TESORO PETROLEUM CORP /NEW/ - 10-Q Quarterly Report

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q


(Mark One)
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


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

For the transition period from . . . . . . . . . . . to . . . . . . . . . .

Commission File Number 1-3473

TESORO PETROLEUM CORPORATION
(Exact name of registrant as specified in its charter)


Delaware (State or other jurisdiction of incorporation or organization)		95-0862768 (I.R.S. Employer Identification No.)

300 Concord Plaza Drive, San Antonio, Texas 78216-6999
(Address of principal executive offices) (Zip Code)

210-828-8484
(Registrant’s telephone number, including area code)

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

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Securities Exchange Act of 1934).
Yes X No

There were 64,616,678 shares of the registrant’s Common Stock outstanding at August 1, 2003.

TABLE OF CONTENTS


PART I — FINANCIAL INFORMATION
	ITEM 1. FINANCIAL STATEMENTS
		CONDENSED CONSOLIDATED BALANCE SHEETS
		CONDENSED STATEMENTS OF CONSOLIDATED OPERATIONS
		CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS
		NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
	ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
	ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
	ITEM 4. CONTROLS AND PROCEDURES
PART II — OTHER INFORMATION
	ITEM 2. CHANGES IN SECURITIES AND USE OF PROCEEDS
	ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
	ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
SIGNATURES
EXHIBIT INDEX
EX-31.1 Certification Pursuant to Section 302
EX-31.2 Certification Pursuant to Section 302
EX-32.1 Certification Pursuant to Section 906
EX-32.2 Certification Pursuant to Section 906

TESORO PETROLEUM CORPORATION AND SUBSIDIARIES

QUARTERLY REPORT ON FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2003

TABLE OF CONTENTS


			Page
PART I. FINANCIAL INFORMATION
	Item 1. Financial Statements (Unaudited)
		Condensed Consolidated Balance Sheets — June 30, 2003 and December 31, 2002		3
		Condensed Statements of Consolidated Operations — Three Months and Six Months Ended June 30, 2003 and 2002		4
		Condensed Statements of Consolidated Cash Flows — Six Months Ended June 30, 2003 and 2002		5
		Notes to Condensed Consolidated Financial Statements		6
	Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			15
	Item 3. Quantitative and Qualitative Disclosures About Market Risk			29
	Item 4. Controls and Procedures			30
PART II. OTHER INFORMATION
	Item 2. Changes in Securities and Use of Proceeds			31
	Item 4. Submission of Matters to a Vote of Security Holders			31
	Item 6. Exhibits and Reports on Form 8-K			31
SIGNATURES				33
EXHIBIT INDEX				34

PART I — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

TESORO PETROLEUM CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
(Dollars in millions except per share amounts)


				June 30,			December 31,
				2003			2002

ASSETS
CURRENT ASSETS
	Cash and cash equivalents			$	68.0		$	109.8
	Receivables, less allowance for doubtful accounts				406.5			412.2
	Income taxes receivable				—			41.9
	Inventories				427.8			461.5
	Prepayments and other				26.5			28.8

		Total Current Assets			928.8			1,054.2

PROPERTY, PLANT AND EQUIPMENT
	Refining				2,403.3			2,363.1
	Retail				236.2			239.0
	Corporate and Other				111.7			111.0

					2,751.2			2,713.1
	Less accumulated depreciation and amortization				(460.1	)		(409.7	)

		Net Property, Plant and Equipment			2,291.1			2,303.4

OTHER NONCURRENT ASSETS
	Goodwill				91.1			91.1
	Acquired intangibles, net				143.8			150.6
	Other, net				155.1			159.5

		Total Other Noncurrent Assets			390.0			401.2

			Total Assets	$	3,609.9		$	3,758.8

LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
	Accounts payable			$	361.6		$	338.6
	Accrued liabilities				227.1			199.7
	Current maturities of debt				4.6			70.0

		Total Current Liabilities			593.3			608.3

DEFERRED INCOME TAXES					141.0			128.7

OTHER LIABILITIES					244.4			227.5

DEBT					1,730.2			1,906.7

COMMITMENTS AND CONTINGENCIES (Note G)
STOCKHOLDERS’ EQUITY
	Common stock, par value $0.16-2/3; authorized 100,000,000 shares; 66,387,273 shares issued (66,379,928 in 2002)				11.0			11.0
	Additional paid-in capital				689.8			689.8
	Retained earnings				218.3			204.9
	Treasury stock, 1,771,695 common shares, at cost				(18.1	)		(18.1	)

		Total Stockholders’ Equity			901.0			887.6

			Total Liabilities and Stockholders’ Equity	$	3,609.9		$	3,758.8

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

TESORO PETROLEUM CORPORATION AND SUBSIDIARIES
CONDENSED STATEMENTS OF CONSOLIDATED OPERATIONS
(Unaudited)
(In millions except per share amounts)


		Three Months Ended						Six Months Ended
		June 30,						June 30,

		2003			2002			2003			2002

REVENUES		$	2,116.4		$	1,736.8		$	4,402.5		$	2,969.4
COSTS AND EXPENSES
	Costs of sales and operating expenses		1,979.6			1,663.7			4,110.7			2,895.6
	Selling, general and administrative expenses		32.1			33.8			70.4			72.3
	Depreciation and amortization		36.7			29.5			73.7			54.7
	Loss on asset sales		0.9			0.1			1.1			0.3

OPERATING INCOME (LOSS)			67.1			9.7			146.6			(53.5	)
Interest and financing costs, net of capitalized interest			(78.6	)		(41.6	)		(125.8	)		(71.9	)
Interest income			0.4			2.1			0.6			2.8

EARNINGS (LOSS) BEFORE INCOME TAXES			(11.1	)		(29.8	)		21.4			(122.6	)
Income tax provision (benefit)			(4.1	)		(11.9	)		8.0			(49.1	)

NET EARNINGS (LOSS)		$	(7.0	)	$	(17.9	)	$	13.4		$	(73.5	)

NET EARNINGS (LOSS) PER SHARE
	Basic	$	(0.11	)	$	(0.28	)	$	0.21		$	(1.30	)

	Diluted	$	(0.11	)	$	(0.28	)	$	0.21		$	(1.30	)

WEIGHTED AVERAGE COMMON SHARES
	Basic		64.6			64.6			64.6			56.4

	Diluted		64.6			64.6			64.8			56.4

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

TESORO PETROLEUM CORPORATION AND SUBSIDIARIES
CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS
(Unaudited)
(In millions)


					Six Months Ended
					June 30,

					2003			2002

CASH FLOWS FROM (USED IN) OPERATING ACTIVITIES
	Net earnings (loss)				$	13.4		$	(73.5	)
	Adjustments to reconcile net earnings (loss) to net cash from (used in) operating activities:
		Depreciation and amortization				73.7			54.7
		Amortization of debt issuance costs and discounts				11.1			4.3
		Write-off of unamortized debt issue costs				33.3			12.6
		Loss on asset sales				1.1			0.3
		Deferred income taxes				16.9			22.6
		Other changes in non-current assets and liabilities				2.3			(31.4	)
		Changes in current assets and current liabilities:
			Receivables			5.7			(47.3	)
			Income taxes receivable			41.9			(71.4	)
			Inventories			33.7			35.8
			Prepayments and other			2.3			(9.4	)
			Accounts payable and accrued liabilities			45.8			78.4

				Net cash from (used in) operating activities		281.2			(24.3	)

CASH FLOWS FROM (USED IN) INVESTING ACTIVITIES
	Capital expenditures					(43.6	)		(96.4	)
	Acquisition					—			(933.9	)
	Other					1.8			(11.7	)

				Net cash used in investing activities		(41.8	)		(1,042.0	)

CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES
	Proceeds from debt offering, net of issuance costs of $10.9 in 2003 and $9.4 in 2002					360.3			440.6
	Borrowings under term loans					350.0			425.0
	Debt refinanced					(721.2	)		—
	Other repayments of debt					(247.8	)		(23.3	)
	Proceeds from Common Stock offering, net of issuance costs of $13.7					—			245.1
	Other financing costs					(22.5	)		(30.0	)

				Net cash from (used in) financing activities		(281.2	)		1,057.4

DECREASE IN CASH AND CASH EQUIVALENTS						(41.8	)		(8.9	)
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD						109.8			51.9

CASH AND CASH EQUIVALENTS, END OF PERIOD					$	68.0		$	43.0

SUPPLEMENTAL CASH FLOW DISCLOSURES
	Interest paid, net of capitalized interest				$	85.0		$	43.7
	Income taxes paid (refunded)				$	(50.8	)	$	—

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

TESORO PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

NOTE A — BASIS OF PRESENTATION

The interim Condensed Consolidated Financial Statements and Notes thereto of Tesoro Petroleum Corporation and its subsidiaries (collectively, the “Company” or “Tesoro”) have been prepared by management without audit pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”). Accordingly, the accompanying financial statements reflect all adjustments that, in the opinion of management, are necessary for a fair presentation of results for the periods presented. Such adjustments are of a normal recurring nature. The Consolidated Balance Sheet at December 31, 2002 has been condensed from the audited Consolidated Financial Statements at that date. Certain information and notes normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”) have been condensed or omitted pursuant to the SEC’s rules and regulations. However, management believes that the disclosures presented herein are adequate to make the information not misleading. The accompanying Condensed Consolidated Financial Statements and Notes should be read in conjunction with the Consolidated Financial Statements and Notes thereto contained in the Company’s Annual Report on Form 10-K for the year ended December 31, 2002.

The preparation of the Company’s Condensed Consolidated Financial Statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the periods. Actual results could differ from those estimates. The results of operations for any interim period are not necessarily indicative of results for the full year.

Certain amounts previously reported during 2002 have been reclassified to conform with the current presentation and the presentation in the consolidated financial statements for the year ended December 31, 2002. The Company reclassified the amortization of major maintenance refinery turnaround, catalyst and drydocking costs from costs of sales and operating expenses to depreciation and amortization in the Condensed Statements of Consolidated Operations. The Company also reclassified revenues and costs of sales in the Condensed Statements of Consolidated Operations to report certain crude oil and product purchases and resales on a net basis following guidance issued in 2002 by the Emerging Issues Task Force of the Financial Accounting Standards Board.

NOTE B — EARNINGS (LOSS) PER SHARE

Basic earnings (loss) per share are determined by dividing net earnings (loss) by the weighted average number of common shares outstanding during the period. For the six months ended June 30, 2003, the calculation of diluted earnings per share takes into account the effects of potentially dilutive common stock options outstanding during the period. The assumed exercise of common stock options produced anti-dilutive results for three months ended June 30, 2003 and the three months and six months ended June 30, 2002, and was not included in the calculation of diluted earnings (loss) per share. Earnings (loss) per share calculations are presented below (in millions except per share amounts):


			Three Months Ended						Six Months Ended
			June 30,						June 30,

			2003			2002			2003		2002

Basic:
	Numerator:
		Net earnings (loss)	$	(7.0	)	$	(17.9	)	$	13.4	$	(73.5	)

	Denominator:
		Weighted average common shares outstanding		64.6			64.6			64.6		56.4

	Basic Earnings (Loss) Per Share		$	(0.11	)	$	(0.28	)	$	0.21	$	(1.30	)

TESORO PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


				Three Months Ended						Six Months Ended
				June 30,						June 30,

				2003			2002			2003		2002

Diluted:
	Numerator:
		Net earnings (loss)		$	(7.0	)	$	(17.9	)	$	13.4	$	(73.5	)

	Denominator:
		Weighted average common shares outstanding			64.6			64.6			64.6		56.4
			Dilutive effect of assumed exercise of stock options		—			—			0.2		—

			Total diluted shares		64.6			64.6			64.8		56.4

	Diluted Earnings (Loss) Per Share			$	(0.11	)	$	(0.28	)	$	0.21	$	(1.30	)

NOTE C — DEBT

On April 17, 2003, the Company replaced its $1.275 billion senior secured credit facility (the “Credit Facility”) with a new credit agreement, senior secured term loans and 8% senior secured notes due 2008 (described below). The Company expensed $33.3 million of unamortized debt issuance costs during the 2003 second quarter in connection with the extinguishment of the Credit Facility in April 2003 and the voluntary prepayment of other debt.

Debt and Maturities

Debt and other obligations consisted of the following (in millions):


		June 30,		December 31,
		2003		2002

Senior Secured Credit Facility — Tranche A Term Loan		$	—	$	194.2
Senior Secured Credit Facility — Tranche B Term Loan			—		723.8
Credit Agreement — Revolving Credit Facility			—		—
Credit Agreement — Term Loan			124.7		—
Senior Secured Term Loans			200.0		—
8% Senior Secured Notes Due 2008 (net of unamortized discount of $3.6)			371.4		—
9-5/8% Senior Subordinated Notes Due 2012			429.0		450.0
9-5/8% Senior Subordinated Notes Due 2008			211.0		215.0
9% Senior Subordinated Notes Due 2008 (net of unamortized discount of $2.0 in 2003 and $2.1 in 2002)			298.0		297.9
Junior Subordinated Notes (net of unamortized discount of $77.8 in 2003 and $83.0 in 2002)			72.2		67.0
Other debt, primarily capital leases			28.5		28.8

	Total debt		1,734.8		1,976.7
Less current maturities			4.6		70.0

	Debt less current maturities	$	1,730.2	$	1,906.7

As of June 30, 2003, the aggregate scheduled maturities of outstanding debt, including capital leases, for each of the five following 12-month periods were as follows: 2003 — 2004, $4.6 million; 2004 — 2005, $4.8 million; 2005 — 2006, $4.7 million; 2006 — 2007, $124.4 million; and 2007 — 2008, $568.0 million.

Credit Agreement

On April 17, 2003, the Company entered into a new $650 million credit agreement (the “Credit Agreement”), consisting of a $500 million revolving credit facility (with a $400 million sublimit for letters of credit) maturing in June 2006 and a $150 million term loan maturing in April 2007. The Credit Agreement, together with the net proceeds of the $200 million senior secured term loans and $375 million aggregate principal amount of 8% senior secured notes

TESORO PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

discussed below, replaced the Company’s Credit Facility. In addition, $25 million of the proceeds were used to repurchase existing 9-5/8% senior subordinated notes. In June 2003, the Company also prepaid $25 million on the $150 million term loan.

The Credit Agreement provides for borrowings (including letters of credit) up to the lesser of $624.7 million as of June 30, 2003, or the amount of a weekly-adjusted borrowing base with respect to the Company’s eligible cash and cash equivalents, receivables and petroleum inventories, as defined in the Credit Agreement. As of June 30, 2003, the Company had no borrowings and $250.5 million in letters of credit outstanding under the revolving credit facility, and $124.7 million remained outstanding under the term loan. The borrowing base under the Credit Agreement as of June 30, 2003 was $624.7 million, resulting in total unused credit availability of $249.5 million.

The Credit Agreement contains covenants and conditions that, among other things, limit the Company’s ability to pay dividends, incur indebtedness, create liens and make investments. The Company is also required to maintain specified levels of fixed charge coverage and tangible net worth. The Company satisfied all of the financial covenants under the Credit Agreement for the quarter ended June 30, 2003. Beginning with the quarter ending March 31, 2004, maintenance of the fixed charge coverage ratio is not required if unused credit availability under the Credit Agreement exceeds 15% of the eligible borrowing base then in effect. The Credit Agreement requires the Company to maintain a collection account for cash receipts which will be used daily to repay any borrowings outstanding on the revolving credit facility. The Credit Agreement is guaranteed by substantially all of the Company’s active subsidiaries and is secured by substantially all of the Company’s cash and cash equivalents, petroleum inventories and receivables.

At June 30, 2003, the interest rate on the term loan was 5.5%. Borrowings under the Credit Agreement bear interest at either a base rate (4.0% at June 30, 2003) or a eurodollar rate (ranging from 1.03% to 1.14% at June 30, 2003), plus an applicable margin. The applicable margins at June 30, 2003 for the revolving credit facility were 1.5% in the case of the base rate and 3.25% in the case of the eurodollar rate. Letters of credit outstanding under the revolving credit facility incur fees at an annual rate equal to the eurodollar rate applicable margin for the revolving credit facility. The applicable margins under the revolving credit facility vary based on credit availability levels. In July 2003, the revolving credit facility eurodollar rate applicable margin was reduced from 3.25% to 2.75% based on the 2003 second quarter credit availability levels. The applicable margins for the term loan were 2.25% in the case of the base rate and 4.0% in the case of the eurodollar rate.

Senior Secured Term Loans

On April 17, 2003, the Company entered into new $200 million senior secured term loans due April 15, 2008 (the “Term Loans”). The Term Loans are subject to optional redemption by the Company beginning April 15, 2004 at premiums of 3% through April 14, 2005, 1% from April 15, 2005 to April 14, 2006, and at par thereafter. In addition, the Company, for the first year, may use proceeds from certain equity issuances to redeem up to 35% of the aggregate principal amount, subject to a prepayment premium equal to the annual interest rate then in effect. The Term Loans contain covenants and restrictions which are less restrictive than those in the Credit Agreement. The Term Loans and the 8% senior secured notes described below are secured by substantially all of the Company’s Refining property, plant and equipment and are guaranteed by substantially all of our active subsidiaries.

At June 30, 2003, interest rates were 6.53% to 6.64% on the Term Loans. Borrowings under the Term Loans bear interest at either a base rate (4.0% at June 30, 2003) or a eurodollar rate (ranging from 1.03% to 1.14% at June 30, 2003), plus an applicable margin. The applicable margins at June 30, 2003 for the Term Loans were 4.5% in the case of the base rate and 5.5% in the case of the eurodollar rate.

8% Senior Secured Notes Due 2008

On April 17, 2003, the Company issued $375 million aggregate principal amount of 8% senior secured notes due April 15, 2008 (the “2008 Notes”) through a private offering. The 2008 Notes have a five-year maturity with no sinking fund requirements and are subject to optional redemption by the Company after three years at a premium of 4% in year four and at par thereafter. In addition, the Company, for the first three years, may redeem up to 35% of the aggregate

TESORO PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

principal amount at a redemption price of 108% with proceeds from certain equity issuances. The indenture for the 2008 Notes contains covenants and restrictions which are customary for notes of this nature and are similar to the covenants in the indentures for the Company’s existing senior subordinated notes. The 2008 Notes and the Term Loans are secured by substantially all of the Company’s Refining property, plant and equipment and guaranteed by substantially all of Tesoro’s active subsidiaries. The 2008 Notes were issued at 98.994% of par, resulting in proceeds to the Company of $371.2 million before debt issuance costs. The effective interest rate on the 2008 Notes was 8.25%, after giving effect to the discount at the date of issue. On July 29, 2003, the Company completed an exchange of substantially all of the outstanding 2008 Notes for 8% senior secured notes due 2008 that had been registered under the Securities Act of 1933.

NOTE D — OPERATING SEGMENTS

The Company’s revenues are derived from two major operating segments, Refining and Retail. The Company also derives revenues from marine services activities included in the Other operating segment. Management has identified these segments for managing operations and investing activities and evaluates the performance of these segments and allocates resources based primarily on segment operating income. Segment operating income includes those revenues and expenses that are directly attributable to management of the respective segment. Intersegment sales from Refining to Retail are made at prevailing market rates.

Operating income includes charges for voluntary early retirement benefits and severance costs totaling $9.0 million during the six months ended June 30, 2003, of which $8.8 million was incurred during the three months ended March 31, 2003, including a non-cash pretax charge of $7.0 million related to voluntary early retirement benefits. The $9.0 million charge includes $2.6 million in Refining, $1.3 million in Retail, $0.4 million in Other and $4.7 million in Corporate. Income taxes, interest and financing costs, interest income, corporate general and administrative expenses and losses on asset sales are not included in determining segment operating income. Segment information is as follows (in millions):


					Three Months Ended						Six Months Ended
					June 30,						June 30,

					2003			2002			2003			2002

Revenues
	Refining:
		Refined products			$	1,950.8		$	1,555.8		$	4,034.1		$	2,631.3
		Crude oil resales and other				66.8			97.0			183.9			188.4
	Retail:
		Fuel				205.7			234.4			403.8			402.3
		Merchandise and other				30.7			33.3			56.8			56.2
	Other					36.3			31.4			79.5			57.9
	Intersegment Sales from Refining to Retail					(173.9	)		(215.1	)		(355.6	)		(366.7	)

				Total Revenues	$	2,116.4		$	1,736.8		$	4,402.5		$	2,969.4

Segment Operating Income (Loss)
	Refining				$	72.3		$	36.9		$	181.5		$	1.1
	Retail					10.3			(7.4	)		2.2			(17.0	)
	Other					1.7			0.1			2.8			0.6

		Total Segment Operating Income (Loss)				84.3			29.6			186.5			(15.3	)
	Corporate and Unallocated Costs					(16.3	)		(19.8	)		(38.8	)		(37.9	)
	Loss on Asset Sales					(0.9	)		(0.1	)		(1.1	)		(0.3	)

		Operating Income (Loss)				67.1			9.7			146.6			(53.5	)
	Interest and Financing Costs, Net of Capitalized Interest					(78.6	)		(41.6	)		(125.8	)		(71.9	)
	Interest Income					0.4			2.1			0.6			2.8

			Earnings (Loss) Before Income Taxes		$	(11.1	)	$	(29.8	)	$	21.4		$	(122.6	)

TESORO PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


			Three Months Ended				Six Months Ended
			June 30,				June 30,

			2003		2002		2003		2002

Depreciation and Amortization
	Refining		$	29.6	$	23.4	$	59.4	$	43.8
	Retail			5.0		3.9		10.0		7.3
	Other			0.7		0.8		1.4		1.5
	Corporate			1.4		1.4		2.9		2.1

		Total Depreciation and Amortization	$	36.7	$	29.5	$	73.7	$	54.7

Capital Expenditures
	Refining		$	15.4	$	27.0	$	42.4	$	63.3
	Retail			0.1		15.3		0.3		25.4
	Other			0.1		0.9		0.4		2.1
	Corporate			0.3		0.6		0.5		5.6

		Total Capital Expenditures	$	15.9	$	43.8	$	43.6	$	96.4

Capital expenditures do not include major maintenance refinery turnaround, catalyst and drydocking costs of $9.5 million and $17.7 million for the three months ended June 30, 2003 and 2002, respectively, and $18.0 million and $37.4 million for the six months ended June 30, 2003 and 2002, respectively.

Identifiable assets are those assets utilized by the segment. Corporate assets are principally cash, income taxes receivable and other assets that are not associated with an operating segment. Segment assets were as follows (in millions):


			June 30,		December 31,
			2003		2002

Identifiable Assets
	Refining		$	3,063.8	$	3,118.1
	Retail			286.3		287.8
	Other			60.9		68.4
	Corporate			198.9		284.5

		Total Assets	$	3,609.9	$	3,758.8

NOTE E — INVENTORIES

Components of inventories were as follows (in millions):


		June 30,		December 31,
		2003		2002

Crude oil and refined products, at LIFO		$	369.2	$	402.6
Other fuel, oxygenates and by-products, at FIFO			9.0		11.2
Merchandise and other			9.4		9.3
Materials and supplies			40.2		38.4

	Total Inventories	$	427.8	$	461.5

NOTE F — STOCK-BASED COMPENSATION

The Company accounts for stock-based compensation using the intrinsic value method prescribed in Accounting Principles Board (“APB”) Opinion No. 25, “Accounting for Stock Issued to Employees,” and related interpretations. Accordingly, compensation cost for stock options is measured as the excess, if any, of the quoted market price of the Company’s Common Stock at the date of grant over the amount an employee must pay to acquire the stock. The

TESORO PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

following table represents the effect on net earnings (loss) and earnings (loss) per share if the Company had applied a fair value based method and recognition provisions of Statement of Financial Accounting Standards (“SFAS”) No. 123, “Accounting for Stock-Based Compensation,” for the grant of stock options (in millions except per share amounts):


		Three Months Ended						Six Months Ended
		June 30,						June 30,

		2003			2002			2003			2002

Reported net earnings (loss)		$	(7.0	)	$	(17.9	)	$	13.4		$	(73.5	)
Deduct total stock-based employee compensation expense determined under fair value based methods for all awards, net of related tax effects			(1.1	)		(0.7	)		(1.6	)		(1.3	)

Pro forma net earnings (loss)		$	(8.1	)	$	(18.6	)	$	11.8		$	(74.8	)

Net earnings (loss) per share:
	Basic and diluted, as reported	$	(0.11	)	$	(0.28	)	$	0.21		$	(1.30	)

	Basic and diluted, pro forma	$	(0.13	)	$	(0.29	)	$	0.18		$	(1.33	)

For purposes of the pro forma disclosures above, the estimated fair value of stock-based compensation plans is amortized to expense primarily over the vesting period. The fair value of each option grant was estimated on the date of grant using the Black-Scholes option-pricing model.

NOTE G — COMMITMENTS AND CONTINGENCIES

The Company is a party to various litigation and contingent loss situations, including environmental and tax matters, arising in the ordinary course of business. The Company has made accruals in accordance with SFAS No. 5, “Accounting for Contingencies,” in order to provide for these matters. The ultimate effects of these matters cannot be predicted with certainty, and related accruals are based on management’s best estimates, subject to future developments. Although the resolution of certain of these matters could have a material adverse effect on interim or annual results of operations, the Company believes that the outcome of these matters will not result in a material adverse effect on its liquidity or consolidated financial position.

In the normal course of business, the Company is subject to audits by federal, state and local taxing authorities. It is possible that tax audits could result in claims against the Company in excess of liabilities currently recorded. Management believes, however, that the ultimate resolution of these matters will not materially affect the Company’s consolidated financial position or results of operations.

Environmental

The Company is subject to extensive federal, state and local environmental laws and regulations. These laws, which change frequently, regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites, or install additional controls, or make other modifications or changes in use for certain emission sources.

Environmental Remediation Liabilities

Soil and groundwater conditions at the California refinery may require substantial expenditures over time. The Company has revised its estimate of pre-acquisition environmental liabilities including soil and groundwater conditions at the refinery in connection with various projects, including those required pursuant to orders by the California Regional Water Quality Control Board, to approximately $42 million. The Company believes that all of such liabilities will be paid, directly or indirectly, by former owners or operators of the refinery (or their successors) under two separate indemnification agreements. Additionally, if remediation liabilities are incurred in excess of the indemnification, the Company expects to be reimbursed for such excess liabilities under certain environmental insurance policies.

TESORO PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

The Company is currently involved with the U.S. Environmental Protection Agency (“EPA”) regarding a waste disposal site near Abbeville, Louisiana. The Company has been named a potentially responsible party under the Federal Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA” or “Superfund”) at this location. Although the Superfund law may impose joint and several liability upon each party at the site, the extent of the Company’s allocated financial contributions for cleanup is expected to be de minimis based upon the number of companies, volumes of waste involved and total estimated costs to close the site. The Company believes, based on these considerations and discussions with the EPA, that its liability at the Abbeville site will not exceed $25,000.

The Company is currently involved in remedial responses and has incurred cleanup expenditures associated with environmental matters at a number of sites, including certain of its owned properties. At June 30, 2003, the Company’s accruals for environmental expenses totaled approximately $39 million. The Company’s accruals for environmental expenses include retained liabilities for previously owned or operated properties, refining, pipeline, terminal and marine services operations and retail service stations. Based on currently available information, including the participation of other parties or former owners in remediation actions, the Company believes these accruals are adequate.

Environmental Capital

EPA regulations pursuant to the Clean Air Act require reduction in the sulfur content in gasoline beginning January 1, 2004. To meet the revised gasoline standard, the Company currently estimates it will make capital improvements of approximately $37 million through 2006 and an additional $15 million thereafter. This will permit all of the Company’s refineries to produce gasoline meeting the sulfur limits imposed by the EPA.

EPA regulations pursuant to the Clean Air Act also require a reduction in the sulfur content in diesel fuel manufactured for on-road consumption. In general, the new diesel fuel standards will become effective on June 1, 2006. Based on the latest engineering estimates and spending to date, the Company expects to spend approximately $55 million in capital improvements through 2007. The Company does not plan to make similar expenditures at the Alaska refinery because limited demand for low sulfur diesel presently does not justify the capital investment. The Company expects to meet the demand for low sulfur diesel in Alaska from other sources.

The Company expects to spend approximately $50 million in capital improvements through 2006 to comply with the second phase of the Maximum Achievable Control Technologies standard for petroleum refineries (“Refinery MACT II”), promulgated in April 2002. The Refinery MACT II regulations require new emission controls at certain processing units at several of the Company’s refineries. The Company is currently evaluating a selection of control technologies to assure operations flexibility and compatibility with long-term air emission reduction goals.

The California refinery has made substantial expenditures to meet California’s CARB III gasoline requirements, including the mandatory phase-out of using the oxygenate known as MTBE by the end of 2003. To comply with these requirements, the Company spent approximately $77 million since May 2002, including $17.7 million in 2003. The CARB III project commenced operations in March 2003.

In connection with the 2002 acquisition of the California refinery, subject to certain conditions, the Company also assumed the seller’s obligations pursuant to its settlement efforts with the EPA concerning the Section 114 refinery enforcement initiative under the Clean Air Act, except for any potential monetary penalties which the seller retains. The Company believes these obligations will not have a material impact on its financial position.

The Company will need to spend additional capital at the California refinery for reconfiguring and replacing above-ground storage tank systems and upgrading piping within the refinery. These future costs are currently estimated at $129 million through 2007 and an additional $86 million through 2010. Both of these cost estimates are subject to further review and analysis by the Company.

In connection with the 2001 acquisition of the North Dakota and Utah refineries, the Company assumed the sellers’ obligations and liabilities under a consent decree among the United States, BP Exploration and Oil Co. (“BP”), Amoco Oil Company and Atlantic Richfield Company. BP entered into this consent decree for both the North Dakota and Utah

TESORO PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

refineries for various alleged violations. As the new owner of these refineries, the Company is required to address issues, including leak detection and repair, flaring protection and sulfur recovery unit optimization. The Company currently estimates it will spend an aggregate of $7 million to comply with this consent decree. In addition, the Company has agreed to indemnify the sellers for all losses of any kind incurred in connection with the consent decree.

Conditions may develop that require additional expenditures for various Company sites, including, but not limited to, the Company’s refineries, tank farms, retail gasoline stations (operating and closed locations) and petroleum product terminals, and for compliance with the Clean Air Act and other state, federal and local requirements. The Company cannot currently determine the amounts of such future expenditures.

Other

Union Oil Company of California has asserted claims against other refining companies for infringement of patents related to the production of certain reformulated gasoline. The Company’s California refinery produces grades of gasoline that might be subject to similar claims. Since the validity of those patents is being questioned by the U.S. Patent Office and the Federal Trade Commission, the Company has not paid or accrued liabilities for patent royalties that might be related to production at the California refinery.

NOTE H — NEW ACCOUNTING STANDARDS

SFAS No. 143

On January 1, 2003, the Company adopted SFAS No. 143, “Accounting for Asset Retirement Obligations,” which addresses financial accounting and reporting for legal obligations associated with the retirement of long-lived assets. The Company has identified asset retirement obligations that are within the scope of the standard, including obligations imposed by certain state laws pertaining to closure and/or removal of storage tanks, and contractual removal obligations included in certain lease and right-of-way agreements associated with the Company’s retail, pipeline and terminal operations. The Company has estimated the fair value of its asset retirement obligations, based in part on the terms of the agreements and the probabilities associated with the eventual sale or other disposition of these assets. The Company cannot currently make reasonable estimates of the fair values of some retirement obligations, principally those associated with refineries, certain pipeline rights-of-way and certain terminals, because the related assets have indeterminate useful lives which preclude development of assumptions about the potential timing of settlement dates. Such obligations will be recognized in the period in which sufficient information exists to estimate a range of potential settlement dates. The present value of obligations was accrued to the extent that settlement dates could be estimated, primarily for assets on leased sites. The effect of adopting this accounting standard on January 1, 2003, was to increase property, plant and equipment by approximately $0.6 million, net of accumulated amortization and increase noncurrent other liabilities by approximately $1.7 million. The cumulative effect charge of approximately $1.1 million pretax was included in operating income due to immateriality during the three months ended March 31, 2003. Additional depreciation and operating expense also was immaterial during the six months ended June 30, 2003, and similarly, would not have had a material effect on the six months ended June 30, 2002, if the standard had been adopted in 2002.

SFAS No. 149

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, and for hedging activities under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” SFAS No. 149, among other things, clarifies the circumstances under which a contract with an initial net investment meets the characteristic of a derivative and amends the definition of an “underlying” to conform it to language used in FIN 45. SFAS No. 149 is effective for contracts entered into or modified after June 30, 2003. The Company adopted this statement effective July 1, 2003. Implementation of this new standard did not have a material effect on the Company’s consolidated financial position or results of operations.

TESORO PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

FIN 46

In January 2003, the FASB issued Interpretation No. 46. “Consolidation of Variable Interest Entities” (“FIN 46”), which requires the consolidation of variable interest entities, as defined. FIN 46 applies immediately to variable interest entities created after January 31, 2003. The consolidation requirements apply to older entities in the first fiscal year or interim period beginning after June 15, 2003. Certain of the disclosure requirements apply to all financial statements issued after January 31, 2003, regardless of when the variable interest entity was established. Implementation of FIN 46 on July 1, 2003 did not result in the consolidation of any variable interest entities.

Proposed Statement of Position

In 2001, the American Institute of Certified Public Accountants (“AICPA”) issued an Exposure Draft for a proposed Statement of Position, “Accounting for Certain Costs and Activities Related to Property, Plant and Equipment.” The proposed Statement of Position (“SOP”), as originally written, would require major maintenance activities, such as refinery turnarounds, to be expensed as costs are incurred. If this proposed SOP is adopted as originally written, the Company would be required to write off the unamortized carrying value of deferred major maintenance costs as a cumulative effect of an accounting change, net of tax, and to expense future costs as incurred. At June 30, 2003, deferred major maintenance costs, which are included in other noncurrent assets — other in the Condensed Consolidated Balance Sheet, totaled $65.1 million.

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

Those statements in this section that are not historical in nature should be deemed forward-looking statements that are inherently uncertain. See “Forward-Looking Statements” on page 28 for a discussion of the factors that could cause actual results to differ materially from those projected in these statements.

BUSINESS OVERVIEW

Our earnings, cash flows from operations and liquidity depend upon many factors, including producing and selling refined products at margins above fixed and variable expenses. The prices of crude oil and refined products have fluctuated substantially in our markets. Our operating results can be significantly influenced by the timing of changes in crude oil costs and how quickly refined product prices adjust to reflect these changes. These price fluctuations depend on numerous factors beyond our control, including the demand for crude oil, gasoline and other refined products, which is subject to, among other things, changes in the economy and the level of foreign and domestic production of crude oil and refined products, worldwide political conditions, threatened or actual terrorist incidents or acts of war, availability of crude oil and refined product imports, the infrastructure to transport crude oil and refined products, weather conditions, earthquakes and other natural disasters, seasonal variations in demand for products, government regulations and local factors, including market conditions and the level of operations of other refineries in our markets. As a result of these factors, margin fluctuations during any reporting period can have a significant impact on our results of operations, cash flows, liquidity and financial position.

Several factors during the first six months of 2003 have impacted industry margins and finished product inventory levels. During the first and second quarters of 2003, uncertainties related to the conflict in Iraq resulted in significant fluctuations in crude oil prices and refined product margins. Industry margins in the first quarter of 2003 in our market areas averaged above our five-year first quarter average (January 1, 1998 through December 31, 2002) while industry margins in the second quarter of 2003 averaged below our five-year second quarter average. We determine our “five-year average” by comparing gasoline, diesel and jet fuel prices to crude oil prices in our market areas, with volumes weighted according to our typical refinery yields, excluding heavy fuel oils. During the 2003 second quarter compared to the first quarter, there were high seasonal production levels of finished products, decreased jet fuel demand and tightening of the light to heavy crude oil differential, primarily affecting California. Higher than normal industry maintenance during the 2003 first quarter reduced overall industry finished product inventory levels, and the cold winter in 2003 increased demand and margins for distillates. Although jet fuel demand slowly improved and approached pre-September 11, 2001 levels during the first quarter of 2003, we believe the outbreak of SARS in the Far East during the 2003 second quarter resulted in a significant decrease in jet traffic, which negatively impacted jet fuel demand in Hawaii and on the U.S. west coast. Jet fuel margins and demand have begun to recover in the 2003 third quarter, as it appears that fears surrounding the SARS outbreak have subsided. The tightening of the light to heavy crude oil differential was primarily due to a decline in alternate foreign heavy crude supplies, including those from Venezuela, Ecuador and Iraq. Although industry margins were lower overall in the second quarter, that decrease was partly offset by increased gasoline margins in California. Gasoline margins increased as a result of operating problems at several California refineries, and west coast gasoline supply tightened due to changes in gasoline specifications related to the phase-out of MTBE in California.

BUSINESS STRATEGY

Our strategy is to create a geographically focused, value-added refining and marketing business that has (i) economies of scale, (ii) a low-cost structure, (iii) superior management information systems and (iv) outstanding employees focused on business excellence, and that seeks to provide stockholders with competitive returns in any economic environment. Our immediate focus is to reduce our level of debt through a combination of cash flows from operations, cost savings and revenue enhancements.

Debt Reduction Initiatives

In June 2002, we announced our goal to reduce debt by $500 million by the end of 2003. As reflected in our 2002 operating results, we experienced a weak margin environment in 2002, which negatively affected our debt reduction plans. Nevertheless, through June 30, 2003, we have repaid $371 million of debt since May 2002, of which $248 million was paid in the 2003 first and second quarters. We continue to pursue our goal to further reduce debt through positive operating cash flows and cash conservation measures which have been based on the following initiatives: (i) cost reduction and refinery yield improvement, (ii) reduction or deferral of capital expenditures and refinery turnaround spending without compromising safety or reliability, (iii) achievement of system-wide synergies from the acquisition of our California refinery, (iv) asset sales and (v) increasing cash available to reduce debt by the use of letters of credit under our new credit agreement to reduce early payments and prepayments on crude oil and product purchases.

Cost Reduction and Refinery Yield Improvement

One of our initiatives for 2003 was to realize $65 million of operating income improvements in 2003 through $50 million of cost reductions and $15 million of refinery yield improvements that do not require significant capital investments. Although we expect to exceed our goal of $15 million in refinery yield improvements, we do not expect to achieve our goal of $50 million in absolute cost reductions by the end of 2003. During the 2003 first and second quarters, we achieved $17 million in operating improvements including $5 million in cost reductions and $12 million in refinery yield improvements. Through a focused effort across the corporation, we have made progress in reducing the costs that we control, but a number of factors discussed below have offset the reductions we have made. We continued programs to consolidate our marketing organization, reduce travel costs and reduce contract labor in both operations and administration. We completed a workforce reduction program in the first quarter which included a voluntary early retirement offer and various position eliminations. During the first six months of 2003, we expensed $9 million for voluntary early retirement benefits and severance costs, and we estimate that the results of the workforce reduction program will yield annual savings of approximately $20 million. Our total operating and overhead costs, however, have shown little improvement during the first six months of 2003, primarily due to increases in natural gas and utility costs and accruals for incentive compensation, voluntary early retirement and severance expenses. These cost increases have largely offset reductions in our controllable costs. For the remainder of 2003, we will continue our efforts to reduce costs through economies in refinery maintenance, purchasing and other cost savings.

Capital Expenditures and Refinery Turnaround Spending

In another initiative, we have reduced or deferred spending plans for certain discretionary projects while maintaining spending to meet environmental, safety, regulatory and other operational requirements. We currently expect to spend approximately $165 million in 2003, including $45 million for major maintenance turnarounds at our refineries. Capital expenditures and turnaround spending in 2002 totaled $244 million. The reduced capital plan primarily relates to the deferral of discretionary economic projects at our refineries, along with lower spending for Retail. We do not expect to build any new retail stations in 2003, reflecting our current strategy of minimal growth that will focus on jobber investments in selected markets. We expect our aggregate spending level for 2003, relating to environmental, safety, regulatory and turnarounds, to remain comparable to amounts expended during 2002. We spent $62 million in the 2003 first and second quarters, which included $18 million for the CARB III project at the California refinery and $18 million for refinery turnarounds.

Achievement of Synergies

We also are focusing on pursuing new synergies from our refinery system following the acquisition of the California refinery. Our goal is to achieve $25 million of annual system synergies by the end of 2003, and we achieved approximately $18 million in synergies in the 2003 first and second quarters. A portion of these synergies are directly related to our California refinery, but the majority of the improvements have come from our ability to move products among our operating regions to capture higher product values, such as moving gasoline from the Northwest to California and low sulfur fuel oil from Alaska to Hawaii.

New Credit Agreement

As further discussed below under Capital Resources and Liquidity — Overview, we repaid debt by $248 million during the first six months of 2003. At June 30, 2003, we had no borrowings and $251 million in letters of credit outstanding on our revolving line of credit, and our cash balance was $68 million. In April we replaced our previous credit facility with a new $650 million credit agreement, which includes a $400 million sublimit for letters of credit, compared with $150 million under the prior credit facility. We have increased the use of letters of credit to substantially eliminate early payments and prepayments to suppliers, providing working capital flexibility and additional cash for repayments of debt.

RESULTS OF OPERATIONS — THREE MONTHS AND SIX MONTHS ENDED JUNE 30, 2003 COMPARED WITH THREE AND SIX MONTHS ENDED JUNE 30, 2002

Summary

Our net loss was $7.0 million ($0.11 net loss per basic share and diluted share) for the three months ended June 30, 2003 (“2003 Quarter”) compared with a net loss of $17.9 million ($0.28 net loss per basic share and diluted share) for the three months ended June 30, 2002 (“2002 Quarter”). For the year-to-date periods our net earnings were $13.4 million ($0.21 per basic and diluted share) for the six months ended June 30, 2003 (“2003 Period”), compared with a net loss of $73.5 million ($1.30 net loss per basic and diluted share) for the six months ended June 30, 2002 (“2002 Period”). The net loss for the 2003 Quarter included the write-off of unamortized debt issuance costs of $33.3 million pretax. Operating income increased for the 2003 Quarter and 2003 Period primarily from the contribution of our California refinery operations and improved margins in our Refining and Retail segments as discussed below. Voluntary early retirement benefits and severance costs, primarily in the first quarter of 2003, resulted in charges of $9.0 million pretax in the 2003 Period.

A discussion and analysis of the factors contributing to our results of operations are presented below. The accompanying Condensed Consolidated Financial Statements and related Notes, together with the following information, are intended to provide investors with a reasonable basis for assessing our operations, but should not serve as the only criteria for predicting our future performance.

Refining Segment


				Three Months Ended						Six Months Ended
				June 30,						June 30,

(Dollars in millions except per barrel amounts)				2003			2002			2003			2002

Revenues
	Refined products (a)			$	1,951		$	1,556		$	4,034		$	2,632
	Crude oil resales and other				67			97			184			188

		Total Revenues		$	2,018		$	1,653		$	4,218		$	2,820

Refining Throughput (thousand barrels per day) (b)
	California (c)				159			60			158			31
	Pacific Northwest
		Washington			118			117			112			101
		Alaska			46			60			45			55
	Mid-Pacific
		Hawaii			76			89			76			85
	Mid-Continent
		North Dakota			53			52			51			51
		Utah			45			55			39			51

			Total Refining Throughput		497			433			481			374

% Heavy Crude Oil of Total Refinery Throughput (d)					59	%		45	%		60	%		41	%


					Three Months Ended				Six Months Ended
					June 30,				June 30,

					2003		2002		2003		2002

Yield (thousand barrels per day) (c)
	Gasoline and gasoline blendstocks					248		204		239		161
	Jet fuel					56		69		56		66
	Diesel fuel					107		77		102		65
	Heavy oils, residual products, internally produced fuel and other					104		98		103		92

			Total Yield			515		448		500		384

Refining Margin ($/throughput barrel) (e) (f)
	California (c)
			Gross refining margin		$	9.08	$	7.76	$	9.81	$	7.76
			Manufacturing cost before depreciation and amortization		$	4.58	$	4.67	$	4.43	$	4.67
	Pacific Northwest
			Gross refining margin		$	4.93	$	4.67	$	5.53	$	3.72
			Manufacturing cost before depreciation and amortization		$	1.99	$	1.83	$	2.21	$	2.16
	Mid-Pacific
			Gross refining margin		$	2.21	$	2.15	$	2.68	$	2.53
			Manufacturing cost before depreciation and amortization		$	1.42	$	1.34	$	1.41	$	1.38
	Mid-Continent
			Gross refining margin		$	5.29	$	4.68	$	5.03	$	3.55
			Manufacturing cost before depreciation and amortization		$	2.31	$	2.00	$	2.38	$	2.16
	Total
			Gross refining margin		$	5.92	$	4.60	$	6.40	$	3.73
			Manufacturing cost before depreciation and amortization		$	2.80	$	2.17	$	2.85	$	2.18

Segment Operating Income
	Gross refining margin (after inventory changes) (g)				$	267	$	177	$	562	$	257
	Expenses (h)
		Manufacturing costs (f)				127		86		248		148
		Other operating expenses				32		24		59		48
		Selling, general and administrative				7		7		15		16
		Depreciation and amortization (i)				29		23		59		44

				Segment Operating Income	$	72	$	37	$	181	$	1

Product Sales (thousand barrels per day) (a) (j)
	Gasoline and gasoline blendstocks					292		254		281		231
	Jet fuel					79		96		83		92
	Diesel fuel					131		100		128		98
	Heavy oils, residual products and other					77		74		70		67

				Total Product Sales		579		524		562		488

Product Sales Margin ($/barrel) (j)
	Average sales price				$	37.00	$	32.47	$	39.69	$	29.54
	Average costs of sales					32.01		28.78		34.22		26.65

				Product Sales Margin	$	4.99	$	3.69	$	5.47	$	2.89

(a)

Includes intersegment sales to our Retail segment at prices which approximate market of $174 million and $215 million for the three months ended June 30, 2003 and 2002, respectively, and $356 million and $367 million for the six months ended June 30, 2003 and 2002, respectively.

(b) The Washington refinery reduced throughput in the 2002 first quarter during a planned major maintenance turnaround. The Hawaii refinery temporarily reduced throughput in the 2003 first quarter for maintenance to its crude oil distillation unit. The Utah refinery decreased throughput in the 2003 first quarter during a planned major maintenance turnaround. The Alaska refinery reduced throughput in the 2003 second quarter during a planned major maintenance turnaround.

(c) Volumes and margins for 2002 include amounts for the California operations since acquisition on May 17, 2002, averaged over the periods presented. Throughput and yield averaged over the 45 days of operation in 2002 were 122 thousand barrels per day (“Mbpd”) and 130 Mbpd, respectively.

(d) We define “heavy” crude oil as Alaska North Slope or crude oil with an American Petroleum Institute specific gravity of 32 or less. Heavy crude oil throughput increased in 2003 compared to 2002, primarily reflecting the additional throughput from the California refinery since its acquisition on May 17, 2002.

(e) Management uses gross refining margin per barrel to compare profitability to other companies in the industry. Gross refining margin per barrel is calculated by dividing gross refining margin by total refining throughput. Gross refining margin per barrel may not be comparable to similarly titled measures used by other entities.

(f) Management uses manufacturing costs per barrel to evaluate the efficiency of refinery operations. Manufacturing costs per barrel may not be comparable to similarly titled measures used by other entities.

(g) Gross refining margin is calculated as revenues less costs of refining feedstock and blendstock. Gross refining margin approximates total Refining segment throughput times gross refining margin per barrel, adjusted for changes in refined product inventory due to selling a volume and mix of product that is different than actual volumes manufactured. Gross refining margin also includes the effect of intersegment sales to the Retail segment at prices which approximate market.

(h) Includes $2.6 million for voluntary early retirement benefits and severance costs in the first quarter of 2003.

(i) Includes manufacturing depreciation and amortization per throughput barrel of approximately $0.58 and $0.56 for the three months ended June 30, 2003 and 2002, respectively, and $0.60 and $0.56 for the six months ended June 30, 2003 and 2002, respectively.

(j) Sources of total product sales included products manufactured at the refineries and products purchased from third parties. Total product sales margin included margins on sales of manufactured and purchased products and the effects of inventory changes.

Three Months Ended June 30, 2003 Compared with Three Months Ended June 30, 2002. Operating income from our Refining segment was $72 million in the 2003 Quarter compared to $37 million for the 2002 Quarter. Our results for the 2003 Quarter included a complete quarter of operating income from the California refinery acquired in mid-May 2002. Our California operations contributed approximately $44 million to our Refining segment operating income during the 2003 Quarter, compared to approximately $8 million during the 2002 Quarter.

The $35 million increase in our operating income was primarily due to operating the California refinery for a complete quarter and improved refined product margins, compared with the low margins in the 2002 Quarter. In the 2002 Quarter, a portion of the California refinery was temporarily shut down for a major maintenance turnaround. Our total gross refining margin averaged $5.92 per barrel in the 2003 Quarter, a 29% increase compared to $4.60 per barrel in the 2002 Quarter, reflecting California’s margin contribution and slightly higher gross margins in all of our other regions. Gross margin per barrel in our California region increased 17% to $9.08 per barrel. Operating problems during the quarter at some refineries contributed to increased gasoline margins in California. Furthermore, U.S. west coast gasoline supply tightened due to changes in gasoline specifications related to the phase-out of MTBE in California. At the same time, our California refinery produced increased volumes of CARB gasoline following completion of the CARB III project in March 2003. Gasoline and diesel demand remained strong on the U.S. west coast, however, demand and margins for jet fuel decreased on the U.S. west coast and in Hawaii. Although jet fuel demand and margins had improved during the first quarter of 2003, we believe the outbreak of SARS in the Far East during the 2003 Quarter resulted in a significant decrease in jet traffic. Jet fuel demand and margins have begun to recover in the 2003 third quarter, as it appears that fears surrounding the SARS outbreak have subsided.

On an aggregate basis, our total gross refining margins increased from $177 million in the 2002 Quarter to $267 million in the 2003 Quarter, reflecting higher per barrel refining margins in all of our regions and additional throughput volumes from the California refinery, which added an additional 99 thousand barrels per day (“Mbpd”) to our total refinery throughput in the 2003 Quarter compared to the 2002 Quarter. Excluding the California refinery, throughput rates were 338 Mbpd in the 2003 Quarter compared to 373 Mbpd in the 2002 Quarter. Refining throughput at the Alaska refinery declined from the 2002 Quarter, reflecting the effect of the scheduled major maintenance turnaround

during the 2003 Quarter. Refining throughput at the Hawaii and Utah refineries was reduced from the 2002 Quarter in response to lower product margins.

Revenues from sales of refined products increased 25% to $1,951 million in the 2003 Quarter, from $1,556 million in the 2002 Quarter, due to increased sales volumes from the California refinery and higher product sales prices. Total product sales averaged 579 Mbpd in the 2003 Quarter, an increase of 10% from the 2002 Quarter. Our average product prices increased 14% to $37.00 per barrel. Costs of sales also increased, compared with the 2002 Quarter, due to the additional throughput from the California refinery and higher average prices for feedstocks and purchased product supply.

Expenses, excluding depreciation and amortization increased to $166 million in the 2003 Quarter, compared with $117 million in the 2002 Quarter, primarily due to additional operating expenses of approximately $41 million from the California refinery, acquired on May 17, 2002, and increased costs for natural gas supplies and utilities. Depreciation and amortization increased to $29 million primarily due to inclusion of the California refinery for a full quarter in 2003.

Six Months Ended June 30, 2003 Compared with Six Months Ended June 30, 2002. Operating income from our Refining segment was $181 million in the 2003 Period compared to $1 million for the 2002 Period. Our results for the 2003 Period included a complete six months of operating income from the California refinery acquired in mid-May 2002. The California operations contributed approximately $114 million to our Refining segment operating income during the 2003 Period compared to approximately $8 million during the 2002 Period when the operations were owned for only part of the period.

Our total gross refining margin averaged $6.40 per barrel in the 2003 Period compared to $3.73 per barrel in the 2002 Period, reflecting California’s margin contribution and higher gross margins in all of our other regions. Gross margins per barrel in our Pacific Northwest and Mid-Continent regions increased 49% and 42%, respectively. Our Pacific Northwest margins also were improved as compared with 2002 when, during the first quarter, the Washington refinery was in a major maintenance turnaround and its heavy oil conversion project was being completed. Gross margins in our Mid-Pacific region remained depressed. Industry margins on a national basis improved primarily due to increased demand and below average inventory levels for finished products. The cold winter in 2003 increased demand and margins for distillates during the 2003 first quarter. Although jet fuel demand slowly improved and approached pre-September 11, 2001 levels during the first quarter of 2003, we believe the outbreak of SARS in the Far East during the 2003 second quarter resulted in a significant decrease in jet traffic which negatively impacted Hawaii and the U. S. west coast markets. Jet fuel demand and margins have begun to improve in the 2003 third quarter, as it appears that fears surrounding the SARS outbreak have subsided. Higher than normal industry maintenance during the 2003 first quarter reduced overall industry finished product inventory levels. Operating problems during the 2003 second quarter at several California refineries again reduced production, resulting in increased gasoline margins in California. Furthermore, U.S. west coast gasoline supply tightened due to changes in gasoline specifications related to the phase-out of MTBE in California.

On an aggregate basis, our total gross refining margins increased from $257 million in the 2002 Period to $562 million in the 2003 Period, reflecting higher per-barrel refining margins in all of our regions and additional throughput volumes from the California refinery, which added an additional 127 Mbpd to our total refining throughput in the 2003 Period, compared to the 2002 Period.

Revenues from sales of refined products increased 53% to $4,034 million in the 2003 Period, from $2,632 million in the 2002 Period, due to increased sales volumes from the California refinery and significantly higher product sales prices. Total product sales averaged 562 Mbpd in the 2003 Period, an increase of 15% from the 2002 Period. Our average product prices increased 34% to $39.69 per barrel. Costs of sales also increased due to the additional throughput from the California refinery and higher average prices for feedstocks and purchased product supply compared with the 2002 Period.

Expenses, excluding depreciation and amortization, increased to $322 million in the 2003 Period, from $212 million in the 2002 Period, primarily due to additional operating expenses of approximately $101 million from the California refinery and increased costs for natural gas supplies and utilities. Depreciation and amortization increased to $59 million primarily due to inclusion of the California refinery for the full 2003 Period.

Retail Segment


				Three Months Ended						Six Months Ended
				June 30,						June 30,

(Dollars in millions except per gallon amounts)				2003			2002			2003			2002

Revenues
	Fuel			$	206		$	234		$	404		$	402
	Merchandise and other				31			33			57			56

			Total Revenues	$	237		$	267		$	461		$	458

Fuel Sales (millions of gallons)					150			202			294			375
Fuel Margin ($/gallon) (a)				$	0.21		$	0.10		$	0.16		$	0.09
Merchandise Margin (in millions)				$	8		$	8		$	14		$	14
Merchandise Margin (percent of sales)					27	%		26	%		26	%		26	%
Average Number of Stations (during the period)
	Company-operated				229			250			230			234
	Branded jobber/dealer				349			459			354			462

			Total Average Retail Stations		578			709			584			696

Segment Operating Income (Loss)
	Gross Margins
		Fuel (b)		$	32		$	19		$	48		$	35
		Merchandise and other non-fuel margin			9			10			16			17

			Total gross margins		41			29			64			52
	Expenses (c)
		Operating expenses			17			24			35			43
		Selling, general and administrative			9			8			17			19
		Depreciation and amortization			5			4			10			7

			Segment Operating Income (Loss)	$	10		$	(7	)	$	2		$	(17	)

(a)		Management uses fuel margin per gallon calculations to compare profitability to other companies in the industry. Fuel margin per gallon is calculated by dividing fuel gross margin by fuel sales volumes. Fuel margin per gallon may not be comparable to similarly titled measures used by other entities.

(b)		Includes the effect of intersegment purchases from our Refining segment at prices which approximate market.

(c)		Includes $1.3 million for voluntary early retirement benefits and severance costs in the 2003 first quarter.

Three Months Ended June 30, 2003 Compared with Three Months Ended June 30, 2002. Operating income for our Retail segment was $10 million in the 2003 Quarter, compared to an operating loss of $7 million in the 2002 Quarter. Total gross margins increased to $41 million during the 2003 Quarter, reflecting higher fuel margins per gallon, partially offset by lower sales volume. Fuel margin increased to $0.21 per gallon in the 2003 Quarter from $0.10 per gallon in the 2002 Quarter, reflecting improved market conditions. Total gallons sold decreased to 150 million, reflecting the decrease in average station count to 578 in the 2003 Quarter from 709 in the 2002 Quarter. The decrease was primarily due to selling 70 company-operated stations in December 2002 (acquired with the California refinery in mid-May 2002) and the fact that approximately 150 BP/Amoco branded independent jobber/dealer stations (included in the 2001 acquisition of the Mid-Continent refining and retail assets) did not rebrand to the Tesoro® brand.

Revenues on fuel sales decreased to $206 million in the 2003 Quarter, from $234 million in the 2002 Quarter, reflecting lower sales volumes, partly offset by increased sales prices. Costs of sales also decreased in the 2003 Quarter due to lower sales volumes, partly offset by higher prices of purchased fuel. The decrease in operating, selling, general and administrative expenses from $32 million in the 2002 Quarter to $26 million in the 2003 Quarter reflects our initiatives to reorganize and reduce expenses in the Retail segment and the decrease in average station count.

Six Months Ended June 30, 2003 Compared with Six Months Ended June 30, 2002. Operating income for our Retail segment was $2 million in the 2003 Period, compared to an operating loss of $17 million in the 2002 Period. Total gross margins increased to $64 million during the 2003 Period, reflecting higher fuel margins per gallon, partially offset by lower sales volume. Fuel margin increased to $0.16 per gallon in the 2003 Period from $0.09 per gallon in the 2002 Period, reflecting improved market conditions, primarily in the 2003 Quarter. Total gallons sold decreased to 294 million, reflecting the decrease in average station count to 584 in the 2003 Period from 696 in the 2002 Period as discussed above.

Revenues on fuel sales remained consistent at $404 million in the 2003 Period versus $402 million in the 2002 Period, as increased sales prices were largely offset by lower sales volumes. Costs of sales decreased in the 2003 Period due to lower sales volumes, partly offset by higher prices of purchased fuel. The decrease in operating, selling, general and administrative expenses from $62 million in the 2002 Period to $52 million in the 2003 Period reflects our initiatives to reorganize and reduce expenses in the Retail segment and the decrease in average station count. Depreciation increased to $10 million during the 2003 Period reflecting the placement of new assets into service in 2002 and accelerated depreciation for certain assets written-off during the 2003 Period.

Other

In addition to our Refining and Retail segments, we market and distribute petroleum products and provide logistical support services to the marine and offshore exploration and production industries operating in the Gulf of Mexico. Operating income from these operations increased to $2 million during the 2003 Quarter and $3 million during the 2003 Period, reflecting higher sales volumes and margins, and lower operating expenses. This segment is largely dependent on the volume of oil and gas drilling, workover, construction and seismic activity.

Selling, General and Administrative Expenses

Selling, general and administrative expenses decreased by $2 million in the 2003 Quarter and 2003 Period. Lower expenses in the Refining and Retail segments during the 2003 Period referred to above were partially offset by an increase of $4 million in corporate expenses due to the voluntary early retirement benefits and severance costs.

Interest and Financing Costs

Interest and financing costs, net of capitalized interest, increased by $37 million and $54 million during the 2003 Quarter and 2003 Period, respectively. The increases were due primarily to the write-off of $33 million of unamortized debt issuance costs related to our previous credit facility as well as the additional debt we incurred in May 2002 to finance our acquisition of the California refinery. The 2002 Quarter and 2002 Period interest and financing costs included $4 million and $13 million, respectively, related to bridge and other financing fees for the acquisition of the California refinery.

Income Tax Provision (Benefit)

The income tax benefit amounted to $4 million for the 2003 Quarter while the income tax provision amounted to $8 million for the 2003 Period, compared to the income tax benefits of $12 million and $49 million for the 2002 Quarter and 2002 Period. The benefit reflected the pretax loss for the 2003 Quarter while the provision reflected the pretax earnings for the 2003 Period and an estimated combined Federal and state effective income tax rate of 37% for 2003.

CAPITAL RESOURCES AND LIQUIDITY

Overview

We operate in an environment where our liquidity and capital resources are impacted by changes in the price of crude oil and refined petroleum products, availability of trade credit, market uncertainty and a variety of additional factors beyond our control. These risks include, among others, the level of consumer product demand, weather conditions, fluctuations in seasonal demand, governmental regulations, worldwide political conditions and overall market and economic conditions. See “Forward-Looking Statements” on page 28 for further information related to risks and other

factors. Our future capital expenditures, as well as borrowings under our credit agreement and other sources of capital, may be affected by these factors.

Our primary sources of liquidity have been cash flows from operations and borrowing availability under revolving lines of credit. We believe available capital resources will be adequate to meet our capital expenditures, working capital and debt service requirements for existing operations. At the end of the second quarter of 2003, we had no borrowings under our revolving credit facility and $250.5 million in outstanding letters of credit. During the first and second quarters of 2003 we reduced total debt by $248 million of repayments, partly offset by $6 million of debt discount accretion. As further described below, on April 17, 2003, we replaced our previous credit facility, including its related term loans, by entering into a new $650 million credit agreement (with a $400 million sublimit for letters of credit) and issuing $375 million in 8% senior secured notes and $200 million in senior secured term loans.

We are a significant purchaser of crude oil and other feedstocks in our market areas, which enables us to use various purchasing strategies, including open credit terms, early payments, netting agreements, and to a lesser extent, prepayments of invoices. Under our new credit agreement, we have used the increased letters of credit capacity to replace early payments and prepayments on crude and product purchases. We had $250.5 million in letters of credit outstanding at the end of the 2003 second quarter compared to $85.1 million at the end of the 2003 first quarter. As of June 30, 2003, the amounts of early payments and prepayments which totaled $156 million at March 31, 2003 have been substantially eliminated, providing working capital flexibility and additional cash for repayments of debt.

Capitalization

On April 17, 2003, we replaced our $1.275 billion senior secured credit facility with a new credit agreement, senior secured term loans and 8% senior secured notes due 2008 (described below). We expensed $33.3 million of unamortized debt issuance costs during the 2003 Quarter in connection with the extinguishment of the credit facility in April 2003 and the voluntary prepayment of other debt.

Our capital structure at June 30, 2003 was comprised of the following (in millions):


Debt, including current maturities:
	Credit Agreement — Revolving Credit Facility		$	—
	Credit Agreement — Term Loan			125
	Senior Secured Term Loans			200
	8% Senior Secured Notes due 2008			371
	9-5/8% Senior Subordinated Notes due 2012			429
	9-5/8% Senior Subordinated Notes due 2008			211
	9% Senior Subordinated Notes due 2008			298
	Junior subordinated notes			72
	Other debt, primarily capital leases			29

		Total debt		1,735
Common stockholders’ equity				901

		Total Capitalization	$	2,636

At June 30, 2003, our debt to capitalization ratio was 66% compared with 69% at year-end 2002, reflecting scheduled payments and voluntary prepayments of debt, and net earnings of $13 million during the 2003 Period.

Our new credit agreement, senior secured term loans, senior secured notes and the existing senior subordinated notes impose various restrictions and covenants on us that could potentially limit our ability to respond to market conditions, to raise additional debt or equity capital, or to take advantage of business opportunities.

Credit Agreement

On April 17, 2003, we entered into a new $650 million credit agreement consisting of a $500 million revolving credit facility (with a $400 million sublimit for letters of credit) maturing in June 2006 and a $150 million term loan maturing in April 2007. The credit agreement, together with the net proceeds of the $200 million senior secured term loans and

$375 million aggregate principal amount of 8% senior secured notes discussed below, replaced our previous credit facility. In addition, $25 million of the proceeds were used to repurchase existing 9-5/8% senior subordinated notes. In June 2003, we also prepaid $25 million on the $150 million term loan.

The credit agreement provides for borrowings (including letters of credit) up to the lesser of $624.7 million as of June 30, 2003, or the amount of a weekly-adjusted borrowing base with respect to our eligible cash and cash equivalents, receivables and petroleum inventories, as defined in the credit agreement. As of June 30, 2003, we had no borrowings and $250.5 million in letters of credit outstanding under the revolving credit facility, and $124.7 million remained outstanding under the term loan. The borrowing base under the credit agreement as of June 30, 2003 was $624.7 million, resulting in total unused credit availability of $249.5 million.

The credit agreement contains covenants and conditions that, among other things, limit our ability to pay dividends, incur indebtedness, create liens and make investments. We are also required to maintain specified levels of fixed charge coverage and tangible net worth. We satisfied all of the financial covenants under the credit agreement for the quarter ended June 30, 2003. Beginning with the quarter ending March 31, 2004, maintenance of the fixed charge coverage ratio is not required if unused credit availability under the credit agreement exceeds 15% of the eligible borrowing base then in effect. The credit agreement requires us to maintain a collection account for cash receipts which will be used daily to repay any borrowings outstanding on the revolving credit facility. The credit agreement is guaranteed by substantially all of our active subsidiaries and is secured by substantially all of our cash and cash equivalents, petroleum inventories and receivables.

At June 30, 2003, the interest rate on the term loan was 5.5%. Borrowings under the credit agreement bear interest at either a base rate (4.0% at June 30, 2003) or a eurodollar rate (ranging from 1.03% to 1.14% at June 30, 2003), plus an applicable margin. The applicable margins at June 30, 2003 for the revolving credit facility were 1.5% in the case of the base rate and 3.25% in the case of the eurodollar rate. Letters of credit outstanding under the revolving credit facility incur fees at an annual rate equal to the eurodollar rate applicable margin for the revolving credit facility. The applicable margins under the revolving credit facility vary based on credit availability levels. In July 2003, the revolving credit facility eurodollar rate applicable margin was reduced from 3.25% to 2.75% based on the 2003 second quarter credit availability levels. The applicable margins for the term loan were 2.25% in the case of the base rate and 4.0% in the case of the eurodollar rate.

Senior Secured Term Loans

On April 17, 2003, we entered into new $200 million senior secured term loans due April 15, 2008. The senior secured term loans are subject to optional redemption by us beginning April 15, 2004 at premiums of 3% through April 14, 2005, 1% from April 15, 2005 to April 14, 2006, and at par thereafter. In addition, for the first year, we may use proceeds from certain equity issuances to redeem up to 35% of the aggregate principal amount, subject to a prepayment premium equal to the annual interest rate then in effect. The senior secured term loans contain covenants and restrictions which are less restrictive than those in the credit agreement. The senior secured term loans and the 8% senior secured notes described below are secured by substantially all of our Refining property, plant and equipment and are guaranteed by substantially all of our active subsidiaries.

At June 30, 2003, interest rates were 6.53% to 6.64% on the senior secured term loans. Borrowings under the senior secured term loans bear interest at either a base rate (4.0% at June 30, 2003) or a eurodollar rate (ranging from 1.03% to 1.14% at June 30, 2003), plus an applicable margin. The applicable margins at June 30, 2003 for the senior secured term loans were 4.5% in the case of the base rate and 5.5% in the case of the eurodollar rate.

8% Senior Secured Notes Due 2008

On April 17, 2003, we issued $375 million aggregate principal amount of 8% senior secured notes due April 15, 2008 through a private offering. The senior secured notes have a five-year maturity with no sinking fund requirements and are subject to optional redemption by us after three years at a premium of 4% in year four and at par thereafter. In addition, for the first three years, we may redeem up to 35% of the aggregate principal amount at a redemption price of 108% with proceeds from certain equity issuances. The indenture for the senior secured notes contains covenants and restrictions, which are customary for notes of this nature and are similar to the covenants in the indentures for our

existing senior subordinated notes. The senior secured notes and senior secured term loans are secured by substantially all of our Refining property, plant and equipment and guaranteed by substantially all of our active subsidiaries. The senior secured notes were issued at 98.994% of par, resulting in proceeds of $371 million before debt issuance costs. The effective interest rate on the senior secured notes was 8.25%, after giving effect to the discount at the date of issue. On July 29, 2003, we completed an exchange of substantially all of the outstanding senior secured notes for 8% senior secured notes due 2008 that had been registered under the Securities Act of 1933.

Cash Flow Summary

Components of our cash flows are set forth below (in millions):


		Six Months Ended
		June 30,

		2003			2002

Cash Flows From (Used In):
	Operating Activities	$	281		$	(24	)
	Investing Activities		(42	)		(1,042	)
	Financing Activities		(281	)		1,057

Decrease in Cash and Cash Equivalents		$	(42	)	$	(9	)

Net cash from operating activities during the 2003 Period totaled $281 million, compared to $24 million used in operating activities in the 2002 Period. The increase was primarily due to improved earnings, the collection of income tax refunds and reduced working capital requirements. Net cash used in investing activities of $42 million in the 2003 Period was primarily for capital expenditures. Net cash used in financing activities of $281 million in the 2003 Period was primarily for the repayments of debt and financing costs related to the new credit agreement. Gross borrowings and repayments under revolving credit lines amounted to $811 million during the 2003 Period. Working capital totaled $336 million at June 30, 2003 compared to $446 million at year-end 2002.

Historical EBITDA

EBITDA represents earnings before interest and financing costs, interest income, income taxes, and depreciation and amortization. EBITDA is presented herein because we believe it enhances an investor’s understanding of our ability to satisfy principal and interest obligations with respect to our indebtedness and to use cash for other purposes, including capital expenditures. EBITDA is also used for internal analysis and as a component of the fixed charge coverage financial covenant in our new credit agreement. EBITDA should not be considered as an alternative to net earnings (loss), earnings (loss) before income taxes, cash flows from operating activities or any other measure of financial performance presented in accordance with accounting principles generally accepted in the United States (“U.S. GAAP”). EBITDA may not be comparable to similarly titled measures used by other entities. Our EBITDA for the three months and six months ended June 30, 2003 and 2002 were as follows (in millions):


		Three Months Ended						Six Months Ended
		June 30,						June 30,

		2003			2002			2003			2002

Net Earnings (Loss)		$	(7.0	)	$	(17.9	)	$	13.4		$	(73.5	)
Add Income Tax Provision (Benefit)			(4.1	)		(11.9	)		8.0			(49.1	)
Add Interest and Financing Costs			78.6			41.6			125.8			71.9
Less Interest Income			(0.4	)		(2.1	)		(0.6	)		(2.8	)

	Operating Income (Loss)		67.1			9.7			146.6			(53.5	)
Add Depreciation and Amortization			36.7			29.5			73.7			54.7

	EBITDA	$	103.8		$	39.2		$	220.3		$	1.2

Historical EBITDA as presented above is different than EBITDA as defined under our previous credit facility and new credit agreement. The primary differences are non-cash postretirement benefit costs and loss on asset sales and impairment, which are added to net earnings (loss) under the credit agreement EBITDA calculations.

Capital Expenditures and Refinery Turnaround Spending

We revised our 2003 capital spending plans in response to the weaker refining and retail margin environment experienced in 2002. We reduced or deferred spending plans for certain discretionary projects while maintaining spending to meet environmental, safety, regulatory and other operational requirements. We currently expect to spend approximately $165 million in 2003, including $45 million for major maintenance turnarounds at our refineries. Capital expenditures and turnaround spending in 2002 totaled $244 million. The reduced capital plan primarily relates to the deferral of discretionary economic projects at our refineries, along with lower spending for Retail. We do not expect to build any new retail stations in 2003, reflecting our current strategy of minimal growth that will focus on jobber investments in selected markets. We expect our aggregate spending level for 2003, relating to environmental, safety, regulatory and turnarounds, to remain comparable to amounts expended during 2002.

During the 2003 Period, our capital expenditures totaled $44 million, which included approximately $18 million to complete our California refinery project to meet CARB III gasoline production requirements. After the March 2003 completion of the CARB III project, our California refinery has been able to produce up to 100,000 barrels per day of CARB gasoline. However, our initial estimate indicates that the planned phase-out of MTBE in California in November 2003 could result in a decrease of 5,000 barrels per day of our CARB gasoline production. Other capital spending was primarily for various refinery improvements and environmental requirements.

During the remainder of 2003, we expect to spend approximately $76 million in capital expenditures including approximately $36 million for projects at our California refinery. We expect to spend approximately $3 million during the remainder of 2003 for retail projects, including selected expansion of branded jobber/dealer stations and improvements to existing company-owned stations. We expect 2004 capital spending to be $200 million to $225 million, including refinery turnaround and other major maintenance costs.

During the 2003 Period we spent $18 million for refinery turnaround and other major maintenance, including $14 million for scheduled turnarounds at our Utah and Alaska refineries. We expect to spend approximately $27 million during the last two quarters of 2003, primarily for a major turnaround at our North Dakota refinery scheduled to begin in the third quarter.

Environmental

Extensive federal, state and local environmental laws and regulations govern our operations. These laws, which change frequently, regulate the discharge of materials into the environment and may require us to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites, install additional controls, or make other modifications or changes in use for certain emission sources.

Environmental Remediation Liabilities

Soil and groundwater conditions at the California refinery may require substantial expenditures over time. We have revised our estimate of pre-acquisition environmental liabilities including soil and groundwater conditions at the refinery in connection with various projects, including those required pursuant to orders by the California Regional Water Quality Control Board, to approximately $42 million. Management believes that all of such liabilities will be paid, directly or indirectly, by former owners or operators of the refinery (or their successors) under two separate indemnification agreements. Additionally, if remediation liabilities are incurred in excess of the indemnification, we expect to be reimbursed for such excess liabilities under certain environmental insurance policies.

We are currently involved in remedial responses and have incurred cleanup expenditures associated with environmental matters at a number of sites, including certain of our own properties. At June 30, 2003, our accruals for environmental expenses totaled approximately $39 million. Our accruals for environmental expenses include retained liabilities for previously owned or operated properties, refining, pipeline, terminal and marine services operations and retail service stations. Based on currently available information, including the participation of other parties or former owners in remediation actions, we believe these accruals are adequate.

Environmental Capital

EPA regulations pursuant to the Clean Air Act require a reduction in the sulfur content in gasoline beginning January 1, 2004. To meet the revised gasoline standard, we currently estimate we will make capital improvements of approximately $37 million through 2006 and an additional $15 million thereafter. This will permit all of our refineries to produce gasoline meeting the sulfur limits imposed by the EPA.

EPA regulations pursuant to the Clean Air Act also require a reduction in the sulfur content in diesel fuel manufactured for on-road consumption. In general, the new diesel fuel standards will become effective on June 1, 2006. Based on the latest engineering estimates and spending to date, we expect to spend approximately $55 million in capital improvements through 2007. We do not plan to make similar expenditures at our Alaska refinery because limited demand for low sulfur diesel presently does not justify the capital investment. We expect to meet the demand for low sulfur diesel in Alaska from other sources.

We expect to spend approximately $50 million in capital improvements through 2006 to comply with the second phase of the Refinery MACT II regulations promulgated in April 2002. The Refinery MACT II regulations will require new emission controls at certain processing units at several of our refineries. We are currently evaluating a selection of control technologies to assure operations flexibility and compatibility with long-term air emission reduction goals.

The California refinery has made substantial expenditures to meet California’s CARB III gasoline requirements, including the mandatory phase-out of using the oxygenate known as MTBE by the end of 2003. To comply with these requirements, we spent approximately $77 million since May 2002, including $17.7 million in 2003. The CARB III project commenced operations in March 2003.

In connection with the 2002 acquisition of the California refinery, subject to certain conditions, we assumed the seller’s obligations pursuant to its settlement efforts with the EPA concerning the Section 114 refinery enforcement initiative under the Clean Air Act, except for any potential monetary penalties which the seller retains. We believe these obligations will not have a material impact on our financial position.

We will need to expend additional capital at the California refinery for reconfiguring and replacing above-ground storage tank systems and upgrading piping within the refinery. These future costs are currently estimated at $129 million through 2007 and an additional $86 million through 2010. Both of these cost estimates are subject to further review and analysis.

In connection with the 2001 acquisition of the North Dakota and Utah refineries, we assumed the sellers’ obligations and liabilities under a consent decree among the United States, BP Exploration and Oil Co., Amoco Oil Company and Atlantic Richfield Company. BP entered into this consent decree for both the North Dakota and Utah refineries for various alleged violations. As the new owner of these refineries, we are required to address issues, including leak detection and repair, flaring protection and sulfur recovery unit optimization. We currently estimate that we will spend an aggregate of $7 million to comply with this consent decree. In addition, we have agreed to indemnify the sellers for all losses of any kind incurred in connection with the consent decree.

Conditions may develop that require additional expenditures for our various sites, including, but not limited to, our refineries, tank farms, retail gasoline stations (operating and closed locations) and petroleum product terminals, and for compliance with the Clean Air Act and other state, federal and local requirements. We cannot currently determine the amounts of these future expenditures.

New Accounting Standards

SFAS No. 143 — On January 1, 2003, we adopted SFAS No. 143, “Accounting for Asset Retirement Obligations.” which addresses financial accounting and reporting for legal obligations associated with the retirement of long-lived assets. We have identified asset retirement obligations that are within the scope of the standard, including obligations imposed by certain state laws pertaining to closure and/or removal of storage tanks, and contractual removal obligations included in certain lease and right-of-way agreements associated with our retail, pipeline and terminal operations. We have estimated the fair value of our asset retirement obligations, based in part on the terms of the

agreements and the probabilities associated with the eventual sale or other disposition of these assets. We cannot currently make reasonable estimates of the fair values of some retirement obligations, principally those associated with refineries, certain pipeline rights-of-way and certain terminals, because the related assets have indeterminate useful lives which preclude development of assumptions about the potential timing of settlement dates. Such obligations will be recognized in the period in which sufficient information exists to estimate a range of potential settlement dates. The present value of obligations was accrued to the extent that settlement dates could be estimated, primarily for assets on leased sites. The effect of adopting this accounting standard on January 1, 2003, was to increase property, plant and equipment by approximately $0.6 million, net of accumulated amortization and increase non-current other liabilities by approximately $1.7 million. The cumulative effect charge of approximately $1.1 million pretax was included in selling, general and administrative expenses during the three months ended March 31, 2003. Additional depreciation and operating expense also was immaterial during the six months ended June 30, 2003, and similarly, would not have had a material effect on the six months ended June 30, 2002, if the standard had been adopted in 2002.

SFAS No. 149 — 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, and for hedging activities under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” SFAS No. 149, among other things, clarifies the circumstances under which a contract with an initial net investment meets the characteristic of a derivative and amends the definition of an “underlying” to conform it to language used in FIN 45. SFAS No. 149 is effective for contracts entered into or modified after June 30, 2003. We adopted this statement effective July 1, 2003. Implementation of this new standard did not have a material effect on our consolidated financial position or results of operations.

FIN 46 — In January 2003, the FASB issued Interpretation No. 46, “Consolidation of Variable Interest Entities” (“FIN 46”), which requires the consolidation of variable interest entities, as defined. FIN 46 applies immediately to variable interest entities created after January 31, 2003. The consolidation requirements apply to older entities in the first fiscal year or interim period beginning after June 15, 2003. Certain of the disclosure requirements apply in all financial statements issued after January 31, 2003, regardless of when the variable interest entity was established. Implementation of FIN 46 on July 1, 2003 did not result in the consolidation of any variable interest entities.

Proposed Statement of Position — In 2001, the American Institute of Certified Public Accountants issued an Exposure Draft for a proposed Statement of Position, “Accounting for Certain Costs and Activities Related to Property, Plant and Equipment.” The proposed Statement of Position (“SOP”), as originally written, would require major maintenance activities, such as refinery turnarounds, to be expensed as costs are incurred. If this proposed SOP is adopted as originally written, we would be required to write off the unamortized carrying value of deferred major maintenance costs as a cumulative effect of an accounting change, net of tax, and expense future costs as incurred. At June 30, 2003, deferred major maintenance costs totaled $65 million.

FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q includes forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. These statements are included throughout this Form 10-Q and relate to, among other things, projections of refining margins, revenues, earnings, earnings per share, cash flows, capital expenditures, working capital or other financial items, throughput, expectations regarding debt reduction goals, discussions of estimated future revenue enhancements, potential synergies and cost savings. These statements also relate to our business strategy, goals and expectations concerning our market position, future operations, margins, profitability, liquidity and capital resources. We have used the words “anticipate”, “believe”, “could”, “estimate”, “expect”, “intend”, “may”, “plan”, “predict”, “project”, “will” and similar terms and phrases to identify forward-looking statements in this Quarterly Report on Form 10-Q.

Although we believe the assumptions upon which these forward-looking statements are based are reasonable, any of these assumptions could prove to be inaccurate and the forward-looking statements based on these assumptions could be incorrect. Our operations involve risks and uncertainties, many of which are outside our control, and any one of

which, or a combination of which, could materially affect our results of operations and whether the forward-looking statements ultimately prove to be correct.

Actual results and trends in the future may differ materially from those suggested or implied by the forward-looking statements depending on a variety of factors including, but not limited to:

• changes in general economic conditions;

• the timing and extent of changes in commodity prices and underlying demand for our products;

• the availability and costs of crude oil, other refinery feedstocks and refined products;

• changes in our cash flow from operations, liquidity and capital requirements;

• our ability to achieve our debt reduction goal;

• our ability to meet debt covenants;

• adverse changes in the ratings assigned to our trade credit and debt instruments;

• reduced availability of trade credit;

• increased interest rates and the condition of the capital markets;

• direct or indirect effects on our business resulting from actual or threatened terrorist incidents or acts of war;

• political developments in foreign countries;

• changes in our inventory levels and carrying costs;

• seasonal variations in demand for refined products;

• changes in the cost or availability of third-party vessels, pipelines and other means of transporting feedstocks and products;

• changes in fuel and utility costs for our facilities;

• disruptions due to equipment interruption or failure at our or third-party facilities;

• execution of planned capital projects;

• state and federal environmental, economic, safety and other policies and regulations, any changes therein, and any legal or regulatory delays or other factors beyond our control;

• adverse rulings, judgments, or settlements in litigation or other legal or tax matters, including unexpected environmental remediation costs in excess of any reserves;

• actions of customers and competitors;

• weather conditions affecting our operations or the areas in which our products are marketed; and

• earthquakes or other natural disasters affecting operations.

Many of these factors are described in greater detail in our filings with the SEC. All future written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by the previous statements. We undertake no obligation to update any information contained herein or to publicly release the results of any revisions to any forward-looking statements that may be made to reflect events or circumstances that occur, or that we becomes aware of, after the date of this Quarterly Report on Form 10-Q.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Changes in commodity prices and interest rates are our primary sources of market risk. We have a risk management committee responsible for overseeing energy risk management activities.

Commodity Price Risks

Our earnings and cash flows from operations depend on the margin above fixed and variable expenses (including the costs of crude oil and other feedstocks) at which we are able to sell refined products. The prices of crude oil and refined products have fluctuated substantially in recent years. These prices depend on many factors, including the demand for crude oil, gasoline and other refined products, which in turn depend on, among other factors, changes in the economy, the level of foreign and domestic production of crude oil and refined products, worldwide political conditions, the availability of imports of crude oil and refined products, the marketing of alternative and competing fuels and the

impact of government regulations. The prices we receive for refined products are also affected by local factors such as local market conditions and the level of operations of other refineries in our markets.

The prices at which we sell our refined products are influenced by the commodity price of crude oil. Generally, an increase or decrease in the price of crude oil results in a corresponding increase or decrease in the price of gasoline and other refined products. The timing of the relative movement of the prices, however, can impact profit margins which could significantly affect our earnings and cash flows. In addition, the majority of our crude oil supply contracts are short-term in nature with market-responsive pricing provisions. Our financial results can be affected significantly by price level changes during the period between purchasing refinery feedstocks and selling the manufactured refined products from such feedstocks. We also purchase refined products manufactured by others for resale to our customers. Our financial results can be affected significantly by price level changes during the periods between purchasing and selling such products. Assuming all other factors remained constant, a $1.00 per barrel change in average gross refining margins based on our 2003 year to date average throughput of 481 Mbpd would change annualized pretax operating income by approximately $176 million.

We maintain inventories of crude oil, intermediate products and refined products, the values of which are subject to fluctuations in market prices. In our Refining and Retail segments, our inventories of refinery feedstocks and refined products totaled 16.7 million and 17.8 million barrels at June 30, 2003 and December 31, 2002, respectively. The average cost of our refinery feedstocks and refined product as of June 30, 2003 was approximately $24 per barrel. If market prices for refined products decline to a level below the average cost of these inventories, we may be required to write down the carrying value of our inventory.

We periodically enter into derivative type arrangements on a limited basis as part of our programs to acquire refinery feedstocks at reasonable costs and to manage margins on certain refined product sales. We also engage in limited non-hedging activities which are marked to market with changes in the fair value of the derivatives recognized in earnings. During the second quarter of 2003, we entered into futures positions for 125,000 barrels of crude oil and 45,000 barrels of gasoline, and price swap transactions for 25,000 barrels of gasoline. These transactions settled during the second quarter of 2003 resulting in gains during the three months ended June 30, 2003 of less than $0.1 million on the futures positions and a loss of $0.2 million on the price swap transactions. During the second quarter we also settled options to sell May futures contracts in crude oil for a $2.4 million gain, $1.6 million of which was recognized during the second quarter of 2003. At June 30, 2003, we did not have any open derivatives positions that could have a material effect on our results of operations, financial position or cash flows.

Interest Rate Risk

At June 30, 2003, we had $325 million of outstanding floating-rate debt under our credit agreement and senior secured term loans and $1.4 billion of fixed-rate debt. The weighted average interest rate on the floating-rate debt was 6.2% at June 30, 2003. The impact on annual cash flow of a 10% change in the floating-rate for our credit agreement and senior secured term loans (62 basis points) would be approximately $2 million.

The fair market value of our fixed-rate debt at June 30, 2003 was approximately $77 million less than its book value of $1.4 billion, based on transactions and bid quotes for our senior notes.

ITEM 4. CONTROLS AND PROCEDURES

We carried out an evaluation required by the Securities Exchange Act of 1934, as amended (the “Exchange Act”), under the supervision and with the participation of our management, including the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures as of the end of the period covered by this report. Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures are effective in alerting them on a timely basis to material information relating to the Company and required to be included in our periodic filings under the Exchange Act. During the period covered by this report, there have been no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II — OTHER INFORMATION

ITEM 2. CHANGES IN SECURITIES AND USE OF PROCEEDS

On April 17, 2003, the Company entered into a new $650 million credit agreement, issued new $200 million senior secured term loans, and issued $375 million aggregate principal amount of 8% senior secured notes. The credit agreement, among other things, requires the Company to maintain specified levels of fixed charge coverage and tangible net worth. The term loans contain covenants and restrictions which are less restrictive than those in the credit agreement. The indenture for the senior secured notes contains covenants and restrictions which are customary for notes of this nature and are similar to the covenants in the indentures for the Company’s existing senior subordinated notes.

For further information related to restrictions and covenants in the credit agreement, senior secured term loans and senior secured notes, see Note C of Notes to Condensed Consolidated Financial Statements in Part I, Item 1, and “Capital Resources and Liquidity” in Management’s Discussion and Analysis of Financial Condition and Results of Operations in Part I, Item 2, contained herein.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

(a) The 2003 Annual Meeting of Stockholders of the Company was held on May 1, 2003.

(b) The following directors were elected at the 2003 Annual Meeting of Stockholders to hold office until the 2004 Annual Meeting of Stockholders or until their successors are elected and qualified. A tabulation of the number of votes for or withheld with respect to each such director is set forth below:


Name	Votes For		Withheld

Steven H. Grapstein		56,369,328		1,358,712
William J. Johnson		56,382,312		1,345,728
A. Maurice Myers		56,380,892		1,347,148
Donald H. Schmude		56,387,928		1,340,112
Bruce A. Smith		56,046,751		1,681,289
Patrick J. Ward		56,393,032		1,335,008

(c) With respect to extending the expiration date for the grant of awards under the Amended and Restated Executive Long-Term Incentive Plan, there were 35,116,979 votes for; 4,588,808 votes against; 211,707 abstentions; and 17,810,546 broker non-votes.

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

(a) Exhibits


31.1		Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2		Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1		Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2		Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

(b) Reports on Form 8-K

On April 2, 2003, a Current Report on Form 8-K was filed reporting under Item 5, Other Events, that the Company had issued two press releases announcing (i) the completion of the CARB III project at its California refinery and (ii) a private offering of $400 million of senior secured notes (subsequently revised to $375 million on April 7, 2003). The Company also reported under Item 5 additional information regarding the new credit agreement and term loans. In addition, a press release, announcing that the Company expected to report a profit for the quarter ended March 31, 2003, was filed under Item 9, Regulation FD Disclosure. These three press releases were filed as Exhibits under Item 7 of this Form 8-K. An Unaudited Pro Forma Condensed Statement of Operations for the year ended December 31, 2002 was included under Item 7 of this Form 8-K.

On April 24, 2003, a Current Report on Form 8-K was filed reporting under Item 5, Other Events, that the Company had issued a press release announcing that the Company had successfully completed the refinancing of its senior secured credit facility. The press release was filed as an Exhibit under Item 7 of this Form 8-K.

On April 30, 2003, a Current Report on Form 8-K was filed reporting under Item 9, Regulation FD Disclosure, that the Company had issued a press release containing its first quarter 2003 earnings update. The press release was filed as an Exhibit under Item 7 of this Form 8-K.

On July 8, 2003, a Current Report on Form 8-K was filed reporting under Item 9, Regulation FD Disclosure, that the Company had issued a press release updating its debt reduction goal through the 2003 second quarter. The press release was filed as an Exhibit under Item 7 of this Form 8-K.

On July 31, 2003, a Current Report on Form 8-K was filed reporting under Item 12, Results of Operations and Financial Condition, that the Company had issued a press release containing its second quarter 2003 earnings update. The press release was filed as an Exhibit under Item 7 of the Form 8-K.

SIGNATURES

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


		TESORO PETROLEUM CORPORATION
		Registrant

Date: August 12, 2003		/s/ BRUCE A. SMITH

		Bruce A. Smith
		Chairman of the Board of Directors,
		President and Chief Executive Officer
		(Principal Executive Officer)

Date: August 12, 2003		/s/ GREGORY A. WRIGHT

		Gregory A. Wright
		Senior Vice President and Chief Financial Officer
		(Principal Financial Officer)

EXHIBIT INDEX


Exhibit
Number

31.1		Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2		Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1		Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2		Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

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(b)		The Washington refinery reduced throughput in the 2002 first quarter during a planned major maintenance turnaround. The Hawaii refinery temporarily reduced throughput in the 2003 first quarter for maintenance to its crude oil distillation unit. The Utah refinery decreased throughput in the 2003 first quarter during a planned major maintenance turnaround. The Alaska refinery reduced throughput in the 2003 second quarter during a planned major maintenance turnaround.

(c)		Volumes and margins for 2002 include amounts for the California operations since acquisition on May 17, 2002, averaged over the periods presented. Throughput and yield averaged over the 45 days of operation in 2002 were 122 thousand barrels per day (“Mbpd”) and 130 Mbpd, respectively.

(d)		We define “heavy” crude oil as Alaska North Slope or crude oil with an American Petroleum Institute specific gravity of 32 or less. Heavy crude oil throughput increased in 2003 compared to 2002, primarily reflecting the additional throughput from the California refinery since its acquisition on May 17, 2002.

(e)		Management uses gross refining margin per barrel to compare profitability to other companies in the industry. Gross refining margin per barrel is calculated by dividing gross refining margin by total refining throughput. Gross refining margin per barrel may not be comparable to similarly titled measures used by other entities.

(f)		Management uses manufacturing costs per barrel to evaluate the efficiency of refinery operations. Manufacturing costs per barrel may not be comparable to similarly titled measures used by other entities.

(g)		Gross refining margin is calculated as revenues less costs of refining feedstock and blendstock. Gross refining margin approximates total Refining segment throughput times gross refining margin per barrel, adjusted for changes in refined product inventory due to selling a volume and mix of product that is different than actual volumes manufactured. Gross refining margin also includes the effect of intersegment sales to the Retail segment at prices which approximate market.

(h)		Includes $2.6 million for voluntary early retirement benefits and severance costs in the first quarter of 2003.

(i)		Includes manufacturing depreciation and amortization per throughput barrel of approximately $0.58 and $0.56 for the three months ended June 30, 2003 and 2002, respectively, and $0.60 and $0.56 for the six months ended June 30, 2003 and 2002, respectively.

(j)		Sources of total product sales included products manufactured at the refineries and products purchased from third parties. Total product sales margin included margins on sales of manufactured and purchased products and the effects of inventory changes.

	•		changes in general economic conditions;

	•		the timing and extent of changes in commodity prices and underlying demand for our products;

	•		the availability and costs of crude oil, other refinery feedstocks and refined products;

	•		changes in our cash flow from operations, liquidity and capital requirements;

	•		our ability to achieve our debt reduction goal;

	•		our ability to meet debt covenants;

	•		adverse changes in the ratings assigned to our trade credit and debt instruments;

	•		reduced availability of trade credit;

	•		increased interest rates and the condition of the capital markets;

	•		direct or indirect effects on our business resulting from actual or threatened terrorist incidents or acts of war;

	•		political developments in foreign countries;

	•		changes in our inventory levels and carrying costs;

	•		seasonal variations in demand for refined products;

	•		changes in the cost or availability of third-party vessels, pipelines and other means of transporting feedstocks and products;

	•		changes in fuel and utility costs for our facilities;

	•		disruptions due to equipment interruption or failure at our or third-party facilities;

	•		execution of planned capital projects;

	•		state and federal environmental, economic, safety and other policies and regulations, any changes therein, and any legal or regulatory delays or other factors beyond our control;

	•		adverse rulings, judgments, or settlements in litigation or other legal or tax matters, including unexpected environmental remediation costs in excess of any reserves;

	•		actions of customers and competitors;

	•		weather conditions affecting our operations or the areas in which our products are marketed; and

	•		earthquakes or other natural disasters affecting operations.

	(a)		The 2003 Annual Meeting of Stockholders of the Company was held on May 1, 2003.

	(b)		The following directors were elected at the 2003 Annual Meeting of Stockholders to hold office until the 2004 Annual Meeting of Stockholders or until their successors are elected and qualified. A tabulation of the number of votes for or withheld with respect to each such director is set forth below:

	(b)		Reports on Form 8-K

			On April 2, 2003, a Current Report on Form 8-K was filed reporting under Item 5, Other Events, that the Company had issued two press releases announcing (i) the completion of the CARB III project at its California refinery and (ii) a private offering of $400 million of senior secured notes (subsequently revised to $375 million on April 7, 2003). The Company also reported under Item 5 additional information regarding the new credit agreement and term loans. In addition, a press release, announcing that the Company expected to report a profit for the quarter ended March 31, 2003, was filed under Item 9, Regulation FD Disclosure. These three press releases were filed as Exhibits under Item 7 of this Form 8-K. An Unaudited Pro Forma Condensed Statement of Operations for the year ended December 31, 2002 was included under Item 7 of this Form 8-K.

			On April 24, 2003, a Current Report on Form 8-K was filed reporting under Item 5, Other Events, that the Company had issued a press release announcing that the Company had successfully completed the refinancing of its senior secured credit facility. The press release was filed as an Exhibit under Item 7 of this Form 8-K.

			On April 30, 2003, a Current Report on Form 8-K was filed reporting under Item 9, Regulation FD Disclosure, that the Company had issued a press release containing its first quarter 2003 earnings update. The press release was filed as an Exhibit under Item 7 of this Form 8-K.

			On July 8, 2003, a Current Report on Form 8-K was filed reporting under Item 9, Regulation FD Disclosure, that the Company had issued a press release updating its debt reduction goal through the 2003 second quarter. The press release was filed as an Exhibit under Item 7 of this Form 8-K.

			On July 31, 2003, a Current Report on Form 8-K was filed reporting under Item 12, Results of Operations and Financial Condition, that the Company had issued a press release containing its second quarter 2003 earnings update. The press release was filed as an Exhibit under Item 7 of the Form 8-K.