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 March 31, 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 9,376,382 shares of Common Stock, $.10 par value, of the registrant outstanding as of May 5, 2004.

CLAYTON WILLIAMS ENERGY, INC.

TABLE OF CONTENTS

PART I. FINANCIAL INFORMATION

Item 1.	Financial Statements

	Consolidated Balance Sheets as of March 31, 2004 and December 31, 2003

	Consolidated Statements of Operations for the three months ended March 31, 2004 and 2003

	Consolidated Statement of Stockholders’ Equity for the three months ended March 31, 2004

	Consolidated Statements of Cash Flows for the three months ended March 31, 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

CLAYTON WILLIAMS ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

	March 31, 2004			December 31, 2003
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	7,995		$	15,454
Accounts receivable:
Oil and gas sales, net	15,409			16,725
Joint interest and other, net	2,748			2,972
Affiliates	380			453
Inventory	1,440			787
Deferred income taxes	1,514			1,241
Prepaids and other	1,675			1,518
	31,161			39,150
PROPERTY AND EQUIPMENT
Oil and gas properties, successful efforts method	680,841			656,531
Natural gas gathering and processing systems	16,838			16,829
Other	12,420			12,300
	710,099			685,660
Less accumulated depreciation, depletion and amortization	(512,623		)	(504,101		)
Property and equipment, net	197,476			181,559
OTHER ASSETS
Investments and other	3,604			3,724
	$	232,241		$	224,433

LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts payable:
Trade	$	31,774		$	33,523
Oil and gas sales	9,018			10,086
Affiliates	1,057			1,254
Current maturities of long-term debt	4,171			2,453
Fair value of derivatives	5,177			2,233
Accrued liabilities and other	2,760			2,720
	53,957			52,269
NON-CURRENT LIABILITIES
Long-term debt	51,406			53,295
Deferred income taxes	11,288			8,504
Other	9,821			9,584
	72,515			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 – 9,373,700 shares in 2004 and 9,368,322 shares in 2003	937			937
Additional paid-in capital	74,147			73,972
Retained earnings	30,685			25,872
	105,769			100,781
	$	232,241		$	224,433

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

CLAYTON WILLIAMS ENERGY, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share)

	Three Months Ended March 31,
	2004			2003
REVENUES
Oil and gas sales	$	36,332		$	48,697
Natural gas services	2,527			2,048
Total revenues	38,859			50,745

COSTS AND EXPENSES
Lease operations	6,955			7,571
Exploration:
Abandonments and impairments	4,632			4,462
Seismic and other	1,925			2,352
Natural gas services	2,352			1,940
Depreciation, depletion and amortization	8,524			10,571
Accretion of abandonment obligations	175			151
General and administrative	3,301			1,740
Total costs and expenses	27,864			28,787
Operating income	10,995			21,958
OTHER INCOME (EXPENSE)
Interest expense	(460		)	(992		)
Gain (loss) on sales of property and equipment	5			(9		)
Change in fair value of derivatives	(3,093		)	3,449
Other	(124		)	275
Total other income (expense)	(3,672		)	2,723
Income before income taxes	7,323			24,681
Income tax expense	2,510			8,560
Income before extraordinary items	4,813			16,121
Cumulative effect of accounting change, net of tax	—			207
NET INCOME	$	4,813		$	16,328
Net income per common share:
Basic:
Income before extraordinary items	$	0.51		$	1.73
Net income	$	0.51		$	1.76

Diluted:
Income before extraordinary items	$	0.50		$	1.71
Net income	$	0.50		$	1.73

Weighted average common shares outstanding:
Basic	9,371			9,303
Diluted	9,720			9,433

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

CLAYTON WILLIAMS ENERGY, INC.

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY

(Unaudited)

(In thousands)

	Common Stock			Additional Paid-In Capital		Retained Earnings
	No. of Shares	Par Value		Additional Paid-In Capital		Retained Earnings
BALANCE,
December 31, 2003	9,368	$	937	$	73,972	$	25,872
Net income and total comprehensive income	—	—		—		4,813
Issuance of stock through compensation plans	6	—		175		—
BALANCE,
March 31, 2004	9,374	$	937	$	74,147	$	30,685

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

CLAYTON WILLIAMS ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In thousands)

	Three Months Ended March 31,
	2004			2003
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	4,813		$	16,328
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation, depletion and amortization	8,524			10,571
Exploration costs	4,632			4,462
(Gain) loss on sales of property and equipment	(5		)	9
Deferred income taxes	2,510			8,560
Non-cash employee compensation	752			44
Change in fair value of derivatives	2,945			(3,863		)
Accretion of abandonment obligations	175			151
Cumulative effect of accounting change, net of tax	—			(207		)
Changes in operating working capital:
Accounts receivable	1,613			(11,435		)
Accounts payable	(3,544		)	6,691
Other	(771		)	(1,724		)
Net cash provided by operating activities	21,644			29,587

CASH FLOWS FROM INVESTING ACTIVITIES
Additions to property and equipment	(28,604		)	(19,146		)
Proceeds from sales of property and equipment	5			3
Other	137			(193		)
Net cash used in investing activities	(28,462		)	(19,336		)

CASH FLOWS FROM FINANCING ACTIVITIES
Repayments of long-term debt	(641		)	(1,656		)
Proceeds from sale of common stock	—			104
Net cash used in financing activities	(641		)	(1,552		)

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	(7,459		)	8,699

CASH AND CASH EQUIVALENTS
Beginning of period	15,454			5,676
End of period	$	7,995		$	14,375

SUPPLEMENTAL DISCLOSURE
Cash paid for interest, net of amounts capitalized	$	421		$	534

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

CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2004

(Unaudited)

1. Nature of Operations

Clayton Williams Energy, Inc. (a Delaware corporation) and its subsidiaries (collectively, the “Company”) 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 50% of the Company’s 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 period. Actual results could differ materially from those estimates.

In the opinion of management, the Company’s unaudited consolidated financial statements as of March 31, 2004 and for the interim periods ended March 31, 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 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 quarter ended March 31, 2004 had no impact on the Company’s consolidated financial statements.

In its recent review of registrants’ filings, the staff of the SEC has questioned the applicability of SFAS No. 142 “Goodwill and Other Intangible Assets” (“SFAS 142”) to lease agreements and drilling rights commonly utilized in the oil and gas industry. If applicable, SFAS 142 could require oil and gas companies to separately report on their balance sheets the costs of proved and unproved leasehold and mineral interests acquired after June 30, 2001, including related accumulated depletion, as intangible assets and provide related intangible asset disclosures. Oil and gas companies have generally included leasehold costs in the property and equipment caption on the balance sheet since the value of the proved leases is inseparable from the value of the related oil and gas reserves, and since the costs of unproved leasehold and mineral interests are regularly evaluated for impairment based on lease terms and drilling activity. The Emerging Issues Task Force has recently added this issue to its agenda. If SFAS 142 is determined to apply to oil and gas companies, we may be required to make certain reclassifications within property and equipment on the balance sheet, and additional disclosures may be required.

If it is ultimately determined that SFAS 142 requires the Company to reclassify costs associated with mineral rights from property and equipment to intangible assets, the amounts that would be reclassified are as follows, assuming all mineral rights are reclassified:

	March 31, 2004			December 31, 2003
	(In thousands)
INTANGIBLE ASSETS:
Proved leasehold acquisition costs	$	69,382		$	68,496
Unproved leasehold acquisition costs	20,757			18,466
Total leasehold acquisition costs	90,139			86,962
Less: Accumulated depletion	(43,390		)	(42,249		)
Net leasehold acquisition costs	$	46,749		$	44,713

The Company does not believe the reclassification of these amounts would affect the method in which such costs are amortized or the manner in which the Company assesses impairment of capitalized costs. As a result, net income would not be affected by the reclassification.

4. Long-Term Debt

Long-term debt consists of the following:

	March 31, 2004		December 31, 2003
	(In thousands)
Secured Bank Credit Facility (matures December 31, 2005)	$	50,000	$	50,000
Vendor finance obligations	5,577		5,748
	55,577		55,748
Less current maturities of vendor finance obligations	4,171		2,453
	$	51,406	$	53,295

Secured Bank Credit Facility

The Company’s secured bank credit facility provides for a revolving loan facility in an amount not to exceed the lesser of the borrowing base, as established by the banks, or that portion of the borrowing base determined by the Company to be the elected borrowing limit. The borrowing base, which is based on the discounted present value of future net revenues from oil and gas production, is subject to

redetermination at any time, but at least semi-annually in May and November, and is made at the discretion of the banks. If, at any time, the redetermined borrowing base is less than the amount of outstanding indebtedness, the Company will be required to (i) pledge additional collateral, (ii) prepay the excess in not more than five equal monthly installments, or (iii) elect to convert the entire amount of outstanding indebtedness to a term obligation based on amortization formulas set forth in the loan agreement. Substantially all of the Company’s oil and gas properties are pledged to secure advances under the credit facility.

At March 31, 2004, the borrowing base established by the banks was $95 million, with no monthly commitment reductions. After allowing for outstanding letters of credit totaling $4.3 million, the Company had $40.7 million available under the credit facility at March 31, 2004.

All outstanding balances on the credit facility may be designated, at the Company’s option, as either “Base Rate Loans” or “Eurodollar Loans” (as defined in the loan agreement), provided that not more than two Eurodollar traunches may be outstanding at any time. Base Rate Loans bear interest at the fluctuating Base Rate plus a Base Rate Margin ranging from 0% to 0.5% per annum, depending on levels of outstanding advances and letters of credit. Eurodollar Loans bear interest at the LIBOR rate plus a Eurodollar Margin ranging from 1.25% to 2.25%. At March 31, 2004, the Company’s indebtedness under the credit facility consisted of $50 million of Eurodollar Loans at a rate of 3%. The effective annual interest rate on the credit facility, including bank fees, for the three months ended March 31, 2004 was 3.8%.

In addition, the Company pays the banks a commitment fee ranging from .25% to .38% per annum on the unused portion of the revolving loan commitment. Interest on the revolving loan and commitment fees are payable quarterly, and all outstanding principal and interest will be due December 31, 2005.

The loan agreement contains financial covenants that are computed quarterly and prohibit a ratio of current assets to current liabilities less than 1 to 1 and a ratio of debt to cash flow greater than 2.75 to 1. For purposes of these computations, current assets and current liabilities are adjusted, as appropriate, to include funds available under the credit facility, and to exclude fair value of derivatives and current maturities of vendor finance obligations. The Company was in compliance with all of the financial and non-financial covenants at March 31, 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.

5. Other Non-Current Liabilities

Other non-current liabilities consist of the following:

	March 31, 2004		December 31, 2003
	(In thousands)
Abandonment obligations	$	9,054	$	8,849
Production payment	767		735
	$	9,821	$	9,584

Abandonment Obligations

Abandonment obligations as of March 31, 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 quarter ended March 31, 2004 consist primarily of $175,000 of accretion expense.

Production Payment

Also in connection with the Romere Pass acquisition, 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.

6. 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 three months ended March 31, 2004, the Company issued 3,362 shares of common stock to Mr. Williams in lieu of net cash compensation aggregating $112,000, which is included in general and administrative expenses in the accompanying consolidated financial statements. Subsequent to March 31, 2004, the Company issued an additional 1,220 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. No options were granted during the quarter ended March 31, 2004.

The SFAS 123 pro forma information for the three months ended March 31, 2004 and 2003 is as follows:

	Three Months Ended March 31,
	2004		2003
	(In thousands, except per share)
Net income, as reported	$	4,813	$	16,328
Add: Stock-based employee compensation expense (credit) included in net income, net of tax	375		(45		)
Deduct: Stock-based employee compensation expense determined under fair value based method (SFAS 123), net of tax	—		(159		)
Net income, pro forma	$	5,188	$	16,124
Basic:
Net income per common share, as reported	$	.51	$	1.76
Net income per common share, pro forma	$	.55	$	1.73
Diluted:
Net income per common share, as reported	$	.50	$	1.73
Net income per common share, pro forma	$	.53	$	1.71

In accordance with Financial Accounting Standards Board Interpretation No. 44 (“FIN 44”) to APB 25, 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 Company’s closing market price at March 31, 2004 was $34.70. Accordingly, general and administrative expenses for the three months ended March 31, 2004 and 2003 included a non-cash charge of $577,000 and a non-cash credit of $69,000, 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

The Compensation Committee of the Board of Directors, in September 2002, 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.

7. Derivatives

Commodity Derivatives

From time to time, the Company utilizes commodity derivatives, consisting of swaps 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. 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.

The following summarizes information concerning the Company’s net positions in open commodity derivatives applicable to periods subsequent to March 31, 2004.

	Oil Swaps
	Bbls	Average Price
Production Period:
2nd Quarter 2004	150,000	$	31.53
3rd Quarter 2004	150,000	$	31.53
4th Quarter 2004	150,000	$	31.53
	450,000

	Gas Collars
	MMBtu (a)	Floor		Ceiling
Production Period:
2nd Quarter 2004	2,500,000	$	4.20	$	5.28
3rd Quarter 2004	2,220,000	$	4.20	$	5.28
4th Quarter 2004	690,000	$	4.20	$	5.28
	5,410,000

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

Interest Rate Derivatives

In November 2001, the Company entered into an interest rate swap on $50 million of its long-term bank debt designated as Eurodollar Loans (see Note 4). The swap provided for the Company to pay a fixed rate of 3.63% for the two-year term of the swap. The swap expired in November 2003.

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 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.

8. Financial Instruments

Cash and cash equivalents, receivables, accounts payable and accrued liabilities were each estimated to have a fair value approximating the carrying amount due to the short maturity of those instruments. Indebtedness under the 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 $6.2 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, consisting solely of commodity derivatives, are equal to their associated carrying values of a $5.2 million liability at March 31, 2004 and a $2.2 million liability at December 31, 2003.

9. 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 assets at March 31, 2004 and December 31, 2003 are as follows:

	March 31, 2004			December 31, 2003
	(In thousands)
Deferred tax assets:
Net operating loss carryforwards	$	7,265		$	6,915
Accrued stock-based compensation	537			335
Fair value of derivatives	1,814			783
Credits related to alternative minimum tax	343			343
Depletion carryforwards	53			—
Other	1,609			1,419
	11,621			9,795
Deferred tax liabilities:
Property and equipment	(21,395		)	(17,058		)
Net deferred tax assets (liabilities)	$	(9,774	)	$	(7,263	)

Components of net deferred tax assets (liabilities):
Current assets	$	1,514		$	1,241
Non-current liabilities	(11,288		)	(8,504		)
	$	(9,774	)	$	(7,263	)

For the three months ended March 31, 2004 and 2003, the Company’s effective income tax rates were different than the statutory federal income tax rates for the following reasons:

	Three Months Ended March 31,
	2004			2003
	(In thousands)
Income tax expense at statutory rate of 35%	$	2,563		$	8,641
Tax depletion in excess of basis	(53		)	(53		)
Revision of previous tax estimates	—			(28		)
Income tax expense	$	2,510		$	8,560

Current	$	—		$	291
Deferred	2,510			8,269
Income tax expense	$	2,510		$	8,560

The Company derives an income tax benefit when employees and directors exercise options granted under the Company’s stock compensation plans (see Note 6). 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.

At March 31, 2004, the Company’s cumulative tax loss carry forwards were approximately $20.8 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

March 31, 2004. A valuation allowance at March 31, 2003 of $876,000 was reversed during the quarter ended June 30, 2003.

10. Stock Repurchase Program

The Company’s Board of Directors has authorized a stock repurchase program that expires in July 2004. Under this program, the Company is authorized to spend up to $3 million to repurchase shares of its common stock on the open market at times and prices deemed appropriate by the Company’s management. To date, the Company has spent $1.4 million to repurchase and cancel 115,100 shares of common stock, none of which were repurchased in 2003 or 2004.

11. 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.

12. Potential Abandonment

The Company is continuing completion operations on the State Lease 17378 #1 (Fleur) in Plaquemines Parish, Louisiana, but results to date have been unsuccessful. The Company first attempted completion in one interval at a vertical depth of 19,550 feet and found the sand to be wet. A second interval at a vertical depth of 19,380 feet was also wet and has been abandoned. The Company is currently attempting completion in the third interval within the same geologic formation at a vertical depth of 18,230 feet. If this interval is not productive, the Company may abandon the lower formation and attempt completion in up to six intervals in a shallower formation between 13,170 feet and 15,900 feet. To date, the Company has incurred drilling and completion costs on this well totaling approximately $11 million, net to its interest. If the lower formation is abandoned, the Company will record a pre-tax charge to exploration expense of $8.5 million related to the unsuccessful drilling and completion activities in the lower formation, of which $6 million was incurred through March 31, 2004.

13. Subsequent Event

On May 3, 2004, the Company entered into a cash merger agreement to purchase the common stock of Southwest Royalties, Inc. (“SWR”), a privately owned energy company based in Midland, Texas. The stock purchase will include working capital and other assets and liabilities of SWR. The transaction is subject to approval by SWR shareholders and is expected to close on or before May 21, 2004. The amount of cash consideration to be paid by the Company at closing is estimated to be $187.8 million. The Company intends to finance the merger through a new financing package provided by Bank One NA.

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, oil prices have strengthened and gas prices have been relatively stable. 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 not found sufficient reserves to replace our production. We must reverse this trend in order to prevent further liquidation of our proved reserves. Our success rate improved this quarter with three of the four operated wells drilled in south Louisiana discovering commercially productive oil and gas reserves. However, the productive status of our Fleur prospect in south Louisiana remains uncertain as we continue to incur significant costs attempting to complete an interval below 18,000 feet.

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 first quarter of 2004 and the outlook for the remainder of 2004.

• On May 3, 2004, we entered into a cash merger agreement to purchase the common stock of Southwest Royalties, Inc. (see “Proposed Merger”).

• We are continuing completion operations on the State Lease 17378 #1 (Fleur) in Plaquemines Parish, Louisiana, but results to date have been unsuccessful. To date, we have incurred drilling and completion costs of approximately $11 million, net to our 75% working interest. If all or portions of the well are deemed unsuccessful, the applicable costs will be charged to exploration expense when abandoned.

• Although exploration costs related to abandonments and impairments totaled $4.6 million for the first quarter of 2004, most of these costs related to wells reported as dry holes in the fourth quarter of 2003. Of the four operated exploratory wells drilled in south Louisiana during the first quarter of 2004, one is currently producing and two have been evaluated as productive and are in the process of being completed.

• We currently plan to spend $73.5 million in 2004 on exploration and development activities, of which more than 90% relates to exploratory prospects. These planned activities are in areas where we had limited success in 2003 and 2002. Since past results are not necessarily indicative of future results, we cannot predict our drilling success in 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 on an Mcfe basis dropped 27% from the first quarter of 2003 to the first quarter of 2004. Gas production declined 39% from 2003 levels. Excluding any additional production from wells currently in progress or to be drilled, or from the proposed merger discussed below, we project that annual oil and gas production in 2004 will decline about 30% as compared to 2003. Absent a significant increase in product prices, lower production will cause our annual oil and gas sales and cash flow to be lower in 2004 than 2003.

Recent Exploration Activities

South Louisiana

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

Spud Date	Well Name (Prospect)	Working Interest		Current Status
September 2003	OCS – G – 21142 #4 (Nonoperated)	10	%	Completed
October 2003	State Lease 17378 #1 (Fleur)	75	%	Completing
December 2003	Allen Gautreaux #1 (King)	100	%	Productive
December 2003	OCS – G – 21142 #5 (Nonoperated)	10	%	Waiting on completion
February 2004	Louisiana Fruit Co. #1 (Tiger Pass)	100	%	Waiting on completion
February 2004	Mervine Jankower #1 (Helen Gayle)	100	%	In progress
March 2004	Louisiana Fruit Co. #2 (Tiger Pass)	100	%	Completing
March 2004	State Lease 17341 #1 (Brandi)	100	%	Dry
March 2004	State Lease 17057 #1 (Nonoperated)	13	%	In progress

We are continuing completion operations on the State Lease 17378 #1 (Fleur) in Plaquemines Parish, but results to date have been unsuccessful. We first attempted completion in one interval at a vertical depth of 19,550 feet and found the sand to be wet. A second interval at a vertical depth of 19,380 feet was also wet and has been abandoned. We are currently attempting completion in the third interval within the same geologic formation at a vertical depth of 18,230 feet. If this interval is not productive, we may abandon the lower formation and attempt completion in up to six intervals in a shallower formation between 13,170 feet and 15,900 feet. To date, we have incurred drilling and completion costs on this well totaling approximately $11 million, net to our interest. If the lower formation is abandoned, we will record a pre-tax charge to exploration expense of $8.5 million related to the unsuccessful drilling and completion activities in the lower formation, of which $6 million was incurred through March 31, 2004.

We have successfully completed the Allen Gautreaux #1 (King), an exploratory well in Acadia Parish. This well was completed in the Homeseeker E-3 sand at a vertical depth of 13,320 feet. We have logged, cored and run production casing on the Louisiana Fruit Co. #1 (Tiger Pass), an exploratory well in Plaquemines Parish, and plan to complete this well after we have completed the Louisiana Fruit Co. #2, an offset well drilled on the same prospect. Both wells are expected to be commercially productive. We also are currently drilling the Mervine Jankower #1 (Helen Gayle), a 13,600-foot exploratory well in Acadia Parish, at a vertical depth of 12,900 feet. The State Lease 17341 #1 (Brandi) in Plaquemines Parish was a dry hole.

Black Warrior Basin

In February 2004, we spudded the Weyerhaeuser #1, a 15,500-foot exploratory well in Webster County, Mississippi, and are currently drilling at a vertical depth of 11,500 feet. We expect to complete drilling operations on this well in the second quarter of 2004. We plan to spend approximately $7.9 million in the Black Warrior Basin in 2004, of which $2.8 million was incurred in the first quarter.

Proposed Merger

On May 3, 2004, we entered into a cash merger agreement to purchase the common stock of Southwest Royalties, Inc. (“SWR”), a privately owned energy company based in Midland, Texas. The stock purchase will include working capital and other assets and liabilities of SWR. The transaction is subject to approval by SWR shareholders and is expected to close on or before May 21, 2004. The amount of cash consideration we expect to pay at closing is estimated to be $187.8 million. We intend to finance the merger through a new financing package provided by Bank One NA. The effects of the proposed merger on our results of operations and our liquidity and capital resources have not been included in this Form 10-Q, but will be made available as soon as practicable through future filings with the SEC.

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 March 31,
	2004		2003
Oil and Gas Production Data:
Gas (MMcf)	4,177		6,896
Oil (MBbls)	375		373
Natural gas liquids (MBbls)	69		49
Total (MMcfe)	6,841		9,428

Average Realized Prices:
Gas ($/Mcf):
Before hedging losses	$	5.17	$	6.24
Hedging losses (1)	—		(.98		)
Net realized price	$	5.17	$	5.26
Oil ($/Bbl):
Before hedging losses	$	34.04	$	32.62
Hedging losses (1)	—		(3.59		)
Net realized price	$	34.04	$	29.03
Natural gas liquids ($/Bbl):	$	24.57	$	24.80

Average Daily Production:
Natural Gas (Mcf):
Austin Chalk (Trend)	3,669		4,210
Cotton Valley Reef Complex	28,119		51,400
Louisiana	10,739		17,488
New Mexico/West Texas	1,866		1,700
Other	1,508		1,824
Total	45,901		76,622
Oil (Bbls):
Austin Chalk (Trend)	2,393		2,817
Louisiana	738		621
New Mexico/West Texas	940		654
Other	50		52
Total	4,121		4,144
Natural Gas Liquids (Bbls):
Austin Chalk (Trend)	371		262
New Mexico/West Texas	186		136
Louisiana	201		146
Total	758		544

Exploration Costs (in thousands):
Abandonment and impairment costs:
South Louisiana	$	3,600	$	3,100
Cotton Valley Reef Complex	—		1,000
Nevada, Arizona, California and Utah	500		300
Other	500		100
Total	4,600		4,500
Seismic and other	1,900		2,300
Total exploration costs	$	6,500	$	6,800

Oil and Gas Costs ($/Mcfe Produced):
Lease operating expenses	$	1.02	$	.80
Oil and gas depletion	$	1.14	$	1.08
Net Wells Drilled (2):
Exploratory Wells		2.1		4.2
Developmental Wells		5.5		.1

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

Operating Results

The following discussion compares our results for the three months ended March 31, 2004 to the comparative period in 2003. Unless otherwise indicated, references to 2004 and 2003 within this section refer to the respective quarterly periods. Forward-looking statements related to future results of operations do not give effect to the proposed merger discussed elsewhere in this Item 2.

Oil and gas operating results

Oil and gas sales in 2004 were 25% lower than 2003 due mostly to lower gas production, offset in part by higher oil prices.

Gas production in 2004 fell 39% as compared to 2003, continuing its downward trend since reaching a peak during the second quarter of 2003. Oil production, on the other hand, increased slightly as a result of a limited developmental drilling program we began late in 2003 on existing acreage in New Mexico.

Overall, product prices continue to be strong. Our realized oil price in 2004 increased 17% from 2003, while our realized gas price decreased 2%. The 2003 realized prices include losses from hedging activities, but the 2004 amounts do not include hedging losses. This difference is because our hedging activity in 2003 was designated as cash flow hedges under SFAS 133, and therefore, the effective portion of any gains or losses on those derivatives were recorded as oil and gas sales. We did not designate our current derivatives as cash flow hedges. In this case, SFAS 133 requires that any gains or losses be reported as other income or loss, not as oil and gas sales. During 2004, we realized hedging losses on oil derivatives of $408,000.

Looking forward, in the absence of new production from our exploration program or from acquisitions of proved reserves, we currently estimate that our oil and gas production on an Mcfe basis will be approximately 30% lower for the year 2004 than for the year 2003. Annual oil production will trend downward although at a slightly slower rate due to the developmental drilling in New Mexico and water fracs in the Austin Chalk (Trend). Annual gas production will trend downward due primarily to declines in the Cotton Valley Reef Complex area and south Louisiana. We currently plan to spend approximately $73.5 million in 2004 to explore for new oil and gas production. Through these exploration efforts, we believe we can add sufficient volumes of new production to reduce this decline. If we do not offset the projected decline in production with new production from exploration activities or acquisitions of proved properties, annual oil and gas sales and cash flow in 2004 may be significantly lower than 2003.

Oil and gas production costs decreased 8% in 2004 as compared to 2003 due primarily to lower operating costs in the Romere Pass area of Louisiana. However, since a portion our oil and gas production

costs, such as labor, supervision, insurance and administration, are relatively fixed in nature and do not reduce significantly as production volumes decline, production costs on an Mcfe basis increased 28%. If production continues to decline, we estimate that production costs on an Mcfe basis for the year 2004 will be 20% to 40% higher than those costs reported for the year 2003.

Depreciation, depletion and amortization (“DD&A”) expense in 2004 decreased 20% as compared to 2003 due primarily to a 27% decline in oil and gas production on an Mcfe basis. DD&A expense per Mcfe produced increased 6% from 2003 to 2004. We currently estimate that our DD&A expense per Mcfe produced could be between 15% and 25% higher in 2004 than 2003.

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 $6.5 million of exploration costs, as compared to $6.8 million in 2003. Most of these costs were incurred in south Louisiana.

We plan to spend approximately $73.5 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 this 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.

Other

Other income/expense for the first quarter of 2004 included a $3.1 million loss associated with the change in fair value of derivative contracts as compared to a $3.4 million gain in the 2003 quarter. 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 $6.5 million variance in other income/expense between the two quarters.

At March 31, 2004, we have $20.8 million of federal tax loss carryforwards that begin to expire in 2008. As long as we are profitable in future periods, it is likely that we will be able to utilize these carryforwards before they expire. However, to the extent we incur any pre-tax losses in future periods, we do not currently intend to record a deferred tax benefit. Instead, we will record a valuation allowance against the increase in deferred tax assets caused by such losses.

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 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 Credit Facility as needed to supplement our operating cash flow as a financing source for our capital expenditure program. 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 our exploration program does not replace our oil and gas reserves, we may also suffer a reduction in our operating cash flow and access to funds under the 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 certain factors that can affect our liquidity and capital resources.

Capital Expenditures

Excluding the proposed merger, we presently plan to spend approximately $73.5 million on exploration and development activities during 2004, as summarized by area in the following table.

	Actual Expenditures Three Months Ended March 31, 2004		Total Planned Expenditures Year Ended December 31, 2004		Percentage of Total
	(In thousands)
South Louisiana	$	23,200	$	52,200	71	%
Cotton Valley Reef Complex	100		3,500		5	%
Mississippi	2,800		8,700		12	%
New Mexico	2,400		3,400		5	%
Austin Chalk (Trend)	300		2,500		3	%
Other	1,300		3,200		4	%
	$	30,100	$	73,500	100	%

Over 90% 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. You need to be aware that 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. We do not attempt to forecast our success rate on exploratory drilling. Accordingly, these current estimates do not include any costs we may incur to complete our 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. 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.

Credit Facility

We rely on the Credit Facility for both our short-term liquidity and our long-term financing needs. The funds available to us at any time under this Credit Facility are limited to the amount of the borrowing base established by the banks. As long as we have sufficient availability under the Credit Facility to meet our obligations as they come due, we have sufficient liquidity.

At the beginning of 2004, we had an outstanding balance under the Credit Facility of $50 million, and the borrowing base was $95 million (as amended), leaving $40.7 million of availability, after allowing for $4.3 million of outstanding letters of credit. During the three months ended March 31, 2004, we generated cash flow from operating activities of $21.6 million, spent $28.6 million on capital expenditures and repaid $600,000 on long-term debt. This activity contributed to a cash decrease of $7.5 million. The outstanding balance on the Credit Facility at March 31, 2004 remained at $50 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 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 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 Credit Facility requires us to (i) include the amount of funds available under the Credit 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.

Our reported working capital deficit at March 31, 2004 was $22.8 million, as compared to a deficit of $13.1 million at December 31, 2003. Giving effect to the above adjustments our working capital for loan compliance purposes is a positive $27.3 million at March 31, 2004, as compared to a positive $32.3 million at December 31, 2003. Although working capital computed for loan compliance purposes differs from our working capital in accordance with generally accepted accounting principles (GAAP), the loan compliance working capital is useful in measuring our liquidity since it includes the resources available to us under the Credit Facility and negates the volatility in working capital caused by changes in fair value of derivatives. The following table reconciles our GAAP working capital to the working capital computed under the loan covenant at March 31, 2004 and December 31, 2003.

	March 31, 2004			December 31, 2003
	(In thousands)
Working capital (deficit) per GAAP	$	(22,796	)	$	(13,119	)
Add funds available under the Credit Facility	40,725			40,725
Exclude fair value of derivatives classified as current assets or current liabilities	5,177			2,233
Exclude current maturities of vendor finance obligations	4,171			2,453
Working capital per loan covenant	$	27,277		$	32,292

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. The loan agreement contains financial covenants that are computed quarterly and requires us to maintain minimum levels of working capital and cash flow. We were in compliance with all of the financial and non-financial covenants at March 31, 2004.

Alternative Capital Resources

Although our base of oil and gas reserves, as collateral for the Credit Facility, has historically been our primary capital resource, we have in the past, and 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 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 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 $8.6 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.

We attempt to optimize the price we receive for our oil and gas production while maintaining a prudent hedging program to mitigate our exposure to declining product prices. This strategy means that within the framework of a comprehensive hedging program, we sometimes terminate a hedge when we believe that market factors indicate that there could be an increase in product prices that we would not realize with the hedge in place. While we attempt to make informed market decisions on the termination of hedges, this strategy may sometimes expose us 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 March 31, 2004.

	Oil Swaps
	Bbls	Average Price
Production Period:
2nd Quarter 2004	150,000	$	31.53
3rd Quarter 2004	150,000	$	31.53
4th Quarter 2004	150,000	$	31.53
	450,000

	Gas Collars
	MMBtu (a)	Floor		Ceiling
Production Period:
2nd Quarter 2004	2,500,000	$	4.20	$	5.28
3rd Quarter 2004	2,220,000	$	4.20	$	5.28
4th Quarter 2004	690,000	$	4.20	$	5.28
	5,410,000

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

Interest Rates

All of our outstanding bank indebtedness at March 31, 2004 is subject to market rates of interest as determined from time to time by the banks pursuant to the Credit Facility. We may designate borrowings under the Credit Facility 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. We do not have any interest rate derivatives in place at the present time.

Item 4 - Controls and Procedures

Disclosure Controls and Procedures

In September 2002, our Board of Directors adopted a policy designed to establish disclosure controls and procedures that are adequate to provide reasonable assurance that 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 March 31, 2004 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

Item 6 - Exhibits and Reports on Form 8-K

Exhibits

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.

Reports on Form 8-K

During the quarter ended March 31, 2004, the Company filed the following reports on Form 8-K:

• Form 8-K dated February 12, 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.

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: May 5, 2004	By:	/s/ L. Paul Latham
		L. Paul Latham
		Executive Vice President and Chief Operating Officer


Date: May 5, 2004	By:	/s/ Mel G. Riggs
		Mel G. Riggs
		Senior Vice President and Chief Financial Officer

WASHINGTON, D.C. 20549

FORM 10-Q

For the quarterly period ended March 31, 2004

PART II. OTHER INFORMATION

CONSOLIDATED BALANCE SHEETS

Commodity Derivatives

Disclosure Controls and Procedures

Changes in Internal Control Over Financial Reporting

PART II. OTHER INFORMATION

Exhibits