UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

ý Quarterly Report Pursuant to Section 13 or 15(d)
of the Securities Exchange Act of 1934

For the quarterly period ended September 30, 2002

o Transition Report Pursuant to Section 13 or 15(d)
of the Securities Exchange Act of 1934


For the transition period from to

Commission File No. 0-20838

CLAYTON WILLIAMS ENERGY, INC.
(Exact name of Registrant as specified in its charter)

Delaware		75-2396863
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification Number)

6 Desta Drive, Suite 6500, Midland, Texas		79705-5510
(Address of principal executive offices)		(Zip code)

Registrant’s Telephone Number, including area code: (915) 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

Number of shares of Common Stock outstanding as of November 11, 2002….9,272,693.

CLAYTON WILLIAMS ENERGY, INC.

TABLE OF CONTENTS

PART I. FINANCIAL INFORMATION

Item 1.	Financial Statements

	Consolidated Balance Sheets as of September 30, 2002 and December 31, 2001

	Consolidated Statements of Operations for the three months and nine months ended September 30, 2002 and 2001

	Consolidated Statement of Stockholders’ Equity for the nine months ended September 30, 2002

	Consolidated Statements of Cash Flows for the nine months ended September 30, 2002 and 2001

	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

	Certifications

CLAYTON WILLIAMS ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

	September 30, 2002			December 31, 2001
	(Unaudited)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	2,945		$	2,856
Accounts receivable:
Oil and gas sales, net	10,638			7,489
Joint interest and other, net	3,064			2,103
Affiliates	282			210
Inventory	3,835			2,663
Deferred income taxes	447			438
Fair value of derivatives	—			4,426
Prepaids and other	5,277			1,035
	26,488			21,220

PROPERTY AND EQUIPMENT
Oil and gas properties, successful efforts method	602,972			576,784
Natural gas gathering and processing systems	15,270			14,513
Other	11,751			11,370
	629,993			602,667
Less accumulated depreciation, depletion and amortization	(458,284		)	(443,307		)
Property and equipment, net	171,709			159,360

OTHER ASSETS
Deferred income taxes	7,012			401
Fair value of derivatives	—			505
Investments and other	1,925			1,793
	8,937			2,699
	$	207,134		$	183,279

LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts payable:
Trade	$	16,241		$	28,742
Oil and gas sales	7,877			7,890
Affiliates	994			374
Fair value of derivatives	12,227			659
Accrued liabilities and other	1,268			1,334
	38,607			38,999

NON-CURRENT LIABILITIES
Long-term debt	98,440			62,000
Fair value of derivatives	677			—
	99,117			62,000

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 - 9,266,644 shares in 2002 and 9,246,046 shares in 2001	927			925
Additional paid-in capital	72,683			72,525
Retained earnings	4,383			7,019
Accumulated other comprehensive income (loss)	(8,583		)	1,811
	69,410			82,280
	$	207,134		$	183,279

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 September 30,						Nine Months Ended September 30,
	2002			2001			2002			2001
REVENUES
Oil and gas sales	$	22,227		$	22,823		$	59,642		$	85,775
Natural gas services	1,151			1,683			3,768			7,212
Total revenues	23,378			24,506			63,410			92,987

COSTS AND EXPENSES
Lease operations	5,103			5,315			15,123			15,421
Exploration:
Abandonments and impairments	6,565			3,670			15,308			23,011
Seismic and other	2,242			1,275			5,852			11,702
Natural gas services	1,115			1,644			3,290			6,141
Depreciation, depletion and amortization	7,646			9,473			21,472			28,659
Impairment of property and equipment	—			5,018			—			15,371
General and administrative	2,076			1,773			5,899			4,681
Total costs and expenses	24,747			28,168			66,944			104,986
Operating income (loss)	(1,369		)	(3,662		)	(3,534		)	(11,999		)

OTHER INCOME (EXPENSE)
Interest expense	(1,082		)	(911		)	(2,934		)	(2,150		)
Gain on sales of property and equipment	1,854			10,756			1,923			10,773
Change in fair value of derivatives	(428		)	2,884			(1,088		)	2,664
Other	55			77			1,760			219
Total other income (expense)	399			12,806			(339		)	11,506

Income (loss) before income taxes	(970		)	9,144			(3,873		)	(493		)
Income tax expense (benefit)	—			3,119			(1,098		)	(403		)
Income (loss) from continuing operations	(970		)	6,025			(2,775		)	(90		)
Cumulative effect of accounting change, net of tax	—			—			—			(164		)
Income from discontinued operations, net of tax	—			84			139			387
NET INCOME (LOSS)	$	(970	)	$	6,109		$	(2,636	)	$	133

Net income (loss) per common share:
Basic:
Income (loss) from continuing operations	$	(.10	)	$	.65		$	(.30	)	$	(.01	)
Net income (loss)	$	(.10	)	$	.66		$	(.29	)	$	.01

Diluted:
Income (loss) from continuing operations	$	(.10	)	$	.65		$	(.30	)	$	(.01	)
Net income (loss)	$	(.10	)	$	.65		$	(.29	)	$	.01

Weighted average common shares outstanding:
Basic	9,255			9,262			9,231			9,244
Diluted	9,255			9,403			9,231			9,448

Total comprehensive income (loss)	$	(4,664	)	$	8,832		$	(13,030	)	$	3,222

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

CLAYTON WILLIAMS ENERGY, INC.

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY

(Unaudited)

(In thousands)

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

BALANCE,
December 31, 2001	9,246		$	925		$	72,525		$	7,019		$	1,811
Net loss	—		—			—			(2,636		)	—			$	(2,636	)
Changes in fair value of derivatives designated as cash flow hedges	—		—			—			—			(10,394		)	(10,394		)
Total comprehensive loss															$	(13,030	)
Issuance of stock through compensation plans	72		7			801			—			—
Repurchase and cancellation of common stock	(51	)	(5		)	(643		)	—			—
BALANCE,
September 30, 2002	9,267		$	927		$	72,683		$	4,383		$	(8,583	)

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

CLAYTON WILLIAMS ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In thousands)

	Nine Months Ended September 30,
	2002			2001
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	(2,636	)	$	133
Adjustments to reconcile net income (loss) to cash provided by operating activities:
Depreciation, depletion and amortization	21,472			28,659
Impairment of proved properties	—			15,371
Exploration costs	15,308			23,011
Gain on sales of property and equipment	(1,923		)	(10,773		)
Deferred income taxes	(1,098		)	(403		)
Non-cash employee compensation	(247		)	(629		)
Change in fair value of derivatives	1,185			(2,664		)
Non-cash effect of discontinued operations, net of tax	167			382
Cumulative effect of accounting change, net of tax	—			164
Other	764			336

Changes in operating working capital:
Accounts receivable	(4,182		)	5,083
Accounts payable	(3,405		)	(4,353		)
Other	(5,229		)	1,545
Net cash provided by operating activities	20,176			55,862

CASH FLOWS FROM INVESTING ACTIVITIES
Additions to property and equipment	(58,635		)	(91,094		)
Proceeds from sales of property and equipment	7,325			16,106
Other	(105		)	(1,811		)
Net cash used in investing activities	(51,415		)	(76,799		)

CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt	31,940			27,000
Proceeds from sale of common stock	36			150
Repurchase and cancellation of common stock	(648		)	(374		)
Net cash provided by financing activities	31,328			26,776

NET INCREASE IN CASH AND CASH EQUIVALENTS	89			5,839

CASH AND CASH EQUIVALENTS
Beginning of period	2,856			2,384
End of period	$	2,945		$	8,223

SUPPLEMENTAL DISCLOSURES
Cash paid for interest, net of amounts capitalized	$	2,675		$	2,154

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

CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2002

(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”).

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 September 30, 2002 and for the interim periods ended September 30, 2002 and 2001 include all adjustments, consisting only of normal recurring accruals, 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, 2002. The accompanying balance sheet as of December 31, 2001 was audited by the Company’s former independent accounting firm.

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 2001 Form 10-K.

3. Accounting Pronouncements

Effective January 1, 2002 the Company adopted Statement of Financial Accounting Standards No. 144 “Accounting for the Impairment or Disposal of Long–Lived Assets” (“SFAS 144”), which supercedes Statement of Financial Accounting Standards No. 121 (“SFAS 121”). SFAS 144 addresses financial accounting and reporting for the impairment of long-lived assets and for long-lived assets to be disposed of. However, SFAS 144 retains the fundamental provisions of SFAS 121 for recognition and measurement of the impairment of long–lived assets to be held and used, and measurement of long-lived assets to be disposed of by sale. The adoption of SFAS 144 had no impact on the Company’s financial condition or results of operations.

In June 2001, the Financial Accounting Standards Board issued Statement No. 143 “Accounting for Asset Retirement Obligations” (“SFAS 143”), which addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. The standard applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and use of the assets.

SFAS 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset and this additional carrying amount is depreciated over the life of the asset. The liability is accreted at the end of each period through charges to operating expense. If the obligation is settled for other than the carrying amount of the liability, the Company will recognize a gain or loss on settlement.

The Company is required and plans to adopt the provisions of SFAS 143 for the quarter ending March 31, 2003. To accomplish this, the Company must identify all legal obligations for asset retirement obligations, if any, and determine the fair value of these obligations on the date of adoption. The determination of fair value is complex and will require the Company to gather market information and develop cash flow models. Additionally, the Company will be required to develop processes to track and monitor these obligations. Because of the effort necessary to comply with the adoption of SFAS 143, it is not practicable for management to estimate the impact of adopting this Statement at the date of this report.

In June 2002, the Financial Accounting Standards Board issued Statement No. 146 “Accounting for Costs Associated with Exit or Disposal Activities” (“SFAS 146”), which is effective for exit or disposal activities initiated after December 31, 2002. The Company does not believe the adoption of SFAS 146 will have any significant impact on the Company’s financial condition or results of operations.

4. Long-Term Debt

Long-term debt consists of the following:

	September 30, 2002		December 31, 2001
	(In thousands)
Secured Bank Credit Facility (matures December 31, 2004)	$	93,000	$	62,000
Vendor finance obligations	940		—
Abandonment obligations	3,500		—
Production payment obligations	1,000		—
	$	98,440	$	62,000

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.

In July 2002, the banks increased the borrowing base to $110 million in connection with the purchase of certain producing properties in Louisiana as discussed in Note 12. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations”.

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 September 30, 2002, the Company’s indebtedness under the credit facility consisted of $93 million of Eurodollar Loans at a rate of 3.8%.

In addition, the Company pays the banks a commitment fee equal to 1/4% 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.

As of September 30, 2002, the Company had letters of credit outstanding against the credit facility in the aggregate amount of $4.3 million.

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 September 30, 2002.

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, the Company has agreed to repay any unpaid balance. All vendor finance obligations at September 30, 2002 are classified as non-current liabilities.

Abandonment Obligations

In connection with the Romere Pass acquisition discussed in Note 12, the Company assumed the obligation to abandon the acquired assets at the end of their useful lives in accordance with applicable contracts and governmental regulations. Although the estimated abandonment obligation is $3.5 million, the Company has been required to issue letters of credit aggregating $4.25 million to secure this 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.

5. Compensation Plans

Stock Compensation Plan

The Company has reserved 500,000 shares of common stock for issuance under the Executive Incentive Stock Compensation Plan, permitting the Company, at its discretion, to pay all or part of selected executives’ salaries in shares of common stock in lieu of cash. During the nine months ended September 30, 2002, the Company issued 49,290 shares of common stock to Mr. Williams in lieu of cash compensation and bonuses aggregating $589,000, which is included in general and administrative expenses in the accompanying consolidated financial statements. Subsequent to September 30, 2002, the Company issued an additional 2,162 shares to Mr. Williams in lieu of cash compensation aggregating $19,000.

In March 2000, the Financial Accounting Standards Board issued Interpretation No. 44 (“FIN 44”) to Accounting Principles Board Opinion No. 25 “Accounting for Stock Issued to Employees” (“APB 25”) which required a change in the classification of 233,141 stock options repriced by the Company in April 1999 from fixed stock options to variable stock options. Pursuant to FIN 44, 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 September 30, 2002 was $8.40. Accordingly, the Company recorded a non-cash credit for stock-based employee compensation of $247,000, which is included in general and administrative expense, for the nine months ended September 30, 2002. As the repriced options are exercised, the cumulative amount of accrued compensation expense will be credited to additional paid-in capital. Since this provision is based on changes in the quoted market value of the Company’s common stock, the Company’s future results of operations may be subject to significant volatility.

After-Payout Working Interest Incentive Plan

In September 2002, the Compensation Committee of the Board of Directors adopted an incentive plan for key employees and consultants (“Participants”), 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 such Participants. The plan provides for the creation of a series of limited partnerships to which the Company, as general partner, will contribute a portion of its working interest in wells drilled within certain areas. The Company will pay all costs and will receive all revenues until payout of its costs, plus interest. At payout, the limited partners, consisting of key employees and consultants, will receive 99% of all subsequent revenues and will pay 99% of all subsequent expenses. The Company will include its proportionate share of partnership assets, liabilities, revenues, expenses and oil and gas reserves in its consolidated financial statements.

On October 1, 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 12), (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.

6. 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 September 30, 2002.

	Oil Swaps			Gas Swaps
	*Bbls*	Average Price		*MMBtu*	Average Price
Production Period:
4th Quarter 2002	165,000	$	26.12	3,950,000	$	3.43
1st Quarter 2003	160,000	$	25.27	2,275,000	$	3.55
2nd Quarter 2003	240,000	$	24.67	1,545,000	$	3.51
3rd Quarter 2003	120,000	$	24.20	1,810,000	$	3.58
4th Quarter 2003	80,000	$	24.20	1,720,000	$	3.80
	765,000	$	24.99	11,300,000	$	3.55

Based on current estimates, approximately 50% and 75% of the Company’s estimated oil and gas production, respectively, for the remainder of 2002 is subject to commodity derivatives.

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

Effective January 1, 2001, the Company adopted Statement of Financial Accounting Standards No. 133 “Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”), as amended, which established accounting and reporting requirements for derivative instruments and hedging activities. SFAS 133 requires that all derivative instruments be recognized as assets or liabilities in the balance sheet, measured at fair value. The accounting for changes in the fair value of a derivative depends on both the intended purpose and the formal designation of the derivative. Designation is established at the inception of a derivative, but subsequent changes to the designation are permitted. For derivatives designated as cash flow hedges and meeting the effectiveness guidelines of SFAS 133, changes in fair value are recognized in accumulated other comprehensive income until the hedged item is recognized in earnings. Hedge effectiveness is measured quarterly based on relative changes in fair value between the derivative contract and the hedged item over time. Any change in fair value resulting from ineffectiveness is recognized immediately in earnings. Changes in fair value of derivative instruments which are not designated as cash flow hedges or do not meet the effectiveness guidelines of SFAS 133 are recorded in earnings as the changes occur.

Upon adoption of SFAS 133, the Company recorded liabilities aggregating $539,000 applicable to the fair value of all derivatives held by the Company as of January 1, 2001, resulting in a provision for the cumulative effect of accounting change of $164,000 (net of deferred taxes of $89,000), and a charge to accumulated other comprehensive income of $186,000 (net of deferred taxes of $100,000).

The following table sets forth, for the nine months ended September 30, 2002, 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, 2001	$	1,997		$	(186	)	$	1,811

Change in fair value of derivatives, net of tax	(11,770		)	(993		)	(12,763		)
Reclassifications to earnings, net of tax	1,929			440			2,369

Net changes during the period	(9,841		)	(553		)	(10,394		)

Balance, September 30, 2002	$	(7,844	)	$	(739	)	$	(8,583	)

During the twelve months subsequent to September 30, 2002, the Company expects to reclassify $5.5 million of net deferred losses associated with open cash flow hedges and $2.7 million of net deferred losses on terminated cash flow hedges from accumulated other comprehensive income to earnings. The unrealized deferred hedge losses associated with open cash flow hedges remain subject to market price fluctuations until the position is either settled under the terms of the hedge arrangement or terminated prior to maturity. The net deferred losses on terminated cash flow hedges are fixed.

Amounts reported as changes in fair value of derivatives in the accompanying statements of operations consist of the following:

Three Months Ended
September 30,

Nine Months Ended
September 30,

2002

2001

2002

2001

(In thousands)

Net gain (loss) on the ineffective portion of cash flow hedges

$

(820

)

$

209 $

(1,049

)

$

282 Net gain (loss) on derivatives not qualifying as hedges

392 2,675

(39

)

2,382

Net gain (loss)

$

(428

)

$

2,884

$

(1,088

)

$

2,664

Margin Calls

The ISDA master agreement between the Company and its principal derivative counterparty gives either party the right to request credit support to the extent that the mark-to-market value of the derivatives exceeds specified credit limits (a “Margin Call”). Currently, the Company’s credit limit under the master agreement is $2 million; however, the Company and the counterparty are presently negotiating to increase the credit limit. During the quarter ended September 30, 2002, the counterparty issued 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.

Sale of Enron Claim

In September 2002, the Company assigned $4.9 million of its claim in the bankruptcy proceedings of Enron North America Corp. to a third party for $392,000, net of transactions fees totaling $50,000. If the claim is ultimately disallowed, in whole or in part, by the bankruptcy court, the Company will be required to refund a proportionate part of the sales price, with interest, based on the ratio of the amount of the disallowed claim to the total claim. The gain was recorded as a change in fair value of derivatives in the accompanying statement of operations.

7. 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. All other long-term debt, in the aggregate, has an estimated fair value of $4.6 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 September 30, 2002 and December 31, 2001 are set forth below. The associated carrying values of derivatives at September 30, 2002 are equal to their estimated fair values.

	September 30, 2002			December 31, 2001
	(In thousands)
Assets (liabilities):
Commodity derivatives	$	(11,767	)	$	4,558
Interest rate derivatives	(1,137		)	(286		)
Net assets (liabilities)	$	(12,904	)	$	4,272

8. 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 September 30, 2002 and December 31, 2001 are as follows:

	September 30, 2002			December 31, 2001
	(In thousands)
Deferred tax assets:
Net operating loss carryforwards	$	12,551		$	16,964
Depletion carryforwards	—			1,229
Accrued stock-based compensation	57			146
Fair value of derivatives	4,519			—
Other	1,102			971
	18,229			19,310
Deferred tax liabilities:
Property and equipment	(10,416		)	(16,978		)
Fair value of derivatives	—			(1,493		)
Valuation allowance	(354		)	—
	(10,770		)	(18,471		)
Net deferred tax assets	$	7,459		$	839

Components of net deferred tax assets:
Current assets	$	447		$	438
Non-current assets	7,012			401
	$	7,459		$	839

The Company’s effective income tax rates for the nine months ended September 30, 2002 and 2001 were different than the statutory federal income tax rate for the following reasons:

	Nine Months Ended September 30,
	2002			2001
	(In thousands)
Income tax expense (benefit) at statutory rate of 35%	$	(1,355	)	$	(172	)
Tax depletion in excess of basis	(131		)	(157		)
Change in valuation allowance	349			—
Revision of previous tax estimates	39			(74		)
Income tax expense (benefit)	$	(1,098	)	$	(403	)
Current	$	—		$	—
Deferred	(1,098		)	(403		)
Income tax expense (benefit)	$	(1,098	)	$	(403	)

The Company derives an income tax benefit when employees and directors exercise options granted under the Company’s stock compensation plans (see Note 5). 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 the quarter ended September 30, 2002, the Company recorded a valuation allowance of $354,000 due to the uncertainty about the Company’s ability to utilize additional net deferred tax assets. Of the total valuation allowance, $5,000 was related to permanent differences arising from the exercise of employee stock options.

9. 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, of which 50,800 shares were repurchased during the nine months ended September 30, 2002 at an aggregate cost of $648,000.

10. Investment

In May 2001, the Company 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 the Company’s corporate headquarters. In addition, the Company loaned the partnership $100,000 against an unsecured note due in September 2002 and guaranteed up to $675,000 of partnership indebtedness. In August 2002, the partnership repaid the loan, and the Company was released from the guaranty. An affiliate of Mr. Williams serves as general partner of the partnership. Since the Company does not manage or control the operations of the partnership or these buildings, the Company utilizes the equity method of accounting for its investment in the partnership. Included in other income for the nine months ended September 30, 2002 is $102,000 of equity in earnings of the partnership.

11. Settlement of Claim

During the quarter ended June 30, 2002, the Company received $5.5 million from its insurer in full settlement of a coverage dispute regarding the August 2000 blowout of the Mary Muse #1, a Cotton Valley Reef Complex well in Robertson County, Texas. The proceeds were applied first to recover $4.1 million of

unamortized costs attributable to the Mary Muse well. The remaining $1.4 million was recorded as other income in the accompanying consolidated statements of operations.

12. 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 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:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2002		2001		2002		2001
	(In thousands)
Revenues	$	—	$	221	$	363	$	890
Income before income taxes	$	—	$	129	$	214	$	595
Net income	$	—	$	84	$	139	$	387

13. Contingency

The Company and a subcontracted drilling company are parties to a personal injury suit filed in Cameron Parish, Louisiana. The plaintiff is an employee of a subcontractor of the Company, and claims that he was injured while working on the drilling contractor’s barge rig during the drilling of a well operated by the Company. The plaintiff has not yet specified the amount of damages sought.

Currently, there are uncertainties concerning the extent of the Company’s insurance coverage, and Company’s insurance company is providing a defense under a reservation of rights pending resolution of these uncertainties. The drilling contractor has filed a claim against the Company for contractual indemnity pursuant to the terms of the drilling contract for any damages resulting from the fault or negligence attributable to the drilling contractor. It is possible that the Company may be entitled to all or part of any damages for which the Company may be liable pursuant to the terms of a contractual indemnity from the plaintiff’s employer for damages to the plaintiff attributable to any negligence on the part of the Company.

Due to these uncertainties, the Company is currently unable to estimate its financial exposure, if any, in this matter. The Company has filed a general denial and plans to prepare a vigorous defense in this suit.

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

Special Note Regarding Forward-Looking Statements

This Form 10-Q contains statements that constitute “forward-looking statements” within the meaning of Section 27A of the Securities Act and Section 21E of the Securities Exchange Act. Forward-looking statements can be identified by the use of words such as “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 and include statements regarding our plans, beliefs or current expectations 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. Forward-looking statements involve known and unknown risks and uncertainties that could cause our actual results to differ materially from those contained in any forward-looking statement. While we have made assumptions that we believe are reasonable, the assumptions that support our forward-looking statements are based upon information that is currently available and is subject to change. We disclaim any responsibility to publicly update any information contained in or related to a forward-looking statement and therefore disclaim any resulting liability for potentially related damages. All forward-looking statements attributable to Clayton Williams Energy, Inc. are expressly qualified in their entirety by this cautionary statement.

The following discussion is intended to help you understand the historical consolidated financial position of Clayton Williams Energy, Inc. (the “Company”, “we”, “us”, or “our”) at September 30, 2002, and our results of operations and cash flows for each of the periods ended September 30, 2002 and 2001. 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, 2001 and the consolidated financial statements and notes included in this Form 10–Q.

Overview

Since 1997, we have been transforming the Company 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. We are now concentrating our efforts toward finding and producing oil and natural gas through exploration activities, principally in the Miocene Trend in south Louisiana and the Cotton Valley Reef Complex area of east central Texas. Recently, we also began an exploration program in the Black Warrior Basin of Mississippi, targeting the Deep Knox formations.

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. At the time of our initial public offering, we were heavily concentrated in lower risk, developmental drilling and spent an insignificant portion of our capital budget on G&G costs and exploratory drilling. The alternative to the successful efforts method is the full cost method of accounting. Companies that are heavily involved in exploration activities 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.

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 • Valuation of unproved properties • Judgment regarding status of in-progress exploratory wells	• Oil and gas properties • Accumulated DD&A* • 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 • 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	More 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 guidelines 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 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 units-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.

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.

Occasionally, we are unable to make a final determination about the productive status of a well before we are required to release 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 net income or loss. Similarly, a decrease in the valuation allowance will result in an increase in our net deferred tax assets and an increase in net income or loss.

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.

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 Risk”). If our exploration program does not replace our oil and gas reserves, we may also suffer a reduction in our operating cash flow and access to funds under the Credit Facility. Under extreme circumstances, product price reductions or exploration drilling failures could allow the banks to seek to foreclose on our oil and gas properties, thereby threatening our financial viability.

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

Capital Expenditures

Exploration and Development Activities

We presently plan to spend approximately $58.6 million on exploration and development activities during 2002, of which $37.5 million has been incurred through September 30, 2002. The following table sets forth, by area, certain information about our actual and planned exploration and development activities for 2002.

	Actual Expenditures Nine Months Ended September 30, 2002		Total Planned Expenditures Year Ended December 31, 2002

					Percentage of Total
	(In thousands)

South Louisiana	$	17,900	$	26,900	46	%
Cotton Valley Reef Complex	5,100		13,500		23	%
Mississippi	7,300		8,100		14	%
Austin Chalk (Trend)	1,900		3,000		5	%
West Texas	2,000		2,600		4	%
Other	3,300		4,500		8	%
	$	37,500	$	58,600	100	%

Since our previous quarterly report, current estimates of planned expenditures have been revised upward 13% from $51.8 million to $58.6 million due primarily to the addition of a Cotton Valley Reef Complex well, the Scamardo Gas Unit Re-entry, and the acceleration of drilling activities in south Louisiana.

Approximately 95% 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, but may also offer a higher reserve potential and rate of return on investment. You need to be aware that actual expenditures during 2002 may be substantially higher than these estimates as our plans for exploration and development activities change throughout 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 2002.

Acquisitions of Proved Properties

During the quarter ended September 30, 2002, we acquired all of the working interest in the Romere Pass Unit in Plaquemines Parish, Louisiana for an aggregate purchase price of $21.5 million. The purchase price consisted of $17 million cash, the issuance of a $3.5 million letter of credit for future abandonment obligations, and the granting of an after-payout production payment in the amount of $1 million. After we have recouped $21 million, plus certain developmental drilling costs, and interest on the combined amounts at an annual rate of 12%, we will pay to the seller 5% of our net proceeds from production until the $1 million production payment is satisfied. We financed the acquisition through borrowings on the Credit Facility (see Note 4).

Credit Facility

We use one 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 2002, we had an outstanding balance on the Credit Facility of $62 million, and the borrowing base was $85 million, leaving $23 million of availability. During the nine months ended September 30, 2002, we generated cash flow from operating activities of $20.2 million, received proceeds from the sales of property and equipment totaling $7.3 million and spent $58.7 million on capital

expenditures and other investments, resulting in a cash flow deficit of approximately $31.2 million, which was financed primarily by borrowing $31 million on the Credit Facility. During 2002, the banks increased the borrowing base to $110 million, leaving $12.7 million available on the Credit Facility at September 30, 2002, 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 deficit at September 30, 2002 was $12.1 million, as compared to $17.8 million at December 31, 2001. Giving effect to the above adjustments, our working capital for loan compliance purposes is a positive $12.8 million at September 30, 2002, as compared to a positive $1.5 million at December 31, 2001.

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 September 30, 2002.

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, 2001 reserve estimates, we project that a $1 drop in oil price and a $.50 drop in gas price would reduce our gross revenues by $1.6 million and $7.1 million, respectively, before giving effect to hedging activities. See “Quantitative and Qualitative Disclosure About Market Risks.”

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. Delays in bringing wells on production may reduce the borrowing base significantly, depending on the amounts borrowed and the length of the delays.

Oil and gas reserves are depletable assets. We must replace our existing production with newly discovered reserves, or we will liquidate our asset base. If we fail to find new reserves to add to the borrowing base, we may not have sufficient funds to continue drilling activities.

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 could be required to repay the excess or convert the debt to a term note. Without availability on the Credit Facility, we may be unable to meet our obligations as they mature.

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. The Company 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 our principal counterparty gives either party the right to request credit support to the extent that the mark-to-market value of the derivatives exceeds specified credit limits (a “Margin Call”). Currently, the Company’s credit limit under the master agreement is $2 million; however, the Company and the counterparty are presently negotiating to increase the credit limit.

During the third quarter of 2002, our principal counterparty issued Margin Calls totaling $4 million. Although we have been subject to Margin Calls in the past with other counterparties, this is the first time that a counterparty has actually issued a Margin Call. We believe that, in light of a heightened level of concern over credit issues throughout the energy sector, it is more likely that our counterparties will make Margin Calls in the future.

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. We cannot assure you 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. In addition, we loaned the partnership $100,000 against an unsecured note due in September 2002 and guaranteed up to $675,000 of partnership indebtedness. In August 2002, the partnership repaid the loan, and we were released from the guaranty. Our ownership interest in the partnership is 31.9% before payout (as defined in the partnership agreement) and 33.4% after payout. We are not liable for any indebtedness of the partnership. An affiliate of Clayton W. Williams serves as general partner of the partnership. Since we do not manage or control the operations of the partnership or these buildings, 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. This table excludes historical information attributable to discontinued operations (see Note 12 to the accompanying consolidated financial statements).

	Three Months Ended September 30,					Nine Months Ended September 30,
	2002			2001		2002			2001
Oil and Gas Production Data:
Gas (MMcf)	4,436			2,662		10,823			7,732
Oil (MBbls)	388			529		1,206			1,670
Natural gas liquids (MBbls)	59			71		172			188
Total MMcfe(1)	7,118			6,262		19,091			18,880

Average Oil and Gas Sales Prices:
Gas ($/Mcf):
Before hedging gains (losses)	$	3.03		$	2.81	$	2.85		$	4.52
Hedging gains (losses)	(.23		)	.18		(.02		)	.29
Net realized price	$	2.80		$	2.99	$	2.83		$	4.81
Oil ($/Bbl):
Before hedging gains (losses)	$	27.49		$	25.65	$	23.99		$	26.87
Hedging gains (losses)	(3.97		)	.48		(1.95		)	.18
Net realized price	$	23.52		$	26.13	$	22.04		$	27.05
Natural gas liquids ($/Bbl):
Net realized price	$	13.42		$	12.85	$	12.78		$	17.78

Oil and Gas Costs ($/Mcfe Produced):
Lease operating expenses	$	.72		$	.85	$	.79		$	.82
Oil and gas depletion	$	1.03		$	1.46	$	1.07		$	1.47

Net Wells Drilled(2):
Exploratory Wells	3.5			3.7		4.9			17.0
Developmental Wells	—			1.0		1.2			18.6

(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 September 30, 2002 Compared to September 30, 2001

The following discussion compares our results of operations for the three-month period ended September 30, 2002 to the three-month period ended September 30, 2001. All references to 2002 and 2001 within this section refer to the respective three-month periods.

Revenues

Oil and gas sales decreased 3% from $22.8 million in 2001 to $22.2 million in 2002 due primarily to a 27% decline in oil production which was mostly offset by a substantial increase in gas production. Since most of our recent drilling activities have emphasized gas reserves, gas production rose 67% as compared to the third quarter of 2001.

Costs and Expenses

Lease operations expenses decreased 4% from $5.3 million in 2001 to $5.1 million in 2002, while oil and gas production on a Mcfe basis increased 14%, resulting in a 15% decrease in production costs on a Mcfe basis from $.85 in 2001 to $.72 in 2002.

Exploration costs totaled $8.8 million in 2002, as compared to $4.9 million in 2001, due to the following:

• $6.6 million of abandonments (dry hole costs) and unproved property impairments of which $3 million related to prospects in Plaquemines Parish, Louisiana, $1.5 million in West Texas, $1.1 million in Nevada, $500,000 in Mississippi; and

• $2.2 million of seismic and other exploration costs related primarily to the acquisition, processing and interpretation of 3-D seismic data in south Louisiana.

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 decreased 20% from $9.5 million in 2001 to $7.6 million in 2002 due primarily to a 29% 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 $1.46 in 2001 to $1.03 in 2002. The depletion rates in the 2001 quarter were higher than normal due to the effects of lower product prices on reserve estimates, particularly on certain marginally economic properties in the Bossier Sands, Sweetlake and south Texas areas. The depletion rates in the 2002 quarter declined due primarily to the significant improvements in production performance attributable to a recently completed Cotton Valley Reef Complex well.

We recorded a provision for impairment of property and equipment of $5 million during the 2001 quarter, but no corresponding impairment was needed during the 2002 quarter.

General and administrative expenses (“G&A”), excluding non-cash stock-based employee compensation, increased 10% from $2.1 million in 2001 to $2.3 million in 2002 due primarily to higher franchise taxes and professional fees. G&A expenses for the current period of 2002 include a non-cash credit of $178,000 for stock-based employee compensation required by Financial Accounting Standards Board Interpretation No. 44 (Note 5 to the accompanying consolidated financial statements). A $368,000 credit was required for the 2001 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.

Other Income and Expense

Interest expense increased 21% from $911,000 in 2001 to $1.1 million in 2002 due primarily to higher average levels of indebtedness on the Credit Facility, offset in part by lower effective interest rates. The average daily principal balance outstanding on the Credit Facility during the current quarter was $92.1 million compared to $63.9 million in the 2001 period. The increased borrowings were used to finance the Company’s capital expenditures (see “Management’s Discussion and Analysis of Financial Condition

and Results of Operations – Liquidity and Capital Resources”). The effective annual interest rate on bank debt, including bank fees and interest rate derivatives, during 2002 was 5.3% compared to 6.2% in the 2001 period (see Notes 4 and 6 to the accompanying consolidated financial statements). Capitalized interest for 2002 was $172,000 compared to $101,000 in 2001.

We recorded a gain of $1.9 million on the sale of property and equipment in 2002 as compared to $10.8 million in 2001 (see Note 12 to the accompanying consolidated financial statements).

We reported a net loss on the change in fair value of derivatives of $428,000 during the 2002 period compared to a $2.9 million net gain in 2001 in accordance with Statement of Financial Accounting Standards No. 133 “Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”), which we adopted effective January 1, 2001 (see Note 6 to the accompanying consolidated financial statements).

Income Taxes

During 2002, we did not record a tax benefit due to the uncertainty of utilizing the related net operating loss carryforwards prior to their expiration. A tax provision of $3.1 million was made in 2001 (see Note 8 to the accompanying consolidated financial statements). To the extent we incur losses in future periods, it is unlikely that we will record a related tax benefit due to uncertainties about the realization of additional net deferred tax assets.

Nine Months Ended September 30, 2002 Compared to September 30, 2001

The following discussion compares our results of operations for the nine-month period ended September 30, 2002 to the nine-month period ended September 30, 2001. All references to 2002 and 2001 within this section refer to the respective nine-month periods.

Revenues

Oil and gas sales decreased 31% from $85.8 million in 2001 to $59.6 million in 2002 due primarily to the combined effects of a 41% decline in average gas prices, a 19% decline in average oil prices, lower oil production and higher gas production. Since most of our recent drilling activities have been targeting gas reserves, oil production declined 28% and gas production rose 40% as compared to the 2001 period.

Costs and Expenses

Lease operations expenses decreased 2% from $15.4 million in 2001 to $15.1 million in 2002, while oil and gas production on a Mcfe basis increased 1%, resulting in a 2% decrease in production costs on a Mcfe basis from $.82 in 2001 to $.79 in 2002.

Exploration costs totaled $21.2 million in 2002, as compared to $34.7 million in 2001, due to the following:

• $15.3 million in abandonments (dry hole costs) and unproved property impairments, including $6.5 million related to prospects in Plaquemines Parish, Louisiana, $4.2 million related to prospects in the West Texas area, $1.8 million related to the Cotton Valley Reef Complex area, and $1 million for prospects in Nevada; and

• $5.9 million of seismic and other exploration costs related primarily to the acquisition, processing and interpretation of 3-D seismic data in south Louisiana.

DD&A expense decreased 25% from $28.7 million in 2001 to $21.5 million in 2002 due primarily to a 27% 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 $1.47 in 2001 to $1.07 in 2002. The depletion rates in the 2001 period were higher than normal due to the effects of lower product prices on reserve estimates, particularly on certain marginally economic properties in the Bossier Sands, Sweetlake and south Texas areas. The depletion rates in the 2002 period declined due primarily to significant improvements in production performance attributable to a recently completed Cotton Valley Reef Complex well.

We recorded a provision for impairment of property and equipment of $15.4 million during the 2001 period, but no corresponding impairment was needed during the 2002 period.

G&A expense, excluding non-cash stock-based employee compensation, increased 15% from $5.3 million in 2001 to $6.1 million in 2002 due primarily to increased legal costs applicable to a dispute with an insurer (which dispute was settled during the quarter) and other increases in insurance costs, franchise taxes and professional fees. G&A expenses during the current quarter of 2002 include a non-cash credit of $247,000 for stock-based employee compensation pursuant to the requirements of Financial Accounting Standards Board Interpretation No. 44 (see Note 5 to the accompanying consolidated financial statements). A $629,000 credit was required during the 2001 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.

We reported a net loss on the change in fair value of derivatives of $1.1 million during 2002 compared to a $2.7 million net loss in 2001 in accordance with SFAS 133, which we adopted effective January 1, 2001 (see Note 6 to the accompanying consolidated financial statements).

Other Income and Expense

Interest expense increased 32% from $2.2 million in 2001 to $2.9 million in 2002 due primarily to higher average levels of indebtedness on the Credit Facility, offset in part by lower effective interest rates. The average daily principal balance outstanding on the credit facility during 2002 was $81.9 million compared to $48.6 million in the 2001 period. The increased borrowings were used to finance the Company’s capital expenditures (see “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources”). The effective annual interest rate on bank debt, including bank fees and interest rate derivatives, during 2002 was 5.4% compared to 7.1% in the 2001 period (see Notes 4 and 6 to the accompanying consolidated financial statements). Capitalized interest for 2002 was $413,000 compared to $460,000 in 2001.

We recorded a gain on the sale of property and equipment of $1.9 million in 2002 compared to a gain of $10.8 million in 2001 (see Note 12 to the accompanying consolidated financial statements).

Other income for 2002 includes a $1.4 million gain on settlement of an insurance dispute (see Note 11 to the accompanying consolidated financial statements).

Income Taxes

During 2002, we recorded an income tax benefit of $1.1 million, as compared to a benefit of $400,000 in 2001 (see Note 8 to the accompanying consolidated financial statements). To the extent we incur losses in future periods, it is unlikely that we will record a related tax benefit due to uncertainties about the realization of additional net deferred tax assets.

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, 2001 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 for the year ending December 31, 2002 by $8.7 million, before giving effect to hedging activities.

From time to time, we utilize commodity derivatives, consisting of swaps and collars, 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. 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 we receive the fixed price and pay the market price. If the market price is between the call and the put strike prices, then no payments are due from either party. The commodity derivatives we use differ from futures contracts in that there is not a contractual obligation that requires or permits the future physical delivery of the hedged products. We do not enter into commodity derivatives for trading purposes.

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, sometimes this activity may 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 September 30, 2002.

	Oil Swaps			Gas Swaps
	*Bbls*	Average Price		*MMBtu*	Average Price
Production Period:
4th Quarter 2002	165,000	$	26.12	3,950,000	$	3.43
1st Quarter 2003	160,000	$	25.27	2,275,000	$	3.55
2nd Quarter 2003	240,000	$	24.67	1,545,000	$	3.51
3rd Quarter 2003	120,000	$	24.20	1,810,000	$	3.58
4th Quarter 2003	80,000	$	24.20	1,720,000	$	3.80
	765,000	$	24.99	11,300,000	$	3.55

Interest Rates

All of the Company’s outstanding indebtedness at September 30, 2002 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.

Item 4 - 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 Securities and Exchange Commission (“SEC”) and other communications with our stockholders. Disclosure controls and procedures include all processes necessary to ensure that material information is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and is accumulated and communicated to our management, including our chief executive and chief financial officers, to allow timely decisions regarding required disclosures.

With respect to our disclosure controls and procedures:

• We have evaluated the effectiveness of our disclosure controls and procedures within 90 days prior to the filing of this report;

• 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 Controls

There were no significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date the controls were evaluated. No significant deficiencies or material weaknesses were identified in the evaluation of our internal controls and therefore no corrective actions have been taken.

29 PART II. OTHER INFORMATION

Item 1 - Legal Proceedings

Item 6 - Exhibits and Reports on Form 8-K

Exhibits

None.

Reports on Form 8-K

During the quarter ended September 30, 2002, the Company filed the following Form 8-K’s:

• Form 8-K dated July 24, 2002 to report the Company’s acquisition of assets.

• Form 8-K dated August 20, 2002 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, 2002.

CLAYTON WILLIAMS ENERGY, INC.

SIGNATURES

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

			CLAYTON WILLIAMS ENERGY, INC.


Date:	November 12, 2002	By:	/s/ L. Paul Latham
			L. Paul Latham
			Executive Vice President and Chief Operating Officer


Date:	November 12, 2002	By:	/s/ Mel G. Riggs
			Mel G. Riggs
			Senior Vice President and Chief Financial Officer

CERTIFICATION OF

CHIEF EXECUTIVE OFFICER

CLAYTON WILLIAMS ENERGY, INC.

CERTIFICATION

I, Clayton W. Williams, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Clayton Williams Energy, Inc.;

2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;

3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;

b) evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the “Evaluation Date”); and

c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent function):

a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

6. The registrant’s other certifying officer and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date: November 12, 2002


/s/ Clayton W. Williams
Clayton W. Williams
Chief Executive Officer

CERTIFICATION OF

CHIEF FINANCIAL OFFICER

CLAYTON WILLIAMS ENERGY, INC.

CERTIFICATION

I, Mel G. Riggs, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Clayton Williams Energy, Inc.;

b) evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the “Evaluation Date”); and

c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

Date: November 12, 2002


/s/ Mel G. Riggs
Mel G. Riggs
Chief Financial Officer

For the quarterly period ended September 30, 2002

Commission File No. 0-20838

PART II. OTHER INFORMATION

CONSOLIDATED BALANCE SHEETS

Bbls

Average Price

MMBtu

Average Price

Production Period:

4th Quarter 2002

165,000

$

26.12

3,950,000

$

3.43

1st Quarter 2003

160,000

$

25.27

2,275,000

$

3.55

2nd Quarter 2003

240,000

$

24.67

1,545,000

$

3.51

3rd Quarter 2003

120,000

$

24.20

1,810,000

$

3.58

4th Quarter 2003

80,000

$

24.20

1,720,000

$

3.80

765,000

$

24.99

11,300,000

$

3.55

Three Months Ended September 30,

Nine Months Ended September 30,

2002

2001

2002

2001

(In thousands)

Net gain (loss) on the ineffective portion of cash flow hedges

$

(820

)

$

209

$

(1,049

)

$

282

Net gain (loss) on derivatives not qualifying as hedges

392

2,675

(39

)

2,382

Net gain (loss)

$

(428

)

$

Average
Price

Average
Price

Three Months Ended
September 30,

Nine Months Ended
September 30,