Clayton Williams Energy (CWEI) 10-Q 2006 Q1 Quarterly report

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM 10-Q

ý Quarterly Report Pursuant to Section 13 or 15(d)

of the Securities Exchange Act of 1934

For the quarterly period ended March 31, 2006

or

o Transition Report Pursuant to Section 13 or 15(d)

of the Securities Exchange Act of 1934

For the transition period from           to          

Commission File No. 001-10924

CLAYTON WILLIAMS ENERGY, INC.
(Exact name of Registrant as specified in its charter)
Delaware	75-2396863
(State or other jurisdiction of	(I.R.S. Employer
incorporation or organization)	Identification Number)
6 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.   Yes   ý   No   o

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 o Accelerated filer ý Non-accelerated filer o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
o  Yes      ý  No

There were 10,849,461 shares of Common Stock, $.10 par value, of the registrant outstanding as of May 5, 2006.

CLAYTON WILLIAMS ENERGY, INC.

TABLE OF CONTENTS

PART I. FINANCIAL INFORMATION
Item 1.	Financial Statements
	Consolidated Balance Sheets as of March 31, 2006 and December 31, 2005
	Consolidated Statements of Operations for the three months ended March 31, 2006 and 2005
	Consolidated Statement of Stockholders’ Equity for the three months ended March 31, 2006
	Consolidated Statements of Cash Flows for the three months ended March 31, 2006 and 2005
	Notes to Consolidated Financial Statements
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 3.	Quantitative and Qualitative Disclosure About Market Risks
Item 4.	Controls and Procedures
PART II. OTHER INFORMATION
Item 1A.	Risk Factors
Item 6.	Exhibits
	Signatures

2

CLAYTON WILLIAMS ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

ASSETS

	March 31, 2006			December 31, 2005
	(Unaudited)
CURRENT ASSETS
Cash and cash equivalents	$	8,660		$	5,935
Accounts receivable:
Oil and gas sales, net	22,619			28,317
Joint interest and other, net	8,120			6,972
Affiliates	758			254
Inventory	45,088			43,753
Deferred income taxes	427			439
Fair value of derivatives	339			191
Prepaids and other	1,481			2,581
	87,492			88,442
PROPERTY AND EQUIPMENT
Oil and gas properties, successful efforts method	1,090,976			1,037,862
Natural gas gathering and processing systems	18,043			18,034
Other	14,626			12,396
	1,123,645			1,068,292
Less accumulated depreciation, depletion and amortization	(608,854		)	(594,225		)
Property and equipment, net	514,791			474,067
OTHER ASSETS
Debt issue costs	8,187			8,557
Advances to drilling rig joint venture	16,776			10,329
Fair value of derivatives	101			127
Other	5,315			5,813
	30,379			24,826
	$	632,662		$	587,335

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

3

LIABILITIES AND STOCKHOLDERS’ EQUITY

	March 31, 2006		December 31, 2005
	(Unaudited)
CURRENT LIABILITIES
Accounts payable:
Trade	$	60,096	$	59,861
Oil and gas sales	12,877		18,236
Affiliates	1,829		2,857
Current maturities of long-term debt	12		19
Fair value of derivatives	31,857		33,670
Accrued liabilities and other	5,426		9,611
	112,097		124,254
NON-CURRENT LIABILITIES
Long-term debt	291,700		235,700
Deferred income taxes	38,847		37,042
Fair value of derivatives	45,135		49,705
Other	20,935		20,343
	396,617		342,790
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS’ EQUITY
Preferred stock, par value $.10 per share, authorized – 3,000,000 shares; issued – none	—		—
Common stock, par value $.10 per share, authorized – 30,000,000 shares; issued and outstanding – 10,848,450 shares in 2006 and 10,815,575 shares in 2005	1,085		1,082
Additional paid-in capital	107,386		107,108
Retained earnings	15,477		12,101
	123,948		120,291
	$	632,662	$	587,335

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

4

CLAYTON WILLIAMS ENERGY, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(In thousands, except per share)

	Three Months Ended March 31,
	2006			2005
REVENUES
Oil and gas sales	$	60,181		$	61,496
Natural gas services	3,196			2,581
Gain on sales of property and equipment	17			1,612
Total revenues	63,394			65,689
COSTS AND EXPENSES
Production	14,965			12,571
Exploration:
Abandonments and impairments	12,843			11,270
Seismic and other	3,101			788
Natural gas services	2,829			2,417
Depreciation, depletion and amortization	14,710			12,292
Accretion of abandonment obligations	379			279
General and administrative	4,067			2,518
Loss on sales of property and equipment	13			32
Total costs and expenses	52,907			42,167
Operating income	10,487			23,522
OTHER INCOME (EXPENSE)
Interest expense	(4,339		)	(2,366		)
Loss on derivatives	(1,572		)	(35,089		)
Other	618			446
Total other income (expense)	(5,293		)	(37,009		)
Income (loss) before income taxes	5,194			(13,487		)
Income tax expense (benefit)	1,818			(4,495		)
NET INCOME (LOSS)	$	3,376		$	(8,992	)
Net income (loss) per common share:
Basic	$	0.31		$	(0.83	)
Diluted	$	0.30		$	(0.83	)
Weighted average common shares outstanding:
Basic	10,841			10,792
Diluted	11,351			10,792

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

5

CLAYTON WILLIAMS ENERGY, INC.

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY

(Unaudited)

(In thousands)

	Common Stock			Additional Paid-In Capital
	No. of Shares	Par Value				Retained Earnings
BALANCE,
December 31, 2005	10,815	$	1,082	$	107,108	$	12,101
Net income and total comprehensive income	—	—		—		3,376
Issuance of stock through compensation plans	33	3		278		—
BALANCE,
March 31, 2006	10,848	$	1,085	$	107,386	$	15,477

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

6

CLAYTON WILLIAMS ENERGY, INC.

CONSOLIDATED STATEMENT OF CASH FLOWS

(Unaudited)

(In thousands)

	Three Months Ended March 31,
	2006			2005
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	3,376		$	(8,992	)
Adjustments to reconcile net income (loss) to cash provided by operating activities:
Depreciation, depletion and amortization	14,710			12,292
Exploration costs	12,843			11,270
(Gain) loss on sales of property and equipment, net	(4		)	(1,580		)
Deferred income taxes	1,818			(4,651		)
Non-cash employee stock compensation	605			333
Unrealized (gain) loss on derivatives	(6,505		)	31,452
Settlements on derivatives with financing elements	7,921			4,205
Amortization of debt issue costs	371			—
Accretion of abandonment obligations	379			279
Changes in operating working capital:
Accounts receivable	4,046			(4,467		)
Accounts payable	867			(10,166		)
Other	(2,891		)	(29		)
Net cash provided by operating activities	37,536			29,946
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to property and equipment	(75,616		)	(38,814		)
Proceeds from sales of property and equipment	29			1,694
Other	(7,471		)	(278		)
Net cash used in investing activities	(83,058		)	(37,398		)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt	56,000			6,200
Repayments of long-term debt	(7		)	—
Proceeds from sale of common stock	175			—
Settlements on derivatives with financing elements	(7,921		)	(4,205		)
Net cash provided by financing activities	48,247			1,995
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	2,725			(5,457		)
CASH AND CASH EQUIVALENTS
Beginning of period	5,935			16,359
End of period	$	8,660		$	10,902
SUPPLEMENTAL DISCLOSURES
Cash paid for interest, net of amounts capitalized	$	8,212		$	2,602

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

7

CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2006

(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 45% of the Company’s outstanding common stock is beneficially owned by its Chairman of the Board and Chief Executive Officer, Clayton W. Williams (“Mr. Williams”). Oil and gas exploration and production is the only business segment in which the Company operates.

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.

In the opinion of management, the Company’s unaudited consolidated financial statements as of March 31, 2006 and for the interim periods ended March 31, 2006 and 2005 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, 2006.

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 2005 Form 10-K.

3.Recent Accounting Pronouncements

Emerging Issues Task Force Issue 04-5 (“EITF 04-5”), which became effective January 1, 2006, requires companies to fully consolidate any limited partnerships that the company controls as general partner. EITF 04-5 presumes that a sole general partner in a limited partnership controls the limited partnership; however, the presumption of control can be overcome if the limited partners have (i) the substantive ability to remove the sole general partner or otherwise dissolve the limited partnership or (ii)

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substantive participating rights. For this purpose, the EITF has concluded that a general partner lacks control if the limited partners can remove the general partner with a simple majority vote. The Company has entered into contracts with 17 oil and gas limited partnerships of which the Company is the sole general partner. Generally, these contracts require the Company to abstain from voting any of its limited partnership units in matters related to the removal of the Company as general partner. As a result, the limited partners in all of the oil and gas partnerships in which the Company serves as general partner can remove the Company as general partner with a simple majority vote. Accordingly, the Company will continue consolidating its proportionate share of all of these limited partnerships. The adoption of EITF 04-5 had no affect on the Company’s consolidated financial statements.

4.Long-Term Debt

Long-term debt consists of the following:

	March 31, 2006			December 31, 2005
	(In thousands)
7¾% Senior Notes due 2013	$	225,000		$	225,000
Secured bank credit facility, due May 2007	66,700			10,700
Other	12			19
	291,712			235,719
Less current maturities	(12		)	(19		)
	$	291,700		$	235,700

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, 2006.

9

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, 2006, the borrowing base established by the banks was $150 million, with no monthly commitment reductions.  After allowing for outstanding letters of credit totaling $804,000, the Company had $82.5 million available under the credit facility at March 31, 2006.

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. The prime rate margin is currently 2.5%, and the LIBOR margin is 4%. 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, 2006 was 7.7%.

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, 2006.

5.Other Non-Current Liabilities

Other non-current liabilities consist of the following:

	March 31, 2006		December 31, 2005
	(In thousands)
Abandonment obligations	$	20,055	$	19,447
Other	880		896
	$	20,935	$	20,343

10

Changes in abandonment obligations for the three months ended March 31, 2006 and 2005 are as follows:

	Three Months Ended March 31,
	2006			2005
	(In thousands)
Beginning of period	$	19,447		$	16,147
Additional abandonment obligations from new wells	328			140
Sales or abandonments of properties	(82		)	(42		)
Revisions of previous estimates	(17		)	—
Accretion expense	379			279
End of period	$	20,055		$	16,524

6.Compensation Plans

Stock-Based Compensation

In January 2006, the Company adopted Statement of Financial Accounting Standards No. 123 (revised 2004) “Share-Based Payments” (“SFAS 123R”). SFAS 123R requires that the cost from all share-based payment transactions, including stock options, be recognized in the financial statements at fair value. Under SFAS 123R, compensation expense related to the grant of stock options will be determined based on the grant date fair value of future awards. Prior to adoption of SFAS 123R, the Company accounted for stock-based compensation utilizing the intrinsic value method prescribed by Accounting Principles Board Opinion No. 25 “Accounting for Stock Issued to Employee” (“APB 25”) and related interpretations.

The Company has accounted for options which were repriced in 1999 as variable stock options under APB 25 whereby compensation expense has been recognized through December 31, 2005 for unexercised options based on changes in the market value of the Company’s common stock. In accordance with SFAS 123R, the Company ceased accounting for these options as variable stock options upon the adoption date. The Company adopted SFAS 123R using the modified prospective application method. Since all of the Company’s outstanding options were fully vested at January 31, 2006, no future compensation expense will be recognized under SFAS 123R unless the options are modified, and the Company did not recognize any cumulative effect of change in accounting principles upon adoption of SFAS 123R.

For the three months ended March 31, 2006, the Company did not recognize any compensation expense related to stock-based compensation plans. For the three months ended March 31, 2005, the Company recognized $118,000 of compensation expense and a related tax benefit of $41,000 related to stock-based compensation plans.

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, 2006 expire 10 years from the date of grant and become exercisable based on varying vesting schedules.

11

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 44,000 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, 2006:

	Shares		Weighted Average Exercise Price		Weighted Average Remaining Contractual Term	Aggregate Intrinsic Value
Outstanding at January 1, 2006	1,338,551		$	19.53
Granted	4,000		$	41.74
Exercised	(30,566	)	$	5.72		$		1,374,305
Outstanding at March 31, 2006	1,311,985		$	19.91	3.9	$	27,558,439
Vested at March 31, 2006	1,311,985		$	19.91	3.9	$	27,558,439
Exercisable at March 31, 2006	1,311,985		$	19.91	3.9	$	27,558,439

The following pro forma information, as required by Statement of Financial Accounting Standards No. 123 “Accounting for Stock-Based Compensation” (“SFAS 123”), as amended by Statement of Financial Accounting Standards No. 148 (“SFAS 148”), presents net income and earnings per share information as if the stock options issued since December 31, 1994 were accounted for using the fair value method under SFAS 123. The fair value of stock operations issued for each year was estimated at the date of grant using the Black-Scholes option pricing model.

The SFAS 123 pro forma information for the three months ended March 31, 2005 is as follows:

	Three Months Ended March 31, 2005
	(In thousands, except per share)
Net income (loss), as reported	$	(8,992	)
Add: Stock-based employee compensation expense (credit) included in net income, net of tax	77
Net income (loss), pro forma	$	(8,915	)
Basic:
Net income (loss) per common share, as reported	$	(.83	)
Net income (loss) per common share, pro forma	$	(.83	)
Diluted:
Net income (loss) per common share, as reported	$	(.83	)
Net income (loss) per common share, pro forma	$	(.83	)

12

After-Payout Working Interest Incentive Plans

In September 2002, the Compensation Committee of the Board of Directors 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 working interest in the production developed, directly or indirectly, by the participants. The plan provides for the creation of a series of limited partnerships to which the Company, as general partner, contributes a portion of its working interest in wells drilled within certain areas, and the key employee and consultants, as limited partners, contribute cash. The Company pays all costs and receives all revenues until payout of its costs, plus interest. At payout, the limited partners receive 99% of all subsequent revenues and pay 99% of all subsequent expenses attributable to the partnerships’ interests.

Between 3% and 6% of the Company’s working interests in certain specified wells drilled by the Company subsequent to October 2002 are subject to this arrangement. The Company consolidates its proportionate share of the assets, liabilities, revenues, expenses and oil and gas reserves of these partnerships in its consolidated financial statements. In April 2004, one of the partnerships achieved payout, and the Company’s interest in the partnership was reduced to 1%. Aggregate cash distributions of approximately $61,000 were paid to the limited partners during 2006. During the three months ended March 31, 2006, the Company recognized $500,000 of non-cash compensation expense for the estimated value of the after-payout interests subject to this arrangement.

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.

13

The following summarizes information concerning the Company’s net positions in open commodity derivatives applicable to periods subsequent to March 31, 2006. The settlement prices of commodity derivatives are based on NYMEX futures prices.

Collars:

	Gas					Oil
	MMBtu (a)	Floor		Ceiling		Bbls	Floor		Ceiling
Production Period:
2nd Quarter 2006	551,000	$	4.00	$	5.21	156,000	$	23.00	$	25.32
3rd Quarter 2006	456,000	$	4.00	$	5.21	150,000	$	23.00	$	25.32
4th Quarter 2006	456,000	$	4.00	$	5.21	150,000	$	23.00	$	25.32
2007	1,831,000	$	4.00	$	5.18	562,000	$	23.00	$	25.20
2008	1,279,000	$	4.00	$	5.15	392,000	$	23.00	$	25.07
	4,573,000					1,410,000

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

Subsequent to March 31, 2006, the Company entered into swap agreements covering 1,050,000 MMBtu of gas production during the fourth quarter of 2006 at $10.03 per MMBtu and 5,350,000 MMBtu of gas production during 2007 at $10.23 per MMBtu.

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 following summarizes information concerning the Company’s net positions in open interest rate swaps applicable to periods subsequent to March 31, 2006.

Interest Rate Swaps:

	Principal Balance		Libor Rates
Period:
April 1, 2006 to November 1, 2006	$	55,000,000	4.29	%
November 1, 2006 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 period ended March 31, 2006, the Company reported a $1.6 million net loss on derivatives, consisting of a $6.5 million gain related to changes in mark-to-market valuations and an $8.1 million cash charge for settled contracts. For the period ended March 31, 2005, loss on derivates was $35.1 million, consisting of a $31.5 million non-cash charge related to changes in mark-to-market valuations and a $3.6 million cash charge for settled contracts.

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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 facilities was estimated to have a fair value approximating the carrying amount since the stated interest rate is generally market sensitive. Abandonment obligations are carried at net present value which approximates their fair value since the discount rate is based on the Company’s credit-adjusted, risk-free rate. The fair value of other noncurrent liabilities approximate their carrying value.

The fair values of derivatives as of March 31, 2006 and December 31, 2005 are set forth below. The associated carrying values at these dates are equal to their estimated fair values.

	March 31, 2006			December 31, 2005
	(In thousands)
Assets (liabilities):
Commodity derivatives	$	(76,643	)	$	(82,635	)
Interest rate derivatives	91			(422		)
Net assets (liabilities)	$	(76,552	)	$	(83,057	)

9.Income Taxes

Deferred tax assets and liabilities are the result of temporary differences between the financial statement carrying values and the tax bases of assets and liabilities. Significant components of net deferred tax liabilities at March 31, 2006 and December 31, 2005 are as follows:

	March 31, 2006			December 31, 2005
	(In thousands)
Deferred tax assets:
Net operating loss carryforwards	$	5,807		$	2,497
Fair value of derivatives	26,629			28,906
Credits related to alternative minimum tax	395			395
Statutory depletion carryforwards	4,018			3,861
Other	6,108			5,748
	42,957			41,407
Deferred tax liabilities:
Property and equipment	(81,377		)	(78,010		)
Net deferred tax liabilities	$	(38,420	)	$	(36,603	)
Components of net deferred tax assets (liabilities):
Current assets	$	427		$	439
Non-current liabilities	(38,847		)	(37,042		)
	$	(38,420	)	$	(36,603	)

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For the three months ended March 31, 2006 and 2005, the Company’s effective income tax rates were different than the statutory federal income tax rates for the following reasons:

	Three Months Ended March 31,
	2006			2005
	(In thousands)
Income tax expense (benefit) at statutory rate of 35%	$	1,818		$	(4,720	)
Tax depletion in excess of basis	(158		)	(112		)
State income taxes, net of federal tax effect	90			337
Other	68			—
Income tax expense (benefit)	$	1,818		$	(4,495	)
Current	$	—		$	156
Deferred	1,818			(4,651		)
Income tax expense (benefit)	$	1,818		$	(4,495	)

At March 31, 2006, the Company’s cumulative tax loss carryforwards were approximately $18 million. Based upon current commodity prices and production volumes, as well as the availability of tax planning strategies (such as elective capitalization of intangible drilling costs), the Company believes that it is more likely than not that the Company will be able to utilize these tax loss carryforwards before they expire (beginning in 2008).  Accordingly, no valuation allowance has been provided at March 31, 2006.

10.Investment

In April 2006, the Company invested $500,000 in a joint venture (“Larclay JV”) with Lariat Services, Inc. (“Lariat”) to 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. Construction of all the rigs is expected to be completed by February 28, 2007 at a cost of approximately $75 million. A lender has provided a $75 million credit facility to Larclay JV to finance the construction and equipping of the rigs. Pursuant to the terms of the credit facility, the Company has issued a $19 million letter of credit to the lender as additional collateral during the construction period. Upon the earlier of compliance with specified collateral ratios or February 28, 2007, the lender will release the letter of credit in exchange for a $19.5 million guaranty from the Company. After completion of the construction period, outstanding advances under the credit facility must not exceed 75% of the appraised value of the rigs. If proceeds available to Larclay JV under the credit facility are not sufficient to fully finance the cost of the rigs, the Company will be required to loan funds to Larclay JV at the same interest rate as the credit facility. The Larclay JV credit facility bears interest at a floating rate based on a LIBOR average, plus 3.25%, and provides for interest payments through March 2007 and 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 credit facility prohibits Larclay JV from making any cash distributions to the Company or Lariat until the balance on the credit facility is fully repaid, and repayments by Larclay JV of any loans by the Company or Lariat are subordinated to the loans outstanding under the credit facility and are subject to other restrictions.

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 require

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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 Lariat, affiliates of Lariat or other third party 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.

11.Commitments

In addition to the rigs the Company has committed to use pursuant to the drilling contract described in Note 10, the Company is presently obligated under firm orders for two drilling rigs and related equipment in an aggregate amount of $18.1 million. The total cost of the rigs, when completed and fully equipped, will be approximately $24 million. The rigs are scheduled for delivery in mid-2007 and are expected to be utilized to drill the Company’s deep Bossier prospects in East Texas and North Louisiana.

12.Exploratory Drilling Costs

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, 2006 and December 31, 2005, the Company had capitalized $15.8 million and $10.3 million, respectively, of exploratory drilling costs applicable to wells that were pending determination of proved reserves. Of the $10.3 million costs at December 31, 2005, $1.2 million was expensed as a dry hole during the three months ended March 31, 2006, $2.1 million was subsequently deemed productive and the remaining $7 million exploratory drilling costs were still pending determination of proved reserves.

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

The following discussion is intended to provide information relevant to an understanding of our financial condition, changes in our financial condition and our results of operations and cash flows and should be read in conjunction with our consolidated financial statements and notes thereto included elsewhere in this Form 10-Q and in our Form 10-K for the year ended December 31, 2005.

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 our discovered 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. Oil and gas prices have remained strong. Supply and demand fundamentals continue to suggest that energy prices will remain high for the near term, providing us with the economic incentives necessary for us to assume the risks we face in our search for oil and gas reserves. On the downside, however, we are also experiencing significant cost increases in almost all areas of our business activities, especially in drilling and production costs. High demand for oilfield services is being met with shortages in equipment and trained personnel, resulting in rate increases. While profit margins still remain favorable, operating metrics per Mcfe, such as finding costs, production costs and overhead costs, are rising.

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 2006 and the outlook for the remainder of 2006.

•We spent $68.1 million on exploration and development activities during the first quarter of 2006, most of which was on exploratory prospects, and we now plan to spend approximately $222.7 million for the year 2006. These levels of expenditures are significantly higher than our anticipated cash flow from operations in 2006.

•We increased borrowings under our revolving credit facility from $10.7 million to $66.7 million to partially finance our exploration and development activities.

•We recorded a $1.6 million net loss on derivatives during the first quarter of 2006. Cash settlements to counterparties accounted for $8.1 million of this loss offset by a $6.5 million gain for changes in mark-to-market valuations. Since we do not presently designate our derivatives as cash flow hedges under applicable accounting standards, we recognize the full effect of changing prices on mark-to-market valuations as a current charge or credit to our results of operations.

•Exploration costs related to abandonments and impairments totaled $12.8 million during the first quarter of 2006, most of which was attributable to South Louisiana and Montana.

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•Financing arrangements have been completed for the construction of 12 new drilling rigs to be owned and operated by a joint venture in which we own a 50% interest.

•We have placed firm orders for two drilling rigs and related equipment in an aggregate amount of $18.1 million.

Recent Exploration and Developmental Activities

Overview

As shown in “Liquidity and Capital Resources – Capital Expenditures,” we incurred expenditures for exploration and development activities of $68.1 million during the first quarter of 2006. We have also increased our estimates for capital expenditures in fiscal 2006 from $184.1 million to $222.7 million. Approximately 40% of our first quarter 2006 expenditures were lease purchases and seismic and other exploration costs.

We are actively acquiring leases in North Louisiana and East Texas in order to establish a significant acreage position for future exploratory and, if successful, developmental drilling activities. We believe that the reserve potential in these areas is significant and warrants this investment in acreage.

South Louisiana

The following table sets forth certain information about our exploratory well activities in south Louisiana subsequent to December 31, 2005.

Spud Date	Well Name (Prospect)	Working Interest		Current Status
January 2006	Borah #1 (Cypress Isle)	75	%	Dry
February 2006	SL 195 QQ #2 (Floyd)	81.3	%	Waiting on production facilities
February 2006	SL 195 QQ #3 (Floyd)	75	%	Waiting on production facilities
March 2006	SL 195 QQ #4 (Floyd)	75	%	Completing
March 2006	A. J. Beshel #1 (Beshel)	100	%	Completing
April 2006	Cobena #1 (Boa II)	62.5	%	Drilling

We completed the first three wells on the Floyd prospect in Plaquemines Parish as gas wells. We have also drilled and logged the State Lease 195 QQ #4. This well encountered multiple pay zones and is currently being completed. We presently plan to drill four additional wells on this acreage. Under the terms of a farmout agreement, we bear 100% of the costs on these wells before casing point to earn a 75% working interest in the drilled acreage.

We have also drilled and logged the A.J. Beshel #1, a 12,000-foot exploratory well in Plaquemines Parish. This well also encountered potentially productive sands and is currently being completed. We own 100% of the working interest in this well.

We also abandoned the Borah #1 (Cypress Isle), a 17,500-foot exploratory well in St. Martin Parish after determining that the well was nonproductive. We recorded a pre-tax charge of $7.8 million related to the abandonment of this well in the first quarter of 2006, and will record an additional pre-tax charge of approximately $2.5 million in the second quarter of 2006.

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North Louisiana

We are currently completing the Harris #1, a 14,500-foot exploratory well in Jackson Parish targeting the Bossier formation, in which we own a 53% working interest. While we do not currently expect the reserves from this well to be substantial, we do believe the well will be productive. We plan to spud our next Bossier well in the third quarter 2006. In addition, we have participated in 11 non-operated Cotton Valley/Hosston wells in which our working interests have ranged from 1% to 44%. Currently, six of the wells are producing, three are completing, and two are drilling. We plan to spud our first operated Cotton Valley/Hosston well in the second quarter of 2006.

Other

We have continued to acquire leases in the Bossier play in East Texas, and to date have acquired approximately 35,000 net acres. We have also abandoned the Ruegsegger 24H #1, a 7,600-foot exploratory well in Sheridan County, Montana, and recorded a pre-tax charge of $1.9 million related to the abandonment of this well in the first quarter of 2006.

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Supplemental Information

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

	Three Months Ended March 31,
	2006			2005
Oil and Gas Production Data:
Gas (MMcf)	3,463			4,761
Oil (MBbls)	555			619
Natural gas liquids (MBbls)	48			66
Total (MMcfe)	7,081			8,871
Average Realized Prices (a):
Gas ($/Mcf)	$	7.22		$	6.22
Oil ($/Bbl)	$	60.01		$	47.83
Natural gas liquids ($/Bbl):	$	38.90		$	27.50
Gains (Losses) on Settled Derivative Contracts (a): ($in thousands, except per unit)
Gas:Net realized gain (loss)	$	(2,178	)	$	708
Per unit produced ($/Mcf)	$	(0.63	)	$	0.15
Oil:Net realized loss	$	(5,895	)	$	(4,220	)
Per unit produced ($/Bbl)	$	(10.62	)	$	(6.82	)
Average Daily Production:
Natural Gas (Mcf):
Permian Basin	13,824			16,156
Louisiana	9,466			15,272
Austin Chalk (Trend)	3,261			2,558
Cotton Valley Reef Complex	11,439			18,014
Other	488			900
Total	38,478			52,900
Oil (Bbls):
Permian Basin	3,216			3,332
Louisiana	1,079			1,474
Austin Chalk (Trend)	1,828			2,033
Other	44			39
Total	6,167			6,878
Natural Gas Liquids (Bbls):
Permian Basin	262			233
Austin Chalk (Trend)	258			337
Other	13			163
Total	533			733

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	Three Months Ended March 31,
	2006		2005
Exploration Costs (in thousands):
Abandonment and impairment costs:
Louisiana	$	8,008	$	1,272
Permian Basin	2,202		288
Montana	1,933		—
Mississippi	679		2,464
Cotton Valley Reef Complex	11		7,246
Other	10		—
Total	12,843		11,270
Seismic and other	3,101		788
Total exploration costs	$	15,944	$	12,058
Oil and Gas Costs ($/Mcfe Produced):
Production costs	$	2.11	$	1.42
Oil and gas depletion	$	1.97	$	1.30
Net Wells Drilled (b):
Exploratory Wells	7.6		3.3
Developmental Wells	1.7		8.9

(a)No derivatives were designated as cash flow hedges in 2006 or 2005. 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, 2006 to the comparative period in 2005. Unless otherwise indicated, references to 2006 and 2005 within this section refer to the respective quarterly period.

Oil and gas operating results

Oil and gas sales in 2006 decreased 2% from 2005. Oil and gas sales decreased $1.3 million, of which price variances accounted for a $10.8 million increase and production variances accounted for a $12.1 million decrease.

Production in 2006 (on an Mcfe basis) was 20% lower than 2005. Our oil production decreased 10% in 2006 from 2005 due in part to lost production in Louisiana as a result of hurricane damage and normal production declines on existing wells. Our gas production decreased 27% in 2006 from 2005 due partially to lost gas production from the hurricanes and by production declines in the Cotton Valley Reef Complex area due to formation performance.

In 2006, our realized oil price was 25% higher than 2005, while our realized gas price was 16% higher. Historically, the markets for oil and gas have been volatile, and they are likely to continue to be volatile.

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Oil and gas production costs on an Mcfe basis increased from $1.42 per Mcfe in 2005 to $2.11 per Mcfe in 2006. The increase in operating costs in 2006 was due primarily to higher oilfield service costs and an increase in workover activities, combined with a production decline of 20% on an Mcfe basis for the current period. It is likely that these factors will continue to contribute to higher production costs in future periods.

Depreciation, depletion, and amortization (“DD&A”) expense attributable to our oil and gas properties increased from $12.3 million in 2005 to $14.7 million in 2006. Rate variances accounted for a $4.9 million increase in DD&A expense and production variances accounted for a $2.5 million decrease. On an Mcfe basis, DD&A expense increased 52% from $1.30 per Mcfe in 2005 to $1.97 per Mcfe in 2006. Depletion rates for each depletable group are a function of net capitalized costs and estimated reserve quantities.

General and administrative (“G&A”) expenses increased from $2.5 million in 2005 to $4.1 million in 2006 due primarily to higher personnel costs and professional fees derived from the increase in overall drilling and exploration activities.

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 2006, we charged to expense $15.9 million of exploration costs, as compared to $12.1 million in 2005.  Most of these costs were incurred in Louisiana and Montana as a result of the abandonments of the Borah #1 (Cypress Isle) and the Ruegsegger 24H #1.

We plan to spend approximately $222.7 million on exploration and development activities in fiscal 2006, of which approximately 90% 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 remaining costs in fiscal 2006 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.

Interest expense

Interest expense increased from $2.4 million in 2005 to $4.3 million in 2006 due primarily to higher average levels of indebtedness. In July 2005, we repaid all outstanding balances on our bank indebtedness using proceeds from the issuance of $225 million of 7¾% Senior Notes due 2013 (the “Senior Notes”) which bear interest at a fixed rate of 7.75%. The weighted average debt outstanding on our bank credit facilities at March 31, 2006 was $43.5 million compared to $183.2 million at March 31, 2005.

Loss on derivatives

We recorded a loss on derivatives of $1.6 million in 2006 compared to a loss of $35.1 million for 2005. We did not designate any derivative contracts in 2006 or 2005 as cash flow hedges; therefore all cash settlements and changes resulting from mark-to-market valuations have been recorded as losses on derivatives. Cash settlements were $8.1 million in 2006, as compared to $3.6 million in 2005. We recorded a gain on derivatives of $6.5 million in 2006 compared to a loss of $31.5 million in 2005 resulting from mark-to-market valuations.

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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 July 2005, we reduced our dependence on the borrowing base established for the revolving credit facility by issuing $225 million of aggregate principal amount of Senior Notes and using the net proceeds to repay all amounts outstanding on the revolving credit facility and the senior term credit facility. However, we have recently drawn advances under the revolving credit facility to partially finance our exploration and development activities. At March 31, 2006, we had $66.7 million outstanding on the revolving credit facility.

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

Our planned expenditures for exploration and development activities during 2006 total $222.7 million, as summarized by area in the following table.

	Actual		Total
	Expenditures		Planned
	Three Months		Expenditures
	Ended		Year Ended		Percentage
	March 31, 2006		December 31, 2006		of Total
	(In thousands)
North Louisiana	$	12,600	$	85,800	40	%
South Louisiana	26,200		76,600		34	%
East Texas (Bossier)	11,200		27,200		12	%
Permian Basin	12,300		18,100		8	%
Utah/Montana	3,800		7,600		3	%
Austin Chalk (Trend)	1,100		2,900		1	%
Other	900		4,500		2	%
	$	68,100	$	222,700	100	%

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Our actual expenditures during fiscal 2006 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 2006.

Approximately 90% 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.

At our current level of planned activity for 2006, we project that more than half of the cash needed to finance our planned expenditures for exploration and development activities in fiscal 2006 will be provided by operating activities. To the extent that actual costs exceed our cash provided by operating activities, we plan to utilize the revolving credit facility to finance such excess. We borrowed $56 million under our revolving credit facility during the first quarter of 2006 and expect to borrow additional amounts during the remainder of fiscal 2006.

Drilling Rig Joint Venture

In April 2006, we invested $500,000 in a joint venture (“Larclay JV”) with Lariat Services, Inc. (“Lariat”) to own and operate 12 new drilling rigs. CWEI 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. Construction of all the rigs is expected to be completed by February 28, 2007 at a cost of approximately $75 million. A lender has provided a $75 million credit facility to Larclay JV to finance the construction and equipping of the rigs. Pursuant to the terms of the credit facility, we have issued a $19 million letter of credit to the lender as additional collateral during the construction period. Upon the earlier of compliance with specified collateral ratios or February 28, 2007, the lender will release the letter of credit in exchange for a $19.5 million guaranty from us. After completion of the construction period, outstanding advances under the credit facility must not exceed 75% of the appraised value of the rigs. If proceeds available to Larclay JV under the credit facility are not sufficient to fully finance the cost of the rigs, we will be required to loan funds to Larclay JV at the same interest rate as the credit facility. The Larclay JV credit facility bears interest at a floating rate based on a LIBOR average, plus 3.25%, and provides for interest payments through March 2007 and 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 credit facility prohibits Larclay JV from making any cash distributions to us or to Lariat until the balance on the credit facility is fully repaid, and repayments by Larclay JV of any loans by us or by Lariat are subordinated to the loans outstanding under the credit facility and are subject to other restrictions.

At March 31, 2006, we had advanced Larclay JV $16.8 million for interim construction costs. In April 2006, Larclay repaid the full amount of the advances from the proceeds of its credit facility.

Also in April 2006, we entered into a three-year drilling contract with Larclay JV assuring the availability of each rig for use in the ordinary course of our exploration and development drilling program throughout the term of the drilling contract. The provisions of the drilling contract require that we contract for each rig on a well-by-well basis at then current market rates. If a rig is not needed by us at any time

25

during the term of the contract, Larclay JV may contract with Lariat, affiliates of Lariat or other third party operators for the use of such rig, subject to certain restrictions. If a rig is idle, we 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.

Our gross idle rig commitment under the drilling contract with Larclay JV aggregates approximately $114 million over the three-year term of the contract. We plan to mitigate our exposure to our idle rig commitment by permitting Larclay JV to contract with other operators during any time which we do not need specified rigs in our drilling program. As we utilize the Larclay JV rigs in the ordinary course of our drilling program, the cost of such rigs will be included in our exploration and development expenditures.

In addition to the rigs we have committed to use pursuant to the drilling contract with Larclay JV described above, we are directly committed under firm orders for two drilling rigs and related equipment in an aggregate amount of $18.1 million. The total cost of the rigs, when completed and fully equipped, will be approximately $24 million. The rigs are scheduled for delivery in mid-2007 and are expected to be utilized to drill our deep Bossier prospects in East Texas and North Louisiana.

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, 2006 was 25% higher than the same period in 2005 due to the combined effects of several factors. Oil and gas sales, net of production costs, general and administrative costs and interest expense, were $7.2 million lower in the first quarter 2006 as compared to the same period in 2005. However, changes in working capital resulted in an increase in the current quarter of $11.2 million as compared to a decrease in the 2005 quarter of $2.7 million. 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. Higher oil and gas prices also resulted in an increase in cash required to settle 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. Interest expense increased in 2006 due primarily to higher levels of indebtedness resulting from the issuance of the Senior Notes.

Credit facilities

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 2006, we had an outstanding balance under the revolving credit facility of $10.7 million, and the borrowing base was $150 million, providing us with available funds of $138.5 million after accounting for outstanding letters of credit. During the three months ended March 31,

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2006, we generated cash flow from operating activities of $37.5 million. We also spent $83.1 million on capital expenditures and other investments and paid $7.9 million to settle derivatives with financing elements. To finance the excess of exploration over cash flow, we borrowed $56 million on the revolving credit facility, reducing our availability at March 31, 2006 to $82.5 million.

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 decreased from $35.8 million at December 31, 2005 to $24.6 million at March 31, 2006 due primarily to a combination of factors, including decreases in accounts payable and increases in inventory. After giving effect to the adjustments, our working capital computed for loan compliance purposes was a positive $89.4 million at March 31, 2006, as compared to a positive $136.2 million at December 31, 2005. The following table reconciles our GAAP working capital to the working capital computed for loan compliance purposes at March 31, 2006 and December 31, 2005.

	March 31, 2006			December 31, 2005
	(In thousands)
Working capital (deficit) per GAAP	$	(24,605	)	$		(35,812	)
Add funds available under the revolving credit facility	82,496		(a)	138,496
Exclude fair value of derivatives classified as current assets or current liabilities	31,518			33,479
Working capital per loan covenant	$	89,409		$	136,163

(a)Subsequent to March 31, 2006, we issued a letter of credit in the amount of $19 million in connection with the financing of drilling rigs owned by Larclay JV.

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, 2006, our increased leverage and reduced liquidity may

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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. However, the issuance of the Senior Notes described below significantly increases our liquidity and reduces our dependence on the revolving credit facility.

The banks redetermine the borrowing base under the revolving credit facility at least twice a year, in May and November. 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. In connection with the issuance of the Senior Notes, the borrowing base was reduced to $132.5 million in July 2005, and all outstanding balances on our revolving credit facility were repaid. However, we have recently drawn advances under the revolving credit facility to partially finance our explanation and development activities. At March 31, 2006, we had $66.7 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, 2006.

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

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placement if we choose to raise capital through either of these markets. While we believe we would be able to obtain funds through one or more of these alternatives, if needed, there can be no assurance that these capital resources would be available on terms acceptable to us.

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Item 3 -Quantitative and Qualitative 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, 2005 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, 2006 by $11 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. The commodity derivatives we use differ from futures contracts in that there is not a contractual obligation that requires or permits the future physical delivery of the hedged products. We do not enter into commodity derivatives for trading purposes. In addition to commodity derivatives, we may, from time to time, sell a portion of our gas production under short-term contracts at fixed prices.

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

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The following summarizes information concerning our net positions in open commodity derivatives applicable to periods subsequent to March 31, 2006. The settlement prices of commodity derivatives are based on NYMEX futures prices.

Collars:

	Gas					Oil
	MMBtu (a)	Floor		Ceiling		Bbls	Floor		Ceiling
Production Period:
2nd Quarter 2006	551,000	$	4.00	$	5.21	156,000	$	23.00	$	25.32
3rd Quarter 2006	456,000	$	4.00	$	5.21	150,000	$	23.00	$	25.32
4th Quarter 2006	456,000	$	4.00	$	5.21	150,000	$	23.00	$	25.32
2007	1,831,000	$	4.00	$	5.18	562,000	$	23.00	$	25.20
2008	1,279,000	$	4.00	$	5.15	392,000	$	23.00	$	25.07
	4,573,000					1,410,000

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

Subsequent to March 31, 2006, we entered into swap agreements covering 1,050,000 MMBtu of gas production during the fourth quarter of 2006 at $10.03 per MMBtu and 5,350,000 MMBtu of gas production during 2007 at $10.23 per MMBtu.

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 $3 million.

Interest Rates

We are party to interest rate swaps that were acquired in connection with the SWR acquisition. 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, 2006.

	Principal  Balance			Libor  Rates
Period:
April 2006 to November 1, 2006	$		55,000,000	4.29	%
November 1, 2006 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.

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Item 4 -Controls and Procedures

Disclosure Controls and Procedures

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

With respect to our disclosure controls and procedures:

•We have 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 operate such that material information flows to the appropriate collection and disclosure points in a timely manner and are effective in ensuring that material information is accumulated and communicated to our management and is made known to the chief executive and chief financial officers, particularly during the period in which this report was prepared, as appropriate to allow timely decisions regarding required disclosures.

Changes in Internal Control Over Financial Reporting

No changes in internal control over financial reporting were made during the quarter ended March 31, 2006 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II. FINANCIAL INFORMATION

Item 1A -Risk Factors

In evaluating all forward-looking statements, you should specifically consider various factors that may cause actual results to vary from those contained in the forward-looking statements. Our risk factors are included in our Annual Report on Form 10-K for the year ended December 31, 2005, as filed with the U.S. Securities and Exchange Commission on March 16, 2006 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**	Bylaws of the Company, filed as Exhibit 3.4 to our Form S-1 Registration Statement, Commission File No. 33-43350
3.4**	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 June 1, 2005††
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**	First Amendment to Amended and Restated Credit Agreement dated July 18, 2005, filed as Exhibit 10.1 to our Current Report on Form 8-K filed with the Commission on July 20, 2005††
10.2**	Limited Liability Company Agreement, dated April 21, 2006, by and between Clayton Williams Energy, Inc. and Lariat Services, Inc., with respect to the formation of Larclay GP, LLC, a Texas limited liability company, filed as Exhibit 10.1 to our Current Report on Form 8-K filed with the Commission on April 26, 2006††

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10.3**	Agreement of Limited Partnership, dated April 21, 2006, by and among Larclay GP, LLC, Clayton Williams Energy, Inc. and Lariat Services, Inc., with respect to the formation of Larclay L.P., a Texas limited partnership, filed as Exhibit 10.2 to our Current Report on Form 8-K filed with the Commission on April 26, 2006††
10.4**	Drilling Contract for Multiple Rigs, dated April 21, 2006, by and between Clayton Williams Energy, Inc. and Larclay L.P., filed as Exhibit 10.3 to our Current Report on Form 8-K filed with the Commission on April 26, 2006††
10.5**	Subordination Agreement, dated April 21, 2006, by and among Clayton Williams Energy, Inc., Lariat Services, Inc. and Merrill Lynch Capital, as agent, filed as Exhibit 10.4 to our Current Report on Form 8-K filed with the Commission on April 26, 2006††
10.6**	Consent and Agreement, dated April 21, 2006, by and among Clayton Williams Energy, Inc., Lariat Services, Inc. and Merrill Lynch Capital, as agent, filed as Exhibit 10.5 to our Current Report on Form 8-K filed with the Commission on April 26, 2006††
10.7**	Letter of Credit, dated April 21, 2006, issued in favor of Merrill Lynch Capital, as agent, filed as Exhibit 10.6 to our Current Report on Form 8-K filed with the Commission on April 26, 2006††
10.8**	Form of Unconditional Limited Guaranty, to be issued by Clayton Williams Energy, Inc. in favor of Merrill Lynch Capital, as agent, filed as Exhibit 10.7 to our Current Report on Form 8-K filed with the Commission on April 26, 2006††
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
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
32.1*	Certifications by the Chief Executive Officer and Chief Financial Officer of the Company pursuant to 18 U.S.C. § 1350

*Filed herewith

**Incorporated by reference to the filing indicated

††Filed under our Commission File No. 001-10924

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CLAYTON WILLIAMS ENERGY, INC.

SIGNATURES

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

			CLAYTON WILLIAMS ENERGY, INC.
Date:	May 9, 2006	By:	/s/ L. Paul Latham
			L. Paul Latham
			Executive Vice President and Chief Operating Officer
Date:	May 9, 2006	By:	/s/ Mel G. Riggs
			Mel G. Riggs
			Senior Vice President and Chief Financial Officer

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