Clayton Williams Energy (CWEI) 10-Q 2005 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

ý   Quarterly Report Pursuant to Section 13 or 15(d)

of the Securities Exchange Act of 1934

For the quarterly period ended September 30, 2005

or

o   Transition Report Pursuant to Section 13 or 15(d)

of the Securities Exchange Act of 1934

For the transition period from                   to

Commission File No. 0-10924

CLAYTON WILLIAMS ENERGY, INC.

(Exact name of Registrant as specified in its charter)

Delaware	75-2396863
(State or other jurisdiction of	(I.R.S. Employer
incorporation or organization)	Identification Number)
6 Desta Drive, Suite 6500, Midland, Texas	79705-5510
(Address of principal executive offices)	(Zip code)

Registrant’s Telephone Number, including area code:   (432) 682-6324

Not applicable

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

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

Indicate by check mark whether the registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2).       Yes  ý   No  o

There were 10,813,552 shares of Common Stock, $.10 par value, of the registrant outstanding as of November 7, 2005.

CLAYTON WILLIAMS ENERGY, INC.

TABLE OF CONTENTS

	PART I.  FINANCIAL INFORMATION
Item 1.	Financial Statements
	Consolidated Balance Sheets as of September 30, 2005 and December 31, 2004
	Consolidated Statements of Operations for the three months and nine months ended September 30, 2005 and 2004
	Consolidated Statement of Stockholders’ Equity for the nine months ended September 30, 2005
	Consolidated Statements of Cash Flows for the nine months ended September 30, 2005 and 2004
	Notes to Consolidated Financial Statements
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 3.	Quantitative and Qualitative Disclosure About Market Risks
Item 4.	Controls and Procedures
	PART II. OTHER INFORMATION
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds
Item 6.	Exhibits
	Signatures

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CLAYTON WILLIAMS ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

	September 30,			December 31,
	2005			2004
	(Unaudited)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	50,514		$	16,359
Accounts receivable:
Oil and gas sales, net	27,790			25,573
Joint interest and other, net	5,978			4,653
Affiliates	485			553
Inventory	24,354			5,202
Deferred income taxes	1,330			625
Fair value of derivatives	200			2,333
Prepaids and other	3,415			1,401
	114,066			56,699
PROPERTY AND EQUIPMENT
Oil and gas properties, successful efforts method	989,276			909,095
Natural gas gathering and processing systems	17,886			17,286
Other	11,873			11,839
	1,019,035			938,220
Less accumulated depreciation, depletion and amortization	(564,594		)	(539,860		)
Property and equipment, net	454,441			398,360
OTHER ASSETS
Debt issue costs	8,909			3,575
Other	4,583			3,601
	13,492			7,176
	$	581,999		$	462,235
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts payable:
Trade	$	64,740		$	51,014
Oil and gas sales	13,047			11,223
Affiliates	1,202			2,954
Current maturities of long-term debt	25			31
Fair value of derivatives	41,976			16,026
Accrued liabilities and other	7,731			3,017
	128,721			84,265
NON-CURRENT LIABILITIES
Long-term debt	225,003			177,519
Deferred income taxes	36,120			36,897
Fair value of derivatives	57,140			28,958
Other	17,821			17,000
	336,084			260,374
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS’ EQUITY
Preferred stock, par value $.10 per share, authorized – 3,000,000 shares; issued and outstanding – none	—			—
Common stock, par value $.10 per share, authorized – 30,000,000 shares; issued and outstanding – 10,812,208 shares in 2005 and 10,787,013 shares in 2004	1,081			1,078
Additional paid-in capital	105,351			104,674
Retained earnings	10,762			11,844
	117,194			117,596
	$	581,999		$	462,235

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

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CLAYTON WILLIAMS ENERGY, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(In thousands, except per share)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2005			2004			2005			2004
REVENUES
Oil and gas sales	$	65,739		$	52,517		$	190,536		$	129,968
Natural gas services	2,572			2,074			7,703			6,973
Gain on sales of property and equipment	16,832			88			18,911			154
Total revenues	85,143			54,679			217,150			137,095
COSTS AND EXPENSES
Production	16,981			12,372			43,408			27,502
Exploration:
Abandonments and impairments	13,863			11,197			31,563			29,296
Seismic and other	5,123			1,350			7,576			5,087
Natural gas services	2,450			1,882			7,241			6,529
Depreciation, depletion and amortization	11,568			11,583			36,148			29,354
Accretion of abandonment obligations	291			413			858			853
General and administrative	5,483			2,493			11,135			8,080
Loss on sales of property and equipment	100			156			132			156
Total costs and expenses	55,859			41,446			138,061			106,857
Operating income	29,284			13,233			79,089			30,238
OTHER INCOME (EXPENSE)
Interest expense	(5,503		)	(2,806		)	(10,435		)	(4,715		)
Change in fair value of derivatives	(28,766		)	(24,580		)	(73,692		)	(27,982		)
Other	1,317			764			2,413			727
Total other income (expense)	(32,952		)	(26,622		)	(81,714		)	(31,970		)
Loss before income taxes	(3,668		)	(13,389		)	(2,625		)	(1,732		)
Income tax benefit	(1,628		)	(4,201		)	(1,543		)	(226		)
NET LOSS	$	(2,040	)	$	(9,188	)	$	(1,082	)	$	(1,506	)
Net loss per common share:
Basic	$	(0.19	)	$	(0.85	)	$	(0.10	)	$	(0.16	)
Diluted	$	(0.19	)	$	(0.85	)	$	(0.10	)	$	(0.16	)
Weighted average common shares outstanding:
Basic	10,810			10,769			10,800			9,560
Diluted	10,810			10,769			10,800			9,560

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

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CLAYTON WILLIAMS ENERGY, INC.

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY

(Unaudited)

(In thousands)

	Common Stock			Additional
	No. of	Par		Paid-In		Retained
	Shares	Value		Capital		Earnings
BALANCE, December 31, 2004	10,787	$	1,078	$	104,674	$	11,844
Net loss and total comprehensive loss	—	—		—		(1,082		)
Sales of restricted stock	9	1		269		—
Issuance of stock through compensation plans	16	2		408		—
BALANCE, September 30, 2005	10,812	$	1,081	$	105,351	$	10,762

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

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CLAYTON WILLIAMS ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In thousands)

	Nine Months Ended September 30,
	2005			2004
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss	$	(1,082	)	$	(1,506	)
Adjustments to reconcile net loss to cash provided by operating activities:
Depreciation, depletion and amortization	36,148			29,354
Exploration costs	31,563			29,296
(Gain) loss on sales of property and equipment	(18,779		)	2
Deferred income taxes	(1,465		)	(226		)
Non-cash employee stock compensation	2,468			272
Change in fair value of derivatives	56,067			17,627
Settlements on derivatives with financing elements	17,428			4,646
Amortization of debt issue costs	2,631			—
Accretion of abandonment obligations	858			853
Changes in operating working capital:
Accounts receivable	(3,474		)	6,243
Accounts payable	3,301			536
Other	967			(3,938		)
Net cash provided by operating activities	126,631			83,159
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to property and equipment	(126,788		)	(93,593		)
Investment in Southwest Royalties, Inc.	—			(168,204		)
Proceeds from sales of property and equipment	23,252			441
Other	(11,336		)	354
Net cash used in investing activities	(114,872		)	(261,002		)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt	225,000			191,800
Repayments of long-term debt	(177,500		)	(35,258		)
Proceeds from sale of common stock	288			30,008
Settlements on derivatives with financing elements	(17,428		)	(4,646		)
Payment of debt issue costs	(7,964		)	(4,156		)
Net cash provided by financing elements	22,396			177,748
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	34,155			(95		)
CASH AND CASH EQUIVALENTS
Beginning of period	16,359			15,454
End of period	$	50,514		$	15,359
SUPPLEMENTAL DISCLOSURES
Cash paid for interest, net of amounts capitalized	$	5,138		$	3,857

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

6

CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2005

(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 42% of the Company’s outstanding common stock is beneficially owned by its Chairman of the Board and Chief Executive Officer, Clayton W. Williams (“Mr. Williams”).  Oil and gas exploration and production is the only business segment in which the Company operates.

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

2.Presentation

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

In the opinion of management, the Company’s unaudited consolidated financial statements as of September 30, 2005 and for the interim periods ended September 30, 2005 and 2004 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, 2005.

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 2004 Form 10-K.

3.Recent Accounting Pronouncements

In June 2005, the Emerging Issues Task Force (“EITF”) reached consensus on Issue 04-5 regarding when a limited partnership should be consolidated by its general partner.  The proposed framework presumes that a sole general partner in a limited partnership controls the limited partnership.  The presumption of control can be overcome if the limited partners have (i) the substantive ability to remove the sole general partner or otherwise dissolve the limited partnership or (ii) substantive participating rights.   The

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EITF has concluded that a general partner lacks control if the limited partners can remove the general partner with a simple majority vote.  The Company is the general partner of several oil and gas limited partnerships and presently consolidates its proportionate interest in the accounts of these partnerships.  The Company is currently reviewing the applicable provisions of the partnership agreements to determine the impact that EITF 04-5 may have on its consolidated financial statements.  For existing partnerships, EITF 04-5 will be effective for consolidated financial statements issued by the Company after January 1, 2006.  EITF 04-5 is effective for newly created or modified limited partnerships subsequent to June 29, 2005.

In December 2004, the FASB issued Statement of Financial Accounting Standards No. 123 (revised 2004) “Share-Based Payments” (“SFAS 123R”).  SFAS 123R requires that the cost from all share-based payment transactions, including stock options, be recognized in the financial statements at fair value.  The Company currently uses the intrinsic-value method to account for these share-based payments.  For public companies, SFAS 123R is effective for fiscal years beginning after June 15, 2005.  The Company will adopt the provisions of this statement in the first quarter of 2006 and is currently assessing the effect of SFAS 123R on the financial statements.

In April 2005, the FASB issued Staff Position No. 19-1 (“FSP 19-1”).  FSP 19-1 amends the present guidance in SFAS 19, paragraphs 31 and 34, regarding when exploratory drilling costs pending determination of proved reserves can be carried as an asset of an oil and gas company that uses the successful efforts accounting method.  The Company was required to adopt FSP 19-1, including its disclosures, effective July 1, 2005.  The adoption of FSP 19-1 did not have a significant impact on the Company’s results of operations.  At September 30, 2005 and December 31, 2004, the Company had capitalized $0 and $5.4 million, respectively, of exploratory drilling costs applicable to wells that were pending determination of proved reserves.  Substantially all of the December 31, 2004 capitalized costs were subsequently classified as non-productive.

4.Acquisition of Southwest Royalties, Inc.

On May 21, 2004, the Company acquired all the outstanding common stock of Southwest Royalties, Inc. (“SWR”) through a merger.  Prior to the acquisition, SWR was a privately-held, Midland-based energy company engaged in oil and gas exploration, production, development and acquisition activities in the United States.  Most of SWR’s properties are located in the Permian Basin of west Texas and southeastern New Mexico.

In connection with the acquisition of SWR, the Company paid $57.1 million to holders of SWR common stock and common stock warrants and assumed and refinanced approximately $113.9 million of SWR bank debt at closing.  In addition, the Company incurred approximately $9.4 million of merger-related costs, including (i) the assumption of SWR’s obligations to its officers and employees pursuant to change of control arrangements and (ii) investment banking, legal, accounting and other direct transaction costs related to the acquisition of SWR.

The Company has accounted for the acquisition of SWR using the purchase method of accounting for business combinations.  Under this method of accounting, CWEI is deemed to be the acquirer for accounting purposes.  SWR’s assets and liabilities were revalued under the purchase method of accounting and recorded at their estimated fair values.

8

The following table reflects the unaudited pro forma results of operations for the nine months ended September 30, 2004 as though the acquisition of SWR had occurred on January 1, 2004.  The pro forma amounts are not necessarily indicative of the results that may be reported in the future.

	Nine Months Ended
	September 30, 2004
	(In thousands, except
	per share data)
Revenues	$	160,772
Net loss from continuing operations	$	(12,703	)
Net loss from continuing operations per share:
Basic	$	(1.18	)
Diluted	$	(1.18	)

5.Long-Term Debt

Long-term debt consists of the following:

	September 30,			December 31,
	2005			2004
	(In thousands)
7 3/4% Senior Notes due 2013	$	225,000		$	—
Secured bank credit facilities:
Revolving loan, due May 2007	—			147,500
Senior term loan, due May 2008	—			30,000
Other	28			50
	225,028			177,550
Less current maturities	(25		)	(31		)
	$	225,003		$	177,519

7¾% Senior Notes due 2013

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

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

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

Secured Bank Credit Facilities

In connection with the acquisition of SWR in May 2004 (see Note 4), the Company entered into new credit facilities with a group of banks that provided for an increase in borrowing capacity under the Company’s existing revolving credit facility and established a new senior term credit facility.  The borrowing base established under the revolving credit facility increased from $95 million to $180 million, and the Company initially borrowed $75 million on the senior term credit facility.  With a portion of the net proceeds from the private placement of common stock in May 2004 (see Note 7), the Company reduced the principal balance on the senior term credit facility to $50 million.  In November 2004, the banks increased the borrowing base under the revolving credit facility to $195 million, and the Company paid down the senior term credit facility to $30 million with proceeds from certain asset sales.  In connection with the issuance of the 7¾% Senior Notes due 2013 in July 2005, the borrowing base under the revolving credit facility was reduced to $132.5 million, and all outstanding balances on the revolving credit facility and the senior term credit facility were repaid.

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.  Initially, the senior term credit facility provided for interest at rates based on the agent bank’s prime rate plus a margin of 3.5%, or if elected by the Company based on LIBOR plus a margin of 5%.  Subsequently, the prime rate margin was reduced to 2.5%, and the LIBOR margin was reduced to 4%.  Interest and fees are payable at least quarterly.  The effective annual interest rate on borrowings under the combined credit facility, including bank fees and amortization of debt issue costs, for the nine months ended September 30, 2005 was 7.5%.  Included in interest expense for 2005 is a non-cash charge to write off $1.8 million of debt issue costs related to the early repayment of the senior term credit facility and the reduction in the borrowing base on the revolving credit facility.

The amount of funds available to the Company under the revolving credit facility is 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.  At September 30, 2005, the borrowing base was $132.5 million, with no monthly commitment reductions.

The loan agreement applicable to the revolving credit facility contains financial covenants that are computed quarterly.  The working capital covenant requires the Company to maintain a ratio of current assets to current liabilities of at least 1 to 1.  Another financial covenant under the credit facility requires the Company to maintain a ratio of indebtedness to cash flow of no more than 3 to 1.  The computations of current assets, current liabilities, cash flow and indebtedness are defined in the loan agreement.  The Company was in compliance with all financial and non-financial covenants at September 30, 2005.

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6.Other Non-Current Liabilities

Other non-current liabilities consist of the following:

	September 30,		December 31,
	2005		2004
	(In thousands)
Abandonment obligations	$	17,017	$	16,147
Other	804		853
	$	17,821	$	17,000

Changes in abandonment obligations for the nine months ended September 30, 2005 and 2004 are as follows:

	Nine Months Ended
	September 30,
	2005			2004
	(In thousands)
Beginning of period	$	16,147		$	8,849
Abandonment obligations related to the acquisition of Southwest Royalties, Inc.	—			8,512
Additional abandonment obligations from new wells	492			387
Sales or abandonments of properties	(507		)	(170		)
Revisions of previous estimates	27			40
Accretion expense	858			853
End of period	$	17,017		$	18,471

7.Common Stock

In May 2004, the Company sold 1,380,869 shares of its common stock to certain institutional investors at a price of $23.00 per share in a private placement that raised approximately $31.8 million in gross proceeds.  After the payment of typical transaction expenses, net proceeds of approximately $30 million were used to repay a portion of the bank indebtedness incurred to finance the acquisition of SWR (see Note 4).

In a series of seven monthly transactions from February 2005 through August 2005, the Company issued a total of 9,268 shares of its common stock to Mr. Williams in lieu of net cash compensation aggregating $270,000.  These shares were deemed to be sales of restricted securities after it was determined that the Executive Stock Compensation Plan described in Note 8 had expired effective February 1, 2005.

8.Compensation Plans

Executive Stock Compensation Plan

Through January 2005, the Company had a compensation plan which permitted the Company to pay all or part of selected executives’ salaries and bonuses in shares of common stock in lieu of cash.  This plan expired on February 1, 2005.  During January 2005, the Company issued 1,728 shares of common stock to Mr. Williams in lieu of net cash compensation of $36,000.

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Stock-Based Compensation

In June 2005, Mr. Williams was granted options to purchase 200,000 shares of common stock at a price of $29.39 per share, which was the market value at the date of grant.  The Company accounts for stock-based compensation utilizing the intrinsic value method prescribed by Accounting Principles Board Opinion No. 25 “Accounting for Stock Issued to Employees” (“APB 25”) and related interpretations.  The following pro forma information, as required by Statement of Financial Accounting Standards No. 123 “Accounting for Stock-Based Compensation” (“SFAS 123”), as amended by Statement of Financial Accounting Standards No. 148 (“SFAS 148”), presents net income and earnings per share information as if the stock options issued since December 31, 1994 were accounted for using the fair value method.  The fair value of stock options issued for each year was estimated at the date of grant using the Black-Scholes option pricing model.

The SFAS 123 pro forma information for the nine months ended September 30, 2005 and 2004 is as follows:

	Nine Months Ended
	September 30,
	2005			2004
	(In thousands, except per share)
Net loss, as reported	$	(1,082	)	$	(1,506	)
Add: Stock-based employee compensation expense (credit) included in net income, net of tax	1,384			(197		)
Deduct: Stock-based employee compensation expense determined under fair value based method (SFAS 123), net of tax	(2,920		)	(3,840		)
Net loss, pro forma	$	(2,618	)	$	(5,543	)
Basic:
Net loss per common share, as reported	$	(.10	)	$	(.16	)
Net loss per common share, pro forma	$	(.24	)	$	(.58	)
Diluted:
Net loss per common share, as reported	$	(.10	)	$	(.16	)
Net loss per common share, pro forma	$	(.24	)	$	(.58	)

In accordance with the issuance of Financial Accounting Standards Board Interpretation No. 44 (“FIN 44”) to APB 25, the Company changed the classification of 233,141 stock options repriced in April 1999 from fixed stock options to variable stock options.  The Company is required to recognize compensation expense on the repriced options to the extent that the quoted market value of the Company’s common stock at the end of each period after July 1, 2000 exceeds the amended option price ($5.50 per share), except that the Company must recognize compensation expense for options vested as of July 1, 2000 only to the extent that the quoted market value exceeds the market value on that date ($31.94 per share).  As the repriced options are exercised, the cumulative amount of accrued compensation expense will be credited to additional paid-in capital.  Since this provision is based on changes in the quoted market value of the Company’s common stock, the Company’s future results of operations may be subject to significant volatility.  Accrued compensation expense at September 30, 2005 and December 31, 2004 is classified as a current liability in the accompanying consolidated balance sheet and is comprised of the following activity for the periods then ended.

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	September 30,			December 31,
	2005			2004
	(In thousands)
Beginning of period	$	685		$	958
Compensation expense (credit)	2,130			(245		)
Amounts reclassified to additional paid-in capital for options exercised during the period	(37		)	(28		)
End of period	$	2,778		$	685

After-Payout Working Interest Incentive Plans

In September 2002, the Compensation Committee of the Board of Directors adopted an incentive plan for officers, key employees and consultants, excluding Mr. Williams, who promote the Company’s drilling and acquisition programs.  Management’s objective in adopting this plan is to further align the interests of the participants with those of the Company by granting the participants an after-payout working interest in the production developed, directly or indirectly, by the participants.  The plan provides for the creation of a series of limited partnerships to which the Company, as general partner, contributes a portion of its working interest in wells drilled within certain areas, and the key employee and consultants, as limited partners, contribute cash.  The Company pays all costs and receives all revenues until payout of its costs, plus interest.  At payout, the limited partners receive 99% of all subsequent revenues and pay 99% of all subsequent expenses attributable to the partnerships’ interests.

Between 3% and 6% of the Company’s working interests in substantially all wells drilled by the Company subsequent to October 2002 are subject to this arrangement.  The Company consolidates its proportionate share of partnership assets, liabilities, revenues, expenses and oil and gas reserves in its consolidated financial statements.  In April 2004, one of the partnerships achieved payout, and the Company’s interest in the partnership was reduced to 1%.  Aggregate cash distributions of $199,000 were paid to the limited partners of this partnership during the nine months ended September 30, 2005.

9.Derivatives

Commodity Derivatives

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

The following summarizes information concerning the Company’s net positions in open commodity derivatives applicable to periods subsequent to September 30, 2005.  The settlement prices of commodity derivatives are based on NYMEX futures prices.

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Floors:

	Gas			Oil
	MMBtu (a)	Floor		Bbls	Floor
Production Period:
4th Quarter 2005	1,840,000	$	4.50	119,600	$	28.00

Collars:

	Gas					Oil
	MMBtu (a)	Floor		Ceiling		Bbls	Floor		Ceiling
Production Period:
4th Quarter 2005 (b)	588,000	$	4.00	$	5.23	108,000	$	23.00	$	25.41
2006	2,024,000	$	4.00	$	5.21	613,000	$	23.00	$	25.32
2007	1,831,000	$	4.00	$	5.18	562,000	$	23.00	$	25.20
2008	1,279,000	$	4.00	$	5.15	392,000	$	23.00	$	25.07
	5,722,000					1,675,000

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

(b)Excludes a closed hedge position for 54,000 barrels of oil which will be settled during the fourth quarter of 2005 at a loss of $2.4 million.

In November 2005, the Company entered into a swap arrangement covering 1,140,000 barrels of 2006 oil production at a fixed price of $62.30 per barrel.

Interest Rate Derivatives

The following summarizes information concerning our net positions in open interest rate swaps applicable to periods subsequent to September 30, 2005.

Swaps:

	Principal		Libor
	Balance		Rates
Period:
October 1, 2005 to November 1, 2005	$	60,000,000	2.97	%
November 1, 2005 to November 1, 2006	$	55,000,000	4.29	%
November 1, 2006 to November 1, 2007	$	50,000,000	5.19	%
November 1, 2007 to November 1, 2008	$	45,000,000	5.73	%

Accounting For Derivatives

The Company accounts for its derivatives in accordance with Statement of Financial Accounting Standards No. 133 “Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”), as amended.  The Company did not designate any of its currently open commodity or interest rate derivatives as cash flow hedges; therefore, all changes in the fair value of these contracts prior to maturity, plus any realized gains or losses at maturity, are recorded as other income (expense) in the Company’s statements of operations.

Pursuant to SFAS 133, as amended by SFAS 149, the derivative instruments assumed in connection with the SWR acquisition (see Note 4) are deemed to contain a significant financing element, and all cash flows associated with the settlement of these positions are reported as a financing activity in the consolidated statements of cash flows.

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10.Financial Instruments

Cash and cash equivalents, receivables, accounts payable and accrued liabilities were each estimated to have a fair value approximating the carrying amount due to the short maturity of those instruments.  Indebtedness under the secured bank credit facilities was estimated to have a fair value approximating the carrying amount since the stated interest rate is generally market sensitive.  Abandonment obligations are carried at net present value which approximates their fair value since the discount rate is based on the Company’s credit-adjusted, risk-free rate.  The fair value of other noncurrent liabilities approximate their carrying value.

The fair values of derivatives as of September 30, 2005 and December 31, 2004 are set forth below.  The associated carrying values at these dates are equal to their estimated fair values.

	September 30,			December 31,
	2005			2004
	(In thousands)
Liabilities:
Commodity derivatives	$	(98,233	)	$	(41,162	)
Interest rate derivatives	(485		)	(1,489		)
Net liabilities	$	(98,718	)	$	(42,651	)

11.Income Taxes

Deferred tax assets and liabilities are the result of temporary differences between the financial statement carrying values and the tax bases of assets and liabilities.  Significant components of net deferred tax liabilities at September 30, 2005 and December 31, 2004 are as follows:

	September 30,			December 31,
	2005			2004
	(In thousands)
Deferred tax assets:
Net operating loss carryforwards	$	1,504		$	7,915
Accrued stock-based compensation	972			240
Fair value of derivatives	34,553			14,930
Alternative minimum tax credit carryforwards	407			279
Depletion carryforwards	3,628			3,209
Other	5,274			5,058
	46,338			31,631
Deferred tax liabilities:
Property and equipment	(81,128		)	(67,903		)
Net deferred tax liabilities	$	(34,790	)	$	(36,272	)
Components of net deferred tax assets (liabilities):
Current assets	$	1,330		$	625
Non-current liabilities	(36,120		)	(36,897		)
	$	(34,790	)	$	(36,272	)

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For the nine months ended September 30, 2005 and 2004, the Company’s effective income tax rates were different than the statutory federal income tax rates for the following reasons:

	Nine Months Ended
	September 30,
	2005			2004
	(In thousands)
Income tax benefit at statutory rate of 35%	$	(919	)	$	(606	)
Tax depletion in excess of basis	(419		)	(369		)
State income taxes	(205		)	800
Revision of previous tax estimates	—			(51		)
Income tax benefit	$	(1,543	)	$	(226	)
Current	$	(78	)	$	699
Deferred	(1,465		)	(925		)
Income tax benefit	$	(1,543	)	$	(226	)

The Company derives an income tax benefit when employees and directors exercise options granted under the Company’s stock compensation plans (see Note 8).  Employee stock options that are classified as fixed stock options under APB 25 do not result in a charge against book income when the option price is equal to or greater than the market price at date of grant.  Therefore, any tax benefit from the exercise of fixed stock options results in a permanent difference, which is recorded to additional paid-in capital when the tax benefit is realized.

In connection with the SWR merger, the Company acquired $29.3 million of tax loss carryforwards that are subject to limitations under Internal Revenue Code Section 382 from a prior change in control that occurred in April 2002 and from the change in control of SWR that occurred in connection with the Company’s acquisition of SWR in May 2004.  The Company has completed a review of the facts surrounding these changes in control and presently believes that it will be able to utilize all of SWR’s tax loss carryforwards.

At September 30, 2005, the Company’s cumulative tax loss carryforwards were approximately $4 million.  Based upon current commodity prices and production volumes, as well as the availability of tax planning strategies (such as elective capitalization of intangible drilling costs), the Company believes that it is more likely than not that the Company will be able to utilize these tax loss carryforwards before they expire (beginning in 2008).  Accordingly, no valuation allowance has been provided at September 30, 2005.

12.Commitments

Drilling Rig Joint Venture

In October 2005, the Company entered into a letter agreement with a privately-held contract drilling company (the “Co-Venturer”) which calls for the formation of a joint venture to acquire at least 12 new drilling rigs.  Each party will own a 50% interest in the joint venture.  The Co-Venturer will serve as the operations manager of the joint venture, and the Company will be responsible for financing the purchase of the rigs.  The total acquisition cost, including construction and equipping of the rigs, is expected to be approximately $75 million.  The agreement contemplates that the joint venture will be able to finance 100% of the total acquisition costs of the rigs based on a three-year loan amortization.  If the joint venture is unable to obtain 100% financing, the Company will be required to provide the balance either through loans to the joint venture on the same terms as the primary financing or otherwise through equity investments in

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the joint venture.  After initial construction and equipping, all costs to maintain the equipment will be borne equally by the parties.

Equipment Orders

The Company has placed firm orders for tubing, casing, pumping units and other equipment to be used in its exploration and development activities totaling approximately $33 million.  Most of these purchases will be made during the fourth quarter of 2005.

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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, 2004.

Overview

We are an oil and natural gas exploration, development, acquisition and production company.  Our basic business model is to find and develop oil and gas reserves through exploration and development activities, and sell the production from those reserves at a profit.  To be successful, we must, over time, be able to find oil and gas reserves and then sell our discovered production at a price that is sufficient to cover our finding costs, operating expenses, administrative costs and interest expense, plus offer us a return on our capital investment.

From time to time, we may also acquire producing properties if we believe the acquired assets offer us the potential for reserve growth through additional developmental or exploratory drilling activities.  The acquisition of Southwest Royalties, Inc. (“SWR”) in May 2004 provided us with a number of well locations suitable for developmental drilling and also enhanced our ability to conduct exploration activities on or adjacent to some of the acquired properties.

We believe that the economic climate in the domestic oil and gas industry continues to be suitable for our business model.  Oil and gas prices have remained strong.  Supply and demand fundamentals continue to suggest that energy prices will remain high for the near term, providing us with the economic incentives necessary for us to assume the risks we face in our search for oil and gas reserves.  On the downside, however, we are also experiencing significant cost increases in almost all areas of our business activities, especially in drilling and production costs.  High demand for oilfield services is being met with shortages in equipment and trained personnel, resulting in rate increases.  While profit margins still remain favorable, operating metrics per Mcfe, such as finding costs, production costs and overhead costs, are rising.

Finding quality domestic oil and gas reserves through exploration is a significant challenge and involves a high degree of risk.  Although our recent exploration results have improved, our drilling successes in 2002 and 2003 were limited and did not find sufficient reserves to replace our production through exploration activities.  In order to grow our reserve base through our exploration program, we need to continue to improve our drilling success.  We will also continue to look for opportunities to complement our exploration program through the purchase of proved reserves as we did in 2004 with the acquisition of SWR.

Key Factors to Consider

The following summarizes the key factors considered by management in the review of our financial condition and operating performance for the third quarter of 2005 and the outlook for the remainder of 2005.

•We recorded a loss of $28.8 million related to the change in fair value of derivatives during the third quarter of 2005. Cash settlements to counterparties accounted for $8 million of this loss, and changes in mark-to-market valuations accounted for $20.8 million.  Since we do not presently designate our derivatives as cash flow hedges under applicable accounting

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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.

•In August 2005, we sold our interests in two leases in the Breton Sound area in the Gulf of Mexico (offshore Louisiana) for $21.3 million, subject to post-closing adjustments.  We realized a gain of $16.8 million on this sale during the third quarter of 2005.

•Exploration costs related to abandonments and impairments were $13.9 million during the third quarter of 2005, most of which was attributable to two dry holes in south Louisiana.

•Higher oil and gas prices resulted in a 25% increase in oil and gas sales for the third quarter of 2005 as compared to the 2004 period despite a 15% decline in oil and gas production for the same periods.  Approximately half of this decline was attributable to the loss of production in Louisiana as a result of Hurricane Katrina in late August, a condition which we expect to persist at least through the end of 2005.

•We currently plan to spend $174.9 million in 2005 on exploration and development activities, of which approximately 72% relates to exploratory prospects.  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 July 2005, we significantly improved our liquidity by issuing $225 million of aggregate principal amount of 7¾% Senior Notes due 2013.  With net proceeds from the Senior Notes of approximately $217 million, we repaid all amounts outstanding under our secured bank credit facilities and currently have approximately $131.7 million borrowing capacity available under our revolving credit facility.

Recent Exploration and Developmental Activities

South Louisiana

The following table sets forth certain information about our exploratory well activities in south Louisiana subsequent to December 31, 2004.

		Working		Current
Spud Date	Well Name (Prospect)	Interest		Status
August 2004	McIlhenny #1 (Tabasco)	33	%	Dry
November 2004	Orleans Levee District #1    (American Bay)	45	%	Waiting on production facilities
February 2005	State Lease 18065 #1 (Alabama)	100	%	Waiting on production facilities
July 2005	Ransom #1 (Keck)	50	%	Drilling
August 2005	State Lease 17636 #1 (Natalie)	30	%	Dry
August 2005	LL&E #1 (Andrea)	70	%	Dry

We are currently repairing or reconstructing production facilities for the Orleans Levee District #1 (American Bay) and the State Lease 18065 #1 (Alabama) that were damaged by Hurricane Katrina in August 2005.  We currently expect to be able to sell production from these wells beginning late fourth quarter of 2005 or early first quarter of 2006.  We abandoned the State Lease 17636 #1 (Natalie) in Terrebonne Parish and the LL&E #1 (Andrea) in Cameron Parish in October 2005.  We recorded a pretax charge of $8.9 million during the third quarter of 2005 in connection with these abandonments and will record an additional charge of approximately $1.6 million during the fourth quarter of 2005 for costs incurred on these wells after September 30, 2005.

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Permian Basin

Subsequent to December 31, 2004, we have drilled 25 gross (21.2 net) operated wells in various fields in the Permian Basin, all of which were completed as producers.  Several of these wells contributed favorably to our fiscal 2005 production.  In addition, we are currently conducting drilling or completing operations on 8 gross (7.2 net) wells in this area.

Other

We abandoned the Deer-Hamilton #1 well, a 17,000-foot exploratory well in Nueces County, Texas targeting the Vicksburg formation, in August 2005.  In addition to a $4.5 million charge in the second quarter of 2005, we recorded a charge of $3.4 million during the third quarter of 2005 in connection with this abandonment.

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Supplemental Information

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

		Three Months Ended
		September 30,
		2005			2004
Oil and Gas Production Data:
Gas (MMcf)		3,897			4,531
Oil (MBbls)		537			624
Natural gas liquids (MBbls)		52			77
Total (MMcfe)		7,431			8,737
Average Realized Prices (1):
Gas ($/Mcf)		$	7.98		$	5.32
Oil ($/Bbl)		$	59.95		$	41.71
Natural gas liquids ($/Bbl):		$	37.00		$	28.79
Losses on Settled Derivative Contracts (1):
($ in thousands, except per unit)
Gas:	Net realized loss	$	(2,023	)	$	(2,923	)
	Per unit produced ($/Mcf)	$	(.52	)	$	(.65	)
Oil:	Net realized loss	$	(5,935	)	$	(4,312	)
	Per unit produced ($/Bbl)	$	(11.05	)	$	(6.91	)
Average Daily Production:
Natural Gas (Mcf):
Permian Basin		17,300			14,656
Louisiana		8,528			8,745
Austin Chalk (Trend)		2,672			3,021
Cotton Valley Reef Complex		13,336			21,579
Other		523			1,249
Total		42,359			49,250
Oil (Bbls):
Permian Basin		3,131			3,329
Louisiana		809			1,295
Austin Chalk (Trend)		1,839			2,104
Other		58			55
Total		5,837			6,783
Natural Gas Liquids (Bbls):
Permian Basin		261			321
Austin Chalk (Trend)		220			301
Other		84			215
Total		565			837

(Continued)

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	Three Months Ended
	September 30,
	2005		2004
Exploration Costs (in thousands):
Abandonment and impairment costs:
Louisiana	$	9,434	$	9,600
Cotton Valley Reef Complex	5		44
Mississippi	915		—
Permian Basin	72		—
Nevada, Arizona, California and Utah	—		725
Other	3,437		828
Total	13,863		11,197
Seismic and other	5,123		1,350
Total exploration costs	$	18,986	$	12,547
Oil and Gas Costs ($/Mcfe Produced):
Production costs	$	2.29	$	1.42
Oil and gas depletion	$	1.46	$	1.24
Net Wells Drilled (2):
Exploratory Wells	3.7		4.0
Developmental Wells	6.0		.9

		Nine Months Ended
		September 30,
		2005			2004
Oil and Gas Production Data:
Gas (MMcf)		13,205			12,813
Oil (MBbls)		1,771			1,464
Natural gas liquids (MBbls)		185			181
Total (MMcfe)		24,941			22,683
Average Realized Prices(1):
Gas ($/Mcf)		$	6.88		$	5.39
Oil ($/Bbl)		$	52.39		$	38.25
Natural gas liquids ($/Bbl):		$	31.70		$	25.93
Losses on Settled Derivative Contracts (1):
($ in thousands, except per unit)
Gas:	Net realized loss	$	(2,585	)	$	(3,873	)
	Per unit produced ($/Mcf)	$	(.20	)	$	(.30	)
Oil:	Net realized loss	$	(14,918	)	$	(6,316	)
	Per unit produced ($/Bbl)	$	(8.42	)	$	(4.31	)

(Continued)

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	Nine Months Ended
	September 30,
	2005		2004
Average Daily Production:
Natural Gas (Mcf):
Permian Basin	16,512		8,005
Louisiana	12,777		9,790
Austin Chalk (Trend)	2,443		3,266
Cotton Valley Reef Complex	15,972		24,321
Other	666		1,381
Total	48,370		46,763
Oil (Bbls):
Permian Basin	3,248		2,130
Louisiana	1,258		911
Austin Chalk (Trend)	1,927		2,244
Other	54		58
Total	6,487		5,343
Natural Gas Liquids (Bbls):
Permian Basin	238		270
Austin Chalk (Trend)	316		197
Other	124		194
Total	678		661
Exploration Costs (in thousands):
Abandonment and impairment costs:
Louisiana	$	10,911	$	25,475
Cotton Valley Reef Complex	7,405		44
Mississippi	4,262		—
Permian Basin	1,042		—
Nevada, Arizona, California and Utah	—		2,408
Other	7,943		1,369
Total	31,563		29,296
Seismic and other	7,576		5,087
Total exploration costs	$	39,139	$	34,383
Oil and Gas Costs ($/Mcfe Produced):
Production costs	$	1.74	$	1.21
Oil and gas depletion	$	1.36	$	1.19
Net Wells Drilled (2):
Exploratory Wells	11.3		9.1
Developmental Wells	21.9		7.6

(1)Hedging gains (losses) are only included in the determination of our average realized prices if the underlying derivative contracts are designated as cash flow hedges under applicable accounting standards.  We did not designate any of our 2004 or 2005 derivative contracts as cash flow hedges.  This means that our derivatives for 2004 and 2005 have been marked-to-market through our statement of operations as other income/expense instead of through accumulated other comprehensive income on our balance sheet.  This also means that all realized gains/losses on these derivatives are reported in other income/loss instead of as a component of oil and gas sales.

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

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Operating Results – Three-Month Periods

The following discussion compares our results for the three months ended September 30, 2005 to the comparative period in 2004.  Unless otherwise indicated, references to 2005 and 2004 within this section refer to the respective quarterly period.

Oil and gas operating results

Oil and gas sales in 2005 increased 25% from 2004 due primarily to higher product prices, offset in part by a 15% decrease in oil and gas production on an Mcfe basis.  Oil and gas sales increased $13.2 million, of which price variances accounted for a $20.7 million increase and production variances accounted for a $7.5 million decrease.

Production in 2005 (on an Mcfe basis) was 15% lower than 2004.  Our oil production decreased 14% in 2005 from 2004 due in part to lost production in Louisiana as a result of Hurricane Katrina and normal production declines on existing wells.  Our gas production decreased 14% in 2005 from 2004 due partially to lost gas production from the hurricane and by higher than normal production declines in the Cotton Valley Reef Complex area due to formation performance.  We expect our oil and gas production for fiscal 2005 to be approximately equal to fiscal 2004 levels without taking into account any new production from our exploration program or from acquisitions of proved reserves.

In 2005, our realized oil price was 44% higher than 2004, while our realized gas price was 50% higher.  Historically, the markets for oil and gas have been volatile, and they are likely to continue to be volatile.

Oil and gas production costs on an Mcfe basis increased from $1.42 per Mcfe in 2004 to $2.29 per Mcfe in 2005.  The increase in operating costs in 2005 was due primarily to higher oilfield service costs and an increase in workover activities.  It is likely that these factors will continue to contribute to higher production costs in future periods.

Depreciation, depletion, and amortization (“DD&A”) expense attributable to our oil and gas properties was virtually unchanged from 2004 levels at $11.6 million.  Rate variances accounted for a $1.7 million increase in DD&A expense and production variances accounted for a $1.7 million decrease.  On an Mcfe basis, DD&A expense increased 18% from $1.24 per Mcfe in 2004 to $1.46 per Mcfe in 2005.  Depletion rates for each depletable group are a function of net capitalized costs and estimated reserve quantities.

General and administrative (“G&A”) expenses, excluding non-cash stock-based employee compensation, increased 40% in 2005 as compared to 2004 due primarily to higher personnel costs and professional fees derived from the increase in overall drilling and exploration activities.  G&A expenses for 2005 include a non-cash charge of $1.9 million for stock-based employee compensation required by Financial Accounting Standards Board Interpretation No. 44.  A $98,000 non-cash credit (reduction of expense) was required for the 2004 period.  Since the amount of this non-cash provision or credit is based on the quoted market value of our common stock, the future results of our operations may be subject to significant volatility based on changes in the market price of our common stock.

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Gain on property sales

Gain on sales of property and equipment for 2005 was $16.8 million, as compared to $88,000 in 2004.  In August 2005, we sold our interests in two leases in the Breton Sound area in the Gulf of Mexico (offshore Louisiana) for $21.3 million, subject to post-closing adjustments.  We realized a gain of $16.8 million on this sale during the third quarter of 2005.

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 2005, we charged to expense $19 million of exploration costs, as compared to $12.5 million in 2004.  Most of these costs were incurred in Louisiana, Mississippi and south Texas.

We plan to spend approximately $174.9 million on exploration and development activities in fiscal 2005, of which 72% is expected to be allocated to exploration activities.  Since exploratory drilling involves a high degree of risk, it is likely that a significant portion of the remaining costs in fiscal 2005 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.

Interest expense

Interest expense increased from $2.8 million in 2004 to $5.5 million in 2005 due primarily to recording a non-cash charge of $1.8 million of debt issue costs related to the early repayment of our senior term credit facility and the reduction in the borrowing base of our revolving credit facility and higher average levels of indebtedness.  In July 2005, we repaid all outstanding balances on our bank indebtedness using proceeds from the issuance of $225 million of Senior Notes which bear interest at a fixed rate of 7.75%.   Higher effective interest rates on our revolving credit facility and our senior term credit facility also contributed to the increase in interest expense.

Change in fair value of derivatives

We recorded a loss of $28.8 million in 2005 for the change in fair value of derivatives compared to a loss of $24.6 million for 2004.  We have not designated any derivative contracts in 2005 or 2004 as cash flow hedges; therefore all cash settlements and changes resulting from mark-to-market valuations are recorded as changes in fair value of derivatives.  For 2005, cash settlements were $8 million and non-cash mark-to-market adjustments were $20.8 million, as compared to cash settlements of $7.3 million and non-cash mark-to-market adjustments of a $17.3 million loss for the 2004 period.  Future gains or losses on changes in derivatives will be impacted by the volatility of commodity and interest rates, as well as the terms of any new derivative contracts.

Operating Results – Nine-Month Periods

The following discussion compares our results for the nine months ended September 30, 2005 to the comparative period in 2004.  Unless otherwise indicated, references to 2005 and 2004 within this section refer to the respective nine-month period.

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Oil and gas operating results

Oil and gas sales in 2005 increased 47% from 2004 due primarily to higher product prices and an increase in oil and gas production on an Mcfe basis.  Oil and gas sales increased $60.6 million, of which price variances accounted for a $46.1 million increase and production variances accounted for a $14.5 million increase.

Production in 2005 (on an Mcfe basis) was 10% higher than 2004.  We increased our oil production 21% in 2005 primarily through the acquisition of SWR in May 2004 and as a result of production from new wells in Louisiana.  Our gas production increased 3% in 2005 from 2004 due primarily to additional gas production from the SWR acquisition and production from new wells in Louisiana, offset in part by higher than normal production declines in the Cotton Valley Reef Complex area due to formation performance.  We expect our oil and gas production for fiscal 2005 to be approximately equal to fiscal 2004 levels without taking into account any new production from our exploration program or from acquisitions of proved reserves.

In 2005, our realized oil price was 37% higher than 2004, while our realized gas price was 28% higher.  Historically, the markets for oil and gas have been volatile, and they are likely to continue to be volatile.

Oil and gas production costs on an Mcfe basis increased from $1.21 per Mcfe in 2004 to $1.74 per Mcfe in 2005.  The increase in operating costs in 2005 was due primarily to higher oilfield service costs and an increase in workover activities.  In addition, added expense related to higher cost oil properties acquired in connection with the SWR merger, as well as increased production tax costs related to higher product prices added to the increase in operating costs.  It is likely that these factors will continue to contribute to higher production costs in future periods.

DD&A expense attributable to our oil and gas properties increased $6.8 million, of which rate variances accounted for $3.9 million and production variances accounted for $2.9 million.  On an Mcfe basis, DD&A expense increased 14% from $1.19 per Mcfe in 2004 to $1.36 per Mcfe in 2005.  Depletion rates for each depletable group are a function of net capitalized costs and estimated reserve quantities.

G&A expenses, excluding non-cash stock-based employee compensation, increased 7% in 2005 as compared to 2004 due primarily to higher personnel costs and professional fees derived from the increase in overall drilling and exploration activities.  G&A expenses for 2005 include a non-cash charge of $2.1 million for stock-based employee compensation required by Financial Accounting Standards Board Interpretation No. 44.  A $303,000 credit (reduction of expense) was required for the 2004 period.  Since the amount of this non-cash provision or credit is based on the quoted market value of our common stock, the future results of our operations may be subject to significant volatility based on changes in the market price of our common stock.

Gain on property sales

Gain on sales of property and equipment for 2005 was $18.9 million, as compared to $154,000 in 2004.  In August 2005, we sold our interests in two leases in the Breton Sound area in the Gulf of Mexico (offshore Louisiana) for $21.3 million, subject to post-closing adjustments.  We realized a gain of $16.8 million on this sale during the third quarter of 2005.  The 2005 gain also includes the sale of various non-core wells and acreage.

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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 2005, we charged to expense $39.1 million of exploration costs, as compared to $34.4 million in 2004.  Most of these costs were incurred in the Cotton Valley Reef Complex, Mississippi, south Louisiana and south Texas.

We plan to spend approximately $174.9 million on exploration and development activities in fiscal 2005, of which 72% is expected to be allocated to exploration activities.  Since exploratory drilling involves a high degree of risk, it is likely that a significant portion of the remaining costs in fiscal 2005 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.

Interest expense

Interest expense increased from $4.7 million in 2004 to $10.4 million in 2005 due primarily to higher levels of indebtedness, an increase in interest rates and recording a non-cash charge of $1.8 million of debt issue costs related to the early repayment of the senior term credit facility and the reduction in the borrowing base on the revolving credit facility.  In July 2005, we repaid all outstanding balances on our bank indebtedness using proceeds from the issuance of $225 million of Senior Notes which bear interest at a fixed rate of 7.75%.   Higher effective interest rates on the revolving credit facility and the senior term credit facility also contributed to the increase in interest expense.

Change in fair value of derivatives

We recorded a loss of $73.7 million in 2005 for the change in fair value of derivatives compared to a loss of $28 million for 2004.  We have not designated any derivative contracts in 2005 or 2004 as cash flow hedges; therefore all cash settlements and changes resulting from mark-to-market valuations are recorded as changes in fair value of derivatives.  For 2005, cash settlements were $17.6 million and non-cash mark-to-market adjustments were $56.1 million, as compared to cash settlements of $10.3 million and non-cash mark-to-market adjustments of a $17.7 million loss for the 2004 period.  Future gains or losses on changes in derivatives will be impacted by the volatility of commodity and interest rates, as well as the terms of any new derivative contracts.

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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 and, until July 2005, our senior term credit facility.  The banks establish a borrowing base by making an estimate of the collateral value of our oil and gas properties.  We borrow funds on the revolving credit facility as needed to supplement our operating cash flow as a financing source for our capital expenditure program.  Our ability to fund our capital expenditure program is dependent upon the level of product prices and the success of our exploration program in replacing our existing oil and gas reserves.  If product prices decrease, our operating cash flow may decrease and the banks may require additional collateral or reduce our borrowing base, thus reducing funds available to fund our capital expenditure program.  The effects of product prices on cash flow can be mitigated through the use of commodity derivatives.  If we are unable to replace our oil and gas reserves through our exploration program, we may also suffer a reduction in our operating cash flow and access to funds under the revolving credit facility.  Under extreme circumstances, product price reductions or exploration drilling failures could allow the banks to seek to foreclose on our oil and gas properties, thereby threatening our financial viability.

In July 2005, we reduced our dependence on the borrowing base established for the revolving credit facility by issuing $225 million of aggregate principal amount of 7¾% Senior Notes due 2013 (the “Senior Notes”) and using the net proceeds to repay all amounts outstanding on the revolving credit facility and the senior term credit facility.

In this section, we will describe our current plans for capital spending, identify the capital resources available to finance our capital spending, and discuss the principal factors that can affect our liquidity and capital resources.

Capital expenditures

Our total planned expenditures for exploration and development activities during fiscal 2005 are $174.9 million, as summarized by area in the following table.

	Actual		Total
	Expenditures		Planned
	Nine Months		Expenditures
	Ended		Year Ended		Percentage
	September 30, 2005		December 31, 2005		of Total
	(In thousands)
Permian Basin	$	55,600	$	81,200	47	%
Louisiana	40,900		54,700		31	%
South and east Texas	16,500		17,500		10	%
Utah/Montana	9,500		12,500		7	%
Mississippi / Alabama	4,900		6,900		4	%
Other	800		2,100		1	%
	$	128,200	$	174,900	100	%

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Our actual expenditures during fiscal 2005 may be substantially higher or lower than these estimates since our plans for exploration and development activities may change during the year.  Other factors, such as prevailing product prices and the availability of capital resources, could also increase or decrease the ultimate level of expenditures during fiscal 2005.

Approximately 72% of the planned expenditures relate to exploratory prospects.  Exploratory prospects involve a higher degree of risk than developmental prospects.  To offset the higher risk, we generally strive to achieve a higher reserve potential and rate of return on investments in exploratory prospects.  We do not attempt to forecast our success rate on exploratory drilling.  Accordingly, these current estimates do not include costs we may incur to complete any future successful exploratory wells and construct the required production facilities for these wells.  Also, we are actively searching for other opportunities to increase our oil and gas reserves, including the evaluation of new prospects for exploratory and developmental drilling activities and potential acquisitions of proved oil and gas properties.

During the third quarter of 2005, we spent approximately $5.5 million to acquire producing properties in the Permian Basin.

We project that most of the cash needed to finance our planned expenditures for exploration and development activities in fiscal 2005 will be provided by operating activities.  To the extent that actual costs exceed our cash provided by operating activities, we plan to utilize the remaining proceeds from our Senior Notes offering and the existing availability under the revolving credit facility to finance such excess.

Drilling Rig Joint Venture

In October 2005, we entered into a letter agreement with a privately-held contract drilling company (the “Co-Venturer”) which calls for the formation of a joint venture to acquire at least 12 new drilling rigs.  Each party will own a 50% interest in the joint venture.  The Co-Venturer will serve as the operations manager of the joint venture, and we will be responsible for financing the purchase of the rigs.  The total acquisition cost, including construction and equipping of the rigs, is expected to be approximately $75 million.  The agreement contemplates that the joint venture will be able to finance 100% of the total acquisition costs of the rigs based on a three-year loan amortization.  If the joint venture is unable to obtain 100% financing, we will be required to provide the balance either through loans to the joint venture on the same terms as the primary financing or otherwise through equity investments in the joint venture.  We may use cash flow from operating activities and funds available to us under the revolving credit facility to meet our obligations to this joint venture.

Equipment Orders

During the nine months ended September 30, 2005, we increased our inventory of tubing, casing, pumping units and other equipment to be used in our on-going exploration and development activities by $19.2 million.  In addition, we have placed firm orders for similar equipment inventory totaling approximately $33 million, most of which will be filled during the fourth quarter of 2005.  We plan to use cash flow from operating activities and funds available to us under the revolving credit facility to finance the purchase of this equipment.

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.

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Cash flow provided by operating activities for the nine months ended September 30, 2005 was 52% higher than the same period in 2004 due to the combined effects of several drivers.  The positive benefits of a 47% increase in oil and gas sales, driven primarily by higher oil and gas prices and an increase in production, and an $18.8 million increase in gain on property sales were offset in part by increases in production costs, costs of settling commodity hedges and interest expense.  Our primary source of cash from operating activities is our oil and gas sales, net of production costs.  Our cash flow provided by operating activities is subject to material variation from changes in oil and gas production levels and product prices.  Higher oil and gas prices also resulted in an increase in cash required to settle derivative contracts, excluding those contracts that contain a financing element as in the case of the contracts assumed in the SWR acquisition.  Interest expense increased in 2005 due primarily to higher levels of indebtedness resulting from the SWR acquisition and higher interest rates on the Senior Notes.

Credit facilities

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

At the beginning of 2005, we had an outstanding balance under the revolving credit facility of $147.5 million, and the borrowing base was $195 million, providing us with available funds of $46.7 million after accounting for outstanding letters of credit.  During the nine months ended September 30, 2005, we generated cash flow from operating activities of $126.6 million and received proceeds from sales of property and equipment of $23.3 million.  We also spent $138.1 million on capital expenditures and other investments and paid $17.4 million to settle derivatives with financing elements.  With the issuance of the Senior Notes in July 2005, we borrowed $217 million, net of financing costs, repaid the balance on the revolving credit facility and repaid the remaining $30 million balance on the senior term credit facility.  Simultaneously, the borrowing base was reduced from $195 million to $132.5 million to give effect to the issuance of the Senior Notes.  Accordingly, the available funds under our revolving credit facility increased by $85 million to $131.7 million at September 30, 2005.  Our available cash also increased by $34.2 million.

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.

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Working capital computed for loan compliance purposes differs from our working capital in accordance with generally accepted accounting principles (GAAP).  Since compliance with financial covenants is a material requirement under the credit facilities, we consider the loan compliance working capital to be useful as a measure of our liquidity because it includes the funds available to us under the revolving credit facility and is not affected by the volatility in working capital caused by changes in fair value of derivatives.  Our reported working capital deficit decreased from $27.6 million at December 31, 2004 to $14.7 million at September 30, 2005 due primarily to a combination of factors, including decreases in accounts payable, increases in inventory and increases in current liabilities related to the fair value of derivatives.  After giving effect to the adjustments, our working capital computed for loan compliance purposes was a positive $158.8 million at September 30, 2005, as compared to a positive $32.9 million at December 31, 2004.  The following table reconciles our GAAP working capital to the working capital computed for loan compliance purposes at September 30, 2005 and December 31, 2004.

	September 30,			December 31,
	2005			2004
	(In thousands)
Working capital (deficit) per GAAP	$	(14,655	)	$	(27,566	)
Add funds available under the revolving credit facility	131,696			46,725
Exclude fair value of derivatives classified as current assets or current liabilities	41,776			13,693
Working capital per loan covenant	$	158,817		$	32,852

Since we use this revolving credit facility for both short-term liquidity and long-term financing needs, it is important that we comply in all material respects with the loan agreement, including financial covenants that are computed quarterly.  The working capital covenant requires us to maintain positive working capital using the computations described above.  Another financial covenant under the credit facility requires us to maintain a ratio of indebtedness to cash flow of no more than 3 to 1.  While we were in compliance with all financial and non-financial covenants at September 30, 2005, our increased leverage and reduced liquidity may result in our failing to comply with one or more of these covenants in the future.  If we fail to meet any of these loan covenants, we would ask the banks to allow us sufficient time to obtain additional capital resources through alternative means.  If a suitable arrangement could not be reached with the banks, the banks could accelerate the indebtedness and seek to foreclose on the pledged assets.  However, the issuance of the Senior Notes described below significantly increases our liquidity and reduces our dependence on the revolving credit facility.

The banks redetermine the borrowing base under the revolving credit facility at least twice a year, in May and November.  If at any time, the borrowing base is less than the amount of outstanding indebtedness, we will be required to (i) pledge additional collateral, (ii) prepay the excess in not more than five equal monthly installments, or (iii) elect to convert the entire amount of outstanding indebtedness to a term obligation based on amortization formulas set forth in the loan agreement.  In connection with the issuance of the 7¾% Senior Notes due 2013, the borrowing base was reduced to $132.5 million in July 2005, and all outstanding balances on our revolving credit facility were repaid.

7¾% Senior Notes due 2013

In July 2005, we issued, in a private placement, $225 million of aggregate principal amount of Senior Notes.  The Senior Notes were issued at face value and will bear interest at 7¾% per year, payable semi-annually on February 1 and August 1 of each year, beginning February 1, 2006.  After the payment of

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typical transaction expenses, net proceeds of approximately $217 million were used to repay amounts outstanding on our secured credit facilities and for general corporate purposes, including the funding of planned exploration and development activities.

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

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

Since the Senior Notes have an eight-year maturity and bear interest at a fixed rate of 7¾%, we expect our effective annual interest rate to increase in future periods.  However, we believe it is likely that average variable interest rates will exceed the fixed rate of the Senior Notes during this eight-year period.

Alternative capital resources

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

Item 3 -Quantitative and Qualitative Disclosure About Market Risks

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

Oil and Gas Prices

Our financial condition, results of operations, and capital resources are highly dependent upon the prevailing market prices of, and demand for, oil and natural gas.  These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond our control.  These factors include the level of global demand for petroleum products, foreign supply of oil and gas, the

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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, 2004 reserve estimates, we project that a $1.00 drop in the price per Bbl of oil and a $.50 drop in the price per Mcf of gas would reduce our gross revenues for the year ending December 31, 2005 by $12.8 million.

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

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

The following summarizes information concerning our net positions in open commodity derivatives applicable to periods subsequent to September 30, 2005.  The settlement prices of commodity derivatives are based on NYMEX futures prices.

Floors:

	Gas			Oil
	MMBtu (a)	Floor		Bbls	Floor
Production Period:
4th Quarter 2005	1,840,000	$	4.50	119,600	$	28.00

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Collars:

	Gas					Oil
	MMBtu (a)	Floor		Ceiling		Bbls	Floor		Ceiling
Production Period:
4th Quarter 2005 (b)	588,000	$	4.00	$	5.23	108,000	$	23.00	$	25.41
2006	2,024,000	$	4.00	$	5.21	613,000	$	23.00	$	25.32
2007	1,831,000	$	4.00	$	5.18	562,000	$	23.00	$	25.20
2008	1,279,000	$	4.00	$	5.15	392,000	$	23.00	$	25.07
	5,722,000					1,675,000

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

(b)The above table excludes a closed hedge position for 54,000 barrels of oil which will be settled during the fourth quarter of 2005 at a loss of $2.4 million.

In November 2005, we entered into a swap covering 1.1 million barrels of 2006 oil production in 2005 at a fixed price of $62.30 per barrel.

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 $8 million.

Interest Rates

At September 30, 2005, substantially all of our long-term debt bears interest at a fixed rate of 7¾%.  However, we expect to borrow funds in the future on the revolving credit facility which bears interest at a variable rate.

The following summarizes information concerning our net positions in open interest rate swaps applicable to periods subsequent to September 30, 2005.

	Principal		Libor
	Balance		Rates
Period:
October 1, 2005 to November 1, 2005	$	60,000,000	2.97	%
November 1, 2005 to November 1, 2006	$	55,000,000	4.29	%
November 1, 2006 to November 1, 2007	$	50,000,000	5.19	%
November 1, 2007 to November 1, 2008	$	45,000,000	5.73	%

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

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Item 4 -Controls and Procedures

Disclosure Controls and Procedures

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

With respect to our disclosure controls and procedures:

•We have evaluated the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report;

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

•It is the conclusion of our chief executive and chief financial officers that these disclosure controls and procedures operate such that material information flows to the appropriate collection and disclosure points in a timely manner and are effective in ensuring that material information is accumulated and communicated to our management and is made known to the chief executive and chief financial officers, particularly during the period in which this report was prepared, as appropriate to allow timely decisions regarding required disclosures.

Changes in Internal Control Over Financial Reporting

No changes in internal control over financial reporting were made during the quarter ended September 30, 2005 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II.  OTHER INFORMATION

Item 2 -Unregistered Sales of Equity Securities and Use of Proceeds

The Company issued shares of common stock of the Company (the “Common Stock”) to Clayton W. Williams on the dates, in the amounts and for the consideration, paid in the form of services rendered to the Company and in lieu of cash salary earned by and payable to Mr. Williams on those dates, as set forth below:

Date	Shares	Price		Consideration
February 28, 2005	1,257	$	28.92	$	36,353
March 31, 2005	1,530	$	25.41	$	38,887
April 29, 2005	1,644	$	23.64	$	38,887
May 31, 2005	1,384	$	28.08	$	38,887
June 30, 2005	1,274	$	30.50	$	38,887
July 29, 2005	1,127	$	34.50	$	38,887
August 31, 2005	1,052	$	36.94	$	38,887

These shares were issued on each salary payment date at the closing sale price of the Common Stock as reported on the Nasdaq National Market on the day immediately prior to the day of issuance.  These issuances were ratified by the Board of Directors of the Company in September 2005.

The issuances of these shares were determined to be exempt from registration under Section 4(2) of the Securities Act or Regulation D thereunder as transactions by an issuer not involving a public offering.  Mr. Williams was an accredited investor on the date of each issuance and has represented his intention to acquire the shares for investment only and not with a view to or for resale in connection with any distribution thereof.  The issuance of these shares was made without general solicitation or advertising, and there were no underwriters used in connection with the sale of these securities.  All of the shares are deemed to be restricted securities for the purposes of the Securities Act and appropriate legends have been affixed to the share certificates issued in these transactions.

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Item 6 -Exhibits

Exhibits

3.1**	Second Restated Certificate of Incorporation of the Company, filed as Exhibit 3.1 to our Form S-2 Registration Statement, Commission File No. 333-13441
3.2**	Certificate of Amendment of Second Restated Certificate of Incorporation of Clayton Williams Energy, Inc., filed as Exhibit 3.1 to our Form 10-Q for the period ended September 30, 2000
3.3**	Bylaws of the Company, filed as Exhibit 3.4 to our Form S-1 Registration Statement, Commission File No. 33-43350
3.4**	Corporate Bylaws of Clayton Williams Energy, Inc., as amended, filed as Exhibit 3.1 to our Current Report on Form 8-K filed with the Commission on June 1, 2005††
4.1**	Indenture, dated July 20, 2005, among Clayton Williams Energy, Inc., the Subsidiary Guarantors and Wells Fargo Bank, National Association, as Trustee, filed as Exhibit 4.1 to our Current Report on Form 8-K filed with the Commission on July 22, 2005††
4.2**	Registration Rights Agreement dated July 20, 2005, among Clayton Williams Energy, Inc., the Subsidiary Guarantors and J.P. Morgan Securities Inc., filed as Exhibit 4.2 to our Current Report on Form 8-K filed with the Commission on July 22, 2005††
10.1**	First Amendment to Amended and Restated Credit Agreement dated July 18, 2005, filed as Exhibit 10.1 to our Current Report on Form 8-K filed with the Commission on July 20, 2005††
10.2**	Letter agreement dated October 20, 2005 between Clayton Williams Energy, Inc. and Lariat Services, Inc., filed as Exhibit 10.1 to our Current Report on Form 8-K filed with the Commission on October 27, 2005††
31.1*	Certification by the President and Chief Executive Officer of the Company pursuant to Rule 13(a) - 14(a) of the Securities Exchange Act of 1934
31.2*	Certification by the Chief Financial Officer of the Company pursuant to Rule 13(a) - 14(a) of the Securities Exchange Act of 1934
32*	Certifications by the Chief Executive Officer and Chief Financial Officer of the Company pursuant to 18 U.S.C. § 1350

*Filed herewith

**Incorporated by reference to the filing indicated

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

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

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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:November 8, 2005	By:	/s/ L. Paul Latham
		L. Paul Latham
		Executive Vice President and Chief
		Operating Officer
Date:November 8, 2005	By:	/s/ Mel G. Riggs
		Mel G. Riggs
		Senior Vice President and Chief Financial
		Officer

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