UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

x Quarterly Report Pursuant to Section 13 or 15(d)
of the Securities Exchange Act of 1934

For the quarterly period ended June 30, 2006

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.

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. x Yes o No

Large accelerated filer o

Accelerated filer x

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 x No

There were 10,849,551 shares of Common Stock, $.10 par value, of the registrant outstanding as of August 7, 2006.

CLAYTON WILLIAMS ENERGY, INC.

TABLE OF CONTENTS

		PART I. FINANCIAL INFORMATION

Item 1.		Financial Statements

		Consolidated Balance Sheets as of June 30, 2006 and December 31, 2005

		Consolidated Statements of Operations for the three months and six months ended June 30, 2006 and 2005

		Consolidated Statement of Stockholders’ Equity for the six months ended June 30, 2006

		Consolidated Statements of Cash Flows for the six months ended June 30, 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 4.		Submission of Matters to a Vote of Securities Holders

Item 6.		Exhibits

		Signatures

CLAYTON WILLIAMS ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

ASSETS

	June 30,			December 31,
	2006			2005
	(Unaudited)
CURRENT ASSETS
Cash and cash equivalents	$	16,869		$	5,935
Accounts receivable:
Oil and gas sales, net	23,648			28,317
Joint interest and other, net	10,561			6,972
Affiliates	1,248			254
Inventory	46,069			43,753
Deferred income taxes	426			439
Fair value of derivatives	3,850			191
Prepaids and other	1,987			2,581
	104,658			88,442
PROPERTY AND EQUIPMENT
Oil and gas properties, successful efforts method	1,138,718			1,037,862
Natural gas gathering and processing systems	18,052			18,034
Contract drilling equipment	31,607			—
Other	14,862			12,396
	1,203,239			1,068,292
Less accumulated depreciation, depletion and amortization	(624,914		)	(594,225		)
Property and equipment, net	578,325			474,067

OTHER ASSETS
Debt issue costs	8,260			8,557
Advances to drilling rig joint venture	—			10,329
Fair value of derivatives	5,099			127
Other	15,886			5,813
	29,245			24,826
	$	712,228		$	587,335

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

	June 30,		December 31,
	2006		2005
	(Unaudited)
CURRENT LIABILITIES
Accounts payable:
Trade	$	52,884	$	59,861
Oil and gas sales	12,334		18,236
Affiliates	1,877		2,857
Current maturities of long-term debt	3,174		19
Fair value of derivatives	35,968		33,670
Accrued liabilities and other	9,952		9,611
	116,189		124,254
NON-CURRENT LIABILITIES
Long-term debt	348,430		235,700
Deferred income taxes	41,919		37,042
Fair value of derivatives	41,755		49,705
Other	21,976		20,343
	454,080		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 – 10,849,551 shares in 2006 and 10,815,575 shares in 2005	1,085		1,082
Additional paid-in capital	107,431		107,108
Retained earnings	33,443		12,101
	141,959		120,291
	$	712,228	$	587,335

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 June 30,						Six Months Ended June 30,
	2006			2005			2006			2005
REVENUES
Oil and gas sales	$	66,443		$	63,301		$	126,624		$	124,797
Natural gas services	2,789			2,550			5,985			5,131
Drilling rig services	374			—			374			—
Gain on sales of property and equipment	735			467			752			2,079
Total revenues	70,341			66,318			133,735			132,007

COSTS AND EXPENSES
Production	15,931			13,856			30,896			26,427
Exploration:
Abandonments and impairments	3,329			6,430			16,172			17,700
Seismic and other	2,587			1,665			5,688			2,453
Natural gas services	2,261			2,374			5,090			4,791
Drilling rig services	216			—			216			—
Depreciation, depletion and amortization	15,982			12,288			30,692			24,580
Accretion of abandonment obligations	417			288			796			567
General and administrative	4,252			3,134			8,319			5,652
Loss on sales of property and equipment	—			—			13			32
Total costs and expenses	44,975			40,035			97,882			82,202

Operating income	25,366			26,283			35,853			49,805

OTHER INCOME (EXPENSE)
Interest expense	(4,961		)	(2,566		)	(9,300		)	(4,932		)
Gain (loss) on derivatives	245			(9,837		)	(1,327		)	(44,926		)
Other	450			650			1,068			1,096
Total other income (expense)	(4,266		)	(11,753		)	(9,559		)	(48,762		)

Income before income taxes	21,100			14,530			26,294			1,043
Income tax expense	(3,094		)	(4,580		)	(4,912		)	(85		)
Minority interest	(40		)	—			(40		)	—

NET INCOME	$	17,966		$	9,950		$	21,342		$	958

Net income per common share:
Basic	$	1.66		$	0.92		$	1.97		$	0.09
Diluted	$	1.59		$	0.90		$	1.89		$	0.09

Weighted average common shares outstanding:
Basic	10,850			10,800			10,845			10,796
Diluted	11,286			11,089			11,294			11,068

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

CLAYTON WILLIAMS ENERGY, INC.

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY

(Unaudited)

(In thousands)

	Common Stock			Additional
	No. of	Par		Paid-In		Retained
	Shares	Value		Capital		Earnings
BALANCE, December 31, 2005	10,815	$	1,082	$	107,108	$	12,101
Net income and total comprehensive income	—	—		—		21,342
Issuance of stock through compensation plans	35	3		323		—
BALANCE, June 30, 2006	10,850	$	1,085	$	107,431	$	33,443

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

CLAYTON WILLIAMS ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In thousands)

	Six Months Ended June 30,
	2006			2005
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	21,342		$	958
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation, depletion and amortization	30,692			24,580
Exploration costs	16,172			17,700
Accretion of abandonment obligations	796			567
Gain on sales of property and equipment, net	(739		)	(2,047		)
Deferred income taxes	4,912			(44		)
Non-cash employee compensation	1,151			720
Unrealized (gain) loss on derivatives	(14,283		)	35,221
Settlements on derivatives with financing elements	15,508			9,796
Amortization of debt issue costs	735			—
Minority interest, net of tax	40			—

Changes in operating working capital:
Accounts receivable	86			(1,137		)
Accounts payable	143			(8,827		)
Other	493			(8,205		)
Net cash provided by operating activities	77,048			69,282

CASH FLOWS FROM INVESTING ACTIVITIES
Additions to property and equipment	(134,857		)	(79,001		)
Additions to equipment of Larclay JV	(31,607		)	—
Proceeds from sales of property and equipment	684			2,151
Other	(886		)	(418		)
Net cash used in investing activities	(166,666		)	(77,268		)

CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt	79,700			12,100
Proceeds from long-term debt of Larclay JV	36,197			—
Repayments of other long-term debt	(12		)	—
Proceeds from sale of common stock	175			—
Settlements on derivatives with financing elements	(15,508		)	(9,796		)
Net cash provided by financing activities	100,552			2,304

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	10,934			(5,682		)

CASH AND CASH EQUIVALENTS
Beginning of period	5,935			16,359

End of period	$	16,869		$	10,677

SUPPLEMENTAL DISCLOSURES
Cash paid for interest, net of amounts capitalized	$	8,394		$	5,343

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

CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 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.

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 4). 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 June 30, 2006 and for the interim periods ended June 30, 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 Form 10-K for the year ended December 31, 2005.

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) 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.

In June 2006, the Financial Accounting Standards Board (“FASB”) issued FASB 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 is currently reviewing FIN 48 to determine its application to the Company’s consolidated financial statements.

4. Investment in 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. 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 secured term loan to Larclay JV to finance the construction and equipping of the rigs. Pursuant to the term loan, 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 term loan must not exceed 75% of the appraised value of the rigs. If proceeds available to Larclay JV under the term loan 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 term loan. The Larclay JV term loan bears interest at a floating rate based on a LIBOR average, plus 3.25%, and provides for monthly interest payments through March 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.

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 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. The Company’s gross idle rig obligations under this drilling contract, excluding crew labor, if any, aggregates $114 million.

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 FASB Interpretation No. 46R, “Consolidation of Variable Interest Entities — an interpretation of ARB No. 51 (as amended)” (“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 June 30, 2006, Lariat’s equity ownership in the net assets of Larclay JV was $561,000, which is recorded as minority interest and included in other non-current liabilities in the accompanying consolidated financial statements. The Company’s share of intercompany accounts with Larclay JV have been eliminated.

5. Long-Term Debt

Long-term debt consists of the following:

	June 30,			December 31,
	2006			2005
	(In thousands)
7¾% Senior Notes due 2013	$	225,000		$	225,000
Secured bank credit facility, due May 2009	90,400			10,700
Secured term loan of Larclay JV	36,197			—
Other	7			19
	351,604			235,719
Less current maturities(a)	(3,174		)	(19		)
	$	348,430		$	235,700

(a) Includes current portion of term loan of Larclay JV of $3,167 at June 30, 2006.

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 June 30, 2006.

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. In June 2006, the borrowing base established by the banks was increased from $150 million to $200 million, with no monthly commitment reductions. After allowing for outstanding letters of credit totaling $19.8 million, the Company had $89.8 million available under the credit facility at June 30, 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. 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 six months ended June 30, 2006 was 7.4%.

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 June 30, 2006.

Secured Term Loan of Larclay JV

In connection with the Company’s investment in Larclay JV (see Note 4), 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 and a $19 million letter of credit from the Company, which letter of credit will be replaced prior to February 28, 2007 by a $19.5 million guaranty from the Company. Although the Company is not a maker on the Larclay JV term loan, it has provided the letter of credit and guaranty as credit support for the Larclay JV term loan and is required to fully consolidate the accounts of Larclay JV under FIN 46R. At June 30, 2006, the effective interest rate on the Larclay JV term loan was 8.3%. Larclay JV capitalized $338,000 of interest expense related to the construction phase of the drilling rigs.

6. Other Non-Current Liabilities

Other non-current liabilities consist of the following:

	June 30,		December 31,
	2006		2005
	(In thousands)
Abandonment obligations	$	20,522	$	19,447
Minority interest	561		—
Other	893		896
	$	21,976	$	20,343

Changes in abandonment obligations for the six months ended June 30, 2006 and 2005 are as follows:

	Six Months Ended
	June 30,
	2006			2005
	(In thousands)
Beginning of period	$	19,447		$	16,147
Additional abandonment obligations from new wells	410			236
Sales or abandonments of properties	(114		)	(279		)
Revisions of previous estimates	(17		)	—
Accretion expense	796			567
End of period	$	20,522		$	16,671

7. 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 a change in accounting principles upon adoption of SFAS 123R.

Compensation expense related to stock-based compensation plans for the six months ended June 30, 2006 and 2005 was not significant.

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 June 30, 2006 expire 10 years from the date of grant and become exercisable based on varying vesting schedules.

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 six months ended June 30, 2006:

					Weighted
			Weighted		Average
			Average		Remaining	Aggregate
			Exercise		Contractual	Intrinsic
	Shares		Price		Term	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 June 30, 2006	1,311,985		$	19.91	5.5	$	19,187,975

Vested at June 30, 2006	1,311,985		$	19.91	5.5	$	19,187,975
Exercisable at June 30, 2006	1,311,985		$	19.91	5.5	$	19,187,975

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 options 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 six months ended June 30, 2005 is as follows:

	Six Months
	Ended
	June 30, 2005
	(In thousands, except per share)
Net income, as reported	$	958
Add: Stock-based employee compensation expense included in net income, net of tax	182
Deduct: Stock-based employee compensation expense determined under fair value based method (SFAS 123R), net of tax	(2,920		)
Net loss, pro forma	$	(1,780	)

Basic:
Net income per common share, as reported	$	.09
Net loss per common share, pro forma	$	(.16	)

Diluted:
Net income per common share, as reported	$	.09
Net loss per common share, pro forma	$	(.16	)

After-Payout Working Interest 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 working interest in the production developed, directly or indirectly, by the participants. The plan generally provides for the creation of a series of partnerships between the Company and the participants to which the Company contributes a portion of its working interest in wells drilled within certain areas. The Company pays all costs and receives all revenues until payout of its costs, plus interest. At payout, the participants 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 records its allocable share of the assets, liabilities, revenues, expenses and oil and gas reserves of these partnerships in its consolidated financial statements. To date, two of these partnerships achieved payout. Aggregate cash distributions of approximately $181,000 were paid to the participants during the six months ended June 30, 2006. During the six months ended June 30, 2006, the Company recognized $1 million of non-cash compensation expense for the estimated value of the after-payout interests subject to this arrangement.

8. 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.

The following summarizes information concerning the Company’s net positions in open commodity derivatives applicable to periods subsequent to June 30, 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:
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
	4,022,000					1,254,000

Swaps:

	Gas			Oil
	MMBtu (a)	Price		Bbls	Price
Production Period:
3rd Quarter 2006	—	$	—	75,000	$	71.60
4th Quarter 2006	1,050,000	$	10.03	75,000	$	71.60
2007	5,350,000	$	10.23	600,000	$	72.55
2008	3,660,000	$	9.53	—	$	—
	10,060,000			750,000

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

Subsequent to June 30, 2006, the Company closed certain fixed-price oil swaps covering 300,000 barrels from January 2007 through December 2007 at a price of $80.45 per barrel, resulting in an aggregate loss of approximately $2.4 million.

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 June 30, 2006.

Interest Rate Swaps:

	Principal		Libor
	Balance		Rates
Period:
July 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 six months ended June 30, 2006, the Company reported a $1.3 million loss on derivatives, consisting of a $14.3 million gain related to changes in mark-to-market valuations and a $15.6 million cash charge for settled contracts. For the six months ended June 30, 2005, loss on derivates was $44.9 million, consisting of a $35.2 million non-cash charge related to changes in mark-to-market valuations and a $9.7 million cash charge for settled contracts.

9. 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 June 30, 2006 and December 31, 2005 are set forth below. The associated carrying values at these dates are equal to their estimated fair values.

	June 30,			December 31,
	2006			2005
	(In thousands)
Assets (liabilities):
Commodity derivatives	$	(69,201	)	$	(82,635	)
Interest rate derivatives	427			(422		)
Net assets (liabilities)	$	(68,774	)	$	(83,057	)

10. Income Taxes

In May 2006, the State of Texas adopted House Bill 3, which modified the state’s franchise tax structure, replacing the previous tax based on capital or earned surplus with a margin tax (the “Texas Margin Tax”) effective with franchise tax reports filed on or after January 1, 2008. The Texas Margin Tax is computed by applying the applicable tax rate (1% for the Company’s business sector) to the profit margin, which is generally determined by total revenue less either cost of goods sold or compensation, as applicable. Although House Bill 3 states that the Texas Margin Tax is not an income tax, the Company believes that Statement of Financial Accounting Standards No. 109 “Accounting for Income Taxes” (“SFAS 109”) applies to the Texas Margin Tax. Accordingly, the Company has computed its consolidated deferred tax liability based on its current interpretation of the Texas Margin Tax, resulting in a reduction of deferred tax expense during the quarter ended June 30, 2006 of $4.1 million.

The Company’s effective federal and state income tax rate for the six months ended June 30, 2006 of 18.6% differed from the statutory federal rate of 35% due to reductions in the tax provision related to the adoption of the Texas Margin Tax and statutory depletion, offset in part by certain non-deductible expenses.

11. Commitments

The Company is presently obligated under firm orders for two drilling rigs and related equipment in an aggregate amount of $24 million, of which cash deposits totaling $7.1 million have been paid to certain equipment suppliers as of June 30, 2006. The total cost of the rigs, when completed and fully equipped, will be approximately $27 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.

In addition to the Larclay JV drilling contract discussed in Note 4, the Company has also entered into two long-term drilling contracts with third party drilling contractors and is obligated to make payments under these contracts totaling $13 million in 2006 and $16 million in 2007.

12. Oil and Gas Properties

The following sets forth the capitalized costs for oil and gas properties as of June 30, 2006 and December 31, 2005.

	2006			2005
	(In thousands)
Proved properties	$	1,013,847		$	957,962
Unproved properties	124,871			79,900
Total capitalized costs	1,138,718			1,037,862
Accumulated depreciation, depletion and amortization	(599,529		)	(570,386		)
Net capitalized costs	$	539,189		$	467,476

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 June 30, 2006 and December 31, 2005, the Company had capitalized $16.6 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 six months ended June 30, 2006, $8.1 million was subsequently deemed productive and the remaining $1 million exploratory drilling costs were still pending determination of proved reserves.

13. Guarantor Financial Information

In July 2005, Clayton Williams Energy, Inc. (“Issuer”) issued $225 million of Senior Notes (see Note 5). 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 (see Note 4), has not guaranteed the Senior Notes and is referred to in this Note 13 as a Non-Guarantor Entity.

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

Condensed Consolidating Balance Sheet

June 30, 2006

(Unaudited)

(Dollars in thousands)

					Non-
			Guarantor		Guarantor		Adjustments/
	Issuer		Subsidiaries		Entity		Eliminations			Consolidated

Current assets	$	193,425	$	97,301	$	8,274	$	(194,342	)	$	104,658

Property and equipment, net	271,416		275,532		31,463		(86		)	578,325

Investments in subsidiaries	65,494		—		—		(65,494		)	—

Other assets	28,290		349		606		—			29,245

Total assets	$	558,625	$	373,182	$	40,343	$	(259,922	)	$	712,228

Current liabilities	$	119,822	$	184,517	$	6,192	$	(194,342	)	$	116,189

Non-current liabilities:
Long-term debt	315,400		—		33,030		—			348,430
Fair value of derivatives	974		40,781		—		—			41,755
Other	13,500		49,834		—		561			63,895
	329,874		90,615		33,030		561			454,080

Stockholders’ equity	108,929		98,050		1,122		(66,141		)	141,959
Total liabilities and stockholders’ equity	$	558,625	$	373,182	$	40,343	$	(259,922	)	$	712,228

Condensed Consolidating Balance Sheet

December 31, 2005

(Dollars in thousands)

					Non-
			Guarantor		Guarantor		Adjustments/
	Issuer		Subsidiaries		Entity		Eliminations			Consolidated
					(Unaudited)
Current assets	$	188,007	$	96,327	$	—	$	(195,892	)	$	88,442

Property and equipment, net	195,987		278,080		—		—			474,067

Investments in subsidiaries	65,005		—		—		(65,005		)	—

Other assets	24,491		335		—		—			24,826

Total assets	$	473,490	$	374,742	$	—	$	(260,897	)	$	587,335

Current liabilities	$	126,299	$	193,864	$	—	$	(195,909	)	$	124,254

Non-current liabilities:
Long-term debt	235,700		—		—		—			235,700
Fair value of derivatives	610		49,095		—		—			49,705
Other	8,280		49,105		—		—			57,385
	244,590		98,200		—		—			342,790

Stockholders’ equity	102,601		82,678		—		(64,988		)	120,291
Total liabilities and stockholders’ equity	$	473,490	$	374,742	$	—	$	(260,897	)	$	587,335

Condensed Consolidating Statement of Operations

Three Months Ended June 30, 2006

(Unaudited)

(Dollars in thousands)

							Non-
				Guarantor			Guarantor			Adjustments/
	Issuer			Subsidiaries			Entity			Eliminations			Consolidated

Total revenue	$	42,268		$	28,123		$	747		$	(797	)	$	70,341
Costs and expenses	27,743			17,356			587			(711		)	44,975
Operating income (loss)	14,525			10,767			160			(86		)	25,366

Other income (expense)	531			(4,758		)	(39		)	—			(4,266		)

Income tax expense	(3,094		)	—			—			—			(3,094		)

Minority interest	(40		)	—			—			—			(40		)

Net income (loss)	$	11,922		$	6,009		$	121		$	(86	)	$	17,966

Condensed Consolidating Statement of Operations

Six Months Ended June 30, 2006

(Unaudited)

(Dollars in thousands)

							Non-
				Guarantor			Guarantor			Adjustments/
	Issuer			Subsidiaries			Entity			Eliminations			Consolidated

Total revenue	$	79,282		$	55,156		$	747		$	(1,450	)	$	133,735
Costs and expenses	64,525			34,134			587			(1,364		)	97,882
Operating income (loss)	14,757			21,022			160			(86		)	35,853

Other income (expense)	(3,760		)	(5,760		)	(39		)	—			(9,559		)

Income tax expense	(4,912		)	—			—			—			(4,912		)

Minority interest	(40		)	—			—			—			(40		)

Net income (loss)	$	6,045		$	15,262		$	121		$	(86	)	$	21,342

Condensed Consolidating Statement of Operations

Three Months Ended June 30, 2005

(Unaudited)

(Dollars in thousands)

							Non-
				Guarantor			Guarantor		Adjustments/
	Issuer			Subsidiaries			Entity		Eliminations			Consolidated

Total revenue	$	41,796		$	25,008		$	—	$	(486	)	$	66,318
Costs and expenses	27,084			13,437			—		(486		)	40,035
Operating income (loss)	14,712			11,571			—		—			26,283
Other income (expense)	(3,927		)	(7,826		)	—		—			(11,753		)
Income tax expense	(4,580		)	—			—		—			(4,580		)

Net income (loss)	$	6,205		$	3,745		$	—	$	—		$	9,950

Condensed Consolidating Statement of Operations

Six Months Ended June 30, 2005

(Unaudited)

(Dollars in thousands)

							Non-
				Guarantor			Guarantor		Adjustments/
	Issuer			Subsidiaries			Entity		Eliminations			Consolidated

Total revenue	$	85,544		$	47,465		$	—	$	(1,002	)	$	132,007
Costs and expenses	56,659			26,545			—		(1,002		)	82,202
Operating income (loss)	28,885			20,920			—		—			49,805

Other income (expense)	(7,439		)	(41,323		)	—		—			(48,762		)

Income tax expense	(85		)	—			—		—			(85		)

Net income (loss)	$	21,361		$	(20,403	)	$	—	$	—		$	958

Condensed Consolidating Statement of Cash Flows

Six Months Ended June 30, 2006

(Unaudited)

(Dollars in thousands)

							Non-
				Guarantor			Guarantor			Adjustments/
	Issuer			Subsidiaries			Entity			Eliminations			Consolidated

Operating activities	$	34,485		$	39,977		$	2,514		$	72		$	77,048
Investing activities	(123,978		)	(11,509		)	(31,607		)	428			(166,666		)
Financing activities	92,353			(27,887		)	36,586			(500		)	100,552

Net increase in cash and cash equivalents	2,860			581			7,493			—			10,934

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

Cash at end of the period	$	7,162		$	2,214		$	7,493		$	—		$	16,869

Condensed Consolidating Statement of Cash Flows

Six Months Ended June 30, 2005

(Unaudited)

(Dollars in thousands)

							Non-
				Guarantor			Guarantor		Adjustments/
	Issuer			Subsidiaries			Entity		Eliminations		Consolidated

Operating activities	$	33,103		$	36,179		$	—	$	—	$	69,282
Investing activities	(53,261		)	(24,007		)	—		—		(77,268		)
Financing activities	20,600			(18,296		)	—		—		2,304

Net increase (decrease) in cash and cash equivalents	442			(6,124		)	—		—		(5,682		)

Cash at beginning of the period	2,732			13,627			—		—		16,359

Cash at end of the period	$	3,174		$	7,503		$	—	$	—	$	10,677

14. Subsequent Event

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

$58.1 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 controlled by the Company and the limited partner of which is an affiliate of GE Capital Structured Finance Group. 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.

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 second quarter of 2006 and the outlook for the remainder of 2006.

· We have spent $120.1 million on exploration and development activities during the first six months of 2006, most of which was on exploratory prospects, and we currently plan to spend approximately $213.9 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 $66.7 million at March 31, 2006 to $90.4 million at June 30, 2006 to partially finance our exploration and development activities. Borrowings have increased $79.7 million from levels at December 31, 2005.

· We recorded a $245,000 net gain on derivatives during the second quarter of 2006. Cash settlements to counterparties accounted for a $7.5 million loss offset by a $7.8 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.

· At June 30, 2006, our capitalized unproved oil and gas properties totaled $124.9 million, of which approximately $108 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.

· We formed a joint venture to construct, own and operate 12 new drilling rigs (“Larclay JV”) in April 2006 and included the accounts of Larclay JV in our consolidated financial statements beginning in the second quarter of 2006.

Recent Exploration and Developmental Activities

Overview

As shown in “Liquidity and Capital Resources — Capital Expenditures,” we incurred expenditures for exploration and development activities of $120.1 million during the first six months of 2006. Approximately 40% of these 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.

		Working		Current
Spud Date	Well Name (Prospect)	Interest		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	%	Waiting on production facilities
March 2006	A. J. Beshel #1 (Beshel)	100	%	Waiting on production facilities
April 2006	Cobena #1 (Boa II)	62.5	%	Drilling
May 2006	SL 195 QQ #5 (Floyd)	75	%	Waiting on completion
June 2006	SL 195 QQ #8 (Floyd)	75	%	Waiting on completion

We completed the first four wells on the Floyd prospect in Plaquemines Parish as gas wells. We have drilled and logged two additional wells on the Floyd prospect which we expect to complete once a completion rig becomes available. We presently plan to drill up to 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.

North Louisiana

In May 2006, we began drilling the Atkins Estate #1 (Frazier Creek), an 11,900-foot exploratory well in Claiborne Parish targeting the Cotton Valley/Hosston formations. In July 2006, we began drilling the Roberson N. #1 (Terryville), a 14,500-foot exploratory well in Lincoln Parish also targeting the Cotton

Valley/Hosston formations. In addition, we have participated in 11 non-operated Cotton Valley/Hosston wells in which our working interests have ranged from 3% to 44%. Currently, eight of the wells are producing, one is being completed, one is being drilled, and one was dry.

Other

We have leased approximately 35,000 net acres for our Bossier exploration program in East Texas, and we plan to spud our first Bossier well in East Texas during the fourth quarter 2006.

We are currently drilling the Focus Ranch Federal 12 #1 well, an 8,500-foot exploratory well in Routt County, Colorado targeting the Niobraro formation.

Supplemental Information

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

	Three Months Ended
	June 30,
	2006			2005
Oil and Gas Production Data:
Gas (MMcf)	4,016			4,547
Oil (MBbls)	555			615
Natural gas liquids (MBbls)	50			67
Total (MMcfe)	7,646			8,639

Average Realized Prices (a):
Gas ($/Mcf)	$	6.78		$	6.62
Oil ($/Bbl)	$	66.78		$	50.35
Natural gas liquids ($/Bbl):	$	37.56		$	31.73

Losses on Settled Derivative Contracts (a):
($ in thousands, except per unit)
Gas: Net realized loss	$	(887	)	$	(1,271	)
Per unit produced ($/Mcf)	$	(0.22	)	$	(0.28	)
Oil: Net realized loss	$	(6,700	)	$	(4,763	)
Per unit produced ($/Bbl)	$	(12.07	)	$	(7.74	)

Average Daily Production:
Natural Gas (Mcf):
Permian Basin	15,744			16,063
Louisiana	15,428			14,604
Austin Chalk (Trend)	2,757			2,103
Cotton Valley Reef Complex	9,723			16,618
Other	480			579
Total	44,132			49,967
Oil (Bbls):
Permian Basin	3,274			3,281
Louisiana	933			1,494
Austin Chalk (Trend)	1,833			1,920
Other	59			63
Total	6,099			6,758
Natural Gas Liquids (Bbls):
Permian Basin	227			220
Austin Chalk (Trend)	265			392
Other	57			124
Total	549			736

(Continued)

	Three Months Ended
	June 30,
	2006		2005
Exploration Costs (in thousands):
Abandonment and impairment costs:
Louisiana	$	2,879	$	205
Permian Basin	115		684
Montana	297		—
Mississippi	—		876
Cotton Valley Reef Complex	3		154
South Texas	—		4,511
Other	35		—
Total	3,329		6,430
Seismic and other	2,587		1,665
Total exploration costs	$	5,916	$	8,095

Oil and Gas Costs ($/Mcfe Produced):
Production costs	$	2.08	$	1.60
Oil and gas depletion	$	1.98	$	1.34

Net Wells Drilled (b):
Exploratory Wells	5.2		7.5
Developmental Wells	—		15.9

	Six Months Ended
	June 30,
	2006			2005
Oil and Gas Production Data:
Gas (MMcf)	7,479			9,308
Oil (MBbls)	1,110			1,234
Natural gas liquids (MBbls)	98			133
Total (MMcfe)	14,727			17,510

Average Realized Prices(a):
Gas ($/Mcf)	$	6.99		$	6.41
Oil ($/Bbl)	$	63.41		$	49.08
Natural gas liquids ($/Bbl):	$	38.21		$	29.63

Losses on Settled Derivative Contracts(a):
($in thousands, except per unit)
Gas: Net realized loss	$	(3,065	)	$	(562	)
Per unit produced ($/Mcf)	$	(0.41	)	$	(.06	)
Oil: Net realized loss	$	(12,595	)	$	(8,983	)
Per unit produced ($/Bbl)	$	(11.35	)	$	(7.28	)

(Continued)

	Six Months Ended
	June 30,
	2006		2005
Average Daily Production:
Natural Gas (Mcf):
Permian Basin	14,789		16,110
Louisiana	12,465		14,935
Austin Chalk (Trend)	3,007		2,329
Cotton Valley Reef Complex	10,576		17,312
Other	483		739
Total	41,320		51,425
Oil (Bbls):
Permian Basin	3,244		3,305
Louisiana	1,011		1,485
Austin Chalk (Trend)	1,827		1,976
Other	51		52
Total	6,133		6,818
Natural Gas Liquids (Bbls):
Permian Basin	244		227
Austin Chalk (Trend)	262		365
Other	35		143
Total	541		735
Exploration Costs (in thousands):
Abandonment and impairment costs:
Louisiana	$	10,886	$	1,477
Permian Basin	2,317		975
Montana	2,230		—
Mississippi	679		3,337
Cotton Valley Reef Complex	14		7,400
South Texas	—		4,511
Other	46		—
Total	16,172		17,700
Seismic and other	5,688		2,453
Total exploration costs	$	21,860	$	20,153

Oil and Gas Costs ($/Mcfe Produced):
Production costs	$	2.10	$	1.51
Oil and gas depletion	$	1.98	$	1.32

Net Wells Drilled(b):
Exploratory Wells	12.8		10.8
Developmental Wells	1.7		24.8

(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 June 30, 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 increased 5% from 2005. Oil and gas sales increased $3.1 million, of which price variances accounted for a $10.1 million increase and production variances accounted for a $7 million decrease.

Production in 2006 (on an Mcfe basis) was 11% lower than 2005. Our oil production decreased 10% in 2006 from 2005 due primarily to the loss of production from one well in Louisiana, coupled with normal production declines on other wells. Our gas production decreased 12% in 2006 from 2005 due primarily to production declines in the Cotton Valley Reef Complex area due to formation performance.

In 2006, our realized oil price was 33% higher than 2005, while our realized gas price was 2% higher. Historically, the markets for oil and gas have been volatile, and they are likely to continue to be volatile.

Oil and gas production costs on an Mcfe basis increased from $1.60 per Mcfe in 2005 to $2.08 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 11% 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 increased from $12.3 million in 2005 to $16 million in 2006. DD&A expense attributable to oil and gas properties increased $3.6 million, of which rate variances accounted for a $4.9 million increase and production variances accounted for a $1.3 million decrease. On an Mcfe basis, DD&A expense increased 48% from $1.34 per Mcfe in 2005 to $1.98 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 $3.1 million in 2005 to $4.3 million in 2006 due primarily to higher personnel costs and professional fees derived from the increase in overall drilling and exploration activities. In 2006, we also recorded a $500,000 non-cash compensation charge related to our after payout working interest incentive plan.

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 $5.9 million of exploration costs, as compared to $8.1 million in 2005. Most of these costs were incurred in Louisiana as a result of the abandonment of the Borah #1 (Cypress Isle) and due to seismic costs associated with exploration activities.

We plan to spend approximately $213.9 million on exploration and development activities in fiscal 2006, of which approximately 85% 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.

At June 30, 2006, our capitalized unproved oil and gas properties totaled $124.9 million, of which approximately $108 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.

Interest expense

Interest expense increased from $2.6 million in 2005 to $5 million in 2006 due primarily to higher average levels of indebtedness. The average daily principal balance outstanding under our bank credit facility for 2006 was $80.5 million compared to $191.2 million for 2005. In addition, we issued in July 2005 $225 million of 7¾% Senior Notes due 2013 (the “Senior Notes”) which bear interest at a fixed rate of 7.75%.

Gain/Loss on derivatives

We recorded a net gain on derivatives of $245,000 in 2006 compared to a loss of $9.8 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 $7.5 million in 2006, as compared to $6.1 million in 2005. We recorded a gain on derivatives of $7.8 million in 2006 compared to a loss of $3.7 million in 2005 resulting from mark-to-market valuations.

Operating Results – Six-Month Periods

The following discussion compares our results for the six months ended June 30, 2006 to the comparative period in 2005. Unless otherwise indicated, references to 2006 and 2005 within this section refer to the respective six-month period.

Oil and gas operating results

Oil and gas sales in 2006 increased 1% from 2005. Oil and gas sales increased $1.8 million, of which price variances accounted for a $21.1 million increase and production variances accounted for a $19.3 million decrease.

Production in 2006 (on an Mcfe basis) was 16% lower than 2005. Our oil production decreased 10% in 2006 from 2005 due primarily to the loss of production from one well in Louisiana, coupled with normal production declines on existing wells. Our gas production decreased 20% in 2006 from 2005 due primarily to production declines in the Cotton Valley Reef Complex area due to formation performance.

In 2006, our realized oil price was 29% higher than 2005, while our realized gas price was 9% higher. Historically, the markets for oil and gas have been volatile, and they are likely to continue to be volatile.

Oil and gas production costs on an Mcfe basis increased from $1.51 per Mcfe in 2005 to $2.10 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 16% 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.

DD&A expense attributable to oil and gas properties increased $6 million, of which rate variances accounted for a $9.7 million increase and production variances accounted for a $3.7 million decrease. On

an Mcfe basis, DD&A expense increased 50% from $1.32 per Mcfe in 2005 to $1.98 per Mcfe in 2006. Depletion rates for each depletable group are a function of net capitalized costs and estimated reserve quantities.

G&A expenses increased from $5.7 million in 2005 to $8.3 million in 2006 due to higher personnel costs and professional fees derived from the increase in overall drilling and exploration activities and a $1 million non-cash compensation charge in 2006 related to our after payout working interest incentive plan.

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 $21.9 million of exploration costs, as compared to $20.2 million in 2005. Most of these costs were incurred in Louisiana, the Permian Basin and Montana.

Interest expense

Interest expense increased from $4.9 million in 2005 to $9.3 million in 2006 due primarily to higher average levels of indebtedness. The average daily principal balance outstanding under our bank credit facility for 2006 was $62.1 million compared to $187.2 million for 2005. In addition, we issued in July 2005 $225 million of Senior Notes which bear interest at a fixed rate of 7.75%.

Gain/Loss on derivatives

We recorded a loss on derivatives of $1.3 million in 2006 compared to a loss of $44.9 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 $15.6 million in 2006, as compared to $9.7 million in 2005. We recorded a gain on derivatives of $14.3 million in 2006 compared to a loss of $35.2 million in 2005 resulting from mark-to-market valuations.

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 June 30, 2006, we had $90.4 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 $213.9 million, as summarized by area in the following table.

	Actual		Total
	Expenditures		Planned
	Six Months		Expenditures
	Ended		Year Ended		Percentage
	June 30, 2006		December 31, 2006		of Total
	(In thousands)

North Louisiana	$	23,800	$	48,000	22	%
South Louisiana	53,500		97,800		46	%
East Texas (Bossier)	16,500		21,000		10	%
Permian Basin	17,500		26,600		12	%
Utah/Montana	5,000		8,700		4	%
Austin Chalk (Trend)	2,100		6,400		3	%
Other	1,700		5,400		3	%
	$	120,100	$	213,900	100	%

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 85% 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 $79.7 million under our revolving credit facility during the six months 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 construct, 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 secured term loan to Larclay JV to finance the construction and equipping of the rigs. Pursuant to the term loan, 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 term loan must not exceed 75% of the appraised value of the rigs. If proceeds available to Larclay JV under the term loan 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 term loan. The Larclay JV term loan bears interest at a floating rate based on a LIBOR average, plus 3.25%, and provides for monthly interest payments through March 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 us or to Lariat until the balance on the term loan is fully repaid, and repayments by Larclay JV of any loans by us or by Lariat are subordinated to the loans outstanding under the term loan and are subject to other restrictions.

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 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, excluding crew labor, if any, 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 to utilize specific rigs which we do not expect to use 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 $24 million, of which cash deposits totaling $7.1 million have been paid to certain equipment suppliers as of June 30, 2006. The total cost of the rigs, when completed and fully equipped, will be approximately $27 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.

We have also entered into two drilling contracts with third party drilling contractors and are obligated to make payments under these contracts totaling $13 million in 2006 and $16 million in 2007.

Cash flow provided by operating activities

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

Cash flow provided by operating activities for the six months ended June 30, 2006 was 11% 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 $9.7 million lower in the first half of 2006 as compared to the same period in 2005. However, changes in operating working capital resulted in a net increase in operating cash flow of $18.9 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 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 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. In June 2006, the borrowing base was increased to $200 million. During the six months ended June 30, 2006, we generated cash flow from operating activities of $77 million. We also spent $166.7 million on capital expenditures and other investments and paid $15.5 million to settle derivatives with financing elements. To finance the excess of exploration over cash flow, we borrowed $79.7 million on the revolving credit facility.

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 $11.5 million at June 30, 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 $110.4 million at June 30, 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 June 30, 2006 and December 31, 2005.

	June 30,			December 31,
	2006			2005
	(In thousands)

Working capital (deficit) per GAAP	$	(11,531	)	$	(35,812	)
Add funds available under the revolving credit facility	89,796			138,496
Exclude fair value of derivatives classified as current assets or current liabilities	32,118			33,479
Working capital per loan covenant	$	110,383		$	136,163

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 June 30, 2006, 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. 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. The May 2006 borrowing base review resulted in an increase from $150 million to $200 million which was finalized in June 2006. 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 exploration and development activities. At June 30, 2006, we had $90.4 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 June 30, 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 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, 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.

The following summarizes information concerning our net positions in open commodity derivatives applicable to periods subsequent to June 30, 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:
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
	4,022,000					1,254,000

Swaps:

	Gas			Oil
	MMBtu (a)	Price		Bbls	Price
Production Period:
3rd Quarter 2006	—	$	—	75,000	$	71.60
4th Quarter 2006	1,050,000	$	10.03	75,000	$	71.60
2007	5,350,000	$	10.23	600,000	$	72.55
2008	3,660,000	$	9.53	—	$	—
	10,060,000			750,000

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

Subsequent to June 30, 2006, we closed certain fixed-price oil swaps covering 300,000 barrels at a price of $80.45 per barrel, from January 2007 through December 2007 resulting in an aggregate loss of approximately $2.4 million.

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 $6.2 million.

Interest Rates

We are 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 June 30, 2006.

	Principal		Libor
	Balance		Rates
Period:
July 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	%

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

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 June 30, 2006 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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 4 - Submission of Matters to a Vote of Securities Holders

On May 10, 2006, we held our Annual Meeting of Stockholders to (a) elect three directors to the Board of Directors for a term of three years, and (b) advise on the selection of KPMG LLP as our independent auditors for 2006. At such meeting, Stanley S. Beard and Mel G. Riggs were reelected as directors, and stockholders advised that KPMG LLP should be selected as our independent auditors for 2006.

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

Results of Voting	Votes For	Withheld
1. Election of Directors
Stanley S. Beard	8,807,813	509,149
Mel G. Riggs	8,810,790	506,172

		Votes For		Withheld		Abstentions
2. Advisory vote on the selection of KPMG LLP		9,258,059		27,130		31,773

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**		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††

10.2**		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††

10.3**		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††

10.4**		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††

10.5**		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††

10.6**		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††

10.7**		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††

10.8**†		Agreement of Limited Partnership of Floyd Prospect II, L.P., dated May 15, 2006, filed as Exhibit 10.1 to our Current Report on Form 8-K filed with the Commission on May 17, 2006††

10.9**		Third Amendment to Amended and Restated Credit Agreement,, dated June 30, 2006, filed as Exhibit 10.1 to our Current Report on Form 8-K filed with the Commission on July 14, 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*		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:	August 8, 2006	By:	/s/ L. Paul Latham
			L. Paul Latham
			Executive Vice President and Chief
			Operating Officer


Date:	August 8, 2006	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-Q2006 Q2 Quarterly report

Content analysis

WASHINGTON, D.C. 20549

FORM 10-Q

For the quarterly period ended June 30, 2006

Commission File No. 001-10924

Commodity Derivatives

Disclosure Controls and Procedures

Changes in Internal Control Over Financial Reporting

Exhibits