Edgar Filing: PREMCOR INC

Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2003

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

Commission File Number	Exact Name of Registrant as Specified in its Charter, Principal Office Address and Telephone Number	State of Incorporation	I.R.S. Employer Identification No.
1-16827	Premcor Inc. 1700 East Putnam Avenue, Suite 500 Old Greenwich, Connecticut 06870 (203) 698-7500	Delaware	43-1851087

1-11392	The Premcor Refining Group Inc. 1700 East Putnam Avenue, Suite 500 Old Greenwich, Connecticut 06870 (203) 698-7500	Delaware	43-1491230

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.

Premcor Inc.		Yes	þ		No	¨
The Premcor Refining Group Inc.		Yes	þ		No	¨

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

Number of shares of the registrant’s common stock (only one class for each registrant) outstanding as of April 15, 2003:

Premcor Inc.		74,085,860 shares
The Premcor Refining Group Inc.		100 shares (100% owned by Premcor USA Inc., a direct wholly owned subsidiary of Premcor Inc.)

Form 10-Q

March 31, 2003

Table of Contents


	PART I. FINANCIAL INFORMATION

Item 1.	Financial Statements (unaudited)

	Premcor Inc.:

	Independent Accountants’ Report	2

	Condensed Consolidated Balance Sheets as of March 31, 2003 and December 31, 2002	3

	Condensed Consolidated Statements of Operations for the Three Months Ended March 31, 2003 and 2002 (as restated)	4

	Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2003 and 2002 (as restated)	5

	The Premcor Refining Group Inc.:

	Independent Accountants’ Report	6

	Condensed Consolidated Balance Sheets as of March 31, 2003 and December 31, 2002	7

	Condensed Consolidated Statements of Operations for the Three Months Ended March 31, 2003 and 2002 (as restated)	8

	Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2003 and 2002 (as restated)	9

	Notes to Consolidated Financial Statements (Premcor Inc. and The Premcor Refining Group Inc. Combined)	10

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	26

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	42

Item 4.	Controls and Procedures	43

	PART II. OTHER INFORMATION

Item 1.	Legal Proceedings	44

Item 2.	Changes in Securities and Use of Proceeds	44

Item 6.	Exhibits and Reports on Form 8-K	45

FORM 10-Q—PART I. FINANCIAL INFORMATION

This Quarterly Report on Form 10-Q represents a combined report for two registrants, Premcor Inc. and its indirectly wholly owned subsidiary The Premcor Refining Group Inc., or PRG. PRG is the principal operating company and together with its wholly owned subsidiary, Sabine River Holding Corp. and its subsidiaries, or Sabine, owns and operates three refineries. Sabine’s principal operating company is Port Arthur Coker Company L.P., or PACC. The results of operations for Premcor Inc. principally reflect the results of operations of PRG, except for some pipeline operations and long-term debt held at Premcor USA Inc., PRG’s parent company, and some general and administrative costs and interest income at stand-alone Premcor Inc. Included in this Quarterly Report on Form 10-Q are balance sheets, statements of operations, and statements of cash flows for the applicable periods for Premcor Inc. and PRG. The information reflected in the combined, consolidated footnotes are equally applicable to both companies except where indicated otherwise.

ITEM 1. FINANCIAL STATEMENTS

INDEPENDENT ACCOUNTANTS’ REPORT

To the Board of Directors of Premcor Inc.:

We have reviewed the accompanying condensed consolidated balance sheet of Premcor Inc. and subsidiaries (the “Company”) as of March 31, 2003 and the related condensed consolidated statements of operations and cash flows for the three-month periods ended March 31, 2003 and 2002. These financial statements are the responsibility of the Company’s management.

We conducted our review in accordance with standards established by the American Institute of Certified Public Accountants. A review of interim financial information consists principally of applying analytical procedures to financial data and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with auditing standards generally accepted in the United States of America, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

Based on our review, we are not aware of any material modifications that should be made to such condensed consolidated financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.

We have previously audited, in accordance with auditing standards generally accepted in the United States of America, the consolidated balance sheet of the Company as of December 31, 2002, and the related consolidated statements of operations, stockholders’ equity, and cash flows for the year then ended (not presented herein); and in our report dated February 14, 2003 (March 6, 2003 as to Note 22)(which report includes an explanatory paragraph relating to the Company’s change in its method of accounting for stock based compensation issued to employees as described in Note 2), we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 2002 is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

Deloitte & Touche LLP

St. Louis, Missouri

April 28, 2003

PREMCOR INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(in millions, except share data)

	March 31,			December 31,
	2003			2002
	(unaudited)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	307.3		$	167.4
Short-term investments		4.9			4.9
Cash and cash equivalents restricted for debt service		53.8			61.7
Accounts receivable, net of allowance of $3.3 and $3.2		520.2			269.1
Inventories		463.4			287.3
Prepaid expenses		78.5			45.9
Assets held for sale		40.2			49.3

Total current assets		1,468.3			885.6
PROPERTY, PLANT AND EQUIPMENT, NET		1,587.3			1,262.6
DEFERRED INCOME TAXES		40.8			57.5
OTHER ASSETS		124.6			117.3

	$	3,221.0		$	2,323.0

LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable	$	721.0		$	466.2
Accrued expenses and other		85.6			57.2
Accrued taxes other than income		41.9			26.3
Current portion of long-term debt		21.2			15.0

Total current liabilities		869.7			564.7
LONG-TERM DEBT		1,154.5			909.9
OTHER LONG-TERM LIABILITIES		144.4			144.4
COMMITMENTS AND CONTINGENCIES		—			—

COMMON STOCKHOLDERS’ EQUITY:
Common, $0.01 par value per share, 150,000,000 authorized, 74,085,860 issued and outstanding in 2003; 58,043,935 issued and outstanding in 2002		0.7			0.6
Paid-in capital		1,173.1			862.3
Accumulated deficit		(121.4	)		(158.9	)

Total common stockholders’ equity		1,052.4			704.0

	$	3,221.0		$	2,323.0

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

PREMCOR INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(unaudited, in millions, except per share data)

	For the Three Months Ended March 31,
	2003			2002
				(as restated, see Note 1)
NET SALES AND OPERATING REVENUES	$	2,376.3		$	1,228.3
EXPENSES:
Cost of sales		2,108.9			1,061.6
Operating expenses		117.2			114.5
General and administrative expenses		11.7			14.5
Stock-based compensation		4.3			1.9
Depreciation		14.6			12.4
Amortization		9.5			9.8
Refinery restructuring and other charges		15.0			142.0

		2,281.2			1,356.7

OPERATING INCOME (LOSS)		95.1			(128.4	)
Interest and finance expense		(26.9	)		(34.5	)
Loss on extinguishment of long-term debt		(7.0	)		—
Interest income		1.6			3.5

INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES AND MINORITY INTEREST		62.8			(159.4	)
Income tax (provision) benefit		(21.0	)		61.4
Minority interest		—			0.8

INCOME (LOSS) FROM CONTINUING OPERATIONS		41.8			(97.2	)
Loss from discontinued operations, net of income tax benefit of $2.7		(4.3	)		—

NET INCOME (LOSS)		37.5			(97.2	)
Preferred stock dividends		—			(2.5	)

NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS	$	37.5		$	(99.7	)

NET INCOME (LOSS) PER COMMON SHARE:
Basic:
Income (loss) from continuing operations	$	0.60		$	(3.14	)
Discontinued operations		(0.06	)		—

Net income (loss)	$	0.54		$	(3.14	)

Weighted average common shares outstanding		68.9			31.8
Diluted:
Income (loss) from continuing operations	$	0.60		$	(3.14	)
Discontinued operations		(0.06	)		—

Net income (loss)	$	0.54		$	(3.14	)

Weighted average common shares outstanding		69.6			31.8

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

PREMCOR INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited, in millions)

	For the Three Months Ended March 31,
	2003			2002
				(as restated, see Note 1)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	37.5		$	(97.2	)
Adjustments:
Loss on discontinued operations		7.0			—
Depreciation		14.6			12.4
Amortization		12.0			12.4
Deferred income taxes		16.7			(61.7	)
Stock-based compensation		4.3			1.9
Minority interest		—			(0.8	)
Refinery restructuring and other charges		13.6			101.2
Write-off of deferred financing costs		4.7			—
Other, net		2.6			8.8
Cash provided by (reinvested in) working capital—
Accounts receivable, prepaid expenses and other		(274.7	)		(61.0	)
Inventories		(10.8	)		(13.8	)
Accounts payable, accrued expenses, taxes other than income, and other		281.0			106.3
Cash and cash equivalents restricted for debt service		7.7			4.3

Net cash provided by operating activities of continuing operations		116.2			12.8
Net cash used in operating activities of discontinued operations		(0.3	)		(1.5	)

Net cash provided by operating activities		115.9			11.3

CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for property, plant and equipment		(22.0	)		(14.8	)
Expenditures for turnaround		(8.8	)		(27.5	)
Expenditures for refinery acquisition		(474.8	)		—
Cash and cash equivalents restricted for investment in capital additions		2.6			3.2

Net cash used in investing activities		(503.0	)		(39.1	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from the issuance of common stock, net		306.1			—
Proceeds from the issuance of long-term debt		525.0			—
Long-term debt and capital lease payments		(284.7	)		(66.6	)
Cash and cash equivalents restricted for debt repayment		0.2			(26.9	)
Deferred financing costs		(19.6	)		(1.1	)

Net cash provided by (used in) financing activities		527.0			(94.6	)

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		139.9			(122.4	)
CASH AND CASH EQUIVALENTS, beginning of period		167.4			510.1

CASH AND CASH EQUIVALENTS, end of period	$	307.3		$	387.7

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

INDEPENDENT ACCOUNTANTS’ REPORT

To the Board of Directors of The Premcor Refining Group Inc.:

We have reviewed the accompanying condensed consolidated balance sheet of The Premcor Refining Group Inc. and subsidiaries (the “Company”) as of March 31, 2003, and the related condensed consolidated statements of operations and cash flows for the three-month periods ended March 31, 2003 and 2002. These financial statements are the responsibility of the Company’s management.

We have previously audited, in accordance with auditing standards generally accepted in the United States of America, the consolidated balance sheet of the Company as of December 31, 2002, and the related consolidated statements of operations, stockholder’s equity, and cash flows for the year then ended (not presented herein). In our report dated February 14, 2003 (March 6, 2003 as to Note 20) (which report includes an explanatory paragraph relating to the Company’s change in its method of accounting for stock based compensation issued to employees and the restatement of the consolidated financial statements to give effect to the contribution of Sabine River Holding Corp. common stock owned by Premcor Inc. (the Company’s parent company) to the Company, which was accounted for in a manner similar to a pooling of interests as described in Notes 2 and 3), we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 2002 is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

Deloitte & Touche LLP

St. Louis, Missouri

April 28, 2003

THE PREMCOR REFINING GROUP INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(in millions, except share data)

	March 31, 2003		December 31, 2002
	(unaudited)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	255.8	$	119.7
Short-term investments		1.7		1.7
Cash and cash equivalents restricted for debt service		53.8		61.7
Accounts receivable, net of allowance of $3.3 and $3.2		520.0		269.0
Receivables from affiliates		26.4		13.1
Inventories		463.4		287.3
Prepaid expenses and other		77.9		45.7
Assets held for sale		40.2		49.3

Total current assets		1,439.2		847.5
PROPERTY, PLANT AND EQUIPMENT, NET		1,560.9		1,261.7
DEFERRED INCOME TAXES		4.6		19.8
OTHER ASSETS		124.6		117.3

	$	3,129.3	$	2,246.3

LIABILITIES AND STOCKHOLDER’S EQUITY
CURRENT LIABILITIES:
Accounts payable	$	720.4	$	466.2
Payables to affiliates		42.1		41.0
Accrued expenses and other		83.4		55.7
Accrued taxes other than income		41.9		26.4
Current portion of long-term debt		20.9		15.0

Total current liabilities		908.7		604.3
LONG-TERM DEBT		1,144.3		869.8
OTHER LONG-TERM LIABILITIES		144.4		144.4
COMMITMENTS AND CONTINGENCIES		—		—

COMMON STOCKHOLDER’S EQUITY:
Common, $0.01 par value per share, 100 issued and outstanding		—		—
Paid-in capital		806.7		541.4
Retained earnings		125.2		86.4

Total common stockholder’s equity		931.9		627.8

	$	3,129.3	$	2,246.3

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

THE PREMCOR REFINING GROUP INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(unaudited, in millions)

	For the Three Months Ended March 31,
	2003			2002
				(as restated, see Note 1)
NET SALES AND OPERATING REVENUES	$	2,375.8		$	1,228.3
EXPENSES:
Cost of sales		2,109.6			1,062.0
Operating expenses		116.7			114.4
General and administrative expenses		11.7			14.4
Stock-based compensation		4.3			1.9
Depreciation		14.5			12.4
Amortization		9.5			9.8
Refinery restructuring and other charges		15.0			142.0

		2,281.3			1,356.9

OPERATING INCOME (LOSS)		94.5			(128.6	)
Interest and finance expense		(26.2	)		(30.5	)
Loss on extinguishment of long-term debt		(4.7	)		—
Interest income		1.1			2.2

INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES AND MINORITY INTEREST		64.7			(156.9	)
Income tax (provision) benefit		(21.6	)		60.6
Minority interest		—			0.8

INCOME (LOSS) FROM CONTINUING OPERATIONS		43.1			(95.5	)
Loss from discontinued operations, net of income tax benefit of $2.7		(4.3	)		—

NET INCOME (LOSS)	$	38.8		$	(95.5	)

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

THE PREMCOR REFINING GROUP INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited, in millions)

	For the Three Months Ended March 31,
	2003			2002
				(as restated, see Note 1)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	38.8		$	(95.5	)
Adjustments:
Loss on discontinued operations		7.0			—
Depreciation		14.5			12.4
Amortization		12.0			12.4
Deferred income taxes		15.2			(60.9	)
Stock-based compensation		4.3			1.9
Minority interest		—			(0.8	)
Refinery restructuring and other charges		13.6			101.2
Write-off of deferred financing costs		4.7			—
Other, net		2.5			8.6
Cash provided by (reinvested in) working capital—
Accounts receivable, prepaid expenses and other		(274.2	)		(70.3	)
Inventories		(10.8	)		(13.8	)
Accounts payable, accrued expenses, taxes other than income, and other		279.6			99.9
Affiliate receivables and payables		2.8			13.3
Cash and cash equivalents restricted for debt service		7.7			4.3

Net cash provided by operating activities of continuing operations		117.7			12.7
Net cash used in operating activities of discontinued operations		(0.3	)		(1.5	)

Net cash provided by operating activities		117.4			11.2

CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for property, plant and equipment		(22.0	)		(14.8	)
Expenditures for turnaround		(8.8	)		(27.5	)
Expenditures for refinery acquisition		(474.8	)		—
Cash and cash equivalents restricted for investment in capital additions		2.6			3.2

Net cash used in investing activities		(503.0	)		(39.1	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt		525.0			—
Long-term debt and capital lease payments		(244.5	)		(66.6	)
Capital contributions, net		260.6			—
Cash and cash equivalents restricted for debt repayment		0.2			(26.9	)
Deferred financing costs		(19.6	)		(1.1	)

Net cash provided by (used in) financing activities		521.7			(94.6	)

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		136.1			(122.5	)
CASH AND CASH EQUIVALENTS, beginning of period		119.7			482.5

CASH AND CASH EQUIVALENTS, end of period	$	255.8		$	360.0

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

FORM 10-Q—PART I

ITEM 1. FINANCIAL STATEMENTS (continued)

PREMCOR INC. AND SUBSIDIARIES

THE PREMCOR REFINING GROUP INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

March 31, 2003

(Tabular amounts in millions, except per share data)

1. Nature of Business and Basis of Preparation

Premcor Inc., a Delaware corporation, was incorporated in April 1999. Premcor Inc. owns all of the outstanding common stock of Premcor USA Inc. (“Premcor USA”), a Delaware corporation formed in 1988. Premcor USA owns all of the outstanding common stock of The Premcor Refining Group Inc. (“PRG”), a Delaware corporation also formed in 1988. Premcor Inc. and its subsidiaries (the “Company”) is an independent petroleum refiner and supplier of unbranded transportation fuels, heating oil, petrochemical feedstocks, petroleum coke and other petroleum products in the United States. As of March 31, 2003, the Company owned and operated three refineries with a combined crude oil throughput capacity of 610,000 barrels per day (“bpd”). The refineries are located in Port Arthur, Texas; Memphis, Tennessee; and Lima, Ohio.

All of the operations of the Company are in the United States. These operations are related to the refining of crude oil and other petroleum feedstocks into petroleum products and are all considered part of one business segment. The Company’s earnings and cash flows from operations are primarily dependent upon processing crude oil and selling quantities of refined petroleum products at margins sufficient to cover operating expenses. Crude oil and refined petroleum products are commodities, and factors largely out of the Company’s control can cause prices to vary, in a wide range, over a short period of time. This potential margin volatility can have a material effect on the financial position, current period earnings, and cash flows.

The accompanying unaudited condensed consolidated financial statements of Premcor Inc. and PRG and their respective subsidiaries are presented pursuant to the rules and regulations of the United States Securities and Exchange Commission in accordance with the disclosure requirements for Form 10-Q. In the opinion of the management of the Company, the unaudited condensed consolidated financial statements reflect all adjustments (consisting of normal recurring adjustments) necessary to fairly state the results for the interim periods presented. Operating results for the three months ended March 31, 2003 are not necessarily indicative of the results that may be expected for the year ending December 31, 2003. These combined consolidated notes apply equally to the Company and PRG and its subsidiaries, unless otherwise noted. These unaudited condensed financial statements should be read in conjunction with the audited financial statements and notes included in Premcor Inc.’s and PRG’s combined Annual Report on Form 10-K for the year ended December 31, 2002.

In the second quarter of 2002, the Company adopted the recognition and measurement provisions of Statement of Financial Accounting Standard (“SFAS”) No. 123, Accounting for Stock-Based Compensation, and effective January 1, 2002 recognized stock-based compensation expense using the fair value recognition provisions of SFAS No. 123 for all employee awards granted or modified after January 1, 2002. SFAS No. 123 requires the restatement

of previously reported interim financial statements within the year of adoption, and accordingly, the Company restated the financial statements for the first quarter of 2002. For the three months ended March 31, 2002, the adoption of the fair value recognition provisions of SFAS No. 123 increased the Company’s net loss available to common stockholders by $0.2 million ($0.01 per basic and diluted share) from amounts originally reported.

On June 6, 2002, Premcor Inc. and PRG completed a series of transactions, which resulted in Sabine River Holding Corp. and its subsidiaries (“Sabine”), becoming wholly owned subsidiaries of PRG. Prior to this date, Premcor Inc. held a 90% interest in Sabine and a subsidiary of Occidental Petroleum Corporation (“Occidental”) held a 10% interest. Sabine, through Port Arthur Coker Company L.P. (“PACC”), owns and operates a heavy oil processing facility, which is operated in conjunction with PRG’s Port Arthur refinery. The restructuring of Sabine as a wholly owned subsidiary of PRG constituted an exchange of ownership interest between entities under common control, and therefore was accounted for in a manner similar to a pooling of interests. Accordingly, PRG’s historical financial statements have been restated to include the consolidated financial position, results of operations, and cash flows of Sabine for all periods presented.

Certain reclassifications have been made to the prior year’s financial statements to conform to classifications used in the current year.

2. New Accounting Standards

In July 2001, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 143, Accounting for Asset Retirement Obligations. SFAS No. 143 requires fair value recognition of legal obligations to retire long-lived assets at the time the obligations are incurred. The initial recording of a liability for an asset retirement obligation will require the recording of a corresponding asset. The liability will be adjusted for accretion due to the passage of time and the asset will be depreciated. The Company has asset retirement obligations based on its legal obligations at its refinery sites. The Company considers the settlement date of the obligations indeterminable at this time due to uncertainty about the timing of the retirement of the long-lived assets. Accordingly, the Company cannot calculate an associated asset retirement liability at this time. The Company adopted this standard in the first quarter of 2003, but the initial adoption did not have a material impact on the Company’s financial position or results of operations. The Company will measure and recognize the fair value of its asset retirement obligations at such time as a settlement date is determinable.

In November 2002, the FASB issued Interpretation No. 45, Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others. This interpretation requires expanded disclosure of a guarantor’s obligation under certain guarantees that it has issued. It also requires that a guarantor recognize, at the inception of certain guarantees, a liability for the fair value of the obligation undertaken in issuing the guarantee. The disclosure requirements are effective for interim and annual financial statements issued for periods ending after December 15, 2002. The provisions for the recognition of a liability are effective prospectively for guarantees issued or modified after December 31, 2002. The Company has adopted the recognition provisions in the first quarter of 2003 with no material impact on its financial statements.

In January 2003, the FASB issued Interpretation No. 46, Consolidation of Variable Interest Entities, an interpretation of ARB No. 51. This interpretation clarifies consolidation requirements for variable interest entities. It establishes additional factors beyond ownership of a majority voting interest to indicate that a company has a controlling financial interest in an entity (or a relationship sufficiently similar to a controlling financial interest that it requires consolidation). This interpretation applies immediately to variable interest entities created or obtained after January 31, 2003 and must be retroactively applied to holdings in variable interest entities acquired before February 1, 2003 in interim and annual financial statements issued for periods beginning after June 15, 2003. The adoption of this interpretation did not have a material impact on the Company’s financial statements.

In April 2003, the agenda committee of the Emerging Issues Task Force (“EITF”) of the FASB placed the discussion of Issue No. 02-L, Reporting Gains and Losses on Derivative Instruments That are Subject to SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, and Not Held for Trading Purposes, on the agenda for its May 14–15, 2003 meeting. It is anticipated the EITF will address Issue No. 02-L which deals with certain aspects of EITF 02-3, Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities. EITF 02-3 currently requires that gains and losses on all derivative instruments within the scope of SFAS No. 133 be shown net in the income statement, whether or not settled physically, if the derivative instruments are held for trading purposes. The EITF is expected to address the income statement classification of gains and losses on energy contracts within the scope of SFAS No. 133 that are not held for trading purposes and the applicability of EITF 99-19 to such transactions. Energy contract arrangements that are settled physically qualify for “gross” reporting pursuant to EITF 99-19. Any consensus reached by the EITF on this issue may require changes in the Company’s presentation of revenue and cost of sales. The Company does not expect that any such changes will have an impact on its gross margin.

3. Memphis Refinery Acquisition and Related FinancingTransactions

Effective March 3, 2003, the Company completed the acquisition of the Memphis, Tennessee refinery and related supply and distribution assets from The Williams Companies, Inc. and certain of its subsidiaries (“Williams”) at a purchase price of $310 million plus approximately $159 million for crude and product inventories, which is subject to finalization, and approximately $6 million in transaction fees. The Memphis refinery has a rated crude oil throughput capacity of 190,000 bpd but typically processes approximately 170,000 bpd. The related assets include two truck-loading racks; three petroleum terminals in the area; supporting pipeline infrastructure that transports both crude oil and refined products; crude oil tankage at St. James, Louisiana; and an 80-megawatt power plant adjacent to the refinery. The transfer of certain of these assets remains subject to obtaining certain third party consents. No portion of the purchase price was held back relative to this delayed transfer, and the Company is able to utilize the assets based on interim agreements.

The acquisition of the Memphis refinery and related supply and distribution assets was accounted for using the purchase method, and the results of operations of these assets have been included in the Company’s first quarter results from the date of acquisition. The preliminary purchase price allocation, which is subject to change pending finalization of the crude and product inventory settlement with Williams, completion of independent appraisals, and completion of other evaluations including the assessment of any asset retirement obligations, is as follows:

Current assets	$	174.3
Property, plant, and equipment		321.9
Accrued liabilities (including current portion of long-term debt)		(11.2	)
Long-term debt (capital leases)		(10.2	)

	$	474.8

As part of the purchase agreement, the Company assumed liabilities of $11.2 million that primarily related to cancellation fees for contracts entered into by Williams for Tier II technology that will not be utilized by the Company and environmental remediation of a recently closed land farm. Williams assigned several leases to the Company including two capitalized leases that relate to the leasing of crude oil and product pipelines that are within the Memphis refinery system connecting the refinery to storage facilities and other third party pipelines. Both capital leases have 15-year terms with approximately 14 years of the term remaining.

The purchase agreement also provides for contingent participation, or earn-out, payments up to a maximum aggregate of $75 million to Williams over the next seven years, depending on the level of industry refining margins during that period. The earn-out payments will be calculated annually at the end of the seven 12-month periods beginning on March 3, 2003. The annual earn-out calculation will be equal to one-half of the excess of the actual daily value of the Gulf Coast 2/1/1 crack spread over a stipulated margin, at a crude oil throughput rate of 167,123 bpd. The stipulated margin is $3.25 per barrel for the first year and increases by $0.10 per barrel for each year thereafter. Any amounts the Company pays to Williams as a result of the earn-out agreement will be recorded as additional refinery purchase price on the calculation date, and depreciated or amortized accordingly.

Related Financing Transactions

On January 30, 2003, Premcor Inc. completed a public offering of 12.5 million shares of common stock and a private placement of 2.9 million shares of common stock with Blackstone Capital Partners III Merchant Banking Fund L.P. and its affiliates (“Blackstone”), Occidental, and certain Premcor executives. On February 5, 2003, Premcor Inc. sold an additional 0.6 million shares of common stock pursuant to the underwriters’ over-allotment option. Premcor Inc. received net proceeds of approximately $306 million from these transactions. On February 11, 2003, PRG completed an offering of $525 million in senior notes, of which $350 million, due in 2013, bear interest at 9½% per annum and $175 million, due in 2010, bear interest at 9¼% per annum. Concurrently, PRG amended and restated its credit agreement as described in Note 7, Credit Agreement.

In addition to the refinery acquisition, the proceeds from these transactions were also used to redeem the remaining $40.1 million principal balance of Premcor USA’s 11½% subordinated debentures plus a premium thereon of $2.3 million and to repay PRG’s $240 million floating rate loan at par.

Loss on Extinguishment of Long-term Debt

As a result of the early extinguishment of long-term debt and credit agreement restructuring, the Company recorded a loss of $7.0 million (PRG $4.7 million) in the first quarter of 2003. For PRG, the loss included a write-off of unamortized deferred financing costs of $4.7 million related to the repayment of the floating rate loan and the amendment of PRG’s credit agreement. In addition to the $4.7 million write-off, the Company recorded a loss of $2.3 million for a premium related to the redemption of Premcor USA’s 11½% subordinated debentures.

4. Refinery Restructuring and Other Charges

In September 2002, the Company ceased refining operations at its Hartford, Illinois refinery and as of December 31, 2002, had written down the long-lived refining assets to their estimated net realizable value of $49.0 million in anticipation of a sale or lease of the refining assets. The Company continued to operate the storage and distribution facility at the refinery site. In the first quarter of 2003, the Company signed a memorandum of understanding with ConocoPhillips for a sale of refining assets and certain storage and distribution assets for $40 million. In the first quarter of 2003, the Company recorded refinery restructuring and other charges of $16.6 million related to the transaction, which included the write-down of the refining assets held for sale and certain storage and distribution assets included in property, plant and equipment.

In the first quarter of 2002, the Company recorded refinery restructuring and other charges of $142.0 million, which consisted of a $131.2 million charge related to the then planned shutdown of refining operations at the Hartford, Illinois refinery, a $15.8 million charge related to the restructuring of management and administrative functions; and income of $5.0 million related to the unanticipated sale of a portion of the Blue Island refinery assets previously written off.

As of December 31, 2002, the Company had a $4.9 million reserve for plans announced in the third quarter of 2002 to reduce additional staff at the St. Louis administrative office in early 2003. As a result of the Memphis refinery acquisition, the number of positions to be eliminated has been reduced by 25 and the Company recorded a reduction in the restructuring reserve of $1.6 million in the first quarter of 2003. The Company expects to complete the restructuring of its St. Louis administrative functions by the end of the year. The Company also had a $1.0 million reserve for employee severance and plant closure/equipment remediation related to shutdown of the refining operations at the Hartford refinery. The activities related to the Hartford closure were completed in the first quarter of 2003. The following schedule summarizes the activity and balance of these restructuring reserves as of March 31, 2003:

	Reserve as of December 31, 2002		Adjustment to Reserve			Net Cash Outlay			Reserve as of March 31, 2003
St. Louis restructuring	$	4.9	$	(1.6	)	$	(1.5	)	$	1.8
Hartford closure:
Employee severance		0.6		—			(0.6	)		—
Plant closure/equipment remediation		0.4		—			(0.4	)		—

	$	5.9	$	(1.6	)	$	(2.5	)	$	1.8

5. Inventories

The carrying value of inventories consisted of the following:

	March 31, 2003		December 31, 2002
Crude oil	$	151.4	$	63.8
Refined products and blendstocks		286.5		204.5
Warehouse stock and other		25.5		19.0

	$	463.4	$	287.3

The market value of crude oil, refined products and blendstock inventories at March 31, 2003 was approximately $159 million (December 31, 2002—$188 million) above carrying value.

6. Other Assets

Other assets consisted of the following:

	March 31, 2003		December 31, 2002
Deferred turnaround costs	$	85.6	$	86.3
Deferred financing costs		36.8		24.2
Cash restricted for investment in capital additions		—		2.6
Other		2.2		4.2

	$	124.6	$	117.3

Amortization of deferred financing costs for the three months ended March 31, 2003 was $2.3 million for both the Company and PRG (2002—the Company—$2.5 million, PRG—$2.4 million), and was included in “Interest and finance expense”. In the first quarter of 2003, the Company incurred deferred financing costs of $19.6 million related to the amendment of its credit agreement and the issuance of $525 million in senior notes. In the first quarter of 2003, the Company wrote-off $4.7 million of unamortized deferred financing costs as a result of the early repayment of portions of its long-term debt and the amendment of its credit agreement.

7. Credit Agreement

PRG’s credit agreement, which was amended and restated in February 2003, provides for letter of credit issuances of up to the lesser of $750 million or an amount available under a defined borrowing base, less outstanding borrowings. The facility may be increased to $800 million under certain circumstances. PRG utilizes this facility primarily for the issuance of letters of credit to secure crude oil purchase obligations. The borrowing base includes PRG’s unrestricted cash and eligible cash equivalents, eligible investments, eligible receivables, eligible petroleum inventories, paid but unexpired letters of credit, net obligations on swap contracts and PACC’s eligible hydrocarbon inventory. The credit agreement expires in February 2006. As of March 31, 2003, the borrowing base was $1,090.8 million (December 31, 2002—$815.3 million), with $575.0 million (December 31, 2002—$597.1 million) of the facility utilized for letters of credit.

The credit agreement provides for direct cash borrowings of up to, but not exceeding in the aggregate, $200 million, subject to sublimits of $75 million for working capital and general corporate purposes and $150 million for acquisition-related working capital. Acquisition-related borrowings are subject to a defined repayment provision. Borrowings under the credit agreement are secured by a lien on substantially all of PRG’s unrestricted cash and cash equivalents, receivables, crude oil and refined product inventories and trademarks and PACC’s hydrocarbon inventory. PRG’s interest rate for any borrowings under this agreement would bear interest at a rate based on either the U.S. prime lending rate or the Eurodollar rate plus a defined margin, at PRG’s option, based on certain

restrictions. As of March 31, 2003 and December 31, 2002, there were no direct cash borrowings under the credit agreement.

The credit agreement contains covenants and conditions that, among other things, limit PRG’s dividends, indebtedness, liens, investments and contingent obligations. PRG is also required to comply with certain financial covenants, including the maintenance of minimum working capital of $150 million and the maintenance of minimum tangible net worth of $650 million. The covenants also provide for a cumulative cash flow test that from January 1, 2003 must not be less than zero.

8. Long-term Debt

Significant transactions affecting long-term debt were discussed in Note 3. Long-term debt consisted of the following:

	March 31, 2003		December 31, 2002
8⁵/8% Senior Notes due August 15, 2008 (“8⁵/8% Senior Notes”)⁽¹⁾	$	109.8	$	109.8
8³/8% Senior Notes due November 15, 2007 (“8³/8% Senior Notes”)⁽¹⁾		99.7		99.7
8⁷/8% Senior Subordinated Notes due November 15, 2007 (“8⁷/8% Senior Subordinated Notes”)⁽¹⁾		174.4		174.4
Floating Rate Term Loan due November 15, 2003 and 2004 (“Floating Rate Loan”)⁽¹⁾		—		240.0
12½% Senior Notes due January 15, 2009 (“12 ½% Senior Notes”)⁽²⁾		246.3		250.7
9¼% Senior Notes due February 01, 2010 (“9¼% Senior Notes”)⁽¹⁾		175.0		—
9½% Senior Notes due February 01, 2013 (“9½% Senior Notes”)⁽¹⁾		350.0		—
11½% Subordinated Debentures due October 1, 2009 (“11½% Subordinated Debentures”)⁽³⁾		—		40.1
Ohio Water Development Authority Environmental Facilities Revenue Bonds due December 01, 2031		10.0		10.0
Obligation under capital leases⁽⁴⁾		10.5		0.2

		1,175.7		924.9
Less current portion		21.2		15.0

Total long-term debt at Premcor Inc.	$	1,154.5	$	909.9

(1)

Issued or borrowed by PRG

(2)

Issued or borrowed by PAFC

(3)

Issued or borrowed by Premcor USA

(4)

Assumed by The Premcor Pipeline Co., a subsidiary of Premcor USA

PRG’s long-term debt, including current maturities, as of March 31, 2003 was $1,165.2 million and is the same as the Premcor Inc. long-term debt as noted in the table above except that it excludes the $10.5 million of capital lease obligations. The Premcor Pipeline Co. assumed these lease obligations as part of the Memphis acquisition. PRG’s long-term debt, including current maturities, as of December 31, 2002 was $884.8 million and is the same as the Premcor Inc. long-term debt as noted in the table above except that it excludes the $40.1 million in 11½% Subordinated Debentures issued by Premcor USA.

9. Stock-based Compensation Expense

As of March 31, 2003, the Company had outstanding stock awards accounted for under the intrinsic value method of APB Opinion No. 25, Accounting for Stock Issued to Employee (awards granted prior to January 1, 2002). The following table illustrates the effect on net income and earnings per share if the fair value based method of SFAS No. 123 had been applied to all outstanding awards in each period as opposed to only the awards granted or modified after January 1, 2002.

	For the Three Months Ended March 31,
	2003			2002
Net income (loss), as reported	$	37.5		$	(99.7	)
Add: Stock-based compensation expense included in reported net income, net of tax effect		2.7			4.8
Deduct: Stock-based compensation expense determined under fair value based method for all options, net of tax effect		(2.7	)		(4.9	)

Pro forma net income (loss)	$	37.5		$	(99.8	)

Earnings per share:
Basic—as reported and pro forma	$	0.54		$	(3.14	)
Diluted—as reported and pro forma		0.54			(3.14	)

10. Interest and Finance Expense

Interest and finance expense included in the statements of operations consisted of the following:

	Premcor Inc.						PRG
	For the Three Months Ended March 31,						For the Three Months Ended March 31,
	2003			2002			2003			2002
Interest expense	$	26.8		$	32.1		$	26.1		$	28.2
Financing costs		2.4			4.2			2.4			4.1
Capitalized interest		(2.3	)		(1.8	)		(2.3	)		(1.8	)

	$	26.9		$	34.5		$	26.2		$	30.5

The Company’s cash paid for interest expense for the three months ended March 31, 2003 was $25.1 million (2002—$37.9 million). PRG’s cash paid for interest expense for the three months ended March 31, 2003 was $23.1 million (2002—$37.9 million).

11. Income Taxes

The Company made no net cash income tax payments nor received any net cash income tax refunds during the first quarter of 2003 (2002—received net cash income tax refunds of $11.7 million). PRG made no net cash income tax payments nor received any net cash income tax refunds during the first quarter of 2003 (2002—no income tax payment or refunds). The $11.7 million refund in the first quarter of 2002 was received by Premcor Inc. This refund related to a 2001 estimated income tax payment made primarily on behalf of Sabine and was due to Sabine under the terms of its tax sharing agreement with Premcor Inc. and a common security agreement related to PACC senior debt. The refund was returned to Sabine by Premcor Inc. in the second quarter of 2002.

12. Discontinued Operations

In connection with the 1999 sale of the Company’s retail assets to Clark Retail Enterprises, Inc. (“CRE”), PRG assigned approximately 170 leases and subleases of retail stores to CRE. PRG remains jointly and severally liable for CRE’s obligations under approximately 150 of these leases, including payment of rent and taxes. PRG may also

be contingently liable for environmental cleanup responsibilities for releases of petroleum occurring during the term of the CRE leases. On October 15, 2002, CRE and its parent company, Clark Retail Group, Inc., filed a voluntary petition for reorganization under Chapter 11 of the U.S. Bankruptcy Code. As CRE rejects some or all of these leases from its reorganization plan, PRG may become responsible for these obligations. In bankruptcy hearings held in the first quarter of 2003, CRE rejected 30 of these leases. The Company recorded an after-tax charge of $4.3 million in the first quarter of 2003 representing the estimated net present value of our remaining liability under these rejected leases, net of estimated sub-lease income. The Company is currently in discussions with CRE regarding their reorganization plans, the status of environmental remediation agreements, and other matters. While it is possible that the Company may incur additional liability for CRE lease obligations or other costs as CRE finalizes its reorganization plans, the amounts are not estimable at this time.

13. Earnings per Share

The common stock shares used to compute the Company’s basic and diluted earnings per share was as follows:

	For the Three Months Ended March 31,
	2003	2002
Weighted average common shares outstanding	68.9	31.8
Dilutive effect of:
Stock options	0.7	—
Common stock warrants	—	—

Weighted average common shares outstanding, assuming dilution	69.6	31.8

Stock options of 4.4 million shares for the three months ended March 31, 2003, were excluded from the diluted earnings per share calculation because they were anti-dilutive. Stock options and warrants representing common stock equivalents of 3.5 million shares were excluded from diluted shares outstanding for the three months ended March 31, 2002 due to their anti-dilutive effect as a result of the Company’s net loss.

14. Consolidating Financial Statements of PRG as Co-guarantor of PAFC’s Senior Notes

Presented below are the PRG consolidating balance sheets, statement of operations, and cash flows as required by Rule 3-10 of the Securities Exchange Act of 1934. PRG along with PACC, Sabine, and various other subsidiaries of Sabine are full and unconditional guarantors of Port Arthur Finance Corp’s (“PAFC”) 12½% Senior Notes. PAFC is a wholly owned subsidiary of PACC. Under Rule 3-10, the consolidating balance sheets, statement of operations, and cash flows presented below meet the requirements for financial statements of the issuer and each guarantor of the notes since the issuer and guarantors are all direct or indirect wholly owned subsidiaries of PRG, and all guarantees are full and unconditional and joint and several.

THE PREMCOR REFINING GROUP INC. AND SUBSIDIARIES

CONSOLIDATING BALANCE SHEET

As of March 31, 2003

(unaudited, in millions)

	PRG		PAFC		Other Guarantor Subsidiaries		Eliminations			Consolidated PRG
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	250.8	$	—	$	5.0	$	—		$	255.8
Short-term investments		1.7		—		—		—			1.7
Cash and cash equivalents restricted for debt service		—		—		53.8		—			53.8
Accounts receivable		517.6		—		2.4		—			520.0
Receivable from affiliates		71.4		27.4		139.5		(211.9	)		26.4
Inventories		431.7		—		31.7		—			463.4
Prepaid expenses and other		76.9		—		1.0		—			77.9
Assets held for sale		40.2		—		—		—			40.2

Total current assets		1,390.3		27.4		233.4		(211.9	)		1,439.2
PROPERTY, PLANT AND EQUIPMENT, NET		955.9		—		605.0		—			1,560.9
DEFERRED INCOME TAXES		56.5		—		—		(51.9	)		4.6
INVESTMENT IN AFFILIATE		393.2		—		—		(393.2	)		—
OTHER ASSETS		109.6		—		15.0		—			124.6
NOTE RECEIVABLE FROM AFFILIATE		—		225.4		—		(225.4	)		—

	$	2,905.5	$	252.8	$	853.4	$	(882.4	)	$	3,129.3

LIABILITIES AND STOCKHOLDER’S EQUITY
CURRENT LIABILITIES:
Accounts payable	$	619.0	$	—	$	101.4	$	—		$	720.4
Payable to affiliates		175.3		—		55.4		(188.6	)		42.1
Accrued expenses and other		76.4		6.5		0.5		—			83.4
Accrued taxes other than income		40.1		—		1.8		—			41.9
Current portion of long-term debt		—		20.9		—		—			20.9
Current portion of notes payable to affiliate		—		—		23.3		(23.3	)		—

Total current liabilities		910.8		27.4		182.4		(211.9	)		908.7
LONG-TERM DEBT		918.9		225.4		—		—			1,144.3
DEFERRED INCOME TAXES		—		—		51.9		(51.9	)		—
OTHER LONG-TERM LIABILITIES		143.9		—		0.5		—			144.4
NOTE PAYABLE TO AFFILIATE		—		—		225.4		(225.4	)		—
COMMON STOCKHOLDER’S EQUITY:
Common stock		—		—		0.1		(0.1	)		—
Paid-in capital		806.7		—		206.0		(206.0	)		806.7
Retained earnings		125.2		—		187.1		(187.1	)		125.2

Total common stockholder’s equity		931.9		—		393.2		(393.2	)		931.9

	$	2,905.5	$	252.8	$	853.4	$	(882.4	)	$	3,129.3

THE PREMCOR REFINING GROUP INC. AND SUBSIDIARIES

CONSOLIDATING STATEMENT OF OPERATIONS

For the three months ended March 31, 2003

(unaudited, in millions)

	PRG			PAFC			Other Guarantor Subsidiaries			Eliminations			Consolidated PRG
NET SALES AND OPERATING REVENUES	$	2,513.8		$	—		$	704.3		$	(842.3	)	$	2,375.8
EQUITY IN EARNINGS OF AFFILIATE		62.3			—			—			(62.3	)		—
EXPENSES:
Cost of sales		2,392.7			—			550.9			(834.0	)		2,109.6
Operating expenses		82.4			—			42.6			(8.3	)		116.7
General and administrative expenses		10.7			—			1.0			—			11.7
Stock-based compensation		4.3			—			—			—			4.3
Depreciation		9.1			—			5.4			—			14.5
Amortization		9.5			—			—			—			9.5
Refinery restructuring and other charges		15.0			—			—			—			15.0

		2,523.7			—			599.9			(842.3	)		2,281.3
OPERATING INCOME		52.4			—			104.4			(62.3	)		94.5
Interest and finance expense		(17.5	)		(7.7	)		(8.7	)		7.7			(26.2	)
Loss on extinguishment of long-term debt		(4.7	)		—			—			—			(4.7	)
Interest income		1.0			7.7			0.1			(7.7	)		1.1

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		31.2			—			95.8			(62.3	)		64.7
Income tax (provision) benefit		11.9			—			(33.5	)		—			(21.6	)

INCOME FROM CONTINUING OPERATIONS		43.1			—			62.3			(62.3	)		43.1
Loss from discontinued operations, net of income tax benefit of $2.7		(4.3	)		—			—			—			(4.3	)

NET INCOME	$	38.8		$	—		$	62.3		$	(62.3	)	$	38.8

THE PREMCOR REFINING GROUP INC. AND SUBSIDIARIES

CONSOLIDATING STATEMENT OF CASH FLOWS

For the three months ended March 31, 2003

(unaudited, in millions)

	PRG			PAFC			Other Guarantor Subsidiaries			Eliminations			Consolidated PRG
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	38.8		$	—		$	62.3		$	(62.3	)	$	38.8
Adjustments:
Loss on discontinued operations		7.0			—			—			—			7.0
Depreciation		9.1			—			5.4			—			14.5
Amortization		11.1			—			0.9			—			12.0
Deferred income taxes		10.5			—			4.7			—			15.2
Stock-based compensation		4.3			—			—			—			4.3
Refinery restructuring and other charges		13.6			—			—			—			13.6
Write-off of deferred financing costs		4.7			—			—			—			4.7
Equity in earnings of affiliate		(62.3	)		—			—			62.3			—
Other, net		2.3			—			0.2			—			2.5
Cash provided by (reinvested in) working capital:
Accounts receivable, prepaid expenses and other		(273.1	)		—			(1.1	)		—			(274.2	)
Inventories		(6.7	)		—			(4.1	)		—			(10.8	)
Accounts payable, accrued expenses, taxes other than income, and other		312.9			(7.9	)		(25.4	)		—			279.6
Affiliate receivables and payables		36.4			12.2			(45.8	)		—			2.8
Cash and cash equivalents restricted for debt service		—			—			7.7			—			7.7

Net cash provided by operating activities of continuing operations		108.6			4.3			4.8			—			117.7
Net cash used in operating activities of discontinued operations		(0.3	)		—			—			—			(0.3	)

Net cash provided by operating activities		108.3			4.3			4.8			—			117.4

CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for property, plant and equipment		(22.0	)		—			—			—			(22.0	)
Expenditures for turnaround		(8.8	)		—			—			—			(8.8	)
Expenditures for refinery acquisition		(474.8	)		—			—			—			(474.8	)
Cash and cash equivalents restricted for investment in capital additions		2.6			—			—			—			2.6

Net cash used in investing activities		(503.0	)		—			—			—			(503.0	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt		525.0			—			—			—			525.0
Long-term debt and capital lease payments		(240.2	)		(4.3	)		—			—			(244.5	)
Capital contributions, net		260.6			—			—			—			260.6
Cash and cash equivalents restricted for debt repayment		—			—			0.2			—			0.2
Deferred financing costs		(19.6	)		—			—			—			(19.6	)

Net cash provided by (used in) financing activities		525.8			(4.3	)		0.2			—			521.7

NET INCREASE IN CASH AND CASH EQUIVALENTS		131.1			—			5.0			—			136.1
CASH AND CASH EQUIVALENTS, Beginning of period		119.7			—			—			—			119.7

CASH AND CASH EQUIVALENTS, end of period	$	250.8		$	—		$	5.0		$	—		$	255.8

THE PREMCOR REFINING GROUP INC. AND SUBSIDIARIES

CONSOLIDATING BALANCE SHEET

As of December 31, 2002

(in millions)

	PRG		PAFC		Other Guarantor Subsidiaries		Eliminations			Consolidated PRG
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	119.7	$	—	$	—	$	—		$	119.7
Short-term investments		1.7		—		—		—			1.7
Cash and cash equivalents restricted for debt service		—		—		61.7		—			61.7
Accounts receivable		268.7		—		0.3		—			269.0
Receivable from affiliates		32.9		29.2		50.7		(99.7	)		13.1
Inventories		259.7		—		27.6		—			287.3
Prepaid expenses and other		43.7		—		2.0		—			45.7
Assets held for sale		49.3		—		—		—			49.3

Total current assets		775.7		29.2		142.3		(99.7	)		847.5
PROPERTY, PLANT AND EQUIPMENT, NET		651.3		—		610.4		—			1,261.7
DEFERRED INCOME TAXES		67.0		—		—		(47.2	)		19.8
INVESTMENT IN AFFILIATE		330.9		—		—		(330.9	)		—
OTHER ASSETS		101.4		—		15.9		—			117.3
NOTE RECEIVABLE FROM AFFILIATE		2.3		235.9		—		(238.2	)		—

	$	1,928.6	$	265.1	$	768.6	$	(716.0	)	$	2,246.3

LIABILITIES AND STOCKHOLDER’S EQUITY
CURRENT LIABILITIES:
Accounts payable	$	342.9	$	—	$	123.3	$	—		$	466.2
Payable to affiliates		117.7		—		20.1		(96.8	)		41.0
Accrued expenses and other		40.9		14.4		0.4		—			55.7
Accrued taxes other than income		21.1		—		5.3		—			26.4
Current portion of long-term debt		0.2		14.8		—		—			15.0
Current portion of notes payable to affiliate		—		—		2.9		(2.9	)		—

Total current liabilities		522.8		29.2		152.0		(99.7	)		604.3
LONG-TERM DEBT		633.9		235.9		—		—			869.8
DEFERRED INCOME TAXES		—		—		47.2		(47.2	)		—
OTHER LONG-TERM LIABILITIES		144.1		—		0.3		—			144.4
NOTE PAYABLE TO AFFILIATE		—		—		238.2		(238.2	)		—
COMMITMENTS AND CONTINGENCIES		—		—		—		—			—
COMMON STOCKHOLDER’S EQUITY:
Common stock		—		—		0.1		(0.1	)		—
Paid-in capital		541.4		—		206.0		(206.0	)		541.4
Retained earnings		86.4		—		124.8		(124.8	)		86.4

Total common stockholder’s equity		627.8		—		330.9		(330.9	)		627.8

	$	1,928.6	$	265.1	$	768.6	$	(716.0	)	$	2,246.3

THE PREMCOR REFINING GROUP INC. AND SUBSIDIARIES

CONSOLIDATING STATEMENT OF OPERATIONS

For the three months ended March 31, 2002

(unaudited, in millions)

	PRG			PAFC			Other Guarantor Subsidiaries			Eliminations and Minority Interest			Consolidated PRG
NET SALES AND OPERATING REVENUES	$	1,255.9		$	—		$	420.7		$	(448.3	)	$	1,228.3
EQUITY IN EARNINGS OF AFFILIATE		(7.3	)		—			—			7.3			—
EXPENSES:
Cost of sales		1,123.1			—			379.6			(440.7	)		1,062.0
Operating expenses		88.3			—			33.7			(7.6	)		114.4
General and administrative expenses		13.3			—			1.1			—			14.4
Stock-based compensation		1.9			—			—			—			1.9
Depreciation		7.2			—			5.2			—			12.4
Amortization		9.8			—			—			—			9.8
Refinery restructuring and other charges		142.0			—			—			—			142.0

		1,385.6			—			419.6			(448.3	)		1,356.9

OPERATING INCOME (LOSS)		(137.0	)		—			1.1			7.3			(128.6	)
Interest and finance expense		(16.0	)		(12.0	)		(14.6	)		12.1			(30.5	)
Interest income		1.4			12.0			0.9			(12.1	)		2.2

LOSS BEFORE INCOME TAXES AND MINORITY INTEREST		(151.6	)		—			(12.6	)		7.3			(156.9	)
Income tax benefit		56.1			—			4.5			—			60.6
Minority interest		—			—			—			0.8			0.8

NET LOSS	$	(95.5	)	$	—		$	(8.1	)	$	8.1		$	(95.5	)

THE PREMCOR REFINING GROUP INC. AND SUBSIDIARIES

CONSOLIDATING STATEMENT OF CASH FLOWS

For the three months ended March 31, 2002

(unaudited, in millions)

	PRG			PAFC			Other Guarantor Subsidiaries			Eliminations And Minority Interest			Consolidated PRG
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(95.5	)	$	—		$	(8.1	)	$	8.1		$	(95.5	)
Adjustments:
Depreciation		7.2			—			5.2			—			12.4
Amortization		11.6			—			0.8			—			12.4
Deferred income taxes		(56.3	)		—			(4.6	)		—			(60.9	)
Stock-based compensation		1.9			—			—			—			1.9
Minority interest		—			—			—			(0.8	)		(0.8	)
Refinery restructuring and other charges		101.2			—			—			—			101.2
Equity in earnings of affiliate		7.3			—			—			(7.3	)		—
Other, net		8.4			—			0.2			—			8.6
Cash provided by (reinvested in) working capital:
Accounts receivable, prepaid expenses and other		(73.0	)		—			2.7			—			(70.3	)
Inventories		(38.1	)		—			24.3			—			(13.8	)
Accounts payable, accrued expenses, taxes other than income, and other		64.6			(9.5	)		44.8			—			99.9
Affiliate receivables and payables		49.1			75.7			(111.5	)		—			13.3
Cash and cash equivalents restricted for debt service		—			—			4.3			—			4.3

Net cash provided by (used in) operating activities of continued operations		(11.6	)		66.2			(41.9	)		—			12.7
Net cash used in operating activities of discontinued operations		(1.5	)		—			—			—			(1.5	)

Net cash provided by (used in) operating activities		(13.1	)		66.2			(41.9	)		—			11.2

CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for property, plant and equipment		(14.4	)		—			(0.4	)		—			(14.8	)
Expenditures for turnaround		(27.5	)		—			—			—			(27.5	)
Cash and cash equivalents restricted for investment in capital additions		3.2			—			—			—			3.2

Net cash used in investing activities		(38.7	)		—			(0.4	)		—			(39.1	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Long-term debt and capital lease payments		(0.4	)		(66.2	)		—			—			(66.6	)
Cash and cash equivalents restricted for debt repayment		—			—			(26.9	)		—			(26.9	)
Deferred financing costs		—			—			(1.1	)		—			(1.1	)

Net cash used in financing activities		(0.4	)		(66.2	)		(28.0	)		—			(94.6	)

NET DECREASE IN CASH AND CASH EQUIVALENTS		(52.2	)		—			(70.3	)		—			(122.5	)
CASH AND CASH EQUIVALENTS, beginning of period		259.7			—			222.8			—			482.5

CASH AND CASH EQUIVALENTS, end of period	$	207.5		$	—		$	152.5		$	—		$	360.0

15. Commitments and Contingencies

Environmental, Discontinued Operations and Legal Reserves

As a result of its normal course of business, the Company is a party to a number of legal proceedings and environmental-related obligations. The Company has also incurred liabilities related to leases of previously operated retail sites as discussed in Note 12, Discontinued Operations. In relation to these matters and obligations the Company has accrued, on an undiscounted basis unless otherwise noted, the following:

	March 31, 2003		December 31, 2002
Refinery environmental obligations:
Hartford	$	29.8	$	29.6
Blue Island		19.2		19.7
Port Arthur		11.8		11.9
Memphis		1.0		—
Discontinued retail marketing:
Environmental obligations		23.2		23.0
Lease obligations (discounted)		6.8		—
Other legal and environmental		8.4		9.0

	$	100.2	$	93.2

The Company is of the opinion that the ultimate resolution of these claims and obligations, to the extent not previously provided for, will not have a material adverse effect on the consolidated financial condition, results of operations or liquidity of the Company. However, an adverse outcome of any one or more of these matters could have a material effect on quarterly or annual operating results or cash flows when resolved in a future period.

Environmental Product Standards and MACT II

The Environmental Protection Agency, or EPA, has promulgated regulations under the Clean Air Act that establish stringent sulfur content specifications for gasoline and on-road diesel fuel designed to reduce air emissions from the use of these products. The Company expects to incur in the aggregate approximately $727 million, including $657 million that it expects to expend through 2006, in order to comply with environmental regulations related to the new stringent sulfur content specifications and MACT II regulations. Future revisions to these current cost estimates may be necessary as the Company continues to finalize its plans. Information related to the expected expenditures in relation to these new regulations is shown below.

	Total Estimated Expenditures		Total Expenditures Incurred To-Date		Remaining Expenditures at March 31, 2003		Contract Commitments		Year of Concentration of Expenditures
Gasoline Low sulfur standards	$	335	$	66	$	269	$	126	2003/2004
Diesel low sulfur standards		347		4		343		—	2005
MACT II		45		—		45		—	2003/2004

Total	$	727	$	70	$	657	$	126

Other Commitments

Crude Oil Purchase Commitment. On October 1, 2002, the Company entered into a crude oil linefill agreement with Morgan Stanley Capital Group Inc. (“MSCG”), which obligated it to purchase 2.7 million barrels of crude oil in the pipeline system supplying the Lima refinery from MSCG. The Company will purchase the 2.7 million barrels of crude oil upon termination of the agreement with MSCG, at then current market prices as adjusted by certain predetermined contract provisions. The initial term of the contract continues until October 1, 2003, and thereafter, automatically renews for additional 30-day periods unless terminated by either party. The Company has hedged the economic price risk related to the repurchase obligation through the purchase of exchange-traded futures contracts.

Long-Term Crude Oil Agreement. PACC has a long-term crude oil supply agreement with PMI Comercio Internacional, S.A. de C.V., an affiliate of Petroleos Mexicanos or PEMEX, the Mexican state oil company, which supplies approximately 162,000 barrels per day of Maya crude oil to the Port Arthur refinery. Under the terms of this agreement, PACC is obligated to buy Maya crude oil from the affiliate of PEMEX, and the affiliate of PEMEX is obligated to sell Maya crude oil to PACC. The agreement also provides a price adjustment mechanism designed to minimize the effect of adverse refining margin cycles and more specifically to moderate the fluctuations of the coker gross margin, a benchmark measure of the value of coker production over the cost of coker feedstocks. This price adjustment mechanism contains a formula that represents an approximation of the coker gross margin and provides for a minimum average coker margin of $15 per barrel over the first eight years of the agreement, which began on April 1, 2001. The cumulative difference, calculated on a monthly basis, between the actual coker gross margin and the defined minimum coker margin is referred to as a surplus or shortfall, and as of March 31, 2003, a cumulative quarterly surplus of $137.7 million existed under the agreement. As a result, the price the Company pays for Maya crude oil purchased under this agreement in succeeding quarters will not be discounted until this cumulative surplus is offset by future shortfalls.

ITEM 2.—MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Forward-Looking Statements

Certain statements in this document are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. These statements are subject to the safe harbor provisions of this legislation. Words such as “expects,” “intends,” “plans,” “projects,” “believes,” “estimates,” “will” and similar expressions typically identify such forward-looking statements.

Even though we believe our expectations regarding future events are based on reasonable assumptions, forward-looking statements are not guarantees of future performance. Important factors that could cause actual results to differ materially from those contained in our forward-looking statements include, among others, changes in:

•

Industry-wide refining margins;

•

Crude oil and other raw material costs, the cost of transportation of crude oil, embargoes, industry expenditures for the discovery and production of crude oil, military conflicts between, or internal instability in, one or more oil-producing countries, governmental actions, and other disruptions of our ability to obtain crude oil;

•

Market volatility due to world and regional events;

•

Availability and cost of debt and equity financing;

•

Labor relations;

•

U.S. and world economic conditions;

•

Supply and demand for refined petroleum products;

•

Reliability and efficiency of our operating facilities which are affected by such potential hazards as equipment malfunctions, plant construction/repair delays, explosions, fires, oil spills and the impact of severe weather and other factors which could result in significant unplanned downtime;

•

Actions taken by competitors which may include product pricing strategies, production decisions, and expansion or retirement of refinery capacity;

•

Civil, criminal, regulatory or administrative actions, claims or proceedings and regulations dealing with protection of the environment, including refined petroleum product composition and characteristics;

•

Acts of war or terrorism;

•

Other unpredictable or unknown factors not discussed.

Because of all of these uncertainties, and others, you should not place undue reliance on our forward-looking statements.

Overview

This Management Discussion and Analysis of Financial Condition and Results of Operations reflects the results of operations and financial condition of Premcor Inc. and subsidiaries, which are materially the same as the results of operations and financial condition of PRG. Therefore, the discussions provided are equally applicable to Premcor Inc. and PRG except where otherwise noted.

We are an independent petroleum refiner and supplier of unbranded transportation fuels, heating oil, petrochemical feedstocks, petroleum coke and other petroleum products in the United States. We own and operate three refineries with a combined crude oil throughput capacity of approximately 610,000 barrels per day, or bpd. Our refineries are located in Port Arthur, Texas; Memphis, Tennessee; and Lima, Ohio. We acquired our Memphis refinery in March 2003. We sell petroleum products in the Midwest, the Gulf Coast and the Eastern and Southeastern United States on an unbranded basis to approximately 1,200 distributors and chain retailers through a combination of our own product distribution system and an extensive third-party owned product distribution system, as well as in the spot market.

Major Developments

Effective March 3, 2003, we completed the acquisition of the Memphis, Tennessee refinery and related supply and distribution assets from The Williams Companies, Inc. and certain of its subsidiaries (“Williams”) at a purchase price of $310 million plus approximately $159 million for crude and product inventories, and approximately $6 million in transaction fees. The Memphis refinery has a rated crude oil throughput capacity of 190,000 bpd but typically processes approximately 170,000 bpd. The related assets include two truck-loading racks; three petroleum terminals in the area; supporting pipeline infrastructure that transports both crude oil and refined products; crude oil tankage at St. James, Louisiana; and an 80-megawatt power plant adjacent to the refinery. The transfer to us of certain of these assets remains subject to third party consents. No portion of the purchase price was held back relative to this delayed transfer, and we are able to utilize these assets based on interim agreements.

The acquisition of the Memphis refinery and related supply and distribution assets was accounted for using the purchase method, and the results of operations of these assets have been included in our first quarter results from the date of acquisition. The preliminary purchase price allocation, which is subject to change pending finalization of the crude and product inventory settlement with Williams, completion of independent appraisals, and completion of other evaluations including the assessment of any asset retirement obligations, is as follows (in millions):

Current assets	$	174.3
Property, plant, and equipment		321.9
Accrued liabilities (including current portion of long-term debt)		(11.2	)
Long-term debt (capital leases)		(10.2	)

	$	474.8

As part of the purchase agreement, we assumed liabilities of $11.2 million that primarily related to cancellation fees for contracts entered into by Williams for Tier II technology that will not be utilized by us and environmental remediation of a recently closed land farm. Williams assigned several leases to us including two capitalized leases that relate to the leasing of crude oil and product pipelines that are within the Memphis refinery system connecting the refinery to storage facilities and other third party pipelines. Both capital leases have 15-year terms with approximately 14 years of the term remaining.

The purchase agreement also provides for contingent participation, or earn-out, payments up to a maximum aggregate of $75 million to Williams over the next seven years, depending on the level of industry refining margins during that period. The earn-out payments will be calculated annually at the end of the seven 12-month periods beginning on March 3, 2003. The annual earn-out calculation will be equal to one-half of the excess of the actual daily value of the Gulf Coast 2/1/1 crack spread over a stipulated margin, at a crude oil throughput rate of 167,123 bpd. The stipulated margin is $3.25 per barrel for the first year and increases by $0.10 per barrel for each year thereafter. Any amounts we pay to Williams as a result of the earn-out agreement will be recorded as additional refinery purchase price on the calculation date, and depreciated or amortized accordingly.

PRG acquired the refinery and related assets utilizing a portion of the proceeds from the issuance of $525 million in senior notes and utilizing capital contributions from Premcor Inc., which were funded from the proceeds of a public and private offering of common stock. PRG also amended and restated its credit agreement to allow for the acquisition. See “—Liquidity and Capital Resources—Cash Flows from Financing Activities” for additional details of the financings.

Results of Operations

The following tables reflect Premcor Inc.’s financial and operating highlights for the three months ended March 31, 2003 and 2002.

Financial Results

	Three Months Ended March 31,
	2003			2002
	(in millions, except per share data)
Net sales and operating revenues	$	2,376.3		$	1,228.3
Cost of sales		2,108.9			1,061.6

Gross margin		267.4			166.7
Operating expenses		117.2			114.5
General and administrative expenses		11.7			14.5
Stock-based compensation expense		4.3			1.9
Depreciation and amortization		24.1			22.2
Refinery restructuring and other charges		15.0			142.0

Operating income (loss)		95.1			(128.4	)
Interest expense and finance income, net		(25.3	)		(31.0	)
Loss on extinguishment of long-term debt		(7.0	)		—
Income tax benefit (provision)		(21.0	)		61.4
Minority interest		—			0.8

Income (loss) from continuing operations		41.8			(97.2	)
Discontinued operations		(4.3	)		—

Net income (loss)		37.5			(97.2	)
Preferred stock dividends		—			(2.5	)

Net income (loss) available to common stockholders	$	37.5		$	(99.7	)

Net income (loss) available to common stockholders per common share:
Basic	$	0.54		$	(3.14	)
Diluted		0.54			(3.14	)
Weighted average common shares outstanding:
Basic		68.9			31.8
Diluted		69.6			31.8

Market Indicators

	Three Months Ended March 31,
	2003		2002
	(dollars per barrel, except as noted)
West Texas Intermediate (WTI) crude oil	$	34.13	$	21.59
Crack Spreads:
Gulf Coast 2/1/1		5.51		2.44
Chicago 3/2/1		6.42		3.68
Crude Oil Differentials:
WTI less Maya (heavy sour)		7.62		5.43
WTI less WTS (sour)		3.61		1.32
WTI less Dated Brent (foreign)		2.60		0.42
Natural gas (dollars per million btu)		6.05		2.20

Selected Volumetric and Per Barrel Data

	Three Months Ended March 31,
	2003		2002
	(in thousands of barrels per day, except as noted)
Crude oil throughput by refinery:
Port Arthur		244.4		231.7
Lima		132.8		139.7
Memphis⁽¹⁾		52.9		—
Hartford		—		62.8

Total crude oil throughput		430.1		434.2
Total crude oil throughput (in millions of barrels)		38.7		39.1
Per barrel of crude oil throughput (in dollars):
Gross margin	$	6.91	$	4.27
Operating expenses		3.03		2.93

(1)

We purchased Memphis effective March 3, 2003 and the crude oil throughput reflects 29 days of operations averaged over the first quarter of 2003. Average throughput during the 29 days of operations was 163,972 bpd.

	Three Months Ended March 31, 2003
Selected Volumetric Data (in thousands of barrels per day)	Port Arthur	Lima		Memphis⁽¹⁾	Total	*Percent of Total*
Feedstocks:
Crude oil throughput
Sweet	—	128.2		52.1	180.3	40.8	%
Light/medium sour	33.4	4.6		0.8	38.8	8.7
Heavy sour	211.0	—		—	211.0	47.7

Total crude oil	244.4	132.8		52.9	430.1	97.2
Unfinished and blendstocks	13.6	(2.5	)	1.1	12.2	2.8

Total feedstocks	258.0	130.3		54.0	442.3	100.0	%


Production:
Light products:
Conventional gasoline	85.8	66.2		22.8	174.8	38.4	%
Premium and reformulated gasoline	32.2	11.9		3.1	47.2	10.4
Diesel fuel	74.2	23.9		16.0	114.1	25.1
Jet fuel	27.0	17.8		8.8	53.6	11.8
Petrochemical feedstocks	17.3	6.4		2.6	26.3	5.7

Total light products	236.5	126.2		53.3	416.0	91.4
Petroleum coke and sulfur⁽²⁾	27.9	2.3		0.1	30.3	6.6
Residual oil	5.2	2.7		1.1	9.0	2.0

Total production	269.6	131.2		54.5	455.3	100.0	%

(1)

	Three Months Ended March 31, 2002
Selected Volumetric Data (in thousands of barrels per day)	Port Arthur		Lima	Hartford⁽³⁾	Total		*Percent of Total*
Feedstocks:
Crude oil throughput
Sweet	—		134.4	—	134.4		32.0	%
Light/medium sour	49.0		5.3	55.0	109.3		25.9
Heavy sour	182.7		—	7.8	190.5		45.2

Total crude oil	231.7		139.7	62.8	434.2		103.1
Unfinished and blendstocks	(16.7	)	1.1	2.6	(13.0	)	(3.1	)

Total feedstocks	215.0		140.8	65.4	421.2		100.0	%


Production:
Light products:
Conventional gasoline	72.6		78.6	32.3	183.5		41.3	%
Premium and reformulated gasoline	13.9		11.2	3.8	28.9		6.5
Diesel Fuel	64.3		17.4	20.1	101.8		22.9
Jet fuel	26.9		22.7	—	49.6		11.2
Petrochemical feedstocks	15.9		8.1	3.3	27.3		6.2

Total light products	193.6		138.0	59.5	391.1		88.1
Petroleum coke and sulfur⁽²⁾	33.2		2.7	5.1	41.0		9.2
Residual oil	9.2		1.6	1.3	12.1		2.7

Total production	236.0		142.3	65.9	444.2		100.0	%

(2)

Volumes are per barrel equivalents

(3)

Closed September 2002.

2003 Compared to 2002

Overview. Net income available to common stockholders was $37.5 million ($0.54 per diluted share) in the first quarter of 2003 as compared to a net loss available to common stockholders of $99.7 million ($3.14 per diluted share) in the corresponding period in 2002. Our operating income was $95.1 million in the first quarter of 2003 as compared to an operating loss of $128.4 million in the corresponding period in 2002. This increase was principally attributable to stronger refining market conditions and a lower restructuring charge in the first quarter of 2003 compared to the corresponding period in 2002.

Our first quarter 2003 results include the operations of our Memphis refinery beginning March 3, 2003, the date of acquisition. Our first quarter 2002 results include the operations of our Hartford refinery. We ceased refining operations at our Hartford refinery in September 2002.

Net Sales and Operating Revenues. Net sales and operating revenues increased $1,148.0 million, or 93%, to $2,376.3 million in the first quarter of 2003 from $1,228.3 million in the corresponding period in 2002. This increase was principally due to higher overall product and crude oil prices in the first quarter of 2003, which was characterized by particularly volatile market conditions. Crude oil and product prices increased significantly in December 2002, with crude prices remaining well over $30 per barrel through most of the first quarter of 2003. Crude oil prices dropped by $6-$8 per barrel for a short period of time in March, only to increase again in late March. There were many factors during the quarter that we believe contributed to the first quarter’s volatile market conditions including: the looming specter of war with Iraq followed by the commencement of the war; production disruptions caused by the Venezuelan oil workers’ strike; and political turmoil in Nigeria that significantly reduced sweet crude oil production exports to the U.S., among others. The high price scenario of 2003 was in sharp contrast to the first quarter of 2002, when overall prices were at more historical levels.

Gross Margin. Gross margin increased $100.7 million to $267.4 million in the first quarter of 2003 from $166.7 million in the corresponding period in 2002. The increase in gross margin in 2003 over 2002 was principally driven by significantly stronger market conditions including stronger crack spreads and crude oil differentials, and less scheduled maintenance in 2003 than in 2002. The increase in gross margin was partially offset by losses in price risk management activities.

It is common practice in our industry to look to benchmark market indicators, such as the Gulf Coast 2/1/1 and Chicago 3/2/1 crack spreads, as a predictor of actual refining margins. We utilize the Gulf Coast 2/1/1 as an indicator of refining margins at our Port Arthur and Memphis refineries and the Chicago 3/2/1 as an indicator of refining margins at our Lima refinery. Our actual results will vary as our crude oil and product slates differ from the benchmarks and for other ancillary costs that are not included in the benchmarks, such as transportation costs, storage and credit fees, inventory fluctuations and price risk management activities.

Average crack spreads and crude oil differentials were significantly stronger in the first quarter of 2003 as compared to the first quarter of 2002. The Gulf Coast 2/1/1 and Chicago 3/2/1 crack spreads were approximately 126% and 75% higher, respectively, in the first quarter of 2003 than in the corresponding period in 2002. The crack spreads were weak entering into the first quarter of 2003 but increased significantly as product inventories remained at low levels in a period when they normally build for the spring and summer driving season. Factors we believe impacted product inventory levels in the first quarter of 2003 include: heavy refinery maintenance schedules; product exports to South America; and the cold winter weather, which diverted marginal production from gasoline to distillates used for heating. The strong margin conditions experienced in the first quarter of 2003 were in sharp contrast to the poor market conditions experienced in the first quarter of 2002, when the winter was unseasonably

warm and the economic downturn and significant demand declines resulting from the 2001 terrorist attacks plagued the refining market.

The WTI less Maya and WTI less WTS crude oil differentials were approximately 40% and 173% higher, respectively, in the first quarter of 2003 than in the corresponding period in 2002. We believe the strong recovery of crude oil differentials was partially driven by the increase in sour crude oil shipments from OPEC and other producers in answer to crude supply concerns related to the war with Iraq and by the increase in heavy sour crude oil supply from Venezuela as operations resumed in February following the workers’ strikes. Also contributing to the wide crude oil differentials was the rise in light sweet crude oil prices resulting from the reduced Nigerian production. These strong heavy sour and sour crude oil differentials had a significant positive impact on Port Arthur’s gross margin because its crude oil throughput is approximately 80% heavy sour crude oil and approximately 20% light and medium sour crude oils. Both Lima and Memphis process primarily light sweet crude oils and accordingly, do not require an adjustment for crude oil differentials except to the extent to which their crude oil is purchased in a foreign market versus a domestic market. Our Lima and Memphis refineries partially benefited from the stronger WTI less Brent crude oil differential as a portion of their crude oil supply in the first quarter was purchased in the foreign market.

Approximately 10% to 15% of Port Arthur’s product slate is lower value petroleum coke and residual oils which negatively impacted the refinery’s gross margin against the benchmark crack spread. On a normal basis the price of petroleum coke and residuals does not track crude oil prices; therefore, the negative impact was higher in the first quarter of 2003 during a high crude oil price environment than in the first quarter of 2002 in a more average crude oil price environment. Less than 5% of the product slate at Lima and Memphis is the lower value residual oils or petroleum coke.

Although benchmark market indicators such as the Gulf Coast 2/1/1 and Chicago 3/2/1 are useful in predicting refining gross margin, changes in absolute hydrocarbon prices, the “structure” of the hydrocarbon futures market and our specific price risk mitigation activities have an effect on our results that does not correlate with the benchmark market indicators. In order to supply our refineries with crude oil on a timely basis, we enter into purchase contracts that fix the price of crude oil from one to several weeks in advance of receiving and processing that crude oil. In addition, it is common as part of our marketing activities to fix the price of a portion of our product sales in advance of producing and delivering that refined product. Prior to delivery of the related crude oil and production of the related refined products, these fixed price purchase and sale commitments will change in value as prices rise and fall. Our results are measured by recording these commitments at market value at the end of each accounting period. With the acquisition of our Memphis refinery and the related increase in our domestic crude oil requirements, the average level of our open fixed price purchase commitments is approximately 10 million barrels. Since the average level of our open fixed price sale commitments is approximately 2 million barrels, on a net basis, we carry an average level of open fixed price purchase commitments of 8 million barrels. As a result, a $1 per barrel increase in absolute price levels increases the value of our net fixed price purchase commitments and our pretax operating results by approximately $8 million. A $1 per barrel decline in absolute price levels would produce the opposite effect.

To mitigate the absolute price risk while holding these fixed price purchase and sale commitments, we may purchase futures contracts on the New York Mercantile Exchange, or NYMEX, that correspond volumetrically with all or a portion of our fixed price purchase and sale commitments. These futures contracts are normally held in the current, or prompt, contract month on the NYMEX in order to achieve the best correlation with the change in the value of the fixed price commitment. As prices change, the effect of the change on the value of the futures contract tends to offset the effect of the change on the value of the fixed price commitment. However, since the volumetric level of our fixed price commitments is a net purchase and is relatively constant, to mitigate price risk it is typical to carry an offsetting net short futures position. Since this net short futures position is held in the prompt contract month on the NYMEX, it is necessary to exchange the prompt month NYMEX futures contract for the following month contract prior to its expiration. When the contract price of the following month contract is less than the contract price of the prompt month contract (a “backwardated” market structure), a loss is realized on the exchange as the prompt month contract is “purchased” at a value higher than the following month contract is “sold.” When the contract price of the following month contract is greater than the contract price of the prompt month contract (a “contango” market structure), the converse is true and a gain is realized on the exchange.

During the first quarter of 2003, absolute hydrocarbon prices were at historically high levels, but the market structure for crude oil was significantly backwardated. In order to protect against the negative valuation effects of a possible precipitous decline in absolute price levels, we chose to carry net short NYMEX futures contracts to offset a large portion of our net fixed purchase commitment price risk. Due to the backwardated crude oil market structure, this price risk mitigation strategy carried a cost as discussed above which essentially offset the benefits of the strategy measured on a prompt month contract basis. As a result of our neutral price risk mitigation activities, our operating results in the first quarter of 2003 were negatively effected by approximately $16 million from a decline in the value of our net fixed price purchase commitments. By comparison, in the first quarter of 2002, operating results benefited by approximately $24 million from having our fixed price purchase commitments fully exposed to price risk in a rising absolute price environment. See “Quantitative and Qualitative Disclosures about Market Risk—Commodity Risk” for a description of our price risk management strategies and policies.

Refinery Operations

In the first quarter of 2003, the average crude oil throughput rate at our Port Arthur refinery was only slightly lower than the refinery’s rated capacity of 250,000 bpd. Early in the first quarter of 2003, our Port Arthur refinery restricted its crude oil throughput in order to maintain a more conservative crude oil inventory position in a relatively weak refining margin environment but a high outright crude oil price environment. As the crack spreads and crude oil differentials strengthened, the refinery increased crude oil runs to at or above capacity and ran well. In the first quarter of 2002, crude oil throughput was restricted primarily for operational reasons, including a ten day shutdown of the coker unit for unplanned maintenance. We took advantage of the coker outage to make repairs to the distillate and naphtha hydrotreaters, including turnaround maintenance that was originally planned for later in the year. Crude oil throughput rates were restricted by approximately 18,000 barrels per day, or bpd, during this time, but returned to near capacity of 250,000 bpd following the maintenance. We also shut down the fluid catalytic cracking (FCC) unit, gas oil hydrotreating unit and sulfur plant for approximately 39 days at our Port Arthur refinery for planned turnaround maintenance in the first quarter of 2002. This turnaround maintenance did not affect crude oil throughput rates but did lower gasoline production. We sold more unfinished products during the first quarter of 2002 due to this shutdown.

In the first quarter of 2003, the crude oil throughput rate at our Lima refinery was slightly lower than the corresponding period in 2002. The restricted crude oil throughput rate in 2003 related to an 18-day planned turnaround maintenance of the FCC unit and maintenance on the coker and reformer units. The maintenance on the FCC unit was estimated at 14 days, however, severe winter weather slowed the maintenance activity. The maintenance turnaround at our Lima refinery restricted our crude oil throughput rates by an average of approximately 25,000 bpd during the maintenance period. The crude oil throughput rate in both the first quarter of 2003 and 2002 was restricted due to weak market conditions at certain times during those periods.

In the first quarter of 2003, our newly acquired Memphis refinery operated at an average crude oil throughput rate of 163,972 bpd for 29 days in March.

Operating Expenses. Operating expenses increased $2.7 million to $117.2 million in the first quarter of 2003 from $114.5 million in the corresponding period of 2002. Operating expenses for the first quarter of 2003 as compared to 2002 increased approximately $22 million due to significantly higher natural gas prices and approximately $9 million due to the inclusion of Memphis refinery operations for one month in the first quarter of 2003. Natural gas prices were approximately 175% higher in the first quarter of 2003 than in the corresponding period in 2002. These increases were almost completely offset by a decrease of approximately $19 million due to the absence of Hartford refinery operations in 2003 and a decrease of approximately $9 million of which a significant portion related to lower repair and maintenance costs at our Port Arthur refinery in 2003.

General and Administrative Expenses. General and administrative expenses decreased $2.8 million to $11.7 million in the first quarter of 2003 from $14.5 million in the corresponding period in 2002. The decrease in general and administrative expenses was due to the restructuring of our St. Louis office activities and other cost reduction measures initiated in 2002, partially offset by an accrual for incentive compensation and the addition of Memphis refinery operations for one month.

Stock-Based Compensation Expense. Stock-based compensation expense increased $2.4 million to $4.3 million in the first quarter of 2003 from $1.9 million in the corresponding period in 2002. The increase related to the grant of additional options in the second quarter of 2002 and the first quarter of 2003.

Depreciation and Amortization. Depreciation and amortization expenses increased $1.9 million to $24.1million in the first quarter of 2003 from $22.2 million in the corresponding period in 2002. This increase was principally due to capital expenditure activity and the Memphis refinery acquisition.

Refinery Restructuring and Other Charges. In the first quarter of 2003, we recorded net refinery restructuring and other charges of $15.0 million, which consisted of a pretax charge of $16.6 million related to the final disposition of the Hartford refining assets and pretax income of $1.6 million related to a reduction in the St. Louis office restructuring reserve.

In September 2002, we ceased refining operations at our Hartford, Illinois refinery and as of December 31, 2002, had written down the long-lived refining assets to their estimated net realizable value of $49.0 million in anticipation of a sale or lease of the refining assets. We continued to operate the storage and distribution facility at the refinery site. In the first quarter of 2003, we signed a memorandum of understanding with ConocoPhillips for a sale of refining assets and certain storage and distribution assets for $40 million. In the first quarter of 2003, we recorded refinery restructuring and other charges of $16.6 million related to the transaction, which included the write-down of the refining assets held for sale and certain storage and distribution assets included in property, plant and equipment and certain other costs of the sale.

The reduction of the reserve for the St. Louis office restructuring resulted from fewer work force reductions than originally anticipated due to the acquisition of the Memphis refinery. See “—Liquidity and Capital Resources—Cash Flows from Operating Activities—Restructuring Reserves” for information on the reserves for the future costs associated with the St. Louis restructuring and Hartford refinery closure.

In the first quarter of 2002, we recorded refinery restructuring and other charges of $142.0 million, which consisted of a $131.2 million charge related to the then planned shutdown of refining operations at our Hartford, Illinois refinery, a $15.8 million charge related to the restructuring of management and administrative functions; and income of $5.0 million related to the unanticipated sale of a portion of the Blue Island refinery assets previously written off.

Interest Expense and Finance Income, net. Interest expense and finance income, net decreased by $5.7 million to $25.3 million in the first quarter of 2003 from $31.0 million in the corresponding period in 2002. The decrease was primarily related to lower interest expense due to the repurchase of certain debt securities in 2002 and 2003, partially offset by additional interest expense related to the issuance of $525 million senior notes in February 2003.

Loss on Extinguishment of Long-term Debt. In the first quarter of 2003, as a result of the early extinguishment of long-term debt and credit agreement restructuring, we recorded a loss of $7.0 million (PRG $4.7 million). For PRG, the loss included a write-off of unamortized deferred financing costs of $4.7 million related to the repayment of the floating rate loan and the amendment of its credit agreement. In addition to the $4.7 million write-off, we recorded a loss of $2.3 million for a premium related to the redemption of Premcor USA’s 11½% subordinated debentures.

Income Tax (Provision) Benefit. We recorded a $21.0 million income tax provision in the first quarter of 2003 compared to an income tax benefit of $61.4 million in the corresponding period in 2002. Our effective tax rate was 33.4% in the first quarter of 2003 versus 38.5% in the first quarter of 2002. Our subsidiaries are subject to different statutory tax rates. These differing tax rates and the differing amount of taxable income or loss recognized by each subsidiary impacts our consolidated effective tax rate. The decrease in our consolidated effective tax rate from the 2002 first quarter to the 2003 first quarter resulted from a higher percentage of our 2003 first quarter consolidated income being recognized by Sabine, which has a lower effective tax rate than other subsidiaries.

Discontinued Operations. In connection with the 1999 sale of PRG’s retail assets to Clark Retail Enterprises, Inc. (“CRE”), PRG assigned approximately 170 leases and subleases of retail stores to CRE. PRG remains jointly and severally liable for CRE’s obligations under approximately 150 of these leases, including payment of rent and taxes. PRG may also be contingently liable for environmental cleanup responsibilities for releases of petroleum occurring during the term of the CRE leases. On October 15, 2002, CRE and its parent company, Clark Retail

Group, Inc., filed a voluntary petition for reorganization under Chapter 11 of the U.S. Bankruptcy Code. As CRE rejects some or all of these leases from its reorganization plan, PRG may become responsible for these obligations. In bankruptcy hearings held in the first quarter of 2003, CRE rejected 30 of these leases. We recorded an after-tax charge of $4.3 million in the first quarter of 2003 representing the estimated net present value of our remaining liability under these rejected leases, net of estimated sub-lease income. We are currently in discussions with CRE regarding their reorganization plans, the status of environmental remediation agreements, and other matters. While it is possible that we may incur additional liability for CRE lease obligations or other costs as CRE finalizes its reorganization plans, the amounts are not estimable at this time.

Outlook

This Outlook section contains forward-looking statements that reflect our current judgment regarding the direction of our business. Even though we believe our expectations regarding future events are reasonable assumptions, forward-looking statements are not guarantees of future performance. Factors beyond our control could cause our actual results to vary materially from our expectations and are discussed on the first page of the Management Discussion and Analysis of Financial Condition and Results of Operations of this Quarterly Report on Form 10-Q, under the heading “Forward-Looking Statements”.

Market. Market conditions for the beginning of the second quarter of 2003 through the middle of April have been strong. The Gulf Coast 2/1/1 crack spread has averaged over $3.80 per barrel, the Chicago 3/2/1 crack spread has exceeded $7 per barrel, and the WTI/Maya differential has averaged more than $8 per barrel.

Refinery Operations. It is common practice in our industry to look to benchmark market indicators as a predictor of actual refining margins, such as the Gulf Coast 2/1/1 and Chicago 3/2/1. To improve the reliability of this benchmark as a predictor of actual refining margins, it must first be adjusted for a crude oil slate that is not 100% light and sweet. Secondly, it must be adjusted to reflect variances from the benchmark product slate to the actual, or anticipated, product slate. Lastly, it must be adjusted for any other factors not anticipated in the benchmark, including ancillary crude and product costs such as transportation, storage and credit fees, inventory fluctuations and price risk management activities.

Our Port Arthur refinery has historically produced roughly equal parts gasoline and distillate. For this reason, we believe the Gulf Coast 2/1/1 crack spread appropriately reflects our product slate. However, approximately 15% of Port Arthur’s product slate is lower value petroleum coke and residual oils which will negatively impact the refinery’s performance against the benchmark crack spread. Port Arthur’s crude oil slate is approximately 80% heavy sour crude oil and 20% medium sour crude oil. Accordingly, the WTI/Maya and WTI/WTS crude oil differentials can be used as an adjustment to the benchmark crack spread. We do not expect to receive discounts on our purchases of Maya crude oil in 2003 under our long-term crude oil supply agreement. Ancillary crude costs, primarily transportation, at Port Arthur averaged $0.94 per barrel of crude oil throughput in the first quarter of 2003. No significant downtime is planned for the Port Arthur refinery during the second quarter of 2003 and crude oil throughput rates should meet or exceed the first quarter average of approximately 245,000 bpd.

Our Lima refinery has a product slate of approximately 60% gasoline and 30% distillate and we believe the Chicago 3/2/1 is an appropriate benchmark crack spread. This refinery consumes approximately 95% light sweet crude oil with the balance being light sour crude oils. We opportunistically buy a mix of domestic and foreign sweet crude oils. The foreign crude oils consumed at Lima are priced relative to Brent and the WTI/Brent differential can be used to adjust the benchmark. Ancillary crude costs for Lima averaged $1.62 per barrel of crude throughput in the first quarter of 2003. We expect the crude oil throughput rates in the second quarter of 2003 to approximate 130,000 to 140,000 bpd despite repair work that is being performed on the crude and isocracker units.

Our Memphis refinery was acquired effective March 3, 2003 and averaged 164,000 bpd in March 2003. We plan to operate the refinery at approximately 170,000 bpd in the second quarter of 2003. We also expect that the operating results will track a Gulf Coast 2/1/1 benchmark crack spread and that we will be able to realize a gross margin benefit over the Gulf Coast 2/1/1 crack spread resulting from location premiums for refined products, partially offset by crude oil transportation costs. We expect that this location premium will approximate $0.63 per barrel in normalized market conditions.

Operating Expenses. Natural gas is the most variable component of our operating expenses. On an annual basis, our Port Arthur, Memphis and Lima refineries purchase approximately 29 million mmbtu of natural gas, with most of these purchases relating to our Port Arthur refinery. In a normalized natural gas pricing environment and assuming average crude oil throughput levels, our annual operating expenses should range between $470 million and $500 million. However, natural gas prices for the first quarter of 2003 and for the second quarter to-date have been significantly higher than normalized rates. It is also important to note that we contract for the purchase of natural gas on a calendar month basis and set the price at the beginning of the month. Therefore, our natural gas costs will reflect the price of natural gas on the day the contract is set, and not the average price for the period.

General and Administrative Expenses. With the acquisition of the Memphis refinery, we expect our 2003 general and administrative expenses to be approximately $52 million, excluding incentive compensation. Based on a strong earnings outlook in the first quarter of 2003, we began accruing for incentive compensation in the first quarter of 2003.

Stock-based Compensation Expense. We recognize non-cash, stock-based compensation expense computed under SFAS No. 123 for all stock options granted beginning in 2002. During the first quarter of 2003, an additional 562,500 options were granted to employees and directors. Stock-based compensation expense for 2003, for options granted in 2002 and 2003, will approximate $17 million to $18 million.

Depreciation and Amortization. Depreciation and amortization expense for the first quarter of 2003 was $24.1 million. This includes approximately one month of depreciation on the Memphis refinery. Had we owned the Memphis refinery for all of the first quarter, our depreciation and amortization expense would have been approximately $27 million. This amount will increase in future periods based upon capital expenditure activity. Depreciation and amortization expense includes amortization of our turnaround costs, generally over four years.

Interest Expense. Based on our outstanding long-term debt as of March 31, 2003, our annual gross interest expense will be approximately $114 million. All of our outstanding debt is at fixed rates with the exception of $10 million in floating rate notes tied to LIBOR. Reported interest expense is reduced by capitalized interest.

Income Taxes. We expect our effective income tax rate for 2003 will range from approximately 35% to 38%.

Capital Expenditures and Turnarounds. Capital expenditures and turnarounds for the first quarter of 2003 totaled $30.8 million. We plan to expend approximately $200 million to $230 million for capital expenditures and turnarounds for the remainder of 2003. This amount includes expenditures at our Memphis refinery, excluding the original purchase price. We plan to fund capital expenditures with internally generated funds. If internally generated funds are insufficient, we will reduce our capital expenditure plans accordingly.

Liquidity and Capital Resources

Cash Balance

As of March 31, 2003, we had a cash and short-term investment balance of $312.2 million of which $257.5 million was held by PRG, $50.7 million by Premcor Inc, $3.4 million by Opus Energy, a wholly-owned captive insurance subsidiary of Premcor Inc., and $0.6 million by Premcor USA. In addition, under an amended and restated common security agreement related to PACC’s senior debt, PACC is required to restrict $45.0 million of cash for debt service at all times plus restrict an amount equal to the next scheduled principal and interest payment, prorated based on the number of months remaining until that payment is due. As of March 31, 2003 cash of $53.8 million was restricted under these requirements. We reflected the change to this restricted cash balance that relates to principal payments in cash flows from financing activities and the change that relates to interest payments in cash flows from operating activities.

Cash Flows from Operating Activities

Net cash provided by operating activities for the three months ended March 31, 2003 was $115.9 million compared to net cash provided from operations of $11.3 million in the corresponding period in 2002. The increase in the provision of cash from operating activities in 2003 as compared to 2002 is mainly attributable to strong market conditions, which resulted in strong operating results. Working capital as of March 31, 2003 was $598.6 million, a

1.69-to-1 current ratio, versus $320.9 million as of December 31, 2002, a 1.57-to-1 current ratio. The increase in working capital during the first quarter of 2003 was due primarily to strong operating results and the Memphis refinery acquisition.

Restructuring Reserves. As of December 31, 2002, we had a $4.9 million reserve for plans announced in the third quarter of 2002 to reduce additional staff at our St. Louis administrative office in early 2003. As a result of the Memphis refinery acquisition, the number of positions to be eliminated has been reduced by 25 and we recorded a reduction in the restructuring reserve of $1.6 million in the first quarter of 2003. We expect to complete the restructuring of our St. Louis administrative functions by the end of the year. We also had a $1.0 million reserve for employee severance and plant closure/equipment remediation related to shutdown of the refining operations at our Hartford refinery. The activities related to the Hartford closure were completed in the first quarter of 2003. The following schedule summarizes the activity and balance of these restructuring reserves as of March 31, 2003:

	Reserve as of December 31, 2002		Adjustment to Reserve			Net Cash Outlay			Reserve as of March 31, 2003
St. Louis restructuring	$	4.9	$	(1.6	)	$	(1.5	)	$	1.8
Hartford closure:
Employee severance		0.6		—			(0.6	)		—
Plant closure/equipment remediation		0.4		—			(0.4	)		—

	$	5.9	$	(1.6	)	$	(2.5	)	$	1.8

Environmental, Discontinued Operations and Legal Reserves. As a result of our normal course of business, we are party to a number of legal proceedings and environmental-related obligations. We have also incurred liabilities related to leases of previously operated retail sites as discussed above. In relation to these matters and obligations we have accrued, on an undiscounted basis unless otherwise noted, the following:

	March 31, 2003		December 31, 2002
Refinery environmental obligations:
Hartford	$	29.8	$	29.6
Blue Island		19.2		19.7
Port Arthur		11.8		11.9
Memphis		1.0		—
Discontinued retail marketing:
Environmental obligations		23.2		23.0
Lease obligations (discounted)		6.8		—
Other legal and environmental		8.4		9.0

	$	100.2	$	93.2

In January 2001, we ceased refining operations at our Blue Island, Illinois refinery, and in September 2002, we ceased refining operations at our Hartford, Illinois refinery. We continue to utilize storage and distribution facilities at both sites. Upon closure of these refineries we recorded reserves for environmental obligations associated with their closure. The environmental obligations take into account costs that are reasonably foreseeable at this time. In relation to the Blue Island reserve, we are currently in discussions with governmental agencies concerning a remediation program and expect to have a final plan in place before the end of 2003. In relation to the Hartford reserve, we are in preliminary stages of producing a final remediation plan. As the remediation plans are finalized and as work is performed, adjustments of the reserves may be necessary. The final issuance of environmental risk insurance policies covering the Blue Island refinery site is pending final review. We expect to spend approximately $4 million to $6 million in 2003 related to the Hartford and Blue Island reserves.

Other Commitments

Crude Oil Purchase Commitment. On October 1, 2002, we entered into a crude oil linefill agreement with Morgan Stanley Capital Group Inc. or MSCG, which obligated us to purchase 2.7 million barrels of crude oil in the

pipeline system supplying our Lima refinery from MSCG. We will purchase the 2.7 million barrels of crude oil upon termination of the agreement with MSCG, at then current market prices as adjusted by certain predetermined contract provisions. The initial term of the contract continues until October 1, 2003, and thereafter, automatically renews for additional 30-day periods unless terminated by either party. We have hedged the economic price risk related to the repurchase obligation through the purchase of exchange-traded futures contracts.

Long-Term Crude Oil Contract. PACC has a long-term crude oil supply agreement with PMI Comercio Internacional, S.A. de C.V., an affiliate of Petroleos Mexicanos or PEMEX, the Mexican state oil company, which supplies approximately 162,000 barrels per day of Maya crude oil to the Port Arthur refinery. Under the terms of this agreement, PACC is obligated to buy Maya crude oil from the affiliate of PEMEX, and the affiliate of PEMEX is obligated to sell Maya crude oil to PACC. The agreement also provides a price adjustment mechanism designed to minimize the effect of adverse refining margin cycles and more specifically to moderate the fluctuations of the coker gross margin, a benchmark measure of the value of coker production over the cost of coker feedstocks. This price adjustment mechanism contains a formula that represents an approximation of the coker gross margin and provides for a minimum average coker margin of $15 per barrel over the first eight years of the agreement, which began on April 1, 2001. The cumulative difference, calculated on a monthly basis, between the actual coker gross margin and the defined minimum coker margin is referred to as a surplus or shortfall, and as of March 31, 2003, a cumulative quarterly surplus of $137.7 million existed under the agreement. As a result, the price we pay for Maya crude oil purchased under this agreement in succeeding quarters will not be discounted until this cumulative surplus is offset by future shortfalls.

We currently expect that funds generated from operating activities together with existing cash, cash equivalents and short-term investments and availability under our working capital facility will be adequate to fund our ongoing operating requirements.

Cash Flows from Investing Activities

Cash flows used in investing activities for the first quarter of 2003 were $503.0 million as compared to $39.1 million in the first quarter of 2002. The first quarter of 2003 reflected the acquisition of the Memphis refinery. Aside from this acquisition, activity in 2003 and 2002 primarily reflected capital expenditures.

We classify our capital expenditures into two main categories, mandatory and discretionary. Mandatory capital expenditures, such as for turnarounds and maintenance, are required to maintain safe and reliable operations or to comply with regulations pertaining to soil, water and air contamination or pollution, regulations pertaining to new product standards, and regulations pertaining to occupational safety and health issues. The budget for these expenditures, excluding expenditures for new product standards discussed below, is approximately $105 million for 2003. Our total mandatory capital and refinery maintenance turnaround expenditures were $16.8 million and $33.3 million for the first quarter of 2003 and 2002, respectively. The first quarter of 2003 included a turnaround at our Lima refinery, and the first quarter of 2002 included a turnaround at our Port Arthur refinery. Our budget for discretionary capital expenditures is approximately $5 million for 2003. In the first quarter of 2003 and 2002, we incurred discretionary capital expenditures of $1.4 million and $7.6 million, respectively. We plan to fund mandatory and discretionary capital expenditures with available cash and cash flow from operations and will adjust our annual expenditures accordingly.

The Environmental Protection Agency, or EPA, has promulgated regulations under the Clean Air Act that establish stringent sulfur content specifications for gasoline and on-road diesel fuel designed to reduce air emissions from the use of these products. In addition to the mandatory expenditures discussed above, we expect to incur in the aggregate approximately $727 million, including $657 million that we expect to expend through 2006, in order to comply with environmental regulations related to the new stringent sulfur content specifications and MACT II regulations. Future revisions to these current cost estimates may be necessary as we continue to finalize our plans. Information related to the expected capital expenditures in relation to these new regulations is shown below.

	Total Estimated Expenditures		Total Expenditures Incurred To-Date		Remaining Expenditures at March 31, 2003		Contract Commitments		Year of Concentration of Expenditures
Gasoline low sulfur standards	$	335	$	66	$	269	$	126	2003/2004
Diesel low sulfur standards		347		4		343		—	2005
MACT II		45		—		45		—	2003/2004

Total	$	727	$	70	$	657	$	126

Our budget for complying with these regulations is approximately $120 million in 2003. In the first quarter of 2003 and 2002 we incurred capital expenditures of $12.6 million and $1.4 million, respectively, related to these regulations. It is our intention to fund expenditures necessary to comply with these new environmental standards with cash flow from operations. Due to the volatile economic nature of our business we are organizing our plans and associated expenditures for compliance with these regulations into “modules” that can be shifted based on available funding. This will allow us to expedite or slow down the major portions of the project without compromising compliance dates but allowing us to take advantage of phase-in periods if necessary.

In 2001, we received proceeds of $10.0 million from the issuance of Ohio state revenue bonds, which were restricted solely for solid waste and wastewater capital projects at the Lima refinery. The cash and cash equivalents restricted for investment in capital additions for the first quarter of 2003 and 2002 reflected the subsequent use of these proceeds.

Cash Flows from Financing Activities

Cash flows provided by financing activities was $527.0 million for the first quarter of 2003 compared to cash flows used in financing activities of $94.6 million in the corresponding period in 2002. On January 30, 2003, Premcor Inc. completed a public offering of 12.5 million shares of common stock and a private placement of 2.9 million shares of common stock with Blackstone Capital Partners III Merchant Banking Fund L.P. and its affiliates, or Blackstone, Occidental, and certain Premcor executives. On February 5, 2003, Premcor Inc. sold an additional 0.6 million shares of common stock pursuant to the underwriters’ over-allotment option. Premcor Inc. received net proceeds of approximately $306 million from these transactions. In February 2003, PRG completed an offering of $525 million in senior notes, of which $350 million, due in 2013, bear interest at 9½% per annum and $175 million, due in 2010, bear interest at 9¼% per annum. The net proceeds from these transactions were used to fund the acquisition of the Memphis refinery as well as to redeem the remaining $40.1 million principal balance of Premcor USA’s 11½% subordinated debentures and to repay PRG’s $240 million floating rate loan. In the first quarter of 2002, PACC repaid $66.2 million of its outstanding balance under a bank senior loan agreement.

In the first quarter of 2003, we incurred $19.6 million of deferred financing costs in relation to the amendment of the credit agreement and the issuance of the new senior notes. In the first quarter of 2002, we incurred $1.1 million of deferred financing costs for fees necessary to obtain a waiver related to insurance coverage required under the common security agreement.

In the first quarter of 2003, Premcor Inc. made capital contributions to Premcor USA of $294.9 million and Premcor USA subsequently contributed $260.6 million to PRG, all primarily for the repayment of long-term debt.

We continue to evaluate the most efficient use of capital and, from time to time, depending upon market conditions, may seek to purchase certain of our outstanding debt securities in the open market or by other means, in each case to the extent permitted by existing covenant restrictions.

Credit Agreements

inventory. The credit agreement expires in February 2006. As of March 31, 2003, the borrowing base was $1,090.8 million (December 31, 2002—$815.3 million), with $575.0 million (December 31, 2002—$597.1 million) of the facility utilized for letters of credit.

The credit agreement contains covenants and conditions that, among other things, limit PRG’s dividends, indebtedness, liens, investments and contingent obligations. PRG is also required to comply with certain financial covenants, including the maintenance of minimum working capital of $150 million and the maintenance of minimum tangible net worth of $650 million, as amended. The covenants also provide for a cumulative cash flow test that from January 1, 2003 must not be less than zero.

PRG also has a $40 million cash-collateralized credit facility expiring May 31, 2004. This facility was arranged in support of lower interest rates on the Series 2001 Ohio Bonds. In addition, this facility can be utilized for other non-hydrocarbon purposes. As of March 31, 2003, $19.7 million (December 31, 2002—$10.1 million) of the line of credit was utilized for letters of credit.

New Accounting Standards

In July 2001, Financial Accounting Standards Board, or FASB, issued Statement of Financial Accounting Standard, or SFAS No. 143, Accounting for Asset Retirement Obligations. SFAS No. 143 requires fair value recognition of legal obligations to retire long-lived assets at the time the obligations are incurred. The initial recording of a liability for an asset retirement obligation will require the recording of a corresponding asset. The liability will be adjusted for accretion due to the passage of time and the asset will be depreciated. We have asset retirement obligations based on our legal obligations at our refinery sites. We consider the settlement date of the obligations indeterminable at this time due to uncertainty about the timing of the retirement of the long-lived assets. Accordingly, we cannot calculate an associated asset retirement liability at this time. We adopted this standard in the first quarter of 2003, but the initial adoption did not have a material impact on our financial position or results of operations. We will measure and recognize the fair value of our asset retirement obligations at such time as a settlement date is determinable.

In November 2002, the FASB issued Interpretation No. 45, Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others. This interpretation requires expanded disclosure of a guarantor’s obligation under certain guarantees that it has issued. It also requires that a guarantor recognize, at the inception of certain guarantees, a liability for the fair value of the obligation undertaken in issuing the guarantee. The disclosure requirements are effective for interim and annual financial statements issued for periods ending after December 15, 2002. The provisions for the recognition of a liability are effective prospectively for guarantees issued or modified after December 31, 2002. We adopted the recognition provisions in the first quarter of 2003 with no material impact on our financial statements

In January 2003, the FASB issued Interpretation No. 46, Consolidation of Variable Interest Entities, an interpretation of ARB No.51. This interpretation clarifies consolidation requirements for variable interest entities. It establishes additional factors beyond ownership of a majority voting interest to indicate that a company has a controlling financial interest in an entity (or a relationship sufficiently similar to a controlling financial interest that it requires consolidation). This interpretation applies immediately to variable interest entities created or obtained after January 31, 2003 and must be retroactively applied to holdings in variable interest entities acquired before February 1, 2003 in interim and annual financial statements issued for periods beginning after June 15, 2003. The adoption of this interpretation did not have a material impact on our financial statements.

In April 2003, the agenda committee of the Emerging Issues Task Force (“EITF”) of the FASB placed the discussion of Issue No. 02-L, Reporting Gains and Losses on Derivative Instruments That are Subject to SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, and Not Held for Trading Purposes, on the agenda for its May 14—15, 2003 meeting. It is anticipated the EITF will address Issue No. 02-L which deals with certain aspects of EITF 02-3, Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities. EITF 02-3 currently requires that gains and losses on all derivative instruments within the scope of SFAS No. 133 be shown net in the income statement, whether or not settled physically, if the derivative instruments are held for trading purposes. The EITF is expected to address the income statement classification of gains and losses on energy contracts within the scope of SFAS No. 133 that are not held for trading purposes and the applicability of EITF 99-19 to such transactions. Energy contract arrangements that are settled physically qualify for “gross” reporting pursuant to EITF 99-19. Any consensus reached by the EITF on this issue may require changes in our presentation of revenue and cost of sales. We do not expect that any such changes will have an impact on our gross margin.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The risk inherent in our market risk sensitive instruments and positions is the potential loss from adverse changes in commodity prices and interest rates. None of our market risk sensitive instruments are held for trading.

Commodity Risk

Our earnings, cash flow and liquidity are significantly affected by a variety of factors beyond our control, including the supply of, and demand for, commodities such as crude oil, other feedstocks, gasoline, other refined products and natural gas. The demand for these refined products depends on, among other factors, changes in domestic and foreign economies, weather conditions, domestic and foreign political affairs, planned and unplanned downtime in refineries, pipelines and production facilities, production levels, the availability of imports, the marketing of competitive fuels and the extent of government regulation. As a result, the prices of these commodities fluctuate significantly. The movement in petroleum prices does not necessarily have a direct long-term relationship to net income. The effect of changes in crude oil prices on our operating results is determined more by the rate at which the prices of refined products adjust to reflect such changes.

We fix the price on our crude oil purchases from one to several weeks prior to the time when the crude oil is processed and sold. As a result, we are exposed to crude oil price movements relative to refined product price movements during this period. In 2003, with the acquisition of our Memphis refinery, our average fixed price purchase commitments when offset by our fixed price sale commitments increased to a net long inventory position of approximately eight million barrels. As of March 31, 2003, if the market price of these net fixed price commitments had been lower by $1 per barrel, we would have recorded additional cost of sales of approximately $8 million, based on our treatment of these contracts as derivatives. An increase in the market price would reduce cost of sales by a like amount. We may actively mitigate some or all of the price risk related to our fixed price purchase and sale commitments. These risk management decisions are based on many factors including the relative level of absolute hydrocarbon prices and the extent to which the futures market is in backwardation or contango. When the contract price of the following month futures contract is less than the contract price of the current, or prompt, month contract, a “backwardated” market structure exists, and when the contract price of the following month futures contract is greater than the contract price of the prompt month contract, a “contango” market structure exists.

We use several strategies to minimize the impact on profitability of volatility in feedstock costs and refined product prices. These strategies generally involve the purchase and sale of exchange-traded, energy-related futures and options with a duration of six months or less. To a lesser extent we use energy swap agreements similar to those traded on the exchanges, such as crack spreads and crude oil options, to better match the specific price movements in our markets. These strategies are designed to minimize, on a short-term basis, our exposure to the risk of fluctuations in crude oil prices and refined product margins. The number of barrels of crude oil and refined products covered by such contracts varies from time to time. Such purchases and sales are closely managed and subject to internally established risk policies. The results of these price risk mitigation activities affect refining cost of sales and inventory costs. We do not engage in speculative futures or derivative transactions.

We prepared a sensitivity analysis to estimate our exposure to market risk associated with derivative commodity positions. This analysis may differ from actual results. The fair value of each derivative commodity position was based on quoted futures prices. As of March 31, 2003, a 10% change in quoted futures prices would result in an approximate $2 million change to the fair market value of the derivative commodity position and correspondingly the same change in operating income. As of December 31, 2002, a 10% change in quoted futures prices would result in an approximately $8 million change to the fair market value of the derivative commodity position and correspondingly the same change in operating income.

Our results are also sensitive to the fluctuations in natural gas prices due to the use of natural gas to fuel our refinery operations. Based on our average annual consumption of approximately 29 million mmbtu of natural gas, a $1 change per million btu in the price of natural gas would generally change our natural gas costs by $29 million. Our sensitivity to a change in the price of natural gas would also be impacted by our method of purchasing natural gas. We contract for the purchase of natural gas on a calendar month basis and set the price at the beginning of the month. Therefore, our natural gas costs will reflect the price of natural gas on the day the contract is set, and not the average price for the period.

Interest Rate Risk

Our primary interest rate risk is associated with our long-term debt. We manage this interest rate risk by maintaining a high percentage of our long-term debt with fixed rates. As of March 31, 2003 we have an outstanding balance, including current maturities, of $1,175.7 million (PRG—1,165.2 million). The weighted average interest rate on our fixed rate long-term debt is 9.8%. We are subject to interest rate risk on our Ohio bonds and any direct borrowings under our credit agreement. As of March 31, 2003, a 1% change in interest rates on our floating rate loans, which totaled $10 million, would result in a $0.1 million change in pretax income on an annual basis. In the first quarter of 2003, we refinanced our $240 of floating rate loans with fixed rate debt. As of December 31, 2002, a 1% change in interest rate on our floating rate loans, which totaled $250 million, would result in a $2.5 million change in pretax income on an annual basis. As of March 31, 2003 and December 31, 2002, there were no direct borrowings under our credit agreement.

ITEM 4. —Controls and Procedures

Within the 90 days prior to the date of this report, we carried out an evaluation, under the supervision and with the participation of our management, including our chief executive officer and chief financial officer, of the effectiveness of the design and operations of our disclosure controls and procedures pursuant to Exchange Act Rules 13a-14 and 15d-14. Based upon that evaluation, the chief executive officer and chief financial officer concluded that our disclosure controls and procedures are effective in timely alerting them to material information relating to us (including our consolidated subsidiaries) required to be included in our periodic SEC filings. There have not been any significant changes in our internal controls or in other factors that could significantly affect these controls subsequent to the date of evaluation.

PART II.—OTHER INFORMATION

ITEM 1. —Legal Proceedings

The following is an update of developments during the quarter of material pending legal proceedings to which we or any of our subsidiaries are a party or to which any of our or their property is subject, including environmental proceedings that involve potential monetary sanctions of $100,000 or more and to which a governmental authority is a party. For additional discussion of our material pending legal proceedings, see Premcor Inc.’s and PRG’s combined Annual Report on Form 10-K for the period ending December 31, 2002.

Sashabaw Road Retail Location: State Enforcement. In July 1994, the Michigan Department of Natural Resources brought an action alleging that one of our retail locations caused groundwater contamination, necessitating the installation of a new $600,000 drinking water system. The Michigan Department of Natural Resources sought reimbursement of this cost. Although our site may have contributed to contamination in the area, we maintained that numerous other sources were responsible and that a total reimbursement demand from us would be excessive. We made an offer of judgment to resolve the matter. The Michigan Department of Natural Resources rejected the offer and the matter was tried in November 1999, resulting in a judgment against us of $110,000 plus interest. Since the judgment was over 20% below our previous settlement offer, under applicable state law we are entitled to recover our legal fees. Both the Michigan Department of Natural Resources and we appealed the decision. The appellate court rendered its decision on January 10, 2003 and affirmed the trial court’s ruling in all respects. The Michigan Department of Natural Resources elected not to file an appeal with the Michigan Supreme Court. As a result, the judgment became final. The Michigan Department of Natural Resources has paid us approximately $115,000 in resolution of this matter.

ITEM 2. —Changes in Securities and Use of Proceeds

On January 30, 2003, Premcor Inc. sold 2,860,400 shares of common stock to the specified persons set forth below, pursuant to an exemption from registration pursuant to Section 4(2) of the Securities Act of 1933, as amended, as transactions by an issuer not involving a public offering:

Investor	Number of shares	Amount
Blackstone Capital Partners III Merchant Banking Fund L.P. and affiliates	1,300,000	$	24,960,000
Occidental Petroleum Corporation	1,300,000		24,960,000
Thomas D. O’Malley	220,400		4,231,680
Henry M. Kuchta	10,000		192,000
William E. Hantke	10,000		192,000
Michael D. Gayda	5,000		96,000
Donald F. Lucey	5,000		96,000
Joseph D. Watson	5,000		96,000
James R. Voss	5,000		96,000

	2,860,400	$	54,919,680

ITEM 6—Exhibits and Reports on Form 8-K

(a) Exhibits

Exhibit Number		Description

3.01		Amended and Restated Certificate of Incorporation of Premcor Inc. (Incorporated by reference to Exhibit 3.1 filed with Premcor Inc.’s Registration Statement on Form S-1/A (Registration No. 333-70314)).

3.02		Amended and Restated By-Laws of Premcor Inc. (Incorporated by reference to Exhibit 3.2 filed with Premcor Inc.’s Registration Statement on Form S-1 (Registration No. 333-70314)).

3.03		Restated Certificate of Incorporation of The Premcor Refining Group Inc. (“PRG”) (f/k/a Clark Refining & Marketing, Inc. and Clark Oil & Refining Corporation) effective as of February 1, 1993 (Incorporated by reference to Exhibit 3.1 filed with PRG’s Annual Report on Form 10-K, for the year ended December 31, 2000 (File No. 1-11392)).

3.04		Certificate of Amendment to Certificate of Incorporation of PRG (f/k/a Clark Refining & Marketing, Inc. and Clark Oil & Refining Corporation) effective as of September 30, 1993 (Incorporated by reference to Exhibit 3.2 filed with PRG’s Annual Report on Form 10-K, for the year ended December 31, 2000 (File No. 1-11392)).

3.05		Certificate of Amendment of Restated Certificate of Incorporation of PRG (f/k/a Clark Refining & Marketing, Inc. and Clark Oil & Refining Corporation) effective as of May 9, 2000 (Incorporated by reference to Exhibit 3.3 filed with PRG’s Annual Report on Form 10-K, for the year ended December 31, 2000 (File No. 1-11392)).

3.06		By-laws of PRG (f/k/a Clark Refining & Marketing, Inc. and Clark Oil & Refining Corporation) (Incorporated by reference to Exhibit 3.2 filed with PRG’s Registration Statement on Form S-1 (Registration No. 33-28146)).

4.01		Second Amended and Restated Stockholders’ Agreement, dated as of November 3, 1997, between Premcor USA Inc. (f/k/a Clark USA, Inc.) and Occidental C.O.B. Partners (Incorporated by reference to Exhibit 4.19 filed with Premcor Inc.’s Registration Statement on Form S-1 (Registration No. 333-70314)).

4.02		Indenture dated as of November 21, 1997, between PRG (f/k/a Clark Refining & Marketing, Inc.) and Bankers Trust Company, as Trustee, including the form of 8³/8% Senior Notes due 2007 (Incorporated by reference to Exhibit 4.5 filed with PRG’s Registration Statement on Form S-4 (Registration No. 333-42431)).

4.03		Indenture dated as of November 21, 1997, between PRG (f/k/a Clark Refining & Marketing, Inc.) and Marine Midland Bank, including the form of 8⁷/8% Senior Subordinated Notes due 2007 (Incorporated by reference to Exhibit 4.6 filed with PRG’s Registration Statement on Form S-4 (Registration No. 333-42431)).

4.04		Supplemental Indenture dated as of November 21, 1997, between PRG (f/k/a Clark Refining & Marketing, Inc.) and Marine Midland Bank (Incorporated by reference to Exhibit 6.1 filed with PRG’s Registration Statement on Form S-4 (Registration No. 333-42431)).

4.05		Indenture, dated as of August 10, 1998, between PRG (f/k/a Clark Refining & Marketing, Inc.) and Bankers Trust Company, as Trustee, including the form of the 8⁵/8% Senior Notes due 2008 (Incorporated by reference to Exhibit 4.1 filed with PRG’s Registration Statement on Form S-4 (Registration No. 333-64387)).

4.06		Stockholder Agreement, dated as of March 9, 1999, among Premcor Inc. (f/k/a Clark Refining Holdings Inc.), Blackstone Capital Partners III Merchant Banking Fund L.P and Marshall A. Cohen (Incorporated by reference to Exhibit 4.20 filed with Premcor Inc.’s Registration Statement on Form S-1 (Registration No. 333-70314)).

4.07		Stockholders’ Agreement, dated as of August 4, 1999, among Sabine River Holding Corp. (“Sabine”), Premcor Inc. (f/k/a Clark Refining Holdings Inc.), and Occidental Petroleum Corporation (Incorporated by reference to Exhibit 4.18 filed with Premcor Inc.’s Registration Statement on Form S-1 (Registration No. 333-70314)).

4.08		Indenture, dated as of August 19, 1999, among Sabine, Neches River Holding Corp. (“Neches”), Port Arthur Finance Corp. (“PAFC”), Port Arthur Coker Company L.P. (“PACC”), HSBC Bank USA, the Capital Markets Trustee, and Bankers Trust Company, as Collateral Trustee (Incorporated by reference to Exhibit 4.01 filed with PAFC’s Registration Statement on Form S-4 (Registration No. 333-92871)).

Exhibit Number		Description

4.09		First Supplemental Indenture, dated as of June 6, 2002, among PRG, Sabine, Neches, PACC, PAFC, Deutsche Bank Trust Company Americas, as Collateral Trustee, and HSBC Bank USA, as Capital Markets Trustee, including the Form of 12½% Senior Secured Notes due 2009 (Incorporated by reference to Exhibit 4.1 filed with PRG’s Current Report on Form 8-K dated June 6, 2002 (File No. 1-11392)).

4.10		Amended and Restated Common Security Agreement, dated as of June 6, 2002, among Sabine, PRG, PAFC, PACC, Neches, Deutsche Bank Trust Company Americas, as Collateral Trustee and Depositary Bank, and HSBC Bank USA, as Capital Markets Trustee (Incorporated by reference to Exhibit 4.2 filed with PRG’s Current Report on Form 8-K dated June 6, 2002 (File No. 1-11392)).

4.11		Amended and Restated Transfer Restrictions Agreement, dated as of June 6, 2002, among Premcor Inc., Sabine, Neches, PACC, PAFC, Deutsche Bank Trust Company Americas, as Collateral Trustee, and HSBC Bank USA, as Capital Markets Trustee (Incorporated by reference to Exhibit 4.4 filed with PRG’s Current Report on Form 8-K dated June 6, 2002 (File No. 1-11392)).

4.12		Registration Rights Agreement, dated as of April 16, 2002, between Blackstone Capital Partners III Merchant Banking Fund L.P., Blackstone Offshore Capital Partners III L.P., Blackstone Family Investment Partnership III, and Premcor Inc. (Incorporated by reference to Exhibit 4.21 filed with Premcor Inc.’s Registration Statement on Form S-1/A (Registration No. 333-70314)).

4.13		Indenture dated as of February 11, 2003, between PRG and Deutsche Bank Trust Company Americas, as Trustee, including the Form of 9¼% Senior Notes due 2010 and 9½% Senior Notes due 2013 (Incorporated by reference to Exhibit 4.13 filed with PRG’s Annual Report on Form 10-K, for the year ended December 31, 2000 (File No. 1-11392)).

10.1*		Crude Oil Supply Agreement, dated March 3, 2003, between Morgan Stanley Capital Group Inc. and PRG (filed herewith).

10.2		Form of Letter Agreement, dated as of January 22, 2003, amending Employment Agreements of James R. Voss and Michael D. Gayda and Amended and Restated Employment Agreements of William E. Hantke, Henry M. Kuchta and Joseph D. Watson (filed herewith).

15		Awareness letter dated April 28, 2003, from Deloitte & Touche LLP concerning the unaudited interim financial information for March 31, 2003 and 2002 (filed herewith).

99.1		Section 906 Chief Executive Officer certificate for Premcor Inc. (filed herewith)

99.2		Section 906 Chief Financial Officer certificate for Premcor Inc. (filed herewith)

99.3		Section 906 Chief Executive Officer certificate for PRG (filed herewith)

99.4		Section 906 Chief Financial Officer certificate for PRG (filed herewith)

Confidential treatment requested as to certain portions, which portions are omitted and filed separately with the Securities and Exchange Commission.

(b) Reports on Form 8-K

We filed the following reports on Form 8-K during the period covered by this report:

(1)

Premcor Inc. filed a report dated January 21, 2003 pursuant to Item 5 (announcing the operating results of the fourth quarter and twelve months of 2002) and

(2)

Premcor Inc. and The Premcor Refining Group Inc. filed a report dated January 28, 2003 pursuant to Item 5 (announcing, among other things, that The Premcor Refining Group Inc. completed a private offering of $525 million of senior notes and that Premcor Inc. completed common stock offerings).

(3)

SIGNATURE

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 thereunto duly authorized.

PREMCOR INC. THE PREMCOR REFINING GROUP INC. (Co-Registrants)

By:		/s/ DENNIS R. EICHHOLZ

		Dennis R. Eichholz
		Senior Vice President—Finance and Controller (principal accounting officer)

May 1, 2003

CERTIFICATION

I, Thomas D. O’Malley, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Premcor Inc.;

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

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

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

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

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

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

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

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

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

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


Date:	May 1, 2003	/s/ THOMAS D. O’MALLEY
		Chief Executive Officer

CERTIFICATION

I, William E. Hantke, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Premcor Inc.;

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

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

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


Date:	May 1, 2003	/s/ WILLIAM E. HANTKE
		Chief Financial Officer

CERTIFICATION

I, Thomas D. O’Malley, certify that:

1. I have reviewed this quarterly report on Form 10-Q of The Premcor Refining Group Inc.;

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

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

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


Date:	May 1, 2003	/s/ THOMAS D. O’MALLEY
		Chief Executive Officer

CERTIFICATION

I, William E. Hantke, certify that:

1. I have reviewed this quarterly report on Form 10-Q of The Premcor Refining Group Inc.;

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

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

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


Date:	May 1, 2003	/s/ WILLIAM E. HANTKE
		Chief Financial Officer