Clayton Williams Energy 10Q 2008 Q2 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(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, 2008

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

CLAYTON WILLIAMS ENERGY, INC.

(Exact name of registrant as specified in its charter)

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

Not applicable

(Former name, former address and former fiscal year, if changed since last report)

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

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

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

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

There were 12,113,898 shares of Common Stock, $.10 par value, of the registrant outstanding as of August 6, 2008.

CLAYTON WILLIAMS ENERGY, INC

TABLE OF CONTENTS

PART I. FINANCIAL INFORMATION
		Page

Item 1.	Financial Statements

	Consolidated Balance Sheets as of June 30, 2008
	and December 31, 2007	3

	Consolidated Statements of Operations for the three months and six months
	ended June 30, 2008 and 2007	5

	Consolidated Statement of Stockholders’ Equity for the six months
	ended June 30, 2008	6

	Consolidated Statements of Cash Flows for the six months
	ended June 30, 2008 and 2007	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 Risks	37

Item 4.	Controls and Procedures	39


PART II. OTHER INFORMATION
Item 1A.	Risk Factors	40

Item 4.	Submission of Matters to a Vote of Security Holders	40

Item 6.	Exhibits	40

	Signatures	42

CLAYTON WILLIAMS ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

ASSETS
	June 30,			December 31,
	2008			2007
	(Unaudited)
CURRENT ASSETS
Cash and cash equivalents	$	17,492		$	12,344
Accounts receivable:
Oil and gas sales, net		55,904			36,698
Joint interest and other, net		16,829			16,666
Affiliates		601			308
Inventory		19,770			14,348
Deferred income taxes		3,581			3,581
Fair value of derivatives		-			7,191
Assets held for sale		-			17,281
Prepaids and other		10,346			3,962
		124,523			112,379

PROPERTY AND EQUIPMENT
Oil and gas properties, successful efforts method		1,404,221			1,374,090
Natural gas gathering and processing systems		17,808			18,404
Contract drilling equipment		90,573			89,956
Other		14,619			14,505
		1,527,221			1,496,955
Less accumulated depreciation, depletion and amortization		(760,957	)		(765,877	)
Property and equipment, net		766,264			731,078



OTHER ASSETS
Debt issue costs, net		6,840			6,963
Other		14,814			10,676
		21,654			17,639
	$	912,441		$	861,096

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

CLAYTON WILLIAMS ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

LIABILITIES AND STOCKHOLDERS' EQUITY
	June 30,		December 31,
	2008		2007
	(Unaudited)
CURRENT LIABILITIES
Accounts payable:
Trade	$	106,961	$	72,477
Oil and gas sales		28,350		24,806
Affiliates		2,930		1,747
Current maturities of long-term debt		18,750		22,500
Fair value of derivatives		147,506		56,929
Accrued liabilities and other		10,610		10,308
		315,107		188,767

NON-CURRENT LIABILITIES
Long-term debt		309,000		430,175
Deferred income taxes		38,565		44,302
Fair value of derivatives		47,853		-
Other		35,383		37,046
		430,801		511,523

COMMITMENTS AND CONTINGENCIES

STOCKHOLDERS’ EQUITY
Preferred stock, par value $.10 per share, authorized – 3,000,000
shares; none issued		-		-
Common stock, par value $.10 per share, authorized – 30,000,000
shares; issued and outstanding – 12,112,898 shares in 2008
and 11,354,051 shares in 2007		1,211		1,135
Additional paid-in capital		136,963		121,063
Retained earnings		21,898		35,890
Accumulated other comprehensive income, net of tax		6,461		2,718
		166,533		160,806
	$	912,441	$	861,096

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

CLAYTON WILLIAMS ENERGY, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(Dollars in thousands, except per share)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2008			2007			2008			2007
REVENUES
Oil and gas sales	$	134,291		$	74,893		$	253,210		$	136,073
Natural gas services		3,553			2,909			6,091			5,563
Drilling rig services		12,703			14,228			27,535			22,645
Gain on sales of property and equipment		40,721			534			41,290			784
Total revenues		191,268			92,564			328,126			165,065

COSTS AND EXPENSES
Production		21,925			17,840			42,504			35,118
Exploration:
Abandonments and impairments		1,933			23,519			2,230			34,624
Seismic and other		1,562			1,580			5,237			2,470
Natural gas services		3,244			2,904			5,759			5,317
Drilling rig services		9,923			8,506			21,040			13,439
Depreciation, depletion and amortization		24,974			18,487			55,247			33,718
Impairment of property and equipment		-			479			-			1,044
Accretion of abandonment obligations		485			619			1,015			1,237
General and administrative		7,944			4,932			11,392			8,835
Loss on sales of property and equipment		277			-			286			9,323
Total costs and expenses		72,267			78,866			144,710			145,125

Operating income		119,001			13,698			183,416			19,940

OTHER INCOME (EXPENSE)
Interest expense		(6,077	)		(7,986	)		(13,523	)		(15,615	)
Gain (loss) on derivatives		(148,587	)		6,110			(194,696	)		(10,739	)
Other		3,014			3,614			3,669			4,327
Total other income (expense)		(151,650	)		1,738			(204,550	)		(22,027	)

Income (loss) before income taxes		(32,649	)		15,436			(21,134	)		(2,087	)
Income tax (expense) benefit		11,642			(5,357	)		7,420			723
Minority interest, net of tax		(164	)		(1,269	)		(278	)		(2,136	)

NET INCOME (LOSS)	$	(21,171	)	$	8,810		$	(13,992	)	$	(3,500	)

Net income (loss) per common share:
Basic	$	(1.75	)	$	0.78		$	(1.19	)	$	(0.31	)
Diluted	$	(1.75	)	$	0.77		$	(1.19	)	$	(0.31	)

Weighted average common shares outstanding:
Basic		12,111			11,352			11,749			11,236
Diluted		12,111			11,507			11,749			11,236

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

CLAYTON WILLIAMS ENERGY, INC.

CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY

(Unaudited)

(Dollars in thousands)

										Accumulated
										Other		Total
	Common Stock				Additional					Compre-		Compre-
	No. of		Par		Paid-In		Retained			hensive		hensive
	Shares		Value		Capital		Earnings			Income		Loss
BALANCE,
December 31, 2007		11,354	$	1,135	$	121,063	$	35,890		$	2,718
Net loss		-		-		-		(13,992	)		-	$	(13,992	)
Unrealized gain on
marketable securities,
net of tax of $2,015		-		-		-		-			3,743		3,743
Total comprehensive
loss												$	(10,249	)
Issuance of stock through
compensation plans		759		76		15,900		-			-
BALANCE,
June 30, 2008		12,113	$	1,211	$	136,963	$	21,898		$	6,461

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

CLAYTON WILLIAMS ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(Dollars in thousands)

	Six Months Ended
	June 30,
	2008			2007
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss	$	(13,992	)	$	(3,500	)
Adjustments to reconcile net loss to cash
provided by operating activities:
Depreciation, depletion and amortization		55,247			33,718
Impairment of property and equipment		-			1,044
Exploration costs		2,230			34,624
(Gain) loss on sales of property and equipment, net		(41,004	)		8,539
Deferred income taxes		(7,752	)		(723	)
Non-cash employee compensation		1,910			1,110
Unrealized loss on derivatives		145,621			11,236
Settlements on derivatives with financing elements		24,789			12,005
Amortization of debt issue costs		785			625
Accretion of abandonment obligations		1,015			1,237
Minority interest, net of tax		278			2,136

Changes in operating working capital:
Accounts receivable		(19,662	)		(10,657	)
Accounts payable		398			(1,005	)
Other		(442	)		(453	)
Net cash provided by operating activities		149,421			89,936

CASH FLOWS FROM INVESTING ACTIVITIES
Additions to property and equipment		(118,491	)		(120,435	)
Additions to equipment of Larclay JV.		(9	)		(23,415	)
Proceeds from sales of property and equipment		114,049			1,602
Change in equipment inventory		(6,777	)		11,835
Other		785			(8,269	)
Net cash used in investing activities		(10,443	)		(138,682	)

CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt		-			40,500
Proceeds from long-term debt of Larclay JV		4,000			8,727
Repayments of long-term debt		(115,800	)		-
Repayments of long-term debt of Larclay JV		(13,125	)		-
Proceeds from exercise of stock options		15,884			5,970
Settlements on derivatives with financing elements		(24,789	)		(12,005	)
Net cash provided by (used in) financing activities		(133,830	)		43,192

NET INCREASE (DECREASE) IN CASH AND
CASH EQUIVALENTS		5,148			(5,554	)

CASH AND CASH EQUIVALENTS
Beginning of period		12,344			13,840
End of period	$	17,492		$	8,286

SUPPLEMENTAL DISCLOSURES
Cash paid for interest, net of amounts capitalized	$	13,123		$	15,283

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

CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2008

(Unaudited)

1. Nature of Operations

Clayton Williams Energy, Inc. (a Delaware corporation) and its subsidiaries (collectively, the “Company” or “CWEI”) is an independent oil and gas company engaged in the exploration for and development and production of oil and natural gas primarily in its core areas in Texas, Louisiana and New Mexico. Approximately 26% 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 25% is owned by a partnership in which Mr. Williams’ adult children are limited partners.

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

2. Presentation

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

The consolidated financial statements include the accounts of Clayton Williams Energy, Inc., its wholly-owned subsidiaries and the accounts of the Larclay JV (see Note 11). The Company also accounts for its undivided interests in oil and gas limited partnerships using the proportionate consolidation method. Under this method, the Company consolidates its proportionate share of assets, liabilities, revenues and expenses of these limited partnerships utilizing accounting policies followed by the Company. Less than 5% of the Company’s consolidated total assets and total revenues are derived from oil and gas limited partnerships. 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, 2008 and for the interim periods ended June 30, 2008 and 2007 include all adjustments which are necessary for a fair presentation in accordance with accounting principles generally accepted in the United States. These interim results are not necessarily indicative of the results to be expected for the year ending December 31, 2008.

Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States have been condensed or omitted in this Form 10-Q pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”). These consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto included in the Company's Form 10-K for the year ended December 31, 2007.

3. Recent Accounting Pronouncements

In March 2008, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133” (“SFAS 161”). This statement is intended to improve transparency in financial reporting by requiring enhanced disclosures of an entity’s derivative instruments and hedging activities and their effects on the entity’s financial position, financial performance, and cash flows. SFAS 161 applies to all derivative instruments within the scope of SFAS 133 as well as related hedged items, bifurcated derivatives, and non-derivative instruments that are designated and qualify as hedging instruments. Entities with instruments subject to SFAS 161 must provide more robust qualitative disclosures and expanded quantitative disclosures. SFAS 161 is effective prospectively for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application permitted. The Company is currently evaluating the disclosure implications of this statement.

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

4. Long-Term Debt

Long-term debt consists of the following:

	June 30,			December 31,
	2008			2007
	(In thousands)
7¾% Senior Notes, due 2013	$	225,000		$	225,000
Secured bank credit facility, due May 2012		50,000			165,800
Secured term loan of Larclay JV, due June 2011		52,750			61,875
		327,750			452,675
Less current maturities(a)		(18,750	)		(22,500	)
	$	309,000		$	430,175

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

7¾% Senior Notes due 2013

In July 2005, the Company issued, in a private placement, $225 million of aggregate principal amount of 7¾% Senior Notes due 2013 (“Senior Notes”). The Senior Notes were issued at face value and bear interest at 7¾% per year, payable semi-annually on February 1 and August 1 of each year, beginning February 1, 2006.

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

twelve-month period beginning on August 1, 2010, and 100.00% beginning on August 1, 2011 or for any period thereafter, in each case plus accrued and unpaid interest.

The Indenture governing the Senior Notes restricts the ability of the Company and its restricted subsidiaries to: (i) borrow money; (ii) issue redeemable or 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, 2008.

Secured Bank Credit Facility

The Company’s secured bank credit facility provides for a revolving loan facility in an amount not to exceed the lesser of the borrowing base, as established by the banks, or that portion of the borrowing base determined by the Company to be the elected borrowing limit. The borrowing base, which is based on the discounted present value of future net revenues from oil and gas production, is subject to redetermination at any time, but at least semi-annually in May and November, and is made at the discretion of the banks. If, at any time, the redetermined borrowing base is less than the amount of outstanding indebtedness, the Company will be required to (i) pledge additional collateral, (ii) prepay the excess in not more than five equal monthly installments, or (iii) elect to convert the entire amount of outstanding indebtedness to a term obligation based on amortization formulas set forth in the loan agreement. Substantially all of the Company’s oil and gas properties are pledged to secure advances under the credit facility. The borrowing base was reduced in May 2008 from $275 million to $250 million in connection with our sale of certain properties in South Louisiana. In June 2008, we elected to hold the borrowing base at $250 million instead of increasing it to levels supported by the collateral values assigned by the banks. After allowing for outstanding letters of credit totaling $804,000, the Company had $199.2 million available under the credit facility at June 30, 2008.

The revolving credit facility provides for interest at rates based on the agent bank’s prime rate plus margins ranging from .25% to 1%, or if elected by the Company based on LIBOR plus margins ranging from 1.5% to 2.25%. The Company also pays a commitment fee on the unused portion of the revolving credit facility. Interest and fees are payable at least quarterly. The effective annual interest rate on borrowings under the combined credit facility, excluding bank fees and amortization of debt issue costs, for the six months ended June 30, 2008 was 5.2%.

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, 2008.

Secured Term Loan of Larclay JV

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. 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, 2008, the effective interest rate on the Larclay JV term loan was 6.6%.

5. Other Non-Current Liabilities

Other non-current liabilities consist of the following:

	June 30,		December 31,
	2008		2007
	(In thousands)
Abandonment obligations	$	29,062	$	30,994
Minority interest, net of tax		5,164		4,886
Other taxes payable		358		358
Other		799		808
	$	35,383	$	37,046

Changes in abandonment obligations for the six months ended June 30, 2008 and 2007 are as follows:

	Six Months Ended
	June 30,
	2008			2007
	(In thousands)
Beginning of period	$	30,994		$	27,846
Additional abandonment obligations from new wells		228			451
Sales of properties		(1,784	)		(1,036	)
Revisions of previous estimates		(1,391	)		-
Accretion expense		1,015			1,237
End of period	$	29,062		$	28,498

6. Compensation Plans

Stock-Based Compensation

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, 2008 expire 10 years from the date of grant and become exercisable based on varying vesting schedules. The Company issues new shares, not repurchased shares, to option holders that exercise stock options under the 1993 Plan. At June 30, 2008, 101,766 shares remain available for issuance under this plan.

The Company has reserved 86,300 shares of common stock for issuance under the Outside Directors Stock Option Plan (“Directors Plan”). Since the inception of the Directors Plan, the Company has issued options covering 52,000 shares of common stock at option prices ranging from $3.25 to $41.74 per share. All outstanding options expire 10 years from the grant date and are fully exercisable upon issuance. At June 30, 2008, 34,300 shares remain available for issuance under this plan.

The following table sets forth certain information regarding the Company’s stock option plans as of and for the six months ended June 30, 2008:

						Weighted
				Weighted		Average
				Average		Remaining		Aggregate
				Exercise		Contractual		Intrinsic
	Shares			Price		Term		Value (a)
Outstanding at January 1, 2008		811,485		$	20.49
Granted		4,000		$	31.16
Exercised (b)		(758,847	)	$	20.93
Outstanding at June 30, 2008		56,638		$	15.30		3.16	$	5,360,715

Vested at June 30, 2008		56,638		$	15.30		3.16	$	5,360,715
Exercisable at June 30, 2008		56,638		$	15.30		3.16	$	5,360,715

(a) Based on closing price at June 30, 2008 of $109.95 per share.
(b) Cash received for options exercised totaled $15.9 million.

The following table summarizes information with respect to options outstanding at June 30, 2008, all of which are currently exercisable.

	Outstanding and Exercisable Options
			Weighted
		Weighted	Average
		Average	Remaining
		Exercise	Life in
	Shares	Price	Years
Range of exercise prices:
$5.50	27,638	$ 5.50	0.8
$10.00 - $19.74	10,000	$ 11.93	2.8
$22.90 - $41.74	19,000	$ 31.33	6.8
	56,638	$ 15.30	3.2

The following table presents certain information regarding stock-based compensation amounts for the six months ended June 30, 2008 and 2007.

	Six Months Ended
	June 30,
	2008			2007
	(In thousands, except per share)
Weighted average grant date fair value of options granted per share	$	23.06		$	27.56
Intrinsic value of options exercised	$	20,344		$	228

Stock-based employee compensation expense	$	92		$	110
Tax benefit		(32	)		(39	)
Net stock-based employee compensation expense	$	60		$	71

After-Payout Incentive Plan

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

Between 3% and 7.5% of the Company’s economic interests in specified wells drilled or acquired by the Company subsequent to October 2002 are subject to APO Arrangements (excluding properties acquired in a merger with Southwest Royalties, Inc. in May 2004). The Company records its allocable share of the assets, liabilities, revenues, expenses and oil and gas reserves of these APO Arrangements in its consolidated financial statements. The Company recognized $1.8 million of non-cash compensation expense during the six-month period ended June 30, 2008 and $1 million for the six-month period ended June 30, 2007 for the estimated fair value of the APO Arrangements granted during those periods.

Reward Plans

The Company has created four bonus plans designed to reward eligible officers, employees and other service providers for continued quality service to the Company, and to encourage retention of those persons by providing them the opportunity to receive bonus payments that are based on profits derived from a portion of the Company’s working interest in certain wells drilled by the Company.

One bonus plan was activated in January 2007 and established a quarterly bonus amount equal to the after-payout cash flow from a 22.5% working interest in one well. Under the plan, 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.

In June 2008, the Company activated three additional bonus plans. Each of these plans establishes a quarterly bonus amount equal to 7% of the after-payout cash flow from wells drilled in the respective plan areas after the effective date set forth in each plan, which dates range from January 1, 2007 to May 5, 2008. Under these plans, 100% of the quarterly bonus amount is payable to the participants, and the full vesting date is May 5, 2013.

The quarterly bonus amount in these plans is allocated among the participants based on each participant’s bonus percentage. To continue as a participant in the plans, 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 plans, subject to certain restrictions. The full vesting date may be accelerated in the event of a change of control or sale transaction, as defined in the plan documents.

The Company recognizes compensation expense related to these bonus plans over the vesting period. The Company recorded compensation expense of $438,000 for the six months ended June 30, 2008, and $72,000 for the six months ended June 30, 2007, in connection with these bonus plans.

7. Derivatives

Commodity Derivatives

From time to time, the Company utilizes commodity derivatives, consisting of swaps, floors and collars, to attempt to optimize the price received for its oil and gas production. When using swaps to hedge oil and natural gas production, the Company receives a fixed price for the respective commodity and pays a floating market price as defined in each contract (generally NYMEX futures prices), resulting in a net amount due to or from the counterparty. In floor transactions, the Company receives a fixed price (put strike price) if the market price falls below the put strike price for the respective commodity. If the market price is greater than the put strike price, no payments are due from either party. Costless collars are a combination of puts and calls, and contain a fixed floor price (put strike price) and ceiling price (call strike price). If the market price for the respective commodity exceeds the call strike price or falls below the put strike price, then the Company receives the fixed price and pays the market price. If the market price is between the call and the put strike prices, no payments are due from either party. Commodity derivatives are settled monthly as the contract production periods mature.

The following summarizes information concerning the Company’s net positions in open commodity derivatives applicable to periods subsequent to June 30, 2008. The settlement prices of commodity derivatives are based on NYMEX futures prices.

Collars:

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

Swaps:

	Gas				Oil
	MMBtu (a)		Price		Bbls		Price
Production Period:
3rd Quarter 2008		4,000,000	$	9.19		310,000	$	78.96
4th Quarter 2008		4,100,000	$	9.17		400,000	$	82.21
2009		3,600,000	$	9.33		1,440,000	$	85.30
		11,700,000				2,150,000

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

In July 2008, the Company terminated certain fixed-price gas swaps covering 300,000 MMBtu at a price of $10.32 per MMBtu from August 2008 through October 2008, resulting in an aggregate loss of $585,000, which will be paid to the counterparty monthly as the applicable contracts are settled.

In September 2007, the Company terminated certain fixed-priced oil swaps covering 60,000 barrels at a price of $76.65 from July 2008 through December 2008, resulting in an aggregate loss of approximately $663,000, which will be paid to the counterparty monthly as the applicable contracts are settled.

Interest Rate Derivative

At June 30, 2008, the Company was a party to one interest rate swap. Under this derivative, the Company pays a fixed rate for the notional principal balance and receives a floating market rate based on LIBOR. The interest rate swap is settled quarterly. The following summarizes information concerning the Company’s interest rate swap at June 30, 2008.

Interest Rate Swap:

			Fixed
	Principal		Libor
	Balance		Rates
Period:
July 1, 2008 to November 3, 2008	$	45,000,000		5.73	%

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

Accounting For Derivatives

The Company accounts for its derivatives in accordance with SFAS 133. The Company did not designate any of its currently open commodity or interest rate derivatives as cash flow hedges; therefore, all changes in the fair value of these contracts prior to maturity, plus any realized gains or losses at maturity, are recorded as other income (expense) in the Company’s statements of operations. For the six months ended June 30, 2008, the Company reported a $194.7 million net loss on derivatives, consisting of a $145.6 million loss related to changes in mark-to-market valuations and a $49.1 million realized loss for settled contracts. 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, net of a $500,000 realized gain on settled contracts.

8. Financial Instruments

Cash and cash equivalents, receivables, accounts payable and accrued liabilities were each estimated to have a fair value approximating the carrying amount due to the short maturity of those instruments. Indebtedness under the Company’s 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, 2008 and December 31, 2007 was approximately $216 million and $196.9 million, respectively, based on market valuations.

Determination of Fair Value

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

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

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

Level 1 -

Inputs are unadjusted, quoted prices in active markets for identical assets or liabilities at the measurement date.

Level 2 -

Inputs (other than quoted prices included in Level 1) are either directly or indirectly observable for the asset or liability through correlation with market data at the measurement date and for the duration of the instrument’s anticipated life.

Level 3 -

Inputs reflect management’s best estimate of what market participants would use in pricing the asset or liability at the measurement date. Consideration is given to the risk inherent in the valuation technique and the risk inherent in the inputs to the model.

The fair value of the Company’s investment in common stock of SandRidge is measured using Level 1 inputs, and is determined by market prices on an active market.

The fair value of derivative contracts are measured using Level 2 inputs, and are determined by either market prices on an active market for similar assets or by prices quoted by a broker or other market-corroborated prices.

The estimated fair values of assets and liabilities included in the accompanying consolidated balance sheets at June 30, 2008 and December 31, 2007 are summarized below.

	Fair Value Measurements
	June 30, 2008				December 31, 2007
	Quoted Prices In		Significant		Quoted Prices In		Significant
	Active Markets For		Other		Active Markets For		Other
	Identical		Observable		Identical		Observable
	Assets/Liabilities		Inputs		Assets/Liabilities		Inputs
Description	Level 1		Level 2		Level 1		Level 2
	(In thousands)
Assets:
Fair value of commodity
derivatives	$	-	$	-	$	-	$	7,191
Investment securities		12,946		-		7,188		-
Total assets	$	12,946	$	-	$	7,188	$	7,191
Liabilities:
Fair value of derivatives:
Commodity derivatives	$	-	$	194,701	$	-	$	55,885
Interest derivatives		-		658		-		1,044
Total liabilities	$	-	$	195,359	$	-	$	56,929

9. Inventory

The Company maintains an inventory of tubular goods and other well equipment for use in its exploration and development drilling activities. Any gains or losses on disposition of inventory, and any losses on write-down of inventory to its estimated market value, are reported as gain or loss on sales of property and equipment in the accompanying consolidated statements of operations. The 2007 period included a charge of $8.9 million to write-down inventory to its estimated market value at 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.

10. Income Taxes

The Company’s effective federal and state income tax rate for the six months ended June 30, 2008 of 35.1% differed from the statutory federal rate of 35% due to tax benefits derived from excess 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. The Company’s tax returns for fiscal years after 2002 currently remain subject to examination by appropriate taxing authorities. None of the Company’s income tax returns are under examination at this time.

In June 2006, the FASB issued Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (“FIN 48”). Upon adoption of FIN 48, the Company recorded a liability for taxes payable related to unrecognized tax benefits arising from uncertain tax positions taken by the Company in previous periods. A reconciliation of the changes in this tax liability as of June 30, 2008 and December 31, 2007 is as follows:

	June 30,		December 31,
	2008		2007
	(In thousands)
Balance at beginning of period	$	358	$	-
Adoption of FIN 48 on January 1, 2007		-		1,585
Reductions for tax positions of prior years		-		(1,227	)
Balance at end of period	$	358	$	358

No unrecognized tax benefits originated during the first six months of 2008. Reductions in the 2007 tax liability resulted from changes in accounting methods which were submitted to the taxing authority during 2007. All of the remaining unrecognized tax benefits at June 30, 2008 relate to tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductions. Because of the impact of deferred tax accounting, the disallowance of the shorter deduction period would not affect the annual effective tax rate but would only accelerate the payment of taxes to the taxing authority or change the amount of deferred tax assets related to net operating loss carryforwards.

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

11. Investments

Larclay JV

In April 2006, the Company formed a joint venture (“Larclay JV”) with Lariat Services, Inc. (“Lariat”) to construct, own and operate 12 new drilling rigs. The Company and Lariat each own a 50% interest in Larclay JV. A lender has provided a $75 million secured term loan to Larclay JV to finance most of the cost of constructing and initially equipping the rigs (see Note 4). The Company has made loans to Larclay JV totaling $8.6 million to finance excess construction costs and its 50% share of working capital assessments made by Larclay JV. Loans to Larclay JV are due on demand and bear interest, payable monthly, at the same rate as the secured term loan. However, the loans are subject to a subordination agreement with the secured lender that imposes restrictions on payments of principal and interest on the loans.

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 $59.2 million at June 30, 2008. The Company paid $489,000 for idle rig fees during the six months ended June 30, 2008.

Although the Company and Lariat own equal interests in Larclay JV, the Company meets the definition of the primary beneficiary of Larclay JV’s expected cash flows under FIN 46R. As the primary beneficiary under FIN 46R, the Company is required to include the accounts of Larclay JV in the Company’s consolidated financial statements. As of June 30, 2008, Lariat’s equity ownership in the net assets of Larclay JV was $5.2 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 and profits with Larclay JV have been eliminated in consolidation.

SandRidge Energy Inc.

The Company owns 200,460 shares of common stock in SandRidge Energy Inc. (“SandRidge”). During the fourth quarter of 2007, SandRidge became publicly traded and listed its shares on the New York Stock Exchange. The Company’s original cost investment in SandRidge was increased to fair market value in 2007 and the change in fair market value of $4.2 million, net of tax of $1.5 million, was recorded in accumulated other comprehensive income at December 31, 2007. The fair value of the Company’s investment in SandRidge at June 30, 2008 is $12.9 million and is recorded in other non-current assets, based on the closing price of the stock as of June 30, 2008. The change in fair market value during the six months ended June 30, 2008 of $5.8 million, net of tax of $2 million, was recorded in accumulated other comprehensive income.

12. Oil and Gas Properties

The following sets forth the capitalized costs for oil and gas properties as of June 30, 2008 and December 31, 2007.

	June 30,			December 31,
	2008			2007
	(In thousands)
Proved properties	$	1,248,832		$	1,258,166
Unproved properties		155,389			115,924
Total capitalized costs		1,404,221			1,374,090
Accumulated depreciation, depletion and amortization		(717,960	)		(727,739	)
Net capitalized costs	$	686,261		$	646,351

13. Sales of Property and Equipment

In April 2008, the Company and its affiliates sold all of their interests in 16 producing wells for approximately $89.2 million, net of customary closing adjustments. The Company recorded a gain of approximately $33.1 million in the second quarter of 2008 in connection with this transaction. Also, in April 2008, the Company sold a surplus well servicing unit for $1.8 million and recorded a gain of approximately $75,000 in the second quarter of 2008 and also sold two 2,000 horsepower drilling rigs in June 2008 for $21.8 million, net of customary closing adjustments and recorded a gain of $5.7 million.

14. Segment Information

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.

The following tables present selected financial information regarding the Company’s operating segments for the three-month and six-month periods ended June 30, 2008 and 2007.

For the Three Months Ended				Contract			Intercompany			Consolidated
June 30, 2008	Oil and Gas			Drilling			Eliminations			Total
	(In thousands)
Revenues	$	178,076		$	16,874		$	(3,682	)	$	191,268
Depreciation, depletion and amortization (a)		22,860			2,623			(509	)		24,974
Other operating expenses (b)		37,235			12,753			(2,695	)		47,293
Interest expense		5,136			941			-			6,077
Other (income) expense		145,573			-			-			145,573
Income (loss) before income taxes and
minority interest		(32,728	)		557			(478	)		(32,649	)

Income tax (expense) benefit		11,891			(249	)		-			11,642
Minority interest, net of tax		87			(251	)		-			(164	)

Net income (loss)	$	(20,750	)	$	57		$	(478	)	$	(21,171	)

Total assets	$	826,711		$	95,304		$	(9,574	)	$	912,441
Additions to property and equipment	$	93,395		$	608		$	(478	)	$	93,525

For the Six Months Ended				Contract			Intercompany			Consolidated
June 30, 2008	Oil and Gas			Drilling			Eliminations			Total
	(In thousands)
Revenues	$	300,102		$	34,037		$	(6,013	)	$	328,126
Depreciation, depletion and amortization (a)		50,848			5,233			(834	)		55,247
Other operating expenses (b)		68,050			25,761			(4,348	)		89,463
Interest expense		11,488			2,035			-			13,523
Other (income) expense		191,027			-			-			191,027
Income (loss) before income taxes and
minority interest		(21,311	)		1,008			(831	)		(21,134	)

Income tax (expense) benefit		7,927			(507	)		-			7,420
Minority interest, net of tax		149			(427	)		-			(278	)

Net income (loss)	$	(13,235	)	$	74		$	(831	)	$	(13,992	)

Total assets	$	826,711		$	95,304		$	(9,574	)	$	912,441
Additions to property and equipment	$	148,826		$	617		$	(831	)	$	148,612

For the Three Months Ended				Contract			Intercompany			Consolidated
June 30, 2007	Oil and Gas			Drilling			Eliminations			Total
	(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 (loss) before income taxes and
minority interest		11,835			3,904			(303	)		15,436

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

Net income (loss)	$	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				Contract			Intercompany			Consolidated
June 30, 2007	Oil and Gas			Drilling			Eliminations			Total
	(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

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

15. Guarantor Financial Information

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

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

Condensed Consolidating Balance Sheet

June 30, 2008

(Unaudited)					Non-
(Dollars in thousands)			Guarantor		Guarantor		Adjustments/
	Issuer		Subsidiaries		Entities		Eliminations			Consolidated
Current assets	$	127,770	$	116,405	$	20,853	$	(140,505	)	$	124,523
Property and equipment, net		378,977		305,810		81,477		-			766,264
Investments in subsidiaries		86,533		-		-		(86,533	)		-
Other assets		29,645		353		256		(8,600	)		21,654
Total assets	$	622,925	$	422,568	$	102,586	$	(235,638	)	$	912,441

Current liabilities	$	241,652	$	176,451	$	37,509	$	(140,505	)	$	315,107
Non-current liabilities:
Long-term debt		275,000		-		42,600		(8,600	)		309,000
Fair value of derivatives		47,853		-		-		-			47,853
Other		17,431		56,411		106		-			73,948
		340,284		56,411		42,706		(8,600	)		430,801

Stockholders’ equity		40,989		189,706		22,371		(86,533	)		166,533
Total liabilities and
stockholders’ equity	$	622,925	$	422,568	$	102,586	$	(235,638	)	$	912,441

Condensed Consolidating Balance Sheet

December 31, 2007

(Dollars in thousands)					Non-
			Guarantor		Guarantor		Adjustments/
	Issuer		Subsidiaries		Entities		Eliminations			Consolidated
Current assets	$	127,668	$	109,010	$	21,225	$	(145,524	)	$	112,379
Property and equipment, net		369,421		275,609		86,048		-			731,078
Investments in subsidiaries		81,583		-		-		(81,583	)		-
Other assets		21,354		340		545		(4,600	)		17,639
Total assets	$	600,026	$	384,959	$	107,818	$	(231,707	)	$	861,096

Current liabilities	$	112,536	$	179,243	$	42,512	$	(145,524	)	$	188,767
Non-current liabilities:
Long-term debt		390,800		-		43,975		(4,600	)		430,175
Other		24,708		56,528		112		-			81,348
		415,508		56,528		44,087		(4,600	)		511,523

Stockholders’ equity		71,982		149,188		21,219		(81,583	)		160,806
Total liabilities and
stockholders’ equity	$	600,026	$	384,959	$	107,818	$	(231,707	)	$	861,096

Condensed Consolidating Statement of Operations

Three Months Ended June 30, 2008

(Unaudited)							Non-
(Dollars in thousands)				Guarantor			Guarantor			Adjustments/
	Issuer			Subsidiaries			Entities			Eliminations			Consolidated
Total revenue	$	127,281		$	51,269		$	17,217		$	(4,499	)	$	191,268
Costs and expenses		39,800			20,972			15,516			(4,021	)		72,267
Operating income (loss)		87,481			30,297			1,701			(478	)		119,001
Other income (expense)		(141,834	)		(8,912	)		(904	)		-			(151,650	)
Income tax benefit		11,642			-			-			-			11,642
Minority interest, net of tax		(164	)		-			-			-			(164	)
Net income (loss)	$	(42,875	)	$	21,385		$	797		$	(478	)	$	(21,171	)

Condensed Consolidating Statement of Operations

Six Months Ended June 30, 2008

(Unaudited)							Non-
(Dollars in thousands)				Guarantor			Guarantor			Adjustments/
	Issuer			Subsidiaries			Entities			Eliminations			Consolidated
Total revenue	$	207,513		$	93,242		$	34,580		$	(7,209	)	$	328,126
Costs and expenses		79,671			40,100			31,317			(6,378	)		144,710
Operating income (loss)		127,842			53,142			3,263			(831	)		183,416
Other income (expense)		(190,103	)		(12,490	)		(1,957	)		-			(204,550	)
Income tax benefit		7,420			-			-			-			7,420
Minority interest, net of tax		(278	)		-			-			-			(278	)
Net income (loss)	$	(55,119	)	$	40,652		$	1,306		$	(831	)	$	(13,992	)

Condensed Consolidating Statement of Operations

Three Months Ended June 30, 2007

(Unaudited)						Non-
(Dollars 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

Condensed Consolidating Statement of Operations

Six Months Ended June 30, 2007

(Unaudited)							Non-
(Dollars 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	)

Condensed Consolidating Statement of Cash Flows

Six Months Ended June 30, 2008

(Unaudited)							Non-
(Dollars in thousands)				Guarantor			Guarantor			Adjustments/
	Issuer			Subsidiaries			Entities			Eliminations			Consolidated
Operating activities	$	72,828		$	72,085		$	3,675		$	833		$	149,421
Investing activities		37,709			(46,480	)		(839	)		(833	)		(10,443	)
Financing activities		(103,553	)		(25,166	)		(5,111	)		-			(133,830	)
Net increase (decrease) in
cash and cash equivalents		6,984			439			(2,275	)		-			5,148

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

Cash at end of the period	$	12,309		$	1,727		$	3,456		$	-		$	17,492

Condensed Consolidating Statement of Cash Flows

Six Months Ended June 30, 2007

(Unaudited)							Non-
(Dollars 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

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

The following discussion is intended to provide information relevant to an understanding of our financial condition, changes in our financial condition and our results of operations and cash flows and should be read in conjunction with our consolidated financial statements and notes thereto included elsewhere in this Form 10-Q and in our Form 10-K for the year ended December 31, 2007.

Forward-Looking Statements

Certain information included in this quarterly report contains forward-looking statements that are based on management’s current expectations. Forward-looking statements include statements regarding our plans, beliefs or current expectations and may be signified by the words “could”, “should”, “expect”, “project”, “estimate”, “believe”, “anticipate”, “intend”, “budget”, “plan”, “forecast”, “predict” and other similar expressions. Forward-looking statements appear throughout this Form 10-Q with respect to, among other things: profitability; planned capital expenditures; estimates of oil and gas production; future project dates; estimates of future oil and gas prices; estimates of oil and gas reserves; our future financial condition or results of operations; and our business strategy and other plans and objectives for future operations. Actual results in future periods may differ materially from those expressed or implied by such forward-looking statements because of a number of risks and uncertainties affecting our business, including those discussed in “Item 1 – Business – Risk Factors” included in our Form 10-K for the year ended December 31, 2007. We disclaim any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

Overview

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

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

Finding quality domestic oil and gas reserves through exploration is a significant challenge and involves a high degree of risk. DD&A per Mcfe of oil and gas production, an operating metric that measures a company’s cumulative cost to find or purchase a unit of production, increased significantly from the first six months of 2007 to the first six months of 2008. Approximately 73% of our planned activities for 2008 relate to developmental prospects that are not expected to materially reduce our reported DD&A per Mcfe.

Key Factors to Consider

The following summarizes the key factors considered by management in the review of our financial condition and operating performance for the second quarter of 2008 and the outlook for the remainder of 2008.

·	Our oil and gas sales for the second quarter increased $59.4 million, or 79%, from 2007. Price variances accounted for 98% of this increase, and incremental production accounted for the remaining 2%.

We recorded a net gain on the sale of property and equipment of $40.4 million during the second quarter of 2008. We sold all of our interests in 16 producing wells in South Louisiana resulting in a gain of approximately $33.1 million. We also sold two drillings and a surplus well servicing unit for a net gain of approximately $5.7 million in the second quarter of 2008.

Our oil and gas production for the second quarter of 2008 was 4% lower on an Mcfe basis than in the comparable period in 2007. Our oil production was 22% higher than the second quarter of 2007 and gas production was 19% lower compared to the 2007 period. The growth in oil production was attributed to in-fill drilling in the Austin Chalk (Trend) and increased drilling activities in the Permian Basin. As adjusted for the South Louisiana asset sale, gas production was favorably impacted by incremental production from drilling activities in North Louisiana.

We recorded a $148.6 million net loss on derivatives in the second quarter of 2008. We recorded a $35 million realized loss on settled contracts and a $113.6 million loss for changes in mark-to-market valuations. Since we do not presently designate our derivatives as cash flow hedges under applicable accounting standards, we recognize the full effect of changing prices on mark-to-market valuations as a current charge or credit to our results of operations.

·	During 2008, we decreased borrowings under our revolving credit facility by $115.8 million from $165.8 million at December 31, 2007 to $50 million at June 30, 2008 due primarily from proceeds from the sale of assets.

At June 30, 2008, our capitalized unproved oil and gas properties totaled $155.4 million, of which approximately $86.1 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.

Recent Exploration and Developmental Activities

Overview

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

As discussed in “Liquidity and Capital Resources – Capital Expenditures,” we incurred expenditures for exploration and development activities of $154.7 million during the first six months of 2008, of which approximately 19% were related to exploratory drilling and leasing activities. We also increased our estimates for capital expenditures in fiscal 2008 from $344.5 million to $400.7 million. The increase in capital spending relates primarily to planned developmental drilling activities in the Permian Basin and North Louisiana and exploratory drilling activities in South Louisiana.

Permian Basin

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

We spent $60.4 million in the Permian Basin during the first half of 2008 on exploration and development activities, of which $54 million was spent on drilling and completion activities and $6.4 million was spent on seismic and leasing activities. We drilled 18 gross (16.3 net) operated wells in the Permian Basin and conducted various remedial operations on other wells in the first half of 2008.

The Permian Basin continues to be a significant source of cash flow for us. We currently expect to spend $123.7 million on developmental drilling activities in the Permian Basin during the last half of 2008. Most of the planned drilling activities in the Permian Basin relate to our War-Wink, Amacker-Tippett Andrews County, and Barstow areas of West Texas. In the War-Wink area, we are presently drilling horizontal wells targeting oil-prone sands in the Bone Spring formation. In the Amacker-Tippett, Andrews County and Barstow areas, our planned drilling activities relate primarily to wells targeting oil-prone sands in the Spraberry and Wolfcamp formations.

Austin Chalk (Trend)

Prior to 1998, we concentrated our drilling activities in an oil-prone area we refer to as the Austin Chalk (Trend) in Robertson, Burleson, Brazos, Milam and Leon Counties, Texas. Most of our wells in this area were drilled as horizontal wells, many with multiple laterals in different producing horizons, including the Austin Chalk, Buda and Georgetown formations. The existing spacing between some of our wells in this area affords us the opportunity to tap additional oil and gas reserves by drilling new wells between existing wells, a technique referred to as in-fill drilling. These in-fill wells are considered lower risk as compared to exploratory wells and, with oil prices at current levels, we believe that the rates of return are now attractive. In addition, we are conducting secondary water frac operations on existing wells in the Austin Chalk (Trend) area to improve production rates and add new reserves. We spent $28.6 million in the Austin Chalk (Trend) area during the first half of 2008 and currently plan to spend an additional $28.9 million primarily on developmental drilling and recompletion activities during the last half of 2008.

North Louisiana

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

We spent $34.6 million in North Louisiana during the first half of 2008 on exploration and development activities, of which $32.6 million was spent on drilling and completion activities and $2 million was spent on seismic and leasing activities. We currently plan to spend an additional $48.8 million in North Louisiana during the last half of 2008.

To date, we have drilled 16 wells on our Terryville prospect and have completed 14 as producers, with one well waiting on completion activities to commence. We plan to drill two additional development wells on this prospect during the remainder of 2008. On our Ruston prospect, we have completed two wells as producers and are currently drilling a third well. We plan to drill two additional wells on this prospect during the remainder of 2008.

In 2007, adverse drilling conditions forced us to abandon the David Barton #1, an exploratory well in the Winnsboro prospect in Richland Parish, prior to reaching the pressured Bossier formation. We are currently drilling an offset to this well.

South Louisiana

Prior to 2008, we had drilled 75 gross (60.3 net) exploratory wells in South Louisiana, of which 39 gross (30 net) were completed as producers.

We spent $17 million in South Louisiana during the first half of 2008 on exploration and development activities, of which $15.2 million was spent on drilling and completion activities and $1.8 was spent on seismic and leasing activities. We have completed two development wells on our Fleur prospect in Plaquemines Parish and plan to drill another well during the remainder of 2008.

In late 2007, we entered into an agreement with an industry partner, under which they have committed to drill five wells on certain of our prospects in South Louisiana during 2008. The industry partner will operate the wells, and we will have a 15% before casing point working interest and a 50% after casing point working interest in each well drilled. To date, three wells have been completed and are awaiting production facilities, and two additional wells are planned for the last half of 2008.

In April 2008, we sold all of our interests in 16 producing wells in South Louisiana to an industry partner for approximately $89.2 million, net of customary closing adjustments, and recorded a gain of $33.1 million in the second quarter of 2008 in connection with this transaction.

We currently plan to spend an additional $18.7 million in South Louisiana during the last half of 2008 primarily to participate in drilling an exploratory well in Plaquemines Parish on our West Lake Washington prospect and to drill a development well on our Fleur prospect.

East Texas Bossier

We currently have approximately 145,000 net acres under lease in East Texas targeting the prolific deep Bossier sands which are encountered at depths ranging from 14,000 to 22,000 feet in this area. Of this acreage, approximately 70,000 net acres are held by production from existing Austin Chalk (Trend) wells. Exploration for deep Bossier gas sands in this area is in its early stages and involves a high degree of risk. The geological structures are complex, and limited drilling activity offers minimal subsurface control. Deep Bossier wells are expensive to drill, with completed wells costing approximately $18 million each. Although seismic data is helpful in identifying possible sand accumulations, the only way to determine if the deep Bossier sand will be commercially productive is to drill wells to the targeted structures.

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

We spent $11.8 million in the East Texas Bossier area during the first half of 2008 and currently plan to spend approximately $18.5 million during the remainder of the year for leasing and seismic activities. Although the results of the Big Bill Simpson #1 and the Margarita #1 to date have not met our expectations, we are optimistic that our acreage position in this area is prospective for potentially significant deep Bossier discoveries. As more wells are drilled and more subsurface control data is obtained, we believe our prospects for discoveries improve. We have begun a 3-D seismic shoot in Leon County, Texas over the Big Bill Simpson prospect in an attempt to more clearly define the location of our next well on this acreage. In addition, we are conducting a proprietary 3-D shoot in Burleson County, Texas to help identify other potential drill sites for deep Bossier tests in this area.

Other

In Utah, we plan to participate in the drilling of a 12,000-foot exploratory well, the Lamb #1 in the Overthrust prospect (33% working interest) in Sanpete County, Utah. The well will target the oil-prone Navajo sandstone formation.

Supplemental Information

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

	Three Months Ended
	June 30,
	2008			2007
Oil and Gas Production Data:
Gas (MMcf)		4,177			5,151
Oil (MBbls)		703			577
Natural gas liquids (MBbls)		41			57
Total (MMcfe)		8,641			8,955

Average Realized Prices (a):
Gas ($/Mcf)	$	11.07		$	7.20
Oil ($/Bbl)	$	121.51		$	62.51
Natural gas liquids ($/Bbl)	$	63.63		$	42.84

Gain (Losses) on Settled Derivative Contracts (a):
($ in thousands, except per unit)
Gas: Net realized gain (loss)	$	(10,287	)	$	473
Per unit produced ($/Mcf)	$	(2.46	)	$	.09
Oil: Net realized loss	$	(23,348	)	$	(1,971	)
Per unit produced ($/Bbl)	$	(33.21	)	$	(3.42	)

Average Daily Production:
Natural Gas (Mcf):
Permian Basin		14,284			13,724
North Louisiana		15,233			5,229
South Louisiana		7,347			27,206
Austin Chalk (Trend)		2,133			2,445
Cotton Valley Reef Complex		6,277			7,651
Other		627			349
Total		45,901			56,604

Oil (Bbls):
Permian Basin		3,568			3,135
North Louisiana		386			153
South Louisiana		105			1,333
Austin Chalk (Trend)		3,575			1,627
Other		91			93
Total		7,725			6,341

Natural Gas Liquids (Bbls):
Permian Basin		153			226
Austin Chalk (Trend)		241			251
Other		57			149
Total		451			626

(Continued)

	Three Months Ended
	June 30,
	2008		2007
Exploration Costs (in thousands):
Abandonment and impairment costs:
North Louisiana	$	1,865	$	8,679
South Louisiana		-		14,217
Other		68		623
Total		1,933		23,519

Seismic and other		1,562		1,580
Total exploration costs	$	3,495	$	25,099

Depreciation, Depletion and Amortization (in thousands):
Oil and gas depletion	$	22,598	$	16,331
Contract drilling depreciation		2,115		1,862
Other depreciation		261		294
Total DD&A	$	24,974	$	18,487

Oil and Gas Costs ($/Mcfe Produced):
Production costs	$	2.54	$	1.99
Oil and gas depletion	$	2.62	$	1.82

Net Wells Drilled (b):
Exploratory Wells		1.0		4.2
Developmental Wells		22.7		5.7

	Six Months Ended
	June 30,
	2008			2007
Oil and Gas Production Data:
Gas (MMcf)		9,725			9,478
Oil (MBbls)		1,387			1,120
Natural gas liquids (MBbls)		99			103
Total (MMcfe)		18,641			16,816

Average Realized Prices (a):
Gas ($/Mcf)	$	9.81		$	7.06
Oil ($/Bbl)	$	109.05		$	58.95
Natural gas liquids ($/Bbl)	$	58.47		$	38.58

Gain (Losses) on Settled Derivative Contracts (a):
($ in thousands, except per unit)
Gas: Net realized gain (loss)	$	(11,171	)	$	4,982
Per unit produced ($/Mcf)	$	(1.15	)	$	.53
Oil: Net realized loss	$	(36,254	)	$	(4,530	)
Per unit produced ($/Bbl)	$	(26.14	)	$	(4.04	)

(Continued)

	Six Months Ended
	June 30,
	2008		2007
Average Daily Production:
Natural Gas (Mcf):
Permian Basin		14,665		14,552
North Louisiana		14,611		3,815
South Louisiana		15,405		23,695
Austin Chalk (Trend)		2,333		2,228
Cotton Valley Reef Complex		5,857		7,674
Other		563		401
Total		53,434		52,365

Oil (Bbls):
Permian Basin		3,532		3,117
North Louisiana		365		91
South Louisiana		545		1,256
Austin Chalk (Trend)		3,104		1,647
Other		75		77
Total		7,621		6,188

Natural Gas Liquids (Bbls):
Permian Basin		185		211
Austin Chalk (Trend)		258		259
Other		101		99
Total		544		569

Exploration Costs (in thousands):
Abandonment and impairment costs:
Permian Basin	$	-	$	989
North Louisiana		2,162		8,985
South Louisiana		-		21,396
Other		68		3,254
Total		2,230		34,624

Seismic and other		5,237		2,470
Total exploration costs	$	7,467	$	37,094

Depreciation, Depletion and Amortization (in thousands):
Oil and gas depletion	$	50,339	$	29,879
Contract drilling depreciation		4,400		3,245
Other depreciation		508		594
Total DD&A	$	55,247	$	33,718

Oil and Gas Costs ($/Mcfe Produced):
Production costs	$	2.28	$	2.09
Oil and gas depletion	$	2.70	$	1.78

Net Wells Drilled (b):
Exploratory Wells		2.7		9.2
Developmental Wells		35.7		9.2

(a) No derivatives were designated as cash flow hedges in 2008 or 2007. All gains or losses on settled derivatives were included in loss on derivatives.
(b) Excludes wells being drilled or completed at the end of each period.

Operating Results – Three-Month Periods

The following discussion compares our results for the three months ended June 30, 2008 to the comparative period in 2007. Unless otherwise indicated, references to 2008 and 2007 within this section refer to the respective quarterly period.

Oil and gas operating results

Oil and gas sales in 2008 increased $59.4 million, or 79%, from 2007. Price variances accounted for a $58.5 million increase, and production variances accounted for a $900,000 increase. Production in 2008 (on an Mcfe basis) was 4% lower than 2007, despite significant additions from our on-going developmental drilling programs, due to the loss of production from the sale of South Louisiana assets in April 2008. Oil production increased 22% in 2008 from 2007 and gas production decreased 19% in 2008 from 2007. The growth in oil production was attributed to in-fill drilling in the Austin Chalk (Trend) and increased drilling activities in the Permian Basin. As adjusted for the South Louisiana asset sale, gas production was favorably impacted by incremental production from drilling activities in North Louisiana. In 2008, our realized oil price was 94% higher than 2007, while our realized gas price was 54% 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 23% in 2008 as compared to 2007. Increases in oilfield service costs, higher repair and maintenance costs, saltwater disposal fees and higher production taxes related to higher commodity prices were key components for the rise in production costs. It is likely that these factors will continue to contribute to higher production costs in future periods. After giving effect to a 4% decrease in oil and gas production on an Mcfe basis, production costs per Mcfe increased 28% from $1.99 per Mcfe in 2007 to $2.54 per Mcfe in 2008.

Oil and gas depletion expense increased $6.3 million from 2007 to 2008, of which rate variances accounted for a $6.8 million increase and production variances accounted for a $500,000 decrease. On an Mcfe basis, depletion expense increased 44% from $1.82 per Mcfe in 2007 to $2.62 per Mcfe in 2008 due in part to a higher depletable cost basis in 2008 compared to the 2007 period. Depletion expense per Mcfe of oil and gas production is an operating metric that is indicative of our weighted average cost to find or acquire a unit of equivalent production. We may realize higher oil and gas depletion rates in future periods if our exploration and development activities result in higher finding costs.

Exploration costs

Since we follow the successful efforts method of accounting, our results of operations are adversely affected during any accounting period in which significant seismic costs, exploratory dry hole costs, and unproved acreage impairments are expensed. In 2008, we charged to expense $3.5 of exploration costs, as compared to $25.1 million in 2007.

We plan to spend approximately $400.7 million on exploration and development activities in 2008, of which approximately 27% is expected to be allocated to exploration activities. Since exploratory drilling involves a high degree of risk, it is likely that a significant portion of the costs we incur in 2008 will be charged to exploration costs. However, we cannot predict our success rates and, accordingly, cannot predict our exploration costs related to abandonment and impairment costs.

Contract Drilling Services

In April 2006, we formed a joint venture (“Larclay JV”) with Lariat Services, Inc. to construct, own, and operate 12 new drilling rigs. We own a 50% interest in Larclay JV. Although the Company and Lariat own equal interests in Larclay JV, the Company meets the definition of the primary beneficiary of Larclay JV’s expected cash flows under FIN 46R. As the primary beneficiary under FIN 46R, the Company is required to include the accounts of Larclay JV in the Company’s consolidated financial statements. During the three months ended June 30, 2008, we included contract drilling revenues of $16.9 million, other operating expenses of $12.8 million, depreciation expense of $2.6 million and interest expense of $941,000 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

General and administrative (“G&A”) expenses increased 61% from $4.9 million in 2007 to $7.9 million in 2008. Excluding non-cash employee compensation, G&A expenses increased from $4.4 million in 2007 to $6.4 million in 2008 due primarily to cash bonuses paid to employees in connection with our recent sale of properties in South Louisiana. In 2008, we recorded a $1.6 million non-cash charge related to our after payout incentive plan, as compared to a $500,000 non-cash charge in 2007.

Interest expense

Interest expense decreased 24% from $8 million in 2007 to $6 million in 2008 due to a combination of reduced debt levels and lower interest rates. Debt reductions accounted for $1.5 million of the decrease, while lower interest rates resulted in a decrease of approximately $700,000. The average daily principal balance outstanding under our revolving credit facility for 2008 was $94.1 million compared to $175 million for 2007. During 2008, we received approximately $114 million from the sale of assets and used the net proceeds to reduce indebtedness outstanding under our revolving credit facility. In addition, capitalized interest for 2008 was $907,000 compared to $1.1 million in 2007, and interest expense associated with our Larclay JV during 2008 was $941,000 compared to $1 million in 2007.

Gain/loss on derivatives

We did not designate any derivative contracts in 2008 or 2007 as cash flow hedges; therefore all cash settlements and changes resulting from mark-to-market valuations have been recorded as gain/loss on derivatives. For the three months ended June 30, 2008, we reported a $148.6 million net loss on derivatives, consisting of a $113.6 million non-cash loss to mark our derivative positions to their fair value at June 30, 2008 and a $35 million realized loss on settled contracts. 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. Because oil and gas prices are volatile, and because we do not account for our derivatives as cash flow hedges, the effect of mark-to-market valuations on our gain/loss on derivatives can cause significant volatility in our results of operations.

Gain/loss on sales of property and equipment

We recorded a net gain of $40.4 million on sales of property and equipment which included a $33.1 million gain on the sale of properties in South Louisiana and $5.7 million gains on the sales of two drilling rigs and a surplus well servicing unit compared to a $534,000 gain for sales of certain acreage in 2007.

Income tax expense

Our effective income tax rate in 2008 of 35.7% differed from the statutory federal rate of 35% due primarily to increases in the tax provision related primarily to the effects of the recently-enacted Texas Margin Tax and certain non-deductible expenses, offset in part by tax benefits derived from excess statutory depletion deductions.

Operating Results – Six-Month Periods

The following discussion compares our results for the six months ended June 30, 2008 to the comparative period in 2007. Unless otherwise indicated, references to 2008 and 2007 within this section refer to the respective quarterly period.

Oil and gas operating results

Oil and gas sales in 2008 increased $117.1 million, or 86%, from 2007. Price variances accounted for a $98.5 million increase, and production variances accounted for a $18.6 million increase. Production in 2008 (on an Mcfe basis) was 11% higher than 2007. Oil production increased 24% and gas production increased 3% in 2008 from 2007. The growth in oil production was attributed to in-fill drilling in the Austin Chalk (Trend) and increased drilling activities in the Permian Basin. Increases in gas production from our drilling activities in North Louisiana were substantially offset by lower production in South Louisiana caused by the sale of certain properties in April 2008. In 2008, our realized oil price was 85% higher than 2007, while our realized gas price was 39% 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 21% in 2008 as compared to 2007 due primarily to rising oilfield service costs, saltwater disposal fees and higher repair and maintenance costs. In addition higher production taxes related to higher commodity prices contributed to the increase in production costs. It is likely that these factors will continue to contribute to higher production costs in future periods. After giving effect to a 11% increase in oil and gas production on an Mcfe basis, production costs per Mcfe increased 9% from $2.09 per Mcfe in 2007 to $2.28 per Mcfe in 2008.

Oil and gas depletion expense increased $20.5 million from 2007 to 2008, of which production variances accounted for a $3.2 million increase and rate variances accounted for a $17.3 million increase. On an Mcfe basis, depletion expense increased 52% from $1.78 per Mcfe in 2007 to $2.70 per Mcfe in 2008 due in part to a higher depletable cost basis in 2008 compared to the 2007 period. Depletion expense per Mcfe of oil and gas production is an operating metric that is indicative of our weighted average cost to find or acquire a unit of equivalent production. We may realize higher oil and gas depletion rates in future periods if our exploration and development activities result in higher finding costs.

Exploration costs

Since we follow the successful efforts method of accounting, our results of operations are adversely affected during any accounting period in which significant seismic costs, exploratory dry hole costs, and unproved acreage impairments are expensed. In 2008, we charged to expense $7.5 of exploration costs, as compared to $37.1 million in 2007. All of the 2008 costs were incurred in Louisiana.

At June 30, 2008, our capitalized unproved oil and gas properties totaled $155.4 million, of which approximately 86.1 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.

Contract Drilling Services

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, 2008, we included contract drilling revenues of $34 million, other operating expenses of $25.8 million, depreciation expense of $5.2 million and interest expense of $2 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

General and administrative (“G&A”) expenses increased 29% from $8.8 million in 2007 to $11.4 million in 2008. Excluding non-cash employee compensation, G&A expenses increased from $7.7 million in 2007 to $9.5 million in 2008 due primarily to cash bonuses paid to employees in connection with our recent sale of properties in South Louisiana. In 2008, we recorded a $1.8 million non-cash compensation charge related to our after payout incentive plan and $92,000 for stock-based employee compensation. 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

Interest expense decreased 13% from $15.6 million in 2007 to $13.5 million in 2008 due to a combination of reduced debt levels and lower interest rates. Debt reductions accounted for $1.2 million of the decrease, while lower interest rates resulted in a decrease of approximately $1.6 million. The average daily principal balance outstanding under our revolving credit facility for 2008 was $134.3 million compared to $167.1 million for 2007. During 2008, we received approximately $114 million from the sale of assets and used the net proceeds to reduce indebtedness outstanding under on our revolving credit facility. In addition, capitalized interest for 2008 was $1.7 million compared to $2.1 million in 2007, and interest expense associated with our Larclay JV during 2008 was $2 million compared to $1.9 million in 2007.

Gain/loss on derivatives

We did not designate any derivative contracts in 2008 or 2007 as cash flow hedges; therefore all cash settlements and changes resulting from mark-to-market valuations have been recorded as gain/loss on derivatives. For the six months ended June 30, 2008, we reported a $194.7 million net loss on derivatives, consisting of a $145.6 million non-cash loss to mark our derivative positions to their fair value at June 30, 2008 and a $49.1 million realized loss on settled contracts. For the six months ended June 30, 2007, we reported a $10.7 million net loss on derivatives, consisting of a $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. Because oil and gas prices are volatile, and because we do not account for our derivatives as cash flow hedges, the effect of mark-to-market valuations on our gain/loss on derivatives can cause significant volatility in our results of operations.

Gain/loss on sales of property and equipment

We recorded a net gain on sales of property and equipment of $41 million for 2008 which included a $33.1 million gain on sales of properties in South Louisiana and $5.7 million gains on the sales of two drilling rigs and a surplus well servicing unit compared to a net loss of $8.5 million which included losses on inventory during 2007 of $9.2 million, including a non-cash charge of $8.9 million to write-down inventory to its estimated market value at June 30, 2007. The write-down resulted primarily from the sale of certain surplus equipment at an auction in March 2007. No write-downs were recorded during the 2008 period.

Income tax expense

Our effective income tax rate in 2008 of 35.1% differed from the statutory federal rate of 35% due primarily to increases in the tax provision related primarily to the effects of the recently-enacted Texas Margin Tax and certain non-deductible expenses, offset in part by tax benefits derived from statutory depletion deductions.

Liquidity and Capital Resources

Overview

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

In 2005, we issued $225 million of aggregate principal amount of Senior Notes and used the net proceeds to repay all amounts outstanding on the revolving credit facility at that time. Since then, we have relied on advances under our revolving credit facility to finance a portion of our exploration and development activities. During the first half of 2008, we completed certain asset sales for aggregate proceeds of approximately $114 million and applied the net proceeds to reduce indebtedness outstanding under our revolving credit facility. At June 30, 2008, we had $50 million outstanding under the revolving credit facility.

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

Capital expenditures

We incurred expenditures for exploration and development activities of $154.7 million during the first six months of 2008 and have increased our estimates for planned expenditures for fiscal 2008 from $344.5 million to $400.7 million. The following table summarizes, by area, our actual expenditures for exploration and development activities for the first half of 2008 and our planned expenditures for the year ending December 31, 2008.

	Actual		Planned
	Expenditures		Expenditures		Year 2008
	Six Months Ended		Year Ending		Percentage
	June 30, 2008		December 31, 2008		of Total
	(In thousands)
Permian Basin	$	60,400	$	184,100		46	%
North Louisiana		34,600		83,400		21	%
Austin Chalk (Trend)		28,600		57,500		14	%
South Louisiana		17,000		35,700		9	%
East Texas Bossier		11,800		30,300		8	%
Utah/California		1,900		8,700		2	%
Other		400		1,000		-
	$	154,700	$	400,700		100	%

Our actual expenditures during fiscal 2008 may be substantially higher or lower than these estimates since our plans for exploration and development activities may change during the remainder of the year. Other factors, such as prevailing product prices and the availability of capital resources, could also increase or decrease the ultimate level of expenditures during fiscal 2008.

Approximately 27% of the 2008 planned expenditures relate to exploratory prospects. Exploratory prospects involve a higher degree of risk than developmental prospects. To offset the higher risk, we generally strive to achieve a higher reserve potential and rate of return on investments in exploratory prospects. We do not attempt to forecast our success rate on exploratory drilling. Accordingly, these current estimates do not include costs we may incur to complete any future successful exploratory wells and construct the required production facilities for these wells. Also, we are actively searching for other opportunities to increase our oil and gas reserves, including the evaluation of new prospects for exploratory and developmental drilling activities and potential acquisitions of proved oil and gas properties. We cannot predict our drilling success on exploratory prospects, and our future results of operations and financial condition could be adversely affected by unsuccessful exploratory drilling results.

Our expenditures for exploration and development activities for the six months ended June 30, 2008 totaled $154.7 million, of which approximately 19% was on exploratory prospects. We currently plan to spend approximately $400.7 million for the calendar year 2008, of which approximately 27% is estimated to be spent on exploratory prospects. Our 2008 expenditures may also exceed our cash flow from operating activities in 2008. To the extent possible, we intend to finance this shortfall by borrowings on the revolving credit facility. During the first half of 2008, we completed the sale of certain properties in South Louisiana and the sale of two drilling rigs and a well servicing unit for aggregate net proceeds of approximately $114 million, and applied the net proceeds to reduce indebtedness outstanding under our 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 the end of 2008. Although we believe the assumptions and estimates made in our forecasts are reasonable, uncertainties exist which could cause the borrowing base to be less than expected, cash flow to be less than expected, or capital expenditures to be more than expected. In the event we lack adequate liquidity to finance our expenditures in 2008, we will consider options for alternative capital resources, including the sale of assets.

Cash flow provided by operating activities

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

Cash flow provided by operating activities for the six months ended June 30, 2008 increased $59.5 million, or 66.1%, as compared to the corresponding period in 2007. Approximately $4.6 million of the increase in operating cash flow was attributable to Larclay JV. All of Larclay JV’s cash flow is dedicated to the repayment of a $75 million secured term loan facility. The remainder of the increase in operating cash flow was derived primarily from oil and gas producing activities, offset in part by increases in production costs and seismic expenses.

Credit facility

A group of banks have provided us with a revolving credit facility on which we have historically relied for both our short-term liquidity (working capital) and our long-term financing needs. The funds available to us at any time under this revolving credit facility are limited to the amount of the borrowing base established by the banks. As long as we have sufficient availability under this credit facility to meet our obligations as they come due, we will have sufficient liquidity and will be able to fund any short-term working capital deficit.

During the first six months in 2008, we repaid $115.8 million on the revolving credit facility primarily from the sale of assets. At June 30, 2008, we had a borrowing base of $250 million, leaving $199.2 million available under the revolving loan facility after accounting for outstanding letters of credit of $804,000.

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 GAAP reported working capital deficit increased from $76.4 million at December 31, 2007 to $190.6 million at June 30, 2008 due primarily to decreases in other current assets related to assets held for sale and an increase in the net liability for the fair value for derivatives. After giving effect to the adjustments, our working capital computed for loan compliance purposes was a positive $173.2 million at June 30, 2008, as compared to a positive $103.2 million at December 31, 2007. The following table reconciles our GAAP working capital to the working capital computed for loan compliance purposes at June 30, 2008 and December 31, 2007.

	June 30,			December 31,
	2008			2007
	(In thousands)
Working capital (deficit) per GAAP	$	(190,584	)	$	(76,388	)
Add funds available under the revolving credit facility		199,196			108,396
Exclude fair value of derivatives classified as current assets or current liabilities		147,506			49,738
Exclude current assets and current liabilities of Larclay JV		17,039			21,423
Working capital per loan covenant	$	173,157		$	103,169

Since we use this revolving credit facility for both short-term liquidity and long-term financing needs, it is important that we comply in all material respects with the loan agreement, including financial covenants that are computed quarterly. The working capital covenant requires us to maintain positive working capital using the computations described above. Another financial covenant under the credit facility requires us to maintain a ratio of indebtedness to cash flow of no more than 3 to 1. While we were in compliance with all financial and non-financial covenants at June 30, 2008, our increased leverage and reduced liquidity may result in our failing to comply with one or more of these covenants in the future. If we fail to meet any of these loan covenants, we would ask the banks to allow us sufficient time to obtain additional capital resources through alternative means. If a suitable arrangement could not be reached with the banks, the banks could accelerate the indebtedness and seek to foreclose on the pledged assets.

The banks redetermine the borrowing base under the revolving credit facility at least twice a year, in May and November. The borrowing base was reduced in May 2008 from $275 million to $250 million in connection with our sale of certain properties in South Louisiana. In June 2008, we elected to hold the borrowing base at $250 million instead of increasing it to levels supported by the collateral values assigned by the banks. If at any time, the borrowing base is less than the amount of outstanding indebtedness, we will be required to (i) pledge additional collateral, (ii) prepay the excess in not more than five equal monthly installments, or (iii) elect to convert the entire amount of outstanding indebtedness to a term obligation based on amortization formulas set forth in the loan agreement. We have relied heavily on advances under the revolving credit facility to finance a significant portion of our exploration and development activities in fiscal 2007 and the first half of 2008. At June 30, 2008, we had $50 million outstanding on the revolving credit facility.

In June 2008, we amended our loan agreement with the banks to extend the maturity of the credit facility from 2009 to 2012, to modify certain covenants restricting the Company’s ability to engage in hedging transactions, including limits on hedging transactions for the remainder of 2008 and to waive noncompliance with prior limitations on hedging transactions.

7¾% Senior Notes due 2013

In July 2005, we issued, in a private placement, $225 million of aggregate principal amount of Senior Notes. The Senior Notes were issued at face value and 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 or 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, 2008.

Alternative capital resources

Although our base of oil and gas reserves, as collateral for both of our credit facilities, has historically been our primary capital resource, we have in the past, and we believe we could in the future, use alternative capital resources, such as asset sales, vendor financing arrangements, and/or public or private issuances of common stock. We could also issue senior or subordinated debt or preferred stock in a public or a private placement if we choose to raise capital through either of these markets. While we believe we would be able to obtain funds through one or more of these alternatives, if needed, there can be no assurance that these capital resources would be available on terms acceptable to us.

Item 3 - Quantitative and Qualitative Disclosures About Market Risks

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

Oil and Gas Prices

Our financial condition, results of operations, and capital resources are highly dependent upon the prevailing market prices of, and demand for, oil and natural gas. These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond our control. These factors include the level of global demand for petroleum products, foreign supply of oil and gas, the establishment of and compliance with production quotas by oil-exporting countries, weather conditions, the price and availability of alternative fuels, and overall economic conditions, both foreign and domestic. We cannot predict future oil and gas prices with any degree of certainty. Sustained weakness in oil and gas prices may adversely affect our financial condition and results of operations, and may also reduce the amount of net oil and gas reserves that we can produce economically. Any reduction in reserves, including reductions due to price fluctuations, can reduce the borrowing base under our revolving credit facility and adversely affect our liquidity and our ability to obtain capital for our exploration and development activities. Similarly, any improvements in oil and gas prices can have a favorable impact on our financial condition, results of operations and capital resources. Based on December 31, 2007 reserve estimates, we project that a $1 drop in

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

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

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

The following summarizes information concerning our net positions in open commodity derivatives applicable to periods subsequent to June 30, 2008. The settlement prices of commodity derivatives are based on NYMEX futures prices.

Collars:

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

Swaps:

	Gas				Oil
	MMBtu (a)		Price		Bbls		Price
Production Period:
3rd Quarter 2008		4,000,000	$	9.19		310,000	$	78.96
4th Quarter 2008		4,100,000	$	9.17		400,000	$	82.21
2009		3,600,000	$	9.33		1,440,000	$	85.30
		11,700,000				2,150,000

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

We use a sensitivity analysis technique to evaluate the hypothetical effect that changes in the market value of oil and gas may have on the fair value of our commodity derivatives. A $1 per barrel change in the price of oil and a $.50 per MMBtu change in the price of gas would change the fair value of our commodity derivatives by approximately $7.5 million.

Interest Rates

We are exposed to interest rate risk on our long-term debt with a variable interest rate. At June 30, 2008, our variable rate debt had a carrying value of $50 million, which approximated its fair value. At June 30, 2008, our fixed rate debt had a carrying value of $225 million and an approximate fair value of $216 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 $8.7 million. Based on our outstanding variable rate indebtedness at June 30, 2008 of $50 million, a change in interest rates of 100 basis points would affect annual interest payments by $500,000.

We are a party to an interest rate swap. Under this derivative, we pay a fixed rate for the notional principal balance and receive a floating market rate based on LIBOR. The interest rate swap is settled quarterly. The following summarizes information concerning our interest rate swap at June 30, 2008.

Interest Rate Swap:

			Fixed
	Principal		Libor
	Balance		Rates
Period:
July 1, 2008 to November 3, 2008	$	45,000,000		5.73	%

The interest rate swap in the preceding table exposes us to market risks for decreases in interest rates during the periods shown.

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

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;

·	This evaluation was conducted under the supervision and with the participation of our management, including our chief executive and chief financial officers; and

It is the conclusion of our chief executive 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.

Changes in Internal Control Over Financial Reporting

No changes in internal control over financial reporting were made during the quarter ended June 30, 2008 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1A - - Risk Factors

In evaluating all forward-looking statements, you should specifically consider various factors that may cause actual results to vary from those contained in the forward-looking statements. Our risk factors are included in our Annual Report on Form 10-K for the year ended December 31, 2007, as filed with the U.S. Securities and Exchange Commission on March 14, 2008 and available at www.sec.gov. There have been no material changes to these risk factors since the filing of our Form 10-K.

Item 4 - - Submission of Matters to a Vote of Security Holders

On May 7, 2008, we held our Annual Meeting of Stockholders to (a) elect three directors to the Board of Directors for a term of three years, and (b) advise on the selection of KPMG LLP as our independent auditors for 2008. At such meeting Davis L. Ford, Robert L. Parker and Jordan R. Smith were reelected as directors, and stockholders advised that KPMG LLP should be selected as our independent auditors for 2008.

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

	Results of Voting	Votes For		Withheld
1.	Election of Directors
	Davis L. Ford.		8,994,080		1,099,592
	Robert L. Parker		6,108,955		3,984,717
	Jordan R. Smith		8,832,194		1,261,478

		Votes For		Withheld		Abstentions
2.	Advisory vote on the selection of KPMG LLP		10,061,587		24,985	7,100

Item 6 - - Exhibits

Exhibits

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

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

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

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

**10.1		Fifth Amendment to Amended and Restated, dated June 13, 2008, among Clayton Williams Energy, Inc., JP Morgan Chase Bank, N.A. and the other signatories thereto, filed as Exhibit 10.1 to our Current Report on Form 8-K filed with the Commission on June 18, 2008. ††


**10.2†		Amaker-Tippet Reward Plan dated June 19, 2008 filed as Exhibit 10.1 to our Current Report on Form 8-K with the Commission on June 25, 2008. ††

**10.3†		Austin Chalk Reward Plan dated June 19, 2008 filed as Exhibit 10.2 to our Current Report on Form 8-K with the Commission on June 25, 2008. ††

**10.4†		Barstow Area Reward Plan dated June 19, 2008 filed as Exhibit 10.3 to our Current Report on Form 8-K with the Commission on June 25, 2008. ††

**10.5†		Participation Agreement relating to Andrews Area dated June 19, 2008 filed as Exhibit 10.1 to our Current Report on Form 8-K filed with the Commission June 25, 2008. ††

**10.6†		Participation Agreement relating to Crockett County Area dated June 19, 2008 filed as Exhibit 10.2 to our Current Report on Form 8-K filed with the Commission June 25, 2008. ††

**10.7†		Participation Agreement relating to North Louisiana Bossier III dated June 19, 2008 filed as Exhibit 10.3 to our Current Report on Form 8-K filed with the Commission June 25, 2008. ††

**10.8†		Participation Agreement relating to North Louisiana Hosston/Cotton Valley III dated June 19, 2008 filed as Exhibit 10.4 to our Current Report on Form 8-K filed with the Commission June 25, 2008. ††

**10.9†		Participation Agreement relating to South Louisiana VI dated June 19, 2008 filed as Exhibit 10.5 to our Current Report on Form 8-K filed with the Commission June 25, 2008. ††

**10.10†		Participation Agreement relating to Utah dated June 19, 2008 filed as Exhibit 10.6 to our Current Report on Form 8-K filed with the Commission June 25, 2008. ††

*21		Subsidiaries of the registrant

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

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

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

Filed herewith

**	Incorporated by reference to the filing indicated

†

Identifies an Exhibit that consists of or includes a management contract or compensatory plan or arrangement

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

CLAYTON WILLIAMS ENERGY, INC.

SIGNATURES

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

CLAYTON WILLIAMS ENERGY, INC.

Date:	August 8, 2008	By:	/s/ L. Paul Latham
			L. Paul Latham
			Executive Vice President and Chief
			Operating Officer

Date:	August 8, 2008	By:	/s/ Mel G. Riggs
			Mel G. Riggs
			Senior Vice President and Chief Financial
			Officer

Positive
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Uncertain
Constraining
Legalese
Litigous
Readability	H.S. freshman Good

Clayton Williams Energy (CWEI) Inactive 10-Q2008 Q2 Quarterly report

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