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 June 30, 2003

or

		o Transition Report Purs uant 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 o No ý

There were 9,326,350 shares of Common Stock, $.10 par value, of the registrant outstanding as of August 11, 2003.

CLAYTON WILLIAMS ENERGY, INC.

TABLE OF CONTENTS

PART I. FINANCIAL INFORMATION

Item 1.		Financial Statements

		Consolidated Balance Sheets as of June 30, 2003 and December 31, 2002

		Consolidated Statements of Operations for the three months and six months ended June 30, 2003 and 2002

		Consolidated Statement of Stockholders’ Equity for the six months ended June 30, 2003

		Consolidated Statements of Cash Flows for the six months ended June 30, 2003 and 2002

		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 1.		Legal Proceedings

Item 6.		Exhibits and Reports on Form 8-K

		Signatures

CLAYTON WILLIAMS ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

	June 30, 2003			December 31, 2002
	(Unaudited)
ASSETS

CURRENT ASSETS
Cash and cash equivalents	$	15,718		$	5,676
Accounts receivable:
Oil and gas sales, net	19,990			14,426
Joint interest and other, net	2,581			3,714
Affiliates	317			223
Inventory	1,412			2,141
Deferred income taxes	720			524
Prepaids and other	6,484			5,215
	47,222			31,919

PROPERTY AND EQUIPMENT
Oil and gas properties, successful efforts method	638,469			617,320
Natural gas gathering and processing systems	16,572			16,203
Other	12,147			11,918
	667,188			645,441
Less accumulated depreciation, depletion and amortization	(484,877		)	(466,815		)
Property and equipment, net	182,311			178,626

OTHER ASSETS
Deferred income taxes	—			6,594
Investments and other	2,211			1,853
	2,211			8,447

	$	231,744		$	218,992

LIABILITIES AND STOCKHOLDERS’ EQUITY

CURRENT LIABILITIES
Accounts payable:
Trade	$	21,593		$	22,440
Oil and gas sales	12,922			8,274
Affiliates	1,529			1,257
Current maturities of long-term debt	1,308			—
Fair value of derivatives	8,133			12,917
Accrued liabilities and other	2,249			5,874
	47,734			50,762

NON-CURRENT LIABILITIES
Long-term debt	74,196			94,949
Deferred income taxes	5,336			—
Other	9,647			4,500
	89,179			99,449

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 – 9,323,128 shares in 2003 and 9,277,415 shares in 2002	932			928
Additional paid-in capital	73,231			72,787
Retained earnings	25,655			3,016
Accumulated other comprehensive loss	(4,987		)	(7,950		)
	94,831			68,781

	$	231,744		$	218,992

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

CLAYTON WILLIAMS ENERGY, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(In thousands, except per share)

	Three Months Ended June 30,						Six Months Ended June 30,
	2003			2002			2003			2002
REVENUES
Oil and gas sales	$	43,049		$	18,797		$	91,746		$	37,415
Natural gas services	2,254			1,418			4,302			2,617
Total revenues	45,303			20,215			96,048			40,032

COSTS AND EXPENSES
Lease operations	6,679			4,850			14,250			10,020
Exploration:
Abandonments and impairments	8,932			2,514			13,394			8,743
Seismic and other	1,612			1,902			3,964			3,610
Natural gas services	2,049			1,181			3,989			2,175
Depreciation, depletion and amortization	10,653			6,747			21,224			13,826
Accretion of abandonment obligations	155			—			306			—
General and administrative	3,190			1,948			4,930			3,823
Total costs and expenses	33,270			19,142			62,057			42,197

Operating income (loss)	12,033			1,073			33,991			(2,165		)

OTHER INCOME (EXPENSE)
Interest expense	(861		)	(891		)	(1,853		)	(1,852		)
Gain on sales of property and equipment	222			60			213			69
Change in fair value of derivatives	(2,707		)	52			742			(660		)
Other	(392		)	1,584			(117		)	1,705
Total other income (expense)	(3,738		)	805			(1,015		)	(738		)

Income (loss) before income taxes	8,295			1,878			32,976			(2,903		)
Income tax expense (benefit)	1,984			611			10,544			(1,098		)
Income (loss) from continuing operations	6,311			1,267			22,432			(1,805		)
Cumulative effect of accounting change, net of tax	—			—			207			—
Income from discontinued operations, net of tax	—			81			—			139
NET INCOME (LOSS)	$	6,311		$	1,348		$	22,639		$	(1,666	)

Net income (loss) per common share:
Basic:
Income (loss) from continuing operations	$	.68		$	0.14		$	2.41		$	(0.20	)
Net income (loss)	$	.68		$	0.15		$	2.43		$	(0.18	)

Diluted:
Income (loss) from continuing operations	$	.67		$	0.14		$	2.38		$	(0.20	)
Net income (loss)	$	.67		$	0.14		$	2.40		$	(0.18	)

Weighted average common shares outstanding:
Basic	9,319			9,236			9,311			9,219
Diluted	9,447			9,375			9,445			9,219

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		Accumulated Other Compre - hensive Income (Loss)			Total Compre - hensive Income
	No. of Shares	Par Value		Additional Paid-In Capital		Retained Earnings		Accumulated Other Compre - hensive Income (Loss)			Total Compre - hensive Income

BALANCE,
December 31, 2002	9,277	$	928	$	72,787	$	3,016	$	(7,950	)
Net income	—	—		—		22,639		—			$	22,639
Change in fair value of derivatives designated as cash flow hedges, net of tax	—	—		—		—		2,963			2,963
Total comprehensive income											$	25,602
Issuance of stock through compensation plans	46	4		444		—		—
BALANCE,
June 30, 2003	9,323	$	932	$	73,231	$	25,655	$	(4,987	)

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

CLAYTON WILLIAMS ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In thousands)

	Six Months Ended June 30,
	2003			2002
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	22,639		$	(1,666	)
Adjustments to reconcile net income (loss) to cash provided by operating activities:
Depreciation, depletion and amortization	21,224			13,826
Exploration costs	13,394			8,743
Gain or loss on sales of property and equipment	(213		)	(69		)
Deferred income taxes	10,544			(1,098		)
Non-cash employee compensation	347			(69		)
Change in fair value of derivatives	(225		)	403
Accretion of abandonment obligations	306			—
Cumulative effect of accounting change, net of tax	(207		)	—
Non-cash effect of discontinued operations, net of tax	—			167
Other	231			623

Changes in operating working capital:
Accounts receivable	(4,525		)	(1,680		)
Accounts payable	10,005			(3,126		)
Other	(3,841		)	(1,417		)
Net cash provided by operating activities	69,679			14,637

CASH FLOWS FROM INVESTING ACTIVITIES
Additions to property and equipment	(36,237		)	(33,967		)
Proceeds from sales of property and equipment	249			4,125
Other	(312		)	(69		)
Net cash used in investing activities	(36,300		)	(29,911		)

CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt	—			22,000
Repayments of long-term debt	(23,441		)	—
Proceeds from sale of common stock	104			—
Repurchase and cancellation of common stock	—			(648		)
Net cash provided by (used in) financing activities	(23,337		)	21,352

NET INCREASE IN CASH AND CASH EQUIVALENTS	10,042			6,078

CASH AND CASH EQUIVALENTS
Beginning of period	5,676			2,856

End of period	$	15,718		$	8,934

SUPPLEMENTAL DISCLOSURES
Cash paid for interest, net of amounts capitalized	$	1,490		$	1,850

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

CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2003

(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 June 30, 2003 and for the interim periods ended June 30, 2003 and 2002 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, 2003.

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. These consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto included in the Company’s 2002 Form 10-K.

3. Accounting Pronouncements

Effective January 1, 2003 the Company adopted Statement of Financial Accounting Standards No. 143 “Accounting for Asset Retirement Obligations” (“SFAS 143”). SFAS 143 requires the Company to recognize a liability for the present value of all legal obligations associated with the retirement of tangible, long-lived assets and capitalize an equal amount as a cost of the asset. The cost of the abandonment obligation, along with any estimated salvage value, is included in the computation of depreciation, depletion and amortization. Upon adoption of SFAS 143 on January 1, 2003, the Company increased asset costs by $1.5 million, reduced accumulated depreciation, depletion and amortization by $2.9 million, increased abandonment obligations by $4.1 million and recorded an after-tax credit of $207,000 for the cumulative effect of adoption on prior years. Changes in abandonment obligations from January 1, 2003 to June 30, 2003 consist primarily of $700,000 in revisions to previous estimates and

$306,000 of accretion expense. Pro forma adjustments to income from continuing operations for the three month and six month periods ended June 30, 2003 and 2002, assuming SFAS 143 had been applied in each period, were insignificant.

4. Long-Term Debt

Long-term debt consists of the following:

	June 30, 2003		December 31, 2002
	(In thousands)
Secured Bank Credit Facility (matures December 31, 2004)	$	70,000	$	93,000
Vendor finance obligations	5,504		1,949
	75,504		94,949
Less current maturities of vendor finance obligations	1,308		—
	$	74,196	$	94,949

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 June 30, 2003, the borrowing base established by the banks was $110 million, with no monthly commitment reductions. After allowing for outstanding letters of credit totaling $4.3 million, the Company had $35.7 million available under the credit facility at June 30, 2003.

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 June 30, 2003, the Company’s indebtedness under the credit facility consisted of $70 million of Eurodollar Loans at a rate of 3.1%. The effective annual interest rate on the credit facility, including bank fees and interest rate derivatives, for the six months ended June 30, 2003 was 5.2%.

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, 2004.

The loan agreement contains financial covenants that are computed quarterly and require the Company to maintain minimum levels of working capital and cash flow. The Company was in compliance with all of the financial and non-financial covenants at June 30, 2003.

Vendor Finance Obligations

In August 2002, 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:

	June 30, 2003		December 31, 2002
	(In thousands)

Abandonment obligations	$	8,647	$	3,500
Production payment	1,000		1,000
	$	9,647	$	4,500

Abandonment Obligations

Abandonment obligations as of June 30, 2003 represent the present value of the Company’s estimated abandonment obligations under SFAS 143 (see Note 3). As of December 31, 2002, the amounts represent future abandonment obligations applicable to wells acquired in the Romere Pass acquisition discussed in Note 11. The Company has been required to issue letters of credit aggregating $4.25 million to secure the Romere Pass obligation, $3.5 million to a prior owner of the acquired assets and $750,000 to a federal agency.

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 six months ended June 30, 2003, the Company issued 8,482 shares of common stock to Mr. Williams in lieu of net cash compensation aggregating $113,000, which is included in general and administrative expenses in the accompanying consolidated financial statements. Subsequent to June 30, 2003, the Company issued an additional 836 shares to Mr. Williams in lieu of cash compensation aggregating $19,000.

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 2003 and 2002.

The SFAS 123 pro forma information for the six months ended June 30, 2003 and 2002 is as follows:

	Six Months Ended June 30,
	2003			2002

Net income (loss), as reported	$	22,639		$	(1,666	)
Add: Stock-based employee compensation expense (credit) included in net income (loss), net of tax	225			(45		)
Deduct: Stock-based employee compensation expense determined under fair value based method (SFAS 123), net of tax	(318		)	(442		)
Net income (loss), pro forma	$	22,546		$	(2,153	)

Basic:
Net income (loss) per common share, as reported	$	2.43		$	(.18	)
Net income (loss) per common share, pro forma	$	2.42		$	(.23	)

Diluted:
Net income (loss) per common share, as reported	$	2.40		$	(.18	)
Net income (loss) per common share, pro forma	$	2.39		$	(.23	)

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 June 30, 2003 was $18.46. Accordingly, general and administrative expenses for the six months ended June 30, 2003 and 2002 included a non-cash charge of $347,000 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.

Working Interest Trusts

During April 2003, the working interest trust covering certain wells in the Cotton Valley Reef Complex and the Austin Chalk (Trend) paid out. The trust is being dissolved, and the applicable working interests are being distributed to the participants, consisting of officers and key employees of the Company, excluding Mr. Williams.

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.

In October 2002, the Company formed three limited partnerships pursuant to this plan and committed to contribute to the partnerships 5% of its working interests in all applicable wells. Applicable wells will include (i) wells purchased in the Romere Pass acquisition (see Note 11), (ii) a Robertson County, Texas well which was in progress of being drilled at October 1, 2002, and (iii) wells drilled subsequent to October 1, 2002 in Louisiana and in Robertson, Burleson and Milam Counties, Texas. In May 2003, the Company formed an additional partnership and committed to contribute 5% of its working interests in wells to be drilled on certain acreage in Pecos County, Texas. 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 as of June 30, 2003.

	Oil Swaps			Gas Swaps
	*Bbls*	Average Price		*MMBtu (a)*	Average Price
Production Period:
3rd Quarter 2003	120,000	$	24.20	1,810,000	$	3.58
4th Quarter 2003	80,000	$	24.20	1,720,000	$	3.80
Year 2003 (b)	200,000	$	24.20	3,530,000	$	3.69

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

(b) Based on current estimates, these quantities represent approximately 30% of our oil and gas production for the remainder of 2003.

In July 2003, the Company entered into collar arrangements covering 551,000 MMBtu of its gas production from November 2003 through March 2004 with a floor of $4.50 and a ceiling of $7.04, and 541,000 MMBtu of its gas production from April 2004 through October 2004 with a floor of $4.20 and a ceiling of $5.28. These derivatives were designated as cash flow hedges.

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 provides for the Company to pay a fixed rate of 3.63% for the two-year term of the swap. The counterparty will pay a floating rate based on the LIBOR-BBA one-month rate. The swap requires a monthly cash settlement for the difference between the fixed rate and the floating rate.

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 following table sets forth, for the six months ended June 30, 2003, the components of accumulated other comprehensive income, as reported in stockholders’ equity, all of which is related to derivatives designated as cash flow hedges under SFAS 133.

	Accumulated Other Comprehensive Income (Loss)
	Commodity Derivatives			Interest Rate Derivatives			Total
	(In thousands)

Balance, December 31, 2002	$	(7,290	)	$	(660	)	$	(7,950	)

Change in fair value of derivatives, net of tax	(6,972		)	(51		)	(7,023		)
Reclassifications to earnings, net of tax	9,612			374			9,986

Net changes during the period	2,640			323			2,963

Balance, June 30, 2003	$	(4,650	)	$	(337	)	$	(4,987	)

In April 2003, the Company terminated certain fixed-price physical contracts for the sale of net gas production. These contracts were not designated as cash flow hedges and, in accordance with SFAS 133, were stated at their fair market value as of March 31, 2003, and the resulting gain of $3.9 million was recorded in other income for the quarter ended March 31, 2003. On termination of these contracts, the Company realized a pre-tax gain of $1.5 million and, accordingly, reported a pre-tax loss of $2.4 million on these contracts in the quarter ended June 30, 2003.

During the twelve months subsequent to June 30, 2003, the Company expects to reclassify the remaining balance of $5 million of net deferred losses associated with open cash flow hedges from accumulated other comprehensive income to earnings.

Margin Calls

The ISDA master agreement between the Company and one of its principal derivative counterparties gives either party the right to request credit support (a “Margin Call”) to the extent that the fair value of the derivatives exceeds specified credit limits. Currently, the Company’s credit limit under the master agreement is $5 million, subject to reduction or elimination if the Company’s net assets are less than $65 million or if the counterparty has reasonable grounds for insecurity. The counterparty has issued cumulative Margin Calls totaling $4 million. Funds paid to the counterparty for Margin Calls are held in interest-bearing trust accounts controlled by the counterparty and are included in other current assets in the accompanying consolidated balance sheet.

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 $6.7 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 as of June 30, 2003 and December 31, 2002 are set forth below. The associated carrying values of derivatives at June 30, 2003 and December 31, 2002 are equal to their estimated fair values.

	June 30, 2003			December 31, 2002
	(In thousands)
Assets (liabilities):
Commodity derivatives	$	(7,613	)	$	(11,902	)
Interest rate derivatives	(520		)	(1,015		)
Net liabilities	$	(8,133	)	$	(12,917	)

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 June 30, 2003 and December 31, 2002 are as follows:

	June 30, 2003			December 31, 2002
	(In thousands)
Deferred tax assets:
Net operating loss carryforwards	$	3,106		$	10,623
Accrued stock-based compensation	246			132
Fair value of derivatives	2,849			4,523
Credits related to alternative minimum tax	421			—
Other	986			1,105
	7,608			16,383
Deferred tax liabilities:
Property and equipment	(12,224		)	(8,389		)
Valuation allowance	—			(876		)
	(12,224		)	(9,265		)

Net deferred tax assets (liabilities)	$	(4,616	)	$	7,118

Components of net deferred tax assets (liabilities):
Current assets	$	720		$	524
Non-current assets (liabilities)	(5,336		)	6,594
	$	(4,616	)	$	7,118

The Company’s effective income tax rates for the six months ended June 30, 2003 and 2002 were different than the statutory federal income tax rate for the following reasons:

	Six Months Ended June 30,
	2003			2002
	(In thousands)

Income tax expense (benefit) at statutory rate of 35%	$	11,542		$	(1,016	)
Tax depletion in excess of basis	(105		)	(82		)
Revision of previous tax estimates	(29		)	—
Change in valuation allowance	(871		)	—
Other	7			—
Income tax expense (benefit)	$	10,544		$	(1,098	)

Current	$	422		$	—
Deferred	10,122			(1,098		)
Income tax expense (benefit)	$	10,544		$	(1,098	)

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 book income when the option price is equal to or greater than the market price at date of grant. Therefore, any tax benefit from the exercise of fixed stock options results in a permanent difference, which is recorded to additional paid-in capital when the tax benefit is realized.

During 2003, the Company’s pre-tax income was sufficient to cause deferred tax liabilities to exceed deferred tax assets. 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 presently believes that it is more likely than not that the Company will be able to utilize its cumulative tax loss carryforwards of $30.4 million before they expire (beginning in 2008). Accordingly, during the quarter ended June 30, 2003, the Company reversed $876,000 of the valuation allowances provided at December 31, 2002, $5,000 of which was related to permanent differences arising from the exercise of employee stock options.

10. Stock Repurchase Program

In July 2002, the Company’s Board of Directors authorized the continuation of a stock repurchase program initiated in July 2000. 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. This authorization expires in July 2004. To date, the Company has spent $1.4 million to repurchase and cancel 115,100 shares of common stock. No shares were repurchased during the six months ended June 30, 2003.

11. Purchases and Sales of Assets

In July 2002, the Company purchased all of the working interest in the Romere Pass Unit in the Plaquemines Parish, Louisiana for total consideration of $21.5 million, net of estimated closing adjustments. The effective date of the purchase for accounting purposes was August 1, 2002. The purchase price consisted of $17 million cash, the assumption of future abandonment obligations totaling $3.5 million, and the granting of an after-payout production payment in the amount of $1 million. The Company financed the acquisition through borrowings under its bank credit facility (see Note 4).

Also in July 2002, the Company sold its interests in certain wells in Wharton County, Texas, effective July 1, 2002, for $3.2 million and reported a net gain on the sale of approximately $1.9 million during the quarter ended September 30, 2002. Pursuant to the requirements of SFAS 144, the historical operating results from these properties have been reported as discontinued operations in the accompanying statements of operations. The following table summarizes certain historical operating information related to the discontinued operations:

	First Quarter 2002		Second Quarter 2002		Six Months Ended June 30, 2002
	(In thousands)

Revenues	$	165	$	148	$	363
Income before income taxes	$	90	$	124	$	214
Net income	$	58	$	81	$	139

12. Contingency

Legal Proceedings

The Company is a defendant in a personal injury suit filed in the 38th Judicial District Court in Cameron Parish, Louisiana in 2002. The plaintiff, an employee of one of the Company’s subcontractors, claims he was injured while working on a barge drilling rig owned and operated by another subcontractor, Parker Drilling Company (“PDC”). PDC was also named as a defendant in the suit. Robert L. Parker is the Chairman of the Board of Directors of PDC and is a member of our Board of Directors. The plaintiff has not yet specified the amount of damages sought, and no interrogatories or other discovery has been conducted. Currently, there are uncertainties concerning the extent of the Company’s insurance coverage. The Company’s insurance company is providing defense under a reservation of rights pending resolution of these uncertainties. The plaintiff’s employer is subject to the terms of an agreement with the Company in which it agrees to indemnify the Company from damages resulting from injuries to its employees. PDC is seeking indemnification from the Company for any damages resulting from the fault or negligence of PDC under the terms of the drilling contract. Due to these uncertainties, the Company is currently unable to determine its financial exposure, if any, in this matter. The Company has filed an answer denying liability and intends to vigorously defend this suit.

The Company is a defendant in a suit filed in the 82nd Judicial District Court in Robertson County, Texas in January 2003 by lessors of the lease on which its Lee Fazzino #1 and Lee Fazzino #2 wells were drilled. The plaintiffs allege that the Company formed the Lee Fazzino Unit #1, a 320-acre unit that pooled various leases, including the plaintiffs’ lease, in bad faith. The plaintiffs are seeking to have the unit declared to be null and void, with the effect being that the plaintiffs, and certain non-participating royalty owners claiming through the plaintiffs’ lease, are entitled to 100% of the royalties from both wells. If the plaintiffs are successful, the Company’s ability to collect all the royalties previously paid to the pooled royalty owners is uncertain, and the Company’s net interest in the wells will be reduced from 76.8% to 75%. The Company has estimated its maximum liability to the plaintiffs to be approximately $8 million to $9 million. However, the Company believes it is unlikely that the plaintiffs will prevail. The Company denies all claims and intends to vigorously defend this suit. Subsequent to discovery from the plaintiffs, the Company filed a counterclaim seeking damages for the filing of a frivolous lawsuit.

In addition, the Company is a defendant in several lawsuits that have arisen in the ordinary course of business. While the outcome of these lawsuits cannot be predicted with certainty, management does not expect any of these to have a material adverse effect on the Company’s consolidated financial condition or results of operations.

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

The following discussion is intended to help you understand the historical consolidated financial position of Clayton Williams Energy, Inc. (the “Company”, “CWEI”, “we”, “us”, or “our”) at June 30, 2003, and our results of operations and cash flows for each of the periods ended June 30, 2003 and 2002. Our historical consolidated financial statements and notes thereto included in this Form 10-Q contain detailed information that you should consider in conjunction with this discussion. You should read this discussion in connection with our Form 10-K for the year ended December 31, 2002 and the consolidated financial statements and notes included in this Form 10-Q.

Special Note Regarding Forward-Looking Statements

This Form 10-Q contains forward-looking statements that are based on our current expectations. Forward-looking statements include statements regarding our plans, beliefs or current expectations and may be signified by the words “could”, “should”, “expect”, “project”, “estimate”, “believe”, “anticipate”, “intend”, “budget”, “plan”, “forecast”, “predict” and other similar expressions. Forward-looking statements appear throughout this Form 10-Q with respect to, among other things: profitability; planned capital expenditures; estimates of oil and gas production; future project dates; estimates of future oil and gas prices; estimates of oil and gas reserves; our future financial condition or results of operations; and our business strategy and other plans and objectives for future operations. Actual results in future periods may differ materially from those expressed or implied by such forward-looking statements because of a number of risks and uncertainties affecting our business, including those discussed in “Item 1 – Business – Risk Factors” in our Form 10-K for the year ended December 31, 2002 and elsewhere in this report. We disclaim any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

Overview

In recent years, we have been aggressively seeking to transform CWEI from a development driller of horizontal wells in the Austin Chalk (Trend) to an exploration company committed to generating and drilling exploratory prospects, primarily through advanced seismic technology. Thus far in 2003, we have been concentrating our exploration efforts principally in the Miocene Trend in south Louisiana, the Cotton Valley Reef Complex area of east central Texas and the Deep Knox play in the Black Warrior Basin of Mississippi.

Since our inception, we have accounted for our oil and gas activities using the successful efforts method of accounting. Under this method, geological and geophysical (G&G) costs and exploratory dry hole costs are expensed as incurred. Companies that emphasize developmental drilling are usually not affected to a large degree by these costs, making the successful efforts method a preferred accounting method for those companies. The alternative to the successful efforts method is the full cost method of accounting. Companies that are heavily involved in exploration activities most often select this method so they can capitalize G&G costs and exploratory dry hole costs, and thereby reduce the level of volatility in their reported earnings.

As long as we remain heavily involved in exploration activities, the successful efforts method of accounting may contribute to the volatility in our reported earnings. Through discussions like this, we will attempt to explain how the application of this method affects our financial statements, and assist you in making your analysis of our performance as compared to our peers. Following, you will find a detailed discussion about our critical accounting policies and the estimates and assumptions we must use to follow the successful efforts method of accounting.

Application of Critical Accounting Policies

Summary

In this section, we will identify the critical accounting policies we follow in preparing our financial statements and disclosures. Many of these policies require us to make difficult, subjective and complex judgments in the course of making estimates of matters that are inherently imprecise. We will explain the nature of these estimates, assumptions and judgments, and the likelihood that materially different amounts would be reported in our financial statements under different conditions or using different assumptions.

The following table lists our critical accounting policies, the estimates and assumptions that can have a significant impact on the application of these accounting policies, and the financial statement accounts affected by these estimates and assumptions.

Accounting Policies	Estimates or Assumptions	Accounts Affected
Successful efforts accounting for oil and gas properties	• Reserve estimates	• Oil and gas properties
	• Valuation of unproved properties	• Accumulated DD&A*
	• Judgment regarding status of in-progress exploratory wells	• Provision for DD&A* • Impairment of unproved properties • Abandonment costs (dry hole costs)

Impairment of proved properties	• Reserve estimates and related present value of future net revenues	• Oil and gas properties properties • Accumulated DD&A* • Impairment of proved properties

Valuation allowance for net deferred tax assets	• Estimates related to utilizing net operating loss (NOL) carryforwards	• Deferred tax assets • Deferred tax liabilities • Deferred income taxes

* DD&A means depreciation, depletion and amortization.

Significant Estimates and Assumptions

Oil and gas reserves

Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact manner. The accuracy of a reserve estimate depends on the quality of available geological and engineering data, the precision of the interpretation of that data, and judgment based on experience and training. As a result, estimates of different petroleum engineers often vary, and the variances can be material. Annually, we engage an independent petroleum engineering firm to evaluate our oil and gas reserves. As a part of this process, our internal reservoir engineer and the independent engineers exchange information and attempt to reconcile any material differences in estimates and assumptions. We believe this reconciliation process improves the accuracy of the reserve estimates by reducing the likelihood of a material error in judgment.

The techniques used in estimating reserves usually depend on the nature and extent of available data, and the accuracy of the estimates vary accordingly. As a general rule, the degree of accuracy of reserve estimates varies with the reserve classification and the related accumulation of available data, as shown in the following table.

Type of Reserves	Nature of Available Data	Degree of Accuracy
Proved undeveloped	Data from offsetting wells, seismic data	Least accurate

Proved developed nonproducing	Logs, core samples, well tests, pressure data	More accurate

Proved developed producing	Production history, pressure data over time	Most accurate

Assumptions as to future commodity prices and operating and capital costs also play a significant role in estimating oil and gas reserves and the estimated present value of the cash flows to be received from the future production of those reserves. Volumes of recoverable reserves are affected by the assumed prices and costs due to what is known as the economic limit (that point in the future when the projected costs and expenses of producing recoverable reserves exceed the projected revenues from the reserves). But more significantly, the estimated present value of future cash flows from the reserves is extremely sensitive to prices and costs, and may vary materially based on different assumptions. SEC financial accounting and reporting standards require that pricing parameters be tied to the price received for oil and natural gas on the effective date of the reserve report. This requirement can result in significant changes from period to period given the volatile nature of oil and gas product prices.

Valuation of unproved properties

Placing a fair market value on unproved properties (also known as prospects) is very subjective since there is no quoted market for undeveloped exploratory prospects. The negotiated price of any prospect between a willing seller and willing buyer depends on the specific facts regarding the prospect, including:

• The location of the prospect in relation to known fields and reservoirs, available markets and transportation systems for oil and gas production in the vicinity, and other critical services;

• The nature and extent of G&G data on the prospect;

• The terms of the leases holding the acreage in the prospect, such as ownership interests, expiration terms, delay rental obligations, depth limitations, drilling and marketing restrictions, and similar terms;

• The prospect’s risk-adjusted potential for return on investment, giving effect to such factors as potential reserves to be discovered, drilling and completion costs, prevailing commodity prices, and other economic factors; and

• The results of drilling activity in close proximity to the prospect that could either enhance or condemn the prospect’s chances of success.

Valuation allowance for NOL carryforwards

In computing our provision for income taxes, we must assess the need for a valuation allowance on deferred tax assets, which consist primarily of NOL carryforwards. For federal income tax purposes, these carryforwards, if unused, expire 15 to 20 years from the year of origination. Generally, we assess our ability to fully utilize these carryforwards by comparing expected future book income to expected future taxable income based on the assumption that we will produce our existing reserves, as scheduled for production in our reserve report, under current economic conditions. If future book income does not exceed future taxable income by amounts sufficient to utilize NOL’s before they expire, we must impair the resulting deferred tax asset. These computations are inherently imprecise due to the extensive use of estimates and assumptions. As a result, we may make additional impairments to allow for such uncertainties.

Effects of Estimates and Assumptions on Financial Statements

Generally accepted accounting principles do not require, or even permit, the restatement of previously issued financial statements due to changes in estimates. We are required to use our best judgment in making

estimates and assumptions, taking into consideration the best and most current data available to us at the time of the estimate. At each accounting period, we make a new estimate using new data, and continue the cycle. You should be aware that estimates prepared at various times may be substantially different due to new or additional information. While an estimate made at one point in time may differ from an estimate made at a later date, both may be proper due to the differences in available information or assumptions. In this section, we will discuss the effects of different estimates on our financial statements.

Provision for DD&A

We compute our provision for DD&A on a unit-of-production method. Each quarter, we use the following formulas to compute the provision for DD&A for each of our producing properties (or appropriate groups of properties based on geographical and geological similarities):

• DD&A Rate = Unamortized Cost ¸ Beginning of Period Reserves

• Provision for DD&A = DD&A Rate ´ Current Period Production

Reserve estimates have a significant impact on the DD&A rate. If reserve estimates are revised downward in future periods, the DD&A rate will increase as a result of the revision. Alternatively, if reserve estimates are revised upward, the DD&A rate will decrease.

Impairment of Unproved Properties

Each quarter, we review our unproved oil and gas properties to determine if there has been, in our judgment, an impairment in value of each prospect that we consider individually significant. To the extent that the carrying cost of a prospect exceeds its estimated value, we make a provision for impairment of unproved properties, and record the provision as abandonments and impairments within exploration costs on our statement of operations. If the value is revised upward in a future period, we do not reverse the prior provision, and we continue to carry the prospect at a net cost that is lower than its estimated value. If the value is revised downward in a future period, an additional provision for impairment is made in that period.

Impairment of Proved Properties

Each quarter, we assess our producing properties for impairment. If we determine there has been an impairment in any of our producing properties (or appropriate groups of properties based on geographical and geological similarities), we will estimate the value of each affected property. In accordance with applicable accounting standards, the value for this purpose is a fair value instead of a standardized reserve value as prescribed by the SEC for reserves disclosure. We attempt to value each property using reserve classifications and pricing parameters similar to what a willing seller and willing buyer might use. These parameters may include escalations of prices instead of constant pricing, and they may also include the risk-adjusted value of reserves that do not qualify as proved reserves. To the extent that the carrying cost for the affected property exceeds its estimated value, we make a provision for impairment of proved properties. If the value is revised upward in a future period, we do not reverse the prior provision, and we continue to carry the property at a net cost that is lower than its estimated value. If the value is revised downward in a future period, an additional provision for impairment is made in that period. Accordingly, the carrying costs of producing properties on our balance sheet will vary from (and often will be less than) the present value of proved reserves for these properties.

Judgment Regarding Status of In-Progress Wells

On a quarterly basis, we review the status of each in-progress well to determine the proper accounting treatment under the successful efforts method of accounting. Cumulative costs on in-progress wells remain capitalized until their productive status becomes known. If an in-progress exploratory well is found to be unsuccessful (often referred to as a dry hole) prior to the issuance of our financial statements, we write-off all costs incurred through the balance sheet date to abandonments and impairments expense, a component of exploration costs. Costs incurred on that dry hole after the balance sheet date are charged to exploration costs in the period incurred.

19

Occasionally, we are unable to make a final determination about the productive status of a well prior to issuance of our financial statements. In these cases, we leave the well classified as in-progress until we have had sufficient time to conduct additional completion or testing operations and to evaluate the pertinent G&G and engineering data obtained. At the time when we are able to make a final determination of a well’s productive status, the well is removed from the in-progress status and the proper accounting treatment is recorded.

Valuation allowance for NOL carryforwards

Each quarter, we assess our ability to utilize NOL carryforwards. An increase in the valuation allowance from one period to the next will result in a decrease in our net deferred tax assets and a decrease in earnings. Similarly, a decrease in the valuation allowance will result in an increase in our net deferred tax assets and an increase in earnings.

This process requires estimates and assumptions which are complex and may vary materially from our actual ability to utilize NOL carryforwards in the future. Also, the current tax laws in this area are complicated due to the impact of alternative minimum tax on the utilization of NOL carryforwards. As a mitigating factor, as long as we are actively drilling for new production, we have some tax planning strategies available to us, such as elective capitalization of intangible drilling costs, to help us utilize these NOL carryforwards before they expire.

Recent Development

In its recent review of registrants’ filings, the staff of the Securities and Exchange Commission (“SEC”) has taken the position that SFAS No. 142, “Goodwill and Other Intangible Assets” (“SFAS 142”), requires oil and gas entities to separately report on their balance sheets the costs of leasehold and mineral interests acquired after June 30, 2001, including related accumulated depletion, 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 undeveloped leasehold and mineral interests are regularly evaluated for impairment based on lease terms and drilling activity. The SEC staff is expected to refer the question of SFAS 142 applicability to an accounting standards authority, such as the Emerging Issues Task Force. 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. We do not believe that such implementation would have an effect on future earnings.

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 (see “Quantitative and Qualitative Disclosure About Market Risks – Oil and Gas Prices”). We may also suffer a reduction in our operating cash flow and access to funds under the Credit Facility if our exploration program does not replace our oil and gas reserves. 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

Exploration and Development Activities

We presently plan to spend approximately $61.9 million on exploration and development activities during 2003, of which $35.8 million has been incurred through June 30, 2003. The following table sets forth, by area, certain information about our actual and planned exploration and development activities for 2003.

	Actual Expenditures Six Months Ended June 30, 2003		Total Planned Expenditures Year Ended December 31, 2003		Percentage of Total
	(In thousands)

South Louisiana	$	21,200	$	39,300	64	%
Cotton Valley Reef Complex	9,300		11,400		18	%
Mississippi	2,500		3,100		5	%
Other	2,800		8,100		13	%
	$	35,800	$	61,900	100	%

Since our previous quarterly report, we have decreased our estimate of planned expenditures for 2003 by a net of $700,000, as follows:

Cotton Valley Reef Complex. Due to the unsuccessful drilling and attempted completion of the Muse-Patranella Gas Unit #1, we have decided not to drill a previously designated location, resulting in a $1.8 million reduction (net to our 50% working interest) in planned expenditures in this area. We are currently evaluating the information obtained in drilling the Muse-Patranella well to determine the nature and extent of any future drilling in the Cotton Valley Reef Complex.

Mississippi. We now expect to spud our first Deep Knox test in the Black Warrior Basin later in 2003, so we have deferred $1.5 million of planned expenditures to 2004.

South Louisiana. Most of the $2.4 million increase in planned activity in this area for 2003 relates to higher than expected drilling and completion costs on the State Lease 3279 #1.

Approximately 78% of the actual and planned expenditures shown in the preceding table 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. Actual expenditures during 2003 may be substantially higher or lower than these estimates as our plans for exploration and development activities 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 reserves. Other factors, such as prevailing product prices and the availability of capital resources, could also increase or decrease the ultimate level of expenditures during 2003.

Credit Facility

We rely heavily 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 on the Credit Facility to meet our obligations as they come due, we have sufficient liquidity.

At the beginning of 2003, we had an outstanding balance on the Credit Facility of $93 million, and the borrowing base was $110 million, leaving $12.7 million available, after allowing for $4.3 million of outstanding letters of credit. During the six months ended June 30, 2003, we generated cash flow from operating activities of $69.7 million, spent $36.3 million on capital expenditures and other investing activities and repaid $23.4 million on the Credit Facility and other debt. The outstanding balance on the Credit Facility at June 30, 2003 was $70 million, leaving $35.7 million available on the Credit Facility, after allowing for $4.3 million of outstanding letters of credit.

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 on the Credit Facility as a current asset, and (ii) exclude current assets and liabilities related to the fair value of derivatives, when computing the working capital ratio at any balance sheet date.

Our reported working capital at June 30, 2003 was a deficit of $512,000, as compared to a deficit of $18.8 million at December 31, 2002. Giving effect to the above adjustments, our working capital for loan compliance purposes is a positive $43.3 million at June 30, 2003, as compared to a positive $6.8 million at December 31, 2002. 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 June 30, 2003 and December 31, 2002.

	June 30, 2003			December 31, 2002
	(In thousands)

Working capital (deficit) per GAAP	$	(512	)	$	(18,843	)
Add funds available under the Credit Facility	35,700			12,700
Exclude fair value of derivatives classified as current assets or current liabilities	8,133			12,917
Working capital per loan covenant	$	43,321		$	6,774

The banks redetermine the borrowing base at least twice a year, in May and November using the method described below. 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, cash flow and net tangible assets. We were in compliance with all of the financial and non-financial covenants at June 30, 2003.

Uncertainties Regarding Liquidity and Capital Resources

We believe that the amount of funds available to us under the Credit Facility, when combined with our anticipated operating cash flow, will be sufficient to finance our capital expenditures and will provide us with adequate liquidity at least through the next twelve months. Although we believe the assumptions and estimates made in our forecasts are reasonable, uncertainties exist which could cause the borrowing base to be less than expected, cash flow to be less than expected, or capital expenditures to be more than expected. Any of these uncertainties could adversely affect our liquidity and could require us to reduce capital expenditures, sell assets, or seek alternative capital resources. Below is a discussion of certain significant factors that could adversely affect our liquidity.

Adverse changes in reserve estimates or commodity prices could reduce the borrowing base. The banks establish the borrowing base at least twice annually by preparing a reserve report using price-risk assumptions they believe are proper under the circumstances. Any adverse changes in estimated quantities of reserves, the pricing parameters being used, or the risk factors being applied, since the date of the last borrowing base determination, could lower the borrowing base under the Credit Facility.

Adverse changes in reserve estimates or commodity prices could reduce our cash flow from operating activities. We rely on estimates of reserves to forecast our cash flow from operating activities. If the production from those reserves is delayed or is lower than expected, our cash flow from operating activities may be lower than we anticipated. Commodity prices also impact our cash flow from operating activities. Based on December 31, 2002 reserve estimates, we project that a $1.00 drop in oil price and a $.50 drop in gas price would reduce our gross revenues in 2003 by $1.5 million and $11.1 million, respectively, before giving effect to hedging activities. See “Quantitative and Qualitative Disclosure About Market Risks – Oil and Gas Prices.”

Oil and gas reserves are depletable assets. We must replace our existing production with newly discovered reserves, or our borrowing base will decline. If we fail to find new reserves to add to the borrowing base, we may not have sufficient funds to continue drilling activities. Because our focus is on exploration activities, we have a greater risk of drilling dry holes or not finding oil and natural gas that can be produced economically. The seismic data and other technology we use does not allow us to know with certainty prior to drilling a well whether oil or natural gas is present or can be produced economically. We cannot assure you that any of our future exploration efforts will be successful, and if such activities are unsuccessful, it will have a significant adverse affect on our operations and financial condition.

Adverse changes in the borrowing base may cause outstanding debt to equal or exceed the borrowing base. In this event, we will not be able to borrow any additional funds, and we will be required to repay the excess or convert the debt to a term note. Without availability under the Credit Facility, we may be unable to meet our obligations as they mature.

Delays in bringing successful wells on production may reduce our liquidity. As a general rule, we experience a significant lag time between the initial cash outlay on a prospect and the inclusion of any value for such prospect in the borrowing base under the Credit Facility. Until a well is on production, the banks may assign only a minimal borrowing base value to the well, and cash flow from the well are not available to fund our operating expense. Delays in bringing wells on production may reduce the borrowing base significantly, depending on the amounts borrowed and the length of the delays.

We may not be able to comply with certain financial covenants in the Credit Facility if the borrowing base does not increase. The Credit Facility requires us to maintain a working capital average ratio of at least 1 to 1, as adjusted for availability under the Credit Facility and the exclusion of fair value of derivatives. We may not be able to maintain this ratio unless the borrowing base is increased due to new reserve additions, improved reserve performance, or favorable price changes.

Margin calls on derivative contracts could adversely affect our liquidity. Due to the highly volatile nature of the oil and gas commodity markets, a fixed-price derivative entered into as an effective

hedge transaction may be “out of the money” at any time prior to its scheduled maturity, meaning that the current market price exceeds the fixed sell price of the derivative. The ISDA master agreement between us and one of our principal counterparties gives either party the right to request credit support (a “Margin Call”) to the extent that the fair value of the derivatives exceeds specified credit limits. Currently, our credit limit under the master agreement is $5 million, subject to reduction or elimination if our net assets are less than $65 million or if the counterparty has reasonable grounds for insecurity. The counterparty has issued cumulative Margin Calls totaling $4 million. Funds paid to the counterparty for Margin Calls are held for our account in interest-bearing trust accounts controlled by the counterparty.

At June 30, 2003, the fair value of the commodity derivatives with the counterparty was a liability of $7.6 million. Our sensitivity analysis indicates that a 10% increase in the underlying commodity prices would have increased this fair value to a liability of $10.2 million.

Based on current product prices, we have sufficient liquidity under our bank Credit Facility to cover our Margin Call obligations. However, in the event of a significant increase in the future market prices of oil and gas commodity derivatives, the availability of funds under the Credit Facility may be inadequate to cover future Margin Calls. If inadequate, we would be forced to obtain alternative sources of financing to avoid being in default with the counterparty. If future Margin Calls are not paid when due, the counterparty may liquidate our derivative positions and seek to collect from us the resulting monetary obligation to the counterparty.

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 issuances of common stock through a secondary public offering or a rights offering. 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.

Off-Balance Sheet Arrangement

In May 2001, we invested approximately $1.6 million as a limited partner in a partnership formed to purchase and operate two commercial office buildings in Midland, Texas, one of which is the location of our corporate headquarters. Our ownership interest in the partnership is 31.9% before payout (as defined in the partnership agreement) and 33.4% after payout. Substantially all of the partnership’s indebtedness is non-recourse, and we are not liable for any indebtedness of the partnership. An affiliate of Clayton W. Williams ("Mr. Williams") serves as general partner of the partnership. Since we do not manage or control the operations of the partnership or these buildings, and since the partnership is not subject to consolidation under SFAS Interpretation No. 46, we utilize the equity method of accounting for our investment in this limited partnership.

Results of Operations

The following table sets forth certain operating information of the Company for the periods presented. Periods prior to 2003 have been adjusted to account for the sale of certain oil and gas properties in 2002 as discontinued operations (see Note 11 to the accompanying consolidated financial statements).

	Three Months Ended June 30,						Six Months Ended June 30,
	2003			2002			2003			2002
Oil and Gas Production Data:
Gas (MMcf)	7,026			3,376			13,922			6,387
Oil (MBbls)	392			394			765			818
Natural gas liquids (MBbls)	42			63			91			113
Total MMcfe (1)	9,630			6,118			19,058			11,973

Average Oil and Gas Sales Prices:
Gas ($/Mcf):
Before hedging gains (losses)	$	5.38		$	3.16		$	5.81		$	2.72
Hedging gains (losses)	(.81		)	(.52		)	(.90		)	.12
Net realized price	$	4.57		$	2.64		$	4.91		$	2.84
Oil ($/Bbl):
Before hedging gains (losses)	$	28.25		$	24.75		$	30.42		$	22.39
Hedging gains (losses)	(2.34		)	(2.37		)	(2.96		)	(1.03		)
Net realized price	$	25.91		$	22.38		$	27.46		$	21.36
Natural gas liquids ($/Bbl):
Net realized price	$	18.81		$	13.68		$	22.03		$	12.45

Oil and Gas Costs ($/Mcfe Produced):
Lease operating expenses	$	.69		$	.79		$	.75		$	.84
Oil and gas depletion	$	1.05		$	1.05		$	1.07		$	1.10

Net Wells Drilled (2):
Exploratory Wells	1.3			1.0			5.5			1.4
Developmental Wells	2.9			.3			3.0			1.2

(1) Oil is converted to gas equivalents (Mcfe) at the ratio of six Mcf of gas to one Bbl of oil.

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

Three Months Ended June 30, 2003 Compared to June 30, 2002

The following discussion compares our results of operations for the three-month period ended June 30, 2003 to the three-month period ended June 30, 2002. All references to 2003 and 2002 within this section refer to the respective three-month periods.

Revenues

Oil and gas sales increased 129% from $18.8 million in 2002 to $43 million in 2003 due primarily to a 73% increase in average gas prices received and a 108% increase in gas production. A substantial portion of the gas production increase was due to production increases from the Cotton Valley Reef Complex area and production from wells in south Louisiana that were not producing in 2002, including the Romere Pass Unit acquired in July 2002. Oil production was slightly lower but average oil prices realized increased by 16%.

Costs and Expenses

Lease operations expenses increased 37% from $4.9 million in 2002 to $6.7 million in 2003 due primarily to the effects that higher oil and gas prices had on production taxes and the addition of operating

expenses associated with the Romere Pass Unit acquired in July 2002. Oil and gas production on a Mcfe basis increased 57% resulting in a reduction in production costs on a Mcfe basis from $.79 in 2002 to $.69 in 2003.

Exploration costs totaled $10.5 million in 2003, as compared to $4.4 million in 2002, due to the following:

• $8.9 million of abandonments (dry hole costs) and unproved property impairments, including $6.2 million related to the Cotton Valley Reef Complex, $1.7 million related to prospects in Plaquemines Parish, Louisiana and $800,000 for a non-operated dry hole in Mississippi; and

• $1.6 million of seismic and other exploration costs related primarily to the acquisition, processing and interpretation of 3-D seismic data, including $1 million in south Louisiana and $200,000 in Mississippi.

Since we follow the successful efforts method of accounting, our results of operations may be adversely affected during any accounting period in which seismic costs, exploratory dry hole costs, and unproved property impairments are expensed.

Depreciation, depletion and amortization (“DD&A”) expense increased 60% from $6.7 million in 2002 to $10.7 million in 2003 due primarily to a 57% increase in production on an Mcfe basis. Under the successful efforts method of accounting, costs of oil and gas properties are amortized on a unit-of-production method based on estimated proved reserves. The average depletion rate per Mcfe remained constant at $1.05.

During the second quarter 2003, we recorded $155,000 of expense for accretion of abandonment obligations in accordance with Statement of Financial Accounting Standards No. 143 “Accounting for Asset Retirement Obligations” (“SFAS 143”), which we adopted January 1, 2003 (see Note 3 to the accompanying consolidated financial statements).

General and administrative expenses (“G&A”), excluding non-cash stock-based employee compensation, increased 40% from $2 million in 2002 to $2.8 million in 2003. The increase was primarily due to higher personnel costs, professional fees and rising insurance costs. Personnel costs for 2003 include $600,000 of bonuses paid in cash and properties to certain key employees and officers, excluding Mr. Williams. G&A expenses for 2003 also include a non-cash charge of $416,000 for stock-based employee compensation required by Financial Accounting Standards Board Interpretation No. 44 (see Note 6 to the accompanying consolidated financial statements). A $44,000 credit (reduction of expense) was required for the 2002 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.

Interest Expense and Other

Interest expense decreased 3% from $891,000 in 2002 to $861,000 in 2003 due to a combination of factors. The average daily principal balance outstanding on the Credit Facility for 2003 was $81.2 million compared to $81.8 million in the 2002 period. The effective annual interest rate on bank debt, including bank fees and interest rate derivatives, during 2003 was 5.3% compared to 5.1% in 2002. Included in the computation of our effective annual interest rate are losses on interest rate derivatives of $296,000 in 2003 and $226,000 in 2002 (see Note 7 to the accompanying consolidated financial statements). Capitalized interest for 2003 was $270,000 compared to $157,000 in 2002.

We reported a net loss on the change in fair value of derivatives of $2.7 million during the 2003 period compared to a $52,000 net gain in 2002 in accordance with Statement of Financial Accounting

Standards No. 133 “Accounting for Derivative Instruments and Hedging Activities” (see Note 7 to the accompanying consolidated financial statements).

Income Taxes

During 2003, we recorded income tax expense of $2 million, as compared to $611,000 in 2002 (see Note 9 to the accompanying consolidated financial statements).

Six Months Ended June 30, 2003 Compared to June 30, 2002

The following discussion compares our results of operations for the six-month period ended June 30, 2003 to the six-month period ended June 30, 2002. All references to 2003 and 2002 within this section refer to the respective six-month periods.

Revenues

Oil and gas sales increased 145% from $37.4 million in 2002 to $91.7 million in 2003 due primarily to a 73% increase in average gas prices received and a 118% increase in gas production. A substantial portion of the gas production increase was due to production increases from the Cotton Valley Reef Complex area and production from wells in south Louisiana that were not producing in 2002, including the Romere Pass Unit acquired in July 2002. Oil production fell by 6%, which was more than offset by a 29% increase in the average oil prices realized.

Costs and Expenses

Lease operations expenses increased 43% from $10 million in 2002 to $14.3 million in 2003 due primarily to the effects that higher oil and gas prices had on production taxes and the addition of operating expenses associated with the Romere Pass Unit acquired in July 2002. Oil and gas production on a Mcfe basis increased 59% resulting in a reduction in production costs on a Mcfe basis from $.84 in 2002 to $.75 in 2003.

Exploration costs totaled $17.4 million in 2003, as compared to $12.4 million in 2002, due to the following:

• $13.4 million of abandonments (dry hole costs) and unproved property impairments, including $7.2 million related to the Cotton Valley Reef Complex, $4.8 million related to prospects in Plaquemines Parish, Louisiana, $800,000 in Mississippi, and $300,000 in Nevada; and

• $4 million of seismic and other exploration costs related primarily to the acquisition, processing and interpretation of 3-D seismic data, including $2.5 million in south Louisiana and $800,000 in Mississippi.

Depreciation, depletion and amortization (“DD&A”) expense increased 54% from $13.8 million in 2002 to $21.2 million in 2003 due primarily to a 59% increase in production on an Mcfe basis, offset partly by a 3% decrease in the average depletion rate. Under the successful efforts method of accounting, costs of oil and gas properties are amortized on a unit-of-production method based on estimated proved reserves. The average depletion rate per Mcfe decreased from $1.10 in 2002 to $1.07 in 2003.

During 2003, we recorded $306,000 of expense for accretion of abandonment obligations in accordance with Statement of Financial Accounting Standards No. 143 “Accounting for Asset Retirement

Obligations” (“SFAS 143”), which we adopted January 1, 2003 (see Note 3 to the accompanying consolidated financial statements).

General and administrative expenses (“G&A”), excluding non-cash stock-based employee compensation, increased 18% from $3.9 million in 2002 to $4.6 million in 2003. The increase was primarily due to higher personnel costs, professional fees and rising insurance costs. G&A expenses for 2003 include a non-cash charge of $347,000 for stock-based employee compensation required by Financial Accounting Standards Board Interpretation No. 44 (see Note 6 to the accompanying consolidated financial statements). A $69,000 credit (reduction of expense) was required for the 2002 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.

Interest Expense and Other

Interest expense remained constant at $1.9 million for both periods. The average daily principal balance outstanding on the Credit Facility for 2003 was $87.8 million compared to $76.7 million in the 2002 period. The effective annual interest rate on bank debt, including bank fees and interest rate derivatives, during 2003 was 5.2% compared to 5.5% in 2002. Included in the computation of our effective annual interest rate are losses on interest rate derivatives of $575,000 in 2003 and $446,000 in 2002 (see Note 7 to the accompanying consolidated financial statements). Capitalized interest for 2003 was $518,000 compared to $241,000 in 2002.

We reported a net gain on the change in fair value of derivatives of $742,000 during the 2003 period compared to a $660,000 net loss in 2002 in accordance with Statement of Financial Accounting Standards No. 133 “Accounting for Derivative Instruments and Hedging Activities” (see Note 7 to the accompanying consolidated financial statements).

Income Taxes

During 2003, we recorded income tax expense of $10.5 million, as compared to a benefit of $1.1 million in 2002 (see Note 9 to the accompanying consolidated financial statements).

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, 2002 reserve estimates, we

project that a $1 drop in the price per Bbl of oil and a $.50 drop in the price per Mcf of gas would reduce our gross revenues in 2003 by $12.6 million, before giving effect to hedging activities.

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 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. In addition, we may from time to time sell a portion of our gas production under short-term contracts at a fixed price. We do not enter into commodity derivatives for trading purposes.

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 selectively terminate hedges when we believe that market indications point towards upward price potential which could not be realized 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 as of June 30, 2003.

	Oil Swaps			Gas Swaps
	*Bbls*	Average Price		*MMBtu (a)*	Average Price
Production Period:
3rd Quarter 2003	120,000	$	24.20	1,810,000	$	3.58
4th Quarter 2003	80,000	$	24.20	1,720,000	$	3.80
Year 2003 (b)	200,000	$	24.20	3,530,000	$	3.69

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

(b) Based on current estimates, these quantities represent approximately 30% of our oil and gas production for the remainder of 2003.

In July 2003, the Company also entered into collar arrangements covering 551,000 MMBtu of its gas production from November 2003 through March 2004 with a floor of $4.50 and a ceiling of $7.04, and 541,000 MMBtu of its gas production from April 2004 through October 2004 with a floor of $4.20 and a ceiling of $5.28.

We use a sensitivity analysis technique to evaluate the hypothetical effect that changes in the market value of oil and gas may have on the fair value of our commodity derivatives. A 10% increase in the underlying commodity prices would have changed the fair value of our commodity derivatives at June 30, 2003 from a liability of $7.6 million to a liability of $10.2 million.

Interest Rates

All of the Company’s outstanding indebtedness at June 30, 2003 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.

Prompted by declining interest rates during 2001, we entered into a LIBOR-based swap in November 2001 on $50 million of our indebtedness at a fixed rate of 3.63% for two years.

We use a sensitivity analysis technique to evaluate the hypothetical effect that changes in market rates of interest may have on the fair value of our interest rate derivatives. A 10% decrease in the underlying market interest rates would have changed the fair value of our interest rate derivatives at June 30, 2003 from a liability of $519,000 to a liability of $541,000.

Item 4 - Controls and Procedures

Disclosure Controls and Procedures

In September 2002, our Board of Directors adopted a policy designed to establish disclosure controls and procedures that are adequate to provide reasonable assurance that 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 June 30, 2003 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1 - Legal Proceedings

We are a defendant in a personal injury suit filed in the 38th Judicial District Court in Cameron Parish, Louisiana in 2002. The plaintiff, an employee of one of our subcontractors, claims he was injured while working on a barge drilling rig owned and operated by another subcontractor, Parker Drilling Company (“PDC”). PDC was also named as a defendant in the suit. Robert L. Parker is the Chairman of the Board of Directors of PDC and is a member of our Board of Directors. The plaintiff has not yet specified the amount of damages sought, and no interrogatories or other discovery has been conducted. Currently, there are uncertainties concerning the extent of our insurance coverage. Our insurance company is providing defense under a reservation of rights pending resolution of these uncertainties. The plaintiff’s employer is subject to the terms of an agreement with us in which it agrees to indemnify us from damages resulting from injuries to its employees. PDC is seeking indemnification from us for any damages resulting from the fault or negligence of PDC under the terms of our drilling contract with PDC. Due to these uncertainties, we are currently unable to determine our financial exposure, if any, in this matter. We have filed an answer denying liability and intend to vigorously defend this suit.

We are a defendant in a suit filed in the 82nd Judicial District Court in Robertson County, Texas in January 2003 by lessors of the lease on which its Lee Fazzino #1 and Lee Fazzino #2 wells were drilled. The plaintiffs allege that we formed the Lee Fazzino Unit #1, a 320-acre unit that pooled various leases, including the plaintiffs’ lease, in bad faith. The plaintiffs are seeking to have the unit declared to be null and void, with the effect being that the plaintiffs, and certain non-participating royalty owners claiming through the plaintiffs’ lease, are entitled to 100% of the royalties from both wells. If the plaintiffs are successful, our ability to collect all the royalties previously paid to the pooled royalty owners is uncertain, and our net interest in the wells will be reduced from 76.8% to 75%. We have estimated our maximum liability to the plaintiffs to be approximately $8 million to $9 million. However, we believe it is unlikely that the plaintiffs will prevail. We deny all claims and intend to vigorously defend this suit. Subsequent to discovery from the plaintiffs, we filed a counterclaim seeking damages for the filing of a frivolous lawsuit.

In addition, we are a defendant in several lawsuits that have arisen in the ordinary course of business. While the outcome of these lawsuits cannot be predicted with certainty, management does not expect any of these to have a material adverse effect on our consolidated financial condition or results of operations.

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		Certification of the Chief Executive Officer and Chief Financial Officer of Clayton Williams Energy, Inc. pursuant to 18 U.S.C. § 1350.

Reports on Form 8-K

During the quarter ended June 30, 2003, the Company filed the following reports on Form 8-K:

• Form 8-K dated May 13, 2003 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, 2003.

• Form 8-K dated May 1, 2003 reporting the financial results of the Company for the quarter ended March 31, 2003.

CLAYTON WILLIAMS ENERGY, INC.

SIGNATURES

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

			CLAYTON WILLIAMS ENERGY, INC.


Date:	August 13, 2003	By:	/s/ L. Paul Latham
			L. Paul Latham
			Executive Vice President and Chief Operating Officer


Date:	August 13, 2003	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 June 30, 2003

Commission File No. 0-20838

PART II. OTHER INFORMATION

CONSOLIDATED BALANCE SHEETS

Commodity Derivatives

Bbls

Average Price

MMBtu (a)

Average Price

Special Note Regarding Forward-Looking Statements

Overview

Application of Critical Accounting Policies

Summary

Accounting Policies

Estimates or Assumptions

Accounts Affected

Successful efforts accounting for oil and gas properties

• Reserve estimates

• Oil and gas properties

• Valuation of unproved properties

• Accumulated DD&A*

• Judgment regarding status of in-progress exploratory wells

• Provision for DD&A* • Impairment of unproved properties • Abandonment costs (dry hole costs)

Impairment of proved properties

• Reserve estimates and related present value of future net revenues

• Oil and gas properties properties • Accumulated DD&A* • Impairment of proved properties

Valuation allowance for net deferred tax assets

• Estimates related to utilizing net operating loss (NOL) carryforwards

• Deferred tax assets • Deferred tax liabilities • Deferred income taxes

Significant Estimates and Assumptions

Oil and gas reserves

Type of Reserves

Nature of Available Data

Degree of Accuracy

Proved undeveloped

Data from offsetting wells, seismic data

Least accurate

Proved developed nonproducing

Logs, core samples, well tests, pressure data

More accurate

Proved developed producing

Production history, pressure data over time

Most accurate

Effects of Estimates and Assumptions on Financial Statements

Impairment of Proved Properties

Judgment Regarding Status of In-Progress Wells

19

Recent Development

Liquidity and Capital Resources

Overview

Capital Expenditures

Credit Facility

Uncertainties Regarding Liquidity and Capital Resources

Alternative Capital Resources

Off-Balance Sheet Arrangement

Oil and Gas Prices

Bbls

Average Price

MMBtu (a)

Average Price

Disclosure Controls and Procedures

Changes in Internal Control Over Financial Reporting

PART II. OTHER INFORMATION

Average
Price

Average
Price

• Provision for DD&A*
• Impairment of unproved properties
• Abandonment costs (dry hole costs)

• Oil and gas properties properties
• Accumulated DD&A*
• Impairment of proved properties

• Deferred tax assets
• Deferred tax liabilities
• Deferred income taxes

Average
Price

Average
Price