Table of Contents

---

---

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

FORM 10-Q

Commission File Number 1-3473

TESORO PETROLEUM CORPORATION

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 x

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).

Yes x      No x

---

There were 64,619,513 shares of the registrant’s Common Stock outstanding at
November 3, 2003.

---

---

 

---

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 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

---

Table of Contents

TESORO PETROLEUM CORPORATION AND SUBSIDIARIES

QUARTERLY REPORT ON FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2003

TABLE OF CONTENTS

2

---

Table of Contents

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)

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

3

---

Table of Contents

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

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

4

---

Table of Contents

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

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

5

---

Table of Contents

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 the interim periods in 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. The calculations of diluted earnings per share include the effects of potentially dilutive common stock options outstanding. The assumed exercise of common stock options produced anti-dilutive results in 2002, and therefore was not included in the calculations of diluted loss per share. Earnings (loss) per share calculations are presented below (in millions except per share amounts):

6

---

Table of Contents

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

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 and voluntary prepayments of other debt. During the 2003 third quarter, the Company expensed an additional $2.9 million of unamortized debt issuance costs in connection with the voluntary prepayment of the $125 million balance of the term loan, described below under “Credit Agreement.”

Debt and Maturities

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

As of September 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, $3.6 million; 2004-2005, $3.6 million; 2005-2006, $3.5 million; 2006-2007, $50.9 million; and 2007-2008, $820.1 million.

Credit Agreement

On April 17, 2003, the Company entered into a new credit agreement (the “Credit Agreement”), including 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 the Company’s Credit Facility. In addition, $25 million of the proceeds were used to repurchase 9-5/8% senior subordinated notes. The Company subsequently prepaid $25 million of the $150 million term loan in June 2003 and the remaining $125 million balance of the term loan in September 2003.

The Credit Agreement provides for borrowings (including letters of credit) up to the lesser of $500 million as of September 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 September 30, 2003, the Company had no borrowings and $237.3 million in letters of credit outstanding under the revolving credit facility. The borrowing base under the Credit Agreement as of September 30, 2003 was $500 million, resulting in total unused credit availability of $262.7 million, or 52.5% of the borrowing base.

7

---

Table of Contents

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

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. Beginning with the quarter ending March 31, 2004, the Company will not be required to maintain the fixed charge coverage ratio if unused credit availability under the Credit Agreement exceeds 15% of the eligible borrowing base then in effect. 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.

Borrowings under the Credit Agreement bear interest at either a base rate (4.0% at September 30, 2003) or a eurodollar rate (ranging from 1.03% to 1.14% at September 30, 2003), plus an applicable margin. The applicable margins at September 30, 2003 for the revolving credit facility were 1.0% in the case of the base rate and 2.75% 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.

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. The Company may use proceeds from certain equity issuances, through April 14, 2004, 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 Tesoro’s active subsidiaries.

At September 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 September 30, 2003) or a eurodollar rate (ranging from 1.03% to 1.14% at September 30, 2003), plus an applicable margin. The applicable margins at September 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. The Company may redeem up to 35% of the aggregate principal amount at a redemption price of 108% with proceeds from certain equity issuances through April 15, 2006. 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 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 are 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.

8

---

Table of Contents

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

NOTE D — OPERATING SEGMENTS

The Company is an independent refiner and marketer of petroleum products which derives revenues from two major operating segments, Refining and Retail. The Company also has revenues from Marine Services activities. On October 27, 2003, the Company agreed to sell substantially all of the physical assets of Marine Services for approximately $32 million including inventories, which are estimated to be valued at $5 million. Tesoro will retain and subsequently liquidate the remaining net working capital valued at approximately $20 million. The Company recorded a pretax estimated loss of $7.6 million, or $0.07 per share, in September 2003, reflecting the sales value of the Marine Services assets and estimated selling costs. This charge was included in Loss on Asset Sales in the Condensed Statements of Consolidated Operations due to the immateriality of Marine Services operations as compared to the Company’s historical and ongoing Refining and Retail operations.

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. Income taxes, interest and financing costs, 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):

Operating income included charges for voluntary early retirement benefits and severance costs totaling $9.0 million during the nine months ended September 30, 2003, of which $8.8 million was incurred during the first quarter of 2003, including a non-cash pretax charge of $7.0 million related to voluntary early retirement benefits. The $9.0 million charge included $2.6 million in Refining, $1.3 million in Retail, $0.4 million in Marine Services and $4.7 million in Corporate.

9

---

Table of Contents

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

Capital expenditures do not include major maintenance refinery turnaround, catalyst and drydocking costs of $16.3 million and $2.3 million for the three months ended September 30, 2003 and 2002, respectively, and $34.3 million and $39.7 million for the nine months ended September 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):

NOTE E — INVENTORIES

Components of inventories were as follows (in millions):

10

---

Table of Contents

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

NOTE F — STOCK-BASED COMPENSATION

The Company accounts for stock-based compensation using the intrinsic value method prescribed in Accounting Principles Board 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 following table represents the effect on net earnings and earnings 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):

For purposes of the pro forma disclosures above, the estimated fair value of stock-based compensation plans was 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 recorded liabilities. 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.

11

---

Table of Contents

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

Environmental Remediation Liabilities

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 September 30, 2003, the Company’s accruals for environmental expenses totaled approximately $38 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.

Soil and groundwater conditions at the California refinery may require substantial expenditures over time. The Company estimated pre-acquisition environmental liabilities of $42 million, including soil and groundwater conditions at the refinery in connection with various projects and including those required pursuant to orders by the California Regional Water Quality Control Board. The Company believes that all of such pre-acquisition 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.

Environmental Capital

EPA regulations related 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 beyond 2007. This will permit each of the Company’s six refineries to produce gasoline meeting the sulfur limits imposed by the EPA.

EPA regulations related 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 is evaluating the potential impact of the recent EPA proposed rule for the sulfur content of off-road diesel fuel.

The Company expects to spend approximately $50 million in capital improvements through 2006 to comply with 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 the Company’s refineries, including approximately $20 million at the North Dakota refinery and $30 million at the Washington refinery.

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 refineries for various alleged violations. As the 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 $7 million to comply with this consent decree in addition to expenditures for the installation of new emission control equipment at the North Dakota refinery to meet MACT II regulations described above. The Company also has agreed to indemnify the sellers for all losses of any kind incurred in connection with the consent decree.

12

---

Table of Contents

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

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. The Company estimates that it may spend up to $129 million through 2007 and an additional $86 million through 2010. These cost estimates are subject to further review and analysis by the Company.

Conditions may develop that cause increases or decreases in future 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 adoption of this accounting standard on January 1, 2003, did not have a material effect on the Company’s consolidated financial position or results of operations, and similarly would not have had a material effect 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 and for hedging activities under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” SFAS No. 149 is effective for contracts entered into or modified after June 30, 2003. The Company adopted this statement effective July 1, 2003, and implementation of this new standard did not have a material effect on the Company’s consolidated financial position or results of operations.

13

---

Table of Contents

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. The Company’s implementation of FIN 46 did not result in the consolidation of any variable interest entities.

EITF Issue No. 03-11

In August 2003, the FASB ratified the Emerging Issues Task Force (“EITF”) Issue No. 03-11, “Reporting Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, and Not Held for Trading Purposes.” In a related issue in 2002, the EITF reached a consensus that all realized and unrealized gains and losses on derivative instruments within the scope of SFAS No. 133 should be shown net in the statement of operations, whether or not settled physically, if the derivative instruments are held for trading purposes. However, the EITF recognized that there may be other contracts within the scope of SFAS No. 133 that are not held for trading purposes and warrant further consideration as to the appropriate classification of gains and losses. In EITF 03-11, the EITF clarified certain criteria to use in determining whether gains and losses related to non-trading derivative instruments should be shown net in the income statement. The adoption of EITF 03-11 will not have a material effect on the Company’s consolidated results of operations.

Statement of Position

In September 2003, the Accounting Standards Executive Committee of the American Institute of CPAs approved for issuance a Statement of Position (“SOP”), “Capitalization of Certain Costs and Activities Related to Property, Plant and Equipment,” subject to approval and issuance by the FASB. The SOP, upon clearance from the FASB, would require major maintenance activities, such as refinery turnarounds, to be expensed as incurred. The Company would be required to write-off the unamortized carrying value of deferred major maintenance costs as the cumulative effect of an accounting change, net of income tax, and to expense future costs as incurred. The effective date of the SOP is for fiscal years beginning after December 15, 2004. At September 30, 2003, deferred major maintenance costs, which are included in Other Noncurrent Assets — Other in the Condensed Consolidated Balance Sheet, totaled $74 million.

14

---

Table of Contents

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 27 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 nine months of 2003 impacted industry margins, including the conflict in Iraq, operational problems encountered by several refineries in the industry and by certain third-party pipelines, and changes in product specifications. Overall, industry margins during the first nine months of 2003 in our market areas averaged above our five-year average (January 1, 1998 through December 31, 2002). 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.

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. Debt reduction will be our number one financial priority as we continue to focus on ways to improve profitability. In addition, the recently announced sale of our Marine Services assets will complete the process of focusing our business on refining and marketing, while generating additional cash from asset sales and recoupment of working capital.

Debt Reduction Initiatives

In June 2002, we announced our goal to reduce debt by $500 million by the end of 2003. From May 2002 through September 2003, we repaid $498 million of debt, of which $373 million was paid during the first nine months of 2003. While we have substantially met our debt reduction goal, we will continue to pursue further debt reduction.

Cost Reduction and Refinery Yield Improvement

During the first nine months of 2003, we achieved $15 million in operating improvements, however, as previously disclosed, we do not expect to achieve the remaining $50 million from cost reductions by the end of 2003. The cost reductions we have realized, including those in retail and corporate overhead, have been offset by increases in manufacturing costs that are less controllable, including utilities and revenue-based taxes.

15

---

Table of Contents

Capital Expenditures and Refinery Turnaround Spending

In another initiative, 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 $165 million to $170 million in 2003, including major maintenance turnarounds at our refineries. We spent $101 million during the first nine months of 2003, which included $17 million for the CARB III project at the California refinery and $34 million for refinery turnarounds. 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 minimal spending for Retail, while 2002 spending included $60 million for the California refinery CARB III project and $24 million for the completion of the heavy oil project at our Washington refinery. We expect our 2003 total spending, relating to environmental, safety, regulatory and turnarounds, to remain comparable to amounts expended during 2002.

Achievement of Synergies

We also are achieving new synergies from our refinery system following the acquisition of the California refinery. We achieved approximately $20 million of our annual goal of $25 million in synergies during the first nine months of 2003. 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 $373 million during the first nine months of 2003. At September 30, 2003, we had no borrowings and $237 million in letters of credit outstanding on our revolving line of credit. In April we replaced our previous credit facility with a new 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 NINE MONTHS ENDED SEPTEMBER 30, 2003 COMPARED WITH THREE MONTHS AND NINE MONTHS ENDED SEPTEMBER 30, 2002

Summary

Our net earnings were $70.6 million ($1.09 per diluted share) for the three months ended September 30, 2003 (“2003 Quarter”) compared with a net loss of $15.8 million ($0.24 net loss per diluted share) for the three months ended September 30, 2002 (“2002 Quarter”). For the nine months ended September 30, 2003 (“2003 Period”), our net earnings were $84.0 million ($1.30 per diluted share), compared with a net loss of $89.3 million ($1.51 net loss per diluted share) for the nine months ended September 30, 2002 (“2002 Period”). Operating income increased for the 2003 Quarter and 2003 Period primarily from improved product margins and the full-period contribution of our California refinery operations as discussed below. The net earnings for the 2003 Quarter and 2003 Period included the write-off of unamortized debt issuance costs of $2.9 million pretax ($0.03 per share) and $36.2 million pretax ($0.35 per share), respectively. The 2003 Quarter and 2003 Period results also included the estimated loss of $7.6 million pretax ($0.07 per share), on the pending sale of our Marine Services assets. Voluntary early retirement benefits and severance costs, primarily in the first quarter of 2003, resulted in charges of $9.0 million pretax ($0.09 per share) in the 2003 Period. In the 2002 Quarter and 2002 Period, we reported a $5 million pretax benefit ($0.05 per share) from a LIFO inventory liquidation. In the 2002 Period, we also recorded charges of $17 million pretax ($0.18 per share) for financing and integration costs, primarily associated with the acquisition of the California refinery.

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.

16

---

Table of Contents

Refining Segment

17

---

Table of Contents

---

(a)		Includes intersegment sales to our Retail segment at prices which approximate market of $186 million and $247 million for the three months ended September 30, 2003 and 2002, respectively, and $542 million and $614 million for the nine months ended September 30, 2003 and 2002, respectively.
(b)		The North Dakota refinery reduced throughput in the 2003 Quarter during a planned major maintenance turnaround. In the 2003 first quarter, the Hawaii refinery temporarily reduced throughput for maintenance to its crude oil distillation unit, and the Utah refinery decreased throughput during a planned major maintenance turnaround. The Alaska refinery also reduced throughput in the 2003 second quarter during a planned major maintenance turnaround. The Washington refinery reduced throughput in the 2002 first 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 137 days of operation in 2002 were 146 thousand barrels per day (“Mbpd”) and 155 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 and may not be calculated similarly by other companies.
(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 companies.
(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. In addition, during the three months ended September 30, 2002, certain inventory quantities were reduced resulting in the liquidation of applicable LIFO inventory quantities carried at lower costs. This reduction in LIFO inventory resulted in a decrease in cost of sales of approximately $5 million and a decrease in net loss of $3 million for the three months and nine months ended September 30, 2002.

18

---

Table of Contents

(h)		Includes manufacturing depreciation and amortization per throughput barrel of approximately $0.55 and $0.51 for the three months ended September 30, 2003 and 2002, respectively, and $0.58 and $0.54 for the nine months ended September 30, 2003 and 2002, respectively.
(i)		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 September 30, 2003 Compared with Three Months Ended September 30, 2002. Operating income from our Refining segment was $176 million in the 2003 Quarter compared to $33 million for the 2002 Quarter. The $143 million increase in our operating income was primarily due to improved refined product margins, compared with the low margins in the 2002 Quarter. Our total gross refining margin averaged $8.24 per barrel in the 2003 Quarter, an 81% increase compared to $4.56 per barrel in the 2002 Quarter. All of our refining regions experienced higher gross margins in the 2003 Quarter, especially in our California region where gross margins increased to $11.19 per barrel in the 2003 Quarter from $6.38 per barrel in the 2002 Quarter. Industry margins on a national basis improved primarily due to below average inventory levels for finished products resulting from increased demand, operating problems at several refineries in the industry, including the impact of the August 2003 blackout in the Northeast, and lower gasoline imports. A west-bound product pipeline supply disruption to Arizona increased demand from California, which also contributed to increased margins. 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 $216 million in the 2002 Quarter to $377 million in the 2003 Quarter, reflecting higher per barrel refining margins in all of our regions, partially offset by lower total refining throughput. Refining throughput at the North Dakota refinery declined from the 2002 Quarter, reflecting the effect of the scheduled major maintenance turnaround during the 2003 Quarter.

Revenues from sales of refined products increased 9% to $2,149 million in the 2003 Quarter, from $1,980 million in the 2002 Quarter, primarily due to higher product sales prices partially offset by lower product sales volumes. Our average product prices increased 17% to $40.45 per barrel. Total product sales averaged 577 Mbpd in the 2003 Quarter, a decrease of 7% from the 2002 Quarter, reflecting the North Dakota refinery turnaround and reduced sales of purchased products. Cost of sales also increased, compared with the 2002 Quarter, due to higher average prices for feedstocks and purchased product supply.

Expenses, excluding depreciation and amortization, increased to $171 million in the 2003 Quarter, compared with $152 million in the 2002 Quarter, primarily due to increased costs for utilities, revenue-based taxes and performance bonus accruals.

Nine Months Ended September 30, 2003 Compared with Nine Months Ended September 30, 2002. Operating income from our Refining segment was $357 million in the 2003 Period compared to $34 million for the 2002 Period. Our results for the 2003 Period included a complete nine months of operating income from the California refinery acquired in mid-May 2002. The California operations contributed approximately $191 million to our Refining segment operating income during the 2003 Period compared to approximately $26 million during the 2002 Period when the operations were owned for only part of the period.

Our total gross refining margin averaged $7.04 per barrel in the 2003 Period compared to $4.07 per barrel in the 2002 Period, reflecting California’s margin contribution and higher gross margins in all of our other regions, particularly during the 2003 third quarter, as discussed above. Gross margins per barrel in our Pacific Northwest and Mid-Continent regions increased 62% and 52%, 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. While gross margins in our Mid-Pacific region increased 39%, they remained depressed as compared to our other regions. 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. Higher than normal industry maintenance during the 2003 first quarter and operating problems at several refineries in the industry during the second and third quarters of 2003 reduced overall industry finished product inventory levels. Furthermore, U.S. west coast gasoline supply tightened due to changes in gasoline specifications related to the phase-out of MTBE in California.

19

---

Table of Contents

On an aggregate basis, our total gross refining margins increased from $473 million in the 2002 Period to $939 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 86 Mbpd to our total refining throughput in the 2003 Period, compared to the 2002 Period.

Revenues from sales of refined products increased 34% to $6,183 million in the 2003 Period, from $4,612 million in the 2002 Period, due to increased sales volumes from the California refinery and significantly higher product sales prices. Total product sales averaged 567 Mbpd in the 2003 Period, an increase of 6% from the 2002 Period. Our average product prices increased 27% to $39.95 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 $493 million in the 2003 Period, from $365 million in the 2002 Period, primarily due to additional operating expenses of approximately $109 million from the California refinery and increased costs for utilities, revenue-based taxes and performance bonus accruals. Depreciation and amortization increased to $89 million primarily due to inclusion of the California refinery for the full 2003 Period.

Retail Segment

---

(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 calculated similarly by other companies.
(b)		Includes the effect of intersegment purchases from our Refining segment at prices which approximate market.

20

---

Table of Contents

Three Months Ended September 30, 2003 Compared with Three Months Ended September 30, 2002. Operating income for our Retail segment was $7 million in the 2003 Quarter, compared to $4 million in the 2002 Quarter. Total gross margins decreased to $37 million during the 2003 Quarter, reflecting lower fuel sales volumes, partially offset by higher fuel margins per gallon. Fuel margins increased to $0.18 per gallon in the 2003 Quarter from $0.14 per gallon in the 2002 Quarter, reflecting improved market conditions. Total gallons sold decreased to 145 million, reflecting the decrease in average station count to 570 in the 2003 Quarter from 699 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 $213 million in the 2003 Quarter, from $278 million in the 2002 Quarter, reflecting lower sales volumes from fewer stations, 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 $35 million in the 2002 Quarter to $25 million in the 2003 Quarter reflects the decrease in average station count and our other initiatives to reorganize and reduce expenses in the Retail segment.

Nine Months Ended September 30, 2003 Compared with Nine Months Ended September 30, 2002. Operating income for our Retail segment was $9 million in the 2003 Period, compared to an operating loss of $13 million in the 2002 Period. Total gross margins increased to $101 million during the 2003 Period, reflecting higher fuel margins per gallon, partially offset by lower sales volume. Fuel margin increased to $0.17 per gallon in the 2003 Period from $0.11 per gallon in the 2002 Period, reflecting improved market conditions. Total gallons sold decreased to 439 million, reflecting the decrease in average station count to 579 in the 2003 Period from 693 in the 2002 Period as discussed above.

Revenues on fuel sales decreased to $617 million in the 2003 Period from $680 million in the 2002 Period, reflecting lower sales volumes from fewer stations, partly offset by increased sales prices. 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 $97 million in the 2002 Period to $77 million in the 2003 Period reflects the decrease in average station count and our other initiatives to reorganize and reduce expenses in the Retail segment. Depreciation increased to $15 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.

Marine Services

On October 27, 2003, we entered into an agreement to sell substantially all of our Marine Services physical assets for approximately $32 million including inventories, which are estimated to be valued at $5 million. We will retain and subsequently liquidate the remaining net working capital valued at approximately $20 million. This transaction, which is subject to certain closing conditions, is expected to close by December 31, 2003. Proceeds from this sale will be used for general corporate purposes. We recorded an estimated pretax loss on the sale of approximately $8 million in the 2003 Quarter. Marine Services operations have become increasingly immaterial, as compared to our primary Refining and Retail operations. We believe that the sale of Marine Services assets is not significant to the historical or ongoing analysis or comparability of our primary operating results or financial position. Operating income from Marine Services increased to $2 million during the 2003 Quarter and $5 million during the 2003 Period, reflecting higher sales volumes and margins, and lower operating expenses. These operations depend largely on the volume of oil and gas drilling, workover, construction and seismic activity in the Gulf of Mexico. See Note D of Notes to Condensed Consolidated Financial Statements for summarized financial information related to Marine Services.

Selling, General and Administrative Expenses

Selling, general and administrative expenses decreased by $3 million and $5 million in the 2003 Quarter and 2003 Period, respectively, as a result of our cost reduction initiatives.

21

---

Table of Contents

Interest and Financing Costs

Interest and financing cost increased by $3 million and $59 million during the 2003 Quarter and 2003 Period, respectively. The increase during the 2003 Quarter was due to the write-off of $3 million of unamortized debt issuance costs in connection with the voluntary prepayment of the $125 million balance of a term loan. The increase during the 2003 Period was due primarily to the write-off of $36 million of unamortized debt issuance costs related to our previous credit facility and voluntary prepayments of other debt, as well as interest on additional debt that we incurred in May 2002 to finance our acquisition of the California refinery. The 2002 Period interest and financing costs included $13 million related to bridge and other financing fees for the acquisition of the California refinery.

Income Tax Provision (Benefit)

The income tax provision amounted to $43 million and $51 million for the 2003 Quarter and 2003 Period, respectively, compared to the income tax benefits of $8 million and $57 million for the 2002 Quarter and 2002 Period, respectively. The benefits reflected the pretax losses for the 2002 Quarter and 2002 Period while the provisions reflected the pretax earnings for the 2003 Quarter and 2003 Period and an estimated combined Federal and state effective income tax rate of 38% for 2003.

CAPITAL RESOURCES AND LIQUIDITY

Overview

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. At the end of the third quarter of 2003, we had no borrowings under our revolving credit facility and $237 million in outstanding letters of credit. During the first nine months of 2003 we reduced total debt by $373 million of repayments, partly offset by $7 million of debt discount accretion. As further described below, we replaced our previous credit facility in April 2003, including its related term loans, by entering into a new credit agreement, including a $500 million revolving line of credit (with a $400 million sublimit for letters of credit), and issuing $375 million in 8% senior secured notes and $200 million in floating-rate senior secured term loans.

Under our new credit agreement, we have used the increased letter of credit capacity to replace early payments and prepayments on crude and product purchases. We had $237 million in letters of credit outstanding at the end of the 2003 third quarter compared to $85 million at the end of the 2003 first quarter. The amounts of prepayments at September 30, 2003 totaled approximately $30 million, compared to $156 million of prepayments and early payments at March 31, 2003.

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 27 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.

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, as described below. We 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 a term loan. During the 2003 third quarter, we expensed an additional $2.9 million of unamortized debt issue costs and other related expenses in connection with our voluntary prepayment of the $125 million balance of a term loan, described below under “Credit Agreement.”

22

---

Table of Contents

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

At September 30, 2003, our debt to capitalization ratio was 62% compared with 69% at year-end 2002, reflecting scheduled payments and voluntary prepayments of debt of $373 million and net earnings of $84 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 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 9-5/8% senior subordinated notes. We subsequently prepaid $25 million of the $150 million term loan in June 2003 and the remaining $125 million balance of the term loan in September 2003.

The credit agreement provides for borrowings (including letters of credit) up to the lesser of $500 million as of September 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 September 30, 2003, we had no borrowings and $237 million in letters of credit outstanding under the revolving credit facility. The borrowing base under the credit agreement as of September 30, 2003 was $500 million, resulting in total unused credit availability of $263 million, or 52.5% of the borrowing base.

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. Beginning with the quarter ending March 31, 2004, maintenance of the fixed charge coverage ratio will not be required if unused credit availability under the credit agreement exceeds 15% of the eligible borrowing base then in effect. 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.

Borrowings under the credit agreement bear interest at either a base rate (4.0% at September 30, 2003) or a eurodollar rate (ranging from 1.03% to 1.14% at September 30, 2003), plus an applicable margin. The applicable margins at September 30, 2003 for the revolving credit facility were 1.0% in the case of the base rate and 2.75% 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.

23

---

Table of Contents

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 14, 2004 at premiums of 3% through April 14, 2005, 1% from April 15, 2005 to April 14, 2006, and at par thereafter. In addition, through April 15, 2004, 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 September 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 September 30, 2003) or a eurodollar rate (ranging from 1.03% to 1.14% at September 30, 2003), plus an applicable margin. The applicable margins at September 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, through April 15, 2006, 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):

Net cash from operating activities during the 2003 Period totaled $370 million, compared to $30 million from operating activities in the 2002 Period. The increase was primarily due to improved earnings, the collection of income tax refunds and increased deferred income taxes, partially offset by increased inventories. Net cash used in investing activities of $63 million in the 2003 Period was primarily for capital expenditures. Net cash used in financing activities of $407 million in the 2003 Period was primarily for the voluntary debt prepayments under the term loan, repayments of debt, and financing costs related to the new credit agreement. Gross borrowings and repayments under revolving credit lines amounted to $861 million during the 2003 Period. Working capital totaled $357 million at September 30, 2003 compared to $446 million at year-end 2002.

24

---

Table of Contents

Historical EBITDA

EBITDA represents earnings before interest and financing costs, 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 nine months ended September 30, 2003 and 2002 were as follows (in millions):

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, 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 $165 million to $170 million in 2003, including major maintenance turnarounds at our refineries. Capital expenditures and turnaround spending in 2002 totaled $244 million. The reduced capital plan primarily relates to deferral of discretionary economic refinery projects and minimal spending for retail projects, while 2002 spending included $60 million for the California refinery CARB III project and $24 million for the completion of the heavy oil project at our Washington refinery. We expect our 2003 total spending, relating to environmental, safety, regulatory and turnarounds, to remain comparable to amounts expended during 2002. We expect 2004 capital spending to be $220 million to $235 million, including refinery turnaround and other major maintenance costs.

During the 2003 Period, our capital expenditures totaled $67 million, which included approximately $17 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, we estimate 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 2003 Period we spent $34 million for refinery turnaround and other major maintenance, including scheduled turnarounds at our Utah, Alaska and North Dakota refineries.

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.

25

---

Table of Contents

Environmental Remediation Liabilities

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 September 30, 2003, our accruals for environmental expenses totaled approximately $38 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.

Soil and groundwater conditions at the California refinery may require substantial expenditures over time. We have estimated pre-acquisition environmental liabilities of $42 million, including soil and groundwater conditions at the refinery in connection with various projects and those required pursuant to orders by the California Regional Water Quality Control Board. Management believes that all of such pre-acquisition 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.

Environmental Capital

EPA regulations related 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 beyond 2007. This will permit each of our six refineries to produce gasoline meeting the sulfur limits imposed by the EPA.

EPA regulations related 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 are evaluating the potential impact of the recent EPA proposed rule for the sulfur content off off-road diesel fuel.

We expect to spend approximately $50 million in capital improvements through 2006 to comply with the Refinery MACT II regulations promulgated in April 2002. The Refinery MACT II regulations will require new emission controls at certain processing units at our refineries, including approximately $20 million at the North Dakota refinery and $30 million at the Washington refinery.

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 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 $7 million to comply with this consent decree in addition to expenditures for the installation of new emission control equipment at the North Dakota refinery to meet MACT II regulations described above. We have also agreed to indemnify the sellers for all losses of any kind incurred in connection with the consent decree.

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. We estimate that we may spend up to $129 million through 2007 and an additional $86 million through 2010. These estimates are subject to further review and analysis.

Conditions may develop that cause increases or decreases in future expenditures for our various sites, including, but not limited to, our refineries, tank farms, retail gasoline stations (operating and closed locations) and petroleum product

26

---

Table of Contents

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.

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;

•

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 become aware of, after the date of this Quarterly Report on Form 10-Q.

27

---

Table of Contents

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 489 Mbpd would change annualized pretax operating income by approximately $179 million.

We maintain inventories of crude oil, intermediate products and refined products, the values of which are subject to fluctuations in market prices. Our inventories of refinery feedstocks and refined products totaled 20.4 million and 17.8 million barrels at September 30, 2003 and December 31, 2002, respectively. The average cost of our refinery feedstocks and refined product as of September 30, 2003 was approximately $24.69 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. Gains and losses on these transactions are included in costs of 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 third quarter of 2003, we settled futures positions for 4.7 million barrels of crude oil, 0.5 million barrels of heating oil, and 0.5 million barrels of gasoline, resulting in gains during the three months ended September 30, 2003 of approximately $5 million. At September 30, 2003, we had open crude oil futures contracts for 2 million barrels, which resulted in an unrealized mark-to-market loss of approximately $1 million.

Interest Rate Risk

At September 30, 2003, we had $200 million of outstanding floating-rate debt under our senior secured term loans and $1.4 billion of fixed-rate debt. The weighted average interest rate on the floating-rate debt was 6.6% at September 30, 2003. The impact on annual cash flow of a 10% change in the floating-rate for our senior secured term loans (66 basis points) would be approximately $1 million.

The fair market value of our fixed-rate debt at September 30, 2003 was approximately $2 million less than its book value of $1.4 billion, based on transactions and bid quotes for our senior notes.

28

---

Table of Contents

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.

29

---

Table of Contents

PART II — OTHER INFORMATION

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

30

---

Table of Contents

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.

31

---

Table of Contents

EXHIBIT INDEX

32