UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

FORM 10-Q

 

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

 

For the quarterly period ended June 30, 2002

 

or

 

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

For the transition period from            to

 

Commission File No. 0-20838

 

CLAYTON WILLIAMS ENERGY, INC.

(Exact name of Registrant as specified in its charter)

 

 

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 August 9, 2002       9,253,941.

 

 

 

CLAYTON WILLIAMS ENERGY, INC.

TABLE OF CONTENTS

 

PART I.  FINANCIAL INFORMATION
Item 1.		Financial Statements
		Consolidated Balance Sheets as of June 30, 2002 and December 31, 2001
		Consolidated Statements of Operations for the three months and six months ended June 30, 2002 and 2001
		Consolidated Statement of Stockholders’ Equity for the six months ended June 30, 2002
		Consolidated Statements of Cash Flows for the six months ended June 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
PART II.  OTHER INFORMATION
Item 1.	Legal Proceedings
Item 4.	Submission of Matters to a Vote of Security Holders
Item 6.	Exhibits and Reports on Form 8-K

 

2

 

CLAYTON WILLIAMS ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

 

		June 30, 2002			December 31, 2001
		(Unaudited)
ASSETS
CURRENT ASSETS
Cash and cash equivalents		$	8,934		$	2,856
Accounts receivable:
Oil and gas sales, net		8,996			7,489
Joint interest and other, net		2,222			2,103
Affiliates		264			210
Inventory		3,602			2,663
Deferred income taxes		412			438
Fair value of derivatives		—			4,426
Prepaids and other		2,420			1,035
		26,850			21,220
PROPERTY AND EQUIPMENT
Oil and gas properties, successful efforts method		577,923			576,784
Natural gas gathering and processing systems		14,915			14,513
Other		11,588			11,370
		604,426			602,667
Less accumulated depreciation, depletion and amortization		(450,672		)	(443,307		)
Property and equipment, net		153,754			159,360
OTHER ASSETS
Deferred income taxes		5,058			401
Fair value of derivatives		—			505
Investments and other		1,862			1,793
		6,920			2,699
		$	187,524		$	183,279
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts payable:
Trade		$	13,681		$	28,742
Oil and gas sales		7,447			7,890
Affiliates		1,207			374
Fair value of derivatives		6,439			659
Accrued liabilities and other		861			1,334
		29,635			38,999
LONG-TERM DEBT		84,000			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 - 9,245,741 shares in 2002 and 9,246,046 shares		925			925
Additional paid-in capital		72,500			72,525
Retained earnings		5,353			7,019
Accumulated other comprehensive income (loss)		(4,889		)	1,811
		73,889			82,280
		$	187,524		$	183,279

 

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

 

3

 

CLAYTON WILLIAMS ENERGY, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(In thousands, except per share)

 

		Three Months Ended June 30,						Six Months Ended June 30,
		2002			2001			2002			2001
REVENUES
Oil and gas sales		$	18,797		$	30,202		$	37,415		$	62,952
Natural gas services		1,418			2,678			2,617			5,529
Total revenues		20,215			32,880			40,032			68,481
COSTS AND EXPENSES
Lease operations		4,850			5,164			10,020			10,106
Exploration:
Abandonments and impairments		2,514			13,006			8,743			19,341
Seismic and other		1,902			1,919			3,610			10,427
Natural gas services		1,181			1,841			2,175			4,497
Depreciation, depletion and amortization		6,747			11,020			13,826			19,186
Impairment of property and equipment		—			10,353			—			10,353
General and administrative		1,948			1,948			3,823			2,908
Total costs and expenses		19,142			45,251			42,197			76,818
Operating income (loss)		1,073			(12,371		)	(2,165		)	(8,337		)
OTHER INCOME (EXPENSE)
Interest expense		(891		)	(685		)	(1,852		)	(1,239		)
Gain on sales of property and equipment		60			4			69			17
Change in fair value of derivatives		52			(30		)	(660		)	(220		)
Other		1,584			89			1,705			142
Total other income (expense)		805			(622		)	(738		)	(1,300		)
Income (loss) before income taxes		1,878			(12,993		)	(2,903		)	(9,637		)
Income tax expense (benefit)		611			(4,623		)	(1,098		)	(3,522		)
Income (loss) from continuing operations		1,267			(8,370		)	(1,805		)	(6,115		)
Cumulative effect of accounting change, net of tax		—			—			—			(164		)
Income from discontinued operations, net of tax		81			136			139			303
NET INCOME (LOSS)		$	1,348		$	(8,234	)	$	(1,666	)	$	(5,976	)
Net income (loss) per common share:
Basic:
Income (loss) from continuing operations		$	.14		$	(.90	)	$	(.20	)	$	(.66	)
Net income (loss)		$	.15		$	(.89	)	$	(.18	)	$	(.64	)
Diluted:
Income (loss) from continuing operations		$	.14		$	(.90	)	$	(.20	)	$	(.66	)
Net income (loss)		$	.14		$	(.89	)	$	(.18	)	$	(.64	)
Weighted average common shares outstanding:
Basic		9,236			9,273			9,219			9,267
Diluted		9,375			9,273			9,219			9,267

 

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

 

4

 

CLAYTON WILLIAMS ENERGY, INC.

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY

(Unaudited)

(In thousands)

 

							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		—		—			—			(1,666		)	—			$	(1,666	)
Changes in fair value of derivatives designated as cash flow hedges		—		—			—			—			(6,700		)	(6,700		)
Total comprehensive loss																$	(8,366	)
Issuance of stock through compensation plans		51		5			618			—			—
Repurchase and cancellation of common stock		(51	)	(5		)	(643		)	—			—
BALANCE, June 30, 2002		9,246		$	925		$	72,500		$	5,353		$	(4,889	)

 

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

 

5

 

CLAYTON WILLIAMS ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In thousands)

 

		Six Months Ended June 30,
		2002			2001
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss		$	(1,666	)	$	(5,976	)
Adjustments to reconcile net loss to cash provided by operating activities:
Depreciation, depletion and amortization		13,826			19,186
Impairment of proved properties		—			10,353
Exploration costs		8,743			19,341
Gain on sales of property and equipment		(69		)	(17		)
Deferred income taxes		(1,098		)	(3,522		)
Non-cash employee compensation		(69		)	(261		)
Change in fair value of derivatives		403			220
Non-cash effect of discontinued operations, net of tax		167			278
Cumulative effect of accounting change, net of tax		—			164
Other		623			229
Changes in operating working capital:
Accounts receivable		(1,680		)	705
Accounts payable		(3,126		)	7,767
Other		(1,417		)	(37		)
Net cash provided by operating activities		14,637			48,430
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to property and equipment		(33,967		)	(68,545		)
Proceeds from sales of property and equipment		4,125			34
Other		(69		)	(1,816		)
Net cash used in investing activities		(29,911		)	(70,327		)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt		22,000			21,700
Proceeds from sale of common stock		—			95
Repurchase and cancellation of common stock		(648		)	—
Net cash provided by financing activities		21,352			21,795
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		6,078			(102		)
CASH AND CASH EQUIVALENTS
Beginning of period		2,856			2,384
End of period		$	8,934		$	2,282
SUPPLEMENTAL DISCLOSURES
Cash paid for interest, net of amounts capitalized		$	1,850		$	1,247

 

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

 

6

 

CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 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 controlled 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 June 30, 2002 and for the interim periods ended June 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.         Long-Term Debt

 

Long-term debt consists of the following:

 

		June 30, 2002			December 31, 2001
		(In thousands)
Secured Bank Credit Facility (matures December 31, 2004)		$	84,000		$	62,000

 

7

 

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.

 

Effective July 18, 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 – Liquidity and Capital Resources.”

 

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.  Effective July 18, 2002, Base Rate Loans bear interest at the fluctuating Base Rate plus a Base Rate Margin ranging from 0% to 0.5% per annum, depending on levels of outstanding advances and letters of credit.  Eurodollar Loans bear interest at the LIBOR rate plus a Eurodollar Margin ranging from 1.25% to 2.25%.  At June 30, 2002, the Company’s indebtedness under the credit facility consisted of $84 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.

 

The loan agreement contains financial covenants that are computed quarterly and require the Company to maintain minimum levels of working capital and cash flow.  The Company was in compliance with all of the financial and non-financial covenants at June 30, 2002.

 

Subsequent to June 30, 2002, the Company issued letters of credit aggregating $4.3 million.

 

4.                          Compensation Plans

 

The Company has reserved 500,000 shares of common stock for issuance under the Executive Incentive Stock Compensation Plan, permitting the Company, at its discretion, to pay all or part of selected executives’ salaries in shares of common stock in lieu of cash.  During the six months ended June 30, 2002, the Company issued 41,187 shares of common stock to Mr. Williams in lieu of cash compensation and bonuses aggregating $511,000, which is included in general and administrative expenses in the accompanying consolidated financial statements.  Subsequent to June 30, 2002, the Company issued an additional 3,763 shares to Mr. Williams in lieu of cash compensation aggregating $39,000.

 

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 that date ($31.94 per share).  The Company’s closing market price at June 30, 2002 was $11.60.  Accordingly, the Company recorded a non-cash credit for stock-based employee compensation of $69,000, which is included in general and administrative expense, for the six months ended June 30, 2002.  As the repriced options are exercised, the cumulative

 

8

 

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.

 

5.         Derivatives

 

Commodity Derivatives

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

 

The following summarizes information concerning the Company’s net positions in open commodity derivatives as of June 30, 2002, plus positions entered into subsequent to June 30, 2002.

 

		Oil Swaps					Gas Swaps
		Bbls		Average Price			MMBtu		Average Price
Production Period:
3rd Quarter 2002		280,000		$	25.68		3,880,000		$	3.05
4th Quarter 2002		330,000		$	25.63		3,950,000		$	3.43
1st Quarter 2003		240,000		$	25.33		3,355,000		$	3.48
2nd Quarter 2003		240,000		$	24.67		3,165,000		$	3.33
3rd Quarter 2003		120,000		$	24.20		1,810,000		$	3.58
4th Quarter 2003		80,000		$	24.20		1,720,000		$	3.80
		1,290,000		$	25.18		17,880,000		$	3.39

 

Based on current estimates, approximately 85% and 70% of the Company’s estimated oil and gas production for the remainder of 2002, respectively, 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 3).  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

 

9

 

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 six months ended June 30, 2002, the components of accumulated other comprehensive income, as reported in stockholders’ equity, all of which is related to derivatives that qualify for cash flow hedge treatment 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		(6,617		)	(565		)	(7,182		)
Reclassifications to earnings, net of tax		192			290			482
Net changes during the period		(6,425		)	(275		)	(6,700		)
Balance, June 30, 2002		$	(4,428	)	$	(461	)	$	(4,889	)

 

During the twelve months subsequent to June 30, 2002, the Company expects to reclassify $4.2 million of net deferred losses associated with open cash flow hedges and $657,000 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 June 30,						Six Months Ended June 30,
		2002			2001			2002			2001
		(In thousands)
Net gain (loss) on the ineffective portion of cash flow hedges		$	52		$	70		$	(229	)	$	73
Net loss on derivatives not qualifying as hedges		—			(100		)	(431		)	(293		)
Net gain (loss)		$	52		$	(30	)	$	(660	)	$	(220	)

 

6.         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.  Long-term debt was estimated to have a fair value approximating the carrying amount since the stated interest rate is generally market sensitive.

 

10

 

The fair values of derivatives as of June 30, 2002 and December 31, 2001 are set forth below.  The associated carrying values of derivatives at June 30, 2002 are equal to their estimated fair values.

 

		June 30, 2002			December 31, 2001
		(In thousands)
Assets (liabilities):
Commodity derivatives		$	(5,729	)	$	4,558
Interest rate derivatives		(710		)	(286		)
Net assets (liabilities)		$	(6,439	)	$	4,272

 

7.         Income Taxes

 

Deferred tax assets and liabilities are the result of temporary differences between the financial statement carrying values and the tax bases of assets and liabilities.  Significant components of net deferred tax assets at June 30, 2002 and December 31, 2001 are as follows:

 

		June 30, 2002			December 31, 2001
		(In thousands)
Deferred tax assets:
Net operating loss carryforwards		$	13,200		$	16,964
Depletion carryforwards		—			1,229
Accrued stock-based compensation		122			146
Fair value of derivatives		2,256			—
Other		969			971
		16,547			19,310
Deferred tax liabilities:
Property and equipment		(11,077		)	(16,978		)
Fair value of derivatives		—			(1,493		)
		(11,077		)	(18,471		)
Net deferred tax assets		$	5,470		$	839
Components of net deferred tax assets:
Current assets		$	412		$	438
Non-current assets		5,058			401
		$	5,470		$	839

 

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

 

		Six Months Ended June 30,
		2002			2001
		(In thousands)
Income tax expense (benefit) at statutory rate of 35%		$	(1,016	)	$	(3,373	)
Tax depletion in excess of basis		(82		)	(149		)
Income tax expense (benefit)		$	(1,098	)	$	(3,522	)
Current		$	—		$	—
Deferred		(1,098		)	(3,522		)
Income tax expense (benefit)		$	(1,098	)	$	(3,522	)

 

11

 

The Company derives an income tax benefit when employees and directors exercise options granted under the Company’s stock compensation plans (see Note 4).  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.  No options were exercised during the six months ended June 30, 2002.

 

8.         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 six months ended June 30, 2002 at an aggregate cost of $648,000.

 

9.         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.  Subsequent to June 30, 2002, the partnership repaid the loan, and the Company was released from the guaranty.  An affiliate of Mr. Williams serves as general partner.  Since the Company does not manage or control the operations of these buildings, the Company utilizes the equity method of accounting for its investment in the partnership.  Included in other income for the six months ended June 30, 2002 is $69,000 of equity in earnings of the partnership.

 

10.      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 August 2001, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 143 “Accounting for Asset Retirement Obligations” (“SFAS 143”).  SFAS 143 addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated retirement costs.  The Company is in the process of assessing the effect of adopting SFAS 143, which will be effective for its first quarter of 2003.

 

In June 2002, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards 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.

 

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

 

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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.      Subsequent Events

 

In July 2002, the Company acquired 100% working interest in the Romere Pass Unit in the Plaquemines Parish, Louisiana for total consideration of $22 million.  The purchase price consisted of $17.5 million cash, the issuance of a $3.5 million letter of credit for future liabilities, and the granting of an after-payout production payment in the amount of $1 million.  After the Company has recouped $21 million, plus certain developmental drilling costs and interest at an annual rate of 12%, the production payment will be repaid out of 5% of the Company’s net proceeds from production.  The Company financed the acquisition through borrowings on its bank credit facility (see Note 3).

 

Also in July 2002, the Company sold its interests in certain wells in Wharton County, Texas, effective July 1, 2002, for $3.2 million.  These properties were classified as held for sale and have been included at their net book value in other current assets in the accompanying consolidated balance sheet as of June 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 Company will recognize a net gain on the sale of approximately $1.7 million during the third quarter of 2002.

 

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 Company believes that the plaintiff’s employer may be obligated to the Company pursuant to the terms of a contractual indemnity for any damages to the plaintiff attributable to any negligence on the part of the Company.  The drilling contractor 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.

 

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.

 

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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. (“CWEI”) at June 30, 2002, and our results of operations and cash flows for each of the periods ended June 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 CWEI from a development driller of horizontal wells in the Austin Chalk (Trend) to an exploration company committed to generating and drilling exploratory prospects, primarily through advanced seismic technology.  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 have a volatile impact on 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.

 

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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		• Oil and gas properties • Accumulated DD&A • Provision for DD&A
		• Judgment regarding status of in-progress exploratory wells		• 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

 

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.

 

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Type of Reserves		Nature of Available Data		Degree of Accuracy
Proved undeveloped		Data from offsetting wells, seismic data		Least accurate
Proved developed nonproducing		Logs, core samples, well tests, pressure data		More accurate
Proved developed producing		Production history, pressure data over time		Most accurate

 

Assumptions as to future commodity prices and operating and capital costs also play a significant role in estimating oil and gas reserves and the estimated present value of the cash flows to be received from the future production of those reserves.  Volumes of recoverable reserves are affected by the assumed prices and costs due to what is known as the economic limit (that point in the future when the projected costs and expenses exceed the projected revenues).  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 cause 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.  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.

 

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

 

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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.  Instead of using the parameters required by an SEC-based reserve report, we try to evaluate 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.

 

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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 profits 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.  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 $51.8 million on exploration and development activities during 2002, of which $25.2 million has been incurred through June 30, 2002.  The following table sets forth, by area, certain information about our actual and planned exploration and development activities for 2002.

 

		Actual Expenditures Six Months Ended June 30, 2002			Planned Expenditures Year Ended December 31, 2002			Percentage of Total
		(In thousands)
South Louisiana		$	11,100		$	27,500		53	%
Cotton Valley Reef Complex		4,300			9,200			18	%
Mississippi		5,400			7,200			14	%
West Texas		2,000			2,500			5	%
Austin Chalk (Trend)		1,100			2,400			4	%
Other		1,300			3,000			6	%
		$	25,200		$	51,800		100	%

 

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We have made significant changes in our estimates of planned expenditures since our previous report.  Current estimates have been revised downward 14% from $59.9 million to $51.8 million due primarily to delays in scheduled drilling activities in south Louisiana.  A portion of the $14.2 million decrease in planned expenditures for south Louisiana was offset by the addition of $7.2 million related to an exploration program in the Black Warrior Basin of Mississippi.

 

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

 

Since our previous report, we have committed to spend approximately $22 million to acquire 100% working interest and operating rights in the Romere Pass Unit in Plaquemines Parish, Louisiana.  The purchase price consisted of $17.5 million cash (which we paid in July 2002), the issuance of a $3.5 million letter of credit for future liabilities, and the granting of an after-payout production payment in the amount of $1 million.  After the Company has recouped $21 million, plus certain developmental drilling costs and interest at an annual rate of 12%, the production payment will be repaid out of 5% of the Company’s net proceeds from production.  The Company financed the acquisition through borrowings on the Credit Facility (see Note 3).  We plan to begin certain recompletion and developmental drilling activities in the Romere Pass Unit in 2003.

 

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 six months ended June 30, 2002, we generated cash flow from operating activities of $14.6 million and spent $26.9 million on capital expenditures and other investments, resulting in a cash flow deficit of approximately $15.3 million, which was financed by borrowing $22 million on the Credit Facility.  In May 2002, the banks increased the borrowing base to $95 million, leaving $11 million available on the Credit Facility at June 30, 2002.  Subsequent to June 30, 2002, the banks increased the borrowing base to $110 million in connection with the Romere Pass acquisition.  Immediately following the acquisition, we had approximately $11 million available on the Credit Facility.

 

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 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

 

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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 June 30, 2002 was $2.8 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 $14.6 million at June 30, 2002, as compared to a positive $800,000 at December 31, 2001.

 

The banks redetermine the borrowing base at least twice a year, in May and November.  If at any time, the borrowing base is less than the amount of outstanding indebtedness, we will be required to (i) pledge additional collateral, (ii) prepay the excess in not more than five equal monthly installments, or (iii) elect to convert the entire amount of outstanding indebtedness to a term obligation based on amortization formulas set forth in the loan agreement.  The loan agreement contains financial covenants that are computed quarterly and requires us to maintain minimum levels of working capital, cash flow and net tangible assets.  We were in compliance with all of the financial and non-financial covenants at June 30, 2002.

 

Uncertainties Regarding Liquidity and Capital Resources

 

Based on our internal projections for 2002, we believe that the amount of funds available to us on the Credit Facility, when combined with our projected operating cash flow, will be sufficient to finance our capital expenditures and will provide us with adequate liquidity.  Although we believe the assumptions and estimates made in our projections 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 create a liquidity issue 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.

 

Adverse changes in reserve estimates or commodity prices could reduce our cash flow from operating activities.  We rely on estimates of reserves to project our cash flow from operating activities.  If the forecasted 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.  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

 

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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.

 

Alternative Capital Resources

 

Although our base of oil and gas reserves, as collateral for the Credit Facility, has historically been our primary capital resource, we have in the past, and could in the future, use alternative capital resources, such as asset sales, vendor financing arrangements, and/or issuances of common stock through a secondary public offering or a rights offering.  We could also issue subordinated debt or preferred stock in a public or a private placement if we choose to raise capital through either of these markets.  While we believe we would be able to obtain funds through one or more of these alternatives, if needed, we cannot assure you that these 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.  Subsequent to June 30, 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 these buildings, we utilize the equity method of accounting for our investment in this limited partnership.

 

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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 June 30,						Six Months Ended June 30,
		2002			2001			2002			2001
Oil and Gas Production Data:
Gas (MMcf)		3,376			2,898			6,387			5,070
Oil (MBbls)		394			596			818			1,141
Natural gas liquids (MBbls)		63			65			113			117
Total MMcfe (1)		6,118			6,864			11,973			12,618
Average Oil and Gas Sales Prices:
Gas ($/Mcf):
Before hedging gains (losses)		$	3.16		$	4.48		$	2.72		$	5.41
Hedging gains (losses)		(.52		)	.10			.12			.36
Net realized price		$	2.64		$	4.58		$	2.84		$	5.77
Oil ($/Bbl):
Before hedging gains (losses)		$	24.75		$	26.83		$	22.39		$	27.44
Hedging gains (losses)		(2.37		)	(.22		)	(1.03		)	.04
Net realized price		$	22.38		$	26.61		$	21.36		$	27.48
Natural gas liquids ($/Bbl):
Net realized price		$	13.68		$	19.11		$	12.45		$	20.77
Oil and Gas Costs ($/Mcfe Produced):
Lease operating expenses		$	.79		$	.75		$	.84		$	.80
Oil and gas depletion		$	1.05		$	1.57		$	1.10		$	1.48
Net Wells Drilled (2):
Exploratory Wells		1.0			7.8			1.4			13.3
Developmental Wells		.3			5.3			1.2			17.6

 

(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 June 30, 2002 Compared to June 30, 2001

 

Revenues

 

Oil and gas sales decreased 38% from $30.2 million in 2001 to $18.8 million in 2002 due primarily to the combined effects of a 42% decline in average gas prices and a decline in oil production.  Since most of the Company’s recent drilling activities have emphasized gas reserves, oil production declined 34% and gas production rose 16% as compared to the second quarter of 2001.

 

Costs and Expenses

 

Lease operations expenses decreased 6% from $5.2 million in 2001 to $4.9 million in 2002, while oil and gas production on a Mcfe basis decreased 11%, resulting in a 5% increase in production costs on a Mcfe basis from $.75 in 2001 to $.79 in 2002.

 

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Exploration costs totaled $4.4 million in 2002, as compared to $14.9 million in 2001, due to the following:

 

•          $2.5 million in abandonments (dry hole costs) and unproved property impairments related primarily to prospects in Plaquemines Parish, Louisiana; and

 

•          $1.9 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 39% from $11 million in 2001 to $6.7 million in 2002 due primarily to a 33% 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 $1.57 in 2001 to $1.05 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 $10.4 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, remained constant at $2 million.  For the periods presented, stock-based employee compensation required by Financial Accounting Standards Board Interpretation No. 44 (Note 4 to the accompanying consolidated financial statements) was not significant.  However, 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 gain on the change in fair value of derivatives of $52,000 during the 2002 period compared to a $30,000 net loss 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 5 to the accompanying consolidated financial statements).

 

Interest Expense and Other

 

Interest expense increased 30% from $685,000 in 2001 to $891,000 in 2002 due primarily to higher average levels of indebtedness on the secured bank 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 $81.8 million compared to $46.9 million in the 2001 period.  The effective annual interest rate on bank debt, including bank fees and interest rate derivatives, during the current quarter was 5.1% compared to 7.1% in the 2001 period.  Capitalized interest for the current period was $157,000 compared to $161,000 in the 2001 period.

 

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

 

Income Taxes

 

During the current quarter, we recorded income tax expense of $611,000, as compared to a benefit of $4.6 million in 2001 (see Note 7 to the accompanying consolidated financial statements).

 

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Six Months Ended June 30, 2002 Compared to June 30, 2001

 

Revenues

 

Oil and gas sales decreased 41% from $63 million in 2001 to $37.4 million in 2002 due primarily to the combined effects of a 51% decline in average gas prices, a 22% decline in average oil prices, and a decline in oil production.  Since most of the Company’s recent drilling activities have been targeting gas reserves, oil production declined 28% and gas production rose 26% as compared to the 2001 period.

 

Costs and Expenses

 

Lease operations expenses decreased slightly from $10.1 million in 2001 to $10 million in 2002, while oil and gas production on a Mcfe basis decreased 5%, resulting in an equivalent increase in production costs on a Mcfe basis from $.80 in 2001 to $.84 in 2002.

 

Exploration costs totaled $12.4 million in 2002, as compared to $29.8 million in 2001, due to the following:

 

•          $8.7 million in abandonments (dry hole costs) and unproved property impairments, including $3.5 million related to prospects in Plaquemines Parish, Louisiana, $2.7 million related to prospects in the West Texas area, and $1.8 million related to the Cotton Valley Reef Complex area; and

 

•          $3.7 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.

 

DD&A expense decreased 28% from $19.2 million in 2001 to $13.8 million in 2002 due primarily to a 26% 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 $1.48 in 2001 to $1.10 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 $10.4 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 26% from $3.2 million in 2001 to $3.9 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 $69,000 for stock-based employee compensation pursuant to the requirements of Financial Accounting Standards Board Interpretation No. 44 (see Note 4 to the accompanying consolidated financial statements).  A $261,000 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 $660,000 during the 2002 period compared to a $220,000 net loss in 2001 in accordance with SFAS 133, which we adopted effective January 1, 2001 (see Note 5 to the accompanying consolidated financial statements).

 

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Interest Expense and Other

 

Interest expense increased 58% from $1.2 million in 2001 to $1.9 million in 2002 due primarily to higher average levels of indebtedness on the secured bank credit facility, offset in part by lower effective interest rates.  The average daily principal balance outstanding on the credit facility during 2002 was $76.7 million compared to $40.8 million in the 2001 period.  The effective annual interest rate on bank debt, including bank fees and interest rate derivatives, during 2002 was 5.5% compared to 7.8% in the 2001 period.  Capitalized interest for the current period was $241,000 compared to $359,000 in the 2001 period.

 

Other income for the current period 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 $3.5 million in 2001 (see Note 7 to the accompanying consolidated financial statements).

 

Item 3 -          Quantitative and Qualitative Disclosure About Market Risks

 

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

 

Oil and Gas Prices

 

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

 

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Since commodity markets are very volatile, our hedging activities are dynamic.  As market conditions change, we may elect to settle a hedging transaction related to our oil and gas production prior to its scheduled maturity date. As a result, we may realize a gain or loss at the time of the settlement which could be substantially different from any gain or loss which would have been realized if the original hedging transaction had been settled at its scheduled maturity date.

 

Since our primary hedging objective is to optimize the price we receive for our oil and gas production, our hedging strategy may not necessarily reduce our exposure to declining product prices.  However, we believe that we can effectively manage this risk by carefully evaluating the underlying market factors and making informed decisions regarding hedging transactions.

 

The following summarizes information concerning the Company’s net positions in open commodity derivatives as of June 30, 2002, plus positions entered into subsequent to June 30, 2002.

 

		Oil Swaps					Gas Swaps
		Bbls		Average Price			MMBtu		Average Price
Production Period:
3rd Quarter 2002		280,000		$	25.68		3,880,000		$	3.05
4th Quarter 2002		330,000		$	25.63		3,950,000		$	3.43
1st Quarter 2003		240,000		$	25.33		3,355,000		$	3.48
2nd Quarter 2003		240,000		$	24.67		3,165,000		$	3.33
3rd Quarter 2003		120,000		$	24.20		1,810,000		$	3.58
4th Quarter 2003		80,000		$	24.20		1,720,000		$	3.80
		1,290,000		$	25.18		17,880,000		$	3.39

 

Interest Rates

 

All of the Company’s outstanding indebtedness at June 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.

 

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PART II.  OTHER INFORMATION

 

Item 1 -          Legal Proceedings

 

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 Company believes that the plaintiff’s employer may be obligated to the Company pursuant to the terms of a contractual indemnity for any damages to the plaintiff attributable to any negligence on the part of the Company.  The drilling contractor 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.

 

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 4 -          Submission of Matters to a Vote of Security Holders

 

On June 11, 2002, the Company held its annual meeting of Stockholders at which Jerry F. Groner, Robert L. Parker and Jordan R. Smith were re-elected to the Company’s Board of Directors.  Clayton W. Williams, L. Paul Latham, Mel G. Riggs and Stanley S. Beard continue to serve as directors.  The tabulation of votes was as follows:

 

Nominee		For		Withheld
Jerry F. Groner		8,165,587		175,782
Robert L. Parker		8,237,956		103,413
Jordan R. Smith		8,238,104		103,265

 

In addition, shareholders also ratified the appointment of KPMG LLP as the Company’s auditors for the fiscal year ending December 31, 2002.  The tabulation of votes was as follows:  For – 8,321,953; Against – 4,230; Abstain – 15,186.

 

Item 6 -          Exhibits and Reports on Form 8-K

 

Exhibits

 

Exhibit Number		Description
10.1		Ninth Restated Loan Agreement dated July 18, 2002 among Clayton Williams Energy, Inc., Warrior Gas Co., CWEI Acquisitions, Inc., Romere Pass Acquisition Corp., Bank One, NA, Union Bank of California, N.A., and Bank of Scotland
21		Subsidiaries of the Registrant
99.1		Certificate of Chief Executive Officer of Clayton Williams Energy, Inc.
99.2		Certificate of Chief Financial Officer of Clayton Williams Energy, Inc.

 

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Reports on Form 8-K

 

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

 

•          Form 8-K dated April 11, 2002 to change the Company’s certifying accountant.

 

•          Form 8-K dated May 17, 2002 to report the appointment of KPMG LLP as auditors.

 

•          Form 8-K dated May 22, 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.

 

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CLAYTON WILLIAMS ENERGY, INC.

SIGNATURES

 

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

 

			CLAYTON WILLIAMS ENERGY, INC.
Date:	August 13, 2002	By:	/s/ L. Paul Latham
			L. Paul Latham
			Executive Vice President and Chief Operating Officer
Date:	August 13, 2002	By:	/s/ Mel G. Riggs
			Mel G. Riggs
			Senior Vice President and Chief Financial Officer

 

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