Clayton Williams Energy (CWEI) 10-Q 2004 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, 2004

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. 0-20838

CLAYTON WILLIAMS ENERGY, INC.

(Exact name of Registrant as specified in its charter)

Delaware	75-2396863
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification 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 10,780,365 shares of Common Stock, $.10 par value, of the registrant outstanding as of November 3, 2004.

CLAYTON WILLIAMS ENERGY, INC.

TABLE OF CONTENTS

	PART I.  FINANCIAL INFORMATION
Item 1.	Financial Statements
	Consolidated Balance Sheets as of September 30, 2004 and December 31, 2003
	Consolidated Statements of Operations for the three months and nine months ended September 30, 2004 and 2003
	Consolidated Statement of Stockholders’ Equity for the nine months ended September 30, 2004
	Consolidated Statements of Cash Flows for the nine months ended September 30, 2004 and 2003
	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 6.	Exhibits and Reports on Form 8-K
	Signatures

2

CLAYTON WILLIAMS ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

	September 30, 2004			December 31, 2003
	(Unaudited)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	15,359		$	15,454
Accounts receivable:
Oil and gas sales, net	20,225			16,725
Joint interest and other, net	3,568			2,972
Affiliates	1,324			453
Inventory	6,822			787
Deferred income taxes	485			1,241
Prepaids and other	2,512			1,518
	50,295			39,150
PROPERTY AND EQUIPMENT
Oil and gas properties, successful efforts method	963,523			656,531
Natural gas gathering and processing systems	17,374			16,829
Other	13,505			12,300
	994,402			685,660
Less accumulated depreciation, depletion and amortization	(531,226		)	(504,101		)
Property and equipment, net	463,176			181,559
OTHER ASSETS	7,639			3,724
	$	521,110		$	224,433
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts payable:
Trade	$	36,155		$	33,523
Oil and gas sales	10,740			10,086
Affiliates	1,938			1,254
Current maturities of long-term debt	5,196			2,453
Fair value of derivatives	23,935			2,233
Accrued liabilities and other	3,356			2,720
	81,320			52,269
NON-CURRENT LIABILITIES
Long-term debt	217,696			53,295
Deferred income taxes	43,157			8,504
Fair value of derivatives	29,239			—
Other	19,799			9,584
	309,891			71,383
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 – 10,775,409 shares in 2004 and 9,368,322 shares in 2003	1,078			937
Additional paid-in capital	104,455			73,972
Retained earnings	24,366			25,872
	129,899			100,781
	$	521,110		$	224,433

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

3

CLAYTON WILLIAMS ENERGY, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(In thousands, except per share)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2004			2003			2004			2003
REVENUES
Oil and gas sales	$	52,517		$	38,039		$	129,968		$	129,785
Natural gas services	2,074			2,202			6,973			6,504
Gain (loss) on sales of property and equipment	(68		)	(12		)	(2		)	201
Total revenues	54,523			40,229			136,939			136,490
COSTS AND EXPENSES
Production	12,372			7,227			27,502			21,477
Exploration:
Abandonments and impairments	11,197			3,953			29,296			17,347
Seismic and other	1,350			1,481			5,087			5,445
Natural gas services	1,882			2,075			6,529			6,064
Depreciation, depletion and amortization	11,583			10,055			29,354			31,279
Impairment of property and equipment	—			170			—			170
Accretion of abandonment obligations	413			171			853			477
General and administrative	2,493			2,039			8,080			6,969
Total costs and expenses	41,290			27,171			106,701			89,228
Operating income	13,233			13,058			30,238			47,262
OTHER INCOME (EXPENSE)						��
Interest expense	(2,806		)	(697		)	(4,715		)	(2,550		)
Change in fair value of derivatives	(24,580		)	412			(27,982		)	1,154
Other	764			(1,239		)	727			(1,356		)
Total other income (expense)	(26,622		)	(1,524		)	(31,970		)	(2,752		)
Income (loss) before income taxes	(13,389		)	11,534			(1,732		)	44,510
Income tax expense (benefit)	(4,201		)	3,980			(226		)	14,524
Income (loss) before extraordinary items	(9,188		)	7,554			(1,506		)	29,986
Cumulative effect of accounting change, net of tax	—			—			—			207
NET INCOME (LOSS)	$	(9,188	)	$	7,554		$	(1,506	)	$	30,193
Net income (loss) per common share:
Basic:
Income (loss) before extraordinary items	$	(0.85	)	$	0.81		$	(0.16	)	$	3.22
Net income (loss)	$	(0.85	)	$	0.81		$	(0.16	)	$	3.24
Diluted:
Income (loss) before extraordinary items	$	(0.85	)	$	0.79		$	(0.16	)	$	3.17
Net income (loss)	$	(0.85	)	$	0.79		$	(0.16	)	$	3.19
Weighted average common shares outstanding:
Basic	10,769			9,330			9,560			9,318
Diluted	10,769			9,565			9,560			9,463

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

4

CLAYTON WILLIAMS ENERGY, INC.

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY

(Unaudited)

(In thousands)

	Common Stock			Additional
	No. of Shares	Par Value		Paid-In Capital			Retained Earnings
BALANCE,
December 31, 2003	9,368	$	937	$		73,972	$	25,872
Net loss and total comprehensive loss	—	—		—			(1,506			)
Issuance of stock through compensation plans	26	3		634			—
Issuance of common stock, net of offering costs of $1,773	1,381	138		29,849			—
BALANCE,
September 30, 2004	10,775	$	1,078	$	104,455		$		24,366

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

5

CLAYTON WILLIAMS ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In thousands)

	Nine Months Ended September 30,
	2004			2003
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	(1,506	)	$	30,193
Adjustments to reconcile net income (loss) to cash provided by operating activities:
Depreciation, depletion and amortization	29,354			31,279
Impairment of property and equipment	—			170
Exploration costs	29,296			17,347
(Gain) loss on sales of property and equipment	2			(201		)
Deferred income taxes	(226		)	13,989
Non-cash employee compensation	272			738
Change in fair value of derivatives	22,273			(981		)
Accretion of abandonment obligations	853			477
Cumulative effect of accounting change, net of tax	—			(207		)
Changes in operating working capital, net of the effects of a business acquisition in 2004:
Accounts receivable	6,243			(857		)
Accounts payable	536			5,651
Other	(3,938		)	1,247
Net cash provided by operating activities	83,159			98,845
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to property and equipment	(93,593		)	(49,931		)
Consideration paid to acquire a business, net of cash acquired of $12,341	(168,204		)	—
Proceeds from sales of property and equipment	441			236
Other	354			(407		)
Net cash used in investing activities	(261,002		)	(50,102		)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt	191,800			—
Repayments of long-term debt	(35,258		)	(43,956		)
Proceeds from sale of common stock	30,008			243
Payment of debt issue costs	(4,156		)	—
Derivative settlements	(4,646		)	—
Net cash provided by (used in) financing activities	177,748			(43,713		)
NET INCREASE (DECREASE) IN CASH AND
CASH EQUIVALENTS	(95		)	5,030
CASH AND CASH EQUIVALENTS
Beginning of period	15,454			5,676
End of period	15,359			10,706
SUPPLEMENTAL DISCLOSURES
Cash paid for interest, net of amounts capitalized	$	3,857		$	2,587

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

6

CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2004

(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 Texas, Louisiana, New Mexico and Mississippi.  Approximately 41% 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

On May 21, 2004, the Company acquired all the outstanding common stock of Southwest Royalties, Inc. (see Note 4).  The accompanying unaudited consolidated financial statements of the Company for 2004 include the accounts of Southwest Royalties, Inc., its wholly owned subsidiaries and its undivided interests in oil and gas limited partnerships as of September 30, 2004 and for the period from May 21, 2004 through September 30, 2004.

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, 2004 and for the interim periods ended September 30, 2004 and 2003 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, 2004.

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 2003 Form 10-K.

3.Recent Accounting Pronouncements

In January 2003, the Financial Accounting Standards Board (“FASB”) issued Financial Interpretation No. 46, “Consolidation of Variable Interest Entities - an interpretation of ARB No. 51” (“FIN 46”).  In December 2003, the FASB clarified some of the provisions in a revised FIN 46 (“FIN 46R”).  FIN 46R defines the characteristics of a variable interest entity (“VIE”) and requires that if a company is the primary

7

beneficiary of a VIE, that VIE’s assets, liabilities and results of operations should be consolidated in the company’s financial statements.  A company is the primary beneficiary of a VIE if the company will absorb a majority of the VIE’s expected losses if they occur, receive a majority of the VIE’s expected residual returns if they occur, or both.  Since the Company does not hold an interest in any entity that has the characteristics of a VIE, the adoption of FIN 46R during the nine months ended September 30, 2004 had no impact on the Company’s consolidated financial statements.

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.  SWR owns interests in more than 6,000 oil and gas wells, and is the operator of approximately 1,400 of these wells.  The Company estimated that the SWR acquisition added approximately 180 Bcfe to its proved oil and gas reserves on the effective date of the acquisition.

In connection with the acquisition of SWR, the Company paid $57.1 million to holders of SWR common stock and common stock warrants ($45.01 per share) 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.

The following table sets forth the calculation of the preliminary purchase price for SWR and the related allocation of the preliminary purchase price to the assets acquired (in thousands):

Preliminary purchase price:
Acquisition of outstanding common stock and warrants	$	57,139
Long-term debt assumed and refinanced by CWEI	113,949
Assumption of other non-current liabilities	31,024
Transaction costs incurred	9,355
Current liabilities assumed	26,425
Deferred income taxes	36,348
	$	274,240
Allocation of preliminary purchase price:
Current assets	$	23,436
Proved oil and gas properties	228,844
Unproved oil and gas properties	18,096
Other property and equipment	3,494
Other assets	370
	$	274,240

The purchase price for SWR and the related allocation of the purchase price to the assets acquired is preliminary.  The Company is continuing to gather information concerning the estimated fair value of certain assets and liabilities as of the acquisition date and may adjust its preliminary estimates based on this information.  Any such adjustments may be material.  The primary accounts subject to adjustment include deferred income taxes, property and equipment and liability contingencies.  The Company expects to finalize its valuation estimates by December 31, 2004.

8

The revaluation of SWR’s assets and liabilities under the purchase method of accounting created significant differences between the carrying value for financial reporting purposes and those used for income tax reporting purposes, resulting in federal and state deferred tax liabilities of $36.3 million on the effective date of the acquisition.

The following table reflects the unaudited pro forma results of operations for the nine months ended September 30, 2004 and 2003 as though the acquisition of SWR had occurred on January 1, 2003.  The pro forma amounts are not necessarily indicative of the results that may be reported in the future.

	Nine Months Ended September 30,
	2004			2003
	(In thousands, except per share data)
Revenues	$	160,772		$	178,652
Net income (loss) from continuing operations	$	(12,703	)	$	34,528
Net income (loss) from continuing operations per share:
Basic	$	(1.18	)	$	3.23
Diluted	$	(1.18	)	$	3.18

5.Long-Term Debt

Long-term debt consists of the following:

	September 30, 2004			December 31, 2003
	(In thousands)
Secured bank credit facilities:
Revolving loan, due May 2007	$	166,800		$	50,000
Senior term loan, due May 2008	50,000			—
Vendor finance obligations	5,146			5,748
Other	946			—
	222,892			55,748
Less current maturities	(5,196		)	(2,453		)
	$	217,696		$	53,295

Aggregate maturities of long-term debt at September 30, 2004 are as follows:  2005 – $5,196,000; 2006 - $896,000; 2007 - $166,800,000; and 2008 - $50,000,000.

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.

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 provides 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%.  Unless and until the principal balance on the senior term credit facility is equal to or less than $40 million, the applicable margins will increase by .5% per quarter, beginning July 1, 2004.  Once the principal balance

9

is $40 million or less, the prime rate margin will be fixed at 2.5%, and the LIBOR margin will be fixed at 4%.  Interest and fees are payable at least quarterly.  The effective annual interest rate on the combined credit facility, including bank fees and amortization of debt issue costs, for the nine months ended September 30, 2004 was 4.9%.

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, 2004, the borrowing base was $180 million, with no monthly commitment reductions.  After allowing for outstanding letters of credit totaling $4.3 million, the Company had $8.9 million available under the revolving credit facility at September 30, 2004.

Principal under the senior term note is due at maturity; however, mandatory prepayments are required when the Company raises funds from capital markets transactions or sales of assets.  Prepayments that reduce the principal balance on the senior term note below $40 million are subject to a 1% prepayment penalty.

The loan agreements applicable to the respective credit facilities contain 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.  Other financial covenants under the credit facilities require the Company to maintain a ratio of indebtedness to cash flow of no more than 3 to 1, and a ratio of reserve value to indebtedness of at least 1.5 to 1.  The computations of current assets, current liabilities, cash flow, indebtedness and reserve value are defined in the respective loan agreements.  The Company was in compliance with all financial and non-financial covenants at September 30, 2004.

Vendor Finance Obligations

In August 2003, the Company initiated a vendor financing arrangement for wells to be drilled in south Louisiana whereby all costs of participating vendors, including interest at an annual rate of 9%, will be repaid out of a percentage of the net revenues from the wells drilled under the arrangement.  If net revenues are insufficient to repay financed costs within an 18-month period from the invoice date, the Company has agreed to repay any unpaid balance.

6.Other Non-Current Liabilities

Other non-current liabilities consist of the following:

	September 30, 2004		December 31, 2003
	(In thousands)
Abandonment obligations	$	18,471	$	8,849
Production payment	799		735
Other	529		—
	$	19,799	$	9,584

10

Abandonment Obligations

Abandonment obligations as of September 30, 2004 and December 31, 2003 represent the present value of the Company’s estimated abandonment obligations under Statement of Financial Accounting Standards No. 143 “Accounting for Asset Retirement Obligations” (“SFAS 143”).  Changes in abandonment obligations during the nine months ended September 30, 2004 consist primarily of the assumption of $8.4 million of abandonment obligations related to the acquisition of SWR, $414,000 of additional abandonment obligations from new wells, and $853,000 of accretion expense.

Production Payment

In connection with the acquisition of properties in the Romere Pass Unit in Plaquemines Parish, Louisiana in 2002, the Company granted to the seller a $1 million after-payout production payment.  After the Company has recouped $21 million, plus certain developmental drilling costs, and interest on the combined amounts at an annual rate of 12%, the Company will pay to the seller 5% of its net proceeds from production until the $1 million production payment is satisfied.

7.Sale of 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).

8.Compensation Plans

Executive Stock Compensation Plan

The Company has reserved 500,000 shares of common stock for issuance under the Executive Incentive Stock Compensation Plan, permitting the Company, at its discretion, to pay all or part of selected executives’ salaries in shares of common stock in lieu of cash.  During the nine months ended September 30, 2004, the Company issued 13,379 shares of common stock to Mr. Williams in lieu of net cash compensation aggregating $346,000, which is included in general and administrative expenses in the accompanying consolidated financial statements.  Subsequent to September 30, 2004, the Company issued an additional 1,901 shares to Mr. Williams in lieu of cash compensation aggregating $39,000.

Stock-Based Compensation

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.  In July 2004, Mr. Williams was granted options to purchase 300,000 shares of common stock at a price of $26.06, which was the market value at the date of grant.

11

The SFAS 123 pro forma information for the nine months ended September 30, 2004 and 2003 is as follows:

	Nine Months Ended September 30,
	2004			2003
	(In thousands, except per share)
Net income (loss), as reported	$	(1,506	)	$	30,193
Add: Stock-based employee compensation expense (credit) included in net income, net of tax	(197		)	247
Deduct: Stock-based employee compensation expense determined under fair value based method (SFAS 123), net of tax	(3,840		)	(477		)
Net income (loss), pro forma	$	(5,543	)	$	29,963
Basic:
Net income (loss) per common share, as reported	$	(.16	)	$	3.24
Net income (loss) per common share, pro forma	$	(.58	)	$	3.22
Diluted:
Net income (loss) per common share, as reported	$	(.16	)	$	3.19
Net income (loss) per common share, pro forma	$	(.58	)	$	3.17

In accordance with the issuance of Financial Accounting Standards Board Interpretation No. 44 (“FIN 44”) to APB 25 effective July 2000, the Company changed the classification of 233,141 stock options repriced by the Company 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 exceeds the amended option price ($5.50 per share), except that options vested as of July 1, 2000 must recognize compensation expense only to the extent that the quoted market value exceeds the market value on July 1, 2000 ($31.94 per share).  The closing market price of the Company’s common stock at September 30, 2004 was $21.43.  Accordingly, general and administrative expenses for the nine months ended September 30, 2004 and 2003 included a non-cash credit of $303,000 and a non-cash charge of $380,000, respectively, related to stock-based employee compensation.  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.

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.

From 3% to 5% 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 $250,000 were paid to the limited partners during 2004.

12

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.  When using floors to hedge production, the Company purchases an option to sell the hedged production at a fixed price if the market price falls below the put strike price.  Collars contain a fixed floor price (put) and ceiling price (call).  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, then no payments are due from either party.

In connection with the new credit facilities discussed in Note 5, the banks have required the Company to hedge at least 60% of its expected production through 2005.

The following summarizes information concerning the Company’s net positions in open commodity derivatives applicable to periods subsequent to September 30, 2004.  The settlement prices of commodity derivatives are based on NYMEX futures prices.

Swaps:

	Gas			Oil
	MMBtu (a)	Price		Bbls	Price
Production Period:
4th Quarter 2004	620,000	$	7.87	150,000	$	31.53
1st Quarter 2005	1,800,000	$	8.28	—
	2,420,000			150,000

Floors:

	Gas			Oil
	MMBtu (a)	Floor		Bbls	Floor
Production Period:
1st Quarter 2005	1,800,000	$	4.50	117,000	$	28.00
2nd Quarter 2005	1,820,000	$	4.50	118,300	$	28.00
3rd Quarter 2005	1,840,000	$	4.50	119,600	$	28.00
4th Quarter 2005	1,840,000	$	4.50	119,600	$	28.00
	7,300,000			474,500

Collars:

	Gas					Oil
	MMBtu (a)	Floor		Ceiling		Bbls	Floor		Ceiling
Production Period:
4th Quarter 2004	690,000	$	4.20	$	5.28	175,000	$	23.00	$	25.46
4th Quarter 2004	685,000	$	4.00	$	5.24
1st Quarter 2005	649,000	$	4.00	$	5.23	170,000	$	23.00	$	25.41
2nd Quarter 2005	630,000	$	4.00	$	5.23	168,000	$	23.00	$	25.41
3rd Quarter 2005	607,000	$	4.00	$	5.23	165,000	$	23.00	$	25.41
4th Quarter 2005	588,000	$	4.00	$	5.23	162,000	$	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
	8,983,000					2,407,000

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

13

Interest Swaps:

	Principal Balance		Libor Rates
Period:
October 1, 2004 to November 1, 2004	$	65,000,000	1.68	%
November 1, 2004 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 statement of cash flows.

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 facility 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.  Vendor finance and production payment obligations, in the aggregate, have an estimated fair value of $6.5 million based on the net present value of future cash outflows and using assumptions for timing of payments and discount rates that the Company considers appropriate.

The fair values of derivatives are equal to their associated carrying values.  Commodity derivatives were a $51.5 million liability at September 30, 2004 and a $2.2 million liability at December 31, 2003.  Interest rate derivatives were a $1.7 million liability at September 30, 2004.  The Company assumed a $33.3 million liability on derivatives at the acquisition date of SWR (see Note 4).

14

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, 2004 and December 31, 2003 are as follows:

	September 30, 2004			December 31, 2003
	(In thousands)
Deferred tax assets:
Net operating loss carryforwards	$	3,111		$	6,915
Net operating loss carryforwards acquired in SWR merger	6,870			—
Fair value of derivatives	18,617			783
Depletion carryforwards	2,664			—
Other	5,476			2,097
	36,738			9,795
Deferred tax liabilities:
Property and equipment	(79,410		)	(17,058		)
Net deferred tax liabilities	$	(42,672	)	$	(7,263	)
Components of net deferred tax liabilities:
Current assets	$	485		$	1,241
Non-current liabilities	(43,157		)	(8,504		)
	$	(42,672	)	$	(7,263	)

For the nine months ended September 30, 2004 and 2003, 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,
	2004			2003
	(In thousands)
Income tax expense (benefit) at statutory rate of 35%	$	(606	)	$	15,579
Tax depletion in excess of basis	(369		)	(158		)
Revision of previous tax estimates	(51		)	(29		)
Change in valuation allowance	—			(871		)
State income taxes	800			—
Other	—			3
Income tax expense (benefit)	$	(226	)	$	14,524
Current	$	699		$	535
Deferred	(925		)	13,989
Income tax expense (benefit)	$	(226	)	$	14,524

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 financial 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 $29.9 million of tax loss carryforwards that are subject to Section 382 limitations from a prior change in control that occurred in April 2002 and from the change in control that occurred in connection with the Company’s acquisition of SWR in May

15

2004.  The Company has completed a review of the facts surrounding this change in control and presently believes that it will be able to utilize all of SWR’s tax loss carryforwards.  Therefore, the Company has reversed the valuation allowance related to these tax loss carryforwards that was previously recorded at June 30, 2004, and has adjusted the SWR purchase price accordingly.

At September 30, 2004, the Company’s cumulative tax loss carryforwards were approximately $28.5 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 exists at September 30, 2004.  A valuation allowance at December 31, 2002 was reversed during the quarter ended June 30, 2003.

12.Stock Repurchase Program

The Company’s stock repurchase program expired in July 2004.  Since its inception in 2001, the Company spent $1.4 million to repurchase for cancellation 115,100 shares of common stock, none of which were repurchased in 2003 or 2004.

13.Investment

In May 2001, the Company invested approximately $1.6 million as a limited partner in ClayDesta Buildings, L.P. (“CDBLP”).  The general partner of CDBLP is owned and controlled by Mr. Williams.  CDBLP purchased and presently operates two commercial office buildings in Midland, Texas, one of which is the location of the Company’s corporate headquarters.  The Company’s ownership interest in CDBLP is 31.9% before payout (as defined in the partnership agreement) and 33.4% after payout.  The Company is not liable for any indebtedness of CDBLP.  Since the Company does not control CDBLP or manage the operations of these buildings, and since CDBLP does not meet the characteristics of a variable interest entity under FIN 46R (see Note 3), the Company utilizes the equity method of accounting for its investment in CDBLP.

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, 2003.

Overview

We are an oil and gas exploration company.  Our basic business is to find oil and gas reserves through exploration 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.

The economic climate in the domestic oil and gas industry continues to be suitable for this business model.  Since the end of 2003, we have continued to see very strong product prices, with oil prices hitting record highs.  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.

Finding quality domestic oil and gas reserves through exploration is a significant challenge and involves a high degree of risk.  During the past two years, we have had limited drilling successes and have

16

not found sufficient reserves to replace our production.  We must reverse this trend in order to prevent further liquidation of our proved reserves.  Although our exploration success thus far in 2004 has been limited, we acquired approximately 180 Bcfe of proved reserves in a merger in May 2004.

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 2004 and the outlook for the remainder of 2004.

•Our operating results for the third quarter of 2004 were negatively impacted by a $24.6 million pre-tax loss related to the change in fair value of derivatives, including a $17.3 million non-cash provision based on changes in mark-to-market valuations from June 30, 2004 to September 30, 2004.  Since we do not presently designate our derivatives as cash flow hedges under applicable accounting standards, we recognize the full effect of changing prices on mark-to-market valuations as a charge or credit to the current quarter’s results of operations.

•In May 2004, we completed the acquisition of Southwest Royalties, Inc. (“SWR”).

•We successfully completed a second well in the Fleur prospect, the State Lease 17378 #2.  Both wells are currently waiting on production facilities and should be producing in the fourth quarter of 2004.

•We have begun completion operations on the Weyerhaeuser #1 well in the Black Warrior Basin of Mississippi.  Drilling and completion costs to date total approximately $9 million.

•Exploration costs related to abandonments and impairments were $11.2 million during the third quarter of 2004, of which $6.5 million was related to the Mervine Jankower #1 (Helen Gayle) in south Louisiana.

•We currently plan to spend $111.7 million in 2004 on exploration and development activities, of which approximately 80% relates to exploratory prospects.  Most of these planned activities are in areas where we had limited success in the past three years.  Since past results are not necessarily indicative of future results, we cannot predict our drilling success in the remainder of 2004 or beyond.  If we do not achieve a sustained improvement in the results of future exploratory drilling, our future results of operations and financial condition could be adversely affected.

•Production for the third quarter of 2004, on an Mcfe basis, was up slightly from the third quarter of 2003.  This was due primarily to the recent acquisition of SWR which contributed 2.7 Bcfe of oil and gas production during the third quarter of 2004.

Acquisition of Southwest Royalties, Inc.

On May 21, 2004, we acquired all the outstanding common stock of 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.  SWR owns interests in more than 6,000 oil and gas wells, and is the operator of approximately 1,400 of these wells.  We estimate that the SWR acquisition added approximately 180 Bcfe to our proved oil and gas reserves on the effective date of the acquisition.

In connection with the acquisition, we paid $57.1 million to holders of SWR common stock and common stock warrants ($45.01 per share) and assumed and refinanced approximately $113.9 million of SWR bank debt at closing.  In addition, we 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

17

control arrangements and (ii) investment banking, legal, accounting and other direct transaction costs related to the acquisition.

While the on-going integration of SWR’s operations into our existing operations is extensive and requires significant managerial and financial resources, we believe that this acquisition will also provide us with opportunities for significant reserve growth through exploration and development activities that may not have been available through other means.

Recent Exploration Developmental Activities

South Louisiana

The following table sets forth certain information about our exploratory well activities in south Louisiana subsequent to December 31, 2003.

Spud Date	Well Name (Prospect)	Working Interest		Current Status
September 2003	OCS – G – 21142 #4 (Nonoperated)	10	%	Productive
October 2003	State Lease 17378 #1 (Fleur)	75	%	Waiting on production facilities
December 2003	Allen Gautreaux #1 (King)	100	%	Productive
December 2003	OCS – G – 21142 #5 (Nonoperated)	10	%	Productive
February 2004	Louisiana Fruit Co. #1 (Tiger Pass)	100	%	Productive
February 2004	Mervine Jankower #1 (Helen Gayle)	100	%	Dry
March 2004	Louisiana Fruit Co. #2 (Tiger Pass)	100	%	Productive
March 2004	State Lease 17341 #1 (Brandi)	100	%	Dry
March 2004	State Lease 17057 #1 (Nonoperated)	17	%	Dry
May 2004	State Lease 17378 #2 (Fleur) (a)	75	%	Waiting on production facilities
July 2004	JL&S #1 (Nonoperated)	55	%	Dry
August 2004	McIlhenny #1 (Tabasco)	33	%	In Progress
September 2004	State Lease 17657 #1 (Nonoperated)	20	%	Dry
September 2004	Daigle et al #1 (Kelp)	100	%	In Progress
October 2004	LL&E “A” #1 (Jonita)	100	%	In Progress

(a)This well is classified as a developmental well based on data obtained in drilling the State Lease 17378 #1 (Fleur).

We have abandoned the Mervine Jankower #1 (Helen Gayle) in Acadia Parish after attempts to complete the well as a commercial producer were unsuccessful.  We recorded a pre-tax charge of approximately $6.5 million related to the abandonment of this well during the third quarter of 2004.  In addition, we participated in two non-operated wells in south Louisiana that were nonproductive, and recorded a pre-tax charge of  $2.5 million related to these wells during the third quarter of 2004.

We successfully completed two wells on the Fleur Prospect in Plaquemines Parish.  We currently expect both of these wells to begin production during the fourth quarter of 2004 after construction of production facilities are complete.

Mississippi

We have drilled, cored and logged the Weyerhaeuser #1, a test in the Stones River formation of the Black Warrior Basin, located in Webster County.  Completion operations have begun and should be complete by the middle of November.  Based on current geological information, we are unable to determine whether the well will be commercially productive.  CWEI owns a 99% interest in this well and has incurred drilling costs to date totaling approximately $9 million, net to our interest.

18

We began drilling the Mississippi State University #1, located in Oktibbeha County, in October 2004.  This well, which is being drilled pursuant to an 8,000-acre farm-in acquired from Total E&P USA, Inc. (“Total”), is located approximately 13 miles southeast of the Maben Field developed by Total and will target the Stones River (Ordovician) formation.  We will own 100% of the working interest to payout, at which time Total will have the option to back-in for a 35% working interest.  By completing the farm-in well as a producer, we will earn a 65% working interest and be named operator in all remaining land covered by the farm-in agreement.

19

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.  The operating results for SWR include only the period from May 21, 2004 through September 30, 2004.

	Three Months Ended September 30,
	2004		2003
Oil and Gas Production Data:
Gas (MMcf)	4,531		5,823
Oil (MBbls)	624		388
Natural gas liquids (MBbls)	77		82
Total (MMcfe)	8,737		8,643
Average Realized Prices:
Gas ($/Mcf):
Before hedging losses	$	5.32	$	4.84
Hedging losses (1)	—		(0.43		)
Net realized price	$	5.32	$	4.41
Oil ($/Bbl):
Before hedging losses	$	41.71	$	28.95
Hedging losses (1)	—		(1.42		)
Net realized price	$	41.71	$	27.53
Natural gas liquids ($/Bbl):	$	28.79	$	19.96
Average Daily Production:
Natural Gas (Mcf):
Austin Chalk (Trend)	3,021		3,294
Cotton Valley Reef Complex	21,579		38,152
Louisiana	8,745		17,516
New Mexico/West Texas	1,504		1,877
SWR	13,152		—
Other	1,249		2,454
Total	49,250		63,293
Oil (Bbls):
Austin Chalk (Trend)	2,104		2,825
Louisiana	1,295		541
New Mexico/West Texas	673		726
SWR	2,656		—
Other	55		125
Total	6,783		4,217
Natural Gas Liquids (Bbls):
Austin Chalk (Trend)	301		437
New Mexico/West Texas	321		247
Other	215		207
Total	837		891
Exploration Costs (in thousands):
Abandonment and impairment costs:
South Louisiana	$	9,600	$	1,895
Cotton Valley Reef Complex	44		1,429
Nevada, Arizona, California and Utah	725		—
Other	828		629
Total	11,197		3,953
Seismic and other	1,350		1,481
Total exploration costs	$	12,547	$	5,434

(Continued)

20

	Three Months Ended September 30,
	2004		2003
Oil and Gas Costs ($/Mcfe Produced):
Production costs	$	1.42	$	.84
Oil and gas depletion	$	1.24	$	1.11
Net Wells Drilled (3):
Exploratory Wells	4.0		3.2
Developmental Wells	.9		1.0

	Nine Months Ended September 30,
	2004		2003
Oil and Gas Production Data:
Gas (MMcf)	12,813		19,745
Oil (MBbls)	1,464		1,153
Natural gas liquids (MBbls)	181		173
Total (MMcfe)	22,683		27,701
Average Realized Prices:
Gas ($/Mcf):
Before hedging losses	$	5.39	$	5.52
Hedging losses (1)	—		(0.76		)
Net realized price	$	5.39	$	4.76
Oil ($/Bbl):
Before hedging losses	$	38.25	$	29.93
Hedging losses (1)	—		(2.45		)
Net realized price	$	38.25	$	27.48
Natural gas liquids ($/Bbl):	$	25.93	$	21.05
Average Daily Production:
Natural Gas (Mcf):
Austin Chalk (Trend)	3,266		3,726
Cotton Valley Reef Complex	24,321		46,081
Louisiana	9,790		18,415
New Mexico/West Texas	1,760		1,778
SWR (2)	6,245		—
Other	1,381		2,326
Total	46,763		72,326
Oil (Bbls):
Austin Chalk (Trend)	2,244		2,821
Louisiana	911		598
New Mexico/West Texas	829		720
SWR (2)	1,301		—
Other	58		84
Total	5,343		4,223
Natural Gas Liquids (Bbls):
Austin Chalk (Trend)	270		283
New Mexico/West Texas	197		183
Other	194		168
Total	661		634

(Continued)

21

	Nine Months Ended September 30,
	2004		2003
Exploration Costs (in thousands):
Abandonment and impairment costs:
South Louisiana	$	25,475	$	6,644
Cotton Valley Reef Complex	44		8,702
Nevada, Arizona, California and Utah	2,408		394
Other	1,369		1,607
Total	29,296		17,347
Seismic and other	5,087		5,445
Total exploration costs	$	34,383	$	22,792

Oil and Gas Costs ($/Mcfe Produced):
Production costs	$	1.21	$	.78
Oil and gas depletion	$	1.19	$	1.08
Net Wells Drilled (3):
Exploratory Wells	9.1		8.7
Developmental Wells	7.6		4.0

(1)The Company did not designate any of its 2004 derivatives as cash flow hedges under Statement of Financial Accounting Standards No. 133, as amended.  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 and are excluded from the computation of average realized prices from oil and gas sales.

(2)Average daily production for SWR during the nine months ended September 30, 2004 amounted to 12,962 Mcf of gas production and 2,699 barrels of oil production based on the 132-day period.

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

Operating Results – Three-Month Periods

The following discussion compares our results for the three months ended September 30, 2004 to the comparative period in 2003.  Unless otherwise indicated, references to 2004 and 2003 within this section refer to the respective quarterly period.

Oil and gas operating results

Oil and gas sales in 2004 increased 38% from 2003 due primarily to higher product prices and a slight increase in oil and gas production on an Mcfe basis.  The price variance accounted for $13.7 million of the $14.5 million increase in oil and gas sales, while the production variance accounted for the remaining increase of $800,000.

Oil production in 2004 increased 61% primarily as a result of the acquisition of SWR during 2004, offset in part by the continued decline of oil production from existing wells in the Austin Chalk (Trend).  Gas production, on the other hand, declined 22% in 2004 as compared to 2003, continuing its downward trend since reaching a peak during the second quarter of 2003.  Our peak gas production in 2003 was due primarily to high initial production rates from the Lee Fazzino #2 well in the Cotton Valley area.  This well accounted for approximately 62% of our total gas production for the year 2003.  As gas production from the Lee Fazzino #2 and other wells in the Cotton Valley area declined due to normal reservoir depletion, we were unable to completely offset this decline with production from our exploration program.  We expect that production from the properties acquired from SWR will decline at a significantly lower rate than our existing production in the Cotton Valley Reef Complex area and south Louisiana because most of the acquired properties are mature properties with lower depletion rates.

Overall, product prices continue to be strong.  Our realized oil price in 2004 increased 52% from 2003, while our realized gas price increased 21%.  The 2003 prices include $3.1 million of realized losses

22

from hedging activities.  Realized losses of $7.2 million on commodity hedges for 2004 are included in other income/expense as a component of change in fair value of derivatives since the hedges were not designated as cash flow hedges under SFAS 133.

Looking forward, we currently estimate that our oil and gas production on an Mcfe basis for the fourth quarter of 2004 will be more than 10% higher than the same period in 2003 due primarily to the added production from the acquisition of SWR.

Oil and gas production costs increased 71% in 2004 as compared to 2003 due to a combination of higher operating costs and higher production taxes.  The increase in operating costs was primarily due to the added expense related to properties acquired in connection with the SWR merger.  The increase in production taxes was attributable to the effects of higher oil and gas prices.  The combined effects of higher production costs and relatively constant production levels resulted in a 69% increase in production costs per Mcfe.  It is likely that higher production taxes resulting from higher product prices, combined with operating costs attributable to the SWR properties, will continue to contribute to higher production costs in future periods.

Depreciation, depletion, and amortization (“DD&A”) expense in 2004 increased 15% as compared to 2003 due primarily to higher finding costs, offset in part by the effects of higher commodity prices on reserve estimates.  DD&A expense per Mcfe produced increased 12% from 2003 to 2004.  We currently estimate that our DD&A expense per Mcfe produced for the fourth quarter of 2004 could be between 15% and 25% higher than the same period in 2003.

General and administrative (“G&A”) expenses, excluding non-cash stock-based employee compensation, increased 29% in 2004 as compared to 2003 due primarily to higher personnel costs, professional fees and insurance costs, including the acquisition of SWR in May 2004.  G&A expenses for 2004 include a non-cash credit (reduction of expense) of $98,000 for stock-based employee compensation required by Financial Accounting Standards Board Interpretation No. 44.  A $33,000 charge was required for the 2003 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.

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 2004, we charged to expense $12.5 million of exploration costs, as compared to $5.4 million in 2003.  Most of these costs were incurred in south Louisiana.

We plan to spend approximately $111.7 million on exploration and development activities in 2004 primarily in the same core exploration areas as in 2003.  Since exploratory drilling involves a high degree of risk, it is likely that a significant portion of the remaining costs in 2004 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 and Other

Interest expense increased threefold from $697,000 in 2003 to $2.8 million in 2004 due primarily to higher average levels of indebtedness under the credit facilities and higher effective interest rates.  The average daily principal balance outstanding under the credit facilities for 2004 was $216.1 million compared to $59.2 million in 2003.  The increased borrowings were primarily a result of the acquisition of SWR in May of 2004.  The effective annual interest rate on bank debt, including bank fees and interest rate derivatives, during 2004 was 5.3% compared to 5.8% in 2003.

Other income/expense for 2004 included a $24.6 million loss associated with the change in fair value of derivative contracts as compared to a $412,000 gain in 2003.  In both periods, we held commodity

23

derivatives that were not designated as cash flow hedges under applicable accounting standards.  Changes in the fair value of these derivatives are based on the underlying commodity prices and resulted in a $25 million variance in other income/expense between the two quarters.

Operating Results – Nine-Month Periods

The following discussion compares our results for the nine months ended September 30, 2004 to the comparative period in 2003.  Unless otherwise indicated, references to 2004 and 2003 within this section refer to the respective nine-month period.

Oil and gas operating results

Oil and gas sales in 2004 remained relatively constant at approximately $130 million compared to 2003.  The price variance accounted for a $24.7 million increase in oil and gas sales, while the production variance accounted for a $24.6 million decrease.

Oil production in 2004 increased 27% as a result of the acquisition of SWR during 2004, offset in part by the continued decline of oil production from existing wells in the Austin Chalk (Trend).  Gas production, on the other hand, declined 35% in 2004 as compared to 2003, continuing its downward trend since reaching a peak during the second quarter of 2003.  Our peak gas production in 2003 was due primarily to high initial production rates from the Lee Fazzino #2 well in the Cotton Valley area.  This well accounted for approximately 62% of our total gas production for the year 2003.  As gas production from the Lee Fazzino #2 and other wells in the Cotton Valley area declined due to normal reservoir depletion, we were unable to completely offset this decline with production from our exploration program.  We expect that production from the properties acquired from SWR will decline at a significantly lower rate than our existing production in the Cotton Valley Reef Complex area and south Louisiana because most of the acquired properties are mature properties with lower depletion rates.

Overall, product prices continue to be strong.  Our realized oil price in 2004 increased 39% from 2003, while our realized gas price increased 13%.  The 2003 prices include $17.9 million of realized losses from hedging activities.  Realized losses of $10.3 million on commodity hedges for 2004 are included in other income/expense as a component of change in fair value of derivatives since the hedges were not designated as cash flow hedges under SFAS 133.

Looking forward, we currently estimate that our oil and gas production on an Mcfe basis for the fourth quarter of 2004 will be more than 10% higher than the same period in 2003 due primarily to the added production from the acquisition of SWR.

Oil and gas production costs increased 28% in 2004 as compared to 2003 due to a combination of higher operating costs, and to a lesser extent, higher production taxes.  The increase in production taxes was primarily attributable to the effects of higher oil and gas prices.  The increase in operating costs was due largely to the added expense related to properties acquired in connection with the SWR merger.  The combined effects of higher production costs and an 18% decline in production levels resulted in a 55% increase in production costs per Mcfe.  It is likely that higher production taxes resulting from higher product prices, combined with operating costs attributable to the SWR properties, will continue to contribute to higher production costs in future periods.

DD&A expense in 2004 decreased 6% as compared to 2003 due primarily to an 18% decline in oil and gas production on an Mcfe basis, offset in part by a 10% increase in our DD&A rate per Mcfe.  The DD&A rate increased due to a combination of higher finding costs, offset in part by the effects of higher commodity prices on reserve estimates.  We currently estimate that our DD&A expense per Mcfe produced for the fourth quarter of 2004 could be between 15% and 25% higher than the same period in 2003.

G&A expenses, excluding non-cash stock-based employee compensation, increased 27% in 2004 as compared to 2003 due primarily to higher personnel costs, professional fees and insurance costs, including the acquisition of SWR in May 2004.  G&A expenses for 2004 include a non-cash credit (reduction of

24

expense) of $303,000 for stock-based employee compensation required by Financial Accounting Standards Board Interpretation No. 44.  A $380,000 charge was required for the 2003 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.

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 2004, we charged to expense $34.4 million of exploration costs, as compared to $22.8 million in 2003.  Most of these costs were incurred in south Louisiana.

We plan to spend approximately $111.7 million on exploration and development activities in 2004 primarily in the same core exploration areas as in 2003.  Since exploratory drilling involves a high degree of risk, it is likely that a significant portion of the remaining costs in 2004 will be charged to exploration costs in 2004.  However, we cannot predict our success rates and, accordingly, cannot predict our exploration costs related to abandonment and impairment costs.

Interest Expense and Other

Interest expense increased 85% from 2003 due primarily to higher average levels of indebtedness under the credit facilities and higher effective interest rates.  The average daily principal balance outstanding under the credit facilities for 2004 was $130.3 million compared to $78.2 million in the 2003 period. The effective annual interest rate on bank debt, including bank fees and interest rate derivatives, during 2004 was 4.9% compared to 5.4% in 2003.

Other income/expense for 2004 included a $28 million loss associated with the change in fair value of derivative contracts as compared to a $1.2 million gain in 2003.  In both periods, we held commodity derivatives that were not designated as cash flow hedges under applicable accounting standards.  Changes in the fair value of these derivatives are based on the underlying commodity prices and resulted in a $29.2 million variance in other income/expense between the two periods.

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 secure a line of credit, called a revolving credit facility, with a group of banks.  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 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.

25

Capital Expenditures

Our total planned expenditures for exploration and development activities during 2004, excluding the SWR acquisition, are $111.7 million as summarized by area in the following table.

	Actual Expenditures Nine Months Ended September 30, 2004		Total Planned Expenditures Year Ended December 31, 2004		Percentage of Total
	(In thousands)
South Louisiana	$	55,100	$	63,200	57	%
Mississippi	13,300		19,400		17	%
New Mexico/West Texas	4,900		10,100		9	%
Cotton Valley Reef Complex	3,000		4,900		4	%
SWR – New Mexico/West Texas	4,400		9,800		9	%
Other	2,700		4,300		4	%
	$	83,400	$	111,700	100	%

Our actual expenditures during 2004 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 2004.  Most of the cash needed to finance these expenditures will be provided by operating activities.

Approximately 80% 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.

We are currently evaluating up to 200 gross (100 net) well locations on leasehold acreage obtained through the SWR acquisition that may be suitable for conducting lower-risk developmental drilling activities.  We believe that pursuing developmental activities at these locations will complement our efforts to obtain oil and gas reserves through higher-risk exploration activities.  We currently anticipate that our expenditures in 2005 will be more balanced between exploration and development activities.  We may also decide to selectively divest properties acquired through the SWR acquisition that are outside of our strategic focus.

Cash Flow Provided by Operating Activities

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

Cash flow provided by operating activities for the nine months ended September 30, 2004 was 16% lower than the same period in 2003.  The drivers that caused most of this variation are oil and gas production volumes, oil and gas prices, and costs of seismic data and interpretation.  Our primary source of cash from operating activities is our oil and gas sales, net of production costs.  For the reasons mentioned in

26

our previous discussion about changes in oil and gas sales and 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.  Seismic costs, which are costs incurred to generate, purchase, and interpret seismic data used to identify potential prospects for exploratory drilling, is considered to be part of our exploration and development activities. The timing and extent of seismic costs can vary significantly based on the level of our exploration activity which can vary depending on the prospects and opportunities available to us at the time.  Under the successful efforts method of accounting, seismic costs are required to be expensed as incurred, causing these costs to be reported as a reduction in cash flow provided by operating activities instead of an investing activity.  Accordingly, cash flow from operating activities is also subject to variation as seismic costs are incurred.

Credit Facilities

A group of banks have provided us with a revolving credit facility which we rely on 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.

In connection with the acquisition of SWR, we entered into new credit facilities with the banks that provided for an $85 million increase in borrowing capacity under the revolving credit facility and established a new $75 million senior term credit facility.  Immediately prior to the SWR acquisition, we had $40.7 million of availability under the revolving credit facility, after allowing for $4.3 million of outstanding letters of credit.  At September 30, 2004, our availability had decreased to $8.9 million.  This $31.8 million reduction in availability was the result of increased borrowings to partially finance the SWR acquisition and other capital expenditures.  Of the $180 million of funds needed to finance the purchase of SWR, $30 million was provided through a private placement of common stock, $50 million (net of repayments) was borrowed under the senior term credit facility, and $100 million was obtained from the revolving credit facility.  Giving effect to the $85 million increase in the borrowing base, this purchase transaction accounted for $15 million of the reduction in availability on the revolving credit facility.  The remaining $16.8 million of reduction in availability during the nine months ended September 30, 2004 resulted primarily from cash expenditures for property and equipment of $93.6 million, repayment of other long-term debt of $10.3 million, settlement of SWR derivatives of $4.6 million and debt issue costs of $4.2 million, net of cash flow provided by operating activities of $83.2 million and the use of cash on hand of $12.4 million.

Using the 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, when computing the working capital ratio at any balance sheet date.

Working capital computed for loan compliance purposes differs from our working capital in accordance with generally accepted accounting principles (GAAP).  Since compliance with financial covenants is a material requirement under the credit facilities, we consider the loan compliance working capital to be useful as a measure of our liquidity because it includes the funds available to us under the revolving credit facility and is not affected by the volatility in working capital caused by changes in fair

27

value of derivatives.  Our reported working capital deficit increased from $13.1 million at December 31, 2003 to $31 million at September 30, 2004 due primarily to an increase 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 $7 million at September 30, 2004, as compared to a positive $32.3 million at December 31, 2003.  The following table reconciles our GAAP working capital to the working capital computed for loan compliance purposes at September 30, 2004 and December 31, 2003.

	September 30, 2004			December 31, 2003
	(In thousands)
Working capital (deficit) per GAAP	$	(31,025	)	$	(13,119	)
Add funds available under the revolving credit facility	8,925			40,725
Exclude fair value of derivatives classified as current assets or current liabilities	23,935			2,233
Exclude current maturities of vendor finance obligations	5,146			2,453
Working capital per loan covenant	$	6,981		$	32,292

The acquisition of SWR significantly increased our indebtedness and decreased our liquidity.  Our long-term debt (including current maturities) increased from $55.7 million at December 31, 2003 to $222.9 million at September 30, 2004.  As a result, our long-term debt as a percentage of total capitalization (debt plus stockholders’ equity) increased from 36% to 63%.  This additional leverage is expected to increase our cost of capital initially by approximately 150 basis points due primarily to a higher rate of interest on the senior term credit facility and the amortization of debt issue costs incurred in connection with the new credit facilities.  This rate may increase in future periods since the $50 million senior term credit facility requires an increase of 50 basis points per quarter until the balance is reduced to $40 million or less through a capital markets transaction.

Since we rely on the credit facilities for both short-term liquidity and long-term financing needs, it is important that we comply in all material respects with the applicable loan agreements, including financial covenants that are computed quarterly.  The working capital covenant requires us to maintain positive working capital using the computations described above.  Other financial covenants under the credit facilities require us to maintain a ratio of indebtedness to cash flow, as each is determined in accordance with the applicable credit facility, of no more than 3 to 1, and a ratio of reserve value to indebtedness, as each is determined in accordance with the applicable credit facility, of at least 1.5 to 1.  While we were in compliance with all financial and non-financial covenants at September 30, 2004, our increased leverage and reduced liquidity may result in our failing to comply with one or more of these covenants in the future.  If we fail to meet any of these loan covenants, we would ask the banks to allow us sufficient time to obtain additional capital resources through alternative means.  If a suitable arrangement could not be reached with the banks, the banks could accelerate the indebtedness and seek to foreclose on the pledged assets.

The banks redetermine the borrowing base 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.

Alternative Capital Resources

Although our base of oil and gas reserves, as collateral for the revolving credit facility, 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 subordinated debt or preferred stock in a public or a private placement

28

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.

Contractual Obligations and Contingent Commitments

In connection with the acquisition of SWR, we entered into new credit facilities with the banks.  At September 30, 2004, based on the new terms, we are contractually obligated to repay indebtedness of $166.8 million on the revolving loan in 2007 and $50 million on the senior term loan in 2008.  In addition, we assumed approximately $8.4 million of asset retirement obligations in connection with the SWR acquisition, substantially all of which are expected to mature after 2008.

Item 3 - Quantitative and Qualitative Disclosure About Market Risks

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

Oil and Gas Prices

Our financial condition, results of operations, and capital resources are highly dependent upon the prevailing market prices of, and demand for, oil and natural gas.  These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond our control.  These factors include the level of global demand for petroleum products, foreign supply of oil and gas, the establishment of and compliance with production quotas by oil-exporting countries, weather conditions, the price and availability of alternative fuels, and overall economic conditions, both foreign and domestic.  We cannot predict future oil and gas prices with any degree of certainty.  Sustained weakness in oil and gas prices may adversely affect our financial condition and results of operations, and may also reduce the amount of net oil and gas reserves that we can produce economically.  Any reduction in reserves, including reductions due to price fluctuations, can reduce the borrowing base under the 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, 2003 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, 2004 by $10.3 million.

From time to time, we utilize commodity derivatives, consisting primarily of swaps, to attempt to optimize the price received for our oil and natural gas production.  When using swaps to hedge 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 the past we have also used collars which contain a fixed floor price (put) and ceiling price (call).  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, then 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.

Our hedging policy does not require us to hedge a specific percentage of our production unless required under a loan covenant.  We are currently required under the credit facilities to hedge at least 60% of our expected oil and gas production through 2005.  Otherwise, we decide to enter into and terminate hedges

29

based on management’s expectations of future market conditions in an effort to optimize the price we receive for our oil and gas production.  If we terminate a hedge because we anticipate an increase in product prices that we would not realize with the hedge in place, and product prices do not increase as anticipated, we may be exposed to downside risk that would not have existed otherwise.

The following summarizes information concerning the Company’s net positions in open commodity derivatives applicable to periods subsequent to September 30, 2004.

Swaps:

	Gas			Oil
	MMBtu (a)	Price		Bbls	Price
Production Period:
4th Quarter 2004	620,000	$	7.87	150,000	$	31.53
1st Quarter 2005	1,800,000	$	8.28	—
	2,420,000			150,000

Floors:

	Gas			Oil
	MMBtu (a)	Floor		Bbls	Floor
Production Period:	150,000
1st Quarter 2005	1,800,000	$	4.50	117,000	$	28.00
2nd Quarter 2005	1,820,000	$	4.50	118,300	$	28.00
3rd Quarter 2005	1,840,000	$	4.50	119,600	$	28.00
4th Quarter 2005	1,840,000	$	4.50	119,600	$	28.00
	7,300,000			474,500

Collars:

	Gas					Oil
	MMBtu (a)	Floor		Ceiling		Bbls	Floor		Ceiling
Production Period:
4th Quarter 2004	690,000	$	4.20	$	5.28	175,000	$	23.00	$	25.46
4th Quarter 2004	685,000	$	4.00	$	5.24
1st Quarter 2005	649,000	$	4.00	$	5.23	170,000	$	23.00	$	25.41
2nd Quarter 2005	630,000	$	4.00	$	5.23	168,000	$	23.00	$	25.41
3rd Quarter 2005	607,000	$	4.00	$	5.23	165,000	$	23.00	$	25.41
4th Quarter 2005	588,000	$	4.00	$	5.23	162,000	$	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
	8,983,000					2,407,000

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

Interest Rates

All of our outstanding bank indebtedness at September 30, 2004 is subject to market rates of interest as determined from time to time by the banks pursuant to the credit facilities.  We may designate borrowings under the credit facilities as either “Base Rate Loans” or “Eurodollar Loans.”  Base Rate Loans bear interest at a fluctuating rate that is linked to the discount rates established by the Federal Reserve Board.  Eurodollar Loans bear interest at a fluctuating rate that is linked to LIBOR.  Any increases in these interest rates can have an adverse impact on our results of operations and cash flow.  A 25 basis point change in our bank indebtedness at September 30, 2004 would affect our annual interest expense by approximately $550,000.

30

The following summarizes information concerning the Company’s positions in interest rate derivatives applicable to periods subsequent to September 30, 2004.

	Principal Balance		Libor Rates
Period:
October 1, 2004 to November 1, 2004	$	65,000,000	1.68	%
November 1, 2004 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	%

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, 2004 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

31

PART II.  OTHER INFORMATION

Item 6 -Exhibits and Reports on Form 8-K

Exhibits
2.1	**	Agreement and Plan of Merger among Clayton Williams Energy, Inc., CWEI-SWR, Inc. and Southwest Royalties, Inc., dated May 3, 2004, filed as Exhibit 2.1 to our Current Report on Form 8-K filed June 3, 2004
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
10.1	**	Stock Purchase Agreement dated May 19, 2004 by and among the Company and various institutional investors, filed as Exhibit 4 to our Current Report on Form 8-K filed June 2, 2004
10.2	**	Amended and Restated Credit Agreement dated as of May 21, 2004 among Clayton Williams Energy, Inc., et al, and Bank One, NA, et al, filed as Exhibit 10.1 to our Current Report on Form 8-K/A filed on June 23, 2004
10.3	**	Senior Term Credit Agreement dated as of May 21, 2004 among Clayton Williams Energy, Inc., et al, and Bank One, NA, et al, filed as Exhibit 10.2 to our Current Report on Form 8-K/A filed on June 23, 2004
10.4	**	Second Amendment to Consolidation Agreement dated May 19, 2004 among Clayton Williams Energy, Inc., Warrior Gas Co. and the Williams Entities
31.1	*	Certification of the Chief Executive Officer of Clayton Williams Energy, Inc.
31.2	*	Certification of the Chief Financial Officer of Clayton Williams Energy, Inc.
32.1	*	Certification by the President and Chief Executive Officer of Clayton Williams Energy, Inc. pursuant to 18 U.S.C. § 1350
32.2	*	Certification by the Chief Financial Officer of Clayton Williams Energy, Inc. pursuant to 18 U.S.C. § 1350
*		Filed herewith
**		Incorporated by reference to the filing indicated

32

Reports on Form 8-K

During the quarter ended September 30, 2004, the Company filed and furnished the following reports on Form 8-K:

•Form 8-K filed August 9, 2004 pursuant to Items 7 and 12 filing as an exhibit a news release reporting the financial results of the Company for the quarter ended June 30, 2004.

•Form 8-K filed August 19, 2004 to provide public disclosure of certain financial and operating estimates in order to permit the preparation of models to forecast the Company’s operating results for each quarter during the Company’s fiscal year ending December 31, 2004.

33

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 4, 2004	By:	/s/ L. Paul Latham
			L. Paul Latham
			Executive Vice President and Chief Operating Officer
Date:	November 4, 2004	By:	/s/ Mel G. Riggs
			Mel G. Riggs
			Senior Vice President and Chief Financial Officer

34