e10vq
Table of Contents



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 March 31, 2003  
       
    OR  
       
[   ]   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   95-0862768
(State or other jurisdiction of
incorporation or organization)
  (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 [   ]


There were 64,614,008 shares of the registrant’s Common Stock outstanding at May 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 6. EXHIBITS AND REPORTS ON FORM 8-K
SIGNATURES
CERTIFICATION PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
EXHIBIT INDEX
EX-99.1 Certification Pursuant to 18 USC Sec 1350
EX-99.2 Certification Pursuant to 18 USC Sec 1350


Table of Contents

TESORO PETROLEUM CORPORATION AND SUBSIDIARIES

QUARTERLY REPORT ON FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2003

TABLE OF CONTENTS

                 
            Page
PART I. FINANCIAL INFORMATION        
  Item 1.  
Financial Statements (Unaudited)
       
       
Condensed Consolidated Balance Sheets — March 31, 2003 and December 31, 2002
    3  
       
Condensed Statements of Consolidated Operations — Three Months Ended March 31, 2003 and 2002
    4  
       
Condensed Statements of Consolidated Cash Flows — Three Months Ended March 31, 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
    14  
  Item 3.  
Quantitative and Qualitative Disclosures About Market Risk
    27  
  Item 4.  
Controls and Procedures
    28  
PART II. OTHER INFORMATION        
  Item 2.  
Changes in Securities and Use of Proceeds
    29  
  Item 6.  
Exhibits and Reports on Form 8-K
    29  
SIGNATURES     30  
EXHIBIT INDEX     33  

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)

                       
          March 31,   December 31,
          2003   2002
         
 
ASSETS
CURRENT ASSETS
               
 
Cash and cash equivalents
  $ 13.6     $ 109.8  
 
Receivables, trade, less allowance for doubtful accounts
    423.4       412.2  
 
Income taxes receivable
    6.1       41.9  
 
Inventories
    472.7       461.5  
 
Prepayments and other
    47.9       28.8  
 
   
     
 
   
Total Current Assets
    963.7       1,054.2  
 
   
     
 
PROPERTY, PLANT AND EQUIPMENT
               
 
Refining
    2,388.3       2,363.1  
 
Retail
    238.0       239.0  
 
Corporate and Other
    111.4       111.0  
 
   
     
 
 
    2,737.7       2,713.1  
 
Less accumulated depreciation and amortization
    (434.2 )     (409.7 )
 
   
     
 
   
Net Property, Plant and Equipment
    2,303.5       2,303.4  
 
   
     
 
OTHER NONCURRENT ASSETS
               
 
Goodwill
    91.1       91.1  
 
Acquired intangibles, net
    148.1       150.6  
 
Other, net
    157.6       159.5  
 
   
     
 
   
Total Other Noncurrent Assets
    396.8       401.2  
 
   
     
 
     
Total Assets
  $ 3,664.0     $ 3,758.8  
 
   
     
 
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
               
 
Accounts payable
  $ 267.4     $ 338.6  
 
Accrued liabilities
    193.3       199.7  
 
Current maturities of debt
    52.5       70.0  
 
   
     
 
   
Total Current Liabilities
    513.2       608.3  
 
   
     
 
DEFERRED INCOME TAXES
    146.7       128.7  
 
   
     
 
OTHER LIABILITIES
    242.6       227.5  
 
   
     
 
DEBT
    1,853.5       1,906.7  
 
   
     
 
COMMITMENTS AND CONTINGENCIES (Note G)
               
STOCKHOLDERS’ EQUITY
               
 
Common stock, par value $0.16-2/3; authorized 100,000,000 shares; 66,379,928 shares issued
    11.0       11.0  
 
Additional paid-in capital
    689.8       689.8  
 
Retained earnings
    225.3       204.9  
 
Treasury stock, 1,771,695 common shares, at cost
    (18.1 )     (18.1 )
 
   
     
 
   
Total Stockholders’ Equity
    908.0       887.6  
 
   
     
 
     
Total Liabilities and Stockholders’ Equity
  $ 3,664.0     $ 3,758.8  
 
   
     
 

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

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

                   
      Three Months Ended
      March 31,
     
      2003   2002
     
 
REVENUES
  $ 2,286.1     $ 1,232.6  
COSTS AND EXPENSES
               
 
Costs of sales and operating expenses
    2,131.1       1,231.9  
 
Selling, general and administrative expenses
    38.3       38.5  
 
Depreciation and amortization
    37.0       25.2  
 
Loss on asset sales
    0.2       0.2  
 
   
     
 
OPERATING INCOME (LOSS)
    79.5       (63.2 )
Interest and financing costs, net of capitalized interest
    (47.2 )     (30.3 )
Interest income
    0.2       0.7  
 
   
     
 
EARNINGS (LOSS) BEFORE INCOME TAXES
    32.5       (92.8 )
Income tax provision (benefit)
    12.1       (37.2 )
 
   
     
 
NET EARNINGS (LOSS)
  $ 20.4     $ (55.6 )
 
   
     
 
NET EARNINGS (LOSS) PER SHARE
               
 
Basic
  $ 0.32     $ (1.15 )
 
Diluted
  $ 0.32     $ (1.15 )
WEIGHTED AVERAGE COMMON SHARES
               
 
Basic
    64.6       48.2  
 
Diluted
    64.7       48.2  

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

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

                         
            Three Months Ended
            March 31,
           
            2003   2002
           
 
CASH FLOWS FROM (USED IN) OPERATING ACTIVITIES
               
 
Net earnings (loss)
  $ 20.4     $ (55.6 )
 
Adjustments to reconcile net earnings (loss) to net cash from (used in) operating activities:
               
   
Depreciation and amortization
    37.0       25.2  
   
Loss on asset sales
    0.2       0.2  
   
Deferred income taxes
    17.9       11.6  
   
Changes in deferred assets and other liabilities
    12.0       (15.1 )
   
Changes in current assets and current liabilities:
               
     
Receivables, trade
    (11.2 )     (1.2 )
     
Income taxes receivable
    35.8       (48.6 )
     
Inventories
    (11.2 )     13.2  
     
Prepayments and other
    (16.1 )     (5.5 )
     
Accounts payable and accrued liabilities
    (77.6 )     27.9  
 
   
     
 
       
Net cash from (used in) operating activities
    7.2       (47.9 )
 
   
     
 
CASH FLOWS FROM (USED IN) INVESTING ACTIVITIES
               
 
Capital expenditures
    (27.7 )     (52.6 )
 
Deposit and restricted funds for acquisition
          (300.0 )
 
Other
    1.3       (0.1 )
 
   
     
 
       
Net cash used in investing activities
    (26.4 )     (352.7 )
 
   
     
 
CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES
               
 
Repayments of debt
    (76.6 )     (7.9 )
 
Net borrowings under revolving credit facilities
          115.0  
 
Proceeds from Common Stock offering, net of issuance costs of $13.7
          244.9  
 
Financing costs and other
    (0.4 )     (3.1 )
 
   
     
 
       
Net cash from (used in) financing activities
    (77.0 )     348.9  
 
   
     
 
DECREASE IN CASH AND CASH EQUIVALENTS
    (96.2 )     (51.7 )
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD
    109.8       51.9  
 
   
     
 
CASH AND CASH EQUIVALENTS, END OF PERIOD
  $ 13.6     $ 0.2  
 
 
   
     
 
SUPPLEMENTAL CASH FLOW DISCLOSURES
               
 
Interest paid, net of capitalized interest
  $ 30.8     $ 25.1  
 
Income taxes paid (refunded)
  $ (41.9 )   $  

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

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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 three months ended March 31, 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 the three months ended March 31, 2002, and was not included in the calculation of diluted earnings per share. Earnings (loss) per share calculations are presented below for the three months ended March 31, 2003 and 2002 (in millions except per share amounts):

                     
        2003   2002
       
 
Basic:
               
 
Numerator:
               
   
Net earnings (loss)
  $ 20.4     $ (55.6 )
   
 
   
     
 
 
Denominator:
               
   
Weighted average common shares outstanding
    64.6       48.2  
 
   
     
 
 
Basic Earnings (Loss) Per Share
  $ 0.32     $ (1.15 )
   
 
   
     
 

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

                       
          2003   2002
         
 
Diluted:
               
 
Numerator:
               
   
Net earnings (loss)
  $ 20.4     $ (55.6 )
   
 
   
     
 
 
Denominator:
               
   
Weighted average common shares outstanding
    64.6       48.2  
   
Add potentially dilutive securities — incremental dilutive shares from assumed exercise of stock options (anti-dilutive in 2002)
    0.1        
 
   
     
 
     
Total diluted shares
    64.7       48.2  
 
   
     
 
 
Diluted Earnings (Loss) Per Share
  $ 0.32     $ (1.15 )
   
 
   
     
 

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).

Credit Facility

As of March 31, 2003, the Company’s Credit Facility consisted of a five-year $225 million revolving credit facility (with a $150 million sublimit for letters of credit), a five-year tranche A term loan and a six-year tranche B term loan. As of March 31, 2003, the Company had no borrowings and $85.1 million in letters of credit outstanding under the revolving credit facility, resulting in total unused credit available of $139.9 million. Interest rates were 6.34% on the tranche A term loan and 8.5% on the tranche B term loan at March 31, 2003. The Company repaid $76.3 million on the term loans during the quarter ended March 31, 2003, which consisted of a $16.3 million prepayment in January 2003 from the proceeds of asset sales and a $60.0 million payment in March 2003, of which $13.0 million was a scheduled payment and $47.0 million was a voluntary prepayment. The Credit Facility required the Company to meet certain financial covenants, all of which were satisfied for the quarter ended March 31, 2003. In connection with the extinguishment of the Credit Facility in April 2003, the Company will expense $33 million of unamortized debt issuance costs during the 2003 second quarter.

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 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.

The Credit Agreement provides for borrowings (including letters of credit) up to the lesser of $650 million 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 April 30, 2003, the borrowing base under the Credit Agreement was $595 million of which $226 million was borrowed, including the $150 million term loan, and $198 million in letters of credit were outstanding.

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 fixed charge coverage ratio is waived if available borrowings under the Credit Agreement exceed 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 to repay borrowings outstanding on the revolving credit facility daily. 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 accounts receivable.

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

Borrowings under the Credit Agreement bear interest at either a base rate (4.25 % at April 30, 2003) or a eurodollar rate (1.32% at April 30, 2003), plus an applicable margin. The applicable margins at April 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. The applicable margins under the revolving credit facility vary based on borrowing 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 (“Term Loans”). The Term Loans are subject to optional redemption by the Company after one year at declining premiums of 3% in year two, 1% in year three 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.

Borrowings under the Term Loans bear interest at either a base rate (4.25 % at April 30, 2003) or a eurodollar rate (1.32 % at April 30, 2003), plus an applicable margin. The applicable margins at April 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 (“2008 Notes”) through a private offering eligible for Rule 144A. 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 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. The effective interest rate on the 2008 Notes is 8.25%, after giving effect to the discount at the date of issue.

Debt Maturities

As of March 31, 2003, the aggregate scheduled maturities of debt for each of the five following 12-month periods were as follows: 2003-2004, $52.5 million; 2004-2005, $49.7 million; 2005-2006, $52.2 million; 2006-2007, $208.0 million; and 2007-2008, $489.3 million. Giving effect to the new financing on April 17, 2003, described above, our maturities for each of the five 12-month periods following March 31, 2003, would be as follows: 2003-2004, $7.4 million; 2004-2005, $5.0 million; 2005-2006, $5.0 million; 2006-2007, $4.5 million; and 2007-2008, $290.1 million. The above maturities exclude repayments of borrowings under our new revolving credit facility.

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.

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

Operating income includes charges for voluntary early retirement benefits and severance costs totaling $8.8 million in the 2003 first quarter, including a non-cash pretax charge of $7.0 million. The $8.8 million charge includes $2.6 million in Refining, $1.2 million in Retail, $0.4 million in Other and $4.6 million in Corporate. The Company offered voluntary early retirement benefits to 91 qualified employees, 50 of whom accepted. 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
          March 31,
         
          2003   2002
         
 
Revenues
               
 
Refining:
               
   
Refined products
  $ 2,083.3     $ 1,075.5  
   
Crude oil resales and other
    117.1       91.4  
 
Retail:
               
   
Fuel
    198.1       167.9  
   
Merchandise and other
    26.1       22.9  
 
Other
    43.2       26.5  
 
Intersegment Sales from Refining to Retail
    (181.7 )     (151.6 )
 
   
     
 
     
Total Revenues
  $ 2,286.1     $ 1,232.6  
   
 
   
     
 
Segment Operating Income (Loss)
               
 
Refining
  $ 109.2     $ (35.8 )
 
Retail
    (8.1 )     (9.6 )
 
Other
    1.1       0.5  
 
   
     
 
   
Total Segment Operating Income (Loss)
    102.2       (44.9 )
 
Corporate and Unallocated Costs
    (22.5 )     (18.1 )
 
Loss on Asset Sales
    (0.2 )     (0.2 )
 
   
     
 
   
Operating Income (Loss)
    79.5       (63.2 )
 
Interest and Financing Costs, Net of Capitalized Interest
    (47.2 )     (30.3 )
 
Interest Income
    0.2       0.7  
 
   
     
 
   
Earnings (Loss) Before Income Taxes
  $ 32.5     $ (92.8 )
   
 
   
     
 
Depreciation and Amortization
               
 
Refining
  $ 29.8     $ 20.4  
 
Retail
    5.0       3.4  
 
Other
    0.7       0.7  
 
Corporate
    1.5       0.7  
 
   
     
 
     
Total Depreciation and Amortization
  $ 37.0     $ 25.2  
   
 
   
     
 
Capital Expenditures
               
 
Refining
  $ 27.0     $ 36.3  
 
Retail
    0.2       10.1  
 
Other
    0.3       1.2  
 
Corporate
    0.2       5.0  
 
   
     
 
     
Total Capital Expenditures
  $ 27.7     $ 52.6  
   
 
   
     
 

Capital expenditures do not include major maintenance refinery turnaround, catalyst and drydocking costs of $8.5 million and $19.7 million for the three months ended March 31, 2003 and 2002, respectively.

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

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):

                     
        March 31,   December 31,
        2003   2002
       
 
Identifiable Assets
               
 
Refining
  $ 3,151.9     $ 3,118.1  
 
Retail
    292.4       287.8  
 
Other
    65.0       68.4  
 
Corporate
    154.7       284.5  
 
   
     
 
   
Total Assets
  $ 3,664.0     $ 3,758.8  
 
 
   
     
 

NOTE E – INVENTORIES

Components of inventories were as follows (in millions):

                   
      March 31,   December 31,
      2003   2002
     
 
Crude oil and refined products, at LIFO
  $ 416.9     $ 402.6  
Other fuel, oxygenates and by-products, at FIFO
    7.7       11.2  
Merchandise and other
    9.6       9.3  
Materials and supplies
    38.5       38.4  
 
   
     
 
 
Total Inventories
  $ 472.7     $ 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 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):

                   
      Three Months Ended
      March 31,
     
      2003   2002
     
 
Reported net earnings (loss)
  $ 20.4     $ (55.6 )
Deduct total stock-based employee compensation expense determined under fair value based methods for all awards, net of related tax effects
    (0.5 )     (0.6 )
 
   
     
 
Pro forma net earnings (loss)
  $ 19.9     $ (56.2 )
 
   
     
 
Net earnings (loss) per share:
               
 
Basic and diluted, as reported
  $ 0.32     $ (1.15 )
 
Basic and diluted, pro forma
  $ 0.31     $ (1.17 )

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.

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

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

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.

Soil and groundwater conditions at the California refinery may require substantial expenditures over time. The Company’s current estimate of costs to address 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, is approximately $73 million. The Company believes that approximately $63 million of such costs 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 expenses are incurred in excess of the indemnification, the Company expects to receive coverage under certain environmental insurance policies.

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 March 31, 2003, the Company’s accruals for environmental expenses totaled approximately $40 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

In February 2000, the EPA finalized new regulations pursuant to the Clean Air Act requiring reduction in the sulfur content in gasoline beginning January 1, 2004. To meet this 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 limits imposed by the EPA.

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

The EPA also promulgated new regulations in January 2001 pursuant to the Clean Air Act requiring 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, 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 this demand from other sources.

The Company expects to spend approximately $50 million in additional 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 $75 million since May 2002, including $15.4 million in the first quarter of 2003. The CARB III project was substantially completed and commenced operations in March 2003.

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., 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, 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.

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 Environmental Protection Agency 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.

Based on latest estimates, 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. Those costs are currently estimated at approximately $130 million through 2007 and an additional estimated $90 million through 2011. Both of these estimates are subject to further review and analysis by the Company.

Conditions that require additional expenditures may transpire 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.

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

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 is included in operating income due to immateriality. Additional depreciation and operating expense was less than $0.1 million for the three months ended March 31, 2003, and similarly, would not have had a material effect on the three months ended March 31, 2002, if the standard had been adopted in 2002.

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 and to expense future costs as incurred. At March 31, 2003, deferred major maintenance costs, which are included in other noncurrent assets – other in the Condensed Consolidated Balance Sheet, totaled $63.6 million.

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. The Company believes that FIN 46 will not result in the consolidation of any material variable interest entities.

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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 26 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 variation, 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.

During the first quarter of 2003, uncertainties related to the conflict in Iraq resulted in significant fluctuations in crude oil prices and refined product margins. Industry margins were negatively affected in January but recovered later in the quarter. Industry margins in the first quarter 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. The cold winter in 2003 increased demand and margins for distillates. Jet fuel demand slowly improved and approached pre-September 11, 2001 levels. Gasoline supply tightened due to several factors, including changes in gasoline specifications related to the phase-out of MTBE in California.

To better enable us to withstand a low margin environment similar to that experienced in 2002, our 2003 goals include the reduction of ongoing cash expenses and elimination or deferral of capital expenditures. We also replaced our senior secured credit facility in April 2003 with a new credit agreement, term loans and senior secured notes, which provide increased financing flexibility, lower interest rates and the ability to accelerate debt reduction.

We expect a profitable second quarter of 2003, assuming industry margins continue near the five-year average and we achieve continued progress toward our debt reduction initiatives described below under “Business Strategy.” The second quarter will include a non-cash, pre-tax charge of $33 million for the unamortized debt issue costs related to our previous credit facility.

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 flow 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 March 31, 2003, we have repaid $200 million of term loan debt since May 2002 of which $76 million was repaid in the 2003 first quarter, including a $16 million prepayment in January 2003, a $13 million scheduled payment in

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March 2003 and a $47 million voluntary prepayment in March 2003. We continue to pursue our goal to further reduce debt through positive operating cash flows and cash conservation measures based on the following initiatives: (i) a cost reduction and refinery improvement program, (ii) elimination or deferral of capital expenditures and refinery turnaround spending, (iii) achievement of system-wide synergies from the acquisition of our California refinery, (iv) asset sales and (v) increasing cash available to reduce debt through the reduction of early payments and prepayments by the use of letters of credit under our new credit agreement. Our next goal is to pay down at least an additional $150 million of debt by the end of the 2003 second quarter, assuming that the industry does not experience substantial increases in crude oil prices.

Cost Reduction and Refinery Improvement Program

Our largest initiative is to realize $65 million of operating income improvements in 2003 through cost reductions and refining improvements that do not require significant capital investments. During the 2003 first quarter we continued programs to consolidate our marketing organization, eliminate non-essential travel 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. We estimate that the results of the workforce reduction program will yield annual savings of approximately $20 million. In addition, we made other reductions in manufacturing costs, but they were partially offset by higher utility expenses. Through these programs and other efficiencies, we achieved $15 million in operating improvements during the 2003 first quarter, including $10 million in cost reductions and $5 million in refining improvements. For the remainder of 2003, we expect to further reduce operating expenses by achieving economies in refinery maintenance and purchasing and other cost savings.

Reductions in Capital Expenditures and Refinery Turnaround Spending

Another initiative is to reduce capital expenditures and refinery turnaround spending. We currently expect to spend approximately $164 million in 2003, including approximately $47 million for major turnarounds at three of our refineries and approximately $5 million for retail projects. Capital expenditures in 2002 totaled $191 million for refining projects (including refinery turnaround and other major maintenance projects), $41 million for retail projects and $12 million for corporate and other projects. The reduced capital spending for retail projects reflects our current strategy of flat to modest growth that will focus on jobber investments in selected markets. We do not expect to build any new retail stations in 2003. We spent $36 million in the 2003 first quarter, which included $15 million for the CARB III project at the California refinery and $8 million for refinery turnaround and other major maintenance costs. With the March 2003 completion of the CARB III project, our California refinery can produce up to 93,000 barrels per day of CARB III gasoline.

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 $12 million in synergies in the 2003 first quarter. During the first quarter, we were able to achieve benefits that otherwise would have been unavailable without the California refinery. For example, we were able to increase the value of certain gasoline volumes through movements between refineries.

RESULTS OF OPERATIONS – THREE MONTHS ENDED MARCH 31, 2003 COMPARED WITH THREE MONTHS ENDED MARCH 31, 2002

Summary

Our net earnings were $20.4 million ($0.32 per basic share and diluted share) for the three months ended March 31, 2003 (“2003 Quarter”) compared with a net loss of $55.6 million ($1.15 net loss per basic share and diluted share) for the three months ended March 31, 2002 (“2002 Quarter”). The net earnings for the 2003 Quarter were primarily the result of our California refinery operations and improved margins in our Refining segment as discussed below, partially offset by additional interest and financing costs related to the acquisition of the California operations in May 2002. Voluntary early retirement benefits and severance costs resulted in charges of $8.8 million pretax, or $0.08 per share, in the 2003 Quarter.

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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
          March 31,
         
(Dollars in millions except per barrel amounts)   2003   2002
   
 
Revenues
               
 
Refined products (a)
  $ 2,083     $ 1,076  
 
Crude oil resales and other
    117       91  
 
   
     
 
   
Total Revenues
  $ 2,200     $ 1,167  
 
 
   
     
 
Refining Throughput (thousand barrels per day) (b)
               
 
California
    158        
 
Pacific Northwest
               
   
Washington
    106       85  
   
Alaska
    44       50  
 
Mid-Pacific
               
   
Hawaii
    76       82  
 
Mid-Continent
               
   
North Dakota
    49       50  
   
Utah
    32       47  
 
   
     
 
     
Total Refining Throughput
    465       314  
 
   
     
 
% Heavy Crude Oil of Total Refinery Throughput (c)
    61 %     36 %
 
   
     
 
Yield (thousand barrels per day)
               
 
Gasoline and gasoline blendstocks
    230       118  
 
Jet fuel
    56       62  
 
Diesel fuel
    98       53  
 
Heavy oils, residual products, internally produced fuel and other
    100       86  
 
   
     
 
   
Total Yield
    484       319  
 
   
     
 
Refining Margin ($/throughput barrel) (d) (e)
               
 
California
               
   
Gross refining margin
  $ 10.56     $  
   
Manufacturing cost before depreciation and amortization
  $ 4.27     $  
 
Pacific Northwest
               
   
Gross refining margin
  $ 6.19     $ 2.48  
   
Manufacturing cost before depreciation and amortization
  $ 2.45     $ 2.59  
 
Mid-Pacific
               
   
Gross refining margin
  $ 3.15     $ 2.93  
   
Manufacturing cost before depreciation and amortization
  $ 1.40     $ 1.43  
 
Mid-Continent
               
   
Gross refining margin
  $ 4.71     $ 2.27  
   
Manufacturing cost before depreciation and amortization
  $ 2.47     $ 2.34  
 
Total
               
   
Gross refining margin
  $ 6.92     $ 2.52  
   
Manufacturing cost before depreciation and amortization
  $ 2.90     $ 2.21  

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          Three Months Ended
          March 31,
         
          2003   2002
         
 
Segment Operating Income (Loss)
               
 
Gross refining margin (after inventory changes) (f)
  $ 295     $ 80  
 
Expenses (g)
               
   
Manufacturing costs (e)
    121       62  
   
Other operating expenses
    27       24  
   
Selling, general and administrative
    8       9  
   
Depreciation and amortization (h)
    30       21  
 
   
     
 
     
Segment Operating Income (Loss)
  $ 109     $ (36 )
 
 
   
     
 
Product Sales (thousand barrels per day) (a) (i)
               
 
Gasoline and gasoline blendstocks
    270       208  
 
Jet fuel
    87       88  
 
Diesel fuel
    124       96  
 
Heavy oils, residual products and other
    63       59  
 
   
     
 
     
Total Product Sales
    544       451  
 
   
     
 
Product Sales Margin ($/barrel) (j)
               
 
Average sales price
  $ 42.59     $ 26.15  
 
Average costs of sales
    36.60       24.18  
 
   
     
 
     
Product Sales Margin
  $ 5.99     $ 1.97  
 
 
   
     
 


(a)   Includes intersegment sales to our Retail segment at prices which approximate market of $182 million and $152 million for the three months ended March 31, 2003 and 2002, respectively.
 
(b)   The California refinery was acquired in May 2002. The Washington refinery reduced throughput in the 2002 Quarter during a scheduled major maintenance turnaround. The Hawaii refinery temporarily reduced throughput in the 2003 Quarter for maintenance to its crude oil distillation unit. The Utah refinery decreased throughput in the 2003 Quarter during a planned major maintenance turnaround.
 
(c)   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 the 2003 Quarter, compared with the 2002 Quarter, primarily reflecting operations of the California refinery in 2003.
 
(d)   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.
 
(e)   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.
 
(f)   Our gross refining margin is revenues less cost of refining feedstock. 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.
 
(g)   Includes $2.6 million for voluntary early retirement benefits and severance costs in the 2003 Quarter.
 
(h)   Includes manufacturing depreciation and amortization per throughput barrel of approximately $0.62 for the 2003 Quarter and $0.55 for the 2002 Quarter.
 
(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.

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Three Months Ended March 31, 2003 Compared with Three Months Ended March 31, 2002. Operating income from our Refining segment was $109 million in the 2003 Quarter compared to an operating loss of $36 million for the 2002 Quarter. Our results for the 2003 Quarter included operating income from the California refinery acquired in May 2002. The California operations contributed approximately $70 million to our Refining segment operating income during the 2003 Quarter.

The $145 million increase in our operating income was primarily due to the California refinery operations and improved refined product margins during the latter half of the 2003 Quarter, compared with the low margins in the 2002 Quarter. Our total refinery system gross margin averaged $6.92 per barrel in the 2003 Quarter compared to $2.52 in 2002 Quarter, 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 150% and 107%, respectively. Our Pacific Northwest margins also were improved by an increase in throughput, compared with 2002 when the Washington refinery was in turnaround and its heavy oil conversion project was being completed. 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. Jet fuel demand slowly improved and approached pre-September 11, 2001 levels. Increased distillate demand reduced overall industry inventory levels and gasoline production. In addition, the political instability in Venezuela and higher than normal industry maintenance during the 2003 Quarter reduced overall industry product inventory levels. Furthermore, west coast gasoline supply tightened due to several factors, including changes in gasoline specifications related to the phase-out of MTBE in California.

On an aggregate basis, our total gross refining margins increased from $80 million to $295 million in the 2003 Quarter, reflecting higher per-barrel refining margins in all of our regions and throughput volumes from the California refinery, which added 158 thousand barrels per day (“Mbpd”) to our total refinery system throughput in the 2003 Quarter compared to the 2002 Quarter. Throughput volumes were increased to approximately 483 Mbpd in March 2003 (despite a reduction of approximately 30 Mbpd at our Utah refinery due to a scheduled turnaround) due to the strong refined product margins. Based on the current margin environment, we anticipate throughput at our refineries to be between 510 and 520 Mbpd during the 2003 second quarter, taking into account the 30-day scheduled turnaround at our Alaska refinery which began in late April.

Revenues from sales of refined products increased 94% to $2,083 million in the 2003 Quarter, from $1,076 million in the 2002 Quarter, due to increased sales volumes from the California refinery and significantly higher product sales prices. Total product sales averaged 544 Mbpd in the 2003 Quarter, an increase of 21% from the 2002 Quarter. Our average product prices increased 63% to $42.59 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 Quarter.

Expenses, excluding depreciation, increased to $156 million in the 2003 Quarter, primarily due to additional operating expenses of approximately $61 million from the California refinery. Depreciation and amortization increased to $30 million primarily due to depreciation and amortization from the California refinery.

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Retail Segment

                       
          Three Months Ended
          March 31,
         
(Dollars in millions except per gallon amounts)   2003   2002
   
 
Revenues
               
 
Fuel
  $ 198     $ 168  
 
Merchandise and other
    26       23  
 
   
     
 
     
Total Revenues
  $ 224     $ 191  
 
 
   
     
 
Fuel Sales (millions of gallons)
    144       173  
Fuel Margin ($/gallon) (a)
  $ 0.11     $ 0.09  
Merchandise Margin (in millions)
  $ 6     $ 6  
Merchandise Margin (percent of sales)
    25 %     26 %
Average Number of Stations (during the period)
               
 
Company-operated
    231       215  
 
Branded jobber/dealer
    360       464  
 
   
     
 
     
Total Average Retail Stations
    591       679  
 
   
     
 
Segment Operating Loss
               
 
Gross Margins
               
   
Fuel (b)
  $ 16     $ 16  
   
Merchandise and other non-fuel margin
    7       7  
 
   
     
 
     
Total gross margins
    23       23  
 
Expenses (c)
               
   
Operating expenses
    18       19  
   
Selling, general and administrative
    8       11  
   
Depreciation and amortization
    5       3  
 
   
     
 
     
Segment Operating Loss
  $ (8 )   $ (10 )
 
 
   
     
 


(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 $1.2 million for voluntary early retirement benefits and severance costs in the 2003 Quarter.

Three Months Ended March 31, 2003 Compared with Three Months Ended March 31, 2002. Operating loss for our Retail segment was $8 million in the 2003 Quarter, compared to an operating loss of almost $10 million in the 2002 Quarter. Total gross margins remained flat at $23 million during the 2003 Quarter, reflecting higher fuel margins per gallon, offset by lower sales volume. Fuel margin increased to $0.11 per gallon in the 2003 Quarter from $0.09 per gallon in the 2002 Quarter, reflecting slightly improved market conditions. Total gallons sold decreased to 144 million, reflecting the decrease in average station count to 591 in the 2003 Quarter from 679 in the 2002 Quarter. The decrease was primarily due to approximately 150 BP/Amoco branded independent jobber/dealer stations (included in the 2001 acquisition of the Mid-Continent refining and retail assets) that did not rebrand to the Tesoro® brand name. As a result of the decision not to rebrand, we are no longer the exclusive supplier for those jobber/dealer stations.

Revenues on fuel sales increased to $198 million in the 2003 Quarter, from $168 million in the 2002 Quarter, reflecting increased sales prices, partly offset by lower sales volumes. Costs of sales also increased in the 2003 Quarter due to the higher prices of purchased fuel. The decrease in operating, selling, general and administrative expenses from $30 million to $26 million reflects our initiatives to reorganize and reduce expenses in the Retail segment. Depreciation increased to $5 million during the 2003 Quarter reflecting the increase in our company- operated stations from the 2002 Quarter.

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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 $1 million during the 2003 Quarter, reflecting higher sales volumes. 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 of $38 million in the 2003 Quarter were comparable to the 2002 Quarter. Lower expenses in the Refining and Retail segments referred to above were offset by an increase of $4 million in corporate expenses due to the voluntary early retirement benefits and severance costs and a $1 million cumulative effect charge to record asset retirement obligations upon adoption of Financial Accounting Standards Board Statement No. 143.

Interest and Financing Costs

Interest and financing costs, net of capitalized interest, were $47 million in the 2003 Quarter compared to $30 million in the 2002 Quarter. The increase was primarily due to the additional debt we incurred in May 2002 to finance our acquisition of the California refinery. The 2002 Quarter interest and financing costs included $9 million related to bridge financing fees for the acquisition of the California refinery.

The new credit agreement entered into in April 2003 and further debt repayments are expected to reduce interest expense during the remainder of 2003, compared with the previous credit facility. However, we will expense $33 million of unamortized debt issue costs related to our previous credit facility in the second quarter of 2003. The debt issue costs of the new credit agreement, senior secured term loans and 8% senior secured notes totaling approximately $34 million will be amortized over their terms, ranging from three to five years.

Income Tax Provision (Benefit)

The income tax provision amounted to $12 million for the 2003 Quarter, compared to the income tax benefit of $37 million for the 2002 Quarter. The provision reflected the pretax earnings for the 2003 Quarter 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 26 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, will be affected by these conditions.

Our primary sources of liquidity have been cash flows from operations, borrowing availability under revolving lines of credit and asset sales. We believe available capital resources will be adequate to meet our capital expenditure, working capital and debt service requirements for existing operations. At the end of the first quarter of 2003, we had no borrowings under our revolving credit facility and $85 million in outstanding letters of credit. During the first quarter of 2003 we repaid $76 million in term debt, of which $47 million was a voluntary prepayment. 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.

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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. The increase in crude oil prices required us to increase the amounts of early payments and prepayments during the 2003 Quarter, which amounted to $156 million at March 31, 2003. Under our new credit agreement, we are using the increased letter of credit capacity to replace early payments and prepayments on crude and product purchases. We are using cash, which had been used for early payments and prepayments, to reduce debt.

Capitalization

Our capital structure at March 31, 2003 was comprised of the following (in millions):

             
Debt, including current maturities:
       
 
Senior Secured Credit Facility – Tranche A Term Loan
  $ 165  
 
Senior Secured Credit Facility – Tranche B Term Loan
    677  
 
Senior Secured Credit Facility – Revolver
     
 
9-5/8% Senior Subordinated Notes due 2012
    450  
 
9-5/8% Senior Subordinated Notes due 2008
    215  
 
9% Senior Subordinated Notes due 2008
    298  
 
Junior subordinated notes
    69  
 
Other debt, primarily capital leases
    32  
 
   
 
   
Total debt
    1,906  
Common stockholders’ equity
    908  
 
   
 
   
Total Capitalization
  $ 2,814  
 
 
   
 

At March 31, 2003, our debt to capitalization ratio was 68% compared with 69% at year-end 2002, reflecting the repayment of term loans totaling $76 million and net earnings of $20 million during the 2003 first quarter.

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 Facility

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). As of March 31, 2003, our credit facility consisted of a five-year $225 million revolving credit facility (with a $150 million sublimit for letters of credit), a five-year tranche A term loan and a six-year tranche B term loan. As of March 31, 2003, we had no borrowings and $85 million in letters of credit outstanding under our previous revolving credit facility, resulting in total unused credit available of $140 million. Interest rates were 6.34% on the tranche A term loan and 8.5% on the tranche B term loan at March 31, 2003. The credit facility required us to meet certain financial covenants, all of which were satisfied for the quarter ended March 31, 2003.

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.

The credit agreement provides for borrowings (including letters of credit) up to the lesser of $650 million 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 April 30, 2003, the borrowing base under the credit agreement was $595 million of which $226 million was borrowed, including the $150 million term loan, and $198 million in letters of credit were outstanding.

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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, the fixed charge coverage ratio is waived if the amount available to be borrowed 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 to repay borrowings outstanding on the revolving credit facility daily. 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 accounts receivable.

Borrowings under the credit agreement bear interest at either a base rate (4.25% at April 30, 2003) or a eurodollar rate (1.32 % at April 30, 2003), plus an applicable margin. The applicable margins at April 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. The applicable margins under the revolving credit facility vary based on borrowing 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 after one year at declining premiums of 3% in year two, 1% in year three 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.

Borrowings under the senior secured term loans bear interest at either a base rate (4.25 % at April 30, 2003) or a eurodollar rate (1.32 % at April 30, 2003), plus an applicable margin. The applicable margins at April 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 eligible for Rule 144A. 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. The effective interest rate on the senior secured notes is 8.25%, after giving effect to the discount at the date of issue.

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Cash Flow Summary

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

                   
      Three Months Ended
      March 31,
     
      2003   2002
     
 
Cash Flows From (Used In):
               
 
Operating Activities
  $ 7     $ (48 )
 
Investing Activities
    (26 )     (353 )
 
Financing Activities
    (77 )     349  
 
   
     
 
Decrease in Cash and Cash Equivalents
  $ (96 )   $ (52 )
 
 
   
     
 

Net cash from operating activities during the 2003 Quarter totaled $7 million, compared to $48 million used in operating activities in the 2002 Quarter. The increase was primarily due to our earnings before depreciation and amortization, largely offset by a decrease in accounts payable for early payments and prepayments to suppliers. Net cash used in investing activities of $26 million in the 2003 Quarter was primarily for capital expenditures, net of proceeds from asset sales. Net cash used in financing activities of $77 million in the 2003 Quarter was primarily for the repayments of debt. Gross borrowings and repayments under revolving credit lines amounted to $288 million during the 2003 Quarter. Working capital totaled $451 million at March 31, 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 ended March 31, 2003 and 2002 were as follows (in millions):

                   
      2003   2002
     
 
Net Earnings (Loss)
  $ 20.4     $ (55.6 )
Add Income Tax Provision (Benefit)
    12.1       (37.2 )
Add Interest and Financing Costs
    47.2       30.3  
Less Interest Income
    (0.2 )     (0.7 )
 
   
     
 
 
Operating Income (Loss)
    79.5       (63.2 )
Add Depreciation and Amortization
    37.0       25.2  
 
   
     
 
 
EBITDA
  $ 116.5     $ (38.0 )
 
   
     
 

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

We revised our 2003 capital spending plans in response to the weaker refining and retail margin environment experienced in 2002. We deferred our spending plans for certain discretionary projects while maintaining spending to meet environmental, safety, regulatory and other operational requirements. We currently estimate that our capital expenditures will total approximately $117 million in 2003 (excluding refinery turnaround and other major maintenance costs of approximately $47 million), primarily for Refining segment projects. We have adopted a flat

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to modest growth strategy for the Retail segment that will focus on jobber investments in selected markets. Therefore, we do not expect to build any new retail stations in 2003.

During the 2003 Quarter, our capital expenditures totaled $28 million, which included approximately $15 million for our California refinery project to meet CARB III gasoline production requirements. Other capital spending was primarily for various refinery improvements and environmental requirements.

During the remainder of 2003, we expect to spend approximately $89 million in capital expenditures including approximately $37 million for projects at our California refinery. We expect to spend approximately $5 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 approximate $240 million to $250 million, including refinery turnaround and other major maintenance costs.

Refinery Turnaround and Other Major Maintenance

During the 2003 Quarter we spent $8 million for refinery turnaround and other major maintenance, including $6 million for our scheduled turnaround of certain processing units at our Utah refinery. We expect to spend approximately $39 million, primarily for major turnarounds at our Alaska and North Dakota refineries during the last three quarters of 2003.

Environmental and Other

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. Our current estimate of costs to address 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, is approximately $73 million. Management believes that approximately $63 million of such costs 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 expenses are incurred in excess of the indemnification, we expect to receive coverage 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 March 31, 2003, our accruals for environmental expenses totaled approximately $40 million. Our accruals for environmental expenses include retained liabilities for prior 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

In February 2000, the EPA finalized new regulations pursuant to the Clean Air Act requiring 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 limits imposed by the EPA.

In January 2001, the EPA also promulgated new regulations pursuant to the Clean Air Act requiring 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, we expect to spend approximately $55 million in capital improvements through 2007. We do not plan to make similar expenditures at our Alaska refinery

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because limited demand for low sulfur diesel presently does not justify the capital investment. We expect to meet this demand from other sources.

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 $75 million since May 2002, including $15.4 million in the first quarter of 2003. The CARB III project was substantially completed and commenced operations in March 2003.

We expect to spend approximately $50 million in additional 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.

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.

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 Environmental Protection Agency 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.

Based on latest estimates, 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 costs are currently estimated at approximately $130 million through 2007 and an additional estimated $90 million through 2011. Both of these cost estimates are subject to further review and analysis.

Conditions that require additional expenditures may transpire 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, is included in selling, general and administrative expenses. Additional depreciation and operating expense was less than $0.1 million for the

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three months ended March 31, 2003, and similarly, would not have had a material effect on the three months ended March 31, 2002, if the standard had been adopted in 2002.

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, we would be required to write off the unamortized carrying value of deferred major maintenance costs and expense future costs as incurred. At December 31, 2002, deferred major maintenance costs totaled $64 million.

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. We believe that FIN 46 will not result in the consolidation of any material variable interest entities.

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 our 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;
 
    the 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;

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    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 extent 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 first quarter average throughput of 465 Mbpd would change annualized pretax operating income and cash flows from operations by approximately $167 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 18.2 million and 17.8 million barrels at March 31, 2003 and December 31, 2002, respectively. The average cost of our refinery feedstocks and refined product as of March 31, 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.

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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 first quarter of 2003, we entered into futures positions for 917,000 barrels of crude oil and price swap transactions for 175,000 barrels of gasoline. Both of these transactions settled during the first quarter of 2003 resulting in losses during the three months ended March 31, 2003 of $1.9 million for the futures positions and $1.4 million for the price swap transactions. At March 31, 2003, we held open futures positions for 29,000 barrels of crude oil which expire in the second and third quarters of 2003. Recording the fair value of these positions resulted in a mark-to-market gain of less than $0.1 million during the three months ended March 31, 2003. In addition, at March 31, 2003 we held 1,170,000 open put options to sell May crude oil futures at various strike prices. These options will expire in the second quarter of 2003. The total premium invested to purchase these options was $1.75 million. Recording the fair value of these option positions resulted in a mark-to-market gain of $0.8 million during the three months ended March 31, 2003. We believe that any potential impact from holding these open futures positions and open options to sell futures will not result in a material adverse effect on our results of operations, financial position or cash flows.

Interest Rate Risk

At March 31, 2003, we had $842 million of outstanding floating-rate debt under our senior secured credit facility and $1.064 billion of fixed-rate debt. The weighted average interest rate on the floating-rate debt was 8.1% at March 31, 2003. The impact on annual cash flow of a 10% change in the floating-rate for our senior secured credit facility (81 basis points) would be approximately $7 million.

The fair market value of our fixed-rate debt at March 31, 2003 was approximately $62 million less than its book value of $1 billion, based on transactions and bid quotes for our senior subordinated notes.

ITEM 4. CONTROLS AND PROCEDURES

Within the 90 days prior to the filing date of this report, we carried out an evaluation, 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 pursuant to Rule 13a-14 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). 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 required to be included in our periodic filings under the Exchange Act. Subsequent to the date of this evaluation, there have been no significant changes in our internal controls or in other factors that could significantly affect internal controls, nor were any corrective actions required with regard to significant deficiencies or material weaknesses.

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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, 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 6. EXHIBITS AND REPORTS ON FORM 8-K

  (a)   Exhibits

  99.1   Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
 
  99.2   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 January 6, 2003, a Current Report on Form 8-K was filed under Item 5, Other Events, reporting that the Company had issued press releases announcing that the Company had (i) entered into a second amendment of its senior secured credit facility, (ii) sold 70 retail stations in northern California, (iii) sold its product pipeline system in North Dakota and Minnesota and (iv) completed a sale/lease-back transaction for 30 company-operated retail stations in Alaska, Hawaii, Idaho and Utah. The amendment to the senior secured credit facility and five press releases issued in December 2002 were filed as Exhibits under Item 7 of this Form 8-K. No financial statements were filed with this Current Report.
 
      On April 2, 2003, a Current Report on Form 8-K was filed reporting under Item 5, Other Events, that the Company had issued 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. The three press releases issued in April 2003 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.

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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: May 9, 2003   /s/ BRUCE A. SMITH
   
    Bruce A. Smith
    Chairman of the Board of Directors,
President and Chief Executive Officer
     
Date: May 9, 2003   /s/ GREGORY A. WRIGHT
   
    Gregory A. Wright
    Senior Vice President and Chief Financial Officer
(Principal Financial Officer)

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CERTIFICATION PURSUANT TO
SECTION 302 OF
THE SARBANES-OXLEY ACT OF 2002

I, Bruce A. Smith, certify that:

1.   I have reviewed this quarterly report on Form 10-Q of Tesoro Petroleum Corporation;
 
2.   Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;
 
3.   Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report;
 
4.   The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

  a.   designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;
 
  b.   evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the “Evaluation Date”); and
 
  c.   presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

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

  a.   all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and
 
  b.   any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

6.   The registrant’s other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
     
Date: May 9, 2003   /s/ BRUCE A. SMITH
   
    Bruce A. Smith
    Principal Executive Officer

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CERTIFICATION PURSUANT TO
SECTION 302 OF
THE SARBANES-OXLEY ACT OF 2002

I, Gregory A. Wright, certify that:

1.   I have reviewed this quarterly report on Form 10-Q of Tesoro Petroleum Corporation;
 
2.   Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;
 
3.   Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report;
 
4.   The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

  a.   designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;
 
  b.   evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the “Evaluation Date”); and
 
  c.   presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

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

  a.   All significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and
 
  b.   Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

6.   The registrant’s other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
     
Date: May 9, 2003   /s/ GREGORY A. WRIGHT
   
    Gregory A. Wright
    Principal Financial Officer

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EXHIBIT INDEX

     
Exhibit    
Number    

   
99.1   Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.2   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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