisting of a $169.5 million non-cash gain due to changes in mark-to-market valuations and a $36.8 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 third quarter of 2009, we increased borrowings under our revolving credit facility by $50.7 million from $119.3 million at June 30, 2009 to $170 million at September 30, 2009. In August 2009, werepaid in full all amounts outstanding under the secured term loan of Desta Drilling, LP “Desta Drilling” with borrowings of approximately $27.2 million under the revolving credit facility (see Liquidity and Capital Resources).

At September 30, 2009, our capitalized unproved oil and gas properties totaled $63.5 million, of which approximately $33 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

Due to recent improvements in operating margins attributable to higher oil prices and lower costs for field services, we elected to resume drilling developmental oil wells in the Permian Basin and the Austin Chalk (Trend) during the second quarter of 2009. Approximately 46% of the $89.9 million spent on exploration and development activities during the first nine months of 2009 was applicable to developmental prospects. We currently plan to spend approximately $131.1 million on exploration and development activities during fiscal 2009, of which approximately 60% 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.

We spent $32.7 million in the Permian Basin during the first nine months of 2009 on drilling and completion activities and $1.2 million was spent on seismic and leasing activities. We drilled 23 gross (21.68 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 began a drilling program in Andrews County targeting the Wolfcamp/Spraberry formations and currently have three of our drilling rigs employed in this program. We currently plan to spend approximately $62.3 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. We believe that the existing spacing between some of our wells in this area affords us the opportunity to tap additional oil and gas reserves by drilling new wells between existing wells, a technique referred to as in-fill drilling. These in-fill wells are considered lower risk as compared to exploratory wells and until recently, offered more attractive rates of return.

We spent $4.6 million in the Austin Chalk (Trend) area during the first nine months 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 two of our drilling rigs employed in this program and plan to add another rig in early 2010. We currently plan to spend approximately $13.3 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 moved the drilling rig approximately 20 feet north of the current location and drilled the Miami Corp #2 as a replacement well. We also abandoned the Miami Corp #2 well and recorded a pre-tax charge of $17.5 million in connection with these wells during the third quarter of 2009.

We spent $24.5 million in South Louisiana during the first nine months of 2009 on exploration and development activities, of which $22 million was spent on drilling and completion activities and $2.5 million was spent on seismic and leasing activities. We currently plan to spend $25.4 million for fiscal 2009, of which $22.3 million relates to drilling and completion activities and the remaining $3.1 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 wells as producers. On our Ruston prospect, we have completed four wells as producers. We spent $4.4 million in North Louisiana during the first nine months of 2009 on exploration and development activities, of which $3.9 million was spent on drilling and completion activities and $500,000 was spent on seismic and leasing activities. We currently plan to spend $5.1 million for fiscal 2009 in this area.

East Texas Bossier

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

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 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.

We spent $15 million in the East Texas Bossier area during the first nine months of 2009 on exploration and development activities, of which $6 million was spent on drilling and completion activities and $9 million was spent on seismic and leasing activities. We currently plan to spend approximately $15.4 million for fiscal 2009, of which $6.2 million relates to drilling and completion activities and the remaining $9.2 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 abandoned this well in the first quarter of 2009 and recorded a pre-tax charge of approximately $1.7 million for drilling and leasehold impairments related to this well in the first nine months of 2009. Plans to participate in the drilling of a third exploratory well in this area have been deferred until 2010.

Supplemental Information

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

	Three Months Ended
	September 30,
	2009			2008
Oil and Gas Production Data:
Gas (MMcf)		3,900			3,920
Oil (MBbls)		662			755
Natural gas liquids (MBbls)		63			39
Total (MBOE)		1,375			1,447

Average Realized Prices (a):
Gas ($/Mcf)	$	3.79		$	9.88
Oil ($/Bbl)	$	64.60		$	116.01
Natural gas liquids ($/Bbl)	$	31.89		$	69.90

Gain (Loss) on Settled Derivative Contracts (a):
($ in thousands, except per unit)
Gas: Net realized gain (loss)	$	2,992		$	(7,190	)
Per unit produced ($/Mcf)	$	.77		$	(1.83	)
Oil: Net realized loss	$	(8,861	)	$	(29,324	)
Per unit produced ($/Bbl)	$	(13.39	)	$	(38.84	)

Average Daily Production:
Gas (Mcf):
Permian Basin		14,374			13,536
North Louisiana		10,076			16,273
South Louisiana		10,755			4,320
Austin Chalk (Trend)		2,306			2,271
Cotton Valley Reef Complex		3,916			5,832
Other		964			377
Total		42,391			42,609

Oil (Bbls):
Permian Basin		3,526			3,983
North Louisiana		230			392
South Louisiana		773			90
Austin Chalk (Trend)		2,585			3,659
Other		82			83
Total		7,196			8,207

Natural Gas Liquids (Bbls):
Permian Basin		246			174
North Louisiana		26			3
South Louisiana		116			6
Austin Chalk (Trend)		288			233
Other		9			8
Total		685			424

(Continued)

	Three Months Ended
	September 30,
	2009		2008
Exploration Costs (in thousands):
Abandonment and impairment costs:
Permian Basin	$	4	$	716
North Louisiana		3,172		-
South Louisiana		18,955		-
East Texas Bossier		958		40,063
Utah		750		-
Other		310		2,257
Total		24,149		43,036

Seismic and other		898		5,993
Total exploration costs	$	25,047	$	49,029

Depreciation, Depletion and Amortization (in thousands):
Oil and gas depletion	$	29,481	$	24,881
Contract drilling depreciation		392		2,134
Other depreciation		180		211
Total DD&A	$	30,053	$	27,226

Oil and Gas Costs ($/BOE Produced):
Production costs	$	14.01	$	15.80
Oil and gas depletion	$	21.44	$	17.19

Net Wells Drilled (b):
Exploratory Wells		1.1		-
Developmental Wells		16.6		21.6

	Nine Months Ended
	September 30,
	2009			2008
Oil and Gas Production Data:
Gas (MMcf)		12,369			13,645
Oil (MBbls)		2,129			2,142
Natural gas liquids (MBbls)		175			138
Total (MBOE)		4,366			4,554

Average Realized Prices (a):
Gas ($/Mcf)	$	4.11		$	9.83
Oil ($/Bbl)	$	52.10		$	111.48
Natural gas liquids ($/Bbl)	$	26.70		$	61.70

Gain (Loss) on Settled Derivative Contracts (a):
($ in thousands, except per unit)
Gas: Net realized gain (loss)	$	7,478		$	(18,361	)
Per unit produced ($/Mcf)	$	.60		$	(1.35	)
Oil: Net realized loss	$	(13,701	)	$	(65,578	)
Per unit produced ($/Bbl)	$	(6.44	)	$	(30.62	)

(Continued)

	Nine Months Ended
	September 30,
	2009		2008
Average Daily Production:
Natural Gas (Mcf):
Permian Basin		15,157		14,287
North Louisiana		12,007		15,169
South Louisiana		10,342		11,682
Austin Chalk (Trend)		2,580		2,313
Cotton Valley Reef Complex		3,989		5,848
Other		1,233		500
Total		45,308		49,799

Oil (Bbls):
Permian Basin		4,010		3,683
North Louisiana		257		363
South Louisiana		624		393
Austin Chalk (Trend)		2,821		3,291
Other		87		88
Total		7,799		7,818

Natural Gas Liquids (Bbls):
Permian Basin		241		181
North Louisiana		21		3
South Louisiana		73		62
Austin Chalk (Trend)		296		249
Other		10		9
Total		641		504

Exploration Costs (in thousands):
Abandonment and impairment costs:
Permian Basin	$	768	$	716
North Louisiana		4,280		2,162
South Louisiana		19,768		-
East Texas Bossier		11,742		40,063
Utah		3,082		-
Other		1,426		2,325
Total		41,066		45,266
Seismic and other		6,556		11,230
Total exploration costs	$	47,622	$	56,496

Depreciation, Depletion and Amortization (in thousands):
Oil and gas depletion	$	89,914	$	75,220
Contract drilling depreciation		2,171		6,533
Other depreciation		619		720
Total DD&A	$	92,704	$	82,473

Oil and Gas Costs ($/BOE Produced):
Production costs	$	12.97	$	14.35
Oil and gas depletion	$	20.59	$	16.52

Net Wells Drilled (b):
Exploratory Wells		2.5		2.7
Developmental Wells		28.5		57.3

(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.

Operating Results – Three-Month Periods

The following discussion compares our results for the three months ended September 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 $68.9 million, or 54%, from 2008. Price variances accounted for $60.1 million of this decrease. Production in 2009 (on a BOE basis) was 5% lower than 2008, despite additions from our developmental drilling programs. Oil production decreased 12% in 2009 from 2008 and gas production decreased 1% in 2009 from 2008. In 2009, our realized oil price was 44% lower than 2008, and our realized gas price was 62% 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 16% in 2009 as compared to 2008 due primarily to lower production taxes caused by decreases in commodity prices and to overall reductions in the cost of oilfield services. After giving effect to a 5% decrease in oil and gas production on a BOE basis, production costs per BOE decreased 11% from $15.80 per BOE in 2008 to $14.01 per BOE in 2009.

Oil and gas depletion expense increased $4.6 million from 2008 to 2009, of which rate variances accounted for a $5.8 million increase and production variances accounted for a $1.2 million decrease. On a BOE basis, depletion expense increased 25% from $17.19 per BOE in 2008 to $21.44 per BOE in 2009 due to a combination of higher depletable costs and lower estimated reserve quantities in 2009 compared to the 2008 period. In 2009, our estimated reserve quantities were negatively impacted by production performance from certain wells in South Louisiana. 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 $25 million of exploration costs, as compared to $49 million in 2008.

Contract Drilling Services

In 2006, CWEI formed a joint venture with Lariat Services, Inc. (“Lariat”) to construct, own, and operate 12 new drilling rigs. Until April 15, 2009, CWEI 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. Effective April 15, 2009, CWEI acquired the remaining 50% equity interest in Desta Drilling. As primary beneficiary of Desta Drilling’s expected cash flows, prior to April 15, 2009, we fully consolidated the accounts of Desta Drilling in our financial statements and accounted for the equity interest owned by Lariat as a noncontrolling interest.

We utilize drilling rigs owned by Desta Drilling to drill wells in our exploration and development activities. In 2006, CWEI entered into a three-year drilling contract with Desta Drilling under which it contracts 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, CWEI is 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.

All intercompany transactions are eliminated in consolidation to the extent of our equity ownership in Desta Drilling. Accordingly, consolidated drilling services revenues and drilling services costs may vary significantly based on our equity ownership and the percentage of revenues derived from CWEI. Since April 2009, Desta Drilling has worked exclusively for CWEI. As a result, all drilling services revenues received by Desta Drilling subsequent to April 2009, along with the related drilling services costs, have been eliminated in our consolidated statements of operations.

General and Administrative

General and administrative (“G&A”) expenses decreased 38% from $6.5 million in 2008 to $4 million in 2009. Excluding employee compensation related to non-equity incentive plans, G&A expenses decreased from $4.5 million in 2008 to $3.7 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 $338,000 in 2009 compared to $2 million in 2008.

Interest expense

Interest expense increased 21% from $5.4 million in 2008 to $6.5 million in 2009 primarily due to higher average levels of debt. The average daily principal balance outstanding under our revolving credit facility for 2009 was $156.5 million compared to $89.6 million for 2008. Increased borrowings on our revolving credit facility accounted for a $703,000 increase in interest expense, while lower interest rates resulted in a decrease of approximately $465,000. In addition, capitalized interest for 2009 was $96,000 compared to $1.3 million in 2008, and interest expense associated with Desta Drilling’s secured term loan during 2009 was $609,000 compared to $891,000 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 September 30, 2009, we reported a $4.7 million net gain on derivatives, consisting of a $10.6 million non-cash gain to mark our derivative positions to their fair value at September 30, 2009 and a $5.9 million realized loss on settled contracts. For the three months ended September 30, 2008, we reported a $132.7 million net gain on derivatives, consisting of a $169.5 million non-cash gain to mark our derivative positions to their fair value at September 30, 2008 and a $36.8 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 gain of $796,000 on sales of assets and inventory write-downs for the third quarter of 2009 related to the sale of a prospect in South Louisiana offset by the write-down of inventory to its estimated market value at September 30, 2009. In 2008, we recorded a net gain of $3 million on sales of property and equipment related primarily to a gain on the sale of our interest in a North Louisiana prospect.

Income tax expense

Our estimated 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 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 – Nine-Month Periods

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

Oil and gas operating results

Oil and gas sales in 2009 decreased $214.1 million, or 56%, from 2008. Price variances accounted for a $204.5 million decrease, and production variances accounted for a $9.6 million decrease. Production in 2009 (on a BOE basis) was 4% lower than 2008. Oil production decreased 1% and gas production decreased 9% in 2009 from 2008. In 2009, our realized oil price was 53% lower than 2008 while our realized gas price was 58% 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 13% in 2009 as compared to 2008 due primarily to lower production taxes caused by decreases in commodity prices. After giving effect to a 4% decrease in oil and gas production on a BOE basis, production costs per BOE decreased 10% from $14.35 per BOE in 2008 to $12.97 per BOE in 2009.

Oil and gas depletion expense increased $14.7 million from 2008 to 2009, of which rate variances accounted for a $17.8 million increase and production variances accounted for a $3.1 million decrease. On a BOE basis, depletion expense increased 25% from $16.52 per BOE in 2008 to $20.59 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 $47.6 million of exploration costs, as compared to $56.5 million in 2008.

At September 30, 2009, our capitalized unproved oil and gas properties totaled $63.5 million, of which approximately $33 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.

Contract Drilling Services

We utilize drilling rigs owned by Desta Drilling to drill wells in our exploration and development activities. In 2006 CWEI 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 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 during the second quarter of 2009 and designated the rigs as “Assets Held for Sale” in the accompanying consolidated balance sheet.

General and Administrative

G&A expenses decreased 17% from $17.9 million in 2008 to $14.8 million in 2009. Excluding employee compensation related to non-equity incentive plans, G&A expenses decreased from $14 million in 2008 to $12.5 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 $2.3 million in 2009 compared to $3.9 million in 2008.

Interest expense

Interest expense decreased 6% from $18.9 million in 2008 to $17.7 million in 2009 due to a combination of reduced debt levels and lower interest rates. Debt reductions accounted for $184,000 of the decrease, while lower interest rates resulted in a decrease of approximately $1.8 million. The average daily principal balance outstanding under our revolving credit facility for 2009 was $123.1 million compared to $119.3 million for 2008. During 2008, we received approximately $117 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 $562,000 compared to $3 million in 2008, and interest expense associated with Desta Drilling’s term loan during 2009 was $1.3 million compared to $2.9 million 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 nine months ended September 30, 2009, we reported a $14.5 million net loss on derivatives, consisting of an $8.3 million non-cash loss to mark our derivative positions to their fair value at September 30, 2009 and a $6.2 million realized loss on settled contracts. For the nine months ended September 30, 2008, we reported a $62 million net loss on derivatives, consisting of a $23.9 million non-cash gain to mark our derivative positions to their fair value at September 30, 2008 and an $85.9 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 $2.4 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 September 30, 2009. In 2008, we recorded a net gain on sales of property and equipment of $44 million, which included a $33.1 million gain on sales of properties in South Louisiana, a $3.1 million gain on the sale of a North Louisiana prospect, and a $5.7 million gain 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 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 experienced reductions in operating margins and 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 $131.1 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.

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 $89.9 million during the first nine months of 2009 and have increased our estimates for planned expenditures for fiscal 2009 from $113.8 million to $131.1 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 nine months of 2009 and our planned expenditures for the year ending December 31, 2009.

	Actual		Planned
	Expenditures		Expenditures		Year 2009
	Nine Months Ended		Year Ending		Percentage
	September 30, 2009		December 31, 2009		of Total
	(In thousands)
Permian Basin	$	33,900	$	62,300		48	%
South Louisiana		24,500		25,400		19	%
East Texas Bossier		15,000		15,400		12	%
Austin Chalk (Trend)		4,600		13,300		10	%
Utah/California		5,500		6,200		5	%
North Louisiana		4,400		5,100		4	%
Other		2,000		3,400		2	%
	$	89,900	$	131,100		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 40% of the fiscal 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 nine months ended September 30, 2009 totaled $89.9 million, of which approximately 54% 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.

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 $21.9 million.

Cash flow provided by operating activities

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

Cash flow provided by operating activities for the nine months ended September 30, 2009 decreased $154.8 million, or 69%, as compared to the corresponding period in 2008 due primarily to a 56% drop in oil and gas sales caused by lower commodity prices.

Credit facility

We have a revolving credit facility with a syndicate of banks led by JPMorgan Chase Bank, N.A. We have historically relied on the revolving credit facility for both our short-term liquidity (working capital) and our long-term financial needs. The funds available to us at any time under the revolving credit facility are limited to the amount of the borrowing base determined by the banks. As long as we have sufficient availability under the revolving credit facility to meet our obligations as they become due, we believe that we will have sufficient liquidity and will be able to fund any short-term working capital deficit.

The banks redetermine the borrowing base under the revolving credit facility on a semi-annual basis, in May and November. In addition, we or the banks may request an unscheduled borrowing base redetermination at other times during the year. If at any time, the borrowing base is less than the amount of outstanding credit exposure under the revolving credit facility, we will be required to (1) pledge additional collateral, (2) prepay the principal amount of the loans in an amount sufficient to eliminate the excess or (3) prepay the excess in six equal monthly installments. In October 2009, the borrowing was affirmed by the banks at $250 million.

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

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 nine months ended September 30, 2009 was 2.6%.

The revolving credit facility contains various covenants and restrictive provisions which may, among other things, limit our ability to sell assets, incur additional indebtedness, make investments or loans and create liens. One such covenant requires that we maintain a ratio of consolidated current assets to consolidated current liabilities (the “Consolidated Current Ratio”) of at least 1 to 1. In computing the Consolidated Current Ratio at any balance sheet date, we must (1) include the amount of funds available under this facility as a current asset, (2) exclude current assets and liabilities related to the fair value of derivatives, (3) exclude current maturities of loans under the revolving credit facility, if any, and (4) exclude current assets and liabilities attributable to vendor financing transactions, if any.

Working capital computed for loan compliance purposes differs from our working capital in accordance with generally accepted accounting principles (“GAAP”). Since compliance with financial covenants is a material requirement under the credit facilities, we consider the loan compliance working capital to be useful as a measure of our liquidity because it includes the funds available to us under the revolving credit facility and is not affected by the volatility in working capital caused by changes in fair value of derivatives. Our GAAP reported working capital increased from $2.6 million at December 31, 2008 to $48.4 million at September 30, 2009. After giving effect to the adjustments, our working capital computed for loan compliance purposes was $135.6 million at September 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 September 30, 2009 and December 31, 2008.

	September 30,		December 31,
	2009		2008
	(In thousands)
Working capital per GAAP	$	48,356	$	2,607
Add funds available under the revolving credit facility		79,196		155,096
Exclude fair value of derivatives classified as current assets or current liabilities		8,049		-
Exclude current assets and current liabilities of Desta Drilling (a)		-		13,205
Working capital per loan covenant	$	135,601	$	170,908

(a) In August 2009, we repaid all of the secured term loan of Desta Drilling with borrowings under our secured bank credit facility due May 2012.

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 September 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.

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., Compass 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 September 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 nine months in 2009, we increased indebtedness outstanding under the revolving credit facility by $75.9 million. At September 30, 2009, we had $170 million of borrowings outstanding under the revolving credit facility, leaving $79.2 million available on the facility after allowing for outstanding letters of credit totaling $804,000. The revolving credit facility matures in May 2012.

7¾% Senior Notes due 2013

In July 2005, we issued, in a private placement, $225 million of aggregate principal amount of Senior Notes. The Senior Notes were issued at face value and bear interest at 7¾% per year, payable semi-annually on February 1 and August 1 of each year, beginning February 1, 2006.

We may redeem some or all of the Senior Notes at redemption prices (expressed as percentages of principal amount) equal to 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 September 30, 2009.

Desta Drilling Term Loan

In 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. In August 2009, we repaid in full all amounts outstanding under the secured term loan of Desta Drilling with borrowings of approximately $27.2 million under our revolving credit facility. All of the assets of Desta Drilling were pledged as collateral under our revolving credit facility.

Alternative capital resources

Although our base of oil and gas reserves, as collateral for our revolving credit facility, has historically been our primary capital resource, we have in the past, and we believe we could in the future, use alternative capital resources, such as asset sales, vendor financing arrangements, and/or public or private issuances of common stock. We could also issue senior or subordinated debt or preferred stock in a public or a private placement if we choose to raise capital through either of these markets. While we believe we would be able to obtain funds through one or more of these alternatives, if needed, there can be no assurance that these capital resources would be available on terms acceptable to us.

Item 3 - Quantitative and Qualitative Disclosures About Market Risks

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

Oil and Gas Prices

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

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

Swaps:

	Gas				Oil
	MMBtu (a)		Price		Bbls		Price
Production Period:
4th Quarter 2009		1,850,000	$	5.47		400,000	$	46.15
2010		7,540,000	$	6.80		2,204,000	$	76.50
2011		6,420,000	$	7.07		-	$	-
		15,810,000				2,604,000

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

We use a sensitivity analysis technique to evaluate the hypothetical effect that changes in the market value of oil and gas may have on the fair value of our commodity derivatives. A $1 per barrel change in the price of oil and a $.50 per MMBtu change in the price of gas would change the fair value of our commodity derivatives by approximately $11.6 million.

Interest Rates

We are exposed to interest rate risk on our long-term debt with a variable interest rate. At September 30, 2009, our fixed rate debt had a carrying value of $225 million and an approximate fair value of $193.5 million, based on current market quotes. We estimate that the hypothetical change in the fair value of our long-term debt resulting from a 100-basis point change in interest rates would be approximately $6 million. Based on our outstanding variable rate indebtedness at September 30, 2009 of $170 million, a change in interest rates of 100 basis points would affect annual interest payments by $1.7 million.

Item 4 - Controls and Procedures

Disclosure Controls and Procedures

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

With respect to our disclosure controls and procedures:

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

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

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 September 30, 2009 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1A - Risk Factors

In evaluating all forward-looking statements, you should specifically consider various factors that may cause actual results to vary from those contained in the forward-looking statements. Our risk factors are included in our Annual Report on Form 10-K for the year ended December 31, 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.

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 CFTC is considering 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. Separately, two committees of the House of Representatives, the Financial Services and Agriculture Committees, acted on October 15 and October 21, 2009, respectively, to adopt legislation that would impose comprehensive regulation on the over-the-counter (OTC) derivatives marketplace. This legislation would subject swap dealers and major swap participants to substantial supervision and regulation, including capital standards, margin requirements, business conduct standards, and recordkeeping and reporting requirements. It also would require central clearing for transactions entered into between swap dealers or major swap participants, and would provide the CFTC with authority to impose position limits in the OTC derivatives markets. A major swap participant generally would be someone other than a dealer who maintains a “substantial” position in outstanding swaps other than swaps used for commercial hedging, or whose positions create substantial exposure to its counterparties or the system. 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 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††

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

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

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

Filed herewith

Incorporated by reference to the filing indicated

***

Furnished herewith

†

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

††

Filed under our Commission File No. 001-10924

CLAYTON WILLIAMS ENERGY, INC.

SIGNATURES

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

CLAYTON WILLIAMS ENERGY, INC.

Date:	November 6, 2009	By:	/s/ L. Paul Latham
			L. Paul Latham
			Executive Vice President and Chief
			Operating Officer

Date:	November 6, 2009	By:	/s/ Mel G. Riggs
			Mel G. Riggs
			Senior Vice President and Chief Financial
			Officer

INDEX TO EXHIBITS

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

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

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

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

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

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

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

Filed herewith

Incorporated by reference to the filing indicated

***

Furnished herewith

†

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

††

Filed under our Commission File No. 001-10924

CLAYTON WILLIAMS ENERGY INC /DE - FORM 10-Q - November 6, 2009

Attached files

CLAYTON WILLIAMS ENERGY INC /DE Reports