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, 2003

 

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)

 

 

Registrant’s Telephone Number, including area code:  (432) 682-6324

 

Not applicable

(Former name, former address and former fiscal year, if changed since last report)

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.   Yes   ý   No   o

 

Indicate by check mark whether the registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2).   Yes   o   No   ý

 

There were 9,364,454 shares of Common Stock, $.10 par value, of the registrant outstanding as of November 10, 2003.

 

 

CLAYTON WILLIAMS ENERGY, INC.

TABLE OF CONTENTS

 

PART I.  FINANCIAL INFORMATION
Item 1.	Financial Statements
	Consolidated Balance Sheets as of September 30, 2003 and December 31, 2002
	Consolidated Statements of Operations for the three months and nine months ended September 30, 2003 and 2002
	Consolidated Statement of Stockholders’ Equity for the nine months ended September 30, 2003
	Consolidated Statements of Cash Flows for the nine months ended September 30, 2003 and 2002
	Notes to Consolidated Financial Statements
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 3.	Quantitative and Qualitative Disclosure About Market Risks
Item 4.	Controls and Procedures
PART II.  OTHER INFORMATION
Item 1.	Legal Proceedings
Item 6.	Exhibits and Reports on Form 8-K
	Signatures

 

2

 

CLAYTON WILLIAMS ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

 

		September 30, 2003			December 31, 2002
		(Unaudited)
ASSETS
CURRENT ASSETS
Cash and cash equivalents		$	10,706		$	5,676
Accounts receivable:
Oil and gas sales, net		16,461			14,426
Joint interest and other, net		2,441			3,714
Affiliates		318			223
Inventory		1,332			2,141
Deferred income taxes		738			524
Fair value of derivatives		498			—
Prepaids and other		2,427			5,215
		34,921			31,919
PROPERTY AND EQUIPMENT
Oil and gas properties, successful efforts method		647,823			617,320
Natural gas gathering and processing systems		16,708			16,203
Other		12,208			11,918
		676,739			645,441
Less accumulated depreciation, depletion and amortization		(495,093		)	(466,815		)
Property and equipment, net		181,646			178,626
OTHER ASSETS
Deferred income taxes		—			6,594
Investments and other		2,325			1,853
		2,325			8,447
		$	218,892		$	218,992
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts payable:
Trade		$	19,284		$	22,440
Oil and gas sales		10,275			8,274
Affiliates		1,139			1,257
Current maturities of long-term debt		1,303			—
Fair value of derivatives		2,308			12,917
Accrued liabilities and other		2,972			5,874
		37,281			50,762
NON-CURRENT LIABILITIES
Long-term debt		54,453			94,949
Deferred income taxes		11,085			—
Fair value of derivatives		48			—
Other		9,566			4,500
		75,152			99,449
STOCKHOLDERS’ EQUITY
Preferred stock, par value $.10 per share; authorized - 3,000,000 shares; issued and outstanding - none		—			—
Common stock, par value $.10 per share; authorized - 30,000,000 shares; issued - 9,354,588 shares in 2003 and 9,277,415 shares in 2002		935			928
Additional paid-in capital		73,714			72,787
Retained earnings		33,209			3,016
Accumulated other comprehensive loss		(1,399		)	(7,950		)
		106,459			68,781
		$	218,892		$	218,992

 

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

 

3

 

CLAYTON WILLIAMS ENERGY, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(In thousands, except per share)

 

		Three Months Ended September 30,						Nine Months Ended September 30,
		2003			2002			2003			2002
REVENUES
Oil and gas sales		$	38,039		$	22,227		$	129,785		$	59,642
Natural gas services		2,202			1,151			6,504			3,768
Total revenues		40,241			23,378			136,289			63,410
COSTS AND EXPENSES
Lease operations		7,227			5,103			21,477			15,123
Exploration:
Abandonments and impairments		3,953			6,565			17,347			15,308
Seismic and other		1,481			2,242			5,445			5,852
Natural gas services		2,075			1,115			6,064			3,290
Depreciation, depletion and amortization		10,055			7,646			31,279			21,472
Impairment of property and equipment		170			—			170			—
Accretion of abandonment obligations		171			—			477			—
General and administrative		2,039			2,076			6,969			5,899
Total costs and expenses		27,171			24,747			89,228			66,944
Operating income (loss)		13,070			(1,369		)	47,061			(3,534		)
OTHER INCOME (EXPENSE)
Interest expense		(697		)	(1,082		)	(2,550		)	(2,934		)
Gain (loss) on sales of property and equipment		(12		)	14			201			83
Change in fair value of derivatives		412			(428		)	1,154			(1,088		)
Other		(1,239		)	55			(1,356		)	1,760
Total other income (expense)		(1,536		)	(1,441		)	(2,551		)	(2,179		)
Income (loss) before income taxes		11,534			(2,810		)	45,510			(5,713		)
Income tax expense (benefit)		3,980			(644		)	14,524			(1,742		)
Income (loss) from continuing operations		7,554			(2,166		)	29,986			(3,971		)
Cumulative effect of accounting change, net of tax		—			—			207			—
Income from discontinued operations, net of tax		—			1,196			—			1,335
NET INCOME (LOSS)		$	7,554		$	(970	)	$	30,193		$	(2,636	)
Net income (loss) per common share:
Basic:
Income (loss) from continuing operations		$	.81		$	(0.23	)	$	3.22		$	(0.43	)
Net income (loss)		$	.81		$	(0.10	)	$	3.24		$	(0.29	)
Diluted:
Income (loss) from continuing operations		$	.79		$	(0.23	)	$	3.17		$	(0.43	)
Net income (loss)		$	.79		$	(0.10	)	$	3.19		$	(0.29	)
Weighted average common shares outstanding:
Basic		9,330			9,255			9,318			9,231
Diluted		9,565			9,255			9,463			9,231

 

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

 

4

 

CLAYTON WILLIAMS ENERGY, INC.

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY

(Unaudited)

(In thousands)

 

		Common Stock					Additional Paid-In Capital			Retained Earnings			Accumulated Other Compre - hensive Income (Loss)			Total Compre - hensive Income
		No. of Shares		Par Value
BALANCE, December 31, 2002		9,277		$	928		$	72,787		$	3,016		$	(7,950	)
Net income		—		—			—			30,193			—			$	30,193
Change in fair value of derivatives designated as cash flow hedges, net of tax		—		—			—			—			6,551			6,551
Total comprehensive income																$	36,744
Issuance of stock through compensation plans		78		7			927			—			—
BALANCE, September 30, 2003		9,355		$	935		$	73,714		$	33,209		$	(1,399	)

 

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

 

5

 

CLAYTON WILLIAMS ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In thousands)

 

		Nine Months Ended September 30,
		2003			2002
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)		$	30,193		$	(2,636	)
Adjustments to reconcile net income (loss) to cash provided by operating activities:
Depreciation, depletion and amortization		31,279			21,472
Impairment of proved properties		170			—
Exploration costs		17,347			15,308
Gain or loss on sales of property and equipment		(201		)	(83		)
Deferred income taxes		13,989			(1,742		)
Non-cash employee compensation		738			517
Change in fair value of derivatives		(981		)	1,185
Accretion of abandonment obligations		477			—
Cumulative effect of accounting change, net of tax		(207		)	—
Non-cash effect of discontinued operations, net of tax		—			(1,029		)
Changes in operating working capital:
Accounts receivable		(857		)	(4,182		)
Accounts payable		5,651			(3,405		)
Other		1,247			(5,229		)
Net cash provided by operating activities		98,845			20,176
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to property and equipment		(49,931		)	(58,635		)
Proceeds from sales of property and equipment		236			7,325
Other		(407		)	(105		)
Net cash used in investing activities		(50,102		)	(51,415		)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt		—			31,940
Repayments of long-term debt		(43,956		)	—
Proceeds from sale of common stock		243			36
Repurchase and cancellation of common stock		—			(648		)
Net cash provided by (used in) financing activities		(43,713		)	31,328
NET INCREASE IN CASH AND CASH EQUIVALENTS		5,030			89
CASH AND CASH EQUIVALENTS
Beginning of period		5,676			2,856
End of period		$	10,706		$	2,945
SUPPLEMENTAL DISCLOSURES
Cash paid for interest, net of amounts capitalized		$	2,587		$	2,675

 

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

 

6

 

CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2003

(Unaudited)

 

1.                                      Nature of Operations

 

Clayton Williams Energy, Inc. (a Delaware corporation) and its subsidiaries (collectively, the “Company”) is an independent oil and gas company engaged in the exploration for and development and production of oil and natural gas primarily in Texas, Louisiana, New Mexico and Mississippi.  Approximately 50% of the Company’s common stock is beneficially owned by its Chairman of the Board and Chief Executive Officer, Clayton W. Williams (“Mr. Williams”).  Oil and gas exploration and production is the only business segment in which the Company operates.

 

Substantially all of the Company’s oil and gas production is sold under short-term contracts which are market-sensitive.  Accordingly, the Company’s financial condition, results of operations, and capital resources are highly dependent upon prevailing market prices of, and demand for, oil and natural gas.  These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond the control of the Company.  These factors include the level of global demand for petroleum products, foreign supply of oil and gas, the establishment of and compliance with production quotas by oil-exporting countries, weather conditions, the price and availability of alternative fuels, and overall economic conditions, both foreign and domestic.

 

2.                                      Presentation

 

The preparation of these consolidated financial statements in conformity with accounting principles generally accepted in the United States requires management of the Company to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.  Actual results could differ materially from those estimates.

 

In the opinion of management, the Company’s unaudited consolidated financial statements as of September 30, 2003 and for the interim periods ended September 30, 2003 and 2002 include all adjustments which are necessary for a fair presentation in accordance with accounting principles generally accepted in the United States.  These interim results are not necessarily indicative of the results to be expected for the year ending December 31, 2003.

 

Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States have been condensed or omitted in this Form 10-Q pursuant to the rules and regulations of the Securities and Exchange Commission.  These consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto included in the Company’s 2002 Form 10-K.

 

3.                                      Accounting Pronouncements

 

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

 

7

 

$477,000 of accretion expense.  Pro forma adjustments to income from continuing operations for the three-month and nine-month periods ended September 30, 2003 and 2002, assuming SFAS 143 had been applied in each period, were insignificant.

 

In May 2003, the FASB issued Statement of Financial Accounting Standards No. 150 “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity” (“SFAS 150”). This statement establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity and requires that an issuer classify a financial instrument that is within its scope as a liability (or an asset in certain circumstances). SFAS 150 is effective at the beginning of the first interim period beginning after June 15, 2003 for financial instruments entered into or modified after May 31, 2003. The Company’s adoption of SFAS 150 did not have a material effect on its consolidated financial position or results of operations.

 

4.                                      Long-Term Debt

 

Long-term debt consists of the following:

 

		September 30, 2003			December 31, 2002
		(In thousands)
Secured Bank Credit Facility (matures December 31, 2004)		$	50,000		$	93,000
Vendor finance obligations		5,756			1,949
		55,756			94,949
Less current maturities of vendor finance obligations		1,303			—
		$	54,453		$	94,949

 

Secured Bank Credit Facility

The Company’s secured bank credit facility provides for a revolving loan facility in an amount not to exceed the lesser of the borrowing base, as established by the banks, or that portion of the borrowing base determined by the Company to be the elected borrowing limit.  The borrowing base, which is based on the discounted present value of future net revenues from oil and gas production, is subject to redetermination at any time, but at least semi-annually in May and November, and is made at the discretion of the banks.  If, at any time, the redetermined borrowing base is less than the amount of outstanding indebtedness, the Company will be required to (i) pledge additional collateral, (ii) prepay the excess in not more than five equal monthly installments, or (iii) elect to convert the entire amount of outstanding indebtedness to a term obligation based on amortization formulas set forth in the loan agreement.  Substantially all of the Company’s oil and gas properties are pledged to secure advances under the credit facility.

 

At September 30, 2003, the borrowing base established by the banks was $110 million, with no monthly commitment reductions.  After allowing for outstanding letters of credit totaling $4.3 million, the Company had $55.7 million available under the credit facility at September 30, 2003.

 

All outstanding balances on the credit facility may be designated, at the Company’s option, as either “Base Rate Loans” or “Eurodollar Loans” (as defined in the loan agreement), provided that not more than two Eurodollar Loans 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, 2003, the Company’s indebtedness under the credit facility consisted of $50 million of Eurodollar Loans at a rate of 2.6%.  The effective annual interest rate on the credit facility, including bank fees and interest rate derivatives, for the nine months ended September 30, 2003 was 5.4%.

 

8

 

In addition, the Company pays the banks a commitment fee ranging from .25% to .38% per annum on the unused portion of the revolving loan commitment.  Interest on the revolving loan and commitment fees are payable quarterly, and all outstanding principal and interest will be due December 31, 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 September 30, 2003.

 

Vendor Finance Obligations

In August 2002, the Company initiated a vendor financing arrangement for wells to be drilled in South Louisiana whereby all costs of participating vendors, including interest at an annual rate of 9%, will be repaid out of a percentage of the net revenues from the wells drilled under the arrangement.  If net revenues are insufficient to repay financed costs within an 18-month period from the invoice date, the Company has agreed to repay any unpaid balance.

 

5.                                      Other Non-Current Liabilities

 

Other non-current liabilities consist of the following:

 

		September 30, 2003			December 31, 2002
		(In thousands)
Abandonment obligations		$	8,831		$	3,500
Production payment		735			1,000
		$	9,566		$	4,500

 

Abandonment Obligations

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

 

Production Payment

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

 

6.                          Compensation Plans

 

Executive Stock Compensation Plan

The Company has reserved 500,000 shares of common stock for issuance under the Executive Incentive Stock Compensation Plan, permitting the Company, at its discretion, to pay all or part of selected executives’ salaries in shares of common stock in lieu of cash.  During the nine months ended September 30, 2003, the Company issued 11,266 shares of common stock to Mr. Williams in lieu of net cash compensation aggregating $171,000, which is included in general and administrative expenses in the accompanying consolidated financial statements.  Subsequent to September 30, 2003, the Company issued an additional 942 shares to Mr. Williams in lieu of cash compensation aggregating $19,000.

 

Stock-Based Compensation

The Company accounts for stock-based compensation utilizing the intrinsic value method prescribed by Accounting Principles Board Opinion No. 25 “Accounting for Stock Issued to Employees”

 

9

 

(“APB 25”) and related interpretations.  The following pro forma information, as required by Statement of Financial Accounting Standards No. 123 “Accounting for Stock-Based Compensation” (“SFAS 123”), as amended by Statement of Financial Accounting Standards No. 148 (“SFAS 148”), presents net income and earnings per share information as if the stock options issued since December 31, 1994 were accounted for using the fair value method.  The fair value of stock options issued for each year was estimated at the date of grant using the Black-Scholes option pricing model.  No options were granted during 2003 and 2002.

 

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

 

 

In accordance with Financial Accounting Standards Board Interpretation No. 44 (“FIN 44”) to APB 25, the Company changed the classification of 233,141 stock options repriced by the Company in April 1999 from fixed stock options to variable stock options.  The Company is required to recognize compensation expense on the repriced options to the extent that the quoted market value of the Company’s common stock at the end of each period exceeds the amended option price ($5.50 per share), except that options vested as of July 1, 2000 must recognize compensation expense only to the extent that the quoted market value exceeds the market value on July 1, 2000 ($31.94 per share).  The Company’s closing market price at September 30, 2003 was $18.88.  Accordingly, general and administrative expenses for the nine months ended September 30, 2003 and 2002 included a non-cash charge of $380,000 and a non-cash credit of $247,000, respectively, related to stock-based employee compensation.  As the repriced options are exercised, the cumulative amount of accrued compensation expense will be credited to additional paid-in capital.  Since this provision is based on changes in the quoted market value of the Company’s common stock, the Company’s future results of operations may be subject to significant volatility.

 

In October 2003, the Company granted options to purchase 200,000 shares to Mr. Williams.  The options are fully exercisable at an option price of $19.74, which was the market price on the date of the grant.

 

Working Interest Trusts

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

 

10

 

After-Payout Working Interest Incentive Plans

The Compensation Committee of the Board of Directors, in September 2002, adopted an incentive plan for officers, key employees and consultants, excluding Mr. Williams, who promote the Company’s drilling and acquisition programs.  Management’s objective in adopting this plan is to further align the interests of the participants with those of the Company by granting the participants an after-payout working interest in the production developed, directly or indirectly, by the participants.  The plan provides for the creation of a series of limited partnerships to which the Company, as general partner, contributes a portion of its working interest in wells drilled within certain areas, and the key employee and consultants, as limited partners, contribute cash.  The Company pays all costs and receives all revenues until payout of its costs, plus interest.  At payout, the limited partners receive 99% of all subsequent revenues and pay 99% of all subsequent expenses attributable to the partnerships’ interests.

 

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

 

7.                                      Derivatives

 

Commodity Derivatives

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

 

The following summarizes information concerning the Company’s net positions in open commodity derivatives as of September 30, 2003.

 

 

 

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

 

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Interest Rate Derivatives

In November 2001, the Company entered into an interest rate swap on $50 million of its long-term bank debt designated as Eurodollar Loans (see Note 4).  The swap provides for the Company to pay a fixed rate of 3.63% for the two-year term of the swap.  The counterparty will pay a floating rate based on the LIBOR-BBA one-month rate.  The swap requires a monthly cash settlement for the difference between the fixed rate and the floating rate.

 

Accounting For Derivatives

The Company accounts for its derivatives in accordance with Statement of Financial Accounting Standards No. 133 “Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”), as amended.  The following table sets forth, for the nine months ended September 30, 2003, the components of accumulated other comprehensive income, as reported in stockholders’ equity, all of which is related to derivatives designated as cash flow hedges under SFAS 133.

 

 

During the twelve months subsequent to September 30, 2003, the Company expects to reclassify the remaining balance of $1.4 million of net deferred losses associated with open cash flow hedges from accumulated other comprehensive income to earnings.

 

The Company did not designate the gas collar derivatives as cash flow hedges under SFAS 133; therefore, all changes in the fair value of these contracts prior to maturity, plus any realized gains or losses at maturity, are recorded as other income (expense) in the accompanying statements of operations.

 

Margin Calls

The ISDA master agreement between the Company and one of its principal derivative counterparties gives either party the right to request credit support (a “Margin Call”) to the extent that the fair value of the derivatives exceeds specified credit limits.  Currently, the Company’s credit limit under the master agreement is $5 million, subject to reduction or elimination if the Company’s net assets are less than $65 million or if the counterparty has reasonable grounds for insecurity.  During the quarter ended September 30, 2003, the counterparty refunded to the Company all previous Margin Calls totaling an aggregate of $4 million.

 

8.                                      Financial Instruments

 

Cash and cash equivalents, receivables, accounts payable and accrued liabilities were each estimated to have a fair value approximating the carrying amount due to the short maturity of those instruments.  Indebtedness under the secured bank credit facility was estimated to have a fair value approximating the carrying amount since the stated interest rate is generally market sensitive.  Abandonment obligations are carried at net present value which approximates their fair value since the discount rate is based on the Company’s credit-adjusted, risk-free rate.  Vendor finance and production payment obligations, in the aggregate, have an estimated fair value of $7 million based on the net present value of future cash outflows and using assumptions for timing of payments and discount rates that the Company considers appropriate.

 

12

 

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

 

 

9.                                      Income Taxes

 

Deferred tax assets and liabilities are the result of temporary differences between the financial statement carrying values and the tax bases of assets and liabilities.  Significant components of net deferred tax assets at September 30, 2003 and December 31, 2002 are as follows:

 

 

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

 

 

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The Company derives an income tax benefit when employees and directors exercise options granted under the Company’s stock compensation plans (see Note 6).  Employee stock options that are classified as fixed stock options under APB 25 do not result in a charge against book income when the option price is equal to or greater than the market price at date of grant.  Therefore, any tax benefit from the exercise of fixed stock options results in a permanent difference, which is recorded to additional paid-in capital when the tax benefit is realized.

 

During 2003, the Company’s pre-tax income was sufficient to cause deferred tax liabilities to exceed deferred tax assets.  Based upon current commodity prices and production volumes, as well as the availability of tax planning strategies (such as elective capitalization of intangible drilling costs), the Company presently believes that it is more likely than not that the Company will be able to utilize its cumulative tax loss carryforwards of $37.3 million at December 31, 2002 before they expire (beginning in 2008).  Accordingly, during the quarter ended June 30, 2003, the Company reversed $876,000 of the valuation allowances provided at December 31, 2002, $5,000 of which was related to permanent differences arising from the exercise of employee stock options.

 

10.                               Stock Repurchase Program

 

In July 2002, the Company’s Board of Directors authorized the continuation of a stock repurchase program initiated in July 2000.  Under this program, the Company is authorized to spend up to $3 million to repurchase shares of its common stock on the open market at times and prices deemed appropriate by the Company’s management.  This authorization expires in July 2004.  To date, the Company has spent $1.4 million to repurchase and cancel 115,100 shares of common stock.  No shares were repurchased during the nine months ended September 30, 2003.

 

11.                               Purchases and Sales of Assets

 

In July 2002, the Company purchased all of the working interest in the Romere Pass Unit in the Plaquemines Parish, Louisiana for total consideration of $21.2 million, net of closing adjustments.  The effective date of the purchase for accounting purposes was August 1, 2002.  The purchase price consisted of $17 million cash, the assumption of future abandonment obligations and the granting of a $1 million after-payout production payment.  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 $1.8 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:

 

 

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12.                               Contingency

 

Legal Proceedings

The Company is a defendant in a personal injury suit filed in the 38th Judicial District Court in Cameron Parish, Louisiana in 2002.  The plaintiff, an employee of one of the Company’s subcontractors, claims he was injured while working on a barge drilling rig owned and operated by another subcontractor, Parker Drilling Company (“PDC”).  PDC was also named as a defendant in the suit.  Robert L. Parker is the Chairman of the Board of Directors of PDC and is a member of our Board of Directors.  The plaintiff has not yet specified the amount of damages sought.  Trial of this case is set for March 2004.  Initially, there were uncertainties concerning the extent of insurance coverage available to the Company and the insurance available through contractual arrangements with the other parties.  Many of these uncertainties have been resolved, and the Company currently believes that insurance coverage will be adequate to protect the Company from any material liability in connection with this suit.

 

The Company is a defendant in a suit filed in the 82^nd Judicial District Court in Robertson County, Texas by lessors of the lease on which its Lee Fazzino Unit #1 and #2 wells (the “Wells”) were drilled.  In November 2003, the Company and the lessors entered into a letter of intent to settle this litigation.  Under the terms of the letter of intent, the Company will (i) grant the lessor a 1.2% overriding royalty interest in the Wells, which interest reduces to 1% after 24 months and (ii) pay the lessors $400,000 in cash.  The Company has also agreed to reimburse those royalty owners in the Wells whose interests were aligned with the Company in the suit for certain of their attorney fees incurred in connection with the litigation.  The lessors will (i) grant a new lease to the Company for approximately 500 net acres, (ii) ratify all existing leases and the unit agreement, and (iii) execute a release of any and all claims with regard to the leases, Wells and unit agreement.  The Company recorded a $1.3 million pre-tax charge against earnings during the third quarter of 2003 for the settlement of this litigation.  The charge is reported in other income (expense) in the accompanying statement of operations.  Although the Company believes that this litigation will ultimately be settled on terms substantially similar to those contained in the letter of intent, the suit will not be dismissed until all parties have executed the definitive settlement documents.

 

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

 

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

 

The following discussion is intended to help you understand the historical consolidated financial position of Clayton Williams Energy, Inc. (the “Company”, “CWEI”, “we”, “us”, or “our”) at September 30, 2003, and our results of operations and cash flows for each of the periods ended September 30, 2003 and 2002.  Our historical consolidated financial statements and notes thereto included in this Form 10-Q contain detailed information that you should consider in conjunction with this discussion.  You should read this discussion in connection with our Form 10-K for the year ended December 31, 2002 and the consolidated financial statements and notes included in this Form 10-Q, and our most recent guidance filed on Form 8-K.

 

Special Note Regarding Forward-Looking Statements

 

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

 

Overview

 

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

 

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

 

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

 

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Application of Critical Accounting Policies

 

Summary

 

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

 

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

 

 

*                      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.

 

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

 

Valuation of unproved properties

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

 

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

 

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

 

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

 

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

 

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

 

Valuation allowance for NOL carryforwards

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

 

Effects of Estimates and Assumptions on Financial Statements

 

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

 

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

 

Provision for DD&A

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

 

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

 

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

 

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

 

Impairment of Unproved Properties

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

 

Impairment of Proved Properties

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

 

Judgment Regarding Status of In-Progress Wells

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

 

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

 

Valuation allowance for NOL carryforwards

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

 

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

 

Recent Development

 

In its recent review of registrants’ filings, the staff of the Securities and Exchange Commission (“SEC”) has questioned the applicability of SFAS No. 142, “Goodwill and Other Intangible Assets” (“SFAS 142”) to lease agreements and drilling rights commonly utilized in the oil and gas industry.  If applicable, SFAS 142 could require oil and gas companies to separately report on their balance sheets the costs of proved and unproved leasehold and mineral interests acquired after June 30, 2001, including related accumulated depletion, as intangible assets and provide related intangible asset disclosures.  Oil and gas companies have generally included leasehold costs in the property and equipment caption on the balance sheet since the value of the proved leases is inseparable from the value of the related oil and gas reserves, and since the costs of unproved leasehold and mineral interests are regularly evaluated for impairment based on lease terms and drilling activity.  The Emerging Issues Task Force has recently added this issue to its agenda.  If SFAS 142 is determined to apply to oil and gas companies, we may be required to make certain reclassifications within property and equipment on the balance sheet, and additional disclosures may be required.  As currently proposed by the SEC, we do not believe that such implementation would have an effect on future earnings.

 

Liquidity and Capital Resources

 

Overview

 

Our primary financial resource is our base of oil and gas reserves.  We pledge our producing oil and gas properties to secure a line of credit, called a Credit Facility, with a group of banks.  The banks establish a borrowing base by making an estimate of the collateral value of our oil and gas properties.  We borrow funds on the Credit Facility as needed to supplement our operating cash flow as a financing source for our capital expenditure program. Our capital expenditure program is dependent upon the level of product prices and the success of our exploration program in replacing our existing oil and gas reserves.  If product prices decrease, our operating cash flow may decrease and the banks may require additional collateral or reduce our borrowing base, thus reducing funds available to fund our capital expenditure program.  The effects of product prices on cash flow can be mitigated through the use of commodity derivatives (see “Quantitative and Qualitative Disclosure About Market Risks – Oil and Gas Prices”).  We may also suffer a reduction in our operating cash flow and access to funds under the Credit Facility if our exploration program does not replace our oil and gas reserves.  Under extreme circumstances, product price reductions or exploration

 

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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 $76 million on exploration and development activities during 2003, of which $47 million has been incurred through September 30, 2003.  The following table sets forth, by area, certain information about our actual and planned exploration and development activities for 2003.

 

 

Since our previous quarterly report, we have increased our estimate of planned expenditures for 2003 by $14.1 million, of which $13.6 million was related to additional planned activity in South Louisiana.  Earlier in 2003, we slowed the pace of our exploratory drilling activities in South Louisiana in order to accelerate repayment of our bank debt and improve our debt-to-equity ratio.  We believe that we have now accomplished our objectives.  Since March 31, 2003, we have reduced our bank debt from $91 million to $50 million while our stockholders’ equity has increased from $85.5 million to $106.5 million.  Accordingly, we accelerated our South Louisiana drilling activities in the fourth quarter of 2003.

 

Approximately 85% of the actual and planned expenditures shown in the preceding table relate to exploratory prospects.  Exploratory prospects involve a higher degree of risk than developmental prospects.  To offset the higher risk, we generally strive to achieve a higher reserve potential and rate of return on investments in exploratory prospects.  Actual expenditures during 2003 may be substantially higher or lower than these estimates as our plans for exploration and development activities change during the year.  We do not attempt to forecast our success rate on exploratory drilling.  Accordingly, these current estimates do not include any costs we may incur to complete our successful exploratory wells and construct the required production facilities for these wells.  Also, we are actively searching for other opportunities to increase our oil and gas reserves, including the evaluation of new prospects for exploratory and developmental drilling activities and potential acquisitions of proved oil and gas reserves.  Other factors, such as prevailing product prices and the availability of capital resources, could also increase or decrease the ultimate level of expenditures during 2003.

 

Credit Facility

 

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

 

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At the beginning of 2003, we had an outstanding balance on the Credit Facility of $93 million, and the borrowing base was $110 million, leaving $12.7 million available, after allowing for $4.3 million of outstanding letters of credit.  During the nine months ended September 30, 2003, we generated cash flow from operating activities of $98.8 million, spent $50.1 million on capital expenditures and other investing activities and repaid $43 million on the Credit Facility and $1 million on vendor finance obligations.  The outstanding balance on the Credit Facility at September 30, 2003 was $50 million, leaving $55.7 million available on the Credit Facility, after allowing for $4.3 million of outstanding letters of credit.

 

Using the Credit Facility for both our short-term liquidity and long-term financing needs can cause unusual fluctuations in our reported working capital, depending on the timing of cash receipts and expenditures.  On a daily basis, we use most of our available cash to pay down our outstanding balance on the Credit Facility, which is classified as a non-current liability since we currently have no required principal reductions.  As we use cash to pay a non-current liability, our reported working capital decreases.  Conversely, as we draw on the Credit Facility for funds to pay current liabilities (such as payables for drilling and operating costs), our reported working capital increases.  Also, volatility in oil and gas prices can cause significant fluctuations in reported working capital as we record changes in the fair value of derivatives from period to period.  For these reasons, the working capital covenant related to the Credit Facility requires us to (i) include the amount of funds available on the Credit Facility as a current asset, and (ii) exclude current assets and liabilities related to the fair value of derivatives, when computing the working capital ratio at any balance sheet date.

 

Our reported working capital at September 30, 2003 was a deficit of $2.4 million, as compared to a deficit of $18.8 million at December 31, 2002.  Giving effect to the above adjustments, our working capital for loan compliance purposes is a positive $55.2 million at September 30, 2003, as compared to a positive $6.8 million at December 31, 2002.  Although working capital computed for loan compliance purposes differs from our working capital in accordance with generally accepted accounting principles (GAAP), the loan compliance working capital is useful in measuring our liquidity since it includes the resources available to us under the Credit Facility and negates the volatility in working capital caused by changes in fair value of derivatives.  The following table reconciles our GAAP working capital to the working capital computed under the loan covenant at September 30, 2003 and December 31, 2002.

 

 

The banks redetermine the borrowing base at least twice a year, in May and November, using the method described below.  Although the banks have not completed the borrowing base review for November 2003, we are expecting a 10% to 20% reduction in the borrowing base for the next six-month period based on our internal estimates.  However, we do not expect the reduction to have a material impact on our liquidity and capital resources.  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, 2003.

 

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Uncertainties Regarding Liquidity and Capital Resources

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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Alternative Capital Resources

 

Although our base of oil and gas reserves, as collateral for the Credit Facility, has historically been our primary capital resource, we have in the past, and could in the future, use alternative capital resources, such as asset sales, vendor financing arrangements, and/or issuances of common stock through a secondary public offering or a rights offering.  We could also issue subordinated debt or preferred stock in a public or a private placement if we choose to raise capital through either of these markets.  While we believe we would be able to obtain funds through one or more of these alternatives, if needed, there can be no assurance that these capital resources would be available on terms acceptable to us.

 

Off-Balance Sheet Arrangement

 

In May 2001, we invested approximately $1.6 million as a limited partner in a partnership formed to purchase and operate two commercial office buildings in Midland, Texas, one of which is the location of our corporate headquarters.  Our ownership interest in the partnership is 31.9% before payout (as defined in the partnership agreement) and 33.4% after payout.  Substantially all of the partnership’s indebtedness is non-recourse, and we are not liable for any indebtedness of the partnership.  An affiliate of Clayton W. Williams (“Mr. Williams”) serves as general partner of the partnership.  We do not manage or control the operations of the partnership or these buildings.  We currently utilize the equity method of accounting for our investment in this partnership.  Under the provisions of SFAS Interpretation No. 46 “Consolidation of Variable Interest Entities” (“FIN 46”), we do not believe we will be classified as the primary beneficiary based on aggregation rules affecting related parties.  However, we are still evaluating the impact of FIN 46 on our accounting for this partnership.  We must adopt FIN 46 during the fourth quarter of 2003.

 

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Results of Operations

 

The following table sets forth certain operating information of the Company for the periods presented.  Periods prior to 2003 have been adjusted to account for the sale of certain oil and gas properties in 2002 as discontinued operations (see Note 11 to the accompanying consolidated financial statements).  See “Application of Critical Accounting Policies” for an explanation of the accounting policies described in this discussion.

 

 

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

(2)                                  Includes only gains (losses) from derivatives designated as cash flow hedges.

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

 

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

 

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

 

Revenues

 

Oil and gas sales increased 71% from $22.2 million in 2002 to $38 million in 2003 due primarily to a 58% increase in average gas prices received and a 31% increase in gas production.  A substantial portion of the gas production increase was due to production increases from the Cotton Valley Reef Complex area and production from wells in south Louisiana that were not producing in 2002.  Oil production was constant but average oil prices realized increased by 17%.

 

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Costs and Expenses

 

Lease operations expenses increased 41% from $5.1 million in 2002 to $7.2 million in 2003 due primarily to the effects that higher oil and gas prices had on production taxes and higher operating expenses associated with South Louisiana production.  Oil and gas production on a Mcfe basis increased 21% while production costs on a Mcfe basis increased 17% from $.72 in 2002 to $.84 in 2003.

 

Exploration costs totaled $5.4 million in 2003, as compared to $8.8 million in 2002, due to the following:

 

•                  $4 million of abandonments (dry hole costs) and unproved property impairments, including $1.9 million related to prospects in Plaquemines Parish, Louisiana, $1.4 million related to the Cotton Valley Reef Complex, and $500,000 for three non-operated wells in West Texas; and

 

•                  $1.4 million of seismic and other exploration costs related primarily to the acquisition, processing and interpretation of 3-D seismic data, including $1 million in south Louisiana and $100,000 in Mississippi.

 

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

 

Depreciation, depletion and amortization expense increased 33% from $7.6 million in 2002 to $10.1 million in 2003 due primarily to a 21% increase in production on an Mcfe basis. Under the successful efforts method of accounting, costs of oil and gas properties are amortized on a unit-of-production method based on estimated proved reserves. The average depletion rate per Mcfe increased from $1.03 in 2002 to $1.11 in 2003.

 

We recorded a provision for impairment of property and equipment of $170,000 during 2003 associated with the Sweetlake area of southwest Louisiana since the carrying costs of these properties exceeded their fair value.  No corresponding impairment was needed in 2002.

 

During the third quarter 2003, we recorded $171,000 of expense for accretion of abandonment obligations in accordance with Statement of Financial Accounting Standards No. 143 “Accounting for Asset Retirement Obligations” (“SFAS 143”), which we adopted January 1, 2003 (see Note 3 to the accompanying consolidated financial statements).

 

General and administrative expenses (“G&A”), excluding certain non-cash stock-based employee compensation, decreased 13% from $2.3 million in 2002 to $2 million in 2003.  The decrease was primarily due to lower franchise taxes, offset in part by higher insurance costs and professional fees.  G&A expenses for 2003 also include a non-cash charge of $33,000 for stock-based employee compensation required by Financial Accounting Standards Board Interpretation No. 44 (see Note 6 to the accompanying consolidated financial statements).  A $178,000 credit (reduction of expense) was required for the 2002 period.  Since the amount of this non-cash provision or credit is based on the quoted market value of our common stock, the future results of our operations may be subject to significant volatility.

 

Interest Expense and Other

 

Interest expense decreased 37% from $1.1 million in 2002 to $697,000 in 2003 due to a combination of factors.  The average daily principal balance outstanding on the Credit Facility for 2003 was $59.2 million compared to $92.1 million in the 2002 period.  The effective annual interest rate on bank debt, including bank fees and interest rate derivatives, during 2003 was 5.8% compared to 5.3% in 2002.  Included in the computation of our effective annual interest rate are losses on interest rate derivatives of

 

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$326,000 in 2003 and $231,000 in 2002 (see Note 7 to the accompanying consolidated financial statements).  Capitalized interest for 2003 was $299,000 compared to $172,000 in 2002.

 

We reported a net gain on the change in fair value of derivatives of $412,000 during the 2003 period compared to a $428,000 net loss in 2002 in accordance with Statement of Financial Accounting Standards No. 133 “Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”).  Since we did not designate gas collars as cash flow hedges under SFAS 133, all subsequent changes in fair value of these contracts prior to maturity, plus any realized gain or losses at maturity, will be recorded as other income in future periods (see Note 7 to the accompanying consolidated financial statements).  This may subject our future results of operations to significant volatility.  Also included in other income (expense) for 2003 is $1.3 million for the estimated costs to settle the legal dispute with lessors of the lease on which the Lee Fazzino #1 and #2 wells are drilled.

 

Income Taxes

 

During 2003, we recorded income tax expense of $4 million, as compared to $644,000 in 2002 (see Note 9 to the accompanying consolidated financial statements).

 

Nine Months Ended September 30, 2003 Compared to September 30, 2002

 

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

 

Revenues

 

Oil and gas sales increased 118% from $59.6 million in 2002 to $129.8 million in 2003 due primarily to a 68% increase in average gas prices received and a 82% increase in gas production.  A substantial portion of the gas production increase was due to production increases from the Cotton Valley Reef Complex area and production from wells in south Louisiana that were not producing in 2002, including the Romere Pass Unit acquired in July 2002.  Oil production fell by 4%, which was more than offset by a 25% increase in the average oil prices realized.

 

Costs and Expenses

 

Lease operations expenses increased 42% from $15.1 million in 2002 to $21.5 million in 2003 due primarily to the effects that higher oil and gas prices had on production taxes and the addition of operating expenses associated with the Romere Pass Unit acquired in July 2002.  Oil and gas production on a Mcfe basis increased 45% resulting in a reduction in production costs on a Mcfe basis from $.79 in 2002 to $.78 in 2003.

 

Exploration costs totaled $22.8 million in 2003, as compared to $21.2 million in 2002, due to the following:

 

•                  $17.3 million of abandonments (dry hole costs) and unproved property impairments, including $8.7 million related to the Cotton Valley Reef Complex, $6.6 million related to prospects in Plaquemines Parish, Louisiana, $1 million in Mississippi, and $400,000 in Nevada; and

 

•                  $5.5 million of seismic and other exploration costs related primarily to the acquisition, processing and interpretation of 3-D seismic data, including $3.5 million in south Louisiana and $900,000 in Mississippi.

 

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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 expense increased 46% from $21.5 million in 2002 to $31.3 million in 2003 due primarily to a 45% increase in production on an Mcfe basis.  Under the successful efforts method of accounting, costs of oil and gas properties are amortized on a unit-of-production method based on estimated proved reserves. The average depletion rate per Mcfe increased slightly from $1.07 in 2002 to $1.08 in 2003.

 

We recorded a provision for impairment of property and equipment of $170,000 during 2003 associated with the Sweetlake area of southwest Louisiana since the carrying costs of these properties exceeded their fair value.  No corresponding impairment was needed in 2002.

 

During 2003, we recorded $477,000 of expense for accretion of abandonment obligations in accordance with SFAS 143, which we adopted January 1, 2003 (see Note 3 to the accompanying consolidated financial statements).

 

G&A, excluding certain non-cash stock-based employee compensation, increased 8% from $6.1 million in 2002 to $6.6 million in 2003.  The increase was primarily due to higher personnel costs, professional fees and rising insurance costs.  G&A expenses for 2003 include a non-cash charge of $380,000 for stock-based employee compensation required by Financial Accounting Standards Board Interpretation No. 44 (see Note 6 to the accompanying consolidated financial statements).  A $247,000 credit (reduction of expense) was required for the 2002 period.  Since the amount of this non-cash provision or credit is based on the quoted market value of our common stock, the future results of our operations may be subject to significant volatility.

 

Interest Expense and Other

 

Interest expense decreased 10% from $2.9 million in 2002 to $2.6 million in 2003 due to a combination of factors.  The average daily principal balance outstanding on the Credit Facility for 2003 was $78.2 million compared to $81.9 million in the 2002 period.  The effective annual interest rate on bank debt, including bank fees and interest rate derivatives, during 2003 was 5.4% for both periods.  Included in the computation of our effective annual interest rate are losses on interest rate derivatives of $901,000 in 2003 and $676,000 in 2002 (see Note 7 to the accompanying consolidated financial statements).  Capitalized interest for 2003 was $817,000 compared to $413,000 in 2002.

 

We reported a net gain on the change in fair value of derivatives of $1.2 million during the 2003 period compared to a $1.1 million net loss in 2002 in accordance with SFAS 133.  Since we did not designate gas collars as cash flow hedges under SFAS 133, all subsequent changes in fair value of these contracts prior to maturity, plus any realized gain or losses at maturity, will be recorded as other income in future periods (see Note 7 to the accompanying consolidated financial statements).  This may subject our future results of operations to significant volatility.  Also included in other income (expense) for 2003 is $1.3 million for the estimated costs to settle the legal dispute with lessors of the lease on which the Lee Fazzino #1 and #2 wells are drilled.

 

Income Taxes

 

During 2003, we recorded income tax expense of $14.5 million, as compared to a benefit of $1.7 million in 2002 (see Note 9 to the accompanying consolidated financial statements).

 

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Item 3 -                               Quantitative and Qualitative Disclosure About Market Risks

 

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

 

Oil and Gas Prices

 

Our financial condition, results of operations, and capital resources are highly dependent upon the prevailing market prices of, and demand for, oil and natural gas.  These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond our control.  These factors include the level of global demand for petroleum products, foreign supply of oil and gas, the establishment of and compliance with production quotas by oil-exporting countries, weather conditions, the price and availability of alternative fuels, and overall economic conditions, both foreign and domestic.  We cannot predict future oil and gas prices with any degree of certainty.  Sustained weakness in oil and gas prices may adversely affect our financial condition and results of operations, and may also reduce the amount of net oil and gas reserves that we can produce economically.  Any reduction in reserves, including reductions due to price fluctuations, can reduce the borrowing base under the Credit Facility and adversely affect our liquidity and our ability to obtain capital for our exploration and development activities.  Similarly, any improvements in oil and gas prices can have a favorable impact on our financial condition, results of operations and capital resources.  Based on December 31, 2002 reserve estimates, we project that a $1 drop in the price per Bbl of oil and a $.50 drop in the price per Mcf of gas would reduce our gross revenues in 2003 by $12.6 million, before giving effect to hedging activities.

 

From time to time, we utilize commodity derivatives, consisting primarily of swaps, to attempt to optimize the price received for our oil and natural gas production.  When using swaps to hedge oil and natural gas production, we receive a fixed price for the respective commodity and pay a floating market price as defined in each contract (generally NYMEX futures prices), resulting in a net amount due to or from the counterparty.  In the past we have used collars which contain a fixed floor price (put) and ceiling price (call).  If the market price for the respective commodity exceeds the call strike price or falls below the put strike price, then we receive the fixed price and pay the market price.  If the market price is between the call and the put strike prices, then no payments are due from either party.  The commodity derivatives we use differ from futures contracts in that there is not a contractual obligation that requires or permits the future physical delivery of the hedged products.  In addition, we may from time to time sell a portion of our gas production under short-term contracts at a fixed price.  We do not enter into commodity derivatives for trading purposes.

 

We attempt to optimize the price we receive for our oil and gas production while maintaining a prudent hedging program to mitigate our exposure to declining product prices.  This strategy means that within the framework of a comprehensive hedging program, we sometimes selectively terminate hedges when we believe that market indications point towards upward price potential which could not be realized with the hedge in place.  While we attempt to make informed market decisions on the termination of hedges, this strategy may sometimes expose us to downside risk that would not have existed otherwise.

 

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The following summarizes information concerning the Company’s net positions in open commodity derivatives as of September 30, 2003.

 

 

 

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

 

We use a sensitivity analysis technique to evaluate the hypothetical effect that changes in the market value of oil and gas may have on the fair value of our commodity derivatives.  The fair values of swaps react differently to changes in oil and gas prices than the fair value of collars.  A 10% increase in the underlying commodity prices would have changed the fair value of our oil and gas swaps at September 30, 2003 from a liability of $1.7 million to a liability of $3.2 million.  With regard to our position in gas collars at September 30, 2003, a $.50 per MMBtu increase in gas prices would have resulted in a decrease in fair value of approximately $2.7 million, while a $.50 per MMBtu decrease in gas prices would have resulted in an increase in fair value of approximately $3 million.

 

Interest Rates

 

All of the Company’s outstanding indebtedness at September 30, 2003 is subject to market rates of interest as determined from time to time by the banks pursuant to the Credit Facility.  We may designate borrowings under the Credit Facility as either “Base Rate Loans” or “Eurodollar Loans.”  Base Rate Loans bear interest at a fluctuating rate that is linked to the discount rates established by the Federal Reserve Board.  Eurodollar Loans bear interest at a fluctuating rate that is linked to LIBOR.  Any increases in these interest rates can have an adverse impact on our results of operations and cash flow.  Prompted by declining interest rates during 2001, we entered into a LIBOR-based swap in November 2001 on $50 million of our indebtedness at a fixed rate of 3.63% for two years.

 

We use a sensitivity analysis technique to evaluate the hypothetical effect that changes in market rates of interest may have on the fair value of our interest rate derivatives.  A 10% decrease in the underlying market interest rates would have changed the fair value of our interest rate derivatives at September 30, 2003 from a liability of $191,000 to a liability of $210,000.

 

Item 4 -                               Controls and Procedures

 

Disclosure Controls and Procedures

 

In September 2002, our Board of Directors adopted a policy designed to establish disclosure controls and procedures that are adequate to provide reasonable assurance that we will be able to collect, process and disclose both financial and non-financial information, on a timely basis, in our reports to the SEC and other communications with our stockholders.  Disclosure controls and procedures include all processes necessary to ensure that material information is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and is accumulated and communicated to

 

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our management, including our chief executive and chief financial officers, to allow timely decisions regarding required disclosures.

 

With respect to our disclosure controls and procedures:

 

•                  We have evaluated the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report;

 

•                  This evaluation was conducted under the supervision and with the participation of our management, including our chief executive and chief financial officers; and

 

•                  It is the conclusion of our chief executive and chief financial officers that these disclosure controls and procedures operate such that material information flows to the appropriate collection and disclosure points in a timely manner and are effective in ensuring that material information is accumulated and communicated to our management and is made known to the chief executive and chief financial officers, particularly during the period in which this report was prepared, as appropriate to allow timely decisions regarding required disclosures.

 

Changes in Internal Control Over Financial Reporting

 

No changes in internal control over financial reporting were made during the quarter ended September 30, 2003 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

 

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PART II.  OTHER INFORMATION

 

Item 1 -                               Legal Proceedings

 

We are a defendant in a personal injury suit filed in the 38th Judicial District Court in Cameron Parish, Louisiana in 2002.  The plaintiff, an employee of one of our subcontractors, claims he was injured while working on a barge drilling rig owned and operated by another subcontractor, Parker Drilling Company (“PDC”).  PDC was also named as a defendant in the suit.  Robert L. Parker is the Chairman of the Board of Directors of PDC and is a member of our Board of Directors.  The plaintiff has not yet specified the amount of damages sought.  Trial of this case is set for March 2004.  Initially, there were uncertainties concerning the extent of insurance coverage available to us, and the insurance available through contractual arrangements with the other parties.  Many of these uncertainties have been resolved, and we currently believe that insurance coverage will be adequate to protect us from any material liability in connection with this suit.

 

We are a defendant in a suit filed in the 82^nd Judicial District Court in Robertson County, Texas by lessors of the lease on which our Lee Fazzino Unit #1 and #2 wells (the “Wells”) were drilled.  In November 2003, we entered into a letter of intent with the lessors to settle this litigation.  Under the terms of the letter of intent, we will (i) grant the lessor a 1.2% overriding royalty interest in the Wells, which interest reduces to 1% after 24 months and (ii) pay the lessors $400,000 in cash.  We have also agreed to reimburse those royalty owners in the Wells whose interests were aligned with ours in the suit for certain of their attorney fees incurred in connection with the litigation.  The lessors will (i) grant a new lease to us for approximately 500 net acres, (ii) ratify all existing leases and the unit agreement, and (iii) execute a release of any and all claims with regard to the leases, Wells and unit agreement.  We recorded a $1.3 million pre-tax charge against earnings during the third quarter of 2003 for the settlement of this litigation.  The charge is reported in other income (expense) in the accompanying statement of operations.  Although we believe that this litigation will ultimately be settled on terms substantially similar to those contained in the letter of intent, the suit will not be dismissed until all parties have executed the definitive settlement documents.

 

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

 

Item 6 -                               Exhibits and Reports on Form 8-K

 

Exhibits
**3.1		Second Restated Certificate of Incorporation of the Company, filed as Exhibit 3.1 to the Company’s Form S-2 Registration Statement, Registration No. 333-13441
**3.2		Certificate of Amendment of Second Restated Certificate of Incorporation of Clayton Williams Energy, Inc., filed as Exhibit 3.1 to the Company’s Form 10-Q for the period ended September 30, 2000
**3.3		Bylaws of the Company, filed as Exhibit 3.4 to the Company’s Form S-1 Registration Statement, Registration No. 33-43350
*31.1		Certification of the Chief Executive Officer of Clayton Williams Energy, Inc.

 

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

 

*		Filed herewith
**		Incorporated by reference to the filing indicated

 

Reports on Form 8-K

 

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

 

•                  Form 8-K dated August 14, 2003 to provide public disclosure of certain financial and operating estimates in order to permit the preparation of models to forecast the Company’s operating results for each quarter during the Company’s fiscal year ending December 31, 2003.

 

•                  Form 8-K dated August 13, 2003 announcing second quarter earnings.

 

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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:  November 10, 2003	By:	/s/ L. Paul Latham
		L. Paul Latham
		Executive Vice President and Chief Operating Officer
Date:  November 10, 2003	By:	/s/ Mel G. Riggs
		Mel G. Riggs
		Senior Vice President and Chief Financial Officer

 

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