CLAYTON WILLIAMS ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(Dollars in thousands)

ASSETS

	September 30,			December 31,
	2006			2005
	(Unaudited)
CURRENT ASSETS
Cash and cash equivalents	$	8,746		$	5,935
Accounts receivable:
Oil and gas sales, net	24,616			28,317
Joint interest and other, net	9,359			6,972
Affiliates	1,452			254
Inventory	41,308			43,753
Deferred income taxes	426			439
Fair value of derivatives	16,314			191
Prepaids and other	1,840			2,581
	104,061			88,442
PROPERTY AND EQUIPMENT
Oil and gas properties, successful efforts method	1,188,416			1,037,862
Natural gas gathering and processing systems	18,049			18,034
Contract drilling equipment	47,855			—
Other	15,369			12,396
	1,269,689			1,068,292
Less accumulated depreciation, depletion and amortization	(655,726		)	(594,225		)
Property and equipment, net	613,963			474,067

OTHER ASSETS
Debt issue costs	7,992			8,557
Advances to drilling rig joint venture	—			10,329
Fair value of derivatives	2,673			127
Other	14,229			5,813
	24,894			24,826
	$	742,918		$	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

	September 30,		December 31,
	2006		2005
	(Unaudited)
CURRENT LIABILITIES
Accounts payable:
Trade	$	69,935	$	59,861
Oil and gas sales	14,528		18,236
Affiliates	3,319		2,857
Current maturities of long-term debt	8,011		19
Fair value of derivatives	29,630		33,670
Accrued liabilities and other	5,650		9,611
	131,073		124,254
NON-CURRENT LIABILITIES
Long-term debt	367,157		235,700
Deferred income taxes	44,782		37,042
Fair value of derivatives	29,730		49,705
Other	22,868		20,343
	464,537		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	38,792		12,101
	147,308		120,291
	$	742,918	$	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 September 30,						Nine Months Ended September 30,
	2006			2005			2006			2005
REVENUES
Oil and gas sales	$	61,519		$	65,739		$	188,143		$	190,536
Natural gas services	2,905			2,572			8,890			7,703
Drilling rig services	1,801			—			2,175			—
Gain on sales of property and equipment	164			16,832			916			18,911
Total revenues	66,389			85,143			200,124			217,150

COSTS AND EXPENSES
Production	16,467			16,981			47,363			43,408
Exploration:
Abandonments and impairments	19,650			13,863			35,822			31,563
Seismic and other	3,678			5,123			9,366			7,576
Natural gas services	2,730			2,450			7,820			7,241
Drilling rig services	1,157			—			1,373			—
Depreciation, depletion and amortization	17,686			11,568			48,378			36,148
Impairment of proved properties	12,914			—			12,914			—
Accretion of abandonment obligations	428			291			1,224			858
General and administrative	3,086			5,483			11,405			11,135
Loss on sales of property and equipment	69			100			82			132
Total costs and expenses	77,865			55,859			175,747			138,061
Operating income (loss)	(11,476		)	29,284			24,377			79,089
OTHER INCOME (EXPENSE)
Interest expense	(5,328		)	(5,503		)	(14,628		)	(10,435		)
Gain (loss) on derivatives	26,734			(28,766		)	25,407			(73,692		)
Other	(1,583		)	1,317			(515		)	2,413
Total other income (expense)	19,823			(32,952		)	10,264			(81,714		)
Income (loss) before income taxes	8,347			(3,668		)	34,641			(2,625		)
Income tax (expense) benefit	(2,842		)	1,628			(7,754		)	1,543
Minority interest, net of tax	(156		)	—			(196		)	—
NET INCOME (LOSS)	$	5,349		$	(2,040	)	$	26,691		$	(1,082	)
Net income (loss) per common share:
Basic	$	0.49		$	(0.19	)	$	2.46		$	(0.10	)
Diluted	$	0.48		$	(0.19	)	$	2.38		$	(0.10	)

Weighted average common shares outstanding:
Basic	10,850			10,810			10,847			10,800
Diluted	11,205			10,810			11,220			10,800

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	—	—		—		26,691
Issuance of stock through compensation plans	35	3		323		—
BALANCE,
September 30, 2006	10,850	$	1,085	$	107,431	$	38,792

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

CLAYTON WILLIAMS ENERGY, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
(In thousands)

	Nine Months Ended September 30,
	2006			2005
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	26,691		$	(1,082	)
Adjustments to reconcile net income (loss) to cash provided by operating activities:
Depreciation, depletion and amortization	48,378			36,148
Impairment of proved properties	12,914			—
Exploration costs	35,822			31,563
Accretion of abandonment obligations	1,224			858
Gain on sales of property and equipment, net	(834		)	(18,779		)
Deferred income taxes	7,754			(1,465		)
Non-cash employee compensation	1,651			2,468
Unrealized (gain) loss on derivatives	(42,684		)	56,067
Settlements on derivatives with financing elements	23,311			17,428
Amortization of debt issue costs	1,022			2,631
Minority interest, net of tax	196			—

Changes in operating working capital:
Accounts receivable	116			(3,474		)
Accounts payable	3,073			3,301
Other	(2,152		)	967
Net cash provided by operating activities	116,482			126,631

CASH FLOWS FROM INVESTING ACTIVITIES
Additions to property and equipment	(188,606		)	(126,788		)
Additions to equipment of Larclay JV	(46,126		)	—
Proceeds from sales of property and equipment	1,083			23,252
Other	3,665			(11,336		)
Net cash used in investing activities	(229,984		)	(114,872		)

CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt	93,700			225,000
Proceeds from long-term debt of Larclay JV	45,761			—
Repayments of other long-term debt	(12		)	(177,500		)
Proceeds from sale of common stock	175			288
Payment of debt issue costs	—			(7,964		)
Settlements on derivatives with financing elements	(23,311		)	(17,428		)
Net cash provided by financing activities	116,313			22,396

NET INCREASE IN CASH AND CASH EQUIVALENTS	2,811			34,155

CASH AND CASH EQUIVALENTS
Beginning of period	5,935			16,359
End of period	$	8,746		$	50,514

SUPPLEMENTAL DISCLOSURES
Cash paid for interest, net of amounts capitalized	$	17,996		$	5,138

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

CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
September 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 significant 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 September 30, 2006 and for the interim periods ended September 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

In September 2006, the Securities and Exchange Commission issued Staff Accounting Bulletin No. 108 (“SAB 108”), which becomes effective beginning on January 1, 2007. SAB 108 provides guidance on the consideration of the effects of prior period misstatements in quantifying current year misstatements for the purpose of a materiality assessment. SAB 108 requires an entity to evaluate the impact of correcting all misstatements, including both the carryover and reversing effects of prior year misstatements, on current year financial statements. If a misstatement is material to the current year financial statements, the prior year financial statements should also be corrected, even though such revision was, and continues to be, immaterial to the prior year financial statements. Correcting prior year financial statements for immaterial errors would not require previously filed reports to be amended. Such correction should be made in the current period filings. We are currently evaluating the impact, if any, of adopting SAB 108.

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

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 has continued 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. Investments

West Coast Energy Properties, L.P.

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

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

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

Larclay JV

In April 2006, the Company formed a joint venture (“Larclay JV”) with Lariat Services, Inc. (“Lariat”) to construct, own and operate 12 new drilling rigs. The Company and Lariat each own a 50% interest in Larclay JV. The rigs are being constructed on behalf of Larclay JV by Lariat, as operations manager. 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 is to 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 commitment under this drilling contract, excluding crew labor, if any, aggregates $112 million. Four rigs

are currently operational, of which two are working for the Company and two are working for other operators.

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 September 30, 2006, Lariat’s equity ownership in the net assets of Larclay JV was $696,000, which is recorded as minority interest and included in other non-current liabilities in the accompanying consolidated financial statements. The Company’s intercompany accounts with Larclay JV have been eliminated in consolidation.

5. Long-Term Debt

Long-term debt consists of the following:

	September 30,			December 31,
	2006			2005
	(In thousands)
73¤4% Senior Notes due 2013	$	225,000		$	225,000
Secured bank credit facility, due May 2009	104,400			10,700
Secured term loan of Larclay JV	45,766			—
Other	2			19
	375,168			235,719
Less current maturities(a)	(8,011		)	(19		)
	$	367,157		$	235,700

(a) Includes current portion of term loan of Larclay JV of $8,009 at September 30, 2006.

73¤4% Senior Notes due 2013

In July 2005, the Company issued, in a private placement, $225 million of aggregate principal amount of 73¤4% Senior Notes due 2013 (“Senior Notes”). The Senior Notes were issued at face value and bear interest at 73¤4% 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 September 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. At September 30, 2006, the borrowing base established by the banks was $200 million, with no monthly commitment reductions. After allowing for outstanding letters of credit totaling $19.8 million, the Company had $75.8 million available under the credit facility at September 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 nine months ended September 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 September 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 is to 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 September 30, 2006, the effective interest rate on the Larclay JV term loan was 8.5%. Larclay JV capitalized $1.1 million 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:

	September 30,		December 31,
	2006		2005
	(In thousands)
Abandonment obligations	$	21,293	$	19,447
Minority interest, net of tax	696		—
Other	879		896
	$	22,868	$	20,343

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

	Nine Months Ended
	September 30,
	2006			2005
	(In thousands)
Beginning of period	$	19,447		$	16,147
Additional abandonment obligations from new wells	834			492
Sales or abandonments of properties	(195		)	(507		)
Revisions of previous estimates	(17		)	27
Accretion expense	1,224			858
End of period	$	21,293		$	17,017

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 1, 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 nine months ended September 30, 2005 was $2.1 million.

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 September 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 nine months ended September 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 September 30, 2006	1,311,985		$	19.98	5.3	$	13,533,159
Vested at September 30, 2006	1,311,985		$	19.98	5.3	$	13,533,159
Exercisable at September 30, 2006	1,311,985		$	19.98	5.3	$	13,533,159

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 nine months ended September 30, 2005 is as follows:

	Nine Months
	Ended
	September 30, 2005
	(In thousands, except per share)
Net loss, as reported	$	(1,082	)
Add: Stock-based employee compensation expense included in net loss, net of tax	1,384
Deduct: Stock-based employee compensation expense determined under fair value based method (SFAS 123R), net of tax	(2,920		)
Net loss, pro forma	$	(2,618	)

Basic:
Net loss per common share, as reported	$	(.10	)
Net loss per common share, pro forma	$	(.24	)

Diluted:
Net loss per common share, as reported	$	(.10	)
Net loss per common share, pro forma	$	(.24	)

After-Payout Incentive Plan

The Compensation Committee of the Board of Directors has adopted an incentive plan for officers, key employees and consultants, excluding Mr. Williams, who promote the Company’s drilling and acquisition programs. Management’s objective in adopting this plan is to further align the interests of the participants with those of the Company by granting the participants an after-payout interest in the production developed, directly or indirectly, by the participants. The plan generally provides for the creation of a series of partnerships between the Company and the participants to which the Company contributes a portion of its economic interest in wells drilled or acquired within certain areas. Generally, the Company pays all costs and receives all revenues until payout of its costs, plus interest. At payout, the participants receive 99% to 100% of all subsequent revenues and pay 99% to 100% of all subsequent expenses attributable to the partnerships’ interests.

Between 3% and 7.5% of the Company’s economic interests in specified wells drilled or acquired by the Company subsequent to October 2002 are subject to this arrangement (excluding properties acquired in a merger with Southwest Royalties, Inc. in May 2004). The Company records its allocable share of the assets, liabilities, revenues, expenses and oil and gas reserves of these partnerships in its consolidated financial statements. To date, two of these partnerships have achieved payout. Aggregate cash distributions of approximately $598,000 were paid to the participants during the nine months ended September 30, 2006. The Company recognized $1.5 million of non-cash compensation expense during the nine months ended September 30, 2006 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. Commodity derivatives are settled monthly as the contract production periods mature.

The following summarizes information concerning the Company’s net positions in open commodity derivatives applicable to periods subsequent to September 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:
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
	3,566,000					1,104,000

Swaps:

	Gas			Oil
	MMBtu (a)	Price		Bbls	Price
Production Period:
4th Quarter 2006	1,050,000	$	10.03	75,000	$	71.60
2007	5,100,000	$	9.20	900,000	$	70.06
2008	3,600,000	$	8.37	360,000	$	69.55
	9,750,000			1,335,000

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

In August 2006, the Company terminated certain fixed-price gas swaps covering 9,010,000 MMBtu of gas production at an average price of $9.26 per Mcf for the period from November 2006 through December 2007. The Company received cash proceeds of $6.1 million upon termination of these contracts.

In July 2006, the Company also terminated 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, which will be paid to the counterparty monthly during 2007.

Interest Rate Derivatives

The Company is a party to interest rate swaps that were acquired in connection with the acquisition of Southwest Royalties, Inc. in May 2004. Under these derivatives, the Company pays a fixed rate for the notional principal balances and receives a floating market rate based on LIBOR. The interest rate swaps are settled quarterly. The following summarizes information concerning the Company’s net positions in open interest rate swaps applicable to periods subsequent to September 30, 2006.

Interest Rate Swaps:

	Principal		Fixed Libor
	Balance		Rates
Period:
October 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 nine months ended September 30, 2006, the Company reported a $25.4 million gain on derivatives, consisting of a $42.7 million gain related to changes in mark-to-market valuations and a $17.3 million cash charge for settled contracts. For the nine months ended September 30, 2005, loss on derivates was $28.8 million, consisting of a $20.8 million non-cash charge related to changes in mark-to-market valuations and an $8 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. The fair value of other noncurrent liabilities approximate their carrying value.

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

	September 30,			December 31,
	2006			2005
	(In thousands)
Assets (liabilities):
Commodity derivatives	$	(40,028	)	$	(82,635	)
Interest rate derivatives	(345		)	(422		)
Net assets (liabilities)	$	(40,373	)	$	(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 nine months ended September 30, 2006 of 22.4% 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 $24.5 million, of which cash deposits totaling $8.1 million have been paid to certain equipment suppliers as of September 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 three long-term drilling contracts with third party drilling contractors and is obligated to make payments under these contracts totaling $11 million in the fourth quarter of 2006 and $25 million in 2007.

12. Oil and Gas Properties

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

	September 30, 2006			December 31, 2005
	(In thousands)
Proved properties	$	1,037,610		$	957,962
Unproved properties	150,806			79,900
Total capitalized costs	1,188,416			1,037,862
Accumulated depreciation, depletion and amortization	(629,083		)	(570,386		)
Net capitalized costs	$	559,333		$	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 September 30, 2006 and December 31, 2005, the Company had capitalized $31.9 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 nine months ended September 30, 2006 and the remaining $9.1 million was subsequently deemed productive.

During the quarter ended September 30, 2006, the Company recorded a provision for impairment of proved properties of $12.9 million under Statement of Financial Accounting Standards No. 144 “Accounting for Impairment or Disposal of Long-Lived Assets” (“SFAS 144”) due to the combination of production performance and lower commodity prices. The provision was attributable to two areas in West Texas and one area in South Louisiana.

13. Guarantor Financial Information

In July 2005, Clayton Williams Energy, Inc. (“Issuer”) issued $225 million of Senior Notes (see Note 5). Other than West Coast Energy Properties GP, LLC (“WCEP LLC”), the general partner of WCEP (see Note 4), all of the Issuer’s wholly-owned and active subsidiaries (“Guarantor Subsidiaries”) have jointly and severally, irrevocably and unconditionally guaranteed the performance and payment when due of all obligations under the Senior Notes. Larclay JV, a 50%-owned drilling rig joint venture formed in April 2006, and WCEP, LLC have not guaranteed the Senior Notes and are referred to in this Note 13 as Non-Guarantor Entities.

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

Condensed Consolidating Balance Sheet
September 30, 2006

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

Current assets	$	146,450	$	96,432	$	5,276	$	(144,097	)	$	104,061

Property and equipment, net	287,297		273,369		53,745		(448		)	613,963

Investments in subsidiaries	65,393		—		—		(65,393		)	—

Other assets	23,803		371		720		—			24,894

Total assets	$	522,943	$	370,172	$	59,741	$	(209,938	)	$	742,918


Current liabilities	$	86,594	$	168,320	$	20,256	$	(144,097	)	$	131,073

Non-current liabilities:
Long-term debt	329,400		—		37,757		—			367,157
Fair value of derivatives	1,212		28,518		—		—			29,730
Other	16,851		50,003		100		696			67,650
	347,463		78,521		37,857		696			464,537

Stockholders’ equity	88,886		123,331		1,628		(66,537		)	147,308
Total liabilities and stockholders’ equity	$	522,943	$	370,172	$	59,741	$	(209,938	)	$	742,918

Condensed Consolidating Balance Sheet
December 31, 2005
(Unaudited
(Dollars in thousands)

	Issuer		Guarantor Subsidiaries		Non-Guarantor Entities		Adjustments/ Eliminations			Consolidated

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 September 30, 2006
(Unaudited)
(Dollars in thousands)

	Issuer			Guarantor Subsidiaries		Non-Guarantor Entities			Adjustments/ Eliminations			Consolidated

Total revenue	$	37,055		$	27,844	$	3,491		$	(2,001	)	$	66,389
Costs and expenses	59,448			17,246		2,810			(1,639		)	77,865
Operating income (loss)	(22,393		)	10,598		681			(362		)	(11,476		)

Other income (expense)	7,192			12,804		(173		)	—			19,823

Income tax expense	(2,842		)	—		—			—			(2,842		)

Minority interest, net of tax	(156		)	—		—			—			(156		)

Net income (loss)	$	(18,199	)	$	23,402	$	508		$	(362	)	$	5,349

Condensed Consolidating Statement of Operations
Nine Months Ended September 30, 2006
(Unaudited)
(Dollars in thousands)

	Issuer			Guarantor Subsidiaries		Non-Guarantor Entities			Adjustments/ Eliminations			Consolidated

Total revenue	$	116,337		$	83,000	$	4,238		$	(3,451	)	$	200,124
Costs and expenses	123,973			51,380		3,397			(3,003		)	175,747
Operating income (loss)	(7,636		)	31,620		841			(448		)	24,377

Other income (expense)	3,432			7,044		(212		)	—			10,264

Income tax expense	(7,754		)	—		—			—			(7,754		)

Minority interest, net of tax	(196		)	—		—			—			(196		)

Net income (loss)	$	(12,154	)	$	38,664	$	629		$	(448	)	$	26,691

Condensed Consolidating Statement of Operations
Three Months Ended September 30, 2005
(Unaudited)
(Dollars in thousands)

	Issuer			Guarantor Subsidiaries			Non-Guarantor Entities		Adjustments/ Eliminations			Consolidated

Total revenue	$	55,165		$	30,204		$	—	$	(226	)	$	85,143
Costs and expenses	39,178			16,907			—		(226		)	55,859
Operating income (loss)	15,987			13,297			—		—			29,284

Other income (expense)	(4,972		)	(27,980		)	—		—			(32,952		)

Income tax expense	1,628			—			—		—			1,628

Net income (loss)	$	12,643		$	(14,683	)	$	—	$	—		$	(2,040	)

Condensed Consolidating Statement of Operations
Nine Months Ended September 30, 2005
(Unaudited)
(Dollars in thousands)

	Issuer			Guarantor Subsidiaries			Non-Guarantor Entities		Adjustments/ Eliminations			Consolidated

Total revenue	$	140,709		$	77,669		$	—	$	(1,228	)	$	217,150
Costs and expenses	95,837			43,452			—		(1,228		)	138,061
Operating income (loss)	44,872			34,217			—		—			79,089

Other income (expense)	(12,411		)	(69,303		)	—		—			(81,714		)

Income tax expense	1,543			—			—		—			1,543

Net income (loss)	$	34,004		$	(35,086	)	$	—	$	—		$	(1,082	)

Condensed Consolidating Statement of Cash Flows
Nine Months Ended September 30, 2006
(Unaudited)
Dollars in thousands)

	Issuer			Guarantor Subsidiaries			Non-Guarantor Entities			Adjustments/ Eliminations			Consolidated

Operating activities	$	49,841		$	61,907		$	4,446		$	288		$	116,482
Investing activities	(160,497		)	(15,387		)	(54,312		)	212			(229,984		)
Financing activities	110,952			(47,101		)	52,962			(500		)	116,313

Net increase (decrease) in cash and cash equivalents	296			(581		)	3,096			—			2,811


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

Cash at end of the period	$	4,598		$	1,052		$	3,096		$	—		$	8,746

Condensed Consolidating Statement of Cash Flows
Nine Months Ended September 30, 2005
(Unaudited)
(Dollars in thousands)

	Issuer			Guarantor Subsidiaries			Non-Guarantor Entities		Adjustments/ Eliminations		Consolidated

Operating activities	$	93,442		$	33,189		$	—	$	—	$	126,631
Investing activities	(79,141		)	(35,731		)	—		—		(114,872		)
Financing activities	31,455			(9,059		)	—		—		22,396

Net increase (decrease) in cash and cash equivalents	45,756			(11,601		)	—		—		34,155

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

Cash at end of the period	$	48,488		$	2,026		$	—	$	—	$	50,514

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

· We have spent $183.4 million on exploration and development activities during the first nine months of 2006, most of which was on exploratory prospects, and we currently plan to spend approximately $244.3 million for the calendar 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 $90.4 million at June 30, 2006 to $104.4 million at September 30, 2006 to partially finance our exploration and development activities. Borrowings have increased $93.7 million from levels at December 31, 2005.

· Despite our high level of capital spending in 2006, our average daily oil and gas production for the third quarter of 2006 was 3% lower on an Mcfe basis than the corresponding period in 2005. A significant portion of these expenditures have not resulted in current production because they relate to (i) unproved exploratory prospects, (ii) drilling or completion activities that are in progress, or (iii) non-productive drilling.

· At September 30, 2006, our capitalized unproved oil and gas properties totaled $150.8 million, of which approximately $100.7 million was attributable to unproved

acreage. Unproved properties are subject to a valuation impairment to the extent the carrying cost of a prospect exceeds its estimated fair value. Therefore, our results of operations in future periods may be adversely affected by unproved property impairments.

· Exploration costs related to abandonments and impairments were $19.7 million during the third quarter of 2006, of which $8.1 million was attributable to the Apache Louisiana Minerals 73-1 (Abigail) in South Louisiana, $5.9 million was due to two exploratory wells on the Focus Ranch unit in Colorado, $2.9 million was due to acreage impairments in West Texas and $2.1 million was attributable to the Weyerhaeuser #1 (Frazier Creek) in North Louisiana.

· We recorded a $26.7 million net gain on derivatives during the third quarter of 2006. Cash settlements to counterparties accounted for a $1.7 million loss and changes in mark-to-market valuations accounted for a $28.4 million gain. Since we do not presently designate our derivatives as cash flow hedges under applicable accounting standards, we recognize the full effect of changing prices on mark-to-market valuations as a current charge or credit to our results of operations.

· We recorded a $12.9 million impairment of proved properties during the third quarter of 2006 due to the combined effects of lower commodity prices and lower reserve estimates. The impairment applied to two areas within West Texas and one area in South Louisiana.

Recent Exploration and Developmental Activities

Overview

As shown in “Liquidity and Capital Resources — Capital Expenditures,” we incurred expenditures for exploration and development activities of $183.4 million during the first nine months of 2006. Approximately 70% 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	%	Producing
February 2006	SL 195 QQ #3 (Floyd)	75	%	Producing
March 2006	SL 195 QQ #4 (Floyd)	72	%	Waiting on pipeline
March 2006	A. J. Beshel #1 (Beshel)	100	%	Waiting on production facilities
April 2006	Cobena #1 (Boa II)	62.5	%	Waiting on completion
May 2006	SL 195 QQ #5 (Floyd)	75	%	Producing
June 2006	SL 195 QQ #8 (Floyd)	70	%	Waiting on pipeline
August 2006	SL 195 QQ #6 (Floyd)	75	%	Waiting on pipeline
October 2006	SL 195 QQ #11 (Floyd)	72	%	Waiting on completion
November 2006	Kyle Peterman Mgt #30-1 (Pigeon)	100	%	Drilling
November2006	Luke Harvey #1 (Beshal Shallow)	100	%	Drilling

We have completed seven productive wells on our Floyd prospect in Plaquemines Parish. Four of the wells are currently producing at combined rates of 290 barrels of oil per day and 16,100 Mcf of gas per day. The remaining wells are expected to begin production during the fourth quarter of 2006 at combined rates of approximately 650 barrels of oil per day and 6,000 Mcf of gas per day, based on available well test data. One additional well is waiting on completion, and we may drill up to four additional wells on this prospect, depending on a performance evaluation of existing wells. Under the terms of a farmout agreement, we bear 100% of the cost of wells on this prospect to casing point and earn up to a 75% working interest in the drilled acreage.

We have drilled and logged the Cobena #1 (Boa II), a 15,250-foot exploratory well in Acadia Parish, and have encountered multiple pay zones with encouraging gas shows. We bear 50% of the cost of this well to casing point and 62.5% thereafter. To date, we have incurred approximately $8 million in drilling and completion costs, net to our interest.

We drilled and abandoned the Apache Louisiana Minerals 73-1 (Abigail), a 14,200-foot exploratory well in Terrebonne Parish after determining that the well was nonproductive. We recorded a pre-tax charge of $8.1 million related to the abandonment of this well in the third quarter of 2006 and will record an additional pre-tax charge of approximately $3.2 million in the fourth quarter of 2006.

North Louisiana

We have drilled two exploratory wells on our Frazier Creek prospect in Claiborne Parish targeting the Hosston/Cotton Valley formations. The Atkins Estate #1 was completed as a marginal producer and the Weyerhaeuser #1 was not productive. We recorded a pre-tax charge of $2.1 million related to the abandonment of the Weyerhaeuser well in the third quarter of 2006 and will record an additional pre-tax charge of approximately $1 million in the fourth quarter of 2006. We own a 100% working interest in both wells on this prospect.

On our Terryville prospect in Lincoln Parish, we have drilled and logged the Roberson #1 well and have encountered encouraging gas shows in two Cotton Valley sand intervals. Completion operations on this exploratory well are expected to begin in November pending the availability of a completion rig. In addition, we are currently drilling the Donald Woodard #1 on this prospect. We will own between 71% and 100% of the working interests in these wells, depending on participation elections by other owners.

In addition, we have begun drilling operations on the P. Benoit #1, the first exploratory well on our Serapta prospect in Webster Parish targeting the Hosston/Cotton Valley formations.

We have delayed the start of our Bossier exploration program in North Louisiana until the first quarter of 2007 due to rig scheduling. To date, we have leased approximately 165,000 net acres in this area for potential Bossier drilling activities.

Other

We have also delayed the start of our East Texas Bossier exploration program until the first quarter of 2007 due to rig scheduling. To date, we have leased approximately 47,000 net acres in this area for potential Bossier drilling activities.

We have drilled two wells in Routt County, Colorado targeting the Niobraro formation at a depth of approximately 8,500 feet. The Focus Ranch Federal 12 #1 and the Focus Ranch Federal 3-1 have been temporarily abandoned. As a result, we recorded a pre-tax charge of $5.9 million related to the

abandonments in the third quarter of 2006 and will record an additional pre-tax charge of approximately $1.4 million in the fourth quarter of 2006. We own a 100% working interest in both wells on this prospect.

Supplemental Information

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

	Three Months Ended
	September 30,
	2006			2005
Oil and Gas Production Data:
Gas (MMcf)	3,738			3,897
Oil (MBbls)	532			537
Natural gas liquids (MBbls)	51			52
Total (MMcfe)	7,236			7,431
Average Realized Prices (a):
Gas ($/Mcf)	$	6.26		$	7.98
Oil ($/Bbl)	$	67.27		$	59.95
Natural gas liquids ($/Bbl):	$	43.79		$	37.00
Gain (Losses) on Settled Derivative Contracts (a):
($in thousands, except per unit)
Gas: Net realized gain (loss)	$	5,543		$	(2,023	)
Per unit produced ($/Mcf)	$	1.48		$	(0.52	)
Oil: Net realized loss	$	(7,328	)	$	(5,935	)
Per unit produced ($/Bbl)	$	(13.77	)	$	(11.05	)
Average Daily Production:
Natural Gas (Mcf):
Permian Basin	13,804			17,300
Louisiana	15,059			8,528
Austin Chalk (Trend)	2,102			2,672
Cotton Valley Reef Complex	9,083			13,336
Other	582			523
Total	40,630			42,359
Oil (Bbls):
Permian Basin	3,102			3,131
Louisiana	899			809
Austin Chalk (Trend)	1,719			1,839
Other	63			58
Total	5,783			5,837
Natural Gas Liquids (Bbls):
Permian Basin	230			261
Austin Chalk (Trend)	260			220
Other	64			84
Total	554			565

(Continued)

	Three Months Ended
	September 30,
	2006		2005
Exploration Costs (in thousands):
Abandonment and impairment costs:
Louisiana	$	10,863	$	9,434
Permian Basin	2,850		72
Colorado	5,924		—
Mississippi	—		915
Cotton Valley Reef Complex	13		5
Other	—		3,437
Total	19,650		13,863
Seismic and other	3,678		5,123
Total exploration costs	$	23,328	$	18,986
Oil and Gas Costs ($/Mcfe Produced):
Production costs	$	2.28	$	2.29
Oil and gas depletion	$	2.30	$	1.46
Net Wells Drilled (b):
Exploratory Wells	9.1		3.7
Developmental Wells	—		6.0

	Nine Months Ended
	September 30,
	2006			2005
Oil and Gas Production Data:
Gas (MMcf)	11,217			13,205
Oil (MBbls)	1,642			1,771
Natural gas liquids (MBbls)	151			185
Total (MMcfe)	21,975			24,941
Average Realized Prices(a):
Gas ($/Mcf)	$	6.74		$	6.88
Oil ($/Bbl)	$	64.70		$	52.39
Natural gas liquids ($/Bbl):	$	40.15		$	31.70
Gain (Losses) on Settled Derivative Contracts(a):
($in thousands, except per unit)
Gas: Net realized gain (loss)	$	2,478		$	(2,585	)
Per unit produced ($/Mcf)	$	.22		$	(.20	)
Oil: Net realized loss	$	(19,923	)	$	(14,918	)
Per unit produced ($/Bbl)	$	(12.13	)	$	(8.42	)

(Continued)

	Nine Months Ended
	September 30,
	2006		2005
Average Daily Production:
Natural Gas (Mcf):
Permian Basin	14,455		16,512
Louisiana	13,339		12,777
Austin Chalk (Trend)	2,704		2,443
Cotton Valley Reef Complex	10,073		15,972
Other	517		666
Total	41,088		48,370
Oil (Bbls):
Permian Basin	3,196		3,248
Louisiana	975		1,258
Austin Chalk (Trend)	1,789		1,927
Other	55		54
Total	6,015		6,487
Natural Gas Liquids (Bbls):
Permian Basin	238		238
Austin Chalk (Trend)	271		316
Other	44		124
Total	553		678
Exploration Costs (in thousands):
Abandonment and impairment costs:
Louisiana	$	21,749	$	10,911
Permian Basin	5,167		1,042
Colorado	5,924		—
Montana	2,230		—
Mississippi	679		4,262
Cotton Valley Reef Complex	27		7,405
Other	46		7,943
Total	35,822		31,563
Seismic and other	9,366		7,576
Total exploration costs	$	45,188	$	39,139
Oil and Gas Costs ($/Mcfe Produced):
Production costs	$	2.16	$	1.74
Oil and gas depletion	$	2.08	$	1.36
Net Wells Drilled(b):
Exploratory Wells	21.9		11.3
Developmental Wells	1.7		21.9

(a) No derivatives were designated as cash flow hedges in 2006 or 2005. All gains or losses on settled derivatives were included in loss on derivatives.

(b) Excludes wells being drilled or completed at the end of each period.

Operating Results — Three-Month Periods

The following discussion compares our results for the three months ended September 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 decreased $4.2 million, or 6%, from 2005, of which price variances accounted for a $2.2 million decrease and production variances accounted for a $2 million decrease.

Production in 2006 (on an Mcfe basis) was 3% lower than 2005. Oil production decreased 1% in 2006 from 2005 due primarily to normal production declines, offset in part by higher production from new wells in Louisiana. Gas production decreased 4% in 2006 from 2005 due primarily to higher than normal production declines in the Permian Basin and Cotton Valley Reef Complex area caused by well performance.

In 2006, our realized oil price was 12% higher than 2005, while our realized gas price was 22% lower. 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 decreased from $2.29 per Mcfe in 2005 to $2.28 per Mcfe in 2006. Production costs, consisting of lease operating expenses, production taxes and other miscellaneous marketing costs, declined 3% in 2006 as compared to 2005 due primarily to reduced workover activities and lower production taxes. After giving effect to a 3% decline in oil and gas production on an Mcfe basis, production costs per Mcfe changed only slightly.

Depreciation, depletion, and amortization (“DD&A”) expense increased from $11.6 million in 2005 to $17.7 million in 2006. DD&A expense attributable to oil and gas properties increased $5.8 million, of which rate variances accounted for a $6.1 million increase and production variances accounted for a $300,000 decrease. On an Mcfe basis, DD&A expense increased 58% from $1.46 per Mcfe in 2005 to $2.30 per Mcfe in 2006. Depletion rates for each depletable group are a function of net capitalized costs and estimated reserve quantities.

We recorded a provision for impairment of proved properties under SFAS 144 of $12.9 million during the third quarter of 2006 due to the combination of production performance and lower commodity prices. This provision was attributable to two areas in West Texas and one area in South Louisiana.

General and administrative (“G&A”) expenses, excluding non-cash employee compensation, decreased from $3.6 million in 2005 to $3.1 million in 2006 due primarily to lower professional fees during 2006. In 2006, we recorded a $500,000 non-cash compensation charge related to our after payout incentive plan compared to a $1.9 million non-cash charge in 2005 for stock-based employee compensation.

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 $23.3 million of exploration costs, as compared to $19 million in 2005. Most of these costs were related to properties in Louisiana.

We plan to spend approximately $244.3 million on exploration and development activities in fiscal 2006, of which approximately 87% 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 September 30, 2006, our capitalized unproved oil and gas properties totaled $150.8 million, of which approximately $100.7 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 decreased from $5.5 million in 2005 to $5.3 million in 2006 due to several factors. In July 2005, we issued $225 million of 7¾% Senior Notes due 2013 (the “Senior Notes”) which bear interest at a fixed rate of 7.75%, and used the proceeds to repay our then-outstanding bank indebtedness. As a result, the 2005 period included a non-cash charge of $1.8 million of debt issue costs related to the early repayment of our senior term credit facility and the reduction in our borrowing base under the revolving credit facility. The average daily principal balance outstanding under our bank credit facility for 2006 was $102.6 million compared to $40.4 million for 2005, and the Senior Notes were outstanding for the entire 2006 period. Capitalized interest for 2006 was $1.6 million compared to $727,000 in 2005.

Gain/loss on derivatives

We recorded a net gain on derivatives of $26.7 million in 2006 compared to a loss of $28.8 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 $1.7 million in 2006, as compared to $8 million in 2005. We recorded a gain on derivatives of $28.4 million in 2006 compared to a loss of $20.8 million in 2005 resulting from mark-to-market valuations.

Operating Results — Nine-Month Periods

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

Oil and gas operating results

Oil and gas sales in 2006 decreased $2.4 million, or 1%, from 2005, of which price variances accounted for a $20 million increase and production variances accounted for a $22.4 million decrease.

Production in 2006 (on an Mcfe basis) was 12% lower than 2005. Oil production decreased 7% in 2006 from 2005 due primarily to normal production declines combined with the loss of production from one well in Louisiana. Gas production decreased 15% due primarily to production declines in the Cotton Valley Reef Complex area due to formation performance.

In 2006, our realized oil price was 23% higher than 2005, while our realized gas price was 2% lower. Historically, the markets for oil and gas have been volatile, and they are likely to continue to be volatile.

Production costs, consisting of lease operating expenses, production taxes and other miscellaneous marketing costs, increased 9% in 2006 as compared to 2005 due primarily to higher oilfield service costs and increased workover activities. After giving effect to a 12% decline in oil and gas production on an Mcfe basis, production costs per Mcfe increased 24% from $1.74 per Mcfe in 2005 to $2.16 per Mcfe in 2006. It is likely that these factors will continue to contribute to higher production costs in future periods.

DD&A expense increased from $36.1 million in 2005 to $48.4 million in 2006. DD&A expense attributable to oil and gas properties increased $11.8 million, of which rate variances accounted for a $15.9 million increase and production variances accounted for a $4.1 million decrease. On an Mcfe basis, DD&A expense increased 53% from $1.36 per Mcfe in 2005 to $2.08 per Mcfe in 2006. Depletion rates for each depletable group are a function of net capitalized costs and estimated reserve quantities.

We recorded a provision for impairment of proved properties under SFAS 144 of $12.9 million during 2006 due to the combination of production performance and lower commodity prices. This provision was attributable to two areas in West Texas and one area in South Louisiana.

G&A expenses, excluding non-cash employee compensation, increased from $9 million in 2005 to $11.4 million in 2006 due to higher personnel costs and professional fees attributable to the increase in overall drilling and exploration activities. In 2006, we recorded a $1.5 million non-cash compensation charge related to our after payout incentive plan compared to a $2.1 million non-cash charge in 2005 for stock-based employee compensation.

Gain on property sales

Gain on sales of property and equipment in 2006 was $916,000 as compared to $18.9 million in 2005. Most of the gain in 2005 related to the sale of our interests in two leases in the Breton Sound area of the Gulf of Mexico.

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 $45.2 million of exploration costs, as compared to $39.1 million in 2005. Most of these costs were incurred in Louisiana, the Permian Basin and Montana.

Therefore, our results of operations in future periods may be adversely affected by unproved property impairments.

Interest expense

Interest expense increased from $10.4 million in 2005 to $14.6 million in 2006 due to several factors. In July 2005, we issued $225 million of Senior Notes which bear interest at a fixed rate of 7.75%, and used the proceeds to repay our then-outstanding bank indebtedness. As a result, the 2005 period included a non-cash charge of $1.8 million of debt issue costs related to the early repayment of our senior term credit facility and the reduction in our borrowing base under the revolving credit facility. The average daily principal balance outstanding under our bank credit facility for 2006 was $75.7 million compared to $134.3 million for 2005; however, the Senior Notes were outstanding for the entire 2006 period. Capitalized interest for 2006 was $4.4 million compared to $1.4 million in 2005.

Gain/loss on derivatives

We recorded a gain on derivatives of $25.4 million in 2006 compared to a loss of $73.7 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 $17.3 million in 2006, as compared to $17.6 million in 2005. We recorded a gain on derivatives of $42.7 million in 2006 compared to a loss of $56.1 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 September 30, 2006, we had $104.4 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 $244.3 million, as summarized by area in the following table.

	Actual		Total
	Expenditures		Planned
	Nine Months		Expenditures
	Ended		Year Ended		Percentage
	September 30, 2006		December 31, 2006		of Total
	(In thousands)
South Louisiana	$	84,800	$	114,000	47	%
North Louisiana	36,900		54,300		22	%
Permian Basin	26,300		34,500		14	%
East Texas (Bossier)	20,500		23,600		10	%
Utah/Montana	6,100		7,700		3	%
Austin Chalk (Trend)	2,500		2,700		1	%
Other	6,300		7,500		3	%
	$	183,400	$	244,300	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 half of our expenditures for exploration and development activities for the nine months ended September 30, 2006 have been financed through operating cash flow, and the remainder has been financed through borrowings under the revolving credit facility. We also expect this trend to continue in the fourth quarter of 2006.

Approximately 87% 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.

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

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. At September 30, 2006, the effective interest rate on the Larclay JV term loan was 8.5%. 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 $112 million over the three-year term of the contract. Four rigs are currently operational, of which two are working for us and two are working for other operators. 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 $24.5 million, of which cash deposits totaling $8.1 million have been paid to certain equipment suppliers as of September 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 $11 million in the fourth quarter of 2006 and $25 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 nine months ended September 30, 2006 decreased $10.1 million, or 8%, as compared to the corresponding 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 $10.8 million lower in 2006 as compared to the same period in 2005. Our primary source of cash from operating activities is our oil and gas sales, net of production costs. Our cash flow provided by operating activities is subject to material variation from changes in oil and gas production levels and product prices. Settlements on derivative contracts, excluding those contracts that contain a financing element as in the case of the contracts assumed in our acquisition of Southwest Royalties, Inc. in May 2004, were substantially the same in both periods. 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 nine months ended September 30, 2006, we generated cash flow from operating activities of $116.5 million. We also spent $183.9 million on capital expenditures and other investments (excluding Larclay JV) and paid $23.3 million to settle derivatives with financing elements. To finance the excess of expenditures over cash flow, we borrowed $93.7 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 $27 million at September 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 $62.1 million at September 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 September 30, 2006 and December 31, 2005.

	September 30,			December 31,
	2006			2005
	(In thousands)
Working capital (deficit) per GAAP	$	(27,012	)	$	(35,812	)
Add funds available under the revolving credit facility	75,796			138,496
Exclude fair value of derivatives classified as current assets or current liabilities	13,316			33,479
Working capital per loan covenant	$	62,100		$	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 September 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.

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 September 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. We have recently drawn advances under the revolving credit facility to partially finance our exploration and development activities. At September 30, 2006, we had $104.4 million outstanding on the revolving credit facility.

73¤4% 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 73¤4% 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 September 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. Commodity derivatives are settled monthly as the contract periods mature. The commodity derivatives we use differ from futures contracts in that there is not a contractual obligation that requires or permits the future physical delivery of the hedged products. We do not enter into commodity derivatives for trading purposes. In addition to commodity derivatives, we may, from time to time, sell a portion of our gas production under short-term contracts at fixed prices.

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

The following summarizes information concerning our net positions in open commodity derivatives applicable to periods subsequent to September 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:
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
	3,566,000					1,104,000

Swaps:

	Gas			Oil
	MMBtu(a)	Price		Bbls	Price
Production Period:
4th Quarter 2006	1,050,000	$	10.03	75,000	$	71.60
2007	5,100,000	$	9.20	900,000	$	70.06
2008	3,600,000	$	8.37	360,000	$	69.55
	9,750,000			1,335,000

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

In August 2006, we terminated certain fixed-price gas swaps covering 9,010,000 MMBtu of gas production at an average price of $9.26 per Mcf for the period from November 2006 through December 2007. We received cash proceeds of $6.1 million upon termination of these contracts.

In July 2006, we also terminated 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, which will be paid to the counterparty monthly during 2007.

We use a sensitivity analysis technique to evaluate the hypothetical effect that changes in the market value of oil and gas may have on the fair value of our commodity derivatives. A $1 per barrel change in the price of oil and a $.50 per MMBtu change in the price of gas would change the fair value of our commodity derivatives by approximately $9.1 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 September 30, 2006.

	Principal		Fixed Libor
	Balance		Rates
Period:
October 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 September 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 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**		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††

10.2**		Participation Agreement relating to South Louisiana IV dated August 2, 2006, filed as Exhibit 10.1 to our Current Report on Form 8-K filed with the Commission on August 7, 2006††

10.3**		Participation Agreement relating to North Louisiana — Hosston/Cotton Valley dated August 2, 2006, filed as Exhibit 10.2 to our Current Report on Form 8-K filed with the Commission on August 7, 2006††

10.4**		Participation Agreement relating to North Louisiana — Bossier dated August 2, 2006, filed as Exhibit 10.3 to our Current Report on Form 8-K filed with the Commission on August 7, 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

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)

		Page
Item 1.	Financial Statements

	Consolidated Balance Sheets as of September 30, 2006 and December 31, 2005	3

	Consolidated Statements of Operations for the three months and nine months ended September 30, 2006 and 2005	5

	Consolidated Statement of Stockholders’ Equity for the nine months ended September 30, 2006	6

	Consolidated Statements of Cash Flows for the nine months ended September 30, 2006 and 2005	7

	Notes to Consolidated Financial Statements

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

Item 3.	Quantitative and Qualitative Disclosure About Market Risks	37

Item 4.	Controls and Procedures	40

	PART II. OTHER INFORMATION

Item 1A.	Risk Factors	41

Item 6.	Exhibits	41

	Signatures	43

			CLAYTON WILLIAMS ENERGY, INC.

Date:	November 9, 2006	By:	/s/ L. Paul Latham
			L. Paul Latham
			Executive Vice President and Chief Operating Officer





Date:	November 9, 2006	By:	/s/ Mel G. Riggs
			Mel G. Riggs
			Senior Vice President and Chief Financial Officer

PART I. FINANCIAL INFORMATION

Commodity Derivatives

Interest Rate Derivatives

Disclosure Controls and Procedures

Changes in Internal Control Over Financial Reporting