Clayton Williams Energy 10Q 2009 Q1 Quarterly report

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 March 31, 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 12,135,292 shares of Common Stock, $.10 par value, of the registrant outstanding as of May 4, 2009.

CLAYTON WILLIAMS ENERGY, INC

TABLE OF CONTENTS

PART I. FINANCIAL INFORMATION
		Page

Item 1.	Financial Statements

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

	Consolidated Statements of Operations for the three months
	ended March 31, 2009 and 2008	5

	Consolidated Statement of Equity for the three months
	ended March 31, 2009	6

	Consolidated Statements of Cash Flows for the three months
	ended March 31, 2009 and 2008	7

	Notes to Consolidated Financial Statements	8

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

Item 3.	Quantitative and Qualitative Disclosures About Market Risks	38

Item 4.	Controls and Procedures	40


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

Item 6.	Exhibits	41

	Signatures	42

CLAYTON WILLIAMS ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

ASSETS
	March 31,			December 31,
	2009			2008
	(Unaudited)
CURRENT ASSETS
Cash and cash equivalents	$	15,816		$	41,199
Accounts receivable:
Oil and gas sales		19,313			26,009
Joint interest and other, net		10,569			14,349
Affiliates		599			227
Inventory		22,723			20,052
Deferred income taxes		3,637			3,637
Prepaids and other		17,889			20,011
		90,546			125,484
PROPERTY AND EQUIPMENT
Oil and gas properties, successful efforts method		1,548,566			1,526,473
Natural gas gathering and processing systems		17,816			17,816
Contract drilling equipment		91,142			91,151
Other		14,732			14,954
		1,672,256			1,650,394
Less accumulated depreciation, depletion and amortization		(877,798	)		(840,366	)
Property and equipment, net		794,458			810,028

OTHER ASSETS
Debt issue costs, net		5,898			6,225
Fair value of derivatives		3,416			-
Other		1,787			1,672
		11,101			7,897
	$	896,105		$	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
	March 31,		December 31,
	2009		2008
	(Unaudited)
CURRENT LIABILITIES
Accounts payable:
Trade	$	43,836	$	67,189
Oil and gas sales		26,457		24,702
Affiliates		1,052		1,627
Current maturities of long-term debt		18,750		18,750
Fair value of derivatives		2,037		-
Accrued liabilities and other		6,094		10,609
		98,226		122,877
NON-CURRENT LIABILITIES
Long-term debt		356,938		347,225
Deferred income taxes		108,032		120,414
Other		33,795		32,617
		498,765		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 – 12,135,292 shares in 2009
and 12,115,898 shares in 2008		1,214		1,212
Additional paid-in capital		137,151		137,046
Retained earnings		154,109		176,424
Total Clayton Williams Energy, Inc. stockholders’ equity		292,474		314,682
Noncontrolling interest, net of tax		6,640		5,594
Total equity		299,114		320,276
	$	896,105	$	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
	March 31,
	2009			2008
REVENUES
Oil and gas sales	$	50,796		$	118,919
Natural gas services		1,584			2,538
Drilling rig services		5,219			14,832
Gain on sales of assets		183			569
Total revenues		57,782			136,858

COSTS AND EXPENSES
Production		19,063			20,579
Exploration:
Abandonments and impairments		12,412			297
Seismic and other		4,270			3,675
Natural gas services		1,411			2,515
Drilling rig services		7,086			11,117
Depreciation, depletion and amortization		36,465			30,273
Accretion of abandonment obligations		718			530
General and administrative		4,528			3,448
Loss on sales of assets and inventory write-downs		3,449			9
Total costs and expenses		89,402			72,443

Operating income (loss)		(31,620	)		64,415

OTHER INCOME (EXPENSE)
Interest expense		(5,438	)		(7,446	)
Gain (loss) on derivatives		2,510			(46,109	)
Other		901			655
Total other income (expense)		(2,027	)		(52,900	)

Income (loss) before income taxes		(33,647	)		11,515
Income tax (expense) benefit		12,378			(4,222	)
NET INCOME (LOSS)		(21,269	)		7,293

Less income attributable to noncontrolling interest, net of tax		(1,046	)		(114	)

NET INCOME (LOSS) attributable to Clayton Williams Energy, Inc.	$	(22,315	)	$	7,179

Net income (loss) per common share attributable to
Clayton Williams Energy, Inc. stockholders:
Basic	$	(1.84	)	$	.63
Diluted	$	(1.84	)	$	.62

Weighted average common shares outstanding:
Basic		12,122			11,387
Diluted		12,122			11,643

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)		-		-		-		(22,315	)		1,046
Stock options exercised		19		2		105		-			-
BALANCE,
March 31, 2009		12,135	$	1,214	$	137,151	$	154,109		$	6,640

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

CLAYTON WILLIAMS ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In thousands)

	Three Months Ended
	March 31,
	2009			2008
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	(21,269	)	$	7,293
Adjustments to reconcile net income (loss) to cash
provided by operating activities:
Depreciation, depletion and amortization		36,465			30,273
Exploration costs		12,412			297
(Gain) loss on sales of assets and inventory write-downs, net		3,266			(560	)
Deferred income tax expense (benefit)		(12,382	)		4,100
Non-cash employee compensation		383			342
Unrealized (gain) loss on derivatives		(1,379	)		32,028
Settlements on derivatives with financing elements		-			10,415
Amortization of debt issue costs		308			346
Accretion of abandonment obligations		718			530

Changes in operating working capital:
Accounts receivable		10,104			(13,869	)
Accounts payable		(13,407	)		11,985
Other		(1,928	)		(5,130	)
Net cash provided by operating activities		13,291			78,050

CASH FLOWS FROM INVESTING ACTIVITIES
Additions to property and equipment		(42,626	)		(49,610	)
Additions to equipment of Larclay JV.		-			(9	)
Proceeds from sales of assets		259			624
Change in equipment inventory		(6,017	)		(1,620	)
Other		(110	)		69
Net cash used in investing activities		(48,494	)		(50,546	)

CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt		14,400			-
Repayments of long-term debt		-			(10,800	)
Repayments of long-term debt of Larclay JV		(4,687	)		(6,562	)
Proceeds from exercise of stock options		107			6,452
Settlements on derivatives with financing elements		-			(10,415	)
Net cash provided by (used in) financing activities		9,820			(21,325	)

NET INCREASE (DECREASE) IN CASH AND
CASH EQUIVALENTS		(25,383	)		6,179

CASH AND CASH EQUIVALENTS
Beginning of period		41,199			12,344
End of period	$	15,816		$	18,523

SUPPLEMENTAL DISCLOSURES
Cash paid for interest, net of amounts capitalized	$	9,565		$	11,628

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

CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2009

(Unaudited)

1. Nature of Operations

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

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

2. Presentation

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

The consolidated financial statements include the accounts of Clayton Williams Energy, Inc., its wholly-owned subsidiaries and the accounts of the Larclay JV, a contract drilling joint venture in which the Company owned a 50% interest as of March 31, 2009 (see Notes 10 and 13). The Company also accounts for its undivided interests in oil and gas limited partnerships using the proportionate consolidation method. Under this method, the Company consolidates its proportionate share of assets, liabilities, revenues and expenses of these limited partnerships utilizing accounting policies followed by the Company. Less than 5% of the Company’s consolidated total assets and total revenues are derived from oil and gas limited partnerships. All significant intercompany transactions and balances associated with the consolidated operations have been eliminated.

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

Effective January 1, 2009, the Company adopted SFAS Statement No. 161, “Disclosures about Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133” (“SFAS 161”). This statement is intended to improve transparency in financial reporting by requiring enhanced disclosures of an entity’s derivative instruments and hedging activities and their effects on the entity’s financial position, financial performance, and cash flows. SFAS 161 applies to all derivative instruments within the scope of SFAS No. 133, “Accounting for Derivatives and Hedging Activities” (“SFAS 133”) as well as

related hedged items, bifurcated derivatives, and non-derivative instruments that are designated and qualify as hedging instruments. The adoption of SFAS 161 did not have a material effect on the Company’s financial statements, other than disclosures.

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

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

In the opinion of management, the Company's unaudited consolidated financial statements as of March 31, 2009 and for the interim periods ended March 31, 2009 and 2008 include all adjustments which are necessary for a fair presentation in accordance with accounting principles generally accepted in the United States. These interim results are not necessarily indicative of the results to be expected for the year ending December 31, 2009.

Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States have been condensed or omitted in this Form 10-Q pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”). These consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto included in the Company's Form 10-K for the year ended December 31, 2008.

3. Recent Accounting Pronouncements

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

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

4. Long-Term Debt

Long-term debt consists of the following:

	March 31,			December 31,
	2009			2008
	(In thousands)
7¾% Senior Notes due 2013	$	225,000		$	225,000
Secured bank credit facility, due May 2012		108,500			94,100
Secured term loan of Larclay JV, due June 2011		34,688			39,375
Subordinated notes of Larclay JV(a)		7,500			7,500
		375,688			365,975
Less current maturities(b)		(18,750	)		(18,750	)
	$	356,938		$	347,225

(a) Note payable to Lariat Services Inc. (see Notes 10 and 13).

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

7¾% Senior Notes due 2013

In July 2005, the Company issued, in a private placement, $225 million of aggregate principal amount of 7¾% Senior Notes due 2013 (“Senior Notes”). The Senior Notes were issued at face value and bear interest at 7¾% per year, payable semi-annually on February 1 and August 1 of each year, beginning February 1, 2006.

At any time prior to August 1, 2009, the Company may redeem some or all of the Senior Notes at a redemption price equal to 100% of the principal amount of the Senior Notes to be redeemed, plus a make-whole premium, plus any accrued and unpaid interest. On and after August 1, 2009, the Company may redeem some or all of the Senior Notes at redemption prices (expressed as percentages of principal amount) equal to 103.875% for the twelve-month period beginning on August 1, 2009, 101.938% for the twelve-month period beginning on August 1, 2010, and 100% beginning on August 1, 2011 or for any period thereafter, in each case plus accrued and unpaid interest.

The Indenture governing the Senior Notes contains covenants that restrict the ability of the Company and its restricted 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 restricts the Company from borrowing any additional funds under the revolving credit facility if the Company’s outstanding balance on the facility is greater than $150 million and exceeds 30% of Adjusted Consolidated Net Tangible Assets, as defined in the Indenture. These covenants are subject to a number of important exceptions and qualifications as described in the Indenture. The Company was in compliance with these covenants at March 31, 2009.

Secured Bank Credit Facility

The Company’s secured bank credit facility provides for a revolving loan facility in an amount not to exceed the lesser of the borrowing base, as established by the banks, or that portion of the borrowing base determined by the Company to be the elected borrowing limit. The borrowing base, which is based on the discounted present value of future net revenues from oil and gas production, is subject to redetermination at any time, but at least semi-annually in May and November, and is made at the discretion of the banks. If, at any time, the redetermined borrowing base is less than the amount of outstanding indebtedness, the Company will be required to (1) pledge additional collateral, (2) prepay the excess in not more than five equal monthly installments, or (3) elect to convert the entire amount of outstanding indebtedness to a term obligation based on amortization formulas set forth in the loan agreement. Substantially all of the Company’s oil and gas properties are pledged to secure advances under the credit facility. The borrowing base at March 31, 2009 was $250 million. After allowing for outstanding letters of credit totaling $804,000, the Company had $140.7 million available under the credit facility at March 31, 2009.

The revolving credit facility provides for interest at rates based on the agent bank’s prime rate plus margins ranging from .25% to 1%, or if elected by the Company based on LIBOR plus margins ranging from 1.5% to 2.25%. The Company also pays a commitment fee on the unused portion of the revolving credit facility. Interest and fees are payable at least quarterly. The effective annual interest rate on borrowings under the combined credit facility, excluding bank fees and amortization of debt issue costs, for the three months ended March 31, 2009 was 2.1%.

The loan agreement applicable to the revolving credit facility contains financial covenants that are computed quarterly. The working capital covenant requires the Company to maintain a ratio of current assets to current liabilities of at least 1 to 1. Another financial covenant under the credit facility requires the Company to maintain a ratio of indebtedness to cash flow of no more than 3 to 1. The computations of current assets, current liabilities, cash flow and indebtedness are defined in the loan agreement. The Company was in compliance with all financial and non-financial covenants at March 31, 2009.

In April 2009, the Company and the banks amended the loan agreement applicable to the revolving credit facility to permit the acquisition by the Company of the remaining 50% interest in Larclay JV (see Notes 10 and 13).

Secured Term Loan of Larclay JV

In connection with the Company’s investment in Larclay JV (see Notes 10 and 13), Larclay JV obtained a $75 million secured term loan facility from a lender to finance the construction and equipping of 12 new drilling rigs. The Larclay JV term loan is secured by substantially all of the assets of Larclay JV. As additional credit support, the Company granted the lender a limited guaranty in the original amount of $19.5 million. The maximum obligation under the guaranty reduces by 10% on April 1 of each year, beginning April 1, 2008. At March 31, 2009, the maximum obligation of the Company under the guaranty was approximately $17.6 million. The Company is required to fully consolidate the accounts of Larclay JV under FASB Interpretation No. 46R “Consolidation of Variable Interest Entities – an Interpretation of ARB No. 51 (as amended)” (“FIN 46R”).

The Larclay JV term loan, bears interest at a floating rate based on a LIBOR average, plus 3.25%, and provides for monthly principal and interest payments sufficient to retire the principal balance by 35% in the first year, 25% in each of the next two years, and 15% in the fourth year. The Larclay JV term loan prohibits Larclay JV from making any cash distributions to the Company or Lariat until the balance on the term loan is fully repaid, and repayments by Larclay JV of any loans by the Company or Lariat are subordinated to the loans outstanding under the term loan and are subject to other restrictions. At March 31, 2009, the effective annual interest rate on the Larclay JV term loan was 3.9%.

5. Other Non-Current Liabilities

Other non-current liabilities consist of the following:

	March 31,		December 31,
	2009		2008
	(In thousands)
Abandonment obligations	$	33,010	$	31,737
Other taxes payable		144		145
Other		641		735
	$	33,795	$	32,617

Changes in abandonment obligations for the three months ended March 31, 2009 and 2008 are as follows:

	Three Months Ended
	March 31,
	2009			2008
	(In thousands)
Beginning of period	$	31,737		$	30,994
Additional abandonment obligations from new wells		573			68
Sales of properties		(18	)		(355	)
Accretion expense		718			530
End of period	$	33,010		$	31,237

6. Compensation Plans

Stock-Based Compensation

The Company has reserved 1,798,200 shares of common stock for issuance under the 1993 Stock Compensation Plan (“1993 Plan”). The 1993 Plan provides for the issuance of nonqualified stock options with an exercise price which is not less than the market value of the Company’s common stock on the date of grant. All options granted through March 31, 2009 expire 10 years from the date of grant and become exercisable based on varying vesting schedules. The Company issues new shares, not repurchased shares, to option holders that exercise stock options under the 1993 Plan. At March 31, 2009, 101,766 shares remain available for issuance under this plan.

The Company has reserved 86,300 shares of common stock for issuance under the Outside Directors Stock Option Plan (“Directors Plan”). Since the inception of the Directors Plan, the Company has issued options covering 52,000 shares of common stock at option prices ranging from $3.25 to $41.74 per share. All outstanding options expire 10 years from the grant date and are fully exercisable upon issuance. At March 31, 2009, 34,300 shares remain available for issuance under this plan. Effective January 1, 2009, no additional grants of options will be made under the Director’s Plan.

The following table sets forth certain information regarding the Company’s stock option plans as of and for the three months ended March 31, 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)		(19,394	)	$	5.50
Outstanding at March 31, 2009		34,244		$	20.70		3.74	$	292,493

Vested at March 31, 2009		34,244		$	20.70		3.74	$	292,493
Exercisable at March 31, 2009		34,244		$	20.70		3.74	$	292,493

(a) Based on closing price at March 31, 2009 of $29.24 per share.
(b) Cash received for options exercised totaled $107,000.

The following table summarizes information with respect to options outstanding at March 31, 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:
$5.50	8,244	$ 5.50	0.1
$10.00 - $19.74	8,000	$ 12.42	2.6
$22.90 - $41.74	18,000	$ 31.34	5.9
	34,244	$ 20.70	3.7

The following table presents certain information regarding stock-based compensation amounts for the three months ended March 31, 2009 and 2008.

	Three Months Ended
	March 31,
	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	$	328	$	19,650

Stock-based employee compensation expense	$	-	$	92
Tax benefit		-		(32	)
Net stock-based employee compensation expense	$	-	$	60

Non-Equity Award Plans

The Compensation Committee of the Board of Directors has adopted an after-payout (“APO”) incentive plan for officers, key employees and consultants who promote the Company’s drilling and acquisition programs. Management’s objective in adopting this plan is to further align the interests of the participants with those of the Company by granting the participants an APO interest in the production developed, directly or indirectly, by the participants. The plan generally provides for the creation of a series of partnerships or participation arrangements (“APO Partnerships”) between the Company and the participants to which the Company contributes a portion of its economic interest in wells drilled or acquired within certain areas. Generally, the Company pays all costs to acquire, drill and produce applicable wells and receives all revenues until it has recovered all of its costs, plus interest (“payout”). At payout, the participants receive 99% to 100% of all subsequent revenues and pay 99% to 100% of all subsequent expenses attributable to the APO Partnerships. Between 5% and 7.5% of the Company’s economic interests in specified wells drilled or acquired by the Company subsequent to October 2002 are subject to the APO incentive plan. The Company records its allocable share of the assets, liabilities, revenues, expenses and oil and gas reserves of these APO Partnerships in its consolidated financial statements.

The Compensation Committee has also authorized the formation of the APO Reward Plan which offers eligible officers, key employees and consultants the opportunity to receive bonus payments that are based on certain profits derived from a portion of the Company’s working interest in specified areas where the Company is conducting drilling and production enhancement operations. The wells subject to the APO Reward Plan are mutually exclusive from any wells subject to a participation agreement created under the APO Incentive Plan. Although conceptually similar to the APO Incentive Plan, the APO Reward Plan is a compensatory bonus plan pursuant to which the Company pays participants a bonus equal to a portion of APO cash flows received by the Company from its working interest. Unlike the APO Incentive Plan, however, participants in the APO Reward Plan are not immediately vested in all future amounts payable under the Plan. In May 2008, the Company granted awards under the APO Reward Plan in three 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 to the participants, and the full vesting date is May 5, 2013.

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

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

The Company recognizes compensation expense related to APO Partnerships based on the estimated fair value of the economic interests conveyed to the participants. Estimated compensation expense applicable to the APO Reward Plan and SWR Reward Plan is recognized over the five-year vesting period. The Company recorded non-cash compensation expense of $384,000 for the three months ended March 31, 2009 and $250,000 for the three months ended March 31, 2008 in connection with all non-equity award plans.

7. Derivatives

Commodity Derivatives

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

The following summarizes information concerning the Company’s net positions in open commodity derivatives applicable to periods subsequent to March 31, 2009. The settlement prices of commodity derivatives are based on NYMEX futures prices.

Swaps:

	Gas				Oil
	MMBtu (a)		Price		Bbls		Price
Production Period:
2nd Quarter 2009		1,570,000	$	5.47		470,000	$	49.68
3rd Quarter 2009		1,450,000	$	5.47		440,000	$	48.13
4th Quarter 2009		1,850,000	$	5.47		400,000	$	46.15
2010		7,540,000	$	6.80		327,000	$	53.30
2011		6,420,000	$	7.07		-	$	-
		18,830,000				1,637,000

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

Accounting For Derivatives

The Company accounts for its derivatives in accordance with SFAS 133. The Company did not designate any of its currently open commodity derivatives as cash flow hedges; therefore, all changes in the fair value of these contracts prior to maturity, plus any realized gains or losses at maturity, are recorded as other income (expense) in the Company’s statements of operations. The Company reports its fair value of derivatives as either a net current asset or liability or a net noncurrent asset or liability in its consolidated balance sheets. Cash flow is only impacted to the extent the actual derivative contract is settled by making or receiving a payment to or from the counterparty. For the three months ended March 31, 2009, the Company reported a $2.5 million net gain on derivatives, consisting of a $1.4 million gain related to changes in mark-to-market valuations and a $1.1 million realized gain for settled contracts. For the three months ended March 31, 2008, the Company reported a $46.1 million net loss on derivatives, consisting of a $32 million loss related to changes in mark-to-market valuations and a $14.1 million realized loss on settled contracts. At December 31, 2008, the Company had closed all of its then existing commodity derivatives.

Effect of Derivative Instruments on the Consolidated Balance Sheets

	Asset Derivatives		Liability Derivatives
		March 31,		March 31,
	Balance Sheet	2009	Balance Sheet	2009
	Location	Fair Value	Location	Fair Value
	(In thousands)
Derivatives not designated as
hedging instruments under
SFAS 133:
Commodity contracts	Other assets -		Current liabilities -
	Fair value of derivatives	$ 3,416	Fair value of derivatives	$ 2,037
Total		$ 3,416		$ 2,037

Gross to Net Presentation Reconciliation of Derivative Assets and Liabilities

	March 31, 2009
	Assets			Liabilities			Total
	(In thousands)
Fair value of derivatives – gross presentation	$	16,061		$	(14,682	)	$	1,379
Effects of netting arrangements		(12,645	)		12,645			-
Fair value of derivatives – net presentation	$	3,416		$	(2,037	)	$	1,379

All of the Company’s derivatives are with one counterparty, which has a credit rating of AA as determined by a nationally recognized statistical ratings organization. The Company has elected to net the outstanding positions by 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
		Three Months Ended
	Location of Gain or (Loss)	March 31,
	Recognized in Earnings	2009	2008
		(In thousands)
Derivatives not designated as
hedging instruments under
SFAS 133:
Commodity contracts	Other income (expense) -
	Gain (loss) on derivatives	$ 2,510	$ (46,109)
Total		$ 2,510	$ (46,109)

8. Financial Instruments

Cash and cash equivalents, receivables, accounts payable and accrued liabilities were each estimated to have a fair value approximating the carrying amount due to the short maturity of those instruments. Indebtedness under the Company’s secured bank credit facility was estimated to have a fair value approximating the carrying amount since the interest rate is generally market sensitive. The estimated fair value of the Company’s Senior Notes at March 31, 2009 and December 31, 2008 was approximately $139.5 million and $126 million; respectively, based on market quotes.

Determination of Fair Value

The Company has adopted SFAS 157. SFAS 157 defines fair value, establishes a framework for measuring fair value, outlines a fair value hierarchy based on the quality of inputs used to measure fair value and enhances disclosure requirements for fair value measurements.

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

In accordance with SFAS 157, the Company categorizes its assets and liabilities recorded at fair value in the accompanying consolidated balance sheets based upon the level of judgment associated with the inputs used to measure their fair value. Hierarchical levels, defined by SFAS 157 and directly related to the amount of subjectivity associated with the inputs to fair valuation of these assets and liabilities, are as follows:

Level 1 -

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

Level 2 -

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

Level 3 -

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

The fair value of derivative contracts are measured using Level 2 inputs, and are determined by either market prices on an active market for similar assets or by prices quoted by a broker or other market-corroborated prices.

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

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

	Fair Value Measurements
	March 31, 2009
	Significant
	Other
	Observable
	Inputs
Description	(Level 2)
	(In thousands)
Assets:
Fair value of commodity derivatives	$	3,416
Total assets	$	3,416

Liabilities:
Fair value of commodity derivatives	$	2,037
Total liabilities	$	2,037

Assets measured at fair value on a nonrecurring basis follow and the loss recorded for the three months ended March 31, 2009:

	Fair Value Measurements
	March 31, 2009
	Significant
	Other
	Observable
	Inputs		Total
Description	(Level 2)		Losses
	(In thousands)
Assets:
Inventory	$	10,145	$	3,268
Long-lived assets held and used		15,907		10,093
Total assets	$	26,052	$	13,361

9. Income Taxes

The Company’s effective federal and state income tax benefit rate for the three months ended March 31, 2009 of 36.8% differed from the statutory federal rate of 35% due primarily to increases in the tax provision related primarily to the effects of the Texas Margin Tax and certain non-deductible expenses, offset in part by tax benefits derived from excess statutory depletion deductions.

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

Upon adoption of FASB Interpretation No. 48 “Accounting for Uncertainty in Income Taxes” - “An Interpretation of FASB Statement No. 109” (“FIN 48”), the Company recorded a liability for taxes payable related to unrecognized tax benefits arising from uncertain tax positions taken by the Company in previous periods. A reconciliation of the changes in this tax liability for the quarter ended March 31, 2009.

	March 31,
	2009
	(In thousands)
Balance at beginning of period	$	144
Reductions for tax positions of prior years		-
Balance at end of period	$	144

No unrecognized tax benefits originated during the first three months of 2009. All of the remaining unrecognized tax benefits at March 31, 2009 relate to tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductions. Because of the impact of deferred tax accounting, the disallowance of the shorter deduction period would not affect the annual effective tax rate but would only accelerate the payment of taxes to the taxing authority or change the amount of deferred tax assets related to net operating loss carryforwards.

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

10. Investments

Larclay JV

In April 2006, the Company formed a joint venture (“Larclay JV”) with Lariat Services, Inc. (“Lariat”) to construct, own and operate 12 new drilling rigs. Until April 15, 2009 (see Note 13), the Company and Lariat each owned a 50% equity interest in Larclay JV. A lender has provided a $75 million secured term loan to Larclay JV to finance the cost of constructing and equipping of the drilling rigs (see Note 4). The principal balance outstanding on the Larclay JV term loan at March 31, 2009 was $34.7 million. The Larclay JV term loan is secured by substantially all of the assets of Larclay JV. As additional credit support, the Company granted the lender a limited guaranty in the original amount of $19.5 million. The maximum obligation under the guaranty reduces by 10% on April 1 of each year, beginning April 1, 2008. At March 31, 2009, the Company’s maximum obligation under the guaranty was approximately $17.6 million. CWEI is not obligated under the Larclay JV term loan except to the extent of the guaranty.

Since inception of this joint venture, the Company has made advances structured as subordinated loans to Larclay JV totaling $12.1 million, $4.6 million to finance excess construction costs and $7.5 million to finance the Company’s 50% share of working capital assessments made by Larclay JV. Lariat has also advanced Larclay JV $7.5 million for its 50% share of working capital assessments. Loans to Larclay JV by Lariat and the Company are due on demand and bear interest, payable monthly, at the same rate as the term loan. However, these loans are subject to a subordination agreement with the Larclay JV lender that imposes restrictions on payments of principal and interest on the loans. Subsequent to March 31, 2009, all of these subordinated loans were contributed to the capital of Larclay JV (see Note 13).

In connection with the formation of Larclay JV, the Company entered into a three-year drilling contract with Larclay JV assuring the availability of Larclay JV’s drilling rigs for use in the ordinary course of the Company’s exploration and development drilling program throughout the term of the drilling contract. The drilling contract, which is pledged as collateral to secure the Larclay JV term loan, expires on the earlier of December 31, 2009 or the termination and liquidation of Larclay JV. The drilling contract provides for the Company to contract for each drilling rig on a well-by-well basis at then current market rates. If a drilling rig is not needed by the Company at any time during the term of the contract, Larclay JV may contract with other operators for the use of such drilling rig, subject to certain restrictions. If a drilling rig is idle, the contract requires the Company to pay Larclay JV an idle rig rate ranging from $8,100 per day to $10,300 per day (plus crew labor expenses, if applicable), depending on the size of the drilling rig. At March 31, 2009, all of the Larclay JV drilling rigs were idle. The Company’s maximum potential obligation to pay idle rig rates over the remaining term of the drilling contract, excluding any crew labor expenses, totals approximately $20.6 million at March 31, 2009. The Company paid $7.2 million ($5.4 million net of intercompany eliminations) for idle rig fees during the quarter ended March 31, 2009.

Although the Company and Lariat initially owned equal interests in Larclay JV, the Company met the definition of the primary beneficiary of Larclay JV’s expected cash flows under FIN 46R. As the primary beneficiary under FIN 46R, the Company is required to include the accounts of Larclay JV in the Company’s consolidated financial statements. As of March 31, 2009, Lariat’s equity ownership in the net assets of Larclay JV was $6.6 million, which is recorded as noncontrolling interest and included in equity in the accompanying consolidated financial statements. The Company’s intercompany accounts and profits with Larclay JV have been eliminated in consolidation.

Effective April 15, 2009, Lariat assigned all of its right, title and interest in and to the Larclay JV to the Company (see Note 13).

11. Oil and Gas Properties

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

	March 31,			December 31,
	2009			2008
	(In thousands)
Proved properties	$	1,464,374		$	1,435,718
Unproved properties		84,192			90,755
Total capitalized costs		1,548,566			1,526,473
Accumulated depreciation, depletion and amortization		(826,255	)		(791,507	)
Net capitalized costs	$	722,311		$	734,966

12. Sales of Assets and Inventory Write-downs

The Company recorded a net loss of $3.3 million on sales of assets and inventory write-downs during the first quarter of 2009 related primarily to the write-down of inventory to its estimated market value at March 31, 2009.

13. Subsequent Event

Effective April 15, 2009, the Company acquired the remaining 50% equity interest in Larclay JV pursuant to an agreement with Lariat dated March 13, 2009 (the “Assignment”). As a result of the transactions contemplated by the Assignment, the Company now owns 100% of Larclay JV. In connection with the Assignment, the Company assumed all of the obligations and liabilities of Lariat relating to Larclay JV from and after the effective date, including Lariat’s obligations as operator of the Larclay JV drilling rigs. The assignment from Lariat to the Company includes all of Lariat’s right, title and interest in the subordinated loans previously advanced by Lariat to Larclay JV.

Immediately upon consummation of the Assignment, the Company contributed all of the subordinated notes issued by Larclay JV in the aggregate principal amount of $19.6 million to the capital of Larclay JV, and Larclay JV adopted a plan of disposition whereby Larclay JV would commit to sell eight of its 12 drilling rigs. The plan of disposition meets the criteria under SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets (as amended)” (“SFAS 144”), for the designated assets to be classified as held for sale. SFAS 144 requires the Company to value the designated assets at the lower of their carrying value or fair value, less cost to sell, as of the date the plan of disposition was adopted. The Company estimates the fair value of the designated assets to be approximately $18.8 million. As a result, the Company will reclassify the estimated fair value of the designated assets to “Assets Held for Sale” in its balance sheet effective April 15, 2009, and will record a related charge for impairment of property and equipment of approximately $32.1 million in its statement of operations for the second quarter of 2009. No impairment on the Larclay drilling rigs was recorded at March 31, 2009 since the criteria for impairment under SFAS 144 was not met at that date.

Historically, we have fully consolidated the accounts of Larclay JV under FIN 46R. As a result of the transactions contemplated by the Assignment, as of the effective date, the Company owns a 100% interest in Larclay JV and will continue to fully consolidate the accounts of Larclay JV as a wholly-owned subsidiary.

14. Segment Information

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

The following tables present selected financial information regarding the Company’s operating segments for the three-month periods ended March 31, 2009 and 2008.

For the Three Months Ended
March 31, 2009
(Unaudited)				Contract			Intercompany			Consolidated
(In thousands)	Oil and Gas			Drilling			Eliminations			Total

Revenues	$	52,562		$	9,186		$	(3,966	)	$	57,782
Depreciation, depletion and amortization (a)		34,991			2,738			(1,264	)		36,465
Other operating expenses (b)		52,883			2,693			(2,639	)		52,937
Interest expense		4,905			533			-			5,438
Other (income) expense		(3,411	)		-			-			(3,411	)
Income (loss) before income taxes		(36,806	)		3,222			(63	)		(33,647	)

Income tax (expense) benefit		13,510			(1,132	)		-			12,378
Net income (loss)		(23,296	)		2,090			(63	)		(21,269	)
Less income attributable to
noncontrolling interest, net of tax		563			(1,609	)		-			(1,046	)

Net income (loss) attributable to
Clayton Williams Energy, Inc	$	(22,733	)	$	481		$	(63	)	$	(22,315	)

Total assets	$	820,547		$	76,058		$	(500	)	$	896,105
Additions to property and equipment	$	34,689		$	-		$	-		$	34,689

For the Three Months Ended
March 31, 2008
(Unaudited)				Contract			Intercompany			Consolidated
(In thousands)	Oil and Gas			Drilling			Eliminations			Total

Revenues	$	122,026		$	17,163		$	(2,331	)	$	136,858
Depreciation, depletion and amortization (a)		27,988			2,610			(325	)		30,273
Other operating expenses (b)		30,815			13,008			(1,653	)		42,170
Interest expense		6,352			1,094			-			7,446
Other (income) expense		45,454			-			-			45,454
Income (loss) before income taxes		11,417			451			(353	)		11,515

Income tax (expense) benefit		(3,964	)		(258	)		-			(4,222	)
Net income (loss)		7,453			193			(353	)		7,293
Less income attributable to
noncontrolling interest, net of tax		62			(176	)		-			(114	)

Net income (loss) attributable to
Clayton Williams Energy, Inc	$	7,515		$	17		$	(353	)	$	7,179

Total assets	$	816,632		$	96,197		$	(4,787	)	$	908,042
Additions to property and equipment	$	55,431		$	9		$	(353	)	$	55,087

(a) Includes impairment of property and equipment.

(b)

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

15. Guarantor Financial Information

In July 2005, Clayton Williams Energy, Inc. (“Issuer”) issued $225 million of Senior Notes (see Note 4). Other than West Coast Energy Properties GP, LLC (“WCEP LLC”), the general partner of West Coast Energy Properties, L.P., an affiliated limited partnership, all of the Issuer’s wholly-owned and active subsidiaries (“Guarantor Subsidiaries”) have jointly and severally, irrevocably and unconditionally guaranteed the performance and payment when due of all obligations under the Senior Notes. Larclay JV, a 50%-owned drilling rig joint venture formed in April 2006, and WCEP LLC have not guaranteed the Senior Notes and are referred to in this Note 15 as Non-Guarantor Entities.

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

Condensed Consolidating Balance Sheet

March 31, 2009

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

Current assets	$	141,590	$	190,322	$	9,561	$	(250,927	)	$	90,546
Property and equipment, net		384,596		336,179		73,683		-			794,458
Investments in subsidiaries		72,082		-		-		(72,082	)		-
Other assets		22,692		371		190		(12,152	)		11,101
Total assets	$	620,960	$	526,872	$	83,434	$	(335,161	)	$	896,105

Current liabilities	$	60,578	$	263,316	$	20,707	$	(246,375	)	$	98,226
Non-current liabilities:
Long-term debt		333,500		-		35,538		(12,100	)		356,938
Other		83,782		57,934		111		-			141,827
		417,282		57,934		35,649		(12,100	)		498,765

Equity		143,100		205,622		27,078		(76,686	)		299,114
Total liabilities and
equity	$	620,960	$	526,872	$	83,434	$	(335,161	)	$	896,105

Condensed Consolidating Balance Sheet

December 31, 2008

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

Current assets	$	178,349	$	173,636	$	15,749	$	(242,250	)	$	125,484
Property and equipment, net		388,189		345,327		76,512		-			810,028
Investments in subsidiaries		72,082		-		-		(72,082	)		-
Other assets		19,629		372		211		(12,315	)		7,897
Total assets	$	658,249	$	519,335	$	92,472	$	(326,647	)	$	943,409

Current liabilities	$	83,288	$	253,627	$	28,212	$	(242,250	)	$	122,877
Non-current liabilities:
Long-term debt		319,100		-		40,225		(12,100	)		347,225
Other		101,213		57,301		114		(3	)		158,625
		420,313		57,301		40,339		(12,103	)		505,850

Equity		154,648		208,407		23,921		(72,294	)		314,682
Total liabilities and
equity	$	658,249	$	519,335	$	92,472	$	(326,647	)	$	943,409

Condensed Consolidating Statement of Operations

Three Months Ended March 31, 2009

(Unaudited)							Non-
(In thousands)				Guarantor			Guarantor			Adjustments/
	Issuer			Subsidiaries			Entities			Eliminations			Consolidated

Total revenue	$	33,539		$	19,179		$	9,306		$	(4,242	)	$	57,782
Costs and expenses		63,819			24,110			5,651			(4,178	)		89,402
Operating income (loss)		(30,280	)		(4,931	)		3,655			(64	)		(31,620	)
Other income (expense)		(2,899	)		1,369			(497	)		-			(2,027	)
Income tax (expense) benefit		12,378			-			-			-			12,378
Noncontrolling interest, net of tax		(1,046	)		-			-			-			(1,046	)

Net income (loss)	$	(21,847	)	$	(3,562	)	$	3,158		$	(64	)	$	(22,315	)

Condensed Consolidating Statement of Operations

Three Months Ended March 31, 2008

(Unaudited)							Non-
(In thousands)				Guarantor			Guarantor			Adjustments/
	Issuer			Subsidiaries			Entities			Eliminations			Consolidated

Total revenue	$	80,232		$	41,973		$	17,363		$	(2,710	)	$	136,858
Costs and expenses		39,871			19,128			15,801			(2,357	)		72,443
Operating income (loss)		40,361			22,845			1,562			(353	)		64,415
Other income (expense)		(48,269	)		(3,578	)		(1,053	)		-			(52,900	)
Income tax (expense) benefit		(4,222	)		-			-			-			(4,222	)
Noncontrolling interest, net of tax		(114	)		-			-			-			(114	)

Net income (loss)	$	(12,244	)	$	19,267		$	509		$	(353	)	$	7,179

Condensed Consolidating Statement of Cash Flows

Three Months Ended March 31, 2009

(Unaudited)							Non-
(In thousands)				Guarantor			Guarantor			Adjustments/
	Issuer			Subsidiaries			Entities			Eliminations			Consolidated

Operating activities	$	15,176		$	(8,505	)	$	5,381		$	1,239		$	13,291
Investing activities		(43,738	)		(3,469	)		(48	)		(1,239	)		(48,494	)
Financing activities		3,226			11,312			(4,718	)		-			9,820
Net increase (decrease) in
cash and cash equivalents		(25,336	)		(662	)		615			-			(25,383	)

Cash at the beginning of
the period		35,381			1,810			4,008			-			41,199

Cash at end of the period	$	10,045		$	1,148		$	4,623		$	-		$	15,816

Condensed Consolidating Statement of Cash Flows

Three Months Ended March 31, 2008

(Unaudited)							Non-
(In thousands)				Guarantor			Guarantor			Adjustments/
	Issuer			Subsidiaries			Entities			Eliminations			Consolidated

Operating activities	$	41,156		$	31,955		$	4,614		$	325		$	78,050
Investing activities		(36,008	)		(14,032	)		(181	)		(325	)		(50,546	)
Financing activities		3,172			(17,923	)		(6,574	)		-			(21,325	)
Net increase (decrease) in
cash and cash equivalents		8,320			-			(2,141	)		-			6,179

Cash at the beginning of
the period		5,325			1,288			5,731			-			12,344

Cash at end of the period	$	13,645		$	1,288		$	3,590		$	-		$	18,523

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

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

Forward-Looking Statements

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

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

	•	estimates of our oil and gas reserves;

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

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

	•	our outlook on oil and gas prices;

	•	our outlook on domestic and worldwide economic conditions;

	•	our access to capital and our anticipated liquidity;

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

	•	the impact of political and regulatory developments;

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

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

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

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

	•	the possibility of unsuccessful exploration and development drilling activities;

	•	our ability to replace and sustain production;


	•	commodity price volatility;

	•	domestic and worldwide economic conditions;

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

	•	our level of indebtedness;

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

	•	declines in the value of our oil and gas properties resulting in a decrease in our borrowing base under our credit facility and impairments;
	•	the ability of financial counterparties to perform or fulfill their obligations under existing agreements;
	•	the uncertainty inherent in estimating proved oil and gas reserves and in projecting future rates of production and timing of development expenditures;

	•	drilling and other operating risks;

	•	hurricanes and other weather conditions;

	•	lack of availability of goods and services;

	•	regulatory and environmental risks associated with drilling and production activities;

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

	•	the other risks described in our Form 10-K for the year ended December 31, 2008.

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

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

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

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 the first quarter of 2009 and is currently being viewed by many economists as the most severe recession in United States history, second only to the Great Depression. The United States government has taken significant steps to support the financial markets and stimulate the economy in an effort to slow or reverse the downward spiral of economic indicators, but the success of these measures and the duration of the current recession cannot be predicted.

Reduced demand for energy caused by the current recession has resulted in a significant deterioration in oil and gas prices, which in turn has led to a significant reduction in drilling activity throughout the oil and gas industry. The prices we pay for field services generally lag behind the declines in oil and gas prices. As a result, we have experienced reductions in operating margins during the last half of 2008 and into the first 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. In response to decreases in product prices and the resulting effect on our operating margins, we currently plan to spend approximately $78.5 million on exploration and development activities in fiscal 2009 as compared to $372.7 million spent in fiscal 2008.

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.

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 first quarter of 2009 and the outlook for the remainder of 2009.

·	Our oil and gas sales for the first quarter decreased $68.1 million, or 57%, from 2008. Price variances accounted for a $66.7 million decrease and production variances accounted for a $1.4 million decrease.

Our oil and gas production for the first quarter of 2009 was 6% lower on a barrel of oil equivalent ("BOE") basis than in the comparable period in 2008. Our oil production was 10% higher than the first quarter of 2008 which was more than offset by a 17% drop in gas production compared to the 2008 period. The comparability of production between the two quarters was affected by the sale of certain South Louisiana properties in the second quarter of 2008.

We recorded a $2.5 million net gain on derivatives in the first quarter of 2009, consisting of a $1.1 million realized gain on settled contracts and a $1.4 million gain for changes in mark-to-market valuations. 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 first quarter of 2009, we increased borrowings under our revolving credit facility by $14.4 million from $94.1 million at December 31, 2008 to $108.5 million at March 31, 2009 in order to partially finance additions to property and equipment.

At March 31, 2009, our capitalized unproved oil and gas properties totaled $84.2 million, of which approximately $40.7 million was attributable to unproved acreage. Therefore, our results of operations in future periods may be adversely affected by abandonments and impairments related to unproved oil and gas properties.

Recent Exploration and Development Activities

Overview

Our long-term exploration and development focus is on developmental drilling for oil reserves. With oil prices on the rise during the last half of 2007, we began a program to exploit our large inventory of lower risk, developmental drilling locations, primarily in the Permian Basin and the Austin Chalk (Trend) areas of our asset base. However, we continue to invest in our higher risk, higher impact exploration programs.

The current economic recession has caused us to significantly reduce the level of developmental drilling pending an improvement in product prices and operating margins. Approximately 70% of the $37.9 million spent on exploration and development activities during the first quarter of 2009 was applicable to exploratory prospects. These prospects were primarily in areas where we have invested significant capital in acreage and seismic data, or were prospects for which we had made drilling commitments to joint owners in the wells. We presently plan to spend approximately $78.5 million on exploration and development activities during 2009, of which approximately 50% 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 $8.7 million in the Permian Basin during the first quarter of 2009 on drilling and completion activities. We drilled 4 gross (3.9 net) operated wells in the Permian Basin and conducted various remedial operations on other wells in 2009. We currently plan to spend $25.1 million on drilling and completion activities in the Permian Basin in fiscal 2009.

North Louisiana

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

To date, we have drilled 18 wells on our Terryville prospect and have completed 16 as producers. On our Ruston prospect, we have completed three wells as producers and are currently completing a fourth well. We spent $2.4 million in North Louisiana during the three months of 2009 on exploration and development activities, of which $2.2 million was spent on drilling and completion activities and $200,000 was spent on seismic and leasing activities. We currently plan to spend $4 million for fiscal 2009 in this area.

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 tested during the fourth quarter of 2008 at a rate of 11 million cubic feet of gas per day and 739 barrels of oil per day. After construction of a pipeline is complete, we expect to have the well on production by the middle of 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, Louisiana, due to down hole mechanical problems. We have moved the drilling rig approximately 20 feet north of the current location and are drilling the Miami Corp #2 as a replacement well. We have modified the drilling plan to address the problems encountered in the first well, and will target the same formation in the lower Miocene sands at an approximate depth of 17,500 feet. We will own a 50% working interest in any production established by this well.

We spent $9.8 million in South Louisiana during the three months ended March 31, 2009 on exploration and development activities, of which $9.1 million was spent on drilling and completion activities and $700,000 was spent on seismic and leasing activities. We currently plan to spend $23.3 million for fiscal 2009, of which $20.6 million relates to drilling and completion activities and the remaining $2.7 million relates to seismic and leasing activities.

East Texas Bossier

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

We are currently completing the Sunny Unit #1, a 17,300-foot exploratory well in Burleson County, Texas. The well was successfully drilled to the deep Bossier formation, and completed in the middle Bossier sands. We are currently flow testing the well to determine if the well is capable of producing gas in commercial quantities. To date, we have incurred drilling costs of approximately $17.7 million on this well (100% working interest).

Prior to drilling the Sunny Unit #1, we drilled two other wells targeting the deep Bossier sands in East Texas: the Big Bill Simpson #1, a 19,500-foot exploratory well in Leon County (70% working interest), and the Margarita #1, a 18,300-foot exploratory well in Robertson County (100% working interest). The Big Bill Simpson #1 is currently producing at minimal rates, and the Margarita #1 is currently producing at a rate of approximately 400 Mcf of gas per day from an upper Bossier sand.

We spent $13.5 million in the East Texas Bossier area during the three months ended March 31, 2009 on exploration and development activities, of which $5.9 million was spent on drilling and completion activities and $7.6 million was spent on seismic and leasing activities. We currently plan to spend $19.9 million for fiscal 2009, of which $6.9 million relates to drilling and completion activities and the remaining $13 million relates to seismic and leasing activities.

Austin Chalk (Trend)

Prior to 1998, we concentrated our drilling activities in an oil-prone area we refer to as the Austin Chalk (Trend) in Robertson, Burleson, Brazos, Milam and Leon Counties, Texas. Most of our wells in this area were drilled as horizontal wells, many with multiple laterals in different producing horizons, including the Austin Chalk, Buda and Georgetown formations. The existing spacing between some of our wells in this area affords us the opportunity to tap additional oil and gas reserves by drilling new wells between existing wells, a technique referred to as in-fill drilling. These in-fill wells are considered lower risk as compared to exploratory wells and until recently, offered more attractive rates of return.

We spent $400,000 in the Austin Chalk (Trend) area during the first three months of 2009. Due to recent declines in product prices and lower operating margins on drilling, we currently plan to spend only $1.5 million in the Austin Chalk (Trend) for fiscal 2009.

Utah

In 2008, we participated in the drilling of the Ron Lamb 31A-4-1, a 12,670-foot exploratory well in which we own a 33% non-operated working interest. The well was drilled in the central Overthrust area in Sanpete County, Utah targeting the oil-prone Navajo sandstone formation. We temporarily abandoned this well in the first quarter of 2009 and recorded a pre-tax charge of approximately $1.4 million for drilling and leasehold impairments related to this well in the first quarter of 2009. We plan to participate in the drilling of a third exploratory well in this area in the fourth quarter of 2009 to further evaluate our acreage position.

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
	March 31,
	2009			2008
Oil and Gas Production Data:
Gas (MMcf)		4,613			5,548
Oil (MBbls)		751			684
Natural gas liquids (MBbls)		53			58
Total (MBOE) ��		1,573			1,667

Average Realized Prices (a):
Gas ($/Mcf)	$	4.60		$	8.86
Oil ($/Bbl)	$	37.09		$	96.37
Natural gas liquids ($/Bbl)	$	22.94		$	54.83

Gain (Loss) on Settled Derivative Contracts (a):
($ in thousands, except per unit)
Gas: Net realized gain (loss)	$	1,398		$	(884	)
Per unit produced ($/Mcf)	$	.30		$	(.16	)
Oil: Net realized gain (loss)	$	(267	)	$	(12,906	)
Per unit produced ($/Bbl)	$	(.36	)	$	(18.87	)

Average Daily Production:
Gas (Mcf):
Permian Basin		15,674			15,562
North Louisiana		14,550			13,596
South Louisiana		12,592			23,552
Austin Chalk (Trend)		3,030			2,460
Cotton Valley Reef Complex		4,274			5,270
Other		1,136			527
Total		51,256			60,967

Oil (Bbls):
Permian Basin		4,456			3,494
North Louisiana		270			343
South Louisiana		391			985
Austin Chalk (Trend)		3,142			2,635
Other		85			59
Total		8,344			7,516

Natural Gas Liquids (Bbls):
Permian Basin		225			215
North Louisiana		1			2
South Louisiana		45			140
Austin Chalk (Trend)		307			272
Other		11			8
Total		589			637

(Continued)

	Three Months Ended
	March 31,
	2009		2008
Exploration Costs (in thousands):
Abandonment and impairment costs:
North Louisiana	$	260	$	297
South Louisiana		728		-
Permian Basin		455		-
East Texas Bossier		8,867		-
Utah		1,774		-
Mississippi		311		-
Other		17		-
Total		12,412		297

Seismic and other		4,270		3,675
Total exploration costs	$	16,682	$	3,972

Depreciation, Depletion and Amortization (in thousands):
Oil and gas depletion	$	34,762	$	27,741
Contract drilling depreciation		1,474		2,285
Other depreciation		229		247
Total DD&A	$	36,465	$	30,273

Oil and Gas Costs ($/BOE Produced):
Production costs	$	12.12	$	12.34
Oil and gas depletion	$	22.10	$	16.64

Net Wells Drilled (b):
Exploratory Wells		0.2		1.7
Developmental Wells		6.0		12.9

(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 March 31, 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 $68.1 million, or 57%, from 2008. Price variances accounted for a $66.7 million decrease, and production variances accounted for a $1.4 million decrease. Production in 2009 (on a BOE basis) was 6% lower than 2008, despite significant additions from our developmental drilling programs. Oil production increased 10% in 2009 from 2008 and gas production decreased 17% in 2009 from 2008. The comparability of production between the 2009 and 2008 periods was affected by the sale of certain South Louisiana properties which produced approximately 900 barrels of oil and 13,000 Mcf of gas per day during the 2008 period. After excluding the sold production from the 2008 reported volumes, oil production increased 26% during 2009 while gas production increased 7%. In 2009, our realized oil price was 62% lower than 2008, while our realized gas price was 48% 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 7% in 2009 as compared to 2008 due primarily to lower production taxes. After giving effect to a 6% decrease in oil and gas production on a BOE basis, production costs per BOE decreased 2% from $12.34 per BOE in 2008 to $12.12 per BOE in 2009.

Oil and gas depletion expense increased $7 million from 2008 to 2009, of which rate variances accounted for a $8.6 million increase and production variances accounted for a $1.6 million decrease. On a BOE basis, depletion expense increased 33% from $16.64 per BOE in 2008 to $22.10 per BOE in 2009 due to a combination of higher depletable costs and lower estimated reserve quantities in 2009 compared to the 2008 period. Depletion expense per BOE of oil and gas production is an operating metric that is indicative of our weighted average cost to find or acquire a unit of equivalent production. We may realize higher oil and gas depletion rates in future periods if our exploration and development activities result in higher finding costs.

Exploration costs

Since we follow the successful efforts method of accounting, our results of operations are adversely affected during any accounting period in which significant seismic costs, exploratory dry hole costs, and unproved acreage impairments are expensed. In 2009, we charged to expense $16.7 million of exploration costs, as compared to $4 million in 2008.

We plan to spend approximately $78.5 million on exploration and development activities in fiscal 2009, of which approximately 50% is expected to be allocated to exploration activities. Since exploratory drilling involves a high degree of risk, it is likely that a significant portion of the costs we incur in 2009 will be charged to exploration costs. However, we cannot predict our success rates and, accordingly, cannot predict our exploration costs related to abandonment and impairment costs.

Contract Drilling Services

In April 2006, we formed a joint venture (“Larclay JV”) with Lariat Services, Inc. to construct, own, and operate 12 new drilling rigs. Until April 15, 2009, we owned a 50% equity interest in Larclay JV. Although the Company and Lariat owned equal interests in Larclay JV, we met the definition of the primary beneficiary of Larclay JV’s expected cash flows under FIN 46R. As the primary beneficiary under FIN 46R, we were required to include the accounts of Larclay JV in our consolidated financial statements. During the three months ended March 31, 2009, we included contract drilling revenues of $5.2 million, other operating expenses of $54,000, depreciation expense of $1.5 million

and interest expense of $533,000 in our statement of operations (see Note 14 to the consolidated financial statements). Since the Larclay JV drilling rigs were partially utilized by us, the reported amounts are net of any intercompany profits eliminated in consolidation.

In connection with the formation of Larclay JV, we entered into a drilling contract with Larclay JV for the use of its drilling rigs. The drilling contract, which is pledged as collateral to secure the Larclay JV term loan, expires on the earlier of December 31, 2009 or the termination and liquidation of Larclay JV. The drilling contract provides for us 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 us at any time during the term of the contract, Larclay JV may contract with other operators for the use of such drilling rig, subject to certain restrictions. If a drilling rig is idle, the contract requires us to pay Larclay JV 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. In response to lower product prices and profit margins on drilling, we are suspending drilling activities in certain areas in which we have been utilizing rigs owned by Larclay JV. At March 31, 2009, all of the Larclay JV drilling rigs were idle. Since we fully consolidate the accounts of Larclay JV in our consolidated financial statements, consolidated drilling revenues, after elimination of intercompany transactions, may be lower in future periods.

Effective April 15, 2009, we acquired the remaining 50% equity interest in Larclay JV pursuant to an agreement with Lariat dated March 13, 2009 (the “Assignment”). Immediately upon consummation of the Assignment, Larclay JV adopted a plan of disposition to sell eight of its 12 drilling rigs. In connection with this plan, we expect to record a charge for impairment of property and equipment of approximately $32.1 million during the second quarter of 2009. No impairment was required at March 31, 2009 since the criteria for impairment at that date was not met.

General and Administrative

General and administrative (“G&A”) expenses increased 31% from $3.4 million in 2008 to $4.5 million in 2009. Excluding non-cash employee compensation, G&A expenses increased from $3.1 million in 2008 to $4.2 million in 2009 due primarily to an increase in legal, insurance and professional fees. In 2009, we recorded a $384,000 non-cash charge related to non-equity incentive plans. In 2008, we recorded a $250,000 non-cash compensation charge related to non-equity incentive plans and $92,000 for stock-based compensation to directors.

Interest expense

Interest expense decreased 27% from $7.4 million in 2008 to $5.4 million in 2009 due to a combination of reduced debt levels and lower interest rates. The average daily principal balance outstanding under our revolving credit facility for 2009 was $95.7 million compared to $174.5 million for 2008. During 2008, we received approximately $117 million from the sale of property and equipment and used the net proceeds to reduce indebtedness outstanding under our revolving credit facility. Debt reductions on our revolving credit facility accounted for $1.1 million of the decrease in interest expense, while lower interest rates resulted in a decrease of approximately $800,000. In addition, capitalized interest for 2009 was $321,000 compared to $793,000 in 2008, and interest expense associated with our Larclay JV during 2009 was $422,000 compared to $1.1 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 three months ended March 31, 2009, we reported a $2.5 million net gain on derivatives, consisting of a $1.4 million non-cash gain to mark our derivative positions to their fair value at March 31, 2009 and a $1.1 million realized gain on settled contracts. For the three months ended March 31, 2008, we reported a $46.1 million net loss on derivatives, consisting of a $32 million non-cash loss to mark our derivative positions to their fair value at March 31, 2008 and a $14.1 million realized loss on settled contracts. Because oil and gas prices are volatile, and because we do not account for our derivatives as cash flow hedges, the effect of mark-to-market valuations on our gain/loss on derivatives can cause significant volatility in our results of operations.

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

We recorded a net loss of $3.3 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 March 31, 2009.

Income tax expense

Our estimated effective income tax benefit rate in 2009 of 36.8% differed from the statutory federal rate of 35% due primarily to increases in the tax provision related primarily to the effects of the Texas Margin Tax and certain non-deductible expenses, offset in part by tax benefits derived from excess statutory depletion deductions.

Liquidity and Capital Resources

Overview

Our primary financial resource is our base of oil and gas reserves. We pledge our producing oil and gas properties to a group of banks 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 the cost of field services have lagged behind the decline in oil and gas prices. As a result, we have experienced reductions in operating margins and have realized downward revisions in our proved reserves. The effects of lower operating margins on our business are significant since they reduce our cash flow from operations and diminish the estimated present value of our oil and gas reserves. These factors have an adverse affect on our ability to access the capital resources we need to grow our reserve base. Downward revisions in estimated proved reserves can adversely affect the amount of funds we can borrow on the credit facility. Lower operating margins also offer us less incentive to assume the drilling risks that are inherent in our business. In response to decreases in product prices and the resulting effect on our operating margins, we currently plan to spend approximately $78.5 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. One such covenant prohibits us from borrowing any additional funds under the revolving credit facility if our outstanding balance on the facility is greater than $150 million and exceeds 30% of Adjusted Consolidated Net Tangible Assets, as defined in the Indenture. Based on current product prices, we do not expect this covenant to significantly limit our ability to borrow under the revolving credit facility. However, this covenant could limit our ability to borrow funds in future periods if product prices continue to decline.

Capital expenditures

We incurred expenditures for exploration and development activities of $37.9 million during the first three months of 2009 and have increased our estimates for planned expenditures for fiscal 2009 from $56 million to $78.5 million. The following table summarizes, by area, our actual expenditures for exploration and development activities for the first three months of 2009 and our planned expenditures for the year ending December 31, 2009.

	Actual		Planned
	Expenditures		Expenditures		Year 2009
	Three Months Ended		Year Ending		Percentage
	March 31, 2009		December 31, 2009		of Total
	(In thousands)
Permian Basin	$	8,700	$	25,100		32	%
South Louisiana		9,800		23,300		30	%
East Texas Bossier		13,500		19,900		25	%
North Louisiana		2,400		4,000		5	%
Utah/California		2,700		3,700		5	%
Austin Chalk (Trend)		400		1,500		2	%
Other		400		1,000		1	%
	$	37,900	$	78,500		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 50% of the 2009 planned expenditures relate to exploratory prospects. Exploratory prospects involve a higher degree of risk than developmental prospects. To offset the higher risk, we generally strive to achieve a higher reserve potential and rate of return on investments in exploratory prospects. We do not attempt to forecast our success rate on exploratory drilling. Accordingly, these current estimates do not include costs we may incur to complete any future successful exploratory wells and construct the required production facilities for these wells. We are also actively searching for other opportunities to increase our oil and gas reserves, including the evaluation of new prospects for exploratory and developmental drilling activities and potential acquisitions of proved oil and gas properties. We cannot predict our drilling success on exploratory prospects, and our future results of operations and financial condition could be adversely affected by unsuccessful exploratory drilling results.

Our expenditures for exploration and development activities for the three months ended March 31, 2009 totaled $37.9 million, of which approximately 70% was on exploratory prospects. We financed these expenditures with cash flow from operating activities and advances under the revolving credit facility. Based on preliminary estimates, our internal cash flow forecasts indicate that the amount of funds available to us under our revolving credit facility, when combined with our anticipated operating cash flow, will be sufficient to finance our exploration and development activities and provide us with adequate liquidity through the remainder of 2009. 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 the remainder of 2009, we will consider options for obtaining alternative capital resources, including the sale of assets.

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 three months ended March 31, 2009 decreased $64.8 million, or 82.9%, as compared to the corresponding period in 2008 due primarily to a 57% drop in oil and gas sales caused by lower commodity prices. The decrease was offset in part by an approximate $3 million increase in operating cash flow attributable to Larclay JV. All of Larclay JV’s cash flow is dedicated to the repayment of Larclay JV’s $75 million secured term loan facility.

Credit facility

A group of banks have provided us with a revolving credit facility on which we have historically relied for both our short-term liquidity (working capital) and our long-term financing needs. The funds available to us at any time under this revolving credit facility are limited to the amount of the borrowing base established by the banks. As long as we have sufficient availability under this credit facility to meet our obligations as they come due, we believe that we will have sufficient liquidity and will be able to fund any short-term working capital deficit.

During the first three months in 2009, we increased the indebtedness outstanding under the revolving credit facility by $14.4 million. At March 31, 2009, we had a borrowing base of $250 million, leaving $140.7 million available under the revolving loan facility after accounting for outstanding letters of credit of $804,000.

Using the revolving credit facility for both our short-term liquidity and long-term financing needs can cause unusual fluctuations in our reported working capital, depending on the timing of cash receipts and expenditures. On a daily basis, we use most of our available cash to pay down our outstanding balance on the revolving credit facility, which is classified as a non-current liability since we currently have no required principal reductions. As we use cash to pay a non-current liability, our reported working capital decreases. Conversely, as we draw on the revolving credit facility for funds to pay current liabilities (such as payables for drilling and operating costs), our reported working capital increases. Also, volatility in oil and gas prices can cause significant fluctuations in reported working capital as we record changes in the fair value of derivatives from period to period. For these reasons, the working capital covenant related to the revolving credit facility requires us to (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, and (3) exclude current maturities of vendor finance obligations, if any, when computing the working capital ratio at any balance sheet date.

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 reported working capital decreased from a positive $2.6 million at December 31, 2008 to a $7.7 million deficit at March 31, 2009. After giving effect to the adjustments, our working capital computed for loan compliance purposes was a positive $147 million at March 31, 2009, as compared to a positive $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 March 31, 2009 and December 31, 2008.

	March 31,			December 31,
	2009			2008
	(In thousands)
Working capital (deficit) per GAAP	$	(7,680	)	$	2,607
Add funds available under the revolving credit facility		140,696			155,096
Exclude fair value of derivatives classified as current assets or current liabilities		2,037			-
Exclude current assets and current liabilities of Larclay JV		11,931			13,205
Working capital per loan covenant	$	146,984		$	170,908

Since we use this revolving credit facility for both short-term liquidity and long-term financing needs, it is important that we comply in all material respects with the loan agreement, including financial covenants that are computed quarterly. The working capital covenant requires us to maintain positive working capital using the computations described above. Another financial covenant under the credit facility requires us to maintain a ratio of indebtedness to cash flow of no more than 3 to 1. While we were in compliance with all financial and non-financial

covenants at March 31, 2009, 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 amend the loan agreement to allow us to become compliant or to 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 banks redetermine the borrowing base under the revolving credit facility at least twice a year, in May and November, and may request an unscheduled borrowing base redetermination at other times during the year. The banks are currently in the process of evaluating our oil and gas reserves in order to establish the borrowing base in connection with the May redetermination. We expect the redetermination to be completed by the end of May 2009. Although we believe that the banks will reaffirm the borrowing base at the present level of $250 million, it is possible that one or more of the banks may dissent and request that the borrowing base be reduced to an amount below $250 million. As an alternative to reducing the borrowing base, we may be able to remove the dissenting bank or banks from the bank group and replace the commitments made by such banks through redistribution to existing banks or by adding one or more banks to the bank group. If at any time, the borrowing base is less than the amount of outstanding indebtedness, we will be required to (1) pledge additional collateral, (2) prepay the excess in not more than five equal monthly installments, or (3) elect to convert the entire amount of outstanding indebtedness to a term obligation based on amortization formulas set forth in the loan agreement. At March 31, 2009, we had $108.5 million outstanding on the revolving credit facility.

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. After the payment of typical transaction expenses, net proceeds of approximately $217 million were used to repay amounts outstanding on our secured credit facilities and for general corporate purposes, including the funding of planned exploration and development activities.

At any time prior to August 1, 2009, we may redeem some or all of the Senior Notes at a redemption price equal to 100% of the principal amount of the Senior Notes to be redeemed, plus a make-whole premium, plus any accrued and unpaid interest. On and after August 1, 2009, 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 our ability and the ability of our restricted 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 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 restricts our ability to borrow additional funds under the revolving credit facility if our outstanding balance on the facility is greater than $150 million and exceeds 30% of Adjusted Consolidated Net Tangible Assets, as defined in the Indenture. Based on current economic conditions, we do not expect this covenant to significantly limit our ability to borrow under the revolving credit facility in 2009. 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 March 31, 2009.

Larclay JV

In connection with our investment in Larclay JV, Larclay JV obtained a $75 million secured term loan facility from a lender to finance the construction and equipping of 12 new drilling rigs. The Larclay JV term loan is secured by substantially all of the assets of Larclay JV. As additional credit support, we granted the lender a limited guaranty in the original amount of $19.5 million. The maximum obligation under the guaranty reduces by 10% on April 1 of each year, beginning April 1, 2008. At March 31, 2009, our maximum obligation under the guaranty was approximately $17.6 million. Although CWEI is not obligated under the Larclay JV term loan except to the extent of the guaranty, we are required to fully consolidate the accounts of Larclay JV under FASB Interpretation No. 46R “Consolidation of Variable Interest Entities – an Interpretation of ARB No. 51 (as amended)” (“FIN 46R”).

The Larclay JV term loan, bears interest at a floating rate based on a LIBOR average, plus 3.25%, and provides for monthly principal and interest payments sufficient to retire the principal balance by 35% in the first year, 25% in each of the next two years, and 15% in the fourth year. The Larclay JV term loan prohibits Larclay JV from making any cash distributions to Lariat or us until the balance on the term loan is fully repaid, and repayments by Larclay JV of any loans by Lariat or us are subordinated to the loans outstanding under the term loan and are subject to other restrictions.

Since inception of this joint venture, we have made advances structured as subordinated loans to Larclay JV totaling $12.1 million, $4.6 million to finance excess construction costs and $7.5 million to finance our 50% share of working capital assessments made by Larclay JV. Lariat has also advanced Larclay JV $7.5 million for its 50% share of working capital assessments. Loans to Larclay JV by Lariat and us are due on demand and bear interest, payable monthly, at the same rate as the term loan. However, these loans are subject to a subordination agreement with the Larclay JV lender that imposes restrictions on payments of principal and interest on the loans.

In connection with the formation of Larclay JV, we entered into a three-year drilling contract with Larclay JV assuring the availability of each drilling rig for use in the ordinary course of our exploration and development drilling program throughout the term of the drilling contract. The drilling contract, which is pledged as collateral to secure the Larclay JV term loan, expires on the earlier of December 31, 2009 or the termination and liquidation of Larclay JV. The provisions of the drilling contract provide that we contract for each drilling rig on a well-by-well basis at then current market rates. If a drilling rig is not needed by us at any time during the term of the contract, Larclay JV may contract with other operators for the use of such drilling rig, subject to certain restrictions. If a drilling rig is idle, the contract requires us to pay Larclay JV 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.

During most of 2008, the Larclay JV drilling rigs were being utilized primarily by Lariat and us in our respective drilling programs. However, the material deterioration in oil and gas prices, which began in the second half of 2008 and has continued into the first quarter of 2009, has resulted in a significant reduction in drilling activity throughout the oil and gas industry. As of March 31, 2009, all of the Larclay JV drilling rigs were idle. We do not expect utilization of the Larclay JV drilling rigs to improve for the remainder of 2009. If the drilling rigs remain idle, we may be required under the drilling contract with Larclay JV to pay up to $20.6 million to Larclay JV for the remainder of 2009. These payments will provide Larclay JV with adequate cash flow to meet its debt service obligations under the term loan through 2009. If the drilling rigs remain idle beyond 2009 and Larclay JV is not able to meet its debt service obligations under the term loan, we may be required under the guaranty to make debt service payments on the term loan on behalf of Larclay JV.

Effective April 15, 2009, we acquired the remaining 50% equity interest in Larclay JV pursuant to an agreement with Lariat dated March 13, 2009 (the “Assignment”). As a result of the transactions contemplated by the Assignment, we now own 100% of Larclay JV. In connection with the Assignment, we assumed all of the obligations and liabilities of Lariat relating to Larclay JV from and after the effective date, including Lariat’s obligations as operator of the Larclay JV drilling rigs. The assignment from Lariat includes all of Lariat’s right, title and interest in the subordinated loans previously advanced by Lariat to Larclay JV.

Immediately upon consummation of the Assignment, we contributed all of the subordinated notes issued by Larclay JV in the aggregate principal amount of $19.6 million and all accrued and unpaid interest on the notes to the capital of Larclay JV, and Larclay JV adopted a plan of disposition whereby Larclay JV would commit to sell eight of its 12 drilling rigs. The plan of disposition meets the criteria under SFAS No.144, “Accounting for the Impairment or Disposal of Long-Lived Assets (as amended)” (“SFAS 144”) for the designated assets to be classified as held for sale. SFAS 144 requires us to value the designated assets at the lower of their carrying value or fair value, less cost to sell, as of the date the plan of disposition was adopted. We estimate the fair value of the designated assets to be approximately $18.8 million. As a result, we will reclassify the estimated fair value of the designated assets to “Assets Held for Sale” in our balance sheet effective April 15, 2009, and will record a related charge for impairment of property and equipment of approximately $32.1 million in our statement of operations for the second quarter of 2009.

Alternative capital resources

Although our base of oil and gas reserves, as collateral for both of our credit facilities, 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 March 31, 2009. The settlement prices of commodity derivatives are based on NYMEX futures prices.

Swaps:

	Gas				Oil
	MMBtu (a)		Price		Bbls		Price
Production Period:
2nd Quarter 2009		1,570,000	$	5.47		470,000	$	49.68
3rd Quarter 2009		1,450,000	$	5.47		440,000	$	48.13
4th Quarter 2009		1,850,000	$	5.47		400,000	$	46.15
2010		7,540,000	$	6.80		327,000	$	53.30
2011		6,420,000	$	7.07		-	$	-
		18,830,000				1,637,000

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

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

We use a sensitivity analysis technique to evaluate the hypothetical effect that changes in the market value of oil and gas may have on the fair value of our commodity derivatives. A $1 per barrel change in the price of oil and a $.50 per MMBtu change in the price of gas would change the fair value of our commodity derivatives by approximately $10.6 million.

Interest Rates

We are exposed to interest rate risk on our long-term debt with a variable interest rate. At March 31, 2009, our fixed rate debt had a carrying value of $225 million and an approximate fair value of $139.5 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 $4 million. Based on our outstanding variable rate indebtedness at March 31, 2009 of $150.7 million, a change in interest rates of 100 basis points would affect annual interest payments by $1.5 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 March 31, 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. There have been no material changes to these risk factors since the filing of our Form 10-K.

Item 6 - - Exhibits

Exhibits

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

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

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

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

**10.1		Assignment and Assumption Agreement, dated March 13, 2009, between Clayton Williams Energy, Inc. and Lariat Services, Inc. filed as Exhibit 10.74 to our Annual Report on Form 10-K for the year ended December 31, 2008. ††

*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:	May 8, 2009	By:	/s/ L. Paul Latham
			L. Paul Latham
			Executive Vice President and Chief
			Operating Officer

Date:	May 8, 2009	By:	/s/ Mel G. Riggs
			Mel G. Riggs
			Senior Vice President and Chief Financial
			Officer

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Clayton Williams Energy (CWEI) Inactive 10-Q2009 Q1 Quarterly report

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