cwei10q.htm

ASSETS
	June 30,			December 31,
	2007			2006
	(Unaudited)
CURRENT ASSETS
Cash and cash equivalents	$	8,286		$	13,840
Accounts receivable:
Oil and gas sales		31,373			23,398
Joint interest and other, net		22,353			17,810
Affiliates		575			2,436
Inventory		19,114			40,392
Deferred income taxes		505			505
Fair value of derivatives		9,020			23,729
Prepaids and other		5,554			3,888
		96,780			125,998

PROPERTY AND EQUIPMENT
Oil and gas properties, successful efforts method		1,310,813			1,226,761
Natural gas gathering and processing systems		18,130			18,068
Contract drilling equipment		86,553			66,418
Other		15,871			15,848
		1,431,367			1,327,095
Less accumulated depreciation, depletion and amortization		(717,469	)		(682,286	)
Property and equipment, net		713,898			644,809


OTHER ASSETS
Debt issue costs, net		7,622			8,104
Fair value of derivatives		9			1,785
Other		23,121			14,737
		30,752			24,626
	$	841,430		$	795,433

LIABILITIES AND STOCKHOLDERS' EQUITY
	June 30,		December 31,
	2007		2006
	(Unaudited)
CURRENT LIABILITIES
Accounts payable:
Trade	$	65,361	$	75,815
Oil and gas sales		21,407		14,222
Affiliates		1,938		1,407
Current maturities of long-term debt		26,250		17,397
Fair value of derivatives		33,606		29,722
Accrued liabilities and other		10,698		10,503
		159,260		149,066

NON-CURRENT LIABILITIES
Long-term debt		454,250		413,876
Deferred income taxes		34,101		36,409
Fair value of derivatives		12,148		21,281
Other		34,111		29,821
		534,610		501,387

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 – 11,352,051 shares in 2007
and 11,152,051 shares in 2006		1,135		1,115
Additional paid-in capital		120,025		113,965
Retained earnings		26,400		29,900
		147,560		144,980
	$	841,430	$	795,433

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2007			2006			2007			2006
REVENUES
Oil and gas sales	$	74,893		$	66,443		$	136,073		$	126,624
Natural gas services		2,909			2,789			5,563			5,985
Drilling rig services		14,228			374			22,645			374
Gain on sales of assets		534			735			784			752
Total revenues		92,564			70,341			165,065			133,735

COSTS AND EXPENSES
Production		17,840			15,931			35,118			30,896
Exploration:
Abandonments and impairments		23,519			3,329			34,624			16,172
Seismic and other		1,580			2,587			2,470			5,688
Natural gas services		2,904			2,261			5,317			5,090
Drilling rig services		8,506			216			13,439			216
Depreciation, depletion and amortization		18,487			15,982			33,718			30,692
Impairment of property and equipment		479			-			1,044			-
Accretion of abandonment obligations		619			417			1,237			796
General and administrative		4,932			4,252			8,835			8,319
Loss on sales of assets		-			-			9,323			13
Total costs and expenses		78,866			44,975			145,125			97,882

Operating income		13,698			25,366			19,940			35,853

OTHER INCOME (EXPENSE)
Interest expense		(7,986	)		(4,961	)		(15,615	)		(9,300	)
Gain (loss) on derivatives		6,110			245			(10,739	)		(1,327	)
Other		3,614			450			4,327			1,068
Total other income (expense)		1,738			(4,266	)		(22,027	)		(9,559	)

Income (loss) before income taxes		15,436			21,100			(2,087	)		26,294
Income tax (expense) benefit		(5,357	)		(3,094	)		723			(4,912	)
Minority interest, net of tax		(1,269	)		(40	)		(2,136	)		(40	)

NET INCOME (LOSS)	$	8,810		$	17,966		$	(3,500	)	$	21,342

Net income (loss) per common share:
Basic	$	0.78		$	1.66		$	(0.31	)	$	1.97
Diluted	$	0.77		$	1.59		$	(0.31	)	$	1.89

Weighted average common shares outstanding:
Basic		11,352			10,850			11,236			10,845
Diluted		11,507			11,286			11,236			11,294

	Six Months Ended
	June 30,
	2007			2006
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	(3,500	)	$	21,342
Adjustments to reconcile net income (loss) to cash
provided by operating activities:
Depreciation, depletion and amortization		33,718			30,692
Impairment of property and equipment		1,044			-
Exploration costs		34,624			16,172
(Gain) loss on sales of assets, net		8,539			(739	)
Deferred income taxes		(723	)		4,912
Non-cash employee compensation		1,110			1,151
Unrealized (gain) loss on derivatives		11,236			(14,283	)
Settlements on derivatives with financing elements		12,005			15,508
Amortization of debt issue costs		625			735
Accretion of abandonment obligations		1,237			796
Minority interest, net of tax		2,136			40

Changes in operating working capital:
Accounts receivable		(10,657	)		86
Accounts payable		(1,005	)		143
Other		(453	)		493
Net cash provided by operating activities		89,936			77,048

CASH FLOWS FROM INVESTING ACTIVITIES
Additions to property and equipment		(120,435	)		(134,857	)
Additions to equipment of Larclay JV.		(23,415	)		(31,607	)
Proceeds from sales of property and equipment		1,602			684
Change in equipment inventory		11,835			(1,701	)
Other		(8,269	)		815
Net cash used in investing activities		(138,682	)		(166,666	)

CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt		40,500			79,700
Proceeds from long-term debt of Larclay JV		8,727			36,197
Repayments of long-term debt		-			(12	)
Proceeds from sale of common stock		5,970			175
Settlements on derivatives with financing elements		(12,005	)		(15,508	)
Net cash provided by financing activities		43,192			100,552

NET INCREASE (DECREASE) IN CASH AND
CASH EQUIVALENTS		(5,554	)		10,934

CASH AND CASH EQUIVALENTS
Beginning of period		13,840			5,935
End of period	$	8,286		$	16,869

SUPPLEMENTAL DISCLOSURES
Cash paid for interest, net of amounts capitalized	$	15,283		$	8,394

Clayton Williams Energy, Inc. (a Delaware corporation) and its subsidiaries (collectively, the “Company” or “CWEI”) is an independent oil and gas company engaged in the exploration for and development and production of oil and natural gas primarily in its core areas in Texas, Louisiana and New Mexico. Approximately 20% of the Company’s outstanding common stock is beneficially owned by Clayton W. Williams, Jr. (“Mr. Williams”), Chairman of the Board and Chief Executive Officer of the Company, and approximately 27% is owned by a partnership in which Mr. Williams’ adult children are limited partners.

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

The preparation of these consolidated financial statements in conformity with accounting principles generally accepted in the United States requires management of the Company to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ materially from those estimates.

The consolidated financial statements include the accounts of Clayton Williams Energy, Inc., its wholly-owned subsidiaries and the accounts of the Larclay JV (see Note 11). The Company also accounts for its undivided interests in oil and gas limited partnerships using the proportionate consolidation method, whereby its share of assets, liabilities, revenues and expenses are consolidated with other operations. All significant intercompany transactions and balances associated with the consolidated operations have been eliminated.

In the opinion of management, the Company's unaudited consolidated financial statements as of June 30, 2007 and for the interim periods ended June 30, 2007 and 2006 include all adjustments which are necessary for a fair presentation in accordance with accounting principles generally accepted in the United States. These interim results are not necessarily indicative of the results to be expected for the year ending December 31, 2007.

Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States have been condensed or omitted in this Form 10-Q pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”). These consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto included in the Company's Form 10-K for the year ended December 31, 2006.

In February 2007, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 159 The Fair Value Option for Financial Assets and Financial Liabilities - Including an Amendment of FASB Statement No. 115 (“SFAS 159”). SFAS 159 permits an entity to choose to measure many financial instruments and certain other items at fair value. The fair value option established by SFAS 159 permits all entities to choose to measure eligible items at fair value at specified election dates. Unrealized gains and losses on items for which the fair value option has been elected are to be recognized in earnings at each

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. The Company plans to adopt SFAS 157 beginning in the first quarter of 2008. The Company is currently evaluating the impact, if any, the adoption of SFAS 157 will have on its consolidated financial position or results of operations.

In September 2006, the SEC issued Staff Accounting Bulletin No. 108 (“SAB 108”), which became effective on January 1, 2007. SAB 108 provides guidance on the consideration of the effects of prior period misstatements in quantifying current year misstatements for the purpose of a materiality assessment. SAB 108 requires an entity to evaluate the impact of correcting all misstatements, including both the carryover and reversing effects of prior year misstatements, on current year financial statements. If a misstatement is material to the current year financial statements, the prior year financial statements should also be corrected, even though such revision was, and continues to be, immaterial to the prior year financial statements. Correcting prior year financial statements for immaterial errors would not require previously filed reports to be amended. Such correction should be made in the current period filings. The adoption of SAB 108 had no effect on the Company’s consolidated financial statements.

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

	June 30,			December 31,
	2007			2006
	(In thousands)
7¾% Senior Notes due 2013	$	225,000		$	225,000
Secured bank credit facility, due May 2009		180,500			140,000
Secured term loan of Larclay JV, due June 2011		75,000			66,273
		480,500			431,273
Less current maturities^(a)		(26,250	)		(17,397	)
	$	454,250		$	413,876

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

In July 2005, the Company issued, in a private placement, $225 million of aggregate principal amount of 7¾% Senior Notes due 2013 (“Senior Notes”). The Senior Notes were issued at face value and bear interest at 7¾% per year, payable semi-annually on February 1 and August 1 of each year, beginning February 1, 2006. After the payment of typical transaction expenses, net proceeds of approximately $217 million were used to repay all amounts outstanding under the secured bank credit facilities and for general corporate purposes, including the funding of planned exploration and development activities.

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

The Indenture governing the Senior Notes restricts the ability of the Company and its restricted subsidiaries to: (i) borrow money; (ii) issue redeemable and preferred stock; (iii) pay distributions or dividends; (iv) make investments; (v) create liens without securing the Senior Notes; (vi) enter into agreements that restrict dividends from subsidiaries; (vii) sell certain assets or merge with or into other companies; (viii) enter into transactions with affiliates; (ix) guarantee indebtedness; and (x) enter into new lines of business. The Company was in compliance with these covenants at June 30, 2007.

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 June 30, 2007, 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 $93.7 million available under the credit facility at June 30, 2007.

The revolving credit facility provides for interest at rates based on the agent bank’s prime rate plus margins ranging from .25% to 1%, or if elected by the Company based on LIBOR plus margins ranging from 1.5% to 2.25%. The Company also pays a commitment fee on the unused portion of the revolving credit facility. Interest and fees are payable at least quarterly. The effective annual interest rate on borrowings under the credit facility, excluding bank fees and amortization of debt issue costs, for the six months ended June 30, 2007 was 7.5%.

The loan agreement applicable to the revolving credit facility contains financial covenants that are computed quarterly. The working capital covenant requires the Company to maintain a ratio of current assets to current liabilities of at least 1 to 1. Another financial covenant under the credit facility requires the Company to maintain a ratio of indebtedness to cash flow of no more than 3 to 1. The computations of current assets, current liabilities, cash flow and indebtedness are defined in the loan agreement. The Company was in compliance with all financial and non-financial covenants at June 30, 2007.

In connection with the Company’s investment in Larclay JV (see Note 11), Larclay JV obtained a $75 million secured term loan facility from a lender to finance the construction and equipping of 12 new drilling rigs. The Larclay JV term loan is secured by substantially all of the assets of Larclay JV. Initially, the Company pledged additional collateral in the form of a $19 million letter of credit. In February 2007, the letter of credit was cancelled and replaced by a $19.5 million guaranty from the Company. In March 2007, the Company issued a $5 million letter of credit which expired in June 2007 as additional collateral under the term loan to cover any temporary shortfall in collateral value caused by delays in completing construction of the final drilling rigs being financed by the lender. Concurrently, the guaranty was amended to limit the Company’s combined credit exposure under the guaranty and the letter of credit to $19.5 million. 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 June 30, 2007, the effective interest rate on the Larclay JV term loan was 8.7%.

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 June 30, 2007 expire 10 years from the date of grant and become exercisable based on varying vesting schedules. The Company issues new shares, not repurchased shares, to option holders that exercise stock options under the 1993 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 48,000 shares of common stock at option prices ranging from $3.25 to $41.74 per share. All outstanding options expire 10 years from the grant date and are fully exercisable upon issuance.

						Weighted
				Weighted		Average
				Average		Remaining		Aggregate
				Exercise		Contractual		Intrinsic
	Shares			Price		Term in Years		Value (a)
Outstanding at January 1, 2007		1,009,485		$	22.27
Granted		4,000		$	36.31
Exercised (b)		(200,000	)	$	29.85
Outstanding at June 30, 2007		813,485		$	20.47		5.6	$	4,877,471

Vested at June 30, 2007		813,485		$	20.47		5.6	$	4,877,471
Exercisable at June 30, 2007		813,485		$	20.47		5.6	$	4,877,471

The Compensation Committee of the Board of Directors has adopted an incentive plan for officers, key employees and consultants, excluding Mr. Williams, who promote the Company’s drilling and acquisition programs. Management’s objective in adopting this plan is to further align the interests of the participants with those of the Company by granting the participants an after-payout interest in the production developed, directly or indirectly, by the participants. The plan generally provides for the creation of a series of partnerships or participation arrangements (“APO Arrangements”) between the Company and the participants to which the Company contributes a portion of its economic interest in wells drilled or acquired within certain areas. Generally, the Company pays all costs and receives all revenues until 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 $1 million of non-cash compensation expense during each of the six-month periods ended June 30, 2007 and 2006 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.

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 June 30, 2007.

The Company accounts for its derivatives in accordance with SFAS No. 133 Accounting for Derivative Instruments and Hedging Activities (“SFAS 133”), as amended. The Company did not designate any of its currently open commodity or interest rate derivatives as cash flow hedges; therefore, all changes in the fair value of these contracts prior to maturity, plus any realized gains or losses at maturity, are recorded as other income (expense) in the Company’s statements of operations. For the six months ended June 30, 2007, the Company reported a $10.7 million loss on derivatives, consisting of an $11.2 million loss related to changes in mark-to-market valuations and a $500,000 realized gain on settled contracts. For the six months ended June 30, 2006, loss on derivatives was $1.3 million, consisting of a $14.3 million gain related to changes in mark-to-market valuations and a $15.6 million realized loss 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 June 30, 2007 and December 31, 2006 was approximately $207 million and $207.6 million, respectively.

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 assets 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 June 30, 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.

The Company’s effective federal and state income tax rate for the six months ended June 30, 2007 of 34.6% differed from the statutory federal rate of 35% due to tax benefits derived from statutory depletion deductions, offset in part by increases in the tax provision related primarily to the effects of the recently-enacted Texas Margin Tax and certain non-deductible expenses.

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

The Company adopted FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes (“FIN 48”), effective January 1, 2007. Upon adoption of FIN 48, the Company recorded a $1.6 million liability for taxes payable related to unrecognized tax benefits arising from uncertain tax positions taken by the Company in previous periods. No additional unrecognized tax benefits originated during the six months ended June 30, 2007. The tax liability recorded under FIN 48 is included in other non-current liabilities in the accompanying consolidated balance sheet at June 30, 2007.

All of the unrecognized tax benefits at June 30, 2007 relate to tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductions. Because of the impact of deferred tax accounting, the disallowance of the shorter deduction period would not affect the annual effective tax rate but would only change the amount of deferred tax assets related to net operating loss carryforwards.

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.

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. Eleven of the rigs were fully constructed at June 30, 2007. Equipment rig up on the remaining rig has been temporarily suspended. To date, construction costs of all rigs, excluding capitalized interest, has totaled approximately $83.3 million. A lender has provided a $75 million secured term loan to Larclay JV to finance most of the cost of constructing and initially equipping the rigs. The Company is not a maker on the Larclay JV term loan, but it is providing partial credit support for the Larclay JV term loan (see Note 4).

Also in April 2006, the Company entered into a three-year drilling contract with Larclay JV assuring the availability of each rig for use in the ordinary course of the Company’s exploration and development drilling program throughout the term of the drilling contract. The provisions of the drilling contract provide that the Company contract for each rig on a well-by-well basis at then current market rates. If a rig is not needed by the Company at any time during the term of the contract, Larclay JV may contract with other operators for the use of such rig, subject to certain restrictions. If a rig is idle, the Company will pay Larclay JV an idle rig rate ranging from $8,100 per day to $10,300 per day (plus crew labor expenses, if applicable), depending on the size of the rig. The Company’s maximum potential obligation to pay idle rig rates over the term of this drilling contract, excluding any crew labor expenses, totals approximately $95.4 million at June 30, 2007.

Although the Company and Lariat own equal interests in Larclay JV, the Company meets the definition of the primary beneficiary of Larclay JV’s expected cash flows under FIN 46R. As the primary beneficiary under FIN 46R, the Company is required to include the accounts of Larclay JV in the Company’s consolidated financial statements. As of June 30, 2007, Lariat’s equity ownership in the net assets of Larclay JV was $3.2 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.

In accordance with SFAS No. 131 Disclosures about Segments of an Enterprise and Related Information (“SFAS 131”), the Company has two reportable operating segments, which are oil and gas exploration and production and contract drilling services. Beginning in April 2006, the Company formed the Larclay JV, a contract drilling joint venture that the Company consolidates in its financial statements (see Note 11). Effective January 1, 2007, the contract drilling segment meets the quantitative thresholds under SFAS 131 to be considered a reportable operating segment and, accordingly, is shown as “Contract Drilling” in the tables below.

For the Three Months Ended June 30, 2007	Oil and Gas			Contract Drilling			Intercompany Eliminations			Consolidated Total
	(Unaudited)
	(In thousands)
Revenues	$	78,336		$	16,939		$	(2,711	)	$	92,564
Depreciation, depletion and amortization (a)		17,104			2,172			(310	)		18,966
Other operating expenses (b)		52,182			9,816			(2,098	)		59,900
Interest expense		6,939			1,047			-			7,986
Other (income) expense		(9,724	)		-			-			(9,724	)
Income before income taxes and
minority interest		11,835			3,904			(303	)		15,436

Income tax expense		(3,991	)		(1,366	)		-			(5,357	)
Minority interest, net of tax		-			(1,269	)		-			(1,269	)

Net income	$	7,844		$	1,269		$	(303	)	$	8,810

Total assets	$	746,953		$	97,866		$	(3,389	)	$	841,430
Additions to property and equipment	$	59,097		$	4,066		$	(303	)	$	62,860

For the Six Months Ended June 30, 2007	Oil and Gas			Contract Drilling			Intercompany Eliminations			Consolidated Total
	(Unaudited)
	(In thousands)
Revenues	$	142,420		$	27,875		$	(5,230	)	$	165,065
Depreciation, depletion and amortization (a)		31,517			3,779			(534	)		34,762
Other operating expenses (b)		98,628			15,643			(3,908	)		110,363
Interest expense		13,734			1,881			-			15,615
Other (income) expense		6,412			-			-			6,412
Income (loss) before income taxes and
minority interest		(7,871	)		6,572			(788	)		(2,087	)

Income tax (expense) benefit		3,023			(2,300	)		-			723
Minority interest, net of tax		-			(2,136	)		-			(2,136	)

Net income (loss)	$	(4,848	)	$	2,136		$	(788	)	$	(3,500	)

Total assets	$	746,953		$	97,866		$	(3,389	)	$	841,430
Additions to property and equipment	$	120,621		$	20,135		$	(788	)	$	139,968

For the Three Months Ended June 30, 2006	Oil and Gas			Contract Drilling			Intercompany Eliminations			Consolidated Total
	(Unaudited)
	(In thousands)
Revenues	$	69,967		$	748		$	(374	)	$	70,341
Depreciation, depletion and amortization (a)		15,910			144			(72	)		15,982
Other operating expenses (b)		28,765			444			(216	)		28,993
Interest expense		4,923			38			-			4,961
Other (income) expense		(695	)		-			-			(695	)
Income before income taxes and
minority interest		21,064			122			(86	)		21,100

Income tax expense		(3,052	)		(42	)		-			(3,094	)
Minority interest, net of tax		-			(40	)		-			(40	)

Net income	$	18,012		$	40		$	(86	)	$	17,966

Total assets	$	673,224		$	40,343		$	(1,339	)	$	712,228
Additions to property and equipment	$	51,316		$	31,607		$	(86	)	$	82,837

For the Six Months Ended June 30, 2006	Oil and Gas			Contract Drilling			Intercompany Eliminations			Consolidated Total
	(Unaudited)
	(In thousands)
Revenues	$	133,361		$	748		$	(374	)	$	133,735
Depreciation, depletion and amortization (a)		30,620			144			(72	)		30,692
Other operating expenses (b)		66,962			444			(216	)		67,190
Interest expense		9,262			38			-			9,300
Other (income) expense		259			-			-			259
Income before income taxes and
minority interest		26,258			122			(86	)		26,294

Income tax expense		(4,870	)		(42	)		-			(4,912	)
Minority interest, net of tax		-			(40	)		-			(40	)

Net income	$	21,388		$	40		$	(86	)	$	21,342

Total assets	$	673,224		$	40,343		$	(1,339	)	$	712,228
Additions to property and equipment	$	119,618		$	31,607		$	(86	)	$	151,139

In July 2005, Clayton Williams Energy, Inc. (“Issuer”) issued $225 million of Senior Notes (see Note 4). Other than West Coast Energy Properties GP, LLC (“WCEP LLC”), the general partner of WCEP (see Note 11), all of the Issuer’s wholly-owned and active subsidiaries (“Guarantor Subsidiaries”) have jointly and severally, irrevocably and unconditionally guaranteed the performance and payment when due of all obligations under the Senior Notes. Larclay JV, a 50%-owned drilling rig joint venture formed in April 2006, and WCEP, LLC have not guaranteed the Senior Notes and are referred to in this Note 15 as Non-Guarantor Entities.

(Unaudited)					Non-
(In thousands)			Guarantor		Guarantor		Adjustments/
	Issuer		Subsidiaries		Entities		Eliminations			Consolidated
Current assets	$	123,611	$	99,836	$	16,328	$	(142,995	)	$	96,780
Property and equipment, net		350,023		276,219		87,656		-			713,898
Investments in subsidiaries		71,545		-		-		(71,545	)		-
Other assets		29,843		324		585		-			30,752
Total assets	$	575,022	$	376,379	$	104,569	$	(214,540	)	$	841,430

Current liabilities	$	90,434	$	171,946	$	39,875	$	(142,995	)	$	159,260
Non-current liabilities:
Long-term debt		405,500		-		48,750		-			454,250
Fair value of derivatives		3,307		8,841		-		-			12,148
Other		11,914		56,189		109		-			68,212
		420,721		65,030		48,859		-			534,610

Stockholders’ equity		63,867		139,403		15,835		(71,545	)		147,560
Total liabilities and
stockholders’ equity	$	575,022	$	376,379	$	104,569	$	(214,540	)	$	841,430

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

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

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

Three Months Ended June 30, 2007

(Unaudited)						Non-
(In thousands)				Guarantor		Guarantor			Adjustments/
	Issuer			Subsidiaries		Entities			Eliminations			Consolidated
Total revenue	$	52,272		$	26,311	$	17,098		$	(3,117	)	$	92,564
Costs and expenses		53,357			16,195		12,128			(2,814	)		78,866
Operating income (loss)		(1,085	)		10,116		4,970			(303	)		13,698
Other income (expense)		1,557			1,204		(1,023	)		-			1,738
Income tax expense		(5,357	)		-		-			-			(5,357	)
Minority interest, net of tax		(1,269	)		-		-			-			(1,269	)
Net income (loss)	$	(6,154	)	$	11,320	$	3,947		$	(303	)	$	8,810

(Unaudited)							Non-
(In thousands)				Guarantor			Guarantor			Adjustments/
	Issuer			Subsidiaries			Entities			Eliminations			Consolidated
Total revenue	$	92,399		$	50,480		$	28,136		$	(5,950	)	$	165,065
Costs and expenses		98,250			32,334			19,703			(5,162	)		145,125
Operating income (loss)		(5,851	)		18,146			8,433			(788	)		19,940
Other income (expense)		(18,000	)		(2,198	)		(1,829	)		-			(22,027	)
Income tax benefit		723			-			-			-			723
Minority interest, net of tax		(2,136	)		-			-			-			(2,136	)
Net income (loss)	$	(25,264	)	$	15,948		$	6,604		$	(788	)	$	(3,500	)

(Unaudited)							Non-
(In thousands)				Guarantor			Guarantor			Adjustments/
	Issuer			Subsidiaries			Entity			Eliminations			Consolidated
Total revenue	$	42,268		$	28,123		$	747		$	(797	)	$	70,341
Costs and expenses		27,743			17,356			587			(711	)		44,975
Operating income (loss)		14,525			10,767			160			(86	)		25,366
Other income (expense)		531			(4,758	)		(39	)		-			(4,266	)
Income tax expense		(3,094	)		-			-			-			(3,094	)
Minority interest, net of tax		(40	)		-			-			-			(40	)
Net income (loss)	$	11,922		$	6,009		$	121		$	(86	)	$	17,966

(Unaudited)							Non-
(In thousands)				Guarantor			Guarantor			Adjustments/
	Issuer			Subsidiaries			Entity			Eliminations			Consolidated
Total revenue	$	79,282		$	55,156		$	747		$	(1,450	)	$	133,735
Costs and expenses		64,525			34,134			587			(1,364	)		97,882
Operating income (loss)		14,757			21,022			160			(86	)		35,853
Other income (expense)		(3,760	)		(5,760	)		(39	)		-			(9,559	)
Income tax expense		(4,912	)		-			-			-			(4,912	)
Minority interest, net of tax		(40	)		-			-			-			(40	)
Net income (loss)	$	6,045		$	15,262		$	121		$	(86	)	$	21,342

(Unaudited)							Non-
(In thousands)				Guarantor			Guarantor			Adjustments/
	Issuer			Subsidiaries			Entities			Eliminations			Consolidated
Operating activities	$	58,415		$	21,692		$	9,295		$	534		$	89,936
Investing activities		(110,585	)		(7,652	)		(20,411	)		(34	)		(138,682	)
Financing activities		49,095			(14,124	)		8,721			(500	)		43,192
Net increase (decrease) in
cash and cash equivalents		(3,075	)		(84	)		(2,395	)		-			(5,554	)
Cash at the beginning of
the period		6,116			1,298			6,426			-			13,840
Cash at end of the period	$	3,041		$	1,214		$	4,031		$	-		$	8,286

(Unaudited)							Non-
(In thousands)				Guarantor			Guarantor			Adjustments/
	Issuer			Subsidiaries			Entity			Eliminations			Consolidated
Operating activities	$	34,485		$	39,977		$	2,514		$	72		$	77,048
Investing activities		(123,978	)		(11,509	)		(31,607	)		428			(166,666	)
Financing activities		92,353			(27,887	)		36,586			(500	)		100,552
Net increase in cash and
cash equivalents		2,860			581			7,493			-			10,934
Cash at beginning of
the period		4,302			1,633			-			-			5,935
Cash at end of the period	$	7,162		$	2,214		$	7,493		$	-		$	16,869

The following discussion is intended to provide information relevant to an understanding of our financial condition, changes in our financial condition and our results of operations and cash flows and should be read in conjunction with our consolidated financial statements and notes thereto included elsewhere in this Form 10-Q and in our Form 10-K for the year ended December 31, 2006.

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

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

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

Despite our high level of capital spending in fiscal 2006 and continuing through June 2007, our oil and gas production for the three months ended June 30, 2007 was only 17% higher on an Mcfe basis than in the comparable period in 2006. A significant portion of our fiscal 2006 and fiscal 2007 expenditures to date have not resulted in current production because they relate to (a) unproved exploratory prospects, (b) drilling or completion activities that are in progress, or (c) non-productive leasing and drilling activities.

We spent $119.7 million on exploration and development activities during the first half of 2007, of which approximately 65% was on exploratory prospects. We currently plan to spend approximately $235.1 million for fiscal 2007, an increase of $48.9 million from our previous estimate of $186.2 million. Most of the increase relates to developmental drilling in North Louisiana, the Austin Chalk (Trend) and the Permian Basin. As a result, our planned expenditures are expected to be more balanced, with approximately 53% applied to exploratory activities.

Our expenditures on exploration and development activities for the first six months of 2007 exceeded cash flow from operating activities, excluding cash flow from our contract drilling segment, by approximately $37 million, and our expenditures for the remainder of 2007 are also expected to exceed our operating cash flow, although not by as large a margin. We cannot predict our drilling success on exploratory prospects, and our future results of operations and financial condition could be adversely affected by unsuccessful exploratory drilling results.

At June 30, 2007, our capitalized unproved oil and gas properties totaled $139.3 million, of which approximately $98.4 million was attributable to unproved acreage. Unproved properties are subject to a valuation impairment to the extent the carrying cost of a prospect exceeds its estimated fair value. Therefore, our results of operations in future periods may be adversely affected by unproved property impairments.

We recorded a $6.1 million net gain on derivatives in the second quarter of 2007. We recorded a $1.5 million realized loss on settled contracts and a $7.6 million gain for changes in mark-to-market valuations. Since we do not presently designate our derivatives as cash flow hedges under applicable accounting standards, we recognize the full effect of changing prices on mark-to-market valuations as a current charge or credit to our results of operations.

As shown in “Liquidity and Capital Resources – Capital Expenditures,” we incurred expenditures for exploration and development activities of $119.7 million during the first six months of 2007, of which approximately 65% were related to exploratory drilling and leasing activities. We also increased our estimates for capital expenditures in fiscal 2007 from $186.2 million to $235.1 million.

		Working			Current
Spud Date	Well Name (Prospect)	Interest			Status
April 2006	Cobena #1 (Boa II)		63	%	Dry
January 2007	SL 195 QQ #7 (Floyd)		100	%	Producing
February 2007	SL 195 QQ #10 (Floyd)		75	%	Producing
February 2007	Orleans Levee District #2 (American Bay)		45	%	Producing
March 2007	Bowie Lumber Co. #1 (Bayou Boeuf)		100	%	Dry
April 2007	Pivach Agency #1 (Elsa)		94	%	Dry
June 2007	SL 195 QQ #12 (Floyd)		100	%	Drilling
June 2007	SL 16849 #2 (Dolly)		94	%	Waiting on pipeline

In our Floyd prospect, we have drilled 11 wells to date, of which 10 are on production, with the remaining well presently drilling. These wells are producing at combined rates of 10,700 Mcf of gas per day and 450 barrels of oil per day, net to the Company’s interest. During the second quarter of 2007, the Company was able to partially resolve its production facility constraints, and increase the level of combined production to near the combined rates at which the wells are capable of producing. In order to fully resolve these capacity issues, the Company may build its own plant and production facilities in the future to process and market gas production from all the wells in the prospect. We have also drilled and completed a second well in the Dolly prospect, the SL 16849 #2, an offset to the SL 16849 #1, which is currently waiting on pipeline construction.

In 2005, we began an exploration 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.

		Working			Current
Spud Date	Well Name (Prospect)	Interest			Status
October 2006	P. Benoit #1 (Sarepta)		91	%	Waiting on completion
January 2007	J.L. Hood #1 (Terryville)		86	%	Producing
February 2007	J. Huey #1 (Terryville)		86	%	Producing
March 2007	David Barton #1 (Winnsboro)		100	%	Dry
March 2007	George Staton #1 (Sarepta)		70	%	Producing
April 2007	Bice #1 (Terryville)		86	%	Producing
May 2007	C. Dugdale #1 (Choudrant)		99	%	Waiting on pipeline
June 2007	Stephenson #1 (Terryville)		86	%	Producing
June 2007	John Warren #1 (Terryville)		86	%	Waiting on completion
July 2007	Burks #1 (Terryville)		86	%	Waiting on completion
July 2007	Henry #2 (Terryville)		86	%	Drilling
July 2007	Allen Estate #1 (Terryville)		86	%	Drilling
August 2007	McCrary #1 (Terryville)		86	%	Drilling

On our Terryville prospect in Lincoln Parish, we completed two wells, the C.M. Bice #1 and the Stephenson #1, as producers. We also drilled two additional development wells, the John Warren #1 and the Burks #1, which are waiting on completion operations to commence. We are currently drilling three additional development wells, the Henry #2, the Allen Estate #1, and the McCrary #1, and plan to drill up to seven additional development wells in the Terryville prospect during the remainder of 2007.

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

We temporarily abandoned the David Barton #1, an exploratory well in the Winnsboro prospect in Richland Parish, prior to reaching the target interval. Based on a geological evaluation, we recorded a pre-tax charge of $8.6 million related to the abandonment of this well in the second quarter of 2007. We may drill an offset to the Barton well in late 2007 or 2008 in order to test the pressured Bossier interval in this area. We currently have approximately 188,000 acres leased for Bossier drilling in North Louisiana.

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

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

	Three Months Ended
	June 30,
	2007			2006
Oil and Gas Production Data:
Gas (MMcf)		5,151			4,016
Oil (MBbls)		577			555
Natural gas liquids (MBbls)		57			50
Total (MMcfe)		8,955			7,646

Average Realized Prices ^(a):
Gas ($/Mcf)	$	7.20		$	6.78
Oil ($/Bbl)	$	62.51		$	66.78
Natural gas liquids ($/Bbl):	$	42.84		$	37.56

Gain (Loss) on Settled Derivative Contracts ^(a):
($ in thousands, except per unit)
Gas: Net realized gain (loss)	$	473		$	(887	)
Per unit produced ($/Mcf)	$	.09		$	(0.22	)
Oil: Net realized loss	$	(1,971	)	$	(6,700	)
Per unit produced ($/Bbl)	$	(3.42	)	$	(12.07	)

Average Daily Production:
Natural Gas (Mcf):
Permian Basin		13,724			15,744
Louisiana		32,435			15,428
Austin Chalk (Trend)		2,445			2,757
Cotton Valley Reef Complex		7,651			9,723
Other		349			480
Total		56,604			44,132
Oil (Bbls):
Permian Basin		3,135			3,274
Louisiana		1,486			933
Austin Chalk (Trend)		1,627			1,833
Other		93			59
Total		6,341			6,099
Natural Gas Liquids (Bbls):
Permian Basin		226			227
Austin Chalk (Trend)		251			265
Other		149			57
Total		626			549

	Three Months Ended
	June 30,
	2007		2006
Exploration Costs (in thousands):
Abandonment and impairment costs:
South Louisiana	$	14,217	$	2,879
North Louisiana		8,679		-
Other		623		450
Total		23,519		3,329

Seismic and other		1,580		2,587
Total exploration costs	$	25,099	$	5,916

Depreciation, Depletion and Amortization (in thousands):
Oil and gas depletion	$	16,331	$	15,155
Contract drilling depreciation		1,862		-
Other depreciation		294		827
Total DD&A	$	18,487	$	15,982

Oil and Gas Costs ($/Mcfe Produced):
Production costs	$	1.99	$	2.08
Oil and gas depletion	$	1.82	$	1.98

Net Wells Drilled ^(b):
Exploratory Wells		4.2		5.2
Developmental Wells		5.7		-

	Six Months Ended
	June 30,
	2007			2006
Oil and Gas Production Data:
Gas (MMcf)		9,478			7,479
Oil (MBbls)		1,120			1,110
Natural gas liquids (MBbls)		103			98
Total (MMcfe)		16,816			14,727

Average Realized Prices ^(a):
Gas ($/Mcf)	$	7.06		$	6.99
Oil ($/Bbl)	$	58.95		$	63.41
Natural gas liquids ($/Bbl):	$	38.58		$	38.21

Gain (Loss) on Settled Derivative Contracts ^(a):
($ in thousands, except per unit)
Gas: Net realized gain (loss)	$	4,982		$	(3,065	)
Per unit produced ($/Mcf)	$	.53		$	(0.41	)
Oil: Net realized loss	$	(4,530	)	$	(12,595	)
Per unit produced ($/Bbl)	$	(4.04	)	$	(11.35	)

	Six Months Ended
	June 30,
	2007		2006
Average Daily Production:
Natural Gas (Mcf):
Permian Basin		14,552		14,789
Louisiana		27,510		12,465
Austin Chalk (Trend)		2,228		3,007
Cotton Valley Reef Complex		7,674		10,576
Other		401		483
Total		52,365		41,320
Oil (Bbls):
Permian Basin		3,117		3,244
Louisiana		1,347		1,011
Austin Chalk (Trend)		1,647		1,827
Other		77		51
Total		6,188		6,133
Natural Gas Liquids (Bbls):
Permian Basin		211		244
Austin Chalk (Trend)		259		262
Other		99		35
Total		569		541

Exploration Costs (in thousands):
Abandonment and impairment costs:
South Louisiana	$	21,396	$	10,886
North Louisiana		8,985		-
Permian Basin		989		2,317
Other		3,254		2,969
Total		34,624		16,172

Seismic and other		2,470		5,688
Total exploration costs	$	37,094	$	21,860

Depreciation, Depletion and Amortization (in thousands):
Oil and gas depletion	$	29,879	$	29,136
Contract drilling depreciation		3,245		-
Other depreciation		594		1,556
Total DD&A	$	33,718	$	30,692

Oil and Gas Costs ($/Mcfe Produced):
Production costs	$	2.09	$	2.10
Oil and gas depletion	$	1.78	$	1.98

Net Wells Drilled ^(b):
Exploratory Wells		9.2		12.8
Developmental Wells		9.2		1.7

Oil and gas sales in 2007 increased $8.5 million, or 13%, from 2006, due almost entirely to an increase in production. Production in 2007 (on an Mcfe basis) was 17% higher than 2006. Oil production increased 4% and gas production increased 28% in 2007 from 2006 due primarily to incremental production attributable to recent drilling activity in South Louisiana. In 2007, our realized oil price was 6% lower than 2006, while our realized gas price was 6% 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 12% in 2007 as compared to 2006 due primarily to higher oilfield service costs. After giving effect to a 17% increase in oil and gas production on an Mcfe basis, production costs per Mcfe decreased 4% from $2.08 per Mcfe in 2006 to $1.99 per Mcfe in 2007. It is likely that production costs will continue to increase in future periods.

Oil and gas depletion expense increased $1.2 million, of which production variances accounted for a $2.6 million increase and rate variances accounted for a $1.4 million decrease. On an Mcfe basis, depletion expense decreased 8% from $1.98 per Mcfe in 2006 to $1.82 per Mcfe in 2007 due in part to a lower depletable cost basis in 2007 compared to the 2006 period in two areas where we recorded an impairment of proved property under SFAS No. 144 in the last half of 2006. Depletion expense per Mcfe of oil and gas production is an operating metric that is indicative of our weighted average cost to find or acquire a unit of equivalent production. We may realize higher oil and gas depletion rates in future periods if our exploration activities result in higher finding costs in 2007.

Since we follow the successful efforts method of accounting, our results of operations are adversely affected during any accounting period in which significant seismic costs, exploratory dry hole costs, and unproved acreage impairments are expensed. In 2007, we charged to expense $25.1 million of exploration costs, as compared to $5.9 million in 2006. Most of the 2007 costs were incurred in Louisiana.

We plan to spend approximately $235.1 million on exploration and development activities in fiscal 2007, of which approximately 53% is expected to be allocated to exploration activities. Since exploratory drilling involves a high degree of risk, it is likely that a significant portion of the costs we incur in fiscal 2007 will be charged to exploration costs. However, we cannot predict our success rates and, accordingly, cannot predict our exploration costs related to abandonment and impairment costs.

consolidated financial statements. During the three months ended June 30, 2007, we included contract drilling revenues of $14.2 million, net other operating expenses of $8.5 million, depreciation expense of $1.9 million and interest expense of $1 million in our statement of operations (see Note 14 to the consolidated financial statements). Since the Larclay JV drilling rigs are partially utilized by us, the reported amounts are net of any intercompany profits eliminated in consolidation.

General and administrative (“G&A”) expenses increased 16% from $4.3 million in 2006 to $4.9 million in 2007 due primarily to increases in professional fees and services, salaries and legal fees. Excluding non-cash employee compensation, G&A expenses increased from $3.8 million in 2006 to $4.4 million in 2007. In 2007 and 2006, we recorded a $500,000 non-cash compensation charge related to our after payout incentive plan.

Interest expense increased 60% from $5 million in 2006 to $8 million in 2007 due to a combination of factors. In 2006 and 2007, we used our revolving loan facility to partially finance our exploration and development activities. The average daily principal balance outstanding under our revolving credit facility for 2007 was $175 million compared to $80.5 million for 2006. Capitalized interest for 2007 was $1.1 million compared to $1.5 million in 2006. We also included $1 million of interest expense associated with our Larclay JV during 2007.

We did not designate any derivative contracts in 2007 or 2006 as cash flow hedges; therefore all cash settlements and changes resulting from mark-to-market valuations have been recorded as gain/loss on derivatives. For the three months ended June 30, 2007, we reported a $6.1 million net gain on derivatives, consisting of a $7.6 million non-cash gain to mark our derivative positions to their fair value at June 30, 2007 and a $1.5 million realized loss on settled contracts. For the three months ended June 30, 2006, we recorded a net gain on derivatives of $245,000, consisting of a $7.7 million non-cash gain related to changes in mark-to-market valuations and a $7.5 million realized loss on settled contracts.

Oil and gas sales in 2007 increased $9.4 million, or 7%, from 2006, of which production variances accounted for a $13.6 million increase and price variances accounted for a $4.2 million decrease. Production in 2007 (on an Mcfe basis) was 14% higher than 2006. Oil production increased 1% in 2007 and gas production increased 27% in 2007 from 2006 due primarily to production attributable to recent drilling activity in South Louisiana. In 2007, our realized

Production costs, consisting of lease operating expenses, production taxes and other miscellaneous marketing costs, increased 14% in 2007 as compared to 2006 due primarily to higher oilfield service costs. After giving effect to a 14% increase in oil and gas production on an Mcfe basis, production costs per Mcfe decreased from $2.10 per Mcfe in 2006 to $2.09 per Mcfe in 2007. It is likely that production costs will continue to increase in future periods.

Oil and gas depletion expense increased $743,000, of which volume variances accounted for a $4.1 million increase and rate variances accounted for a $3.4 million decrease. On an Mcfe basis, depletion expense decreased 10% from $1.98 per Mcfe in 2006 to $1.78 per Mcfe in 2007 due in part to a lower depletable cost basis in 2007 compared to the 2006 period in two areas where we recorded an impairment of proved property under SFAS No. 144 in the last half of 2006. Depletion expense per Mcfe of oil and gas production is an operating metric that is indicative of our weighted average cost to find or acquire a unit of equivalent production. We may realize higher oil and gas depletion rates in future periods if our exploration activities result in higher finding costs in 2007.

Since we follow the successful efforts method of accounting, our results of operations are adversely affected during any accounting period in which significant seismic costs, exploratory dry hole costs, and unproved acreage impairments are expensed. In 2007, we charged to expense $37.1 million of exploration costs, as compared to $21.9 million in 2006. Most of the 2007 costs were incurred in Louisiana, the Permian Basin and Utah.

In April 2006, we formed a joint venture (“Larclay JV”) with Lariat Services, Inc. to construct, own, and operate 12 new drilling rigs. We own a 50% interest in Larclay JV. The rigs were constructed on behalf of Larclay JV by Lariat, as operations manager. 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 six months ended June 30, 2007, we included contract drilling revenues of $22.6 million, net other operating expenses of $13.5 million, depreciation expense of $3.2 million and interest expense of $1.9 million in our statement of operations (see Note 14 to the consolidated financial statements). Since the Larclay JV drilling rigs are partially utilized by us, the reported amounts are net of any intercompany profits eliminated in consolidation.

General and administrative (“G&A”) expenses increased 6% from $8.3 million in 2006 to $8.8 million in 2007 due primarily to higher professional fees and services and salaries. Excluding non-cash employee compensation, G&A expenses increased from $7.2 million in 2006 to $7.7 million in 2007. In 2007, we recorded a $1 million non-cash compensation charge related to our after payout incentive plan and $110,000 for stock-based employee compensation.

Interest expense increased 68% from $9.3 million in 2006 to $15.6 million in 2007 due to a combination of factors. In 2006 and 2007, we used our revolving loan facility to partially finance our exploration and development activities. The average daily principal balance outstanding under our revolving credit facility for 2007 was $167.1 million compared to $62.1 million for 2006. Capitalized interest for 2007 was $2.1 million compared to $2.8 million in 2006. We also included $1.9 million of interest expense associated with our Larclay JV during 2007.

We did not designate any derivative contracts in 2007 or 2006 as cash flow hedges; therefore all cash settlements and changes resulting from mark-to-market valuations have been recorded as gain/loss on derivatives. For the six months ended June 30, 2007, we reported a $10.7 million net loss on derivatives, consisting of an $11.2 million non-cash loss to mark our derivative positions to their fair value at June 30, 2007 and a $500,000 realized gain on settled contracts. For the six months ended June 30, 2006, we recorded a net loss on derivatives of $1.3 million, consisting of a $14.3 million non-cash gain related to changes in mark-to-market valuations and a $15.6 million realized loss on settled contracts.

Loss on sale of assets for 2007 was $9.3 million compared to $13,000 for 2006. The 2007 charge was due to recording losses on inventory which 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. Other income for 2007 was income of $4.3 million compared to income of $1.1 million for the 2006 period. The 2007 period included a $2.9 million gain on settlement of litigation. No lawsuit settlements or write-downs of inventory were recorded during the 2006 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.

We incurred expenditures for exploration and development activities of $119.7 million during the first six months of 2007 and have increased our estimates for planned expenditures for fiscal 2007 by $48.9 million from $186.2 million to $235.1 million. The following table summarizes, by area, our actual expenditures for exploration and development activities for the first half of 2007 and our planned expenditures for the year ending December 31, 2007.

	Actual		Planned
	Expenditures		Expenditures		Year 2007
	Six Months Ended		Year Ending		Percentage
	June 30, 2007		December 31, 2007		of Total
	(In thousands)
North Louisiana	$	36,100	$	84,700		36	%
South Louisiana		49,900		65,700		28	%
East Texas Bossier		13,900		34,200		15	%
Permian Basin		12,200		28,300		12	%
Austin Chalk (Trend)		3,500		14,500		6	%
Utah/California		3,700		7,200		3	%
Other		400		500		-
	$	119,700	$	235,100		100	%

Most of the $48.9 million increase in estimated capital expenditures for fiscal 2007 relates to increased drilling activity in the Terryville area in North Louisiana, the Austin Chalk (Trend) and the Permian Basin. Based on recent drilling results, we have changed the classification on wells drilled in 2007 in our Terryville prospect from exploratory to developmental and have added nine additional locations for developmental drilling during the last half of 2007. In addition, we have decided to increase developmental drilling activities in oil-prone areas such as our core acreage block in the Austin Chalk (Trend), where we have in-fill drilling opportunities, and in the Permian Basin. As a result, we now estimate that our expenditures for exploration and development activities for fiscal 2007 will be more balanced, with approximately 53% relating to exploratory prospects and approximately 47% relating to development activities, as compared to our previous estimate of 78% and 22%, respectively.

Our expenditures for exploration and development activities for the six months ended June 30, 2007 exceeded our cash flow from operating activities for the same period, excluding cash flows from our contract drilling segment, by approximately $37 million, and we expect our spending during the remainder of 2007 to outpace our operating cash flow, although not by as large a margin. To the extent possible, we intend to finance this shortfall by borrowings on the revolving credit facility. Our internal cash flow forecasts indicate that the amount of funds available to us under our revolving credit facility, when combined with our anticipated operating cash flow, will be sufficient to finance our capital expenditures and will provide us with adequate liquidity at least through 2007. Although we believe the assumptions and estimates made in our forecasts are reasonable, uncertainties exist which could cause the borrowing base to be less than expected, cash flow to be less than expected, or capital expenditures to be more than expected. In

We have placed orders for two 2,000 horsepower rigs for possible use in our Bossier drilling program in North Louisiana and East Texas. At June 30, 2007, we had invested $16.3 million in these rigs and were committed under firm purchase contracts for an additional $6 million which we paid in July 2007. We have offered these drilling rigs for sale (see “Alternative Capital Resources”).

Cash flow provided by operating activities for the six months ended June 30, 2007 increased $12.9 million, or 16%, as compared to the corresponding period in 2006. Approximately $7.2 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 (see “-Secured Term Loan of Larclay JV”). The remainder of the increase in operating cash flow was derived primarily from oil and gas producing activities, offset in part by increased interest expense on higher levels of indebtedness.

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 six months in 2007, we increased our borrowing base to $275 million and borrowed $40.5 million on the revolving credit facility to finance the excess of our exploration and development expenditures over cash flow from operating activities. We also cancelled a $19 million letter of credit that had been issued in connection with the Larclay JV term loan. At June 30, 2007, we had $93.7 million available under the revolving loan facility after accounting for outstanding letters of credit.

Using the revolving credit facility for both our short-term liquidity and long-term financing needs can cause unusual fluctuations in our reported working capital, depending on the timing of cash receipts and expenditures. On a daily basis, we use most of our available cash to pay down our outstanding balance on the revolving credit facility, which is classified as a non-current liability since we currently have no required principal reductions. As we use cash to pay a non-current liability, our reported working capital decreases. Conversely, as we draw on the revolving credit facility for funds to pay current liabilities (such as payables for drilling and operating costs), our reported working capital increases. Also, volatility in oil and gas prices can cause significant fluctuations in reported working capital as we record changes in the fair value of derivatives from period to period. For these reasons, the working capital covenant related to the revolving credit facility requires us to (i) include the amount of funds available under this facility as a current asset, (ii) exclude current assets and liabilities related to the fair value of derivatives, and (iii) exclude current maturities of vendor finance obligations, if any, when computing the working capital ratio at any balance sheet date.

Working capital computed for loan compliance purposes differs from our working capital in accordance with generally accepted accounting principles (GAAP). Since compliance with financial covenants is a material requirement under the credit facilities, we consider the loan compliance working capital to be useful as a measure of our liquidity because it includes the funds available to us under the revolving credit facility and is not affected by the volatility in working capital caused by changes in fair value of derivatives. Our reported working capital deficit increased from $23.1 million at December 31, 2006 to $62.5 million at June 30, 2007 due primarily to a combination of factors, including decreases in inventory and an increase in the net liability for the fair value for derivatives. After

	June 30,			December 31,
	2007			2006
	(In thousands)
Working capital (deficit) per GAAP	$	(62,480	)	$	(23,068	)
Add funds available under the revolving credit facility		93,696			40,196
Exclude fair value of derivatives classified as current assets or current liabilities		24,586			5,993
Exclude current assets and current liabilities of Larclay JV		23,625			13,759
Working capital per loan covenant	$	79,427		$	36,880

Since we use this revolving credit facility for both short-term liquidity and long-term financing needs, it is important that we comply in all material respects with the loan agreement, including financial covenants that are computed quarterly. The working capital covenant requires us to maintain positive working capital using the computations described above. Another financial covenant under the credit facility requires us to maintain a ratio of indebtedness to cash flow of no more than 3 to 1. While we were in compliance with all financial and non-financial covenants at June 30, 2007, our increased leverage and reduced liquidity may result in our failing to comply with one or more of these covenants in the future. If we fail to meet any of these loan covenants, we would ask the banks to allow us sufficient time to obtain additional capital resources through alternative means. If a suitable arrangement could not be reached with the banks, the banks could accelerate the indebtedness and seek to foreclose on the pledged assets.

The banks redetermine the borrowing base under the revolving credit facility at least twice a year, in May and November. In June 2007, the borrowing base was increased from $200 million to $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 2006 and the first half of 2007. At June 30, 2007, we had $180.5 million outstanding on the revolving credit facility.

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

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

The Indenture governing the Senior Notes restricts our ability and the ability of our restricted subsidiaries to: (i) borrow money; (ii) issue redeemable and preferred stock; (iii) pay distributions or dividends; (iv) make investments; (v) create liens without securing the Notes; (vi) enter into agreements that restrict dividends from subsidiaries; (vii) sell certain assets or merge with or into other companies; (viii) enter into transactions with affiliates; (ix) guarantee indebtedness; and (x) enter into new lines of business. These covenants are subject to a number of important exceptions and qualifications. We were in compliance with these covenants at June 30, 2007.

Larclay JV, a contract drilling joint venture with Lariat Services, Inc., obtained a $75 million secured term loan facility from a lender to finance the construction and equipping of twelve new drilling rigs. The Larclay JV term loan is secured by substantially all of the assets of Larclay JV. Initially, we pledged additional collateral in the form of a $19 million letter of credit to support the term loan. In February 2007, we cancelled the letter of credit and replaced it with our corporate guaranty in the amount of $19.5 million. In March 2007, we issued a $5 million letter of credit which expired in June 2007 as additional collateral under the term loan to cover any temporary shortfall in collateral value caused by delays in completing construction of the final drilling rigs being financed by the lender. Concurrently, the guaranty was amended to limit our combined credit exposure under the guaranty and the letter of credit to $19.5 million. Although we are not a maker on the Larclay JV term loan, we are providing partial credit support for the Larclay JV term loan and 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 us or Lariat until the balance on the term loan is fully repaid, and repayments by Larclay JV of any loans by us or Lariat are subordinated to the loans outstanding under the term loan and are subject to other restrictions. At June 30, 2007, the effective interest rate on the Larclay JV term loan was 8.7%.

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.

We have offered for sale most of our proven oil and gas properties in South Louisiana, the majority of which are located in Plaquemines Parish and the two 2,000 horsepower drilling rigs that we have ordered. If we receive adequate consideration for these assets, we plan to sell these assets and use the net sales proceeds to repay indebtedness on our revolving credit facility. In addition, Larclay JV has offered for sale its two 2,000 horsepower drillings rigs and, if an adequate offer is received, plans to use the net sales proceeds to repay a portion of its indebtedness under the Larclay JV term loan.

Item 3 - Quantitative and Qualitative Disclosures About Market Risk

Our business is impacted by fluctuations in commodity prices and interest rates. The following discussion is intended to identify the nature of these market risks, describe our strategy for managing such risks, and to quantify the potential affect of market volatility on our financial condition and results of operations.

Oil and Gas Prices

Our financial condition, results of operations, and capital resources are highly dependent upon the prevailing market prices of, and demand for, oil and natural gas. These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond our control. These factors include the level of global demand for petroleum products, foreign supply of oil and gas, the establishment of and compliance with production quotas by oil-exporting countries, weather conditions, the price and availability of alternative fuels, and overall economic conditions, both foreign and domestic. We cannot predict future oil and gas prices with any degree of certainty. Sustained weakness in oil and gas prices may adversely affect our financial condition and results of operations, and may also reduce the amount of net oil and gas reserves that we can produce economically. Any reduction in reserves, including reductions due to price fluctuations, can reduce the borrowing base under our revolving credit facility and adversely affect our liquidity and our ability to obtain capital for our exploration and development activities. Similarly, any improvements in oil and gas prices can have a favorable impact on our financial condition, results of operations and capital resources. Based on December 31, 2006 reserve estimates, we project that a $1.00 drop in the price per Bbl of oil and a $.50 drop in the price per Mcf of gas would reduce our gross revenues for the year ending December 31, 2007 by $10.7 million.

From time to time, we utilize commodity derivatives, consisting primarily of swaps, floors and collars to attempt to optimize the price received for our oil and natural gas production. When using swaps to hedge our oil and natural gas production, we receive a fixed price for the respective commodity and pay a floating market price as defined in each contract (generally NYMEX futures prices), resulting in a net amount due to or from the counterparty. In floor transactions, we receive a fixed price (put strike price) if the market price falls below the put strike price for the respective commodity. If the market price is greater than the put strike price, no payments are due from either party. Costless collars are a combination of puts and calls, and contain a fixed floor price (put strike price) and ceiling price (call strike price). If the market price for the respective commodity exceeds the call strike price or falls below the put strike price, then we receive the fixed price and pay the market price. If the market price is between the call and the put strike prices, no payments are due from either party. Commodity derivatives are settled monthly as the contract periods mature. The commodity derivatives we use differ from futures contracts in that there is not a contractual obligation that requires or permits the future physical delivery of the hedged products. We do not enter into commodity derivatives for trading purposes. In addition to commodity derivatives, we may, from time to time, sell a portion of our gas production under short-term contracts at fixed prices.

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

We are exposed to interest rate risk on our long-term debt with a variable interest rate. At June 30, 2007, our variable rate debt had a carrying value of $255.5 million, which approximated its fair value. At June 30, 2007, our fixed rate debt had a carrying value of $225 million and an approximate fair value of $207 million, based on current market quotes. We estimate that the hypothetical change in the fair value of our fixed-rate, long-term debt resulting from a 100-basis point change in interest rates would be approximately $9.2 million.

We are a party to interest rate swaps that were acquired in connection with the acquisition of Southwest Royalties, Inc. in May 2004. Under these derivatives, we pay a fixed rate for the notional principal balances and receives a floating market rate based on LIBOR. The following summarizes information concerning our net positions in open interest rate swaps applicable to periods subsequent to June 30, 2007.

Item 4 - Controls and Procedures

Disclosure Controls and Procedures

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

With respect to our disclosure controls and procedures:

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

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, 2006, as filed with the U.S. Securities and Exchange Commission on March 16, 2007 and available at www.sec.gov. There have been no material changes to these risk factors since the filing of our Form 10-K.

On May 9, 2007, we held our Annual Meeting of Stockholders to (a) elect two directors to the Board of Directors for a term of three years, and (b) advise on the selection of KPMG LLP as our independent auditors for 2007. At such meeting, Clayton W. Williams, Jr. and L. Paul Latham were reelected as directors, and stockholders advised that KPMG LLP should be selected as our independent auditors for 2007.

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

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

**3.3	Corporate Bylaws of Clayton Williams Energy, Inc., as amended, filed as Exhibit 3.1 to our Current Report on Form 8-K filed with the Commission on March 8, 2007††

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

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

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

(Mark One)
x	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
	OF THE SECURITIES EXCHANGE ACT OF 1934
	For the quarterly period ended June 30, 2007

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

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

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

PART I. FINANCIAL INFORMATION
		Page

Item 1.	Financial Statements

	Consolidated Balance Sheets as of June 30, 2007 and December 31, 2006	3

	Consolidated Statements of Operations for the three months and six months ended June 30, 2007 and 2006	5

	Consolidated Statements of Stockholders’ Equity for the six months ended June 30, 2007	6

	Consolidated Statements of Cash Flows for the six months ended June 30, 2007 and 2006	7

	Notes to Consolidated Financial Statements	8

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

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	37

Item 4.	Controls and Procedures	40


PART II. OTHER INFORMATION
Item 1A.	Risk Factors	41

Item 4.	Submission of Matters to a Vote of Security Holders	41

Item 6.	Exhibits	41

	Signatures	43

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

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

Net loss and total comprehensive loss		-		-		-		(3,500	)

Issuance of stock through compensation
plans		200		20		6,060		-

BALANCE,
June 30, 2007		11,352	$	1,135	$	120,025	$	26,400

		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		1.8
$	10.00 - $19.74		462,000	$	17.49		4.8
$	22.90 - $41.74		318,000	$	26.38		7.0
			813,485	$	20.47		5.6

	Gas						Oil
	MMBtu ^(a)		Floor		Ceiling		Bbls		Floor		Ceiling
Production Period:
3^rd Quarter 2007		459,000	$	4.00	$	5.18		141,000	$	23.00	$	25.20
4^th Quarter 2007		459,000	$	4.00	$	5.18		141,000	$	23.00	$	25.20
2008		1,279,000	$	4.00	$	5.15		392,000	$	23.00	$	25.07
		2,197,000						674,000

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

	June 30, 2007			December 31, 2006
	(In thousands)
Proved properties	$	1,171,540		$	1,097,341
Unproved properties		139,273			129,420
Total capitalized costs		1,310,813			1,226,761
Accumulated depreciation, depletion and amortization		(685,134	)		(654,316	)
Net capitalized costs	$	625,679		$	572,445

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

	Results of Voting	Votes For	Withheld
1.	Election of Directors
	Clayton W. Williams, Jr.	10,534,676	134,752
	L. Paul Latham	10,531,476	137,952

		Votes For	Withheld	Abstentions
2.	Advisory vote on the selection of KPMG LLP	10,623,441	30,586	15,401

*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

Date:	August 9, 2007	By:	/s/ L. Paul Latham
			L. Paul Latham
			Executive Vice President and Chief
			Operating Officer

Date:	August 9, 2007	By:	/s/ Mel G. Riggs
			Mel G. Riggs
			Senior Vice President and Chief Financial
			Officer