Edgar Filing: PREMCOR INC

Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 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 400

Old Greenwich, Connecticut 06870

(203) 698-7500

Delaware

43-1851087

1-11392

The Premcor Refining Group Inc.

1700 East Putnam Avenue, Suite 400

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).

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

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

Premcor Inc.

74,086,860 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

June 30, 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 June 30, 2003 and December 31, 2002	3

	Condensed Consolidated Statements of Operations for the Three Months and Six Months Ended June 30, 2003 and 2002	4

	Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2003 and 2002	5

	The Premcor Refining Group Inc.:

	Independent Accountants’ Report	6

	Condensed Consolidated Balance Sheets as of June 30, 2003 and December 31, 2002	7

	Condensed Consolidated Statements of Operations for the Three Months and Six Months Ended June 30, 2003 and 2002	8

	Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2003 and 2002	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	27

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	46

Item 4.	Controls and Procedures	47

	PART II. OTHER INFORMATION

Item 1.	Legal Proceedings	48

Item 4.	Submission of Matters to a Vote of Security Holders	48

Item 6.	Exhibits and Reports on Form 8-K	49

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 certain pipeline operations, general and administrative costs, interest income and interest expense at stand-alone Premcor Inc. and/or its other subsidiaries. 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 June 30, 2003, the related condensed consolidated statements of operations for the three-month and six-month periods ended June 30, 2003 and 2002, and the related condensed consolidated statements of cash flows for the six-month periods then ended. 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

July 23, 2003

PREMCOR INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(in millions, except share data)

	June 30, 2003			December 31, 2002
	(unaudited)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	446.0		$	167.4
Short-term investments		5.9			4.9
Cash and cash equivalents restricted for debt service		66.9			61.7
Accounts receivable, net of allowance of $3.5 and $3.2		437.1			269.1
Inventories		582.5			287.3
Prepaid expenses		57.0			45.9
Assets held for sale		40.2			49.3

Total current assets		1,635.6			885.6

PROPERTY, PLANT AND EQUIPMENT, NET		1,610.1			1,262.6
DEFERRED INCOME TAXES		23.8			57.5
OTHER ASSETS		121.6			117.3

	$	3,391.1		$	2,323.0

LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable	$	549.6		$	466.2
Accrued expenses and other		96.4			57.2
Accrued taxes other than income		46.4			26.3
Current portion of long-term debt		21.2			15.0

Total current liabilities		713.6			564.7

LONG-TERM DEBT		1,439.9			909.9
OTHER LONG-TERM LIABILITIES		148.6			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		1,177.4			862.3
Accumulated deficit		(89.1	)		(158.9	)

Total common stockholders’ equity		1,089.0			704.0

	$	3,391.1		$	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 June 30,						For the Six Months Ended June 30,
	2003			2002			2003			2002
NET SALES AND OPERATING REVENUES	$	2,619.9		$	1,679.0		$	4,996.2		$	2,907.3
EXPENSES:
Cost of sales		2,354.6			1,523.4			4,463.5			2,585.0
Operating expense		134.4			114.1			251.6			228.6
General and administrative expenses		15.7			14.4			27.4			28.9
Stock-based compensation		4.4			3.8			8.7			5.7
Depreciation		16.0			11.8			30.6			24.2
Amortization		9.1			10.1			18.6			19.9
Refinery restructuring and other charges		0.7			16.6			15.7			158.6

		2,534.9			1,694.2			4,816.1			3,050.9

OPERATING INCOME (LOSS)		85.0			(15.2	)		180.1			(143.6	)
Interest and finance expense		(30.4	)		(32.9	)		(57.3	)		(67.4	)
Loss on extinguishment of long-term debt		(3.4	)		(19.3	)		(10.4	)		(19.3	)
Interest income		1.3			2.9			2.9			6.4

INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES AND MINORITY INTEREST		52.5			(64.5	)		115.3			(223.9	)
Income tax (provision) benefit		(18.0	)		23.5			(39.0	)		84.9
Minority interest		—			0.9			—			1.7

INCOME (LOSS) FROM CONTINUING OPERATIONS		34.5			(40.1	)		76.3			(137.3	)
Loss from discontinued operations, net of income tax benefit of $1.3 and $4.0		(2.2	)		—			(6.5	)		—

NET INCOME (LOSS)		32.3			(40.1	)		69.8			(137.3	)
Preferred stock dividends		—			—			—			(2.5	)

NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS	$	32.3		$	(40.1	)	$	69.8		$	(139.8	)

Basic net income (loss) per common share:
Income (loss) from continuing operations	$	0.47		$	(0.82	)	$	1.07		$	(3.47	)
Discontinued operations		(0.03	)		—			(0.09	)		—

Net income (loss)	$	0.44		$	(0.82	)	$	0.98		$	(3.47	)

Weighted average common shares outstanding		74.1			48.7			71.5			40.3
Diluted net income (loss) per common share:
Income (loss) from continuing operations	$	0.46		$	(0.82	)	$	1.06		$	(3.47	)
Discontinued operations		(0.03	)		—			(0.09	)		—

Net income (loss)	$	0.43		$	(0.82	)	$	0.97		$	(3.47	)

Weighted average common shares outstanding		74.8			48.7			72.2			40.3

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 Six Months Ended June 30,
	2003			2002
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	69.8		$	(137.3	)
Adjustments:
Loss on discontinued operations		10.5			—
Depreciation		30.6			24.2
Amortization		23.3			24.9
Deferred income taxes		33.7			(85.3	)
Stock-based compensation		8.7			5.7
Minority interest		—			(1.7	)
Refinery restructuring and other charges		13.6			103.6
Write-off of deferred financing costs		5.4			9.5
Other, net		6.7			11.8
Cash provided by (reinvested in) working capital –
Accounts receivable, prepaid expenses and other		(170.1	)		(116.6	)
Inventories		(129.9	)		(11.5	)
Accounts payable, accrued expenses, taxes other than income, and other		123.8			113.0
Cash and cash equivalents restricted for debt service		(0.3	)		8.3

Net cash provided by (used in) operating activities of continuing operations		25.8			(51.4	)
Net cash used in operating activities of discontinued operations		(3.1	)		(3.4	)

Net cash provided by (used in) operating activities		22.7			(54.8	)

CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for property, plant and equipment		(60.7	)		(38.5	)
Expenditures for turnaround		(9.5	)		(31.7	)
Expenditures for refinery acquisition		(474.8	)		—
Purchase of short-term investments		(1.0	)		—
Cash and cash equivalents restricted for investment in capital additions		0.2			4.3
Other		—			0.2

Net cash used in investing activities		(545.8	)		(65.7	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from the issuance of common stock, net		306.5			482.0
Proceeds from the issuance of long-term debt		825.0			—
Long-term debt and capital lease payments		(299.6	)		(637.1	)
Cash and cash equivalents restricted for debt repayment		(4.9	)		(42.9	)
Deferred financing costs		(25.3	)		(11.1	)

Net cash provided by (used in) financing activities		801.7			(209.1	)

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		278.6			(329.6	)
CASH AND CASH EQUIVALENTS, beginning of period		167.4			510.1

CASH AND CASH EQUIVALENTS, end of period	$	446.0		$	180.5

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 June 30, 2003, the related condensed consolidated statements of operations for the three-month and six-month periods ended June 30, 2003 and 2002, and the related condensed consolidated statements of cash flows for the six-month periods then ended. 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

July 23, 2003

THE PREMCOR REFINING GROUP INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(in millions, except share data)

	June 30, 2003		December 31, 2002
	June 30, 2003		December 31, 2002
	(unaudited)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	398.0	$	119.7
Short-term investments		1.7		1.7
Cash and cash equivalents restricted for debt service		66.9		61.7
Accounts receivable, net of allowance of $3.5 and $3.2		436.9		269.0
Receivables from affiliates		30.3		13.1
Inventories		582.5		287.3
Prepaid expenses and other		56.7		45.7
Assets held for sale		40.2		49.3

Total current assets		1,613.2		847.5

PROPERTY, PLANT AND EQUIPMENT, NET		1,584.0		1,261.7
DEFERRED INCOME TAXES		—		19.8
OTHER ASSETS		121.6		117.3

	$	3,318.8	$	2,246.3

LIABILITIES AND STOCKHOLDER’S EQUITY
CURRENT LIABILITIES:
Accounts payable	$	549.3	$	466.2
Payables to affiliates		46.4		41.0
Accrued expenses and other		97.3		55.7
Accrued taxes other than income		46.4		26.4
Current portion of long-term debt		20.9		15.0

Total current liabilities		760.3		604.3

LONG-TERM DEBT		1,429.7		869.8
DEFERRED INCOME TAXES		9.2		—
OTHER LONG-TERM LIABILITIES		148.6		144.4
COMMITMENTS AND CONTINGENCIES		—		—

COMMON STOCKHOLDER’S EQUITY:
Common, $0.01 par value per share, 100 issued and outstanding		—		—
Paid-in capital		813.7		541.4
Retained earnings		157.3		86.4

Total common stockholder’s equity		971.0		627.8

	$	3,318.8	$	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 June 30,						For the Six Months Ended June 30,
	2003			2002			2003			2002
NET SALES AND OPERATING REVENUES	$	2,619.3		$	1,679.0		$	4,995.1		$	2,907.3

EXPENSES:
Cost of sales		2,356.7			1,526.3			4,466.3			2,588.3
Operating expenses		133.2			113.9			249.9			228.3
General and administrative expenses		15.6			14.4			27.3			28.8
Stock-based compensation		4.4			3.8			8.7			5.7
Depreciation		15.7			11.8			30.2			24.2
Amortization		9.1			10.1			18.6			19.9
Refinery restructuring and other charges		0.7			16.6			15.7			158.6

		2,535.4			1,696.9			4,816.7			3,053.8

OPERATING INCOME (LOSS)		83.9			(17.9	)		178.4			(146.5	)
Interest and finance expense		(29.9	)		(27.5	)		(56.1	)		(58.0	)
Loss on extinguishment of long-term debt		(3.4	)		(9.3	)		(8.1	)		(9.3	)
Interest income		1.5			2.2			2.6			4.4

INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES AND MINORITY INTEREST		52.1			(52.5	)		116.8			(209.4	)
Income tax (provision) benefit		(17.8	)		19.4			(39.4	)		80.0
Minority interest		—			0.9			—			1.7

INCOME (LOSS) FROM CONTINUING OPERATIONS		34.3			(32.2	)		77.4			(127.7	)
Loss from discontinued operations, net of income tax benefit of $1.3 and $4.0		(2.2	)		—			(6.5	)		—

NET INCOME (LOSS)	$	32.1		$	(32.2	)	$	70.9		$	(127.7	)

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 Six Months Ended June 30,
	2003			2002
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	70.9		$	(127.7	)
Adjustments:
Loss on discontinued operations		10.5			—
Depreciation		30.2			24.2
Amortization		23.3			24.8
Deferred income taxes		29.0			(80.5	)
Stock-based compensation		8.7			5.7
Minority interest		—			(1.7	)
Refinery restructuring and other charges		13.6			103.6
Write-off of deferred financing costs		5.4			7.9
Other, net		6.9			11.5
Cash provided by (reinvested in) working capital –
Accounts receivable, prepaid expenses and other		(169.9	)		(125.9	)
Inventories		(129.9	)		(11.5	)
Accounts payable, accrued expenses, taxes other than income, and other		125.9			109.6
Affiliate receivables and payables		3.2			14.8
Cash and cash equivalents restricted for debt service		(0.3	)		8.3

Net cash provided by (used in) operating activities of continuing operations		27.5			(36.9	)
Net cash used in operating activities of discontinued operations		(3.1	)		(3.4	)

Net cash provided by (used in) operating activities		24.4			(40.3	)

CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for property, plant and equipment		(60.7	)		(38.5	)
Expenditures for turnaround		(9.5	)		(31.7	)
Expenditures for refinery acquisition		(474.8	)		—
Cash and cash equivalents restricted for investment in capital additions		0.2			4.3
Other		—			0.2

Net cash used in investing activities		(544.8	)		(65.7	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt		825.0			—
Long-term debt and capital lease payments		(259.4	)		(438.6	)
Capital contributions, net		263.3			234.6
Cash and cash equivalents restricted for debt repayment		(4.9	)		(42.9	)
Deferred financing costs		(25.3	)		(11.1	)

Net cash provided by (used in) financing activities		798.7			(258.0	)

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		278.3			(364.0	)
CASH AND CASH EQUIVALENTS, beginning of period		119.7			482.5

CASH AND CASH EQUIVALENTS, end of period	$	398.0		$	118.5

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)

June 30, 2003

(Tabular amounts in millions, except per share data)

1. Nature of Business and Basis of Preparation

Premcor Inc., together with 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. The Company owns and operates 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. The Premcor Refining Group Inc., together with its subsidiaries, (“PRG”) is an indirect, wholly owned subsidiary of Premcor Inc. and together with its indirect subsidiary, Port Arthur Coker Company LP (“PACC”) is the principal operating subsidiary of Premcor Inc. PACC owns and operates a heavy oil processing facility, which is operated in conjunction with PRG’s Port Arthur refinery.

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-month and six-month periods ended June 30, 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, 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.

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 future meetings. 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.

In April 2003, the FASB issued SFAS No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities. SFAS No. 149 amends and clarifies financial accounting and reporting for derivative instruments, including certain derivative instruments embedded in other contracts. More specifically, SFAS No. 149, among other things, clarifies under what circumstances a contract with an initial net investment meets the characteristics of a derivative, clarifies when a derivative contains a financing component, and amends the definition of an “underlying” to conform to recently issued standards. SFAS No. 149 is effective for contracts entered into or modified after June 30, 2003, except for certain aspects of the standard that relate to previously issued guidance, which should continue to be applied in accordance with the previously set effective dates. Also, this standard is effective for existing and new contracts entered into after June 30, 2003 as they relate to forward purchases or sales of when-issued securities or other securities that do not yet exist. The Company does not expect the adoption of this standard will have a material impact on its financial statements.

In May 2003, the FASB issued SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity. SFAS No. 150 establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. SFAS No. 150 requires classification of a financial instrument that is within its scope as a liability, or an asset in some circumstances. SFAS No. 150 is effective for financial instruments entered into or modified after May 31, 2003, and shall otherwise be effective at the beginning of the first interim period beginning after June 15, 2003, except for mandatorily redeemable financial instruments of a nonpublic entity. For instruments created before the issuance of SFAS No. 150 and still existing at the beginning of the interim period of adoption, this standard shall be implemented by reporting the cumulative effect of a change in an accounting principle. The adoption of this standard did not have a material impact on the Company’s financial statements.

3. Memphis Refinery Acquisition

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,

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 year-to-date results from the date of acquisition. The preliminary purchase price allocation, which is subject to change pending completion of independent appraisals and 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 April 1, 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. The actual daily value of the Gulf Coast 2/1/1 crack spread, as defined by the agreement, averaged $2.88 per barrel for the three- month period from April 1, 2003 through June 30, 2003. 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.

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. See Note 8, Long-term Debt and Note 9, Stockholders’ Equity for more details of these transactions. Concurrently, PRG amended and restated its credit agreement to permit the acquisition as described in Note 7, Credit Agreement.

4. Refinery Restructuring and Other Charges

In 2003, the Company recorded refinery restructuring and other charges of $15.7 million, of which $0.7 million was recorded in the second quarter. The second quarter charge related to the Company’s plans to close the St. Louis administrative office. The year-to-date charge also included a $1.6 million reversal in restructuring charge related to the administrative restructuring which began in 2002 and a $16.6 million charge related to a proposed sale of certain Hartford refinery assets. These activities and transactions are described more fully below.

In 2002, the Company recorded refinery restructuring and other charges of $158.6 million, of which $16.6 million was recorded in the second quarter. The second quarter charge consisted of $6.2 million related to the then anticipated Hartford refinery shutdown, $6.5 million related to the 2002 restructuring of management and administrative functions, $2.5 million related to the termination of certain guarantees at PACC, and $1.4 million related to the write-down of idled assets held for sale. The year-to-date charge consisted of $137.4 million related to

the anticipated Hartford refinery shutdown, $22.3 million related to the 2002 restructuring of management and administrative functions, $2.5 million related to the termination of certain guarantees at PACC, and $1.4 million related to the write-down of idled assets held for sale, partially offset by income of $5.0 million related to the unanticipated sale of a portion of previously written-off Blue Island refinery assets.

Hartford Refinery Closure and Proposed Sale. 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 fair value of $49.0 million in anticipation of a sale or lease of the refining assets. The Company continues 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 at the Hartford refinery for $40 million. The $16.6 million charge in 2003 related to the sale 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.

As of December 31, 2002, the Company had a $1.0 million reserve for employee severance and plant closure/equipment remediation related to the shutdown of the refining operations at the Hartford refinery. The final cash outlays related to the Hartford refinery shutdown were completed in the first quarter of 2003.

Administrative Restructuring. As of December 31, 2002, the Company had a $4.9 million reserve for plans announced in the third quarter of 2002 to reduce 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 had been reduced by 25 and the Company recorded a reduction in the restructuring reserve of $1.6 million in the first quarter of 2003. In May 2003, the Company announced that it would be closing the St. Louis office and moving the administrative functions to the Connecticut office over the next six to twelve months. The office move is expected to cost approximately $12.8 million, which includes $6.9 million of severance related benefits and $5.9 million of other costs such as training, relocation, and the movement of physical assets. The severance related costs will be amortized over the future service period of the affected employees and the other costs will be expensed as incurred.

The following table summarizes the expected costs associated with the administrative restructuring and provides a reconciliation of the administrative restructuring reserve as of June 30, 2003:

	Severance			Other Costs		Total Costs
Summary of Expected Costs:
Expected total cost	$	6.9		$	5.9	$	12.8
Costs incurred this quarter		0.7			—		0.7
Cumulative costs incurred to date		0.7			—		0.7

Reserve Activity:
Beginning balance, December 31, 2002	$	4.9		$	—	$	4.9
Costs incurred		0.7			—		0.7
Adjustments		(1.6	)		—		(1.6	)
Net cash outlays		(2.2	)		—		(2.2	)

Ending balance, June 30, 2003	$	1.8		$	—	$	1.8

5. Inventories

The carrying value of inventories consisted of the following:

	June 30, 2003		December 31, 2002
Crude oil	$	226.2	$	63.8
Refined products and blendstocks		330.2		204.5
Warehouse stock and other		26.1		19.0

	$	582.5	$	287.3

The market value of crude oil, refined products and blendstock inventories at June 30, 2003 was approximately $126 million (December 31, 2002—$188 million) above carrying value.

6. Other Assets

Other assets consisted of the following:

	June 30, 2003		December 31, 2002
Deferred turnaround costs	$	77.2	$	86.3
Deferred financing costs		39.5		24.2
Cash restricted for investment in capital additions		—		2.6
Other		4.9		4.2

	$	121.6	$	117.3

Amortization of deferred financing costs for the three-month and six-month periods ended June 30, 2003 was $2.3 million (2002—$2.5 million) and $4.6 million (2002 — $5.0 million), respectively, for the Company and was included in “Interest and finance expense”. Amortization of deferred financing costs for the three-month and six-month periods ended June 30, 2003 was $2.3 million (2002 — $2.4 million) and $4.6 million (2002 — $4.9 million), respectively, for PRG. In 2003, the Company incurred deferred financing costs of $25.3 million related to the amendment of its credit agreement and the issuance of $825 million in senior notes under two separate offerings. In 2003, the Company wrote-off $5.4 million of unamortized deferred financing costs related to the purchase of a portion of its 12¹/2% Senior Notes due January 15, 2009, early repayment of the Floating Rate Term Loan due November 15, 2003 and 2004, 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 June 30, 2003, the borrowing base was $1,130.9 million (December 31, 2002 — $815.3 million), with $463.7 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 June 30, 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

Long-term debt consisted of the following:

	June 30, 2003		December 31, 2002
	June 30, 2003		December 31, 2002
12½% Senior Notes due January 15, 2009
(“12 ½% Senior Notes”) (1)	$	231.6	$	250.7
8³/8% Senior Notes due November 15, 2007 (“8³/8% Senior Notes”) (2)		99.7		99.7
8⁵/8% Senior Notes due August 15, 2008 (“8⁵/8% Senior Notes”) (2)		109.9		109.8
9¼% Senior Notes due February 1, 2010
(“9¼% Senior Notes”) (2)		175.0		—
9½% Senior Notes due February 1, 2013
(“9½% Senior Notes”) (2)		350.0		—
7½% Senior Notes due June 15, 2015
(“7½% Senior Notes”) (2)		300.0		—
8⁷/8% Senior Subordinated Notes due November 15, 2007 (“8⁷/8% Senior Subordinated Notes”) (2)		174.4		174.4
Floating Rate Term Loan due November 15, 2003 and 2004 (“Floating Rate Loan”) (2)		—		240.0
11½% Subordinated Debentures due October 1, 2009 (“11½% Subordinated Debentures”) (3)		—		40.1
Ohio Water Development Authority Environmental Facilities Revenue Bonds due December 1, 2031 (2)		10.0		10.0
Obligation under capital leases (4)		10.5		0.2

		1,461.1		924.9
Less current portion		21.2		15.0

Total long-term debt at Premcor Inc.	$	1,439.9	$	909.9

(1)

Issued or borrowed by Port Arthur Finance Corp., a subsidiary of PACC

(2)

Issued or borrowed by stand-alone PRG

(3)

Issued or borrowed by Premcor USA Inc., a subsidiary of Premcor Inc.

(4)

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

In February 2003, PRG completed an offering of 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. In June 2003, PRG completed a private placement offering of $300 million of 7½% Senior Notes due in 2015.

In February 2003, the Company redeemed the $40.1 million principal balance of Premcor USA Inc.’s 11½% Subordinated Debentures at a $2.3 million premium and repaid PRG’s Floating Rate Term Loan at par with a portion of the proceeds from the common stock offerings described in Note 9, Stockholders Equity and the senior notes issued in February 2003. In May 2003, PRG purchased $14.7 million in face value of the 12½% Senior Notes at a $2.7 million premium.

PRG’s long-term debt, including current maturities, as of June 30, 2003 was $1,450.6 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.

Loss on Extinguishment of Long-term Debt

For the three-month and six-month periods ended June 30, 2003, the Company recorded a loss on extinguishment of long-term debt of $3.4 million and $10.4 million (PRG — $3.4 million and $8.1 million), respectively, related to the early redemption and purchase of long-term debt described above and credit agreement amendment. In the three months ended June 30, 2003, the loss included cash premiums of $2.7 million and a write-off of unamortized deferred financing costs of $0.7 million. In the six months ended June 30, 2003, the loss included a cash premium of $5.0 million (PRG — $2.7 million) and a write-off of unamortized deferred financing costs of $5.4 million.

For the three-month and six-month periods ended June 30, 2002, the Company recorded a loss on extinguishment of long-term debt of $19.3 million (PRG — $9.3 million) primarily related to the early redemption and repurchase of portions of its long-term debt. The loss included cash premiums of $9.2 million (PRG — $0.9 million), a write-off of unamortized deferred financing costs of $9.5 million (PRG — $7.8 million), and the write-off of a prepaid debt guarantee fee of $0.6 million.

9. Stockholders’ Equity

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, a subsidiary of Occidental Petroleum Corporation, 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.

10. Stock-based Compensation Expense

As of June 30, 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 June 30,						For the Six Months Ended June 30,
	2003			2002			2003			2002
Net income (loss), as reported	$	32.3		$	(40.1	)	$	69.8		$	(139.8	)
Add: Stock-based compensation expense included in reported net income, net of tax effect		2.9			2.4			5.7			7.2
Deduct: Stock-based compensation expense determined under fair value based method for all options, net of tax effect		(2.9	)		(2.6	)		(5.7	)		(7.5	)

Pro forma net income (loss)	$	32.3		$	(40.3	)	$	69.8		$	(140.1	)

Earnings per share:
Basic-as reported	$	0.44		$	(0.82	)	$	0.98		$	(3.47	)
Basic-pro forma	$	0.44		$	(0.83	)	$	0.98		$	(3.48	)
Diluted-as reported	$	0.43		$	(0.82	)	$	0.97		$	(3.47	)
Diluted-pro forma	$	0.43		$	(0.83	)	$	0.97		$	(3.48	)

11. Interest and Finance Expense

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

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2003			2002			2003			2002
Interest expense	$	31.4		$	30.7		$	58.2		$	62.8
Financing costs		2.3			3.5			4.7			7.7
Capitalized interest		(3.3	)		(1.3	)		(5.6	)		(3.1	)

	$	30.4		$	32.9		$	57.3		$	67.4

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

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2003			2002			2003			2002
Interest expense	$	30.9		$	25.3		$	57.0		$	53.5
Financing costs		2.3			3.5			4.7			7.6
Capitalized interest		(3.3	)		(1.3	)		(5.6	)		(3.1	)

	$	29.9		$	27.5		$	56.1		$	58.0

Cash paid for interest for the three-month and six-month periods ended June 30, 2003 was $13.1 million (2002—$33.3 million) and $38.2 million (2002—$71.2 million), respectively, for the Company. Cash paid for interest for the three-month and six-month periods ended June 30, 2003 was $12.7 million (2002—$25.2 million) and $35.8 million (2002—$63.0 million), respectively, for PRG.

12. Income Taxes

The Company made net cash income tax payments of $2.3 million in both the three-month and six-month periods ended June 30, 2003. The Company received net cash income tax refunds during the three-month and six-month periods ended June 30, 2002 of $0.7 million and $12.4 million, respectively. PRG made net cash income tax payments of $0.2 million in both the three-month and six-month periods ended June 30, 2003. PRG received net cash income tax refunds during the three-month and six-month periods ended June 30, 2002 of $0.7 million and $12.4 million, respectively.

13. 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 obligations at these sites. In October 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. In bankruptcy hearings throughout the first and second quarter of 2003, CRE rejected approximately 30 of these leases. The Company recorded an after-tax charge of $2.2 million and $6.5 million for the three-month and six-month periods ended June 30, 2003, respectively, representing the estimated net present value of its remaining liability under these rejected leases, net of estimated sub-lease income, and other direct costs. The future lease payments on the remaining properties is currently estimated as follows: (in million) 2003—$9.8, 2004—$10.1, 2005—$10.5, 2006—$10.9, 2007—$11.3, and in the aggregate thereafter—$84.2. In May 2003, CRE announced that it would conduct an orderly sale of its retail assets, including the lease sites that have not been rejected. In efforts to mitigate

any losses the Company might incur as a result of the CRE bankruptcy, the Company is participating in the marketing of CRE’s subleases and discussing alternatives with representatives of CRE’s interests and with certain landlords. It is possible that the Company may incur additional liability for CRE lease obligations or other costs as CRE finalizes the disposition of the properties; however, the amounts are not estimable at this time and could be material. Should any additional leases revert to the Company, it will attempt to reduce the potential liability by subletting or reassigning the leases. The following table reconciles the activity and balance of the reserve for the lease obligations as well as the Company’s environmental liability for previously owned retail sites:

	Lease Obligations			Environmental Obligations of Previously Owned Sites			Total Discontinued Operations
Beginning balance, December 31, 2002	$	—		$	23.0		$	23.0
Net present value of lease obligations		8.6			—			8.6
Accretion and other expenses		2.0			—			2.0
Net cash outlays		(2.5	)		(0.6	)		(3.1	)

Ending balance, June 30, 2003	$	8.1		$	22.4		$	30.5

14. Earnings per Share

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

	For the Three Months Ended June 30,		For the Six Months Ended June 30,
	2003	2002	2003	2002

Weighted average common shares outstanding	74.1	48.7	71.5	40.3
Dilutive effect of stock options	0.7	—	0.7	—

Weighted average common shares outstanding, assuming dilution	74.8	48.7	72.2	40.3

Stock options for 4.4 million common shares for both the three-month and six-month periods ended June 30, 2003, were excluded from the diluted earnings per share calculation because they were anti-dilutive. Stock options and warrants representing common stock equivalents of 6.2 million and 6.6 million shares were excluded from diluted shares outstanding for the three-month and six-month periods ended June 30, 2002 due to their anti-dilutive effect as a result of the Company’s net loss.

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

Presented below are the PRG condensed 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, PRG’s wholly owned subsidiary, Sabine River Holding Corp. (“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 condensed 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

CONDENSED CONSOLIDATING BALANCE SHEET

As of June 30, 2003

(unaudited, in millions)

	PRG		PAFC		Other Guarantor Subsidiaries		Eliminations			Consolidated PRG
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	398.0	$	—	$	—	$	—		$	398.0
Short-term investments		1.7		—		—		—			1.7
Cash and cash equivalents restricted for debt service		—		—		66.9		—			66.9
Accounts receivable		437.4		—		0.3		(0.8	)		436.9
Receivable from affiliates		90.6		35.1		40.0		(135.4	)		30.3
Inventories		538.5		—		44.0		—			582.5
Prepaid expenses and other		51.3		—		5.4		—			56.7
Assets held for sale		40.2		—		—		—			40.2

Total current assets		1,557.7		35.1		156.6		(136.2	)		1,613.2
PROPERTY, PLANT AND EQUIPMENT, NET		980.6		—		603.4		—			1,584.0
DEFERRED INCOME TAXES		48.5		—		—		(48.5	)		—
INVESTMENT IN AFFILIATE		276.4		—		—		(276.4	)		—
OTHER ASSETS		105.6		—		16.0		—			121.6
NOTE RECEIVABLE FROM AFFILIATE		—		225.4		—		(225.4	)		—

	$	2,968.8	$	260.5	$	776.0	$	(686.5	)	$	3,318.8

LIABILITIES AND STOCKHOLDER’S EQUITY
CURRENT LIABILITIES:
Accounts payable	$	426.3	$	—	$	123.0	$	—		$	549.3
Payable to affiliates		77.8		—		80.6		(112.0	)		46.4
Accrued expenses and other		83.2		14.2		0.7		(0.8	)		97.3
Accrued taxes other than income		43.4		—		3.0		—			46.4
Current portion of long-term debt		—		20.9		—		—			20.9
Current portion of notes payable to affiliate		—		—		23.4		(23.4	)		—

Total current liabilities		630.7		35.1		230.7		(136.2	)		760.3
LONG-TERM DEBT		1,219.0		225.4				(14.7	)		1,429.7
DEFERRED INCOME TAXES		—		—		57.7		(48.5	)		9.2
OTHER LONG-TERM LIABILITIES		148.1		—		0.5		—			148.6
NOTE PAYABLE TO AFFILIATE		—		—		225.4		(225.4	)		—
COMMON STOCKHOLDER’S EQUITY:
Common stock		—		—		0.1		(0.1	)		—
Paid-in capital		813.7		—		206.0		(206.0	)		813.7
Retained earnings		157.3		—		55.6		(55.6	)		157.3

Total common stockholder’s equity		971.0		—		261.7		(261.7	)		971.0

	$	2,968.8	$	260.5	$	776.0	$	(686.5	)	$	3,318.8

THE PREMCOR REFINING GROUP INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

For the Three Months Ended June 30, 2003

(unaudited, in millions)

	PRG			PAFC			Other Guarantor Subsidiaries			Eliminations			Consolidated PRG
NET SALES AND OPERATING REVENUES	$	2,730.1		$	—		$	580.0		$	(690.8	)	$	2,619.3
EQUITY IN EARNINGS OF AFFILIATE		43.2			—			—			(43.2	)		—
EXPENSES:
Cost of sales		2,582.1			—			456.8			(682.2	)		2,356.7
Operating expenses		100.5			—			41.3			(8.6	)		133.2
General and administrative expenses		14.7			—			0.9			—			15.6
Stock-based compensation		4.4			—			—			—			4.4
Depreciation		10.2			—			5.5			—			15.7
Amortization		9.1			—			—			—			9.1
Refinery restructuring and other charges		0.7			—			—			—			0.7

		2,721.7			—			504.5			(690.8	)		2,535.4
OPERATING INCOME		51.6			—			75.5			(43.2	)		83.9
Interest and finance expense		(21.6	)		(7.7	)		(8.6	)		8.0			(29.9	)
Loss on extinguishment of long-term debt		(2.7	)		—			(0.7	)		—			(3.4	)
Interest income		1.5			7.7			0.3			(8.0	)		1.5

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		28.8			—			66.5			(43.2	)		52.1
Income tax (provision) benefit		5.5			—			(23.3	)		—			(17.8	)

INCOME FROM CONTINUING OPERATIONS		34.3			—			43.2			(43.2	)		34.3
Loss from discontinued operations, net of income tax benefit of $1.3		(2.2	)		—			—			—			(2.2	)

NET INCOME	$	32.1		$	—		$	43.2		$	(43.2	)	$	32.1

THE PREMCOR REFINING GROUP INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

For the Six Months Ended June 30, 2003

(unaudited, in millions)

	PRG			PAFC			Other Guarantor Subsidiaries			Eliminations			Consolidated PRG
NET SALES AND OPERATING REVENUES	$	5,243.9		$	—		$	1,284.3		$	(1,533.1	)	$	4,995.1
EQUITY IN EARNINGS OF AFFILIATE		105.5			—			—			(105.5	)		—
EXPENSES:
Cost of sales		4,974.8			—			1,007.7			(1,516.2	)		4,466.3
Operating expenses		182.9			—			83.9			(16.9	)		249.9
General and administrative expenses		25.4			—			1.9			—			27.3
Stock-based compensation		8.7			—			—			—			8.7
Depreciation		19.3			—			10.9			—			30.2
Amortization		18.6			—			—			—			18.6
Refinery restructuring and other charges		15.7			—			—			—			15.7

		5,245.4			—			1,104.4			(1,533.1	)		4,816.7
OPERATING INCOME		104.0			—			179.9			(105.5	)		178.4
Interest and finance expense		(39.1	)		(15.4	)		(17.3	)		15.7			(56.1	)
Loss on extinguishment of long-term debt		(7.4	)		—			(0.7	)		—			(8.1	)
Interest income		2.5			15.4			0.4			(15.7	)		2.6

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		60.0			—			162.3			(105.5	)		116.8
Income tax (provision) benefit		17.4						(56.8	)		—			(39.4	)

INCOME FROM CONTINUING OPERATIONS		77.4			—			105.5			(105.5	)		77.4
Loss from discontinued operations, net of income tax benefit of $4.0		(6.5	)		—			—			—			(6.5	)

NET INCOME	$	70.9		$	—		$	105.5		$	(105.5	)	$	70.9

THE PREMCOR REFINING GROUP INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

For the Six Months Ended June 30, 2003

(unaudited, in millions)

	PRG			PAFC			Other Guarantor Subsidiaries			Eliminations			Consolidated PRG
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	70.9		$	—		$	105.5		$	(105.5	)	$	70.9
Adjustments:
Loss on discontinued operations		10.5			—			—			—			10.5
Depreciation		19.3			—			10.9			—			30.2
Amortization		21.4			—			1.9			—			23.3
Deferred income taxes		18.5			—			10.5			—			29.0
Stock-based compensation		8.7			—			—			—			8.7
Refinery restructuring and other charges		13.6			—			—			—			13.6
Write-off of deferred financing costs		4.7			—			0.7			—			5.4
Equity in earnings of affiliate		(105.5	)		—			—			105.5			—
Other, net		6.5			0.1			0.3			—			6.9
Cash provided by (reinvested in) working capital:
Accounts receivable, prepaid expenses and other		(167.3	)		—			(3.4	)		0.8			(169.9	)
Inventories		(113.5	)		—			(16.4	)		—			(129.9	)
Accounts payable, accrued expenses, taxes other than income, and other		129.2			(0.2	)		(2.3	)		(0.8	)		125.9
Affiliate receivables and payables		(80.2	)		4.5			78.9			—			3.2
Cash and cash equivalents restricted for debt service		—			—			(0.3	)		—			(0.3	)

Net cash provided by (used in) operating activities of continuing operations		(163.2	)		4.4			186.3			—			27.5
Net cash used in operating activities of discontinued operations		(3.1	)		—			—			—			(3.1	)

Net cash provided by (used in) operating activities		(166.3	)		4.4			186.3			—			24.4

CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for property, plant and equipment		(56.8	)		—			(3.9	)		—			(60.7	)
Expenditures for turnaround		(9.1	)		—			(0.4	)		—			(9.5	)
Expenditures for refinery acquisition		(474.8	)		—			—			—			(474.8	)
Purchase of investments		(14.7	)		—			—			14.7			—
Cash and cash equivalents restricted for investment in capital additions		2.6			—			(2.4	)		—			0.2

Net cash used in investing activities		(552.8	)		—			(6.7	)		14.7			(544.8	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt		825.0			—			—			—			825.0
Long-term debt and capital lease payments		(240.3	)		(4.4	)		—			(14.7	)		(259.4	)
Capital contributions		263.3			—			—			—			263.3
Dividends received		174.7			—			(174.7	)		—			—
Cash and cash equivalents restricted for debt repayment		—			—			(4.9	)		—			(4.9	)
Deferred financing costs		(25.3	)		—			—			—			(25.3	)

Net cash provided by (used in) financing activities		997.4			(4.4	)		(179.6	)		(14.7	)		798.7

NET INCREASE IN CASH AND CASH EQUIVALENTS		278.3			—			—			—			278.3
CASH AND CASH EQUIVALENTS, Beginning of period		119.7			—			—			—			119.7

CASH AND CASH EQUIVALENTS, end of period	$	398.0		$	—		$	—		$	—		$	398.0

THE PREMCOR REFINING GROUP INC. AND SUBSIDIARIES

CONDENSED 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

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

For the Three Months Ended June 30, 2002

(unaudited, in millions)

	PRG			PAFC			Other Guarantor Subsidiaries			Eliminations and Minority Interest			Consolidated PRG
NET SALES AND OPERATING REVENUES	$	1,793.4		$	—		$	468.2		$	(582.6	)	$	1,679.0
EQUITY IN EARNINGS OF AFFILIATE		(19.2	)		—			—			19.2			—
EXPENSES:
Cost of sales		1,660.2			—			440.8			(574.7	)		1,526.3
Operating expenses		92.8			—			29.0			(7.9	)		113.9
General and administrative expenses		13.1			—			1.3			—			14.4
Stock-based compensation		3.8			—			—			—			3.8
Depreciation		6.5			—			5.3			—			11.8
Amortization		10.1			—			—			—			10.1
Refinery restructuring and other charges		14.1			—			2.5			—			16.6

		1,800.6			—			478.9			(582.6	)		1,696.9

OPERATING LOSS		(26.4	)		—			(10.7	)		19.2			(17.9	)
Interest and finance expense		(15.0	)		(10.8	)		(12.6	)		10.9			(27.5	)
Loss on extinguishment of long-term debt		(1.0	)		—			(8.3	)		—			(9.3	)
Interest income		1.4			10.8			0.9			(10.9	)		2.2

LOSS BEFORE INCOME TAXES AND MINORITY INTEREST		(41.0	)		—			(30.7	)		19.2			(52.5	)
Income tax benefit		8.8			—			10.6			—			19.4
Minority interest		—			—			—			0.9			0.9

NET LOSS	$	(32.2	)	$	—		$	(20.1	)	$	20.1		$	(32.2	)

THE PREMCOR REFINING GROUP INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

For the Six Months Ended June 30, 2002

(unaudited, in millions)

	PRG			PAFC			Other Guarantor Subsidiaries			Eliminations and Minority Interest			Consolidated PRG
NET SALES AND OPERATING REVENUES	$	3,049.3		$	—		$	888.9		$	(1,030.9	)	$	2,907.3
EQUITY IN EARNINGS OF AFFILIATE		(26.5	)		—			—			26.5			—
EXPENSES:
Cost of sales		2,783.3			—			820.4			(1,015.4	)		2,588.3
Operating expenses		181.1			—			62.7			(15.5	)		228.3
General and administrative expenses		26.4			—			2.4			—			28.8
Stock-based compensation		5.7			—			—			—			5.7
Depreciation		13.7			—			10.5			—			24.2
Amortization		19.9			—			—			—			19.9
Refinery restructuring and other charges		156.1			—			2.5			—			158.6

		3,186.2			—			898.5			(1,030.9	)		3,053.8

OPERATING LOSS		(163.4	)		—			(9.6	)		26.5			(146.5	)
Interest and finance expense		(31.0	)		(22.8	)		(27.2	)		23.0			(58.0	)
Loss on extinguishment of long-term debt		(1.0	)		—			(8.3	)		—			(9.3	)
Interest income		2.8			22.8			1.8			(23.0	)		4.4

LOSS BEFORE INCOME TAXES AND MINORITY INTEREST		(192.6	)		—			(43.3	)		26.5			(209.4	)
Income tax benefit		64.9			—			15.1			—			80.0
Minority interest		—			—			—			1.7			1.7

NET LOSS	$	(127.7	)	$	—		$	(28.2	)	$	28.2		$	(127.7	)

THE PREMCOR REFINING GROUP INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

For the Six Months Ended June 30, 2002

(unaudited, in millions)

	PRG			PAFC			Other Guarantor Subsidiaries			Eliminations And Minority Interest			Consolidated PRG
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(127.7	)	$	—		$	(28.2	)	$	28.2		$	(127.7	)
Adjustments:
Depreciation		13.7			—			10.5			—			24.2
Amortization		23.1			—			1.7			—			24.8
Deferred income taxes		(65.2	)		—			(15.3	)		—			(80.5	)
Stock-based compensation		5.7			—			—			—			5.7
Minority interest		—			—			—			(1.7	)		(1.7	)
Refinery restructuring and other charges		103.6			—			—			—			103.6
Write-off of deferred financing costs		1.1			—			6.8			—			7.9
Equity in earnings of affiliate		26.5			—			—			(26.5	)		—
Other, net		11.1			—			0.4			—			11.5
Cash provided by (reinvested in) working capital:
Accounts receivable, prepaid expenses and other		(133.8	)		—			7.9			—			(125.9	)
Inventories		(15.7	)		—			4.2			—			(11.5	)
Accounts payable, accrued expenses, taxes other than income, and other		101.5			(4.7	)		12.8			—			109.6
Affiliate receivables and payables		(20.2	)		292.3			(257.3	)		—			14.8
Cash and cash equivalents restricted for debt service		—			—			8.3			—			8.3

Net cash provided by (used in) operating activities of continued operations		(76.3	)		287.6			(248.2	)		—			(36.9	)
Net cash used in operating activities of discontinued operations		(3.4	)		—			—			—			(3.4	)

Net cash provided by (used in) operating activities		(79.7	)		287.6			(248.2	)		—			(40.3	)

CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for property, plant and equipment		(40.4	)		—			1.9			—			(38.5	)
Expenditures for turnaround		(31.7	)		—			—			—			(31.7	)
Cash and cash equivalents restricted for investment in capital additions		4.3			—			—			—			4.3
Other		0.2			—			—			—			0.2

Net cash provided by (used in) investing activities		(67.6	)		—			1.9			—			(65.7	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Long-term debt and capital lease payments		(151.0	)		(287.6	)		—			—			(438.6	)
Capital contributions, net from Premcor Inc.		150.4			—			84.2			—			234.6
Cash and cash equivalents restricted for debt repayment		—			—			(42.9	)		—			(42.9	)
Deferred financing costs		(1.5	)		—			(9.6	)		—			(11.1	)

Net cash provided by (used in) financing activities		(2.1	)		(287.6	)		31.7			—			(258.0	)

NET DECREASE IN CASH AND CASH EQUIVALENTS		(149.4	)		—			(214.6	)		—			(364.0	)
CASH AND CASH EQUIVALENTS, beginning of period		259.7			—			222.8			—			482.5

CASH AND CASH EQUIVALENTS, end of period	$	110.3		$	—		$	8.2		$	—		$	118.5

16. Commitments and Contingencies

Environmental and Legal Reserves

As a result of its normal course of business and the closure of two of its refineries, the Company is a party to a number of legal proceedings and environmental-related obligations. In relation to these matters and obligations the Company has accrued, on an undiscounted basis, the following:

	June 30, 2003		December 31, 2002

Refinery environmental obligations:
Hartford	$	28.2	$	29.6
Blue Island		18.7		19.7
Port Arthur		11.8		11.9
Memphis		1.0		—
Other legal and environmental		7.9		9.0

	$	67.6	$	70.2

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 (“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 currently expects to incur in the aggregate approximately $666 million, including $571 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. The total costs have been recently revised from an aggregate of $727 million and include further refinement of the plans and in particular a more detailed plan for the newly acquired Memphis refinery. 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 as of June 30, 2003		Contract Commitments		Year of Concentration of Expenditures
Gasoline low sulfur standards	$	310	$	91	$	219	$	203	2003/2004
Diesel low sulfur standards		330		4		326		—	2005
MACT II		26		—		26		—	2003

Total	$	666	$	95	$	571	$	203

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 at then current market prices as adjusted by certain predetermined contract provisions. The agreement with MSCG was terminated in June 2003, and the Company purchased the 2.7 million barrels of crude oil from MSCG at a net cost of approximately $80 million. The Company had 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 (“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 June 30, 2003, a cumulative quarterly surplus of $158.3 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:

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Industry-wide refining margins;

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Crude oil and other raw material costs, including natural gas; 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;

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Market volatility due to world and regional events;

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Availability and cost of debt and equity financing;

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Labor relations;

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U.S. and world economic conditions;

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Supply and demand for refined petroleum products;

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Price fluctuations between the time we enter into domestic crude oil purchase commitments and the time we actually process the crude oil into refined products (approximately one month) and the effect of any related hedging transactions;

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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;

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

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

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Acts of war or terrorism; and

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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. 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.

Memphis Refinery Acquisition

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, or 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 completion of independent appraisals and 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 April 1, 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. The actual daily value of the Gulf Coast 2/1/1 crack spread, as defined by the agreement, averaged $2.88 per barrel for the three- month period from April 1, 2003 through June 30, 2003. 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-month and six-month periods ended June 30, 2003 and 2002.

Financial Results (in millions, except as noted)	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2003			2002			2003			2002
Net sales and operating revenues	$	2,619.9		$	1,679.0		$	4,996.2		$	2,907.3
Cost of sales		2,354.6			1,523.4			4,463.5			2,585.0

Gross margin		265.3			155.6			532.7			322.3
Operating expenses		134.4			114.1			251.6			228.6
General and administrative expenses		15.7			14.4			27.4			28.9
Stock-based compensation		4.4			3.8			8.7			5.7
Depreciation and amortization		25.1			21.9			49.2			44.1
Refinery restructuring and other charges		0.7			16.6			15.7			158.6

Operating income (loss)		85.0			(15.2	)		180.1			(143.6	)
Interest expense and finance income, net		(29.1	)		(30.0	)		(54.4	)		(61.0	)
Loss on extinguishment of long-term debt		(3.4	)		(19.3	)		(10.4	)		(19.3	)
Income tax benefit (provision)		(18.0	)		23.5			(39.0	)		84.9
Minority interest		—			0.9			—			1.7

Income (loss) from continuing operations		34.5			(40.1	)		76.3			(137.3	)
Loss on discontinued operations		(2.2	)		—			(6.5	)		—

Net income (loss)		32.3			(40.1	)		69.8			(137.3	)
Preferred stock dividends		—			—			—			(2.5	)

Net income (loss) available to common stockholders	$	32.3		$	(40.1	)	$	69.8		$	(139.8	)

Income (loss) from continuing operations per common share:
Basic	$	0.47		$	(0.82	)	$	1.07		$	(3.47	)
Diluted		0.46			(0.82	)		1.06			(3.47	)
Weighted average common shares outstanding:
Basic		74.1			48.7			71.5			40.3
Diluted		74.8			48.7			72.2			40.3

Market Indicators (dollars per barrel, except as noted)	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2003			2002			2003			2002
West Texas Intermediate (WTI) crude oil (sweet)	$	29.08		$	26.28		$	31.60		$	23.94
Crack Spreads:
Gulf Coast 2/1/1		2.84			2.61			4.18			2.52
Chicago 3/2/1		6.45			5.29			6.44			4.48
Crude Oil Differentials:
WTI less Maya (heavy sour)		7.21			4.34			7.42			4.89
WTI less WTS (sour)		2.27			1.15			2.94			1.24
WTI less Dated Brent (foreign)		3.08			1.23			2.84			0.82
Natural gas (per mmbtu)		5.58			3.38			5.82			2.79

Selected Volumetric and Per Barrel Data (in thousands of bpd, except as noted)	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2003		2002		2003		2002
Crude oil throughput by refinery:
Port Arthur		245.5		239.9		244.9		235.9
Lima		133.7		142.8		133.3		141.2
Memphis (1)		168.6		—		111.0		—
Hartford		—		65.2		—		64.0

Total throughput		547.8		447.9		489.2		441.1
Total crude oil throughput (in millions of barrels)		49.8		40.8		88.5		79.8
Per barrel of throughput (in dollars):
Gross margin	$	5.32	$	3.82	$	6.02	$	4.04
Operating expenses		2.70		2.80		2.84		2.86

(1)

We acquired the Memphis refinery effective March 3, 2003 and the crude oil throughput for the six months ended June 30, 2003 reflected 120 days of operations averaged over that period. Crude oil throughput averaged 167,449 bpd during the 120 days of operations in 2003.

	Three Months Ended June 30, 2003							Three Months Ended June 30, 2002
Selected volumetric data (in thousands of bpd)	Port Arthur	Lima		Memphis	Total	Percent of Total		Port Arthur		Lima		Hartford	Total		Percent of Total
Feedstocks:
Crude oil throughput:
Sweet	—	131.7		168.6	300.3	53.6	%	—		142.6		—	142.6		31.7	%
Light/medium sour	31.5	2.0		—	33.5	6.0		33.3		0.2		63.2	96.7		21.5
Heavy sour	214.0	—		—	214.0	38.2		206.6		—		2.0	208.6		46.3

Total crude oil	245.5	133.7		168.6	547.8	97.8		239.9		142.8		65.2	447.9		99.5
Unfinished and blendstocks	13.0	(4.3	)	3.8	12.5	2.2		10.3		(12.4	)	4.4	2.3		0.5

Total feedstocks	258.5	129.4		172.4	560.3	100.0	%	250.2		130.4		69.6	450.2		100.0	%

Production:
Light products:
Conventional gasoline	84.8	63.5		70.8	219.1	38.3	%	85.3		70.7		29.4	185.4		39.8	%
Premium and reformulated gasoline	35.2	11.5		14.1	60.8	10.6		29.7		9.5		7.9	47.1		10.1
Diesel fuel	91.6	24.9		49.3	165.8	29.0		66.8		18.8		22.5	108.1		23.2
Jet fuel	8.5	18.8		25.4	52.7	9.2		30.2		20.7		—	50.9		10.9
Petrochemical feedstocks	18.6	7.2		8.2	34.0	6.0		18.4		7.4		3.1	28.9		6.2

Total light products	238.7	125.9		167.8	532.4	93.1		230.4		127.1		62.9	420.4		90.2
Petroleum coke and sulfur	31.2	2.4		0.3	33.9	5.9		29.4		2.8		3.8	36.0		7.8
Residual oil	1.4	0.9		3.6	5.9	1.0		5.6		2.1		1.7	9.4		2.0

Total production	271.3	129.2		171.7	572.2	100.0	%	265.4		132.0		68.4	465.8		100.0	%


	Six Months Ended June 30, 2003							Six Months Ended June 30, 2002
Selected volumetric data (in thousands of bpd)	Port Arthur	Lima		Memphis (1)	Total	Percent of Total		Port Arthur		Lima		Hartford	Total		Percent of Total
Feedstocks:
Crude oil throughput:
Sweet	—	130.0		110.6	240.6	48.0	%	—		138.5		—	138.5		31.8	%
Light/medium sour	32.4	3.3		0.4	36.1	7.2		41.1		2.7		59.1	102.9		23.6
Heavy sour	212.5	—		—	212.5	42.3		194.8		—		4.9	199.7		45.8

Total crude oil	244.9	133.3		111.0	489.2	97.5		235.9		141.2		64.0	441.1		101.2
Unfinished and blendstocks	13.3	(3.4	)	2.5	12.4	2.5		(3.2	)	(5.7	)	3.5	(5.4	)	(1.2	)

Total feedstocks	258.2	129.9		113.5	501.6	100.0	%	232.7		135.5		67.5	435.7		100.0	%

Production:
Light products:
Conventional gasoline	85.3	64.9		46.9	197.1	38.4	%	79.0		74.6		30.8	184.4		40.5	%
Premium and reformulated gasoline	33.7	11.7		8.6	54.0	10.5		21.9		10.3		5.8	38.0		8.4
Diesel fuel	82.9	24.4		32.7	140.0	27.2		65.6		18.1		21.3	105.0		23.1
Jet fuel	17.7	18.3		17.1	53.1	10.3		28.6		21.7		—	50.3		11.1
Petrochemical feedstocks	18.0	6.8		5.4	30.2	5.9		17.2		7.7		3.2	28.1		6.2

Total light products	237.6	126.1		110.7	474.4	92.3		212.3		132.4		61.1	405.8		89.3

Petroleum coke and sulfur	29.6	2.3		0.2	32.1	6.3		31.3		2.8		4.4	38.5		8.3
Residual oil	3.2	1.8		2.3	7.3	1.4		7.4		1.8		1.5	10.7		2.4

Total production	270.4	130.2		113.2	513.8	100.0	%	251.0		137.0		67.0	455.0		100.0	%

(1)

Second Quarter and First Half of 2003 Compared to the Same Periods in 2002

Overview. Net income available to common stockholders was $32.3 million ($0.43 per diluted share) in the second quarter of 2003 as compared to a net loss available to common stockholders of $40.1 million ($0.82 per diluted share) in the corresponding period in 2002. Our operating income was $85.0 million in the second quarter of 2003 as compared to an operating loss of $15.2 million in the corresponding period in 2002. This increase was principally attributable to stronger refining market conditions and a lower restructuring charge in the second quarter of 2003 compared to the corresponding period in 2002.

Net income available to common stockholders was $69.8 million ($0.97 per diluted share) for the first half of 2003 as compared to a net loss available to common stockholders of $139.8 million ($3.47 per diluted share) in the corresponding period in 2002. Our operating income was $180.1 million in the first half of 2003 as compared to an operating loss of $143.6 million in the corresponding period in 2002. The increase was principally due to stronger market conditions and a lower restructuring charge in the first half of 2003 compared to the corresponding period in 2002.

The results of operations in the first half of 2003 include the operations of our Memphis refinery beginning March 3, 2003, the date of acquisition. The results of operations in the first half of 2002 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 $940.9 million, or 56%, to $2,619.9 million in the second quarter of 2003 from $1,679.0 million in the corresponding period in 2002. Net sales and operating revenues increased $2,088.9 million, or 72%, to $4,996.2 million in the first half of 2003 from $2,907.3 million in the corresponding period in 2002. The increases were principally due to higher overall product and crude oil prices. Market conditions were volatile in the first quarter of 2003 and relatively more stable in the second quarter of 2003. 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 slightly in the second quarter of 2003, but were higher overall than the comparable period in 2002. There were many factors that we believe contributed to the overall volatile market conditions in the first quarter of 2003 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, which significantly reduced sweet crude oil production exports to the U.S., among others. We believe the market conditions in the second quarter of 2003 were affected by uncertainties about Iraqi production, continuing problems in Nigeria, and unseasonably low demand for gasoline. The high price scenario of 2003 was in sharp contrast to the first half of 2002, when overall prices were at more historical levels.

Gross Margin. Gross margin increased $109.7 million, or 71%, to $265.3 million in the second quarter of 2003 from $155.6 million in the corresponding period in 2002. Gross margin increased $210.4 million, or 65%, to $532.7 million for the first half of 2003 from $322.3 million in the corresponding period in 2002. The increase in gross margin in the second quarter and first half of 2003 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. These increases were partially offset by our 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 second quarter and first half of 2003 as compared to comparable periods of 2002, although these differentials weakened in the second quarter of 2003 compared to the first quarter of 2003. The Gulf Coast 2/1/1 and Chicago 3/2/1 crack spreads were approximately 9% and 22% higher, respectively, in the second quarter of 2003 than in the corresponding period in 2002, and approximately 66% and 44% higher in the first half of 2003 as compared to 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 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 environment weakened in the second quarter of 2003, but still remained higher than the 2002 margin environment. We believe the weakening of the second quarter margin environment was mainly attributable to unseasonably weak demand going into the summer driving season primarily caused by cool wet weather, particularly in the Northeast. In the second quarter and first half of 2002, the weak margin environment was influenced by an unseasonably warm winter and the economic downturn and significant demand declines resulting from the 2001 terrorist attacks.

The WTI less Maya and WTI less WTS crude oil differentials were approximately 66% and 97% higher, respectively, in the second quarter of 2003 than in the corresponding period in 2002 and approximately 52% and 137% higher in the first half of 2003 as compared to 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 second quarter and first half of 2003 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. 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 half of 2003, absolute hydrocarbon prices were volatile and 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 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. Including the effects of our price risk mitigation activities, our operating results in the second quarter and first half of 2003 were negatively affected by approximately $21 million and $37 million, respectively, from a decline in the value of our net fixed price purchase commitments. By comparison, the first half of 2002 was principally affected by having our fixed price purchase commitments largely exposed to price risk in a rising absolute price environment, which benefited our gross margin by approximately $8 million and $41 million in the second quarter and first half of 2002, respectively. See “Quantitative and Qualitative Disclosures about Market Risk—Commodity Risk” for a description of our price risk management strategies and policies.

Refinery Operations

Port Arthur refinery. In the second quarter and first half 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. As refining margins weakened late in the second quarter of 2003, the Port Arthur refinery slightly reduced its crude oil throughput rate.

In the first quarter of 2002, the average crude oil throughput rate 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 second quarter of 2002, the Port Arthur refinery reduced its crude oil throughput rate due to the narrow price differentials for sour and heavy sour crude oil as discussed above.

Lima refinery. In the second quarter and first half of 2003, the crude oil throughput rate at our Lima refinery was lower than the corresponding periods in 2002. In the second quarter of 2003, the crude oil throughput rate was reduced due to repairs on operational units downstream from the crude unit and due to weakening refining margins late in the quarter. The restricted crude oil throughput rate in 2003 was also affected by an 18-day planned turnaround maintenance of the FCC unit in the first quarter of 2003. The maintenance turnaround at our Lima refinery restricted our crude oil throughput rate by an average of approximately 25,000 bpd during the maintenance period. The crude oil throughput rate in 2002 was restricted due to weak market conditions at certain times during the first half of the year and due to a three-day unplanned shutdown of the reformer unit in the second quarter.

Memphis refinery. In the second quarter and first half of 2003, our newly acquired Memphis refinery operated at an average crude oil throughput rate of approximately 169,000 bpd and 167,000 bpd, respectively.

Operating Expenses. Operating expenses increased $20.3 million, or 18%, to $134.4 million in the second quarter of 2003 from $114.1 million in the corresponding period of 2002. Operating expenses increased $23.0 million, or 10%, to $251.6 million in the first half of 2003 from $228.6 million in the corresponding period of 2002. High natural gas prices were the main contributor to the increase in operating expenses, resulting in an approximate $10 million and $32 million increase in the second quarter and first half of 2003, respectively, as compared to the same periods in 2002. We were able to partially offset the impact of natural gas price increases by reducing consumption of natural gas, primarily through the use of internally generated fuels. The second quarter and first half of 2003 compared to 2002 also reflected the absence of

Hartford refinery operations, the addition of Memphis refinery operations for March through June, and a reduction in repair and maintenance costs at our Port Arthur refinery.

General and Administrative Expenses. General and administrative expenses increased $1.3 million, or 9%, to $15.7 million in the second quarter of 2003 from $14.4 million in the corresponding period in 2002. The increase is mainly attributable to a $1.2 million accrual for incentive compensation. General and administrative expenses decreased $1.5 million, or 5%, to $27.4 million in the first half of 2003 from $28.9 million in the corresponding period in 2002. The decrease in general and administrative expenses was due to the 2002 restructuring of our St. Louis office activities and other cost reduction measures initiated in 2002, partially offset by a $2.4 million accrual for incentive compensation and the addition of Memphis refinery operations in 2003.

Stock-Based Compensation Expense. Stock-based compensation expense increased $0.6 million, or 16%, to $4.4 million in the second quarter of 2003 from $3.8 million in the corresponding period in 2002. Stock-based compensation expense increased $3.0 million, or 53%, to $8.7 million in the first half of 2003 from $5.7 million in the corresponding period in 2002. The increases 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 increased $3.2 million, or 15%, to $25.1 million in the second quarter of 2003 from $21.9 million in the corresponding period in 2002. Depreciation and amortization increased $5.1 million, or 12%, to $49.2 million for the first half of 2003 from $44.1 million in the corresponding period in 2002. This increase was principally due to capital expenditure activity and the addition of depreciation for the Memphis refinery in 2003.

Refinery Restructuring and Other Charges. In 2003, we recorded refinery restructuring and other charges of $15.7 million, of which $0.7 million was recorded in the second quarter. The second quarter charge related to our plans to close the St. Louis administrative office. The year-to-date charge also included a $1.6 million reversal in restructuring charge related to the administrative restructuring which began in 2002 and a $16.6 million charge related to a proposed sale of certain Hartford refinery assets. These activities and transactions are described more fully below.

In 2002, we recorded refinery restructuring and other charges of $158.6 million, of which $16.6 million was recorded in the second quarter. The second quarter charge consisted of $6.2 million related to the then anticipated Hartford refinery shutdown, $6.5 million related to the 2002 restructuring of management and administrative functions, $2.5 million related to the termination of certain guarantees at PACC, and $1.4 million related to the write-down of idled assets held for sale. The year-to-date charge consisted of $137.4 million related to the anticipated Hartford refinery shutdown, $22.3 million related to the 2002 restructuring of management and administrative functions, $2.5 million related to the termination of certain guarantees at PACC, and $1.4 million related to the write-down of idled assets held for sale, partially offset by income of $5.0 million related to the unanticipated sale of a portion of previously written off Blue Island refinery assets.

Hartford Refinery Closure and Proposed Sale. 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 fair value of $49.0 million in anticipation of a sale or lease of the refining assets. We continue 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 at the Hartford refinery for $40 million. We expect to complete the transaction by the end of the third quarter of 2003. The $16.6 million charge in 2003 related to the sale 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.

As of December 31, 2002, we 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 final cash outlays related to the Hartford refinery shutdown were completed in the first quarter of 2003.

the Company announced that it would be closing the St. Louis office and moving the administrative functions to the Connecticut office over the next six to twelve months. The office move is expected to cost approximately $12.8 million, which includes $6.9 million of severance related benefits and $5.9 million of other costs such as training, relocation, and the movement of physical assets. The severance related costs will be amortized over the future service period of the affected employees and the other costs will be expensed as incurred.

The following table summarizes the expected costs associated with the administrative restructuring and provides a reconciliation of the administrative restructuring reserve as of June 30, 2003:

	Severance			Other Costs		Total Costs
Summary of Expected Costs:
Expected total cost	$	6.9		$	5.9	$	12.8
Costs incurred this quarter		0.7			—		0.7
Cumulative costs incurred to date		0.7			—		0.7

Reserve Activity:
Beginning balance, December 31, 2002	$	4.9		$	—	$	4.9
Costs incurred		0.7			—		0.7
Adjustments		(1.6	)		—		(1.6	)
Net cash outlays		(2.2	)		—		(2.2	)

Ending balance, June 30, 2003	$	1.8		$	—	$	1.8

Interest Expense and Finance Income, net. Interest expense and finance income, net decreased by $0.9 million, or 3%, to $29.1 million in the second quarter of 2003 from $30.0 million in the corresponding period in 2002. Interest expense and finance income, net decreased $6.6 million, or 11%, to $54.4 million for the first half of 2003 from $61.0 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 and $300 million senior notes in June 2003. The decrease was also offset by lower interest income.

Loss on Extinguishment of Long-term Debt. In the second quarter and first half of 2003, we recorded a loss on extinguishment of long-term debt of $3.4 million and $10.4 million (PRG — $3.4 million and $8.1 million), respectively, related to the early redemption and purchase of long-term debt and credit agreement amendment. In the second quarter of 2003, the loss included cash premiums of $2.7 million and a write-off of unamortized deferred financing costs of $0.7 million. In the first half of 2003, the loss included a cash premium of $5.0 million (PRG — $2.7 million) and a write-off of unamortized deferred financing costs of $5.4 million.

In the second quarter and first half of 2002, we recorded a loss on extinguishment of long-term debt of $19.3 million (PRG — $9.3 million) primarily related to the early redemption and repurchase of portions of our long-term debt. The loss included cash premiums of $9.2 million (PRG — 0.9 million), a write-off of unamortized deferred financing costs of $9.5 million (PRG — $7.8 million), and the write-off of a prepaid debt guarantee fee of $0.6 million.

Income Tax (Provision) Benefit. We recorded an income tax provision of $18.0 million in the second quarter of 2003 compared to an income tax benefit of $23.5 million in the corresponding period in 2002. Our effective tax rate was 34.2% for the second quarter of 2003 compared to 36.4% in the corresponding period in 2002. We recorded an income tax provision of $39.0 million in the first half of 2003 compared to an income tax benefit of $84.9 million in the corresponding period in 2002. Our effective tax rate was 33.8% in the first half of 2003 compared to 37.9% in the corresponding period in 2002.

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 obligations at these sites. In October 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. In bankruptcy hearings throughout the first and second quarter of 2003, CRE rejected approximately 30 of these leases. We recorded an after-tax charge of $2.2 million and $6.5 million for the second quarter and first half of 2003, respectively, representing the estimated net present value of our remaining liability under these rejected leases, net of estimated sub-lease income, and other direct costs. The future lease payments on the remaining properties is currently estimated as follows: (in million) 2003—$9.8, 2004—$10.1, 2005—$10.5, 2006—$10.9, 2007—$11.3, and in the aggregate thereafter—$84.2. In May 2003, CRE announced that it would conduct an orderly sale of its retail assets, including the lease sites that have not been rejected. In efforts to mitigate any losses we might incur as a result of the CRE bankruptcy, we are participating in the marketing of CRE’s subleases and discussing alternatives with representatives of CRE’s interests and with certain landlords. It is possible that we may incur additional liability for CRE lease obligations or other costs as CRE finalizes the disposition of the properties; however, the amounts are not estimable at this time and could be material. Should any additional leases revert to us, we will attempt to reduce the potential liability by subletting or reassigning the leases. The following table reconciles the activity and balance of the reserve for the lease obligations as well as our environmental liability for previously owned retail sites:

	Lease Obligations			Environmental Obligations of Previously Owned Sites			Total Discontinued Operations
Beginning balance, December 31, 2002	$	—		$	23.0		$	23.0
Net present value of lease obligations		8.6			—			8.6
Accretion and other expenses		2.0			—			2.0
Net cash outlays		(2.5	)		(0.6	)		(3.1	)

Ending balance, June 30, 2003	$	8.1		$	22.4		$	30.5

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 third quarter of 2003 through the middle of July have remained similar to the weakened conditions in the late second quarter. The Gulf Coast 2/1/1 crack spread has averaged approximately $3.90 per barrel, the Chicago 3/2/1 crack spread has averaged approximately $5.10 per barrel, and the WTI/Maya differential has averaged approximately $5.50 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 $0.66 per barrel of crude oil throughput in the second quarter of 2003. Due to a scheduled maintenance turnaround of the hydrocracker unit and weakened refining margins, we expect that the crude oil throughput rate at our Port Arthur refinery will be lower than 245,000 bpd in the third quarter of 2003.

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 $1.34 per barrel of crude throughput in the second quarter of 2003. Based on current market conditions, we expect the crude oil throughput rate in the third quarter of 2003 to approximate 140,000 bpd to 150,000 bpd.

Our Memphis refinery was acquired effective March 3, 2003 and averaged approximately 169,000 bpd in the second quarter of 2003. Based on current market conditions, we expect the crude oil throughput rate in the third quarter of 2003 to approximate 150,000 bpd to 160,000 bpd. 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 of approximately $0.63 per barrel, resulting from location premiums for refined products, partially offset by crude oil transportation costs.

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 $3.00 per million btu natural gas price environment and assuming average crude oil throughput levels, our annual operating expenses should range between $470 million and $500 million. However, natural gas prices in the first half of 2003 have been significantly higher than this rate. 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 reflect the price of natural gas on the day the contract

is set, and not the average price for the period. The natural gas contracts that we have been operating under expired in June 2003 but were extended to September 2003 while we negotiate new contracts.

General and Administrative Expenses. With the acquisition of the Memphis refinery, we expect our full year 2003 general and administrative expenses to be approximately $52 million, excluding incentive compensation. We have accrued $2.4 million for incentive compensation in the first half 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. In the first half of 2003, an additional 590,000 options were granted to employees and directors. Stock-based compensation expense in 2003, for options granted in 2002 and 2003, will approximate $17 million to $18 million.

Depreciation and Amortization. Depreciation and amortization in the second quarter of 2003 was $25.1 million. This includes a complete quarter of depreciation on the Memphis refinery. This amount will increase in future periods based upon the completion and placing into service of our capital expenditure activity. Capital activity is generally depreciated over a 25-year life. 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 June 30, 2003, our annual gross interest expense will be approximately $136 million and amortization of deferred financing costs will be approximately $9 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 half of 2003 totaled $70.2 million. This amount excludes the original purchase price of the Memphis refinery. We plan to expend approximately $200 million to $210 million for capital expenditures and turnarounds for the remainder of 2003, including $25 million related to the recently announced plans to expand the Port Arthur refinery. We plan to fund capital expenditures with internally generated funds and cash on hand. If internally generated funds and cash on hand are insufficient, we will reduce our capital expenditure plans accordingly.

We are continuing to evaluate a project to reconfigure the Lima refinery to process a more sour and heavier crude slate. We are also evaluating a similar project at our Memphis refinery. These initiatives are in a very preliminary stage.

Liquidity and Capital Resources

Cash Balance

As of June 30, 2003, we had a cash and short-term investment balance of $451.9 million of which $399.7 million was held by PRG, $47.2 million by Premcor Inc, $4.4 million by Opus Energy, a wholly-owned captive insurance subsidiary of Premcor Inc., and $0.6 million by Premcor USA. In addition, under our 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 June 30, 2003 cash of $66.9 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 flows provided by operating activities in the first half of 2003 was $22.7 million compared to net cash flows used in operating activities of $54.8 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 June 30, 2003 was $922.0 million, a 2.29-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 half of 2003 was due primarily to strong operating results, the Memphis refinery acquisition, and cash proceeds from our June 2003 debt offering.

Environmental and Legal Reserves. As a result of our normal course of business and the closure of two of our refineries, we are party to a number of legal proceedings and environmental-related obligations. In relation to these matters and obligations we have accrued, on an undiscounted basis, the following:

	June 30, 2003		December 31, 2002
Refinery environmental obligations:
Hartford	$	28.2	$	29.6
Blue Island		18.7		19.7
Port Arthur		11.8		11.9
Memphis		1.0		—
Other legal and environmental		7.9		9.0

	$	67.6	$	70.2

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 remediation plan. As the remediation plans are finalized and as work is performed, adjustments of the reserves may be necessary. We expect to spend approximately $3 million to $5 million in 2003 related to the Hartford and Blue Island reserves.

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 at then current market prices as adjusted by certain predetermined contract provisions. The agreement with MSCG was terminated in June 2003, and we purchased the 2.7 million barrels of crude oil from MSCG at a net cost of approximately $80 million. We had 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 June 30, 2003, a cumulative quarterly surplus of $158.3 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 in the first half of 2003 were $545.8 million as compared to $65.7 million in the corresponding period of 2002. The cash flows used in investing activities in 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. We estimate the total mandatory capital and turnaround expenditures, excluding expenditures for new product standards and MACT II discussed below, for all three refineries will average $130 million per year over the next four years and the forecast for these expenditures is approximately $86 million for 2003. Our total mandatory capital and refinery maintenance turnaround expenditures, excluding expenditures for new product standards and MACT II discussed below, were $27.6 million and $44.7 million in the first half of 2003 and 2002, respectively. Our Lima refinery completed a turnaround in the first quarter of 2003 and our Port Arthur refinery completed a turnaround in the first quarter 2002.

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 a total of approximately $666 million, including $571 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. The total costs have been recently revised from an aggregate of $727 million and include further refinement of the plans and in particular a more detailed plan for the newly acquired Memphis refinery. 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 June 30, 2003		Contract Commitments		Year of Concentration of Expenditures
Gasoline low sulfur standards	$	310	$	91	$	219	$	203	2003/2004
Diesel low sulfur standards		330		4		326		—	2005
MACT II		26		—		26		—	2003

Total	$	666	$	95	$	571	$	203

We currently expect to produce gasoline under the new sulfur standards at our Port Arthur refinery prior to January 1, 2004 and at our Memphis refinery in the first quarter of 2004. As a result of the corporate pool averaging

provisions of the regulations, we believe that we will be able to defer a significant portion of the investment required for compliance at our Lima refinery until the end of 2005 through the purchase of sulfur allotments and credits. There is no assurance that the averaging provisions of the regulations will allow for a deferral of compliance at the Lima refinery or that sufficient allotments or credits to defer investment at our Lima refinery will be available, or if available, that they will be cost effective. Our forecast for complying with these regulations is approximately $155 million in 2003. In the first half of 2003 and 2002 we incurred capital expenditures of $38.1 million and $15.9 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 May 2003, we announced plans to expand our Port Arthur, Texas refinery. The plans include increasing Port Arthur’s crude oil throughput capacity from its current rate of 250,000 bpd to approximately 325,000 bpd, and expanding the coker unit capacity from its current rated capacity of 80,000 bpd to 105,000 bpd, which will further increase our ability to process lower cost, heavy sour crude oil. This project is estimated to cost between $200 million and $220 million and is expected to be completed in the fourth quarter of 2005. This project will be funded primarily from the proceeds of the $300 million in senior notes issued in June 2003, which are described below in “—Cash Flows from Financing Activities.” We plan to spend approximately $25 million in 2003 related to the Port Arthur expansion. Our forecast for other discretionary capital expenditures is approximately $10 million for 2003. In the first half of 2003 and 2002, we incurred discretionary capital expenditures of $4.5 million and $9.6 million, respectively. We plan to fund mandatory and discretionary capital expenditures, excluding the Port Arthur expansion, with available cash and cash flow from operations and will adjust our annual expenditures accordingly.

Cash Flows from Financing Activities

Cash flows provided by financing activities were $801.7 million in the first half of 2003 compared to cash flows used in financing activities of $209.1 million in the corresponding period of 2002. In 2003, cash flows provided by financing activities related to proceeds from the sale of common stock and issuance of new long-term debt partially offset by the early repayment of certain long-term debt.

In 2003, Premcor Inc. received net proceeds of approximately $306 million from a public offering of 13.1 million shares of common stock and a private offering of 2.9 million shares of common stock with Blackstone Capital Partners III Merchant Banking Fund L.P. and its affiliates, a subsidiary of Occidental Petroleum Corporation, and certain Premcor executives. 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. A portion of the net proceeds of these transactions was utilized to redeem the remaining $40.1 million principal balance of Premcor USA’s 11½% subordinated debentures at a $2.3 million premium, to repay PRG’s $240 million floating rate loan at par, and to purchase, in the open market, $14.7 million in face value of a portion of our 12 ½% senior notes at a $2.7 million premium. In June 2003, PRG completed a private placement offering of $300 million in senior notes, due 2015, bearing interest at 7½% per annum.

In 2002, Premcor Inc. received net proceeds of $482 million from the initial public offering of common stock and a private placement of common stock. We used the proceeds from the offerings along with cash on hand to repay certain long-term debt of approximately $637.1 million, of which $438.6 million related to PRG long-term debt.

In 2003, we incurred $25.3 million of deferred financing costs in relation to the amendment of the credit agreement and the issuance of the new senior notes. In 2002, we incurred $11.1 million of deferred financing costs primarily related to a consent solicitation process, which facilitated the restructuring of PRG and PACC.

In 2003, Premcor Inc. made capital contributions to Premcor USA of $297.6 million and Premcor USA subsequently contributed $263.3 million to PRG primarily to fund the Memphis refinery acquisition and to repay certain long-term debt. In 2002, Premcor Inc. made capital contributions to Premcor USA of $442.9 million and Premcor USA subsequently contributed $234.6 million to PRG, all primarily to repay certain 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

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 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 June 30, 2003, the borrowing base was $1,130.9 million (December 31, 2002—$815.3 million), with $463.7 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 a sublimit of $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 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 our option based on certain restrictions. As of June 30, 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 working capital of at least $150 million and the maintenance of tangible net worth of at least $650 million, as amended. The covenants also provide for a cumulative cash flow test that from January 1, 2003 to February 10, 2006 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 June 30, 2003, $18.2 million (December 31, 2002—$10.1 million) of the line of credit was utilized for letters of credit.

New Accounting Standards

In July 2001, the Financial Accounting Standards Board, or 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. 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.

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 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 future meetings. 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.

In April 2003, the FASB issued SFAS No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities. SFAS No. 149 amends and clarifies financial accounting and reporting for derivative instruments, including certain derivative instruments embedded in other contracts. More specifically, SFAS No. 149, among other things, clarifies under what circumstances a contract with an initial net investment meets the characteristics of a derivative, clarifies when a derivative contains a financing component, and amends the definition of an “underlying” to conform to recently issued standards. SFAS No. 149 is effective for contracts entered into or modified after June 30, 2003, except for certain aspects of the standard that relate to previously issued guidance, which should continue to be applied in accordance with the previously set effective dates. Also, this standard is effective for existing and new contracts entered into after June 30, 2003 as they relate to forward purchases or sales of when-issued securities or other securities that do not yet exist. We do not expect the adoption of this standard will have a material impact on our financial statements.

In May 2003, the FASB issued SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity. SFAS No. 150 establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. SFAS No. 150 requires classification of a financial instrument that is within its scope as a liability, or an asset in some circumstances. SFAS No. 150 is effective for financial instruments entered into or modified after May 31, 2003, and shall otherwise be effective at the beginning of the first interim period beginning after June 15, 2003, except for mandatorily redeemable financial instruments of a nonpublic entity. For instruments created before the issuance of SFAS No. 150 and still existing at the beginning of the interim period of adoption, this standard shall be implemented by reporting the cumulative effect of a change in an accounting principle. We do not expect the adoption of this standard will have a material impact on our financial statements.

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 June 30, 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 June 30, 2003, a $1 change in quoted futures prices would result in an approximate $5 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 $1 change in quoted futures prices would result in an approximately $2 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 June 30, 2003 we have an outstanding balance, including current maturities, of $1,461.1 million (PRG—1,450.6 million). The weighted average interest rate on our fixed rate long-term debt is 9.3%. We are subject to interest rate risk on our Ohio bonds and any direct borrowings under our credit agreement. As of June 30, 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 million 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 June 30, 2003 and December 31, 2002, there were no direct borrowings under our credit agreement.

ITEM 4. Controls and Procedures

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 as of the end of the period covered by this report, 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 first half of 2003 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.

Village of Hartford, Illinois Litigation. In May 2003, the Attorney General’s office for the State of Illinois filed a lawsuit against us and a former owner of the Hartford refinery for injunctive relief, cost recovery and penalties related to subsurface contamination in the area of the refinery and facilities owned by other companies. The Attorney General’s office also sent notices to other companies with current or former operations in the area of the state’s intent to sue those companies as well. We have met with representatives of the state regarding issues at the Village of Hartford and those discussions are ongoing.

Lawsuits by Residents of Port Arthur, Texas. In June 2003, approximately 700 residents of Port Arthur, Texas filed a lawsuit against us and five other companies alleging personal injuries and property damage from emissions from refining and chemical facilities in the area. The plaintiffs are seeking class certification, unspecified damages and the establishment of a trust fund for health concerns.

ITEM 4. Submission of Matters to a Vote of Security Holders

Premcor Inc.’s annual meeting of stockholders was held May 20, 2003.

The following directors were elected to hold office for a one-year term until the 2004 annual meeting of stockholders. A tabulation of the number of votes for and withheld with respect to each director is set forth below. There were no abstentions or broker non-votes.

	Votes For	Withheld
Thomas D. O’Malley	70,706,066	1,800,058
Jefferson F. Allen	70,959,164	1,546,960
Wayne A. Budd	70,959,164	1,546,960
Stephen I. Chazen	70,829,664	1,676,460
Marshall A. Cohen	70,959,163	1,546,961
David I. Foley	66,480,670	6,025,454
Robert L. Friedman	66,163,271	6,342,853
Richard C. Lappin	66,163,270	6,342,854
Wilkes McClave III	70,959,164	1,546,960

The appointment of Deloitte & Touche LLP as our independent auditor for the fiscal year ending December 31, 2003 was ratified with 71,912,095 votes for, 592,902 votes against, 1,127 abstentions and no broker non-votes.

ITEM 6. Exhibits and Reports on Form 8-K

(a) Exhibits *

Exhibit Number		Description

4.1		Registration Rights Agreement, dated as of June 10, 2003, among PRG and the purchasers set forth therein (Incorporated by reference to Exhibit 4.10 filed with PRG’s Registration Statement on Form S-4 (Registration No. 333-106916)).

4.2		Form of 7½% Senior Exchange Note due 2015 (Incorporated by reference to Exhibit 4.11 filed with PRG’s Registration Statement on Form S-4 (Registration No. 333-106916)).

10.1		Amendment to Premcor Refining Senior Executive Retirement Plan dated May 30, 2003.

10.2		Fourth Amendment to the Premcor Pension Plan dated May 30, 2003.

10.3		Premcor Welfare Benefit Plan dated April 11, 2003.

10.4		Amendment to Employment Agreement, dated May 20, 2003, of Thomas D. O’Malley (Incorporated by reference to Exhibit 10.26 filed with PRG’s Registration Statement on Amendment No. 1 to Form S-4 (Registration No. 333-106916)).

10.5		Form of Amendment to Employment Agreement, dated May 20, 2003, of William E. Hantke, Henry M. Kuchta, Joseph D. Watson, James R. Voss, Michael D. Gayda, and Donald Lucey.

15.1		Awareness letter dated July 23, 2003, from Deloitte & Touche LLP concerning the unaudited interim financial information for June 30, 2003 and 2002.

99.1		Section 906 Chief Executive Officer certificate for Premcor Inc.

99.2		Section 906 Chief Financial Officer certificate for Premcor Inc.

99.3		Section 906 Chief Executive Officer certificate for PRG.

99.4		Section 906 Chief Financial Officer certificate for PRG.

99.5		Section 302 Chief Executive Officer certificate for Premcor Inc.

99.6		Section 302 Chief Financial Officer certificate for Premcor Inc.

99.7		Section 302 Chief Executive Officer certificate for PRG.

99.8		Section 302 Chief Financial Officer certificate for PRG.

* Filed herewith unless noted otherwise

(b) Current Reports on Form 8-K

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

(1)

Premcor Inc. furnished a report dated April 29, 2003 pursuant to Item 9 (announcing first quarter 2003 operating results);

(2)

Premcor Inc. furnished a report dated May 30, 2003 pursuant to Item 9 (announcing second quarter 2003 earnings expectations); and

(3)

Premcor Inc. and The Premcor Refining Group Inc. filed a report dated June 4, 2003 pursuant to Item 5 (announcing that The Premcor Refining Group Inc. offered, priced and completed a private placement of senior notes due 2015 in June 2003).

(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)

July 28, 2003