Clayton Williams Energy 10Q 2007 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, 2007

¨	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 is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.
Large accelerated filer ¨		Accelerated filer x		Non-accelerated filer ¨

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 11,352,051 shares of Common Stock, $.10 par value, of the registrant outstanding as of May 7, 2007.

CLAYTON WILLIAMS ENERGY, INC

TABLE OF CONTENTS

PART I. FINANCIAL INFORMATION
		Page
Item 1.	Financial Statements

	Consolidated Balance Sheets as of March 31, 2007 and December 31, 2006	3

	Consolidated Statements of Operations for the three months ended March 31, 2007 and 2006	5

	Consolidated Statements of Stockholders’ Equity for the three months ended March 31, 2007	6

	Consolidated Statements of Cash Flows for the three months ended March 31, 2007 and 2006	7

	Notes to Consolidated Financial Statements	8

Item 2.	Management’s Discussion and Analysis of Financial Conditions and Results of Operations	21

Item 3.	Quantitative and Qualitative Disclosure About Market Risks	32

Item 4.	Controls and Procedures	34


PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	35

Item 1A.	Risk Factors	35

Item 6.	Exhibits	35

	Signatures	37

CLAYTON WILLIAMS ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

ASSETS
	March 31,			December 31,
	2007			2006
	(Unaudited)
CURRENT ASSETS
Cash and cash equivalents	$	10,671		$	13,840
Accounts receivable:
Oil and gas sales		26,327			23,398
Joint interest and other, net		17,103			17,810
Affiliates		500			2,436
Inventory		27,053			40,392
Deferred income taxes		505			505
Fair value of derivatives		13,088			23,729
Prepaids and other		3,857			3,888
		99,104			125,998

PROPERTY AND EQUIPMENT
Oil and gas properties, successful efforts method		1,275,920			1,226,761
Natural gas gathering and processing systems		18,099			18,068
Contract drilling equipment		82,487			66,418
Other		16,032			15,848
		1,392,538			1,327,095
Less accumulated depreciation, depletion and amortization		(698,263	)		(682,286	)
Property and equipment, net		694,275			644,809


OTHER ASSETS
Debt issue costs, net		7,791			8,104
Fair value of derivatives		120			1,785
Other		17,780			14,737
		25,691			24,626
	$	819,070		$	795,433

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

CLAYTON WILLIAMS ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

LIABILITIES AND STOCKHOLDERS' EQUITY
	March 31,		December 31,
	2007		2006
	(Unaudited)
CURRENT LIABILITIES
Accounts payable:
Trade	$	73,218	$	75,815
Oil and gas sales		13,231		14,222
Affiliates		2,924		1,407
Current maturities of long-term debt		19,688		17,397
Fair value of derivatives		38,806		29,722
Accrued liabilities and other		6,850		10,503
		154,717		149,066

NON-CURRENT LIABILITIES
Long-term debt		445,312		413,876
Deferred income taxes		28,744		36,409
Fair value of derivatives		18,713		21,281
Other		32,842		29,821
		525,611		501,387

COMMITMENTS AND CONTINGENCIES

STOCKHOLDERS’ EQUITY

Preferred stock, par value $.10 per share, authorized - 3,000,000shares; none issued		-		-
Common stock, par value $.10 per share, authorized - 30,000,000 shares; issued
and outstanding - 11,352,051 shares in 2007 and 11,152,051 shares in 2006		1,135		1,115
Additional paid-in capital		120,017		113,965
Retained earnings		17,590		29,900
		138,742		144,980
	$	819,070	$	795,433

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,
	2007			2006
REVENUES
Oil and gas sales	$	61,180		$	60,181
Natural gas services		2,654			3,196
Drilling rig services		8,417			-
Gain on sales of property and equipment		128			17
Total revenues		72,379			63,394

COSTS AND EXPENSES
Production		17,278			14,965
Exploration:
Abandonments and impairments		11,105			12,843
Seismic and other		890			3,101
Natural gas services		2,413			2,829
Drilling rig services		4,933			-
Depreciation, depletion and amortization		15,231			14,710
Impairment of property and equipment		565			-
Accretion of abandonment obligations		618			379
General and administrative		3,903			4,067
Loss on sales of property and equipment		-			13
Total costs and expenses		56,936			52,907

Operating income		15,443			10,487

OTHER INCOME (EXPENSE)
Interest expense		(7,629	)		(4,339	)
Loss on derivatives		(16,849	)		(1,572	)
Other		(8,488	)		618
Total other income (expense)		(32,966	)		(5,293	)

Income (loss) before income taxes and minority interest		(17,523	)		5,194
Income tax (expense) benefit		6,080			(1,818	)
Minority interest, net of tax		(867	)		-

NET INCOME (LOSS)	$	(12,310	)	$	3,376

Net income (loss) per common share:
Basic	$	(1.09	)	$	0.31
Diluted	$	(1.09	)	$	0.30

Weighted average common shares outstanding:
Basic		11,290			10,841
Diluted		11,290			11,351

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

CLAYTON WILLIAMS ENERGY, INC.

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY

(Unaudited)

(In thousands)

	Common Stock
	No. of		Par		Paid-In		Retained
	Shares		Value		Capital		Earnings
BALANCE,
December 31, 2006		11,152	$	1,115	$	113,965	$	29,900

Net loss and total comprehensive loss		-		-		-		(12,310	)

Issuance of stock through compensation plans		200		20		6,052		-

BALANCE,
March 31, 2007		11,352	$	1,135	$	120,017	$	17,590

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,
	2007			2006
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	(12,310	)	$	3,376
Adjustments to reconcile net income (loss) to cash
provided by operating activities:
Depreciation, depletion and amortization		15,231			14,710
Impairment of property and equipment		565			-
Exploration costs		11,105			12,843
Gain on sales of property and equipment, net		(128	)		(4	)
Deferred income taxes		(6,080	)		1,818
Non-cash employee compensation		610			605
Unrealized (gain) loss on derivatives		18,822			(6,505	)
Settlements on derivatives with financing elements		5,593			7,921
Amortization of debt issue costs		309			371
Accretion of abandonment obligations		618			379
Minority interest, net of tax		867			-

Changes in operating working capital:
Accounts receivable		(286	)		4,046
Accounts payable		(3,703	)		867
Other		5,016			(2,891	)
Net cash provided by operating activities		36,229			37,536

CASH FLOWS FROM INVESTING ACTIVITIES
Additions to property and equipment		(55,749	)		(75,616	)
Additions to equipment of Larclay JV.		(19,316	)		-
Proceeds from sales of property and equipment		645			29
Change in equipment inventory		3,896			(937	)
Other		(2,970	)		(6,534	)
Net cash used in investing activities		(73,494	)		(83,058	)

CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt		25,000			56,000
Proceeds from long-term debt of Larclay JV		8,727			-
Repayments of long-term debt		-			(7	)
Proceeds from sale of common stock		5,962			175
Settlements on derivatives with financing elements		(5,593	)		(7,921	)
Net cash provided by financing activities		34,096			48,247

NET INCREASE (DECREASE) IN CASH AND
CASH EQUIVALENTS		(3,169	)		2,725

CASH AND CASH EQUIVALENTS
Beginning of period		13,840			5,935
End of period	$	10,671		$	8,660

SUPPLEMENTAL DISCLOSURES
Cash paid for interest, net of amounts capitalized	$	11,739		$	8,212

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

CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2007

(Unaudited)

1. Nature of Operations

Clayton Williams Energy, Inc. (a Delaware corporation) and its subsidiaries (collectively, the “Company” or “CWEI”) 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 20% 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 27% 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, 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 (see Note 11). The Company also accounts for its undivided interests in oil and gas limited partnerships using the proportionate consolidation method, whereby its share of assets, liabilities, revenues and expenses are consolidated with other operations. All significant intercompany transactions and balances associated with the consolidated operations have been eliminated.

In the opinion of management, the Company's unaudited consolidated financial statements as of March 31, 2007 and for the interim periods ended March 31, 2007 and 2006 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, 2007.

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, 2006.

3. Recent Accounting Pronouncements

In September 2006, the Securities and Exchange Commission issued Staff Accounting Bulletin No. 108 (“SAB 108”), which became effective on January 1, 2007. SAB 108 provides guidance on the consideration of the effects of prior period misstatements in quantifying current year misstatements for the purpose of a materiality assessment. SAB 108 requires an entity to evaluate the impact of correcting all misstatements, including both the carryover and reversing effects of prior year misstatements, on current year financial statements. If a misstatement is material to the current year financial statements, the prior year financial statements should also be corrected, even

though such revision was, and continues to be, immaterial to the prior year financial statements. Correcting prior year financial statements for immaterial errors would not require previously filed reports to be amended. Such correction should be made in the current period filings. The adoption of SAB 108 had no effect on the Company’s consolidated financial statements.

In September 2006, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 157 Fair Value Measurements (“SFAS 157”), which defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles and expands disclosures about fair value measurements. This Statement applies under other accounting pronouncements that require or permit fair value measurements, the FASB having previously concluded in those accounting pronouncements that fair value is the relevant measurement attribute. Accordingly, this Statement does not require any new fair value measurements. SFAS 157 is effective for fiscal years beginning after December 15, 2007. The Company plans to adopt SFAS 157 beginning in the first quarter of 2008. The Company is currently evaluating the impact, if any, the adoption of SFAS 157 will have on its consolidated financial position, results of operations or cash flows.

In February 2007, the FASB issued SFAS No. 159 The Fair Value Option for Financial Assets and Financial Liabilities - Including an Amendment of FASB Statement No. 115 (“SFAS 159”). SFAS 159 permits an entity to choose to measure many financial instruments and certain other items at fair value. The fair value option established by SFAS 159 permits all entities to choose to measure eligible items at fair value at specified election dates. Unrealized gains and losses on items for which the fair value option has been elected are to be recognized in earnings at each subsequent reporting date. SFAS 159 is effective for financial statements issued for fiscal years beginning after November 15, 2007. The effect of adopting SFAS 159 has not been determined, but it is not expected to have a significant effect on the Company’s consolidated financial position or results of operations.

In June 2006, the FASB issued Interpretation No. 48 Accounting for Uncertainty in Income Taxes (“FIN 48”) to clarify the manner in which enterprises account for uncertainties in their provisions for income taxes. Generally, the standard presented by FIN 48 is a “more likely than not” standard and is intended to enhance the relevancy and comparability of financial reporting by companies. FIN 48 is effective for fiscal years beginning after December 31, 2006. The Company adopted FIN 48 effective January 1, 2007 (see Note 10).

4. Long-Term Debt

Long-term debt consists of the following:

	March 31,			December 31,
	2007			2006
	(In thousands)
7¾% Senior Notes due 2013	$	225,000		$	225,000
Secured bank credit facility, due May 2009		165,000			140,000
Secured term loan of Larclay JV		75,000			66,273
		465,000			431,273
Less current maturities^(a)		(19,688	)		(17,397	)

	$	445,312		$	413,876

(a) Consists of current portion of 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. After the payment of typical transaction expenses, net proceeds of approximately $217 million were used to repay all amounts outstanding

under the secured bank credit facilities and for general corporate purposes, including the funding of planned exploration and development activities.

At any time prior to August 1, 2008, the Company may redeem up to 35% of the aggregate principal amount of the Senior Notes with the proceeds of certain equity offerings at a redemption price of 107.75% of the principal amount, plus accrued and unpaid interest. In addition, 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 100.00% beginning on August 1, 2011, for any period thereafter, in each case plus accrued and unpaid interest.

The Indenture governing the Senior Notes restricts the ability of the Company and its restricted subsidiaries to: (i) borrow money; (ii) issue redeemable and preferred stock; (iii) pay distributions or dividends; (iv) make investments; (v) create liens without securing the Senior Notes; (vi) enter into agreements that restrict dividends from subsidiaries; (vii) sell certain assets or merge with or into other companies; (viii) enter into transactions with affiliates; (ix) guarantee indebtedness; and (x) enter into new lines of business. The Company was in compliance with these covenants at March 31, 2007.

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 (i) pledge additional collateral, (ii) prepay the excess in not more than five equal monthly installments, or (iii) 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. At March 31, 2007, the borrowing base established by the banks was $200 million, with no monthly commitment reductions. After allowing for outstanding letters of credit totaling $5.8 million, the Company had $29.2 million available under the credit facility at March 31, 2007.

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, 2007 was 7.6%.

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, 2007.

Secured Term Loan of Larclay JV

In connection with the Company’s investment in Larclay JV (see Note 11), 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. Initially, the Company pledged additional collateral in the form of a $19 million letter of credit. In February 2007, the letter of credit was cancelled and replaced by a $19.5 million guaranty from the Company. In March 2007, the Company issued a $5 million letter of credit which expires in June 2007 as additional collateral under the term loan to cover any temporary shortfall in collateral value caused by delays in completing construction of the final drilling rigs being financed by the lender. Concurrently, the guaranty was amended to limit the Company’s combined credit exposure under the guaranty and the letter of the credit

to $19.5 million. Although the Company is not a maker on the Larclay JV term loan, it is providing additional credit support for the Larclay JV term loan and is required to fully consolidate the accounts of Larclay JV under FASB Interpretation No. 46R Consolidation of Variable Interest Entities - or Interpretation of ARB No. 51 (as amended) (“FIN 46R”).

The Larclay JV term loan, as amended, bears interest at a floating rate based on a LIBOR average, plus 3.25%, and provides for monthly interest payments through June 2007 and monthly principal and interest payments thereafter 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. Two voluntary prepayments of $10 million each may be made in 2008 and 2009 without a prepayment penalty. 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, 2007, the effective interest rate on the Larclay JV term loan was 8.7%.

5. Other Non-Current Liabilities

Other non-current liabilities consist of the following:

	March 31,		December 31,
	2007		2006
	(In thousands)
Abandonment obligations	$	28,428	$	27,846
Minority interest, net of tax		1,941		1,074
Other taxes payable		1,585		-
Other		888		901
	$	32,842	$	29,821

Changes in abandonment obligations for the three months ended March 31, 2007 and 2006 are as follows:

	Three Months Ended
	March 31,
	2007			2006
	(In thousands)
Beginning of period	$	27,846		$	19,447
Additional abandonment obligations from new wells		145			328
Sales or abandonments of properties		(181	)		(82	)
Revisions of previous estimates		-			(17	)
Accretion expense		618			379
End of period	$	28,428		$	20,055

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 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, 2007 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 plans.

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

48,000 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.

The following table sets forth certain information regarding the Company’s stock option plans as of and for the three months ended March 31, 2007:

						Weighted
				Weighted		Average
				Average		Remaining		Aggregate
				Exercise		Contractual		Intrinsic
	Shares			Price		Term		Value (a)
Outstanding at January 1, 2007		1,009,485		$	22.27
Granted		4,000		$	36.31
Exercised (b)		(200,000	)	$	29.85
Outstanding at March 31, 2007		813,485		$	20.47		5.8	$	6,423,092

Vested at March 31, 2007		813,485		$	20.47		5.8	$	6,423,092
Exercisable at March 31, 2007		813,485		$	20.47		5.8	$	6,423,092

(a) Based on closing price at March 31, 2007 of $28.37 per share.

(b) Cash received for options exercised totaled $6 million.

The following table summarizes information with respect to options outstanding at March 31, 2007, 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		33,485	$	5.50		2.1
$10.00 - $19.74		462,000	$	17.49		5.1
$22.90 - $41.74		318,000	$	26.38		7.3
		813,485	$	20.47		5.8

The following table presents certain information regarding stock-based compensation amounts for the three months ended March 31, 2007 and 2006.

	Three Months Ended
	March 31,
	2007			2006
	(In thousands, except per share)
Weighted average grant date fair value of options granted per share	$	27.56		$	31.91
Intrinsic value of options exercised	$	228		$	1,374
Stock-based employee compensation expense	$	110		$	128
Tax benefit	$	(39	)	$	(45	)
Net stock-based employee compensation expense	$	71		$	83

After-Payout Incentive Plan

The Compensation Committee of the Board of Directors has adopted an incentive plan for officers, key employees and consultants, excluding Mr. Williams, 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 after-payout 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 Arrangements”) 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 and receives all revenues until payout of its costs, plus interest. 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 Arrangements.

Between 3% 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 APO Arrangements (excluding properties acquired in a merger with Southwest Royalties, Inc. in May 2004). The Company records its allocable share of the assets, liabilities, revenues, expenses and oil and gas reserves of these APO Arrangements in its consolidated financial statements. The Company recognized $500,000 of non-cash compensation expense during each of the three-month periods ended March 31, 2007 and 2006 for the estimated fair value of the APO Arrangements granted during those periods.

SWR Reward Plan

In January 2007, the Company granted awards under the Southwest Royalties Reward Plan (the “SWR Reward Plan”), a one-time incentive plan designed to reward eligible employees and other service providers for continued quality service to the Company, and to encourage retention of those employees and service providers by providing them the opportunity to receive bonus payments that are based on certain profits derived from a portion of the Company’s working interest in the RS Windham C3 well in Upton County, Texas. Eligible participants in the SWR Reward Plan include those officers, key employees and consultants, excluding Mr. Williams, who made significant contributions to the acquisition and development of Southwest Royalties, Inc.

The SWR Reward Plan provides for quarterly cash bonuses to the participants, as a group, equal to the after-payout cash flow from a 22.5% working interest in the RS Windham C3 well. 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. The quarterly bonus amounts are allocated among the participants based on each participant’s bonus percentage.

To continue as a participant in the SWR Reward Plan, participants must remain in the employment or service of the Company through the full vesting date. Participants who remain in the employment or service of the Company through the full vesting date will continue as participants for the duration of the SWR Reward plan, subject to certain restrictions. The full vesting date may occur sooner than October 25, 2011 in the event of a change of control or sale transaction, as defined in the SWR Reward Plan.

The Company recognizes compensation expense related to the SWR Reward Plan over the vesting period. For the quarter ended March 31, 2007, the Company recorded compensation expense of $97,000 for the SWR Reward Plan.

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, 2007. The settlement prices of commodity derivatives are based on NYMEX futures prices.

Collars:

	Gas						Oil
	MMBtu ^(a)		Floor		Ceiling		Bbls		Floor		Ceiling
Production Period:
2^nd Quarter 2007		459,000	$	4.00	$	5.18		141,000	$	23.00	$	25.20
3^rd Quarter 2007		459,000	$	4.00	$	5.18		141,000	$	23.00	$	25.20
4^th Quarter 2007		459,000	$	4.00	$	5.18		141,000	$	23.00	$	25.20
2008		1,279,000	$	4.00	$	5.15		392,000	$	23.00	$	25.07

		2,656,000						815,000

Swaps:

	Gas				Oil
	MMBtu ^(a)		Price		Bbls		Price
Production Period:
2^nd Quarter 2007		2,600,000	$	8.16		-	$	-
3^rd Quarter 2007		2,400,000	$	8.34		75,000	$	72.75
4^th Quarter 2007		2,400,000	$	8.34		225,000	$	72.75
2008		6,300,000	$	8.19		720,000	$	65.60

		13,700,000				1,020,000

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

In January 2007, the Company terminated certain fixed-price oil swaps covering 375,000 barrels at a price of $55.35 per barrel from April 2007 through August 2007, resulting in an aggregate realized gain of approximately $6.5 million, which will be collected from the counterparty monthly during 2007.

In July 2006, the Company also terminated certain fixed-price oil swaps covering 225,000 barrels at a price of $80.45 per barrel from April 2007 through December 2007, resulting in an aggregate loss of approximately $1.8 million, which will be paid to the counterparty monthly during 2007.

Interest Rate Derivatives

The Company is a party to interest rate swaps that were acquired in connection with the acquisition of Southwest Royalties, Inc. in May 2004. Under these derivatives, the Company pays a fixed rate for the notional principal balances and receives a floating market rate based on LIBOR. The interest rate swaps are settled quarterly. The following summarizes information concerning the Company’s net positions in open interest rate swaps applicable to periods subsequent to March 31, 2007.

Interest Rate Swaps:

	Principal		Fixed Libor
	Balance		Rates
Period:
April 1, 2007 to November 1, 2007	$	50,000,000		5.19	%
November 1, 2007 to November 1, 2008	$	45,000,000		5.73	%

Accounting For Derivatives

The Company accounts for its derivatives in accordance with Statement of Financial Accounting Standards No. 133 Accounting for Derivative Instruments and Hedging Activities (“SFAS 133”), as amended. The Company did not designate any of its currently open commodity or interest rate 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. For the three months ended March 31, 2007, the Company reported a $16.8 million loss on derivatives, consisting of an $18.8 million loss related to changes in mark-to-market valuations and a $2 million realized gain on settled contracts. For the three months ended March 31, 2006, loss on derivatives was $1.6 million, consisting of a $6.5 million gain related to changes in mark-to-market valuations and an $8.1 million realized loss on settled contracts.

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 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, 2007 and December 31, 2006 was approximately $209.8 million and $207.6 million, respectively.

The fair values of derivatives as of March 31, 2007 and December 31, 2006 are set forth below. The associated carrying values at these dates are equal to their estimated fair values.

	March 31,			December 31,
	2007			2006
	(In thousands)
Assets (liabilities):
Commodity derivatives	$	(43,944	)	$	(25,289	)
Interest rate derivatives		(367	)		(200	)
Net liabilities	$	(44,311	)	$	(25,489	)

9. Inventory

The Company maintains an inventory of tubular goods and other well equipment for use in its exploration and development drilling activities. Any gains or losses on disposition of inventory, and any losses on write-down of inventory to its estimated market value, are reported as other income/expense in the accompanying consolidated statements of operations. For the three months ended March 31, 2007, the Company reported losses on inventory of $9.2 million. No losses were recorded in the 2006 period. The 2007 period included a non-cash charge of $8.9 million to write-down inventory to its estimated market value at March 31, 2007. The write-down resulted primarily from the sale of certain surplus equipment at an auction in March 2007. The Company received $4.5 million of net proceeds from the auction in April 2007 when the auction sale was consummated.

10. Income Taxes

The Company’s effective federal and state income tax rate for the three months ended March 31, 2007 of 34.7% differed from the statutory federal rate of 35% due to tax benefits derived from statutory depletion deductions, offset in part by increases in the tax provision related primarily to the effects of the recently-enacted Texas Margin Tax and certain non-deductible expenses.

The Company and its subsidiaries file federal income tax returns with the United States Internal Revenue Service (“IRS”) and state income tax returns in various state tax jurisdictions. As a general rule, the Company’s tax returns for fiscal years after 2002 currently remain subject to examination by appropriate taxing authorities. None of the Company’s income tax returns are under examination at this time.

The Company adopted FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes (“FIN 48”), effective January 1, 2007. Upon adoption of FIN 48, the Company recorded a $1.6 million liability for taxes payable related to unrecognized tax benefits arising from uncertain tax positions taken by the Company in previous periods. No additional unrecognized tax benefits originated during the quarter ended March 31, 2007. The tax liability recorded

under FIN 48 is included in other non-current liabilities in the accompanying consolidated balance sheet at March 31, 2007.

All of the unrecognized tax benefits at March 31, 2007 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 change the amount of deferred tax assets related to net operating loss carryforwards.

The Company recognizes interest and penalties accrued related to unrecognized tax benefits in interest expense. Due to the Company’s net operating loss positions, no interest or penalties have been accrued on the Company’s unrecognized tax benefits.

The Company currently plans to make all required filings with the appropriate tax jurisdictions in 2007 to reduce or eliminate the uncertainties that resulted in the establishment of this tax liability under FIN 48.

11. Investments

West Coast Energy Properties, L.P.

In August 2006, an affiliated partnership, West Coast Energy Properties, L.P. (“WCEP”), acquired certain producing oil and gas assets in California and Texas for aggregate cash consideration of approximately $58 million. Approximately 75% of the purchase price relates to properties in three fields in southern California, and the remaining 25% relates primarily to properties located in Mitchell County, Texas.

WCEP is a Texas limited partnership formed to facilitate this acquisition, the general partner of which is a limited liability company owned by the Company and the limited partner of which is an affiliate of GE Energy Financial Services. Under the partnership agreement, the general partner contributed approximately $6.2 million to the partnership for an initial partnership interest of 5%, which interest can increase to 37.63%, and ultimately to 49%, upon the achievement of certain target rates of return.

The Company financed its equity contribution to the general partner through borrowings on its revolving credit facility.

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. The Company and Lariat each own a 50% interest in Larclay JV. The rigs are being constructed on behalf of Larclay JV by Lariat, as operations manager. Ten of the rigs were fully constructed at March 31, 2007. The remaining two rigs are expected to be fully constructed by June 2007. The total construction cost of all rigs, excluding capitalized interest, is expected to be approximately $79 million. A lender has provided a $75 million secured term loan to Larclay JV to finance most of the cost of constructing and initially equipping the rigs. The Company is not a maker on the Larclay JV term loan, but it is providing additional credit support for the Larclay JV term loan (see Note 4).

Also in April 2006, the Company entered into a three-year drilling contract with Larclay JV assuring the availability of each rig for use in the ordinary course of the Company’s exploration and development drilling program throughout the term of the drilling contract. The provisions of the drilling contract provide that the Company contract for each rig on a well-by-well basis at then current market rates. If a 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 rig, subject to certain restrictions. If a rig is idle, the Company will 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 rig. The Company’s maximum potential obligation to pay idle rig rates over the term of this drilling contract, excluding any crew labor expenses, totals approximately $103 million at March 31, 2007.

Although the Company and Lariat own equal interests in Larclay JV, the Company meets 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, 2007, Lariat’s equity ownership in the net assets of Larclay JV was $1.9 million, which is recorded as minority interest and included in other non-current liabilities in the accompanying consolidated financial statements. The Company’s intercompany accounts with Larclay JV have been eliminated in consolidation.

12. Commitments and Contingencies

Purchase Commitments

The Company is presently obligated under firm orders for two drilling rigs and related equipment in an aggregate amount of $24.5 million, for which cash deposits totaling $11.5 million have been paid to the equipment suppliers as of March 31, 2007. The total cost of the rigs, when completed and fully equipped, is estimated to be approximately $27 million. The rigs are scheduled for delivery in mid-2007.

In addition to the Larclay JV drilling contract discussed in Note 11, the Company has also entered into three drilling contracts with third party drilling contractors and is obligated to make payments under these contracts totaling $9 million in 2007.

Legal Proceedings

The Company is a co-plaintiff in a lawsuit involving a dispute over rights to produce hydrocarbons under certain leases in Alabama. The parties to the lawsuit have tentatively agreed to settle the lawsuit. Once the agreement is executed and binding, the Company will record a gain on settlement of approximately $2.9 million. Final settlement is expected to occur in the second quarter of 2007.

The Company is a defendant in several lawsuits that have arisen in the ordinary course of business. While the outcome of these lawsuits cannot be predicted with certainty, management does not expect any of these to have a material adverse effect on the Company’s consolidated financial condition or results of operations.

13. Oil and Gas Properties

The following sets forth the capitalized costs for oil and gas properties as of March 31, 2007 and December 31, 2006.

	March 31, 2007			December 31, 2006
	(In thousands)
Proved properties	$	1,137,063		$	1,097,341
Unproved properties		138,857			129,420
Total capitalized costs		1,275,920			1,226,761
Accumulated depreciation, depletion and amortization		(668,387	)		(654,316	)
Net capitalized costs	$	607,533		$	572,445

In April 2005, the Financial Accounting Standards Board issued Staff Position No. 19-1 (“FSP 19-1”). FSP 19-1 amends the present guidance in Statement of Financial Accounting Standards No. 19, paragraphs 31 and 34, regarding when exploratory drilling costs pending determination of proved reserves can be carried as an asset of an oil and gas company that uses the successful efforts method of accounting. The Company was required to adopt FSP 19-1, including its disclosures, effective July 1, 2005. The adoption of FSP 19-1 did not have a significant impact on the Company’s results of operations. At March 31, 2007 and December 31, 2006, the Company had capitalized $34.1 million and $27 million, respectively, of exploratory drilling costs applicable to wells that were pending determination of proved reserves. Of the $27 million costs at December 31, 2006, $16.2 million was subsequently deemed productive and the remaining $10.8 million was still pending determination of proved reserves.

14. Segment Information

In accordance with Statement of Financial Accounting Standards 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. Beginning in April 2006, the Company formed the Larclay JV, a contract drilling joint venture that the Company consolidates in its financial statements (see Note 11). Effective January 1, 2007, the contract drilling segment meets the quantitative thresholds under SFAS 131 to be considered a reportable operating segment and, accordingly, is shown as “Contract Drilling” in the table below.

The following table presents selected financial information regarding the Company’s operating segments for the three-month periods ended March 31, 2007 and 2006.

For the Three Months Ended March 31, 2007	Oil and Gas			Contract Drilling			Intercompany Eliminations			ConsolidatedTotal
	(In thousands)
Revenues	$	63,962		$	10,936		$	(2,519	)	$	72,379
Depreciation, depletion and amortization (a)		14,413			1,607			(224	)		15,796
Other operating expenses (b)		36,175			5,827			(862	)		41,140
Interest expense		6,795			834			-			7,629
Other (income) expense		25,337			-			-			25,337
Income before income taxes and
minority interest		(18,758	)		2,668			(1,433	)		(17,523	)

Income tax (expense) benefit		7,014			(934	)		-			6,080
Minority interest, net of tax		-			(867	)		-			(867	)

Net income (loss)	$	(11,744	)	$	867		$	(1,433	)	$	(12,310	)

Total assets	$	730,651		$	92,350		$	(3,931	)	$	819,070
Additions to property and equipment	$	72,776		$	5,765		$	(1,433	)	$	77,108

For the Three Months Ended						Intercompany		Consolidated
March 31, 2006	Oil and Gas			Other		Eliminations		Total
	(In thousands)
Revenues	$	63,394		$	-	$	-	$	63,394
Depreciation, depletion and amortization (a)		14,710			-		-		14,710
Other operating expenses (b)		38,197			-		-		38,197
Interest expense		4,339			-		-		4,339
Other (income) expense		954			-		-		954
Income before income taxes		5,194			-		-		5,194

Income tax expense		(1,818	)		-		-		(1,818	)

Net income	$	3,376		$	-	$	-	$	3,376

Total assets	$	632,662		$	-	$	-	$	632,662
Additions to property and equipment	$	68,302		$	-	$	-	$	68,302

(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 property and equipment.

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 WCEP (see Note 11), 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, 2007

(Dollars in thousands)					Non-
			Guarantor		Guarantor		Adjustments/
	Issuer		Subsidiaries		Entities		Eliminations			Consolidated
Current assets	$	134,991	$	97,845	$	12,603	$	(146,335	)	$	99,104
Property and equipment, net		329,066		279,449		85,760		-			694,275
Investments in subsidiaries		71,445		-		-		(71,445	)		-
Other assets		24,756		326		609		-			25,691
Total assets	$	560,258	$	377,620	$	98,972	$	(217,780	)	$	819,070

Current liabilities	$	90,857	$	178,423	$	31,772	$	(146,335	)	$	154,717
Non-current liabilities:
Long-term debt		390,000		-		55,313		-			445,313
Fair value of derivatives		3,423		15,290		-		-			18,713
Other		5,142		56,337		106		-			61,585
		398,565		71,627		55,419		-			525,611

Stockholders’ equity		70,836		127,570		11,781		(71,445	)		138,742
Total liabilities and
stockholders’ equity	$	560,258	$	377,620	$	98,972	$	(217,780	)	$	819,070

Condensed Consolidating Balance Sheet

December 31, 2006

(Dollars in thousands)					Non-
			Guarantor		Guarantor		Adjustments/
	Issuer		Subsidiaries		Entities		Eliminations			Consolidated
Current assets	$	160,772	$	96,386	$	11,781	$	(142,941	)	$	125,998
Property and equipment, net		293,775		279,913		71,121		-			644,809
Investments in subsidiaries		72,171		-		-		(72,171	)		-
Other assets		23,638		358		630		-			24,626
Total assets	$	550,356	$	376,657	$	83,532	$	(215,112	)	$	795,433

Current liabilities	$	89,704	$	176,876	$	25,427	$	(142,941	)	$	149,066
Non-current liabilities:
Long-term debt		365,000		-		48,876		-			413,876
Fair value of derivatives		313		20,968		-		-			21,281
Other		10,257		55,870		103		-			66,230
		375,570		76,838		48,979		-			501,387

Stockholders’ equity		85,082		122,943		9,126		(72,171	)		144,980
Total liabilities and
stockholders’ equity	$	550,356	$	376,657	$	83,532	$	(215,112	)	$	795,433

Condensed Consolidating Statement of Operations

Three Months Ended March 31, 2007

(Dollars in thousands)							Non-
				Guarantor			Guarantor			Adjustments/
	Issuer			Subsidiaries			Entities			Eliminations			Consolidated
Total revenue	$	40,005		$	24,169		$	11,038		$	(2,833	)	$	72,379
Costs and expenses		35,570			16,139			7,575			(2,348	)		56,936
Operating income (loss)		4,435			8,030			3,463			(485	)		15,443
Other income (expense)		(28,758	)		(3,402	)		(806	)		-			(32,966	)
Income tax benefit		6,080			-			-			-			6,080
Minority interest, net of tax		(867	)		-			-			-			(867	)

Net income (loss)	$	(19,110	)	$	4,628		$	2,657		$	(485	)	$	(12,310	)

Condensed Consolidating Statement of Operations

Three Months Ended March 31, 2006

(Dollars in thousands)							Non-
				Guarantor			Guarantor		Adjustments/
	Issuer			Subsidiaries			Entities		Eliminations			Consolidated
Total revenue	$	37,014		$	27,033		$	-	$	(653	)	$	63,394
Costs and expenses		36,782			16,778			-		(653	)		52,907
Operating income (loss)		232			10,255			-		-			10,487
Other income (expense)		(4,291	)		(1,002	)		-		-			(5,293	)
Income tax expense		(1,818	)		-			-		-			(1,818	)

Net income (loss)	$	(5,877	)	$	9,253		$	-	$	-		$	3,376

Condensed Consolidating Statement of Cash Flows

Three Months Ended March 31, 2007

(Dollars in thousands)							Non-
				Guarantor			Guarantor			Adjustments/
	Issuer			Subsidiaries			Entities			Eliminations			Consolidated
Operating activities	$	8,042		$	13,657		$	14,306		$	224		$	36,229
Investing activities		19,114			(5,460	)		(87,424	)		276			(73,494	)
Financing activities		(32,185	)		(8,346	)		75,127			(500	)		34,096
Net increase (decrease) in
cash and cash equivalents		(5,029	)		(149	)		2,009			-			(3,169	)

Cash at the beginning of
the period		12,542			1,298			-			-			13,840

Cash at end of the period	$	7,513		$	1,149		$	2,009		$	-		$	10,671

Condensed Consolidating Statement of Cash Flows

Three Months Ended March 31, 2006

(Dollars in thousands)							Non-
				Guarantor			Guarantor		Adjustments/
	Issuer			Subsidiaries			Entities		Eliminations		Consolidated
Operating activities	$	10,784		$	26,752		$	-	$	-	$	37,536
Investing activities		(68,694	)		(14,364	)		-		-		(83,058	)
Financing activities		59,622			(11,375	)		-		-		48,247
Net increase (decrease) in
cash and cash equivalents		1,712			1,013			-		-		2,725

Cash at the beginning of
the period		4,302			1,633			-		-		5,935

Cash at end of the period	$	6,014		$	2,646		$	-	$	-	$	8,660

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, 2006.

Overview

We are an oil and natural gas exploration, development, acquisition, and production company. Our basic business model is to find and develop oil and gas reserves through exploration and development activities, and sell 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.

We believe that the economic climate in the domestic oil and gas industry continues to be suitable for our business model. Although oil prices have retreated from their peaks in mid-2006, and gas prices have been volatile, we believe that supply and demand fundamentals in the energy marketplace continue to provide us with the economic incentives necessary for us to assume the risks we face in our search for oil and gas reserves. However, we are experiencing a shrinking profit margin resulting from rising drilling and production costs. While profit margins still remain favorable, operating metrics per Mcfe, such as finding costs, production costs, and depreciation, depletion and amortization (“DD&A”) expense, are generally on an upward trend.

Finding quality domestic oil and gas reserves through exploration is a significant challenge and involves a high degree of risk. Our planned exploration activities in 2007 offer us the opportunity to add significant oil and gas reserves through the drilling of several potentially high-impact wells, particularly in our East Texas Bossier area. However, these wells are very expensive to drill and involve a high degree of risk.

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 2007 and the outlook for the remainder of 2007.

We spent $60.6 million on exploration and development activities during the first three months of 2007, of which approximately 75% was on exploratory prospects. We currently plan to spend approximately $186.2 million for fiscal 2007, of which approximately 78% is estimated to be spent on exploratory prospects. These expenditures for the first quarter of 2007 exceeded our cash flow from operating activities by approximately $24.3 million. Our expenditures for the remainder of 2007 are also expected to exceed our cash flow from operating activities, although not by as large a margin. 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.

·	During the first quarter of 2007, we increased borrowings under our revolving credit facility by $25 million from $140 million at December 31, 2006 to $165 million at March 31, 2007 to partially finance our exploration and development activities.

Despite our high level of capital spending in fiscal 2006 and the first quarter of 2007, our oil and gas production for the three months ended March 31, 2007 was only 11% higher on an Mcfe basis than in the comparable period in 2006, despite production curtailments in the 2006 period caused by hurricane damage. A significant portion of our fiscal 2006 and first quarter 2007 expenditures have not resulted in current production because they relate to (a) unproved exploratory prospects, (b) drilling or completion activities that are in progress, or (c) non-productive leasing and drilling activities.

At March 31, 2007, our capitalized unproved oil and gas properties totaled $138.9 million, of which approximately $105 million was attributable to unproved acreage. Unproved properties are subject to a valuation impairment to the extent the carrying cost of a prospect exceeds its estimated fair value. Therefore, our results of operations in future periods may be adversely affected by unproved property impairments.

Exploration costs related to abandonments and impairments were $11.1 million in the first quarter of 2007, of which approximately $10 million related to unsuccessful well costs and $1.1 million related to impairment of unproved acreage. Most of the abandonment and impairment costs in the first quarter of 2007 related to prospects in South Louisiana and Utah.

We recorded a $16.8 million net loss on derivatives in the first quarter of 2007. Net cash received from counterparties accounted for a $2 million gain on settled contracts and changes in mark-to-market valuations accounted for an $18.8 million loss. Since we do not presently designate our derivatives as cash flow hedges under applicable accounting standards, we recognize the full effect of changing prices on mark-to-market valuations as a current charge or credit to our results of operations.

We recorded a $9.2 million loss on inventory during the quarter ended March 31, 2007 due primarily to a write-down of certain surplus equipment to its estimated realizable value. Most of this write-down related to equipment that we sold through an auction process in March 2007. Net proceeds from the auction of $4.5 million were received in April 2007.

Recent Exploration and Developmental Activities

Overview

As shown in “Liquidity and Capital Resources - Capital Expenditures,” we incurred expenditures for exploration and development activities of $60.6 million during the first three months of 2007. Approximately 75% of our first quarter 2007 expenditures were related to exploratory drilling activities. We also increased our estimates for capital expenditures in fiscal 2007 from $170.1 million to $186.2 million.

In addition to our on-going drilling program in the Miocene Trends of South Louisiana and our Cotton Valley/Hosston exploration program in North Louisiana, we have begun an aggressive exploratory drilling program targeting the deep Bossier formation in North Louisiana and East Texas.

South Louisiana

Prior to 2007, we had drilled 67 gross (53.6 net) exploratory wells in South Louisiana, of which 34 gross (25.9 net) were completed as producers. The following table sets forth certain information about our exploratory and developmental well activities in South Louisiana subsequent to December 31, 2006.

		Working	Current
Spud Date	Well Name (Prospect)	Interest	Status
April 2006	Cobena #1 (Boa II)	63%	Completing
January 2007	SL 195 QQ #7 (Floyd)	100%	Waiting on pipeline
February 2007	SL 195 QQ #10 (Floyd)	75%	Waiting on pipeline
February 2007	Orleans Levee District #2 (American Bay)	45%	Waiting on pipeline
March 2007	Bowie Lumber Co. #1 (Bayou Boeuf)	100%	Dry
April 2007	Pivach Agency #1 (Elsa)	94%	Dry

We continue to attempt to complete the Cobena #1, a 15,250-foot exploratory well in Acadia Parish in the Boa II prospect on which drilling operations began in April 2006. We temporarily abandoned the Discorbis 3 sand due to mechanical difficulties, and are currently testing the Discorbis 2 sand to which the Company had attributed approximately 2.3 Bcfe of net gas reserves at December 31, 2006. Based on these recent test results, we currently plan to abandon the Discorbis 2 sand and will eliminate all proved reserve estimates previously assigned to this sand. Together with our partners in the well, we are currently evaluating well completion data in the Discorbis 3 sand to

determine if the potential for proved reserves from this sand justifies a second completion attempt. If we decide to abandon the well, we will record exploration expense for cumulative well costs, plus any impaired acreage cost, at the time of determination. To date, we have incurred approximately $9.8 million in drilling and completion costs on this well, net to our interest, and have approximately $1 million of acreage attributable to this prospect that is subject to impairment.

In our Floyd prospect, we have drilled ten wells to date, of which eight are currently producing. The remaining two wells have been completed and are waiting on pipeline construction. Currently, the eight wells are producing at combined rates of approximately 6,700 Mcf of gas per day and 450 barrels of oil per day, net to our interest. However, due to production facility constraints, this current level of combined production is significantly less than the combined rates at which these wells are capable of producing. In order to fully resolve these capacity issues, we plan to build our own plant and production facilities in 2007 to process and market gas production from all the wells in the prospect.

We drilled and abandoned the Bowie Lumber Co. #1, a 13,150-foot exploratory well in the Bayou Boeuf prospect in Lafourche Parish, after it was determined to be non-productive. We recorded a $3.8 million pre-tax charge related to the abandonment of the well in the first quarter of 2007.

We drilled and completed a second well in the American Bay prospect, the Orleans Levee District #2. This development well, which was completed in the Tex “W” sand at 13,986 feet, has been tested and is currently waiting on a pipeline connection. We own a 45% working interest in this well.

We also drilled and abandoned a 3,500-foot exploratory well, the Pivach Agency #1 (Elsa), when it was determined to be incapable of producing hydrocarbons in economic quantities. We recorded a pre-tax charge in the first quarter of 2007 of approximately $200,000, and expect to record an additional charge of approximately $1 million in the second quarter for the abandonment of this well.

North Louisiana

In 2005, we began an exploration program in North Louisiana targeting the Cotton Valley/Hosston and Bossier formations. In this area, the Cotton Valley/Hosston 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. We believe that these tight sandstone formations have become more economically viable due to higher product prices, coupled with enhanced drilling and completion techniques.

Prior to 2007, we had drilled 4 gross (3.7 net) exploratory wells in North Louisiana, of which 2 gross (1.7 net) were completed as producers. The following table sets forth certain information about our exploratory well activities in North Louisiana subsequent to December 31, 2006. This table does not include non-operated wells.

		Working	Current
Spud Date	Well Name (Prospect)	Interest	Status
October 2006	P. Benoit #1 (Sarepta)	91%	Waiting on completion
January 2007	J.L. Hood #1 (Terryville)	86%	Producing
February 2007	J. Huey #1 (Terryville)	86%	Producing
March 2007	David Barton #1 (Winnsboro)	100%	Drilling
March 2007	George Staton #1 (Sarepta)	70%	Waiting on completion
April 2007	Bice #1 (Terryville)	86%	Drilling

On our Terryville prospect in Lincoln Parish we drilled and completed two wells in the Cotton Valley interval in the first quarter of 2007. The J.L. Hood #1 and the J. Huey #1 were both completed as gas wells and are currently producing, on a combined basis, approximately 2,500 Mcf of gas per day and 150 barrels of oil per day, net to our interest. We also began drilling operations on the C.M. Bice #1, an 11,500-foot exploratory well, in April 2007.

Our first exploratory well on the Sarepta prospect in Webster Parish, the P. Benoit #1, targeted a hydrocarbon formation in the Gray sand, but that zone was non-productive. We are waiting on availability of a completion rig to attempt completion in the Cotton Valley interval. We also drilled the George Staton #1, a 12,200-foot exploratory well in the Sarepta prospect, and are waiting on completion operations to commence.

We are currently drilling the David Barton #1, a 17,000-foot exploratory well on our Winnsboro prospect in Richland Parish, targeting the Bossier sands.

East Texas Bossier

We have acquired a significant acreage position in East Texas targeting the Bossier formation which is encountered at depths ranging from 14,000 to 22,000 feet in this area. To date, we have acquired approximately 54,000 net acres and hold up to 50,000 additional acres in the area of our Austin Chalk (Trend) production primarily in Burleson, Robertson, Brazos and Milam Counties, Texas.

In April, we commenced drilling operations on two wells, the Big Bill Simpson #1, a 19,000-foot exploratory well in Leon County (70% working interest), and the Margarita #1, a 20,000-foot exploratory well in Robertson County (100% working interest), both targeting the Bossier formation. These wells are very expensive to drill and involve a high degree of risk. Depending upon drilling results of these two wells, we may drill additional Bossier wells in 2007.

Utah

We are participating in a joint exploration program with industry partners in the Overthrust play in central Utah in which we own a 33% interest. The Vonda Christensen 35A31, a 13,500-foot non-operated exploratory well in Sanpete County, was drilled and abandoned. We recorded a pre-tax charge of $3.6 million in the first quarter of 2007 related to the abandonment of this well. We expect to participate in the drilling of a second exploratory well to further evaluate this acreage in 2008.

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,
	2007			2006
Oil and Gas Production Data:
Gas (MMcf)		4,327			3,463
Oil (MBbls)		543			555
Natural gas liquids (MBbls)		46			48
Total (MMcfe)		7,861			7,081

Average Realized Prices ^(a):
Gas ($/Mcf)	$	6.91		$	7.22
Oil ($/Bbl)	$	55.21		$	60.01
Natural gas liquids ($/Bbl):	$	33.30		$	38.90

Gain (Losses) on Settled Derivative Contracts ^(a):
($ in thousands, except per unit)
Gas: Net realized gain (loss)	$	4,509		$	(2,178	)
Per unit produced ($/Mcf)	$	1.04		$	(0.63	)
Oil: Net realized loss	$	(2,559	)	$	(5,895	)
Per unit produced ($/Bbl)	$	(4.71	)	$	(10.62	)

Average Daily Production:
Natural Gas (Mcf):
Permian Basin		15,389			13,824
Louisiana		22,530			9,466
Austin Chalk (Trend)		2,011			3,261
Cotton Valley Reef Complex		7,697			11,439
Other		451			488
Total		48,078			38,478

Oil (Bbls):
Permian Basin		3,096			3,216
Louisiana		1,201			1,079
Austin Chalk (Trend)		1,672			1,828
Other		64			44
Total		6,033			6,167
Natural Gas Liquids (Bbls):
Permian Basin		199			262
Austin Chalk (Trend)		265			258
Other		47			13
Total		511			533

(Continued)

	Three Months Ended
	March 31,
	2007		2006
Exploration Costs (in thousands):
Abandonment and impairment costs:
South Louisiana	$	7,179	$	8,008
North Louisiana		306		-
Permian Basin		43		2,202
Utah, Montana and Colorado		3,577		1,933
Other		-		700
Total		11,105		12,843

Seismic and other		890		3,101
Total exploration costs	$	11,995	$	15,944

Depreciation, Depletion and Amortization (in thousands):
Oil and gas depletion	$	13,548	$	13,981
Contract drilling depreciation		1,383		-
Other depreciation		300		729
Total DD&A	$	15,231	$	14,710

Oil and Gas Costs ($/Mcfe Produced):
Production costs	$	2.20	$	2.11
Oil and gas depletion	$	1.72	$	1.97

Net Wells Drilled ^(b):
Exploratory Wells		5.0		7.6
Developmental Wells		3.5		1.7

(a) No derivatives were designated as cash flow hedges in 2007 or 2006. All gains or losses on settled derivatives were included in 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, 2007 to the comparative period in 2006. Unless otherwise indicated, references to 2007 and 2006 within this section refer to the respective quarterly period.

Oil and gas operating results

Oil and gas sales in 2007 increased $1 million, or 2%, from 2006, of which production variances accounted for a $5.2 million increase and price variances accounted for a $4.2 million decrease. Production in 2007 (on an Mcfe basis) was 11% higher than 2006. Oil production decreased 2% in 2007 from 2006 due primarily to normal production declines, offset in part by higher production from new wells in Louisiana. Gas production increased 25% in 2007 from 2006 due primarily to production attributable to recent drilling activity in South Louisiana. In 2007, our realized oil price was 8% lower than 2006, while our realized gas price was 4% lower. Historically, the markets for oil and gas have been volatile, and they are likely to continue to be volatile.

Production costs, consisting of lease operating expenses, production taxes and other miscellaneous marketing costs, increased 15% in 2007 as compared to 2006 due primarily to higher oilfield service costs. After giving effect to an 11% increase in oil and gas production on an Mcfe basis, production costs per Mcfe increased 4% from $2.11 per Mcfe in 2006 to $2.20 per Mcfe in 2007. It is likely that these factors will continue to contribute to higher production costs in future periods.

Oil and gas depletion expense decreased $433,000, of which rate variances accounted for a $1.9 million decrease and production variances accounted for a $1.5 million increase. On an Mcfe basis, depletion expense decreased 13% from $1.97 per Mcfe in 2006 to $1.72 per Mcfe in 2007 due in part to a lower depletable cost basis in 2007 compared to the 2006 period in two areas where we recorded an impairment of proved property under SFAS No. 144 in the last half of 2006. Depletion expense per Mcfe 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 activities result in higher finding costs in 2007.

We recorded a provision for impairment of proved properties under SFAS 144 of $565,000 during the first quarter of 2007 due to production performance. This provision was attributable to two areas in the Permian Basin.

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 2007, we charged to expense $11.1 million of exploration costs, as compared to $12.8 million in 2006. Most of the 2007 costs were incurred in Louisiana and Utah.

We plan to spend approximately $186.2 million on exploration and development activities in fiscal 2007, of which approximately 78% 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 fiscal 2007 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. We own a 50% interest in Larclay JV. The rigs are being constructed on behalf of Larclay JV by Lariat, as operations manager. Ten of the rigs were fully constructed at March 31, 2007. Two of the rigs are working for us, seven are working for an affiliate of Lariat and one is working for other operators. The remaining two rigs are expected to be fully constructed by June 2007. Although the Company and Lariat own equal interests in Larclay JV, the Company meets 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. During the three months ended March 31, 2007, we included contract drilling revenues of $8.4 million, net other operating expenses of $5 million, depreciation expense of $1.4 million and interest expense of $834,000 in our statement of operations (see Note 14 to the consolidated financial statements). Since the Larclay JV drilling rigs are partially utilized by us, the reported amounts are net of any intercompany profits eliminated in consolidation.

General and Administrative

General and administrative (“G&A”) expenses decreased 4% from $4.1 million in 2006 to $3.9 million in 2007. Excluding non-cash employee compensation, G&A expenses decreased from $3.4 million in 2006 to $3.3 million in 2007. In 2007, we recorded a $500,000 non-cash compensation charge related to our after payout incentive plan and $110,000 for stock-based employee compensation. In 2006, we recorded a $128,000 non-cash charge for stock-based employee compensation and a $500,000 non-cash charge related to our after payout incentive plan.

Interest expense

Interest expense increased 76% from $4.3 million in 2006 to $7.6 million in 2007 due to a combination of factors. In 2006 and 2007, we used our revolving loan facility to partially finance our exploration and development

activities. The average daily principal balance outstanding under our revolving credit facility for 2007 was $159.1 million compared to $43.5 million for 2006. Capitalized interest for 2007 was $973,000 compared to $1.2 million in 2006. We also included $834,000 of interest expense associated with our Larclay JV during 2007.

Gain/loss on derivatives

We did not designate any derivative contracts in 2007 or 2006 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, 2007, we reported a $16.8 million net loss on derivatives, consisting of an $18.8 million non-cash loss to mark our derivative positions to their fair value at March 31, 2007 and a $2 million realized gain on settled contracts. For the three months ended March 31, 2006, we recorded a net loss on derivatives of $1.6 million, consisting of a $6.5 million non-cash mark-to-market gain related to changes in mark-to-market valuations and an $8.1 million realized loss on settled contracts.

Other expense

We recorded losses on inventory during 2007 of $9.2 million, including a non-cash charge of $8.9 million to write-down inventory to its estimated market value at March 31, 2007. The write-down resulted primarily from the sale of certain surplus equipment at an auction in March 2007. No losses or write-downs were recorded during the 2006 period.

Income tax expense (benefit)

Our effective income tax rate in 2007 of 34.7% differed from the statutory federal rate of 35% due primarily to increases in the tax provision related primarily to the effects of the recently-enacted Texas Margin Tax and certain non-deductible expenses, offset in part by tax benefits derived from 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. The effects of product prices on cash flow can be mitigated through the use of commodity derivatives. If we are unable to replace our oil and gas reserves through our exploration program, we may also suffer a reduction in our operating cash flow and access to funds under the revolving credit facility. Under extreme circumstances, product price reductions or exploration drilling failures could allow the banks to seek to foreclose on our oil and gas properties, thereby threatening our financial viability.

In 2005, we issued $225 million of aggregate principal amount of Senior Notes and used the net proceeds to repay all amounts outstanding on the revolving credit facility at that time. However, we relied heavily on advances under the revolving credit facility to finance a significant portion of our exploration and development activities in 2006 and the first quarter of 2007. At March 31, 2007, we had $165 million outstanding on the revolving credit facility.

Our expenditures for exploration and development activities for the first quarter of 2007 exceeded our cash flow from operating activities for the same period by approximately $24.3 million, and we expect our spending during the remainder of 2007 to outpace our operating cash flow, although not by as large a margin. 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. In this section, we will describe our current plans for

capital spending, identify the capital resources available to finance our capital spending, and discuss the principal factors that can affect our liquidity and capital resources.

Capital expenditures

We incurred expenditures for exploration and development activities of $60.6 million during the first three months of 2007 and have increased our estimates for planned expenditures for fiscal 2007 from $170.1 million to $186.2 million. The following table summarizes, by area, our actual expenditures for exploration and development activities for the first quarter of 2007 and our planned expenditures for the year ending December 31, 2007.

	Actual		Planned
	Expenditures		Expenditures		Year 2007
	Three Months Ended		Year Ending		Percentage
	March 31, 2007		December 31, 2007		of Total
	(In thousands)
South Louisiana	$	32,200	$	58,600		32	%
North Louisiana		14,300		58,300		31	%
East Texas Bossier		2,500		34,100		18	%
Permian Basin		8,300		24,500		13	%
Austin Chalk (Trend)		300		6,000		3	%
Utah		2,900		3,000		2	%
Other		100		1,700		1	%
	$	60,600	$	186,200		100	%

Our actual expenditures during fiscal 2007 may be substantially higher or lower than these estimates since our plans for exploration and development activities may change during 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 fiscal 2007.

Approximately 78% of the 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. Also, we are 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, 2007 exceeded our cash flow from operating activities for the same period by approximately $24.3 million, and we expect our spending during the remainder of 2007 to outpace our operating cash flow, although not by as large a margin. To the extent possible, we intend to finance this shortfall by borrowings on the revolving credit facility. 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 capital expenditures and will provide us with adequate liquidity at least through 2007. Although we believe the assumptions and estimates made in our forecasts are reasonable, uncertainties exist which could cause the borrowing base to be less than expected, cash flow to be less than expected, or capital expenditures to be more than expected. In the event we lack adequate liquidity to finance our expenditures in 2007, we are currently considering several options for alternative capital resources, including the sale of assets and the request for an increase in the amount of funds available under our revolving credit facility based on recent additions to proved reserves.

We have placed orders for two 2,000 horsepower rigs for possible use in our Bossier drilling program in North Louisiana and East Texas. At March 31, 2007, we had invested $11.5 million in these rigs and were committed under firm purchase contracts for an additional $13 million. We estimate that the combined construction cost of both rigs will

be approximately $27 million. We are currently evaluating our need for these drilling rigs, and depending on that evaluation, we may elect to sell the rigs, or we may seek financing for the remaining cost of these rigs.

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, 2007 decreased $1.3 million, or 4%, as compared to the corresponding period in 2006 due to the combined effects of several factors. Oil and gas sales, net of production costs, general and administrative costs and interest expense, were $4.4 million lower in the 2007 period as compared to the same period in 2006. Our primary source of cash from operating activities is our oil and gas sales, net of production costs. Our cash flow provided by operating activities is subject to material variation from changes in oil and gas production levels and product prices. Settlements on derivative contracts, excluding those contracts that contain a financing element as in the case of the contracts assumed in our acquisition of Southwest Royalties, Inc. in May 2004, were $2.3 million lower in the 2007 period compared to the 2006 period. Interest expense increased $3.3 million in the 2007 period due primarily to higher levels of indebtedness resulting from our aggressive exploration and development activities.

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 will have sufficient liquidity and will be able to fund any short-term working capital deficit.

At the beginning of 2007, we had an outstanding balance under the revolving credit facility of $140 million, and the borrowing base was $200 million, providing us with available funds of $40.2 million after accounting for outstanding letters of credit. During 2007, we generated cash flow from operating activities of $36.2 million and received cash proceeds of $6.6 million from sales of assets and issuances of common stock. We also used cash to pay for additions to property and equipment of $55.7 million (excluding Larclay JV) and paid $5.6 million to settle derivatives with financing elements. To finance the excess of expenditures over cash flow, we borrowed $25 million on the revolving credit facility. In addition, Larclay JV paid $19.3 million for property and equipment and borrowed $8.7 million, resulting in a $10.6 million reduction in liquidity.

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 (i) include the amount of funds available under this facility as a current asset, (ii) exclude current assets and liabilities related to the fair value of derivatives, and (iii) 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 deficit

increased from $23.1 million at December 31, 2006 to $55.6 million at March 31, 2007 due primarily to a combination of factors, including decreases in inventory and an increase in the net liability for the fair value for derivatives. After giving effect to the adjustments, our working capital computed for loan compliance purposes was a positive $18.4 million at March 31, 2007, as compared to a positive $36.9 million at December 31, 2006. The following table reconciles our GAAP working capital to the working capital computed for loan compliance purposes at March 31, 2007 and December 31, 2006.

	March 31,			December 31,
	2007			2006
	(In thousands)
Working capital (deficit) per GAAP	$	(55,613	)	$	(23,068	)
Add funds available under the revolving credit facility		29,196			40,196
Exclude fair value of derivatives classified as current assets or current liabilities		25,718			5,993
Exclude current assets and current liabilities of Larclay JV		19,095			13,759
Working capital per loan covenant	$	18,396		$	36,880

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, 2007, 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 allow 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. The November 2006 borrowing base review resulted in maintaining the borrowing base at $200 million. We presently anticipate that the banks will authorize an increase in the borrowing base in connection with the May 2007 borrowing base review, but the amount, if any, of such increase is not known at this time. If at any time, the borrowing base is less than the amount of outstanding indebtedness, we will be required to (i) pledge additional collateral, (ii) prepay the excess in not more than five equal monthly installments, or (iii) elect to convert the entire amount of outstanding indebtedness to a term obligation based on amortization formulas set forth in the loan agreement. We have relied heavily on advances under the revolving credit facility to finance a significant portion of our exploration and development activities in fiscal 2006 and the first quarter of 2007. At March 31, 2007, we had $165 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 will 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, 2008, we may redeem up to 35% of the aggregate principal amount of the Senior Notes with the proceeds of certain equity offerings at a redemption price of 107.75% of the principal amount, plus accrued and unpaid interest. In addition, 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 100.00% beginning on August 1, 2011, for any period thereafter, in each case plus accrued and unpaid interest.

The Indenture governing the Senior Notes restricts our ability and the ability of our restricted subsidiaries to: (i) borrow money; (ii) issue redeemable and preferred stock; (iii) pay distributions or dividends; (iv) make investments; (v) create liens without securing the Notes; (vi) enter into agreements that restrict dividends from subsidiaries; (vii) sell certain assets or merge with or into other companies; (viii) enter into transactions with affiliates; (ix) guarantee indebtedness; and (x) enter into new lines of business. These covenants are subject to a number of important exceptions and qualifications. We were in compliance with these covenants at March 31, 2007.

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 Disclosure 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 affect 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, 2006 reserve estimates, we project that a $1.00 drop in the price per Bbl of oil and a $.50 drop in the price per Mcf of gas would reduce our gross revenues for the year ending December 31, 2007 by $10.7 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. In floor transactions, we receive a fixed price (put strike price) if the market price falls below the put strike price for the respective commodity. If the market price is greater than the put strike price, no payments are due from either party. Costless collars are a combination of puts and calls, and contain a fixed floor price (put strike price) and ceiling price (call strike price). If the market price for the respective commodity exceeds the call strike price or falls below the put strike price, then we receive the fixed price and pay the market price. If the market price is between the call and the put strike prices, no payments are due from either party. Commodity derivatives are settled monthly as the contract periods mature. 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, 2007. The settlement prices of commodity derivatives are based on NYMEX futures prices.

Collars:

	Gas						Oil
	MMBtu ^(a)		Floor		Ceiling		Bbls		Floor		Ceiling
Production Period:
2^nd Quarter 2007		459,000	$	4.00	$	5.18		141,000	$	23.00	$	25.20
3^rd Quarter 2007		459,000	$	4.00	$	5.18		141,000	$	23.00	$	25.20
4^th Quarter 2007		459,000	$	4.00	$	5.18		141,000	$	23.00	$	25.20
2008		1,279,000	$	4.00	$	5.15		392,000	$	23.00	$	25.07

		2,656,000						815,000

Swaps:

	Gas				Oil
	MMBtu ^(a)		Price		Bbls		Price
Production Period:
2^nd Quarter 2007		2,600,000	$	8.16		-	$	-
3^rd Quarter 2007		2,400,000	$	8.34		75,000	$	72.75
4^th Quarter 2007		2,400,000	$	8.34		225,000	$	72.75
2008		6,300,000	$	8.19		720,000	$	65.60

		13,700,000				1,020,000

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

In January 2007, we terminated certain fixed-price oil swaps covering 375,000 barrels at a price of $55.35 per barrel from April 2007 through August 2007, resulting in an aggregate realized gain of approximately $6.5 million, which will be collected from the counterparty monthly during 2007.

In July 2006, we also terminated certain fixed-price oil swaps covering 225,000 barrels at a price of $80.45 per barrel from April 2007 through December 2007, resulting in an aggregate loss of approximately $1.8 million, which will be paid to the counterparty monthly during 2007.

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 $9 million.

Interest Rates

We are exposed to interest rate risk on our long-term debt with a variable interest rate. At March 31, 2007, our variable rate debt had a carrying value of $240 million, which approximated its fair value. At March 31, 2007, our fixed rate debt had a carrying value of $225 million and an approximate fair value of $209.8 million, based on current market quotes. We estimate that the hypothetical change in the fair value of our fixed-rate, long-term debt resulting from a 100-basis point change in interest rates would be approximately $9.9 million.

We are a party to interest rate swaps that were acquired in connection with the acquisition of Southwest Royalties, Inc. in May 2004. Under these derivatives, we pay a fixed rate for the notional principal balances and receives a floating market rate based on LIBOR. The following summarizes information concerning our net positions in open interest rate swaps applicable to periods subsequent to March 31, 2007.

	Principal		Fixed Libor
	Balance		Rates
Period:
April 1, 2007 to November 1, 2007	$	50,000,000		5.19	%
November 1, 2007 to November 1, 2008	$	45,000,000		5.73	%

The interest rate swaps in the preceding table expose us to market risks for decreases in interest rates during the periods shown.

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 Securities and Exchange Commission (“SEC”) and other communications with our stockholders. Disclosure controls and procedures include all processes necessary to ensure that material information is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and is accumulated and communicated to our management, including our chief executive and chief financial officers, to allow timely decisions regarding required disclosures.

With respect to our disclosure controls and procedures:

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

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

It is the conclusion of our chief executive and chief financial officers that these disclosure controls and procedures are effective in ensuring that information that is required to be disclosed by the Company in reports filed or submitted with the SEC is recorded, processed, summarized and reported within the time periods specified in the rules and forms established by the SEC.

Changes in Internal Control Over Financial Reporting

No changes in internal control over financial reporting were made during the quarter ended March 31, 2007 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. FINANCIAL INFORMATION

Item 1 - Legal Proceedings

We are a co-plaintiff in a lawsuit involving a dispute over rights to produce hydrocarbons under certain leases in Alabama. We and the other parties to the lawsuit have tentatively agreed to settle the lawsuit. Once the agreement is executed and binding, we will record a gain on settlement of approximately $2.9 million. Final settlement is expected to occur in the second quarter of 2007.

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, 2006, as filed with the U.S. Securities and Exchange Commission on March 16, 2007 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 8, 2007††

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

**4.2		Registration Rights Agreement dated July 20, 2005, among Clayton Williams Energy, Inc., the Subsidiary Guarantors and J.P. Morgan Securities Inc., filed as Exhibit 4.2 to our Current Report on Form 8-K filed with the Commission on July 22, 2005††

**10.1†		Southwest Royalties Reward Plan dated January 15, 2007, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with Commission on January 18, 2007††

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

Exhibits (Continued)

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

*32		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

† 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, 2007	By:	/s/ L. Paul Latham
			L. Paul Latham
			Executive Vice President and Chief
			Operating Officer

Date:	May 8, 2007	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-Q2007 Q1 Quarterly report

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