cwei10q308.htm

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definition of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

	Large accelerated filer ¨	Accelerated filer x
	Non-accelerated filer ¨	Smaller reporting company ¨

ASSETS
	March 31,			December 31,
	2008			2007
	(Unaudited)
CURRENT ASSETS
Cash and cash equivalents	$	18,523		$	12,344
Accounts receivable:
Oil and gas sales, net		48,991			36,698
Joint interest and other, net		18,241			16,666
Affiliates		9,608			308
Inventory		14,896			14,348
Deferred income taxes		3,581			3,581
Fair value of derivatives		-			7,191
Assets held for sale		72,135			17,281
Prepaids and other		3,583			3,962
		189,558			112,379

PROPERTY AND EQUIPMENT
Oil and gas properties, successful efforts method		1,313,786			1,374,090
Natural gas gathering and processing systems		18,604			18,404
Contract drilling equipment		89,965			89,956
Other		14,536			14,505
		1,436,891			1,496,955
Less accumulated depreciation, depletion and amortization		(736,153	)		(765,877	)
Property and equipment, net		700,738			731,078



OTHER ASSETS
Debt issue costs, net		6,615			6,963
Fair value of derivatives		72			-
Other		11,059			10,676
		17,746			17,639
	$	908,042		$	861,096

LIABILITIES AND STOCKHOLDERS' EQUITY
	March 31,		December 31,
	2008		2007
	(Unaudited)
CURRENT LIABILITIES
Accounts payable:
Trade	$	84,602	$	72,477
Oil and gas sales		27,954		24,806
Affiliates		2,190		1,747
Current maturities of long-term debt		20,625		22,500
Fair value of derivatives		71,646		56,929
Accrued liabilities and other		5,884		10,308
		212,901		188,767

NON-CURRENT LIABILITIES
Long-term debt		414,688		430,175
Deferred income taxes		48,633		44,302
Fair value of derivatives		10,192		-
Other		37,371		37,046
		510,884		511,523

COMMITMENTS AND CONTINGENCIES

STOCKHOLDERS’ EQUITY
Preferred stock, par value $.10 per share, authorized – 3,000,000
shares; none issued		-		-
Common stock, par value $.10 per share, authorized – 30,000,000
shares; issued and outstanding – 12,104,051 shares in 2008
and 11,354,051 shares in 2007		1,210		1,135
Additional paid-in capital		136,831		121,063
Retained earnings		43,069		35,890
Accumulated other comprehensive income, net of tax		3,147		2,718
		184,257		160,806
	$	908,042	$	861,096

	Three Months Ended
	March 31,
	2008			2007
REVENUES
Oil and gas sales	$	118,919		$	61,180
Natural gas services		2,538			2,654
Drilling rig services		14,832			8,417
Gain on sales of property and equipment		569			259
Total revenues		136,858			72,510

COSTS AND EXPENSES
Production		20,579			17,278
Exploration:
Abandonments and impairments		297			11,105
Seismic and other		3,675			890
Natural gas services		2,515			2,413
Drilling rig services		11,117			4,933
Depreciation, depletion and amortization		30,273			15,231
Impairment of property and equipment		-			565
Accretion of abandonment obligations		530			618
General and administrative		3,448			3,903
Loss on sales of property and equipment		9			9,332
Total costs and expenses		72,443			66,268

Operating income		64,415			6,242

OTHER INCOME (EXPENSE)
Interest expense		(7,446	)		(7,629	)
Loss on derivatives		(46,109	)		(16,849	)
Other		655			713
Total other income (expense)		(52,900	)		(23,765	)

Income (loss) before income taxes and minority interest		11,515			(17,523	)
Income tax (expense) benefit		(4,222	)		6,080
Minority interest, net of tax		(114	)		(867	)

NET INCOME (LOSS)	$	7,179		$	(12,310	)

Net income (loss) per common share:
Basic	$	0.63		$	(1.09	)
Diluted	$	0.62		$	(1.09	)

Weighted average common shares outstanding:
Basic		11,387			11,290
Diluted		11,643			11,290

									Accumulated
									Other		Total
	Common Stock				Additional				Compre-		Compre-
	No. of		Par		Paid-In		Retained		hensive		hensive
	Shares		Value		Capital		Earnings		Income		Income
BALANCE,
December 31, 2007		11,354	$	1,135	$	121,063	$	35,890	$	2,718
Net income		-		-		-		7,179		-	$	7,179
Unrealized gain on
marketable securities,
net of tax of $231		-		-		-		-		429		429
Total comprehensive
income											$	7,608
Issuance of stock through
compensation plans		750		75		15,768		-		-
BALANCE,
March 31, 2008		12,104	$	1,210	$	136,831	$	43,069	$	3,147

	Three Months Ended
	March 31,
	2008			2007
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	7,179		$	(12,310	)
Adjustments to reconcile net income (loss) to cash
provided by operating activities:
Depreciation, depletion and amortization		30,273			15,231
Impairment of property and equipment		-			565
Exploration costs		297			11,105
Gain on sales of property and equipment, net		(560	)		(128	)
Deferred income taxes		4,100			(6,080	)
Non-cash employee compensation		342			610
Unrealized loss on derivatives		32,028			18,822
Settlements on derivatives with financing elements		10,415			5,593
Amortization of debt issue costs		346			309
Accretion of abandonment obligations		530			618
Minority interest, net of tax		114			867

Changes in operating working capital:
Accounts receivable		(13,869	)		(286	)
Accounts payable		11,985			(3,703	)
Other		(5,130	)		5,016
Net cash provided by operating activities		78,050			36,229

CASH FLOWS FROM INVESTING ACTIVITIES
Additions to property and equipment		(49,610	)		(55,749	)
Additions to equipment of Larclay JV.		(9	)		(19,316	)
Proceeds from sales of property and equipment		624			645
Change in equipment inventory		(1,620	)		3,896
Other		69			(2,970	)
Net cash used in investing activities		(50,546	)		(73,494	)

CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt		-			25,000
Proceeds from long-term debt of Larclay JV		-			8,727
Repayments of long-term debt		(10,800	)		-
Repayments of long-term debt of Larclay JV		(6,562	)		-
Proceeds from exercise of stock options		6,452			5,962
Settlements on derivatives with financing elements		(10,415	)		(5,593	)
Net cash provided by (used in) financing activities		(21,325	)		34,096

NET INCREASE (DECREASE) IN CASH AND
CASH EQUIVALENTS		6,179			(3,169	)

CASH AND CASH EQUIVALENTS
Beginning of period		12,344			13,840
End of period	$	18,523		$	10,671

SUPPLEMENTAL DISCLOSURES
Cash paid for interest, net of amounts capitalized	$	11,628		$	11,739

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 24% of the Company’s outstanding common stock is beneficially owned by Clayton W. Williams, Jr. (“Mr. Williams”), Chairman of the Board and Chief Executive Officer of the Company, and approximately 27% is owned by a partnership in which Mr. Williams’ adult children are limited partners.

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

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 12). 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. Certain reclassifications of prior year financial statement amounts have been made to conform to current year presentations.

In the opinion of management, the Company's unaudited consolidated financial statements as of March 31, 2008 and for the interim periods ended March 31, 2008 and 2007 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, 2008.

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, 2007.

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133” (“SFAS 161”). This statement is intended to improve transparency in financial reporting by requiring enhanced disclosures of an entity’s derivative instruments and hedging activities and their effects on the entity’s financial position, financial performance, and cash flows. SFAS

161 applies to all derivative instruments within the scope of SFAS 133 as well as related hedged items, bifurcated derivatives, and non-derivative instruments that are designated and qualify as hedging instruments. Entities with instruments subject to SFAS 161 must provide more robust qualitative disclosures and expanded quantitative disclosures. SFAS 161 is effective prospectively for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application permitted. The Company is currently evaluating the disclosure implications of this statement.

In December 2007, the Financial Accounting Standards Board (“FASB”) issued SFAS 141R, “Business Combinations” (“SFAS 141R”) and SFAS 160, “Noncontrolling Interests in Consolidated Financial Statements” (“SFAS 160”). SFAS 141R requires most identifiable assets, liabilities, noncontrolling interests, and goodwill acquired in a business combination to be recorded at “fair value.” The Statement applies to all business combinations, including combinations among mutual entities and combinations by contract alone. Under SFAS 141R, all business combinations will be accounted for by applying the acquisition method. SFAS 141R is effective for periods beginning on or after December 15, 2008. SFAS 160 will require noncontrolling interests (previously referred to as minority interests) to be treated as a separate component of equity, not as a liability or other item outside of permanent equity. The statement applies to the accounting for noncontrolling interests and transactions with noncontrolling interest holders in consolidated financial statements. SFAS 160 is effective for periods beginning on or after December 15, 2008 and will be applied prospectively to all noncontrolling interests, including any that arose before the effective date except that comparative period information must be recast to classify noncontrolling interests in equity, attribute net income and other comprehensive income to noncontrolling interests, and provide other disclosures required by SFAS 160. The impact to the Company from the adoption of SFAS 141R in 2009 will depend on future acquisition activity.

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 or for any period thereafter, in each case plus accrued and unpaid interest.

The Indenture governing the Senior Notes restricts the ability of the Company and its restricted subsidiaries to: (i) borrow money; (ii) issue redeemable and preferred stock; (iii) pay distributions or dividends; (iv) make investments; (v) create liens without securing the Senior Notes; (vi) enter into agreements that restrict dividends from subsidiaries; (vii) sell certain assets or merge with or into other companies; (viii) enter into transactions with affiliates; (ix) guarantee indebtedness; and (x) enter into new lines of business. The Company was in compliance with these covenants at March 31, 2008.

The Company’s secured bank credit facility provides for a revolving loan facility in an amount not to exceed the lesser of the borrowing base, as established by the banks, or that portion of the borrowing base determined by the Company to be the elected borrowing limit. The borrowing base, which is based on the discounted present value of future net revenues from oil and gas production, is subject to redetermination at any time, but at least semi-annually in May and November, and is made at the discretion of the banks. If, at any time, the redetermined borrowing base is less than the amount of outstanding indebtedness, the Company will be required to (i) pledge additional collateral, (ii) prepay the excess in not more than five equal monthly installments, or (iii) elect to convert the entire amount of outstanding indebtedness to a term obligation based on amortization formulas set forth in the loan agreement. Substantially all of the Company’s oil and gas properties are pledged to secure advances under the credit facility. At March 31, 2008, the borrowing base established by the banks was $275 million, with no monthly commitment reductions. After allowing for outstanding letters of credit totaling $804,000, the Company had $119.2 million available under the credit facility at March 31, 2008. Subsequent to March 31, 2008, the borrowing base was reduced to $250 million after the sale of assets (see Note 14).

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 quarter ended March 31, 2008 was 5.6%.

The loan agreement applicable to the revolving credit facility contains financial covenants that are computed quarterly. The working capital covenant requires the Company to maintain a ratio of current assets to current liabilities of at least 1 to 1. Another financial covenant under the credit facility requires the Company to maintain a ratio of indebtedness to cash flow of no more than 3 to 1. The computations of current assets, current liabilities, cash flow and indebtedness are defined in the loan agreement. The Company was in compliance with all financial and non-financial covenants at March 31, 2008.

In connection with the Company’s investment in Larclay JV (see Note 12), Larclay JV obtained a $75 million secured term loan facility from a lender to finance the construction and equipping of 12 new drilling rigs. The Larclay JV term loan is secured by substantially all of the assets of Larclay JV. Initially, the Company pledged additional collateral in the form of a $19 million letter of credit. In February 2007, the letter of credit was cancelled and replaced by a $19.5 million guaranty from the Company. Although the Company is not a maker on the Larclay JV term loan, it is providing partial credit support for the Larclay JV term loan and is required to fully consolidate the accounts of Larclay JV under FASB Interpretation No. 46R “Consolidation of Variable Interest Entities – an Interpretation of ARB No. 51 (as amended)” (“FIN 46R”).

The Larclay JV term loan, as amended, bears interest at a floating rate based on a LIBOR average, plus 3.25%, and provides for monthly interest payments through June 2007 and monthly principal and interest payments thereafter sufficient to retire the principal balance by 35% in the first year, 25% in each of the next two years, and 15% in the fourth year. Two voluntary prepayments of $10 million each may be made in 2008 and 2009 without a prepayment penalty. The Larclay JV term loan prohibits Larclay JV from making any cash distributions to the Company or Lariat until the balance on the term loan is fully repaid, and repayments by Larclay JV of any loans by the Company or Lariat are subordinated to the loans outstanding under the term loan and are subject to other restrictions. At March 31, 2008, the effective interest rate on the Larclay JV term loan was 6.9%.

The Company has reserved 1,798,200 shares of common stock for issuance under the 1993 Stock Compensation Plan (“1993 Plan”). The 1993 Plan provides for the issuance of nonqualified stock options with an exercise price which is not less than the market value of the Company’s common stock on the date of grant. All options granted through March 31, 2008 expire 10 years from the date of grant and become exercisable based on varying vesting schedules. The Company issues new shares, not repurchased shares, to option holders that exercise stock options under the 1993 Plan. At March 31, 2008, 101,766 shares remain available for issuance under this plan.

The Company has reserved 86,300 shares of common stock for issuance under the Outside Directors Stock Option Plan (“Directors Plan”). Since the inception of the Directors Plan, the Company has issued options covering 52,000 shares of common stock at option prices ranging from $3.25 to $41.74 per share. All outstanding options expire 10 years from the grant date and are fully exercisable upon issuance. At March 31, 2008, 34,300 shares remain available for issuance under this plan.

						Weighted
				Weighted		Average
				Average		Remaining		Aggregate
				Exercise		Contractual		Intrinsic
	Shares			Price		Term		Value (a)
Outstanding at January 1, 2008		811,485		$	20.49
Granted		4,000		$	31.16
Exercised (b)		(750,000	)	$	21.00
Outstanding at March 31, 2008		65,485		$	15.27		3.45	$	2,437,566

Vested at March 31, 2008		65,485		$	15.27		3.45	$	2,437,566
Exercisable at March 31, 2008		65,485		$	15.27		3.45	$	2,437,566

(a) Based on closing price at March 31, 2008 of $52.49 per share.
(b) Cash received for options exercised totaled $15.8 million, of which $9.3 million was received in April 2008.

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

Between 3% and 7.5% of the Company’s economic interests in specified wells drilled or acquired by the Company subsequent to October 2002 are subject to APO Arrangements (excluding properties acquired in a merger with Southwest Royalties, Inc. in May 2004). The Company records its allocable share of the assets, liabilities, revenues, expenses and oil and gas reserves of these APO Arrangements in its consolidated financial statements. The Company recognized $250,000 of non-cash compensation expense during the three-month period ended March 31, 2008 and $500,000 for the three-month period ended March 31, 2007 for the estimated fair value of the APO Arrangements granted during those periods.

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

The SWR Reward Plan provides for quarterly cash bonuses to the participants, as a group, equal to the after-payout cash flow from a 22.5% working interest in the RS Windham C3 well. Two-thirds of the quarterly bonus amount is payable to the participants until the full vesting date of October 25, 2011. After the full vesting date, the deferred portion of the quarterly bonus amount, with interest at 4.83% per year, as well as 100% of all subsequent quarterly bonus amounts, are payable to participants. The quarterly bonus amounts are allocated among the participants based on each participant’s bonus percentage.

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

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.

At March 31, 2008, the Company was a party to two interest rate swaps. 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 at March 31, 2008.

The Company accounts for its derivatives in accordance with SFAS 133. The Company did not designate any of its currently open commodity or interest rate derivatives as cash flow hedges; therefore, all changes in the fair value of these contracts prior to maturity, plus any realized gains or losses at maturity, are recorded as other income (expense) in the Company’s statements of operations. For the three months ended March 31, 2008, the Company reported a $46.1 million net loss on derivatives, consisting of a $32 million loss related to changes in mark-to-market valuations and a $14.1 million realized loss for settled contracts. For the three months ended March 31, 2007, the Company reported a $16.8 million loss on derivatives, consisting of an $18.8 million loss related to changes in mark-to-market valuations and a $2 million realized gain on settled contracts.

Cash and cash equivalents, receivables, accounts payable and accrued liabilities were each estimated to have a fair value approximating the carrying amount due to the short maturity of those instruments. Indebtedness under the secured bank credit facility was estimated to have a fair value approximating the carrying amount since the interest rate is generally market sensitive. The estimated fair value of the Company’s Senior Notes at March 31, 2008 and December 31, 2007 was approximately $194.6 million and $196.9 million, respectively.

The Company adopted SFAS No. 157, “Fair Value Measurements” (“SFAS 157”) (as amended) effective January 1, 2008. SFAS 157 defines fair value, establishes a framework for measuring fair value, outlines a fair value hierarchy based on the quality of inputs used to measure fair value and enhances disclosure requirements for fair value measurements. As permitted by FSP No. 157-2, the Company has not applied the provisions of SFAS 157 to nonfinancial assets and liabilities. The Company has not applied the provisions of SFAS 157 to its asset retirement obligations.

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

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

	Fair Value Measurements
	March 31, 2008				December 31, 2007
	Quoted Prices In		Significant		Quoted Prices In		Significant
	Active Markets For		Other		Active Markets For		Other
	Identical		Observable		Identical		Observable
	Assets/Liabilities		Inputs		Assets/Liabilities		Inputs
Description	Level 1		Level 2		Level 1		Level 2
	(In thousands)
Assets:
Investment securities	$	7,848	$	-	$	7,188	$	-
Total assets	$	7,848	$	-	$	7,188	$	-
Liabilities:
Fair value of derivatives:
Commodity derivatives, net	$	-	$	79,550	$	-	$	48,696
Interest derivatives, net		-		2,216		-		1,044
Total liabilities	$	-	$	81,766	$	-	$	49,740

The Company maintains an inventory of tubular goods and other well equipment for use in its exploration and development drilling activities. Any gains or losses on disposition of inventory, and any losses on write-down of inventory to its estimated market value, are reported as gain or loss on sales of property and equipment in the accompanying consolidated statements of operations. The 2007 period included a charge of $8.9 million to write-down inventory to its estimated market value at March 31, 2007. The write-down resulted primarily from the sale of certain surplus equipment at an auction in March 2007. The Company received $4.5 million of net proceeds from the auction in April 2007 when the auction sale was consummated.

Included in assets held for sale is $72.1 million at March 31, 2008 and $17.3 million at December 31, 2007 that the Company has designated as held for sale assets under SFAS 144. The December 31, 2007 balance consisted of $15.8 million for the estimated fair value of two 2,000 horsepower drilling rigs and related components and $1.5 million for well service equipment. At March 31, 2008, assets held for sale consisted of $16 million for the estimated fair value of two 2,000 horsepower drilling rigs and related components, $1.6 million for well service equipment and $54.5 million related to the net book value of certain oil and gas properties in South Louisiana that the Company offered for sale (see Note 14).

The Company’s effective federal and state income tax rate for the three months ended March 31, 2008 of 36.7% differed from the statutory federal rate of 35% due to tax benefits derived from statutory depletion deductions, offset in part by increases in the tax provision related primarily to the effects of the recently-enacted Texas Margin Tax and certain non-deductible expenses.

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

In June 2006, the FASB issued Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (“FIN 48”). Upon adoption of FIN 48, the Company recorded a liability for taxes payable related to unrecognized tax benefits arising from uncertain tax positions taken by the Company in previous periods. A reconciliation of the changes in this tax liability as of March 31, 2008 and December 31, 2007 is as follows:

No unrecognized tax benefits originated during the first three months of 2008. Reductions in the 2007 tax liability resulted from changes in accounting methods which were submitted to the taxing authority during 2007. All of the remaining unrecognized tax benefits at March 31, 2008 relate to tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductions. Because of the impact of deferred tax accounting, the disallowance of the shorter deduction period would not affect the annual effective tax rate but would only accelerate the payment of taxes to the taxing authority or change the amount of deferred tax assets related to net operating loss carryforwards.

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

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. A lender has provided a $75 million secured term loan to Larclay JV to finance most of the cost of constructing and initially equipping the rigs (see Note 4). Pursuant to the requirements of the joint venture agreements, the Company has made two loans to Larclay JV, one in November 2007 for $4.6 million to finance excess construction costs and one in April 2008 for $2.5 million to finance its 50% share of a working capital assessment required by Larclay JV. Loans to Larclay JV are due on demand and bear interest, payable monthly, at the same rate as the secured term loan. However, the loans are subject to a subordination agreement with the secured lender that imposes restrictions on payments of principal and interest on the note.

Also in April 2006, the Company entered into a three-year drilling contract with Larclay JV assuring the availability of each rig for use in the ordinary course of the Company’s exploration and development drilling program throughout the term of the drilling contract. The provisions of the drilling contract provide that the Company contract for each rig on a well-by-well basis at then current market rates. If a rig is not needed by the Company at any time during the term of the contract, Larclay JV may contract with other operators for the use of such rig, subject to certain restrictions. If a rig is idle, the Company will pay Larclay JV an idle rig rate ranging from $8,100 per day to $10,300 per day (plus crew labor expenses, if applicable), depending on the size of the rig. The Company’s maximum potential obligation to pay idle rig rates over the term of this drilling contract, excluding any crew labor expenses, totals approximately $68.7 million at March 31, 2008. The Company did not pay any idle rig fees during the three months ended March 31, 2008.

Although the Company and Lariat own equal interests in Larclay JV, the Company meets the definition of the primary beneficiary of Larclay JV’s expected cash flows under FIN 46R. As the primary beneficiary under FIN 46R, the Company is required to include the accounts of Larclay JV in the Company’s consolidated financial statements. As of March 31, 2008, Lariat’s equity ownership in the net assets of Larclay JV was $5 million, which is recorded as minority interest and included in other non-current liabilities in the accompanying consolidated financial statements. The Company’s intercompany accounts with Larclay JV have been eliminated in consolidation.

The Company owns 200,460 shares of common stock in SandRidge Energy Inc. (“SandRidge”). During the fourth quarter of 2007, SandRidge became publicly traded and listed its shares on the New York Stock Exchange. The Company’s original cost investment in SandRidge was increased to fair market value in 2007 and the change in fair market value of $4.2 million, net of tax of $1.5 million, was recorded in accumulated other comprehensive income at December 31, 2007. The fair value of the Company’s investment in SandRidge at March 31, 2008 is $7.8 million and is recorded in other non-current assets, based on the closing price of the stock as of March 31, 2008. The change in fair market value during the three months ended March 31, 2008 of $660,000, net of tax of $231,000, was recorded in accumulated other comprehensive income.

In April 2008, the Company and its affiliates sold all of their interests in 16 producing wells for approximately $88.6 million, net of customary closing adjustments. The Company expects to record a gain of approximately $33 million in the second quarter of 2008 in connection with this transaction. Also, in April 2008, the Company sold a surplus well servicing unit for $1.8 million. The Company will record a gain of approximately $300,000 on the sale of this asset in the second quarter of 2008.

For the Three Months Ended				Contract			Intercompany			Consolidated
March 31, 2008	Oil and Gas			Drilling			Eliminations			Total
	(In thousands)
Revenues	$	122,026		$	17,163		$	(2,331	)	$	136,858
Depreciation, depletion and amortization (a)		27,988			2,610			(325	)		30,273
Other operating expenses (b)		30,815			13,008			(1,653	)		42,170
Interest expense		6,352			1,094			-			7,446
Other (income) expense		45,454			-			-			45,454
Income before income taxes and
minority interest		11,417			451			(353	)		11,515

Income tax (expense) benefit		(3,964	)		(258	)		-			(4,222	)
Minority interest, net of tax		62			(176	)		-			(114	)

Net income (loss)	$	7,515		$	17		$	(353	)	$	7,179

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

For the Three Months Ended				Contract			Intercompany			Consolidated
March 31, 2007	Oil and Gas			Drilling			Eliminations			Total
	(In thousands)
Revenues	$	64,093		$	10,936		$	(2,519	)	$	72,510
Depreciation, depletion and amortization (a)		14,413			1,607			(224	)		15,796
Other operating expenses (b)		45,507			5,827			(862	)		50,472
Interest expense		6,795			834			-			7,629
Other (income) expense		16,136			-			-			16,136
Income before income taxes and
minority interest		(18,758	)		2,668			(1,433	)		(17,523	)

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

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

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

(a) Includes impairment of property and equipment.
(b) Includes the following expenses: production, exploration, natural gas services, drilling rig services, accretion of abandonment obligations, general and administrative and loss on sales of property and equipment.

In July 2005, Clayton Williams Energy, Inc. (“Issuer”) issued $225 million of Senior Notes (see Note 4). Other than West Coast Energy Properties GP, LLC (“WCEP LLC”), the general partner of West Coast Energy Properties, L.P., an affiliated limited partnership, all of the Issuer’s wholly-owned and active subsidiaries (“Guarantor Subsidiaries”) have jointly and severally, irrevocably and unconditionally guaranteed the performance and payment when due of all obligations under the Senior Notes. Larclay JV, a 50%-owned drilling rig joint venture formed in April 2006, and WCEP LLC have not guaranteed the Senior Notes and are referred to in this Note 16 as Non-Guarantor Entities.

(Dollars in thousands)					Non-
			Guarantor		Guarantor		Adjustments/
	Issuer		Subsidiaries		Entities		Eliminations			Consolidated
Current assets	$	195,784	$	114,244	$	19,463	$	(139,933	)	$	189,558
Property and equipment, net		335,417		281,811		83,510		-			700,738
Investments in subsidiaries		81,954		-		-		(81,954	)		-
Other assets		21,733		336		277		(4,600	)		17,746
Total assets	$	634,888	$	396,391	$	103,250	$	(226,487	)	$	908,042

Current liabilities	$	139,145	$	171,469	$	42,220	$	(139,933	)	$	212,901
Non-current liabilities:
Long-term debt		380,000		-		39,288		(4,600	)		414,688
Fair value of derivatives		10,192		-		-		-			10,192
Other		29,368		56,523		113		-			86,004
		419,560		56,523		39,401		(4,600	)		510,884

Stockholders’ equity		76,183		168,399		21,629		(81,954	)		184,257
Total liabilities and
stockholders’ equity	$	634,888	$	396,391	$	103,250	$	(226,487	)	$	908,042

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

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

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

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

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

(Dollars in thousands)							Non-
				Guarantor			Guarantor			Adjustments/
	Issuer			Subsidiaries			Entities			Eliminations			Consolidated
Total revenue	$	40,136		$	24,169		$	11,038		$	(2,833	)	$	72,510
Costs and expenses		44,902			16,139			7,575			(2,348	)		66,268
Operating income (loss)		(4,766	)		8,030			3,463			(485	)		6,242
Other income (expense)		(19,557	)		(3,402	)		(806	)		-			(23,765	)
Income tax benefit		6,080			-			-			-			6,080
Minority interest, net of tax		(867	)		-			-			-			(867	)

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

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

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

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

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

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

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

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, 2007.

We are an oil and natural gas exploration, development, acquisition, and production company. Our basic business model is to increase shareholder value by finding and developing oil and gas reserves through exploration and development activities, and selling the production from those reserves at a profit. To be successful, we must, over time, be able to find oil and gas reserves and then sell the resulting production at a price that is sufficient to cover our finding costs, operating expenses, administrative costs and interest expense, plus offer us a return on our capital investment. From time to time, we may also acquire producing properties if we believe the acquired assets offer us the potential for reserve growth through additional developmental or exploratory drilling activities.

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 are currently well above historic averages. Although oil and gas prices are typically volatile and are subject to market fluctuations, we believe that supply and demand fundamentals in the energy marketplace continue to provide us with the economic incentives necessary for us to assume the risks we face in our search for oil and gas reserves. However, despite favorable commodity prices, certain of our operating metrics per Mcfe, such as finding costs and depreciation, depletion and amortization (“DD&A”) expense, are rising.

Finding quality domestic oil and gas reserves through exploration is a significant challenge and involves a high degree of risk. DD&A per Mcfe of oil and gas production, an operating metric that measures a company’s cumulative cost to find or purchase a unit of production, increased significantly from the first quarter of 2007 to the first quarter of 2008. Approximately 68% of our planned activities for 2008 relate to developmental prospects that are not expected to materially reduce our reported DD&A per Mcfe.

We recorded a $46.1 million net loss on derivatives in the first quarter of 2008. We recorded a $14.1 million realized loss on settled contracts and a $32 million loss for changes in mark-to-market valuations. Since we do not presently designate our derivatives as cash flow hedges under applicable accounting standards, we recognize the full effect of changing prices on mark-to-market valuations as a current charge or credit to our results of operations.

At March 31, 2008, our capitalized unproved oil and gas properties totaled $134.2 million, of which approximately $80.3 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.

Most of our exploration and development efforts in 2008 are directed toward developmental drilling for oil. With oil at record-high levels, we believe the time is right to exploit our large inventory of lower risk, developmental drilling locations, primarily in the Permian Basin and the Austin Chalk (Trend) areas of our asset base. However, we remain committed to our higher risk, higher impact exploration programs, particularly our deep Bossier plays in East Texas and North Louisiana.

As shown in “Liquidity and Capital Resources – Capital Expenditures,” we incurred expenditures for exploration and development activities of $57.7 million during the first three months of 2008, of which approximately 21% were related to exploratory drilling and leasing activities. We also increased our estimates for capital expenditures in fiscal 2008 from $256.5 million to $344.5 million. The increase in capital spending relates primarily to developmental activities in the Permian Basin and North Louisiana.

The Permian Basin is a sedimentary basin in West Texas and Southeastern New Mexico known for its large oil and gas deposits from the Permian geologic period. Although many fields in the Permian Basin have been heavily exploited in the past, higher product prices and improved technology (including deep horizontal drilling) continue to encourage high levels of current drilling and recompletion activities. We gained a significant position in the Permian Basin in 2004 when we acquired Southwest Royalties, Inc. This acquisition provided us with an inventory of potential drilling and recompletion activities that we are beginning to exploit.

The Permian Basin continues to be a significant source of cash flow for us. We currently expect to spend $168 million on development activities in the Permian Basin in 2008. Most of the drilling activities relate to our War-Wink and Amacker-Tippett prospects in West Texas, and to a lesser extent our acreage positions in Andrews and Crockett Counties, Texas. In the War-Wink area, we are presently drilling horizontal wells targeting oil-prone sands in the Bone Spring formation. In the Amacker-Tippett, Andrews County and Crockett County areas, our planned drilling activities relate primarily to wells targeting oil-prone sands in the Spraberry and Wolfcamp formations.

Prior to 1998, we concentrated our drilling activities in an oil-prone area we refer to as the Austin Chalk (Trend) in Robertson, Burleson, Brazos, Milam and Leon Counties, Texas. Most of our wells in this area were drilled as horizontal wells, many with multiple laterals in different producing horizons, including the Austin Chalk, Buda and Georgetown formations. The existing spacing between some of our wells in this area affords us the opportunity to tap additional oil and gas reserves by drilling new wells between existing wells, a technique referred to as in-fill drilling. These in-fill wells are considered lower risk as compared to exploratory wells and, with oil prices at historic highs, the rates of return are now attractive. In addition, we are conducting secondary water frac operations on existing wells in the Austin Chalk (Trend) area to improve production rates and add new reserves. We spent $10.8 million during the first quarter of 2008 and currently plan to spend $55.4 million on development activities and leasing in this area during fiscal 2008.

In 2005, we began a drilling program in North Louisiana targeting the Cotton Valley/Gray and Bossier formations. In this area, the Cotton Valley/Gray formations are encountered at depths ranging from 8,000 to 12,000 feet, and the Bossier formation is encountered at depths ranging from 11,000 to 15,500 feet. We believe that these tight sandstone formations have become more economically viable due to higher product prices, coupled with enhanced drilling and completion techniques. We currently have approximately 170,000 net acres leased for Bossier drilling in North Louisiana.

To date, we have completed thirteen wells on our Terryville prospect as producers. These wells are currently producing at combined rates of approximately 9,300 Mcf of gas per day and 200 barrels of oil per day, net to our interest. We plan to drill three additional development wells on this prospect during the remainder of 2008. We have also completed one well as a producer in our Ruston prospect and plan to drill three additional wells on this prospect during the remainder of 2008.

In late 2007, we entered into an agreement with an industry partner, in which they have committed to drill five wells on certain of our prospects in South Louisiana during 2008. The industry partner will operate the wells, and we will have a 15% before casing point working interest and a 50% after casing point working interest in each well drilled. We expect to spend approximately $2.9 million for our portion of drilling activities under this agreement.

We currently have approximately 142,000 net acres under lease in East Texas targeting the prolific deep Bossier sands which are encountered at depths ranging from 14,000 to 22,000 feet in this area. Of this acreage, approximately 70,000 net acres are held by production from existing Austin Chalk (Trend) wells. Exploration for deep Bossier gas sands in this area is in its early stages and involves a high degree of risk. The geological structures are complex, and limited drilling activity offers minimal subsurface control. Deep Bossier wells are expensive to drill, with completed wells costing approximately $18 million each. Although seismic data is helpful in identifying possible sand accumulations, the only way to determine if the deep Bossier sand will be commercially productive is to drill wells to the targeted structures.

Late in 2007, we drilled two wells in this area targeting the deep Bossier, the Big Bill Simpson #1, a 19,000-foot exploratory well in Leon County (70% working interest), and the Margarita #1, a 20,000-foot exploratory well in Robertson County (100% working interest). The Big Bill Simpson well encountered a thick section of lower and middle Bossier sands, but these sands had limited porosity. The Margarita #1 well only encountered the upper Bossier sand. We are currently attempting to complete these wells. If we are unable to establish sufficient production levels from either of these two wells, results of operations in subsequent quarters may be adversely affected by the outcome of those wells.

We currently plan to spend approximately $28.6 million in the East Texas Bossier area for leasing and seismic activities and to drill one well on our Jewett prospect. Despite the disappointing results of the Big Bill Simpson #1 and the Margarita #1, we are optimistic that our acreage position in this area is prospective for potentially significant deep Bossier discoveries. As more wells are drilled and more subsurface control data is obtained, we believe our prospects for discoveries improve. We have begun a 3-D seismic shoot in Leon County, Texas over the Big Bill Simpson prospect in an attempt to high grade our next well’s position on this acreage. In addition, we are considering a proprietary 3-D shoot in Burleson County, Texas to help us select potential drill sites on other deep Bossier prospects in this area.

	Three Months Ended
	March 31,
	2008			2007
Oil and Gas Production Data:
Gas (MMcf)		5,548			4,327
Oil (MBbls)		684			543
Natural gas liquids (MBbls)		58			46
Total (MMcfe)		10,000			7,861

Average Realized Prices (a):
Gas ($/Mcf)	$	8.86		$	6.91
Oil ($/Bbl)	$	96.37		$	55.21
Natural gas liquids ($/Bbl)	$	54.83		$	33.30

Gain (Losses) on Settled Derivative Contracts (a):
($ in thousands, except per unit)
Gas: Net realized gain (loss)	$	(884	)	$	4,509
Per unit produced ($/Mcf)	$	(0.16	)	$	1.04
Oil: Net realized loss	$	(12,906	)	$	(2,559	)
Per unit produced ($/Bbl)	$	(18.87	)	$	(4.71	)

Average Daily Production:
Natural Gas (Mcf):
Permian Basin		15,562			15,389
North Louisiana		13,596			2,409
South Louisiana		23,552			20,121
Austin Chalk (Trend)		2,460			2,011
Cotton Valley Reef Complex		5,270			7,697
Other		527			451
Total		60,967			48,078

Oil (Bbls):
Permian Basin		3,494			3,096
North Louisiana		343			29
South Louisiana		985			1,172
Austin Chalk (Trend)		2,635			1,672
Other		59			64
Total		7,516			6,033

Natural Gas Liquids (Bbls):
Permian Basin		215			199
Austin Chalk (Trend)		272			265
Other		150			47
Total		637			511

	Three Months Ended
	March 31,
	2008		2007
Exploration Costs (in thousands):
Abandonment and impairment costs:
North Louisiana	$	297	$	306
South Louisiana		-		7,179
Permian Basin		-		43
Utah		-		3,577
Total		297		11,105

Seismic and other		3,675		890
Total exploration costs	$	3,972	$	11,995

Depreciation, Depletion and Amortization (in thousands):
Oil and gas depletion	$	27,741	$	13,548
Contract drilling depreciation		2,285		1,383
Other depreciation		247		300
Total DD&A	$	30,273	$	15,231

Oil and Gas Costs ($/Mcfe Produced):
Production costs	$	2.06	$	2.20
Oil and gas depletion	$	2.77	$	1.72

Net Wells Drilled (b):
Exploratory Wells		1.7		5.0
Developmental Wells		12.9		3.5

(a) No derivatives were designated as cash flow hedges in 2008 or 2007. 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.

Oil and gas sales in 2008 increased $57.7 million, or 94%, from 2007, of which price variances accounted for a $40.5 million increase and production variances accounted for a $17.2 million increase. Production in 2008 (on an Mcfe basis) was 27% higher than 2007. Oil production increased 26% and gas production increased 28% in 2008 from 2007 due primarily to incremental production attributable to drilling activity in North and South Louisiana, the Permian Basin and Austin Chalk (Trend). In 2008, our realized oil price was 75% higher than 2007, while our realized gas price was 28% higher. 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 19% in 2008 as compared to 2007 due primarily to higher production tax costs related to higher commodity prices. In addition, a combination of factors including increased oil and gas production, rising oilfield service costs, and higher repair and maintenance costs contributed to the rise in production costs. It is likely that these factors will continue to contribute to higher production costs in future periods. After giving effect to a 27% increase in oil and gas production on an Mcfe basis, production costs per Mcfe decreased 6% from $2.20 per Mcfe in 2007 to $2.06 per Mcfe in 2008.

Oil and gas depletion expense increased $14.2 million from 2007 to 2008, of which production variances accounted for a $3.7 million increase and rate variances accounted for a $10.5 million increase. On an Mcfe basis, depletion expense increased 61% from $1.72 per Mcfe in 2007 to $2.77 per Mcfe in 2008 due in part to a higher depletable cost basis in 2008 compared to the 2007 period. Depletion expense per Mcfe of oil and gas production is an operating metric that is indicative of our weighted average cost to find or acquire a unit of equivalent production. We may realize higher oil and gas depletion rates in future periods if our exploration activities result in higher finding costs.

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 2008, we charged to expense $297,000 of exploration costs, as compared to $11.1 million in 2007. All of the 2008 costs were incurred in Louisiana.

We plan to spend approximately $344.5 million on exploration and development activities in 2008, of which approximately 32% is expected to be allocated to exploration activities. Since exploratory drilling involves a high degree of risk, it is likely that a significant portion of the costs we incur in 2008 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.

In April 2006, we formed a joint venture (“Larclay JV”) with Lariat Services, Inc. to construct, own, and operate 12 new drilling rigs. We own a 50% interest in Larclay JV. Although the Company and Lariat own equal interests in Larclay JV, the Company meets the definition of the primary beneficiary of Larclay JV’s expected cash flows under FIN 46R. As the primary beneficiary under FIN 46R, the Company is required to include the accounts of Larclay JV in the Company’s consolidated financial statements. During the three months ended March 31, 2008, we included contract drilling revenues of $14.8 million, other operating expenses of $11.4 million, depreciation expense of $2.3 million and interest expense of $1.1 million in our statement of operations (see Note 15 to the consolidated financial statements). Since the Larclay JV drilling rigs are partially utilized by us, the reported amounts are net of any intercompany profits eliminated in consolidation.

General and administrative (“G&A”) expenses decreased 12% from $3.9 million in 2007 to $3.4 million in 2008. Excluding non-cash employee compensation, G&A expenses decreased from $3.3 million in 2007 to $3.1 million in 2008 due primarily to a decrease in professional fees. In 2008, we recorded a $250,000 non-cash compensation charge related to our after payout incentive plan and $92,000 for stock-based employee compensation. In 2007, we recorded a $500,000 non-cash compensation charge related to our after payout incentive plan and $110,000 for stock-based employee compensation.

Interest expense decreased 2% from $7.6 million in 2007 to $7.4 million in 2008 due to a combination of factors. In 2007 and 2008, we used our revolving loan facility to partially finance our exploration and development activities. The average daily principal balance outstanding under our revolving credit facility for 2008 was $174.5 million compared to $159.1 million for 2007 resulting in an increase in interest expense of approximately $300,000 which was offset by an $800,000 decrease in interest due to lower interest rates. Capitalized interest for 2008 was $793,000 compared to $973,000 in 2007. We also included $1.1 million of interest expense associated with our Larclay JV during 2008 compared to $834,000 in 2007.

We did not designate any derivative contracts in 2008 or 2007 as cash flow hedges; therefore all cash settlements and changes resulting from mark-to-market valuations have been recorded as gain/loss on derivatives. For the three months ended March 31, 2008, we reported a $46.1 million net loss on derivatives, consisting of a $32 million non-cash loss to mark our derivative positions to their fair value at March 31, 2008 and a $14.1 million realized loss on settled contracts. For the three months ended March 31, 2007, we reported a $16.8 million net loss on derivatives, consisting of an $18.8 million non-cash loss to mark our derivative positions to their fair value at March 31, 2007 and a $2 million realized gain on settled contracts.

Loss on sales of property and equipment for 2008 was $9,000 compared to $9.3 million in 2007. We recorded losses on inventory during 2007 of $9.2 million, including a non-cash charge of $8.9 million to write-down inventory to its estimated market value at March 31, 2007. The write-down resulted primarily from the sale of certain surplus equipment at an auction in March 2007. No write-downs were recorded during the 2008 period.

Our primary financial resource is our base of oil and gas reserves. We pledge our producing oil and gas properties to a group of banks to secure our revolving credit facility. The banks establish a borrowing base by making an estimate of the collateral value of our oil and gas properties. We borrow funds on the revolving credit facility as needed to supplement our operating cash flow as a financing source for our capital expenditure program. Our ability to fund our capital expenditure program is dependent upon the level of product prices and the success of our exploration program in replacing our existing oil and gas reserves. If product prices decrease, our operating cash flow may decrease and the banks may require additional collateral or reduce our borrowing base, thus reducing funds available to fund our capital expenditure program. The effects of product prices on cash flow can be mitigated through the use of commodity derivatives. If we are unable to replace our oil and gas reserves through our exploration program, we may also suffer a reduction in our operating cash flow and access to funds under the revolving credit facility. Under extreme circumstances, product price reductions or exploration drilling failures could allow the banks to seek to foreclose on our oil and gas properties, thereby threatening our financial viability.

In 2005, we issued $225 million of aggregate principal amount of Senior Notes and used the net proceeds to repay all amounts outstanding on the revolving credit facility at that time. However, we relied on advances under the revolving credit facility to finance a portion of our exploration and development activities in 2007 and the first quarter of 2008. At March 31, 2008, we had $155 million outstanding on the revolving credit facility. Subsequent to March 31, 2008, we reduced our revolving credit facility to approximately $60 million with proceeds from the sales of assets.

Our 2008 expenditures may exceed our cash flow from operating activities in 2008. We cannot predict our drilling success on exploratory prospects, and our future results of operations and financial condition could be adversely affected by unsuccessful exploratory drilling results. In this section, we will describe our current plans for capital spending, identify the capital resources available to finance our capital spending, and discuss the principal factors that can affect our liquidity and capital resources.

We incurred expenditures for exploration and development activities of $57.7 million during the first three months of 2008 and have increased our estimates for planned expenditures for fiscal 2008 from $256.5 million to $344.5 million. The following table summarizes, by area, our actual expenditures for exploration and development activities for the first quarter of 2008 and our planned expenditures for the year ending December 31, 2008.

	Actual		Planned
	Expenditures		Expenditures		Year 2008
	Three Months Ended		Year Ending		Percentage
	March 31, 2008		December 31, 2008		of Total
	(In thousands)
Permian Basin	$	21,500	$	168,000		49	%
North Louisiana		14,800		62,600		18	%
Austin Chalk (Trend)		10,800		55,400		16	%
East Texas Bossier		6,900		28,600		8	%
South Louisiana		2,700		18,700		6	%
Utah/California		900		10,900		3	%
Other		100		300		-
	$	57,700	$	344,500		100	%

Approximately 32% of the 2008 planned expenditures relate to exploratory prospects. Exploratory prospects involve a higher degree of risk than developmental prospects. To offset the higher risk, we generally strive to achieve a higher reserve potential and rate of return on investments in exploratory prospects. We do not attempt to forecast our success rate on exploratory drilling. Accordingly, these current estimates do not include costs we may incur to complete any future successful exploratory wells and construct the required production facilities for these wells. Also, we are actively searching for other opportunities to increase our oil and gas reserves, including the evaluation of new prospects for exploratory and developmental drilling activities and potential acquisitions of proved oil and gas properties. We cannot predict our drilling success on exploratory prospects, and our future results of operations and financial condition could be adversely affected by unsuccessful exploratory drilling results.

Our expenditures for exploration and development activities for the three months ended March 31, 2008 totaled $57.7 million, of which approximately 21% was on exploratory prospects. We currently plan to spend approximately $344.5 million for the calendar year 2008, of which approximately 32% is estimated to be spent on exploratory prospects. Our 2008 expenditures may also exceed our cash flow from operating activities in 2008. To the extent possible, we intend to finance this shortfall by borrowings on the revolving credit facility. Our internal cash flow forecasts indicate that the amount of funds available to us under our revolving credit facility, when combined with our anticipated operating cash flow, will be sufficient to finance our capital expenditures and will provide us with adequate liquidity at least through 2008. Although we believe the assumptions and estimates made in our forecasts are reasonable, uncertainties exist which could cause the borrowing base to be less than expected, cash flow to be less than expected, or capital expenditures to be more than expected. In the event we lack adequate liquidity to finance our expenditures in 2008, we will consider options for alternative capital resources, including the sale of assets.

Cash flow provided by operating activities for the three months ended March 31, 2008 increased $41.8 million, or 115%, as compared to the corresponding period in 2007. Approximately $2.4 million of the increase in operating cash flow was attributable to Larclay JV. All of Larclay JV’s cash flow is dedicated to the repayment of a $75 million secured term loan facility. The remainder of the increase in operating cash flow was derived primarily from oil and gas producing activities, offset in part by increases in production costs and seismic expense.

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.

During the first three months in 2008, we repaid $10.8 million on the revolving credit facility from excess cash flow from operating activities. At March 31, 2008, we had a borrowing base of $275 million, leaving $119.2 million available under the revolving loan facility after accounting for outstanding letters of credit of $804,000. Subsequent to March 31, 2008, the borrowing base was reduced to $250 million after the sale of assets.

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

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 $76.4 million at December 31, 2007 to $23.3 million at March 31, 2008 due primarily to a combination of factors, including an increase in assets held for sale, decreases in inventory and an increase in the net liability for the fair value for derivatives. After giving effect to the adjustments, our working capital computed for loan compliance purposes was a positive $190.4 million at March 31, 2008, as compared to a positive $103.2 million at December 31, 2007. The following table reconciles our GAAP working capital to the working capital computed for loan compliance purposes at March 31, 2008 and December 31, 2007.

	March 31,			December 31,
	2008			2007
	(In thousands)
Working capital (deficit) per GAAP	$	(23,343	)	$	(76,388	)
Add funds available under the revolving credit facility		119,196			108,396
Exclude fair value of derivatives classified as current assets or current liabilities		71,646			49,738
Exclude current assets and current liabilities of Larclay JV		22,889			21,423
Working capital per loan covenant	$	190,388		$	103,169

Since we use this revolving credit facility for both short-term liquidity and long-term financing needs, it is important that we comply in all material respects with the loan agreement, including financial covenants that are computed quarterly. The working capital covenant requires us to maintain positive working capital using the computations described above. Another financial covenant under the credit facility requires us to maintain a ratio of indebtedness to cash flow of no more than 3 to 1. While we were in compliance with all financial and non-financial covenants at March 31, 2008, our increased leverage and reduced liquidity may result in our failing to comply with one or more of these covenants in the future. If we fail to meet any of these loan covenants, we would ask the banks to allow us sufficient time to obtain additional capital resources through alternative means. If a suitable arrangement could not be reached with the banks, the banks could accelerate the indebtedness and seek to foreclose on the pledged assets.

The banks redetermine the borrowing base under the revolving credit facility at least twice a year, in May and November. The November 2007 borrowing base review resulted in maintaining the borrowing base at $275 million. If at any time, the borrowing base is less than the amount of outstanding indebtedness, we will be required to (i) pledge additional collateral, (ii) prepay the excess in not more than five equal monthly installments, or (iii) elect to convert the entire amount of outstanding indebtedness to a term obligation based on amortization formulas set forth in the loan agreement. We have relied heavily on advances under the revolving credit facility to finance a significant portion of our exploration and development activities in fiscal 2007 and the first quarter of 2008. At March 31, 2008, we had $155 million outstanding on the revolving credit facility. Subsequent to March 31, 2008, the borrowing base was reduced to $250 million after the sale of assets.

In July 2005, we issued, in a private placement, $225 million of aggregate principal amount of Senior Notes. The Senior Notes were issued at face value and bear interest at 7¾% per year, payable semi-annually on February 1 and August 1 of each year, beginning February 1, 2006. After the payment of typical transaction expenses, net proceeds of approximately $217 million were used to repay amounts outstanding on our secured credit facilities and for general corporate purposes, including the funding of planned exploration and development activities.

At any time prior to August 1, 2008, we may redeem up to 35% of the aggregate principal amount of the Senior Notes with the proceeds of certain equity offerings at a redemption price of 107.75% of the principal amount, plus accrued and unpaid interest. In addition, prior to August 1, 2009, we may redeem some or all of the Senior Notes at a redemption price equal to 100% of the principal amount of the Senior Notes to be redeemed, plus a make-whole premium, plus any accrued and unpaid interest. On and after August 1, 2009, we may redeem some or all of the Senior Notes at redemption prices (expressed as percentages of principal amount) equal to 103.875% for the twelve-month period beginning on August 1, 2009, 101.938% for the twelve-month period beginning on August 1, 2010, and 100.00% beginning on August 1, 2011, for any period thereafter, in each case plus accrued and unpaid interest.

The Indenture governing the Senior Notes restricts our ability and the ability of our restricted subsidiaries to: (i) borrow money; (ii) issue redeemable and preferred stock; (iii) pay distributions or dividends; (iv) make investments; (v) create liens without securing the Notes; (vi) enter into agreements that restrict dividends from subsidiaries; (vii) sell certain assets or merge with or into other companies; (viii) enter into transactions with affiliates; (ix) guarantee indebtedness; and (x) enter into new lines of business. These covenants are subject to a number of important exceptions and qualifications. We were in compliance with these covenants at March 31, 2008.

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.

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, 2007 reserve estimates, we project that a $1 drop in the price per Bbl of oil and a $.50 drop in the price per Mcf of gas from year end 2007 would reduce our gross revenues for the year ending December 31, 2008 by $12.4 million.

From time to time, we utilize commodity derivatives, consisting primarily of swaps, floors and collars to attempt to optimize the price received for our oil and natural gas production. When using swaps to hedge our oil and natural gas production, we receive a fixed price for the respective commodity and pay a floating market price as defined in each contract (generally NYMEX futures prices), resulting in a net amount due to or from the counterparty. When purchasing floors, we receive a fixed price (put strike price) if the market price falls below the put strike price for the respective commodity. If the market price is greater than the put strike price, no payments are due from either party. Costless collars are a combination of puts and calls, and contain a fixed floor price (put strike price) and ceiling price

(call strike price). If the market price for the respective commodity exceeds the call strike price or falls below the put strike price, then we receive the fixed price and pay the market price. If the market price is between the call and the put strike prices, no payments are due from either party. The commodity derivatives we use differ from futures contracts in that there is not a contractual obligation that requires or permits the future physical delivery of the hedged products. We do not enter into commodity derivatives for trading purposes. In addition to commodity derivatives, we may, from time to time, sell a portion of our gas production under short-term contracts at fixed prices.

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

We are exposed to interest rate risk on our long-term debt with a variable interest rate. At March 31, 2008, our variable rate debt had a carrying value of $155 million, which approximated its fair value. At March 31, 2008, our fixed rate debt had a carrying value of $225 million and an approximate fair value of $194.6 million, based on current market quotes. We estimate that the hypothetical change in the fair value of our fixed-rate, long-term debt resulting from a 100-basis point change in interest rates would be approximately $7.9 million. Based on our outstanding variable rate indebtedness at March 31, 2008 of $155 million, a change in interest rates of 100 basis points would affect annual interest payments by approximately $1.6 million.

In September 2002, our Board of Directors adopted a policy designed to establish disclosure controls and procedures that are adequate to provide reasonable assurance that our management will be able to collect, process and disclose both financial and non-financial information, on a timely basis, in our reports to the Securities and Exchange Commission (“SEC”) and other communications with our stockholders. Disclosure controls and procedures include all processes necessary to ensure that material information is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and is accumulated and communicated to our management, including our chief executive and chief financial officers, to allow timely decisions regarding required disclosures.

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

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, 2007, as filed with the U.S. Securities and Exchange Commission on March 14, 2008 and available at www.sec.gov. There have been no material changes to these risk factors since the filing of our Form 10-K.

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

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

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

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

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

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

*32.1	Certifications by the Chief Executive Officer and Chief Financial Officer of the Company pursuant to 18 U.S.C. § 1350

(Mark One)
x	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
	OF THE SECURITIES EXCHANGE ACT OF 1934
	For the quarterly period ended March 31, 2008

¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
	OF THE SECURITIES EXCHANGE ACT OF 1934
	For the transition period from to
	Commission File Number 001-10924

Delaware		75-2396863
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)
Six Desta Drive - Suite 6500
Midland, Texas		79705-5510
(Address of principal executive offices)		(Zip code)
Registrant’s telephone number, including area code:		(432) 682-6324

PART I. FINANCIAL INFORMATION
		Page

Item 1.	Financial Statements

	Consolidated Balance Sheets as of March 31, 2008
	and December 31, 2007	3

	Consolidated Statements of Operations for the three months
	ended March 31, 2008 and 2007	5

	Consolidated Statements of Stockholders’ Equity for the three months
	ended March 31, 2008	6

	Consolidated Statements of Cash Flows for the three months
	ended March 31, 2008 and 2007	7

	Notes to Consolidated Financial Statements	8

Item 2.	Management’s Discussion and Analysis of Financial
	Conditions and Results of Operations	22

Item 3.	Quantitative and Qualitative Disclosure About Market Risks	33

Item 4.	Controls and Procedures	35


PART II. OTHER INFORMATION
Item 1A.	Risk Factors	36

Item 6.	Exhibits	36

	Signatures	37

	March 31,			December 31,
	2008			2007
	(In thousands)
7¾% Senior Notes, due 2013	$	225,000		$	225,000
Secured bank credit facility, due May 2009		155,000			165,800
Secured term loan of Larclay JV, due June 2011		55,313			61,875
		435,313			452,675
Less current maturities(a)		(20,625	)		(22,500	)
	$	414,688		$	430,175

(a) Consists of current portion of term loan of Larclay JV.

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
	x Yes		¨ No

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

	Outstanding and Exercisable Options
			Weighted
		Weighted	Average
		Average	Remaining
		Exercise	Life in
	Shares	Price	Years
Range of exercise prices:
$5.50	33,485	$ 5.50	1.1
$10.00 - $19.74	10,000	$ 11.93	3.1
$22.90 - $41.74	22,000	$ 31.65	7.2
	65,485	$ 15.27	3.5

	Gas						Oil
	MMBtu (a)		Floor		Ceiling		Bbls		Floor		Ceiling
Production Period:
2nd Quarter 2008		426,000	$	4.00	$	5.15		132,000	$	23.00	$	25.07
3rd Quarter 2008		419,000	$	4.00	$	5.15		128,000	$	23.00	$	25.07
		845,000						260,000

			Fixed
	Principal		Libor
	Balance		Rates
Period:
April 1, 2008 to September 24, 2008(a)	$	100,000,000		4.73	%
April 1, 2008 to November 3, 2008	$	45,000,000		5.73	%

(a) In April 2008, the Company terminated this $100 million interest rate swap for a cash payment of $899,000.

Date:	May 9, 2008	By:	/s/ L. Paul Latham
			L. Paul Latham
			Executive Vice President and Chief
			Operating Officer

Date:	May 9, 2008	By:	/s/ Mel G. Riggs
			Mel G. Riggs
			Senior Vice President and Chief Financial
			Officer

	Gas				Oil
	MMBtu (a)		Price		Bbls		Price
Production Period:
2nd Quarter 2008		4,650,000	$	9.20		330,000	$	79.84
3rd Quarter 2008		4,200,000	$	9.15		310,000	$	78.96
4th Quarter 2008		4,200,000	$	9.15		400,000	$	82.21
2009		3,600,000	$	9.33		1,440,000	$	85.30
		16,650,000				2,480,000

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