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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
Form 10-K
     
(Mark One)
   
þ
  ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
    For the fiscal year ended December 31, 2004
OR
 
o
  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
    For the transition period from          to
Commission File Number 1-3473
 
TESORO 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
(Address of principal executive offices)
  78216-6999
(Zip Code)
Registrant’s telephone number, including area code:
210-828-8484
Securities registered pursuant to Section 12(b) of the Act:
     
Title of each class   Name of each exchange on which registered
     
Common Stock, $0.162/3 par value
  New York Stock Exchange
Pacific Exchange
Securities registered pursuant to Section 12(g) of the Act:
None
      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 þ          No o
      Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (Section 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.     þ
      Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act).     Yes þ          No o
      At June 30, 2004, the aggregate market value of the voting common stock held by non-affiliates of the registrant was approximately $1,861,784,800 based upon the closing price of its common stock on the New York Stock Exchange Composite tape. At March 1, 2005, there were 66,461,087 shares of the registrant’s common stock outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
      Portions of the registrant’s Proxy Statement pertaining to the 2005 Annual Meeting of Stockholders are incorporated by reference into Part III hereof. The Company intends to file such Proxy Statement no later than 120 days after the end of the fiscal year covered by this Form 10-K.
 


TESORO CORPORATION
ANNUAL REPORT ON FORM 10-K
TABLE OF CONTENTS
             
        Page
         
 PART I
 Items 1. and 2.
   Business and Properties     2  
      Refining     2  
      Retail     8  
      Competition and Other     10  
      Government Regulation and Legislation     11  
      Employees     12  
      Properties     13  
      Executive Officers of the Registrant     13  
      Board of Directors of the Registrant     15  
      Risk Factors     15  
   Legal Proceedings     19  
   Submission of Matters to a Vote of Security Holders     20  
 PART II
   Market for Registrant’s Common Equity and Related Stockholder Matters     20  
   Selected Financial Data     21  
   Management’s Discussion and Analysis of Financial Condition and Results of Operations     24  
      Business Strategy and Overview     24  
      Results of Operations     25  
      Capital Resources and Liquidity     32  
      Accounting Standards     43  
      Forward-Looking Statements     45  
   Quantitative and Qualitative Disclosures about Market Risk     46  
   Financial Statements and Supplementary Data     48  
   Changes in and Disagreements with Accountants on Accounting and Financial Disclosure     84  
   Controls and Procedures     84  
   Other Information     87  
 
 PART III
   Directors and Executive Officers of the Registrant     87  
   Executive Compensation     87  
   Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters     87  
   Certain Relationships and Related Transactions     87  
   Principal Accounting Fees and Services     87  
 
 PART IV
   Exhibits and Financial Statement Schedules     87  
 
  Signatures     94  
 Subsidiaries of the Registrant
 Consent of Deloitte & Touche LLP
 Certification Pursuant to Section 302
 Certification Pursuant to Section 302
 Certification Pursuant to Section 906
 Certification Pursuant to Section 906
      This Annual Report on Form 10-K (including documents incorporated by reference herein) contains statements with respect to our expectations or beliefs as to future events. These types of statements are “forward-looking” and subject to uncertainties. See “Forward-Looking Statements” on page 45.
      When used in this Annual Report on Form 10-K, the terms “Tesoro”, “we”, “our” and “us”, except as otherwise indicated or as the context otherwise indicates, refer to Tesoro Corporation and its subsidiaries.

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PART I
ITEMS 1. AND 2. BUSINESS AND PROPERTIES
      We are an independent refiner and marketer with two major operating segments — (1) refining crude oil and other feedstocks and selling petroleum products in bulk and wholesale markets (“refining”) and (2) selling motor fuels and convenience products in the retail market (“retail”). Through our refining segment, we manufacture products, primarily gasoline and gasoline blendstocks, jet fuel, diesel fuel and heavy fuel oils for sale to a wide variety of commercial customers in the mid-continental and western United States. Our retail segment distributes motor fuels through a network of gas stations, primarily under the Tesoro® and Mirastar® brands. See Notes C, D, E and P in our consolidated financial statements in Item 8 for additional information on our operating segments and properties.
      We were incorporated in Delaware in 1968 under the name Tesoro Petroleum Corporation. On November 8, 2004, our name was changed to Tesoro Corporation. Our principal executive offices are located at 300 Concord Plaza Drive, San Antonio, Texas 78216-6999 and our telephone number is (210) 828-8484. Our website can be found at www.tsocorp.com. We make available free of charge through our Internet website our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. You may receive a copy of our Annual Report on Form 10-K, including the financial statements, free of charge by writing to Tesoro Corporation, Attention: Investor Relations, 300 Concord Plaza Drive, San Antonio, Texas 78216-6999. We submitted to the New York Stock Exchange on June 10, 2004 our annual certification concerning corporate governance pursuant to Section 303A.12(a) of the New York Stock Exchange Listed Company Manual.
REFINING
      We own and operate six petroleum refineries, located in California (“California” region), Alaska and Washington (“Pacific Northwest” region), Hawaii (“Mid-Pacific” region) and North Dakota and Utah (“Mid-Continent” region), and sell refined products to a wide variety of customers in the mid-continental and western United States. Our refineries produce a high proportion of our refined product sales volumes, and we purchase the remainder from other refiners and suppliers. Our six refineries have a combined rated crude oil capacity of 558,000 barrels per day (“bpd”). We operate the largest refineries in Hawaii and Utah, the second largest refineries in northern California and Alaska, and the only refinery in North Dakota. Capacity and throughput rates of crude oil and other feedstocks by refinery are as follows:
                                     
    Rated   Throughput (bpd)
    Crude Oil    
Refinery   Capacity (bpd)   2004   2003   2002
                 
California(a)
                               
 
California
    168,000       152,800       156,400       94,600  
Pacific Northwest
                               
 
Washington
    108,000       117,200       112,300       104,000  
 
Alaska
    72,000       57,200       48,800       53,000  
Mid-Pacific
                               
 
Hawaii
    95,000       84,500       79,700       81,900  
Mid-Continent
                               
 
North Dakota
    60,000       56,200       47,500       51,400  
 
Utah
    55,000       52,500       43,500       50,100  
                         
   
Total Refinery(a)
    558,000       520,400       488,200       435,000  
                         
 
(a) Throughput volumes in 2002 included the California refinery since we acquired it on May 17, 2002, averaged over 365 days. Throughput for the California refinery averaged over the 229 days we owned it in 2002 was 150,800 bpd.

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      Major scheduled refinery maintenance (“turnarounds”) temporarily reduced throughput at our California refinery in 2004, at our Alaska, North Dakota and Utah refineries in 2003 and at our California and Washington refineries in 2002. We also reduced throughput rates at some of our refineries in 2002 and late 2003 in response to regional and seasonal market conditions. Throughput exceeded our Washington refinery’s rated crude oil capacity in 2003 and 2004 due to processing other feedstocks in addition to crude oil.
      Feedstock Supply. We purchase crude oil and other feedstocks for our refineries from a diversified supply of domestic and foreign sources through term agreements with renewal provisions and in the spot market. Prices under the term agreements fluctuate with market prices. We purchase approximately 70% of our crude oil under term contracts, which are primarily short-term agreements with market-related prices, and we purchase the remainder in the spot market. In 2004, we received 69% of our crude oil input from domestic sources (including 27% from Alaska’s North Slope) and 31% from foreign sources (including 12% from Canada). Approximately 50% of our total refining throughput was heavy crude oil in 2004, compared with 58% in 2003 and 49% in 2002. The decrease in the heavy crude oil that we processed in 2004, as compared to 2003, was primarily due to scheduled and unscheduled downtime at our California refinery. We define “heavy” crude oil, which generally is sold at a discount to lighter crudes, as Alaska North Slope or crude oil with an American Petroleum Institute specific gravity of 32 or less. Actual throughput volumes by feedstock type are summarized below (in thousand bpd):
                                                     
    2004   2003   2002
             
    Volume   %   Volume   %   Volume   %
                         
California
                                               
 
Heavy crude
    128       84 %     148       95 %     89       94 %
 
Light crude
    14       9       2       1              
 
Other feedstocks
    11       7       6       4       6       6  
                                     
   
Total
    153       100 %     156       100 %     95       100 %
                                     
Pacific Northwest
                                               
 
Heavy crude
    89       51 %     85       53 %     74       47 %
 
Light crude
    81       47       70       43       75       48  
 
Other feedstocks
    4       2       6       4       8       5  
                                     
   
Total
    174       100 %     161       100 %     157       100 %
                                     
Mid-Pacific
                                               
 
Heavy crude
    42       50 %     51       64 %     49       60 %
 
Light crude
    42       50       29       36       33       40  
                                     
   
Total
    84       100 %     80       100 %     82       100 %
                                     
Mid-Continent
                                               
 
Light crude
    104       95 %     87       96 %     97       96 %
 
Other feedstocks
    5       5       4       4       4       4  
                                     
   
Total
    109       100 %     91       100 %     101       100 %
                                     
Total Refining Throughput
                                               
 
Heavy crude
    259       50 %     284       58 %     212       49 %
 
Light crude
    241       46       188       39       205       47  
 
Other feedstocks
    20       4       16       3       18       4  
                                     
   
Total
    520       100 %     488       100 %     435       100 %
                                     

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      Manufactured Products. Our refining yield consists primarily of gasoline and gasoline blendstocks, jet fuel, diesel fuel and heavy fuel oils. We also manufacture other products, including liquefied petroleum gas and asphalt. Our refining yields, in volumes are summarized below (in thousand bpd):
                                                     
    2004   2003   2002
             
    Volume   %   Volume   %   Volume   %
                         
California(a)
                                               
 
Gasoline and gasoline blendstocks
    96       59 %     99       60 %     62       62 %
 
Diesel fuel
    38       24       38       23       22       22  
 
Heavy oils, residual products, internally produced fuel and other
    28       17       29       17       16       16  
                                     
   
Total
    162       100 %     166       100 %     100       100 %
                                     
Pacific Northwest
                                               
 
Gasoline and gasoline blendstocks
    74       42 %     72       43 %     68       42 %
 
Jet fuel
    31       17       26       16       28       17  
 
Diesel fuel
    27       15       26       16       24       15  
 
Heavy oils, residual products, internally produced fuel and other
    47       26       42       25       42       26  
                                     
   
Total
    179       100 %     166       100 %     162       100 %
                                     
Mid-Pacific
                                               
 
Gasoline and gasoline blendstocks
    21       25 %     19       24 %     20       24 %
 
Jet fuel
    24       28       23       28       26       31  
 
Diesel fuel
    15       17       14       17       12       15  
 
Heavy oils, residual products, internally produced fuel and other
    26       30       25       31       25       30  
                                     
   
Total
    86       100 %     81       100 %     83       100 %
                                     
Mid-Continent
                                               
 
Gasoline and gasoline blendstocks
    60       53 %     49       52 %     54       51 %
 
Jet fuel
    11       10       9       9       10       10  
 
Diesel fuel
    30       27       25       27       29       28  
 
Heavy oils, residual products, internally produced fuel and other
    12       10       11       12       12       11  
                                     
   
Total
    113       100 %     94       100 %     105       100 %
                                     
Total Refining Yield(a)
                                               
 
Gasoline and gasoline blendstocks
    251       47 %     239       47 %     204       45 %
 
Jet fuel
    66       12       58       12       64       15  
 
Diesel fuel
    110       20       103       20       87       19  
 
Heavy oils, residual products, internally produced fuel and other
    113       21       107       21       95       21  
                                     
   
Total
    540       100 %     507       100 %     450       100 %
                                     
 
(a) Refining yield in 2002 included the California refinery since we acquired it on May 17, 2002, averaged over 365 days. Refining yield for the California refinery averaged over the 229 days we owned it was 160,000 bpd.

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      Transportation and Terminals. To optimize system logistics and secure shipping capacity, we term-charter three U.S. flag tankers and one foreign-flag tanker, each of which is double-hulled, to transport crude oil and refined products. Two of our term charters expire in 2010 and the remaining two term charters expire in 2005, one of which has a renewal provision. We also charter several tugs and product barges for our Hawaii and Washington operations over varying terms ending in 2005 through 2010, with options to renew. We charter other tankers and ocean-going barges on a short-term basis to transport crude oil and refined products. We also receive crude oils and ship refined products through Tesoro-owned and third-party pipelines as further described below.
      We operate refined product terminals at our refineries and at several other locations in California, Hawaii, Alaska, Washington and Idaho. We also distribute products through third-party terminals and truck racks, which are supplied by our refineries and through purchases and exchange agreements with other refining and marketing companies.
California Refinery
      Refining. Our California refinery, located in Martinez on 2,206 acres about 30 miles east of San Francisco, is a highly complex refinery with a rated crude oil capacity of 168,000 bpd. We source our California refinery’s crude oil primarily from California and Alaska, and to a lesser extent from foreign locations. Major product upgrading units at the refinery include fluid catalytic cracking (“FCC”), fluid coking, hydrocracking, naphtha reforming, vacuum distillation, hydrotreating and alkylation units. These units enable the refinery to produce a high proportion of motor fuels, including at least 90,000 bpd of cleaner-burning California Air Resources Board (“CARB”) gasoline and CARB diesel, as well as conventional gasoline and diesel. The refinery also produces heavy fuel oils, liquefied petroleum gas and petroleum coke.
      Transportation. Our California refinery has waterborne access through the San Francisco Bay that enables us to receive crude oil and ship products through our marine terminals. In addition, the refinery can receive crude oil through a third-party marine terminal at Martinez. We also receive California crude oils and ship refined products from the refinery through third-party pipeline systems.
      Terminals. We operate a refined product terminal at Stockton, California, and we also distribute products by barge from our refinery. During the second quarter of 2005, we expect to complete construction of a trucking product terminal at our California refinery. We also distribute products through third-party terminals and truck racks, which are supplied by our refinery and through purchases and exchange arrangements with other refining and marketing companies. We also lease approximately 500,000 barrels of storage capacity with waterborne access in southern California.
Pacific Northwest Refineries
Washington
      Refining. Our Washington refinery, located in Anacortes on the Puget Sound on 917 acres about 60 miles north of Seattle, has a total rated crude oil capacity of 108,000 bpd. We source our Washington refinery’s crude oil primarily from Alaska, Canada and other foreign locations. The Washington refinery also processes intermediate feedstocks, primarily heavy vacuum gas oil, provided by some of our other refineries and by spot-market purchases from third-party refineries. Major product upgrading units at the refinery include the FCC, alkylation, hydrotreating, vacuum distillation, deasphalting and naphtha reforming units, which enable our Washington refinery to produce a high proportion of light products, such as gasoline (including components for CARB gasoline), diesel and jet fuel. The refinery also produces heavy fuel oils, liquefied petroleum gas and asphalt.
      Transportation. Our Washington refinery receives Canadian crude oil through a third-party pipeline originating in Edmonton, Canada. We receive other crude oil through our Washington refinery’s marine terminal. Our Washington refinery ships light products (gasoline, jet fuel and diesel) through a third-party pipeline system, which serves western Washington and Portland, Oregon. We also deliver gasoline and diesel fuel through a neighboring refinery’s truck rack, and we distribute diesel fuel through a truck rack at our

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refinery. We deliver refined products through our marine terminal to ships and barges, and we also sell liquefied petroleum gas and asphalt at our refinery.
      Terminals. We operate refined product terminals at Anacortes, Port Angeles and Vancouver, Washington, supplied primarily by our Washington refinery. We also distribute products through third-party terminals and truck racks in our market areas, supplied by our refinery and through purchases and exchange arrangements with other refining and marketing companies.
Alaska
      Refining. Our Alaska refinery is located near Kenai on the Cook Inlet on 488 acres approximately 70 miles southwest of Anchorage. Our Alaska refinery processes crude oil primarily from the Alaska Cook Inlet, Alaska North Slope and, to a lesser extent, foreign locations. The refinery has a total rated crude oil capacity of 72,000 bpd, and its product upgrading units include vacuum distillation, distillate hydrocracking, hydrotreating, naphtha reforming and light naphtha isomerization units. Our Alaska refinery produces gasoline and gasoline blendstocks, jet fuel, diesel fuel, heating oil, heavy fuel oils, liquefied petroleum gas and asphalt.
      Transportation. We receive crude oil by tanker to the Alaska refinery through our marine terminal. Through our owned and operated 24-mile common-carrier crude pipeline, we also receive crude oil at our marine terminal, which is connected with some of the Cook Inlet oil fields. Our marine terminal is also used to load refined products on tankers and barges. We also own and operate a common-carrier petroleum products pipeline that runs from the Alaska refinery to our terminal facilities in Anchorage and to the Anchorage airport. This 71-mile pipeline has the capacity to transport approximately 40,000 bpd of products and allows us to transport gasoline, diesel and jet fuel to the terminal facilities, regardless of weather conditions. Both of our owned pipelines are subject to regulation by various federal, state and local agencies, including the Federal Energy Regulatory Commission (“FERC”).
      Terminals. We operate refined product terminals at Kenai and Anchorage, which are supplied by our Alaska refinery. We also distribute products through third-party terminals and truck racks in our market areas, which are supplied by our refinery and through purchases and exchange arrangements with other refining and marketing companies.
Mid-Pacific Refinery
Hawaii
      Refining. Our 95,000 bpd Hawaii refinery is located at Kapolei on 131 acres about 22 miles west of Honolulu. We supply the Hawaii refinery with crude oil primarily from Alaska, Southeast Asia, the Middle East and other foreign sources. Major product upgrading units include the vacuum distillation, hydrocracking, hydrotreating, visbreaking and naphtha reforming units. The Hawaii refinery produces gasoline and gasoline blendstocks, jet fuel, diesel fuel, heavy fuel oils, liquefied petroleum gas and asphalt.
      Transportation. We transport crude oil to Hawaii by tankers, which discharge through our single-point mooring terminal, 1.5 miles offshore from our refinery. Three underwater pipelines from the single-point mooring terminal allow crude oil and products to be transferred to and from the refinery’s storage tanks. We distribute refined products to customers on the island of Oahu through owned and third-party pipeline systems. Our product pipelines also connect the Hawaii refinery to Barbers Point Harbor, 2.5 miles away.
      Terminals. We also distribute products from our refinery to customers through third-party terminals at Honolulu International Airport and Honolulu Harbor and by barge to Tesoro-owned and third-party terminal facilities on the islands of Oahu, Maui, Kauai and Hawaii.
Mid-Continent Refineries
North Dakota
      Refining. Our 60,000 bpd North Dakota refinery is located near Mandan on 960 acres. We supply our North Dakota refinery primarily with Williston Basin sweet crude oil. The refinery also can access other

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supplies, including Canadian crude oil. Major product upgrading units at the refinery include the FCC, naphtha reforming, hydrotreating and alkylation units. The North Dakota refinery produces gasoline, diesel fuel and jet fuel.
      Transportation. We own a crude oil pipeline system, consisting of over 700 miles of pipeline that delivers all of the crude oil supply to our North Dakota refinery. Our crude oil pipeline system gathers crude oil from the Williston Basin and adjacent production areas in North Dakota and Montana and transports it to our refinery and to other regional points where there is additional demand. Our crude oil pipeline system is a common carrier subject to regulation by various federal, state and local agencies, including the FERC. We distribute approximately 85% of our refinery’s production through a third-party product pipeline system which serves various areas from Bismarck, North Dakota to Minneapolis, Minnesota. All gasoline and distillate products from our refinery, with the exception of railroad-spec diesel fuel, can be shipped through that pipeline to third-party terminals.
      Terminals. Our terminal at the North Dakota refinery connects to a third-party product pipeline system and terminals located in North Dakota and Minnesota. We distribute products from our refinery to customers primarily through these third-party terminals.
      Offtake Agreements. In connection with the 2001 acquisition of the North Dakota refinery, we entered into certain offtake agreements with BP plc (“BP”) for a portion of our refined products. We sold an average of 14,000 bpd of refined products in 2004 under these offtake agreements. In 2004, BP received approximately 66% of the committed product under these offtake agreements through the Minneapolis/ St. Paul terminal with the remainder distributed through terminals at Moorhead and Sauk Centre, Minnesota. The offtake agreements, as amended, for the Moorhead and Sauk Centre terminals expire in September 2005. The offtake agreement for the Minneapolis/ St. Paul terminal expires in September 2006 with declining volumes in each of the last two years, and volumes may be reduced further under certain conditions. We do not anticipate that expiration of any of these offtake agreements will have a material impact on our refinery operations.
Utah
      Refining. Our 55,000 bpd Utah refinery is located in Salt Lake City on 145 acres. Our Utah refinery processes crude oils primarily from Utah, Colorado, Wyoming and, to a lesser extent, crude oil and syncrude from Canada. Major product upgrading units include the FCC, naphtha reforming, alkylation and the newly completed hydrotreating unit. The Utah refinery produces gasoline, diesel fuel and jet fuel.
      Transportation. Our Utah refinery receives crude oil primarily by third-party pipelines from fields in Utah, Colorado, Wyoming and Canada. We distribute the refinery’s production through a system of both owned and third-party terminals and third-party pipeline connections, primarily in Utah, Idaho and eastern Washington, with some product delivered in Nevada and Wyoming.
      Terminals. In addition to sales at the refinery, we distribute products to customers through a third-party pipeline to the two terminals we own at Boise and Burley, Idaho and to two third-party terminals in Pocatello, Idaho and Pasco, Washington.
Wholesale Marketing and Product Distribution
      We sell refined products including gasoline and gasoline blendstocks, jet fuel, diesel fuel, heavy oil and residual products in both the bulk and wholesale markets. In addition, we sell products that we manufacture and products purchased or received on exchange from third parties. Exchange agreements provide for the delivery of Tesoro’s refined products primarily to third-party terminals in exchange for delivery of refined

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products from the third parties at specific locations. These arrangements help to optimize our refinery supply requirements. Our refined product sales, including intersegment sales to our retail operations, consisted of:
                             
    2004   2003   2002(a)
             
Product Sales (thousand bpd)
                       
 
Gasoline and gasoline blendstocks
    300       280       264  
 
Jet fuel
    90       84       94  
 
Diesel fuel
    133       121       115  
 
Heavy oils, residual products and other
    81       72       72  
                   
   
Total Product Sales
    604       557       545  
                   
 
(a)  Sales volumes for 2002 include amounts for the California operations since their acquisition on May 17, 2002, averaged over 365 days.
      Gasoline and Gasoline Blendstocks. We sell gasoline and gasoline blendstocks in both the bulk and wholesale markets in the mid-continental and western United States. The demand for gasoline is seasonal in many of our markets, with lowest demand during the winter months. We also sell gasoline to wholesale customers and bulk end-users (including several major oil companies) under various supply agreements. Gasoline also is delivered to refiners and marketers in exchange for product received at other locations in our markets. We sell, at wholesale, to unbranded distributors and high-volume retailers, and we distribute product through Tesoro-owned and third-party terminals and truck racks.
      Jet Fuel. We supply commercial jet fuel to passenger and cargo airlines at airports in Alaska, Hawaii, California, Washington, Utah and other western states. We also supply jet fuel to the U.S. military in certain of our markets.
      Diesel Fuel. We sell our diesel fuel production primarily on a wholesale basis for marine, transportation, industrial and agricultural use, as well as for home heating. We sell lesser amounts to end-users through marine terminals and for power generation in Hawaii and Washington. Diesel fuel production by refiners in our market areas is generally in balance with demand. As a result of variations in seasonal demand, we ship diesel fuel to or from our Alaska and Hawaii operations.
      Heavy Fuel Oils and Residual Products. We sell heavy fuel oils to other refineries, electric power producers and marine and industrial end-users. Our refineries supply substantially all of the marine fuels that we sell through leased facilities at Port Angeles and Seattle, Washington, and Portland, Oregon, and through owned and leased facilities in Alaska and Hawaii. We sell our asphalt for paving materials in Hawaii, Alaska and Washington. In Alaska and the Pacific Northwest, demand for asphalt is seasonal because mild weather conditions are needed for highway construction. Our California refinery produces petroleum coke that we sell to industrial end-users.
      Sales of Purchased Products. In the normal course of business to meet local market demands, we purchase refined products manufactured by others for resale to our customers. We purchase these products, primarily gasoline, jet fuel, diesel fuel and industrial and marine fuel blendstocks, mainly in the spot market. We conduct our gasoline and diesel fuel purchase and resale activity primarily on the U.S. West Coast. Our jet fuel activity primarily consists of supplying markets in Alaska, California and Hawaii. We also purchase a lesser amount of gasoline and other products that are sold outside of our refineries’ local markets.
RETAIL
      Through our network of retail stations, we sell gasoline and diesel fuel in the mid-continental and western United States. The demand for gasoline is seasonal in a majority of our markets, with highest demand for gasoline during the summer driving season. We sell gasoline and diesel to retail customers through company-operated sites and agreements with third-party branded distributors (or “jobber/dealers”). As of December 31, 2004, our retail segment included a network of 506 branded retail stations (under the Tesoro® and Mirastar® brands), comprising 214 company-operated retail gasoline stations and 292 jobber/dealer stations.

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Our retail network provides a committed outlet for a portion of the motor fuels produced by our refineries. Most of our company-operated Tesoro® stations include 2-Go Tesoro® brand convenience stores that sell a wide variety of merchandise items. The following table summarizes our retail operations:
                             
    2004   2003   2002
             
Number of Branded Retail Stations (end of period)
                       
Tesoro®
                       
 
Company-operated
    136       146       154  
 
Jobber/dealer
    292       331       359  
Mirastar®
                       
 
Company-operated
    78       78       78  
Other
                       
 
Company-operated
          2       2  
Total Branded Retail Stations
                       
 
Company-operated(a)
    214       226       234  
 
Jobber/dealer(b)
    292       331       359  
                   
   
Total
    506       557       593  
                   
Average Number of Branded Stations (during year)(c)
                       
 
Company-operated
    222       229       260  
 
Jobber/dealer
    316       346       419  
                   
   
Total Average Retail Stations
    538       575       679  
                   
Total Fuel Volume (millions of gallons)
                       
 
Company-operated
    290       309       418  
 
Jobber/dealer
    220       259       372  
                   
   
Total Fuel Volumes
    510       568       790  
                   
Average Fuel Volume Per Month Per Station (thousands of gallons)
                       
 
Company-operated
    109       112       134  
 
Jobber/dealer
    58       62       74  
 
Total stations
    79       82       97  
Fuel Revenues (in millions)
                       
 
Company-operated
  $ 566     $ 519     $ 594  
 
Jobber/dealer
    297       278       326  
                   
   
Total Fuel Revenues
  $ 863     $ 797     $ 920  
                   
Merchandise and Other Revenues (in millions)
  $ 131     $ 121     $ 132  
Merchandise Margin
    28 %     27 %     27 %
 
(a) Company-operated stations included 43 in Washington, 39 in Utah, 33 in Hawaii, 29 in Alaska and 70 in several other western and mid-continental states at December 31, 2004.
 
(b) At December 31, 2004, the jobber/dealer stations included 70 in Alaska, 66 in North Dakota, 55 in Utah, 32 in Washington, 24 in Idaho, 14 in California and 31 in several other western states.
 
(c) The average number of company-operated stations in 2002 included 70 stations in northern California that were purchased in May 2002 (with our California refinery) and sold in December 2002. The average number of jobber/dealer stations in 2002 included 150 BP/Amoco branded independent jobber/dealer stations acquired in the Mid-Continent acquisition that did not rebrand to Tesoro®.

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COMPETITION AND OTHER
      The petroleum industry is highly competitive in all phases, including the purchase of crude oil and the marketing of refined petroleum products. The industry also competes with other industries that supply the energy and fuel requirements of industrial, commercial and individual consumers. In recent years, consolidation in the refining and marketing industry has reduced the number of competitors; however, it has not reduced overall competition. We compete with a number of major integrated oil companies and other companies that have greater financial and other resources. These competitors have a greater ability to bear the economic risks inherent in all phases of the industry. In addition, unlike many of our competitors, we do not produce crude oil for use in our refining operations, and we are not as large as many of our competitors who may have a competitive advantage when negotiating with crude oil producers.
      Our California and Washington refineries compete with several refineries on the U.S. West Coast, including refineries that have greater economies of scale. Our Hawaii refinery competes primarily with one other refinery in Hawaii, owned by a major integrated oil company, that also is located at Kapolei and has a rated crude oil capacity of 54,000 bpd. Historically, the other refinery produces lower volumes of jet fuel than our Hawaii refinery. The Alaska refinery competes primarily with other refineries in Alaska and on the U.S. West Coast. Our refining competition in Alaska includes two refineries near Fairbanks and a refinery near Valdez. We estimate that the other Alaska refineries have a combined capacity to process approximately 270,000 bpd of crude oil. After processing Alaska North Slope crude oil and removing the higher-value products, these refiners are permitted, because of their direct connection to the Trans Alaska Pipeline System, to return the remainder of the processed crude oil into the pipeline system as “return oil” in consideration for a fee, thereby eliminating their need to transport and market lower-value products that are not in demand in Alaska. Our Alaska refinery is not connected to the Trans Alaska Pipeline System, and we, therefore, cannot return our lower-value products to that pipeline system. Our North Dakota refinery is the only refinery in North Dakota. Refineries in Wyoming, Montana, the Midwest and the United States Gulf Coast region are the primary competitors with our North Dakota refinery. Our Utah refinery is the largest of five refineries located in Utah. We estimate that these other refineries have a combined capacity to process approximately 107,500 bpd of crude oil. These five refineries collectively supply a high proportion of the gasoline and distillate products consumed in the states of Utah and Idaho, with additional supplies provided from refineries in surrounding states.
      Our jet fuel sales in Alaska are concentrated in Anchorage, where we are one of the principal suppliers to the Anchorage International Airport, a major hub for air cargo traffic between manufacturing regions in the Far East and markets in the United States and Europe. In Hawaii, jet fuel sales are concentrated in Honolulu, where we are the principal supplier to the Honolulu International Airport. We also serve four airports on other islands in Hawaii. In Washington, jet fuel sales are concentrated at the Seattle/Tacoma International Airport. We also supply jet fuel to customers in Portland, Oregon; Los Angeles, San Francisco and San Diego, California; Las Vegas and Reno, Nevada; and Phoenix, Arizona. Other refiners and marketers compete for sales at all of these airports. In Utah, our jet fuel sales are concentrated in Salt Lake City, and we also supply jet fuel to customers in Boise, Burley and Pocatello, Idaho. The North Dakota refinery supplies jet fuel to customers in Minneapolis/St. Paul and Moorhead, Minnesota and in Bismarck and Jamestown, North Dakota. We compete with other suppliers for U.S. military contracts in Alaska, Hawaii and North Dakota. Both the Alaska and Hawaii markets periodically require additional jet fuel supplies from outside the state to meet demand.
      We sell our diesel fuel production primarily on a wholesale basis, competing with other refiners and marketers in all of our market areas. Refined products from foreign sources, including Canada, also compete for distillate customers in our market areas.
      We sell gasoline in Alaska, California, Hawaii, North Dakota, Utah, Washington and other western and mid-continental states through a network of company-operated retail stations and branded and unbranded jobber/dealers. Competitive factors that affect retail marketing include price, station appearance, location and brand awareness. Our retail marketing operations compete with other independent marketing companies, integrated oil companies and high-volume retailers.

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GOVERNMENT REGULATION AND LEGISLATION
Environmental Controls and Expenditures
      All of our operations, like those of other companies engaged in similar businesses, are subject to extensive and frequently changing federal, state, regional and local laws, regulations and ordinances relating to the protection of the environment, including those governing emissions or discharges to the air and water, the handling and disposal of solid and hazardous wastes and the remediation of contamination. While we believe our facilities are in substantial compliance with current requirements, our facilities will continue during 2005 and over the next several years to be engaged in meeting new requirements promulgated by the U.S. Environmental Protection Agency (“EPA”) and the states and local jurisdictions in which we operate as described below.
      Changes in fuel manufacturing standards, including those related to gasoline and diesel fuel sulfur concentrations, also affect our operations. EPA regulations related to the Clean Air Act require reductions in the sulfur content in gasoline, which began January 1, 2004. To meet the revised gasoline standard, we spent approximately $11 million in 2004, and we currently estimate we will make additional capital improvements of approximately $37 million through 2009. This will permit each of our six refineries to produce gasoline meeting the sulfur limits imposed by the EPA.
      EPA regulations related to the Clean Air Act also require reductions in the sulfur content in diesel fuel manufactured for on-road consumption. In general, the new on-road diesel fuel standards will become effective on June 1, 2006. In May 2004, the EPA issued a rule regarding the sulfur content of non-road diesel fuel. The requirements to reduce non-road diesel sulfur content will become effective in phases between 2007 and 2010. We have not determined if we will invest the capital necessary to manufacture low sulfur diesel for the non-road market in Alaska, and we are continuing to evaluate potential projects to manufacture additional non-road low sulfur diesel at our Hawaii refinery. Our California, Washington and North Dakota refineries will not require additional capital spending for non-road low sulfur diesel. We spent $31 million in 2004 to meet low sulfur diesel standards, and based on our latest engineering estimates, we expect to spend approximately $45 million in additional capital improvements through 2006.
      To comply with the Maximum Achievable Control Technologies standard for petroleum refineries (“Refinery MACT II”), we spent $20 million during 2004, primarily to complete the installation of new emission control equipment at our North Dakota refinery. We expect to spend approximately $17 million in additional capital improvements in 2006 at our Washington refinery.
      In connection with our 2001 acquisition of our 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. (“BP”), Amoco Oil Company and Atlantic Richfield Company. BP entered into this consent decree for both the North Dakota and Utah refineries for various alleged violations. As the owner of these refineries, 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 $5 million over the next three years to comply with this consent decree. We also agreed to indemnify the sellers for all losses of any kind incurred in connection with the consent decree.
      In connection with the 2002 acquisition of our California refinery, subject to certain conditions, we assumed the seller’s obligations pursuant to settlement efforts with the EPA concerning the Section 114 refinery enforcement initiative under the Clean Air Act, except for any potential monetary penalties, which the seller retains. We believe these obligations will not have a material impact on our financial position or results of operations.
      We 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. For these related projects at our California refinery, we spent $10 million during 2004, and we estimate that we may spend an additional $90 million through 2010. This cost estimate is subject to further review and analysis.

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      Conditions may develop that cause increases or decreases in future expenditures for our various sites, including, but not limited to, our refineries, tank farms, retail gasoline stations (operating and closed locations) and petroleum product terminals, and for compliance with the Clean Air Act and other federal, state and local requirements. We cannot currently determine the amounts of such future expenditures.
Oil Spill Prevention and Response
      We operate in environmentally sensitive coastal waters, where tanker, pipeline and refined product transportation operations are closely regulated by federal, state and local agencies and monitored by environmental interest groups. The transportation of crude oil and refined product over water involves risk and subjects us to the provisions of the Federal Oil Pollution Act of 1990 and related state regulations, which require that most oil refining, transport and storage companies maintain and update various oil spill prevention and oil spill contingency plans. We have submitted these plans and received federal and state approvals necessary to comply with the Federal Oil Pollution Act of 1990 and related regulations. Our oil spill prevention plans and procedures are frequently reviewed and modified to prevent oil and product releases and to minimize potential impacts should a release occur.
      We currently charter tankers to ship crude oil from foreign and domestic sources to our California, Mid-Pacific and Pacific Northwest refineries. The Federal Oil Pollution Act of 1990 requires, as a condition of operation, that we demonstrate the capability to respond to the “worst case discharge” to the maximum extent practicable. As an example, the State of Alaska requires us to provide spill-response capability to contain or control and cleanup amounts equal to 50,000 barrels of crude oil for a tanker carrying fewer than 500,000 barrels and 300,000 barrels for a tanker carrying more than 500,000 barrels. To meet these requirements, we have entered into contracts with various parties to provide spill response services. We have entered into spill-response agreements with (1) Cook Inlet Spill Prevention and Response, Incorporated (for which we fund approximately 65% of expenditures) and Alyeska Pipeline Service Company for spill-response services in Alaska, (2) Clean Islands Council for response services throughout the State of Hawaii, and (3) Clean Sound Incorporated for response actions associated with the Puget Sound, Washington operations. In addition, for larger spill contingency capabilities, we have entered into contracts with Marine Spill Response Corporation for Hawaii, the San Francisco Bay and Puget Sound. We believe these contracts, and those with other regional spill-response organizations that are in place on a location by location basis, provide the additional services necessary to meet spill-response requirements established by state and federal law.
Regulation of Pipelines
      Our crude oil pipeline system in North Dakota and our pipeline systems in Alaska are common carriers subject to regulation by various federal, state and local agencies, including the FERC under the Interstate Commerce Act. The Interstate Commerce Act provides that, to be lawful, the rates of common carrier petroleum pipelines must be “just and reasonable” and not unduly discriminatory.
      The intrastate operations of our crude oil pipeline system are subject to regulation by the North Dakota Public Services Commission. The intrastate operations of our Alaska pipelines are subject to regulation by the Alaska Public Utilities Commission. Like the FERC, the state regulatory authorities require that we notify shippers of proposed intrastate tariff increases and they have an opportunity to protest the increases. The North Dakota Public Services Commission also files with the state authorities copies of interstate tariff charges filed with the FERC. In addition to challenges to new or proposed rates, challenges to intrastate rates that have already become effective are permitted by complaint of an interested person or by independent action of the appropriate regulatory authority.
EMPLOYEES
      At December 31, 2004, we had approximately 3,640 full-time employees. Approximately 1,060 of our employees are covered by collective bargaining agreements with terms expiring on January 31, 2006. We consider our relations with our employees to be satisfactory.

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PROPERTIES
      Our principal properties are described above under the captions “Refining” and “Retail”. In addition, we own feedstock and refined product storage facilities at our refinery and terminal locations. We believe that our properties and facilities are generally adequate for our operations and that our facilities are maintained in a good state of repair. We are the lessee under a number of cancelable and non-cancelable leases for certain properties, including office facilities, retail facilities, ship charters and equipment used in the storage, transportation and production of feedstocks and refined products. See Notes F and P in our consolidated financial statements in Item 8.
      We conduct our retail business under the Tesoro®, Tesoro Alaska®, Mirastar®, and 2-Go Tesoro® brands. Our retail marketing system under these brands includes 506 branded retail stations, of which 214 are company-operated.
EXECUTIVE OFFICERS OF THE REGISTRANT
      The following is a list of the Company’s executive officers, their ages and their positions with the Company at March 1, 2005.
                     
Name   Age   Position   Position Held Since
             
Bruce A. Smith
    61     Chairman of the Board of Directors, President and Chief Executive Officer     June 1996  
William J. Finnerty
    56     Executive Vice President, Operations     January 2005  
Everett D. Lewis
    57     Executive Vice President, Corporate Strategic Planning     January 2005  
Gregory A. Wright
    55     Executive Vice President and Chief Financial Officer     December 2003  
W. Eugene Burden
    56     Senior Vice President, External Affairs     November 2004  
Claude A. Flagg
    51     Senior Vice President, Supply & Optimization     February 2005  
J. William Haywood
    52     Senior Vice President, Refining     March 2005  
Joseph M. Monroe
    50     Senior Vice President, Business Integration and Analysis     February 2005  
Stephen L. Wormington
    60     Senior Vice President, Performance Management     February 2005  
Susan A. Lerette
    46     Vice President, Human Resources and Communications     May 2004  
Charles S. Parrish
    47     Vice President, General Counsel and Secretary     March 2005  
Otto C. Schwethelm
    50     Vice President and Controller     February 2003  
G. Scott Spendlove
    41     Vice President, Finance and Treasurer     May 2003  
      There are no family relationships among the officers listed, and there are no arrangements or understandings pursuant to which any of them were elected as officers. Officers are elected annually by the board of directors at their first meeting following the annual meeting of stockholders. The term of each office runs until the corresponding meeting of the board of directors in the next year or until a successor has been elected or qualified.

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      Tesoro’s executive officers have been employed by Tesoro or its subsidiaries in an executive capacity for at least the past five years, except for those named below who have had the business experience indicated during that period. Positions, unless otherwise specified, are with Tesoro.
      William J. Finnerty was named Executive Vice President, Operations in January 2005. Prior to that, he served as Senior Vice President, Supply and Distribution of Tesoro Refining and Marketing Company beginning in February 2004. He joined Tesoro in December 2003 as Vice President, Crude Oil and Logistics, of Tesoro Refining and Marketing Company. Prior to joining Tesoro, Mr. Finnerty served as Vice President, Trading North America Crude, for ChevronTexaco from October 2001 to November 2003. From May 2001 to October 2001, he served as Vice President, Texaco Oil Trading and Transport Company. From June 2000 to May 2001, Mr. Finnerty was Senior Vice President, Trading and Operations for Equiva Trading Company. He was Vice President, Crude Oil for Equiva Trading Company from March 1998 to June 2000.
      Everett D. Lewis was named Executive Vice President, Corporate Strategic Planning in January 2005. Prior to that, he served as Senior Vice President, Corporate Strategic Planning beginning in November 2004. Mr. Lewis served as Senior Vice President, Planning and Optimization from February 2003 to November 2004 and Senior Vice President, Planning and Risk Management from April 2001 to February 2003. He served as Senior Vice President of Strategic Projects from March 1999 to April 2001.
      W. Eugene Burden was named Senior Vice President, External Affairs in November 2004. Prior to that, he served as Senior Vice President, Human Resources and Government Relations from June 2002 to November 2004, President of Tesoro Alaska Company from February 2001 to June 2002, and Senior Vice President and President, Northwest Region of Tesoro Refining and Marketing Company from September 2001 until June 2002. Mr. Burden served as Senior Vice President, Government Relations of Tesoro Petroleum Companies, Inc. from September 1999 to February 2001.
      Claude A. Flagg was named Senior Vice President, Supply and Optimization in February 2005. He joined Tesoro in January 2005 as Senior Vice President, Planning and Optimization. Prior to joining Tesoro, he served as General Manager of Supply Optimization at Shell Oil Products U.S. from January 2003 to December 2004. From May 2002 to January 2003, Mr. Flagg was General Manager of Supply Optimization at Equilon Enterprises, LLC. He was General Manager of Equilon Enterprises, LLC’s Bay/ Valley Refining Complex from April 1999 to May 2002.
      J. William Haywood was named Senior Vice President, Refining in March 2005. He joined Tesoro in May 2002 as Senior Vice President and also became President of the California Region of Tesoro Refining and Marketing Company in September 2002. Prior to joining Tesoro, Mr. Haywood served as Regional Vice President of Ultramar Diamond Shamrock Corporation, responsible for California refineries from September 2000 to May 2002. From September 1997 to September 2000, Mr. Haywood was General Manager of Ultramar Diamond Shamrock’s Wilmington refinery near Los Angeles.
      Joseph M. Monroe was named Senior Vice President, Business Integration and Analysis in February 2005. Prior to that, he served as Senior Vice President, Organizational Effectiveness beginning in November 2004. From February 2004 to November 2004, he served as Senior Vice President, Strategic Planning and Business Development of Tesoro Petroleum Companies, Inc. From May 2002 to February 2004, Mr. Monroe served as Senior Vice President, Supply and Distribution, of Tesoro Refining and Marketing Company. Prior to joining Tesoro, he was Vice President, Pipelines and Terminals of Unocal Corporation and President of Unocal Pipeline Company from January 1999 through May 2002.
      Susan A. Lerette was named Vice President, Human Resources and Communications in May 2004. Prior to that, she served as Vice President, Communications from April 2001 to May 2004. She was Director, Investor Relations from April 1999 to April 2001.
      Charles S. Parrish was named Vice President, General Counsel and Secretary in March 2005. Prior to that, he served as Vice President, Assistant General Counsel and Secretary beginning in November 2004. Mr. Parrish served as Vice President, Assistant General Counsel of Tesoro Petroleum Companies, Inc. from March 2003 to November 2004. From 1995 through March 2003, he served numerous roles in the Company’s

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legal department, primarily focused on matters related to the Company’s capital structure and Securities Act reporting.
      Otto C. Schwethelm was named Vice President and Controller in February 2003. From September 2002 to February 2003, Mr. Schwethelm served as Vice President and Operations Controller. Prior to that, he served as Vice President, Shared Services of Tesoro Petroleum Companies, Inc. from December 2001 to September 2002. From November 1999 to December 2001, Mr. Schwethelm was Vice President, Development and Business Analysis.
      G. Scott Spendlove has served as Vice President, Finance and Treasurer since May 2003 and as Vice President, Finance from January 2002 to May 2003. Prior to joining Tesoro in 2002, he served as Vice President, Corporate Planning and Investor Relations of Ultramar Diamond Shamrock Corporation from December 1999 to December 2001.
BOARD OF DIRECTORS OF THE REGISTRANT
      The following is a list of the Company’s Board of Directors:
Bruce A. Smith Chairman, President and Chief Executive Officer of Tesoro Corporation
 
Steven H. Grapstein Lead Director of Tesoro Corporation; Chief Executive Officer of Kuo Investment Company
 
Robert W. Goldman Vice President, Finance for World Petroleum Council; Retired Chief Financial Officer of Conoco, Inc.
 
William J. Johnson Petroleum Consultant; President of JonLoc Inc.
 
A. Maurice Myers Retired Chairman, President and Chief Executive Officer of Waste Management Inc.
 
Donald H. Schmude Retired Vice President of Texaco and President and Chief Executive Officer of Texaco Refining & Marketing Inc.
 
Patrick J. Ward Retired Chairman, President and Chief Executive Officer of Caltex Petroleum Corporation
RISK FACTORS
The volatility of crude oil prices, refined product prices and natural gas and electrical power prices may have a material adverse effect on our cash flow and results of operations.
      Our earnings and cash flows from our refining and wholesale marketing operations depend on a number of factors, including fixed and variable expenses (including the cost of refinery feedstocks) and the margin above those expenses at which we are able to sell refined products. In recent years, the prices of crude oil and refined products have fluctuated substantially. These prices depend on numerous factors beyond our control, including the demand for crude oil, gasoline and other refined products, which are subject to, among other things:
  •  changes in the economy and the level of foreign and domestic production of crude oil and refined products;
 
  •  threatened or actual terrorist incidents, acts of war, and other worldwide political conditions;
 
  •  availability of crude oil and refined products and the infrastructure to transport crude oil and refined products;
 
  •  weather conditions, earthquakes or other natural disasters;
 
  •  government regulations; and
 
  •  local factors, including market conditions and the level of operations of other refineries in our markets.

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      Prices for refined products are influenced by the commodity price of crude oil. Generally, an increase or decrease in the price of crude oil affects the price of gasoline and other refined products. However, the timing of the relative movement of the prices, as well as the overall change in product prices, can reduce profit margins and could have a significant impact on our refining and wholesale marketing operations, earnings and cash flow. Also, crude oil supply contracts are generally term contracts with market-responsive pricing provisions. We purchase our refinery feedstocks before manufacturing and selling the refined products. Price level changes during the period between purchasing feedstocks and selling the manufactured refined products from these feedstocks could have a significant effect on our financial results. We also purchase refined products manufactured by others for sale to our customers. Price level changes during the periods between purchasing and selling these products also could have a material adverse effect on our business, financial condition and results of operations.
      Volatile prices for natural gas and electrical power used by our refineries and other operations have affected manufacturing and operating costs. Natural gas and electricity prices have been and will continue to be affected by supply and demand for fuel and utility services in both local and regional markets.
Our business is impacted by risks inherent in petroleum refining operations.
      The operation of refineries, pipelines and product terminals is inherently subject to spills, discharges or other releases of petroleum or hazardous substances. If any of these events had previously occurred or occurs in the future in connection with any of our refineries, pipelines or product terminals, or in connection with any facilities to which we sent wastes or by-products for treatment or disposal, other than events for which we are indemnified, we could be liable for all costs and penalties associated with their remediation under federal, state and local environmental laws or common law, and could be liable for property damage to third parties caused by contamination from releases and spills. The penalties and clean-up costs that we may have to pay for releases or spills, or the amounts that we may have to pay to third parties for damage to their property, could be significant and the payment of these amounts could have a material adverse effect on our business, financial condition and results of operations.
      We operate in environmentally sensitive coastal waters, where tanker, pipeline and refined product transportation operations are closely regulated by federal, state and local agencies and monitored by environmental interest groups. Our California, Mid-Pacific and Pacific Northwest refineries import crude oil feedstocks by tanker. Transportation of crude oil and refined products over water involves inherent risk and subjects us to the provisions of the Federal Oil Pollution Act of 1990 and state laws in California, Hawaii, Washington and Alaska. Among other things, these laws require us to demonstrate in some situations our capacity to respond to a “worst case discharge” to the maximum extent possible. We have contracted with various spill response service companies in the areas in which we transport crude oil and refined products to meet the requirements of the Federal Oil Pollution Act of 1990 and state laws. However, there may be accidents involving tankers transporting crude oil or refined products, and response services may not respond to a “worst case discharge” in a manner that will adequately contain that discharge, or we may be subject to liability in connection with a discharge.
The dangers inherent in our operations and the potential limits on insurance coverage could expose us to potentially significant liability costs.
      Our operations are subject to hazards and risks inherent in refining operations and in transporting and storing crude oil and refined products, such as fires, natural disasters, explosions, pipeline ruptures and spills and mechanical failure of equipment at our or third-party facilities, any of which can result in personal injury claims and other damage to our properties and the properties of others. In addition, we operate six petroleum refineries, any of which could experience a major accident, be damaged by severe weather or other natural disaster, or otherwise be forced to shut down. Any such unplanned shutdown could have a material adverse effect on our business, financial condition and results of operations. We do not maintain insurance coverage against all potential losses, and we could suffer losses for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could have a material adverse effect on our business, financial condition and results of operations.

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Our operations are subject to general environmental risks, expenses and liabilities which could affect our results of operations.
      From time to time we have been, and presently are, subject to litigation and investigations with respect to environmental and related matters, including product liability claims related to the oxygenate MTBE. We may become involved in further litigation or other proceedings, or we may be held responsible in any existing or future litigation or proceedings, the costs of which could be material.
      We have in the past operated service stations with underground storage tanks in various jurisdictions, and currently operate service stations that have underground storage tanks in 18 states in the mid-continental and western United States. Federal and state regulations and legislation govern the storage tanks, and compliance with these requirements can be costly. The operation of underground storage tanks also poses certain other risks, including damages associated with soil and groundwater contamination. Leaks from underground storage tanks which may occur at one or more of our service stations, or which may have occurred at our previously operated service stations, may impact soil or groundwater and could result in fines or civil liability for us.
      Consistent with the experience of other U.S. refineries, environmental laws and regulations have raised operating costs and require significant capital investments at our refineries. We believe that existing physical facilities at our refineries are substantially adequate to maintain compliance with existing applicable laws and regulatory requirements. However, potentially material expenditures could be required in the future. For example, we may be required to comply with evolving environmental, health and safety laws, regulations or requirements that may be adopted or imposed in the future. We also may be required to address information or conditions that may be discovered in the future and that require a response.
If we are unable to maintain an adequate supply of feedstocks, our results of operations may be adversely affected.
      We may not continue to have an adequate supply of feedstocks, primarily crude oil, available to our six refineries to sustain our current level of refining operations. If additional crude oil becomes necessary at one or more of our refineries, we intend to implement available alternatives that are most advantageous under then prevailing conditions. Implementation of some alternatives could require the consent or cooperation of third parties and other considerations beyond our control. In particular, the North Dakota refinery is completely dependent upon the delivery of crude oil through our crude oil pipeline system. If outside events cause an inadequate supply of crude oil, or if our crude oil pipeline system transports lower volumes of crude oil, our anticipated revenues could decrease. If we are unable to obtain supplemental crude oil volumes, or are only able to obtain these volumes at uneconomic prices, our results of operations could be adversely affected.
We are subject to interruptions of supply and increased costs as a result of our reliance on third-party transportation of crude oil and refined products.
      Our Washington refinery receives all of its Canadian crude oil and delivers a high proportion of its gasoline, diesel and jet fuel through third-party pipelines. Our Hawaii and Alaska refineries receive most of their crude oil and transport a substantial portion of refined products through ships and barges. Our Utah refinery receives substantially all of its crude oil and delivers substantially all of its products through third-party pipelines. Our North Dakota refinery delivers substantially all of its products through a third-party pipeline system. Our California refinery receives approximately half of its crude oil through pipelines and the balance through marine vessels. Substantially all of our California refinery’s production is delivered through third-party pipelines, ships and barges. In addition to environmental risks discussed above, we could experience an interruption of supply or an increased cost to deliver refined products to market if the ability of the pipelines or vessels to transport crude oil or refined products is upset because of accidents, governmental regulation or third-party action. A prolonged upset of the ability of a pipeline or vessels to transport crude oil or product could have a material adverse effect on our business, financial condition and results of operations.

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Our debt instruments impose restrictions on us that may adversely affect our ability to operate our business.
      Our ability to comply with the specified financial covenants of our credit agreement as they currently exist or as they may be amended, may be affected by many events beyond our control and our future operating results may not allow us to comply with the covenants, or in the event of a default, to remedy that default. Our failure to comply with those financial covenants or to comply with the other restrictions contained in our credit agreement could result in a default, which could cause that indebtedness (and by reason of cross-default provisions, indebtedness under the indentures governing our senior secured and senior subordinated notes and other indebtedness) to become immediately due and payable. If we are unable to repay those amounts, the lenders under our credit agreement could proceed against the collateral granted to them to secure that indebtedness. If those lenders accelerate the payment of the credit agreement, we may not be able to pay that indebtedness immediately and continue to operate our business.
      In addition, the indentures for our senior secured and senior subordinated notes contain other covenants that restrict, among other things, our ability to:
  •  pay dividends and other distributions with respect to our capital stock and purchase, redeem or retire our capital stock;
 
  •  incur additional indebtedness and issue preferred stock;
 
  •  sell assets unless the proceeds from those sales are used to repay debt or are reinvested in our business;
 
  •  incur liens on assets to secure certain debt;
 
  •  engage in certain business activities;
 
  •  engage in certain mergers or consolidations and transfers of assets; and
 
  •  enter into transactions with affiliates.
Terrorist attacks and threats or actual war may negatively impact our business.
      Our business is affected by general economic conditions and fluctuations in consumer confidence and spending, which can decline as a result of numerous factors outside of our control, such as actual or threatened terrorist attacks and acts of war. Terrorist attacks in the United States, as well as events occurring in response to or in connection with them, including future terrorist attacks against U.S. targets, rumors or threats of war, actual conflicts involving the United States or its allies, or military or trade disruptions impacting our suppliers or our customers or energy markets generally, may adversely impact our operations. As a result, there could be delays or losses in the delivery of supplies and raw materials to us, delays in our delivery of refined products, decreased sales of our products (especially sales to our customers that purchase jet fuel) and extension of time for payment of accounts receivable from our customers (especially our customers in the airline industry). Strategic targets such as energy-related assets (which could include refineries such as ours) may be at greater risk of future terrorist attacks than other targets in the United States. These occurrences could significantly impact energy prices, including prices for our crude oil and refined products, and have a material adverse impact on the margins from our refining and wholesale marketing operations. In addition, disruption or significant increases in energy prices could result in government-imposed price controls. Any one of, or a combination of, these occurrences could have a material adverse effect on our business, financial condition and results of operations.
Our operating results are seasonal and generally are lower in the first and fourth quarters of the year.
      Demand for gasoline is higher during the spring and summer months than during the winter months in most of our markets due to seasonal increases in highway traffic. As a result, our operating results for the first and fourth quarters are generally lower than for those in the second and third quarters.

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ITEM 3. LEGAL PROCEEDINGS
      In the ordinary course of business, we become party to or otherwise involved in lawsuits, administrative proceedings and governmental investigations, including environmental, regulatory and other matters. Large and sometimes unspecified damages or penalties may be sought from us in some matters and some matters may require years for us to resolve. We cannot provide assurance that an adverse resolution of one or more of the matters described below during a future reporting period will not have a material adverse effect on our financial position or results of operations in future periods. However, on the basis of existing information, we believe that the resolution of these matters, individually or in the aggregate, will not have a material adverse effect on our financial position or results of operations.
      In November 2003, we filed suit in Contra Costa County Superior Court against Tosco Corporation alleging that Tosco misrepresented, concealed and failed to disclose certain environmental conditions at our California refinery. The court granted Tosco’s motion to compel arbitration of our claims for these certain additional environmental conditions. In the arbitration proceedings we initiated against Tosco in December 2003, we are also seeking a determination that Tosco is liable for investigation and remediation of these certain additional environmental conditions, the amount of which is currently unknown and therefore a reserve has not been established. In response to our arbitration claims, Tosco filed counterclaims in the Contra Costa Superior Court action alleging that we are contractually responsible for certain environmental liabilities at the California refinery, including certain liabilities arising from operations at the California refinery before August 2000. In February 2005, the parties agreed to stay the arbitration proceedings for a period of 90 days to pursue settlement discussions. In the event we are unable to reach settlement, we intend to vigorously prosecute our claims against Tosco and to oppose Tosco’s claims against us, although we cannot provide assurance that we will prevail. For further information related to these claims, see Note P in our consolidated financial statements in Item 8.
      As previously disclosed, we were a defendant in seven pending cases alleging MTBE contamination in groundwater. During the 2004 fourth quarter, we were named as a defendant in seven additional pending cases, of which we obtained a dismissal without prejudice in four of these cases in February 2005. The plaintiffs in each of the remaining 10 pending cases, all in California, are generally water providers, governmental authorities and private well owners alleging that refiners and suppliers of gasoline containing MTBE are liable for manufacturing or distributing a defective product. We are being sued as a refiner, supplier and marketer of gasoline containing MTBE along with other refining industry companies. The suits generally seek individual, unquantified compensatory and punitive damages and attorney’s fees, but we cannot estimate the amount or likelihood of the ultimate resolution of these matters at this time, and accordingly, we have not established a reserve for these cases. We believe we have defenses to these claims and intend to vigorously defend the lawsuits.
      As previously reported, on February 10, 2004, we received a Notice of Violation (“NOV”) from the Northwest Air Pollution Authority (“NWAPA”) for alleged violations of an air permit at our Washington refinery. The NWAPA alleged that the refinery emitted sulfur oxides in excess of the permitted allowable limit. NWAPA and Tesoro settled this matter during the 2004 fourth quarter by completion of the installation of certain emission monitoring equipment at the refinery and without the imposition of a monetary penalty. NWAPA withdrew the NOV.
      We are continuing to negotiate a settlement of approximately 70 NOVs issued by the Bay Area Air Quality Management District. The NOVs allege various violations of air quality requirements at the California refinery between May 2002 and February 2004. We have established reserves for this matter which are not material and we believe that the resolution of this matter will not have a material adverse effect on our financial position or results of operations.
      During the first quarter of 2005, we began settlement discussions with the California Air Resources Board (“CARB”) concerning an NOV we received in October 2004. The NOV, issued by CARB, alleges we offered for sale eleven batches of gasoline in California that did not meet CARB’s gasoline exhaust emission limits. As of December 31, 2004, we could not estimate the amount of any penalties that might be associated with this NOV and accordingly, we did not establish a reserve for this matter. We disagree with factual allegations in

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the NOV and believe that the ultimate resolution of this matter with CARB will not have a material adverse effect on our financial position or results of operations.
      On March 3, 2005 we finalized a settlement with the Bay Area Air Quality Management District and the Contra Costa County District Attorney’s office concerning three NOVs we received in March 2004 in response to odor incidents at our California refinery. We have agreed to pay a civil penalty of $225,000 to resolve this matter.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
      None.
PART II
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
      Our common stock is listed under the symbol “TSO” on the New York Stock Exchange and the Pacific Exchange. The high and low sales prices for our common stock on the New York Stock Exchange during 2004 and 2003 are summarized below:
                                 
    2004   2003
         
Quarters Ended   High   Low   High   Low
                 
March 31
  $ 19.35     $ 14.00     $ 7.44     $ 3.38  
June 30
  $ 27.75     $ 17.75     $ 8.55     $ 6.45  
September 30
  $ 31.70     $ 21.76     $ 9.42     $ 6.65  
December 31
  $ 34.65     $ 27.75     $ 15.12     $ 8.56  
      At March 1, 2005, there were approximately 2,244 holders of record of our 66,461,087 outstanding shares of common stock. We have not paid dividends on our common stock since 1986 and have no present plans to pay dividends on our common stock. For information regarding restrictions on future dividend payments and stock repurchases, see Management’s Discussion and Analysis of Financial Condition and Results of Operations in Item 7 and Notes F and G in our consolidated financial statements in Item 8.
      The 2005 annual meeting of stockholders will be held at 8:00 A.M. Mountain Standard Time on Wednesday, May 4, 2005, at The Boulders, 34631 North Tom Darlington Drive, Phoenix, Arizona. Holders of common stock of record at the close of business on March 14, 2005 are entitled to notice of and to vote at the annual meeting.

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      The following table summarizes, as of December 31, 2004, certain information regarding equity compensation to our employees, officers, directors and other persons under our equity compensation plans.
Equity Compensation Plan Information
                           
            Number of Securities
            Remaining Available for
            Future Issuance under
    Number of Securities to be   Weighted-Average Exercise   Equity Compensation
    Issued upon Exercise of   Price of Outstanding   Plans (Excluding
    Outstanding Options,   Options, Warrants   Securities Reflected in
Plan Category   Warrants and Rights   and Rights   the Second Column)
             
Equity compensation plans approved by security holders
    5,529,960     $ 13.56       1,735,352  
Equity compensation plans not approved by security holders(a)
    356,550     $ 10.11        
                   
 
Total
    5,886,510     $ 13.35       1,735,352  
                   
 
(a) The Key Employee Stock Option Plan was approved by our board of directors in November 1999 and provided for stock option grants to eligible employees who are not our executive officers. The options expire ten years after the date of grant. Our board of directors has suspended any future grants under this plan.
ITEM 6. SELECTED FINANCIAL DATA
      The following table sets forth certain selected consolidated financial and operating data of Tesoro as of the end of and for each of the five years in the period ended December 31, 2004. The selected consolidated financial information presented below has been derived from our historical financial statements. Our financial results include the post-acquisition results of our California operations since mid-May 2002 and our Mid-Continent operations since September 2001. The following table should be read in conjunction with Management’s Discussion and Analysis of Financial Condition and Results of Operations in Item 7 and our consolidated financial statements in Item 8.
                                           
    Years Ended December 31,
     
    2004   2003   2002   2001   2000
                     
    (Dollars in millions except per share amounts)
Statement of Operations Data
                                       
Total Revenues
  $ 12,262     $ 8,846     $ 7,119     $ 5,182     $ 5,067  
                               
Net Earnings (Loss)(a)
  $ 328     $ 76     $ (117 )   $ 88     $ 73  
Preferred Dividend Requirements(b)
                      6       12  
                               
Net Earnings (Loss) Applicable to Common Stock
  $ 328     $ 76     $ (117 )   $ 82     $ 61  
                               
Net Earnings (Loss)
                                       
 
Basic
  $ 5.01     $ 1.18     $ (1.93 )   $ 2.26     $ 1.96  
 
Diluted
  $ 4.76     $ 1.17     $ (1.93 )   $ 2.10     $ 1.75  
Weighted Shares Outstanding (millions):(b)
                                       
 
Basic
    65.5       64.6       60.5       36.2       31.2  
 
Diluted
    68.9       65.1       60.5       41.9       41.8  
(table continued on following page)

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    Years Ended December 31,
     
    2004   2003   2002   2001   2000
                     
    (Dollars in millions except per share amounts)
Balance Sheet Data
                                       
Current Assets
  $ 1,393     $ 1,024     $ 1,054     $ 878     $ 630  
Property, Plant and Equipment, Net
  $ 2,304     $ 2,252     $ 2,303     $ 1,522     $ 781  
Total Assets
  $ 4,075     $ 3,661     $ 3,759     $ 2,662     $ 1,544  
Current Liabilities
  $ 993     $ 687     $ 608     $ 539     $ 382  
Total Debt(c)
  $ 1,218     $ 1,609     $ 1,977     $ 1,147     $ 311  
Stockholders’ Equity(b)(d)
  $ 1,327     $ 965     $ 888     $ 757     $ 670  
Current Ratio
    1.4:1       1.5:1       1.7:1       1.6:1       1.6:1  
Working Capital
  $ 401     $ 337     $ 446     $ 339     $ 248  
Total Debt to Capitalization(b)(c)
    48 %     62 %     69 %     60 %     32 %
Common Stock Outstanding (millions of shares)(b)(d)
    66.8       64.8       64.6       41.4       30.9  
Book Value Per Common Share
  $ 19.87     $ 14.89     $ 13.74     $ 18.28     $ 16.39  
 
Cash Flows From (Used In)
                                       
Operating Activities
  $ 685     $ 447     $ 58     $ 214     $ 90  
Investing Activities
    (174 )     (70 )     (941 )     (976 )     (88 )
Financing Activities(b)(c)
    (403 )     (410 )     941       800       (130 )
                               
Increase (Decrease) in Cash and Cash Equivalents
  $ 108     $ (33 )   $ 58     $ 38     $ (128 )
                               
Capital Expenditures(e)
  $ 179     $ 101     $ 204     $ 210     $ 94  
 
Operating Data
                                       
Refining Throughput (thousand barrels per day)(f)
                                       
 
California
    153       156       95              
 
Pacific Northwest
                                       
   
Washington
    117       112       104       119       117  
   
Alaska
    57       49       53       50       48  
 
Mid-Pacific
                                       
   
Hawaii
    84       80       82       87       84  
 
Mid-Continent
                                       
   
North Dakota
    56       48       51       17        
   
Utah
    53       43       50       17        
                               
     
Total Refining Throughput
    520       488       435       290       249  
                               
Refining Yield (thousand barrels per day)(f)
                                       
 
Gasoline and gasoline blendstocks
    251       239       204       111       95  
 
Jet fuel
    66       58       64       59       58  
 
Diesel fuel
    110       103       87       53       39  
 
Heavy oils, residual products, internally produced fuel and other
    113       107       95       75       65  
                               
     
Total Refining Yield
    540       507       450       298       257  
                               
(table continued on following page)

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    Years Ended December 31,
     
    2004   2003   2002   2001   2000
                     
Product Sales (thousand barrels per day)(f)(g)
                                       
 
Gasoline and gasoline blendstocks
    300       280       264       161       135  
 
Jet fuel
    90       84       94       81       76  
 
Diesel fuel
    133       121       115       73       54  
 
Heavy oils, residual products and other
    81       72       72       61       58  
                               
   
Total Product Sales
    604       557       545       376       323  
                               
Retail Fuel Sales (millions of gallons)
    510       568       790       396       215  
Number of Branded Retail Stations (end of period)
    506       557       593       677       276  
 
(a) For the periods 2004, 2003 and 2002, we incurred various charges, including debt prepayment and refinancing costs, retirement benefits and losses on asset sales, that affect the comparability for each of the five years in the period ended December 31, 2004. For information related to these charges, see “Results of Operations” in Management’s Discussion and Analysis of Financial Condition and Results of Operations in Item 7. In 2001, we incurred charges of $7 million aftertax ($0.17 per share) for financing fees and integration costs, primarily associated with the acquisition of our Mid-Continent refineries.
 
(b) Our mandatory convertible preferred stock automatically converted into 10.35 million shares of common stock in July 2001, which eliminated our $12 million annual preferred dividend requirement. During 2002, we completed a public offering of 23 million common shares to partially fund the acquisition of the California refinery.
 
(c) During 2004, we voluntarily prepaid the remaining $297.5 million outstanding principal balance of the 9% senior subordinated notes and $100 million of our senior secured term loans. During 2003, we replaced our previous credit facility by entering into a new credit agreement, and issued $200 million senior secured term loans due 2008 and $375 million of 8% senior secured notes due 2008. During 2002, we issued $450 million in principal amount of 95/8% senior subordinated notes due 2012 and two 10-year junior subordinated notes with face amounts totaling $150 million, and amended and restated our previous credit facility, primarily to fund the acquisition of the California refinery. In 2001, we issued $215 million of 95/8% senior subordinated notes due 2008 and entered into our previous credit facility, primarily to finance the acquisitions of the Mid-Continent refineries.
 
(d) We have not paid dividends on our common stock since 1986.
 
(e) Capital expenditures exclude amounts for major acquisitions in the refining and retail segments during 2002 and 2001, and for refinery turnaround spending and other major maintenance costs.
 
(f) Volumes for 2002 include amounts from the California refinery since we acquired it on May 17, 2002, averaged over 365 days. Throughput and yield for the California refinery averaged over the 229 days of operation that we owned it were 151 thousand barrels per day (“Mbpd”) and 160 Mbpd, respectively. Volumes for 2001 include amounts from the Mid-Continent operations since we acquired them on September 6, 2001, averaged over 365 days. Throughput and yield for these refineries averaged over the 117 days that we owned them in 2001 were 105 Mbpd and 109 Mbpd, respectively.
 
(g) Sources of total refined product sales include products manufactured at the refineries and products purchased from third parties.

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ITEM 7. 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 45 and “Risk Factors” on page 15 for a discussion of the factors that could cause actual results to differ materially from those projected in these statements.
BUSINESS STRATEGY AND OVERVIEW
      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 in a global market, with the objective to provide stockholders with competitive returns in any economic environment. Beginning in 1998, we entered into a series of acquisitions and strategic initiatives that transformed our competitive position, the composition and geographical focus of our assets and our financial and operating results. We expanded our refining capacity from 72,000 bpd to 558,000 bpd through the acquisition of our Hawaii and Washington refineries in 1998, our North Dakota and Utah refineries in 2001 and our California refinery in 2002. To focus on our refining and marketing business, we sold our oil and gas exploration and production assets in 1999 and our marine services assets in December 2003.
      For 2004, our goals were focused on: (i) improving profitability by achieving greater efficiencies; (ii) using cash flows from operations to further reduce debt; and (iii) allocating capital and turnaround spending to (a) maintain safe, reliable operations meeting EPA Clean Air Act standards, (b) high return, low cost projects and (c) further development of systems and people. During 2004, we achieved the following significant results relative to our 2004 goals, which are further described below under “Results of Operations” and “Capital Resources and Liquidity”:
  •  Operating income improved by $378 million to $713 million compared to 2003, reflecting improved reliability, throughput and higher product margins, together with capturing business improvement initiatives.
 
  •  We used cash flows from operations to prepay both our $297.5 million outstanding principal balance of the 9% senior subordinated notes due 2008 and $100 million of our then outstanding $197.5 million senior secured term loans, resulting in annual pretax interest savings of approximately $34 million. Our debt to capitalization ratio was reduced to 48% at year-end, compared to 62% at the end of 2003.
 
  •  Our capital and turnaround spending totaled $229 million, of which $64 million was for Clean Air projects and $64 million was for reliability and safety projects.
      During 2005, we will continue to focus on the goals established for 2004. In addition, our 2005 executive incentive compensation program includes two financial goals: to realize $62 million of operating income improvements through business improvement initiatives and to achieve earnings of at least $3.85 per diluted share.

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      Several factors during 2004 positively impacted industry margins, including improved economic fundamentals in the U.S. and Far East, heavy refining industry turnaround activity in the western U.S. during the 2004 first quarter and recent changes in product specifications. Increased demand and below average inventory levels for finished products resulted in significantly higher than average industry margins in all of our refining regions. Overall, industry margins during 2004 in our market areas averaged above our five-year average (January 1, 1999 through December 31, 2003). We determine our “five-year average” by comparing prices for gasoline, diesel fuel, jet fuel and heavy fuel oils products to crude oil prices in our market areas, with volumes weighted according to our typical refinery yields. Our net earnings for 2004 also benefited from lower interest expense as a result of debt reduction and refinancing during 2003 and additional debt prepayments during 2004.
RESULTS OF OPERATIONS
Summary
      Our net earnings for 2004 were $328 million ($5.01 per basic share and $4.76 per diluted share), compared with net earnings of $76 million ($1.18 per basic share and $1.17 per diluted share) for 2003. The significant increase in net earnings during 2004 was primarily due to (i) higher refined product margins, (ii) increased throughput levels, (iii) lower interest expense as a result of debt reduction and refinancing in 2003 and additional debt prepayments during 2004, and (iv) our continued focus on capturing business improvement initiatives. Net earnings for 2004 included debt prepayment and financing costs of $14 million aftertax, or $0.20 per share. Our 2004 results also included charges for executive retirement costs of $1 million aftertax, or $0.01 per share. Net earnings for 2003 included the write-off of unamortized debt issuance costs of $23 million aftertax, or $0.35 per share. Our 2003 results also included losses on the sale of our marine services assets and certain retail asset impairments of $6 million aftertax, or $0.09 per share, voluntary early retirement benefits and severance costs of $6 million aftertax, or $0.09 per share, and a charge related to the termination of our funded executive security plan of $5.5 million aftertax, or $0.08 per share.
      Our net earnings for 2003 were $76 million ($1.18 per basic share and $1.17 per diluted share), compared with a net loss of $117 million ($1.93 per basic and diluted share) for 2002. Net earnings for 2003 were primarily the result of improved product margins and the full-year contribution at our California refinery operations. In 2002, charges for bridge financing fees, associated with the acquisition of the California refinery, totaled $8 million aftertax, or $0.14 per share. Our 2002 results also included losses on asset sales and impairment of goodwill, which totaled $5 million aftertax, or $0.08 per share, and severance and integration costs of $5 million aftertax, or $0.08 per share. In 2002, our income tax refund claims reduced previously recognized income tax credits by $6 million, or $0.10 per share, and a LIFO inventory liquidation resulted in decreased costs of sales of $3 million aftertax, or $0.05 per share.
      A discussion and analysis of the factors contributing to our results of operations is presented below. The accompanying consolidated financial statements in Item 8, together with the following information, are intended to provide investors with a reasonable basis for assessing our historical operations, but should not serve as the only criteria for predicting our future performance.

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Refining Segment
                               
    2004   2003   2002
             
    (Dollars in millions except per
    barrel amounts)
Revenues
                       
 
Refined products(a)
  $ 11,633     $ 8,098     $ 6,426  
 
Crude oil resales and other
    419       370       335  
                   
   
Total Revenues
  $ 12,052     $ 8,468     $ 6,761  
                   
Refining Throughput (thousand barrels per day)(b)
                       
 
California(c)
    153       156       95  
 
Pacific Northwest
                       
   
Washington
    117       112       104  
   
Alaska
    57       49       53  
 
Mid-Pacific
                       
   
Hawaii
    84       80       82  
 
Mid-Continent
                       
   
North Dakota
    56       48       51  
   
Utah
    53       43       50  
                   
     
Total Refining Throughput
    520       488       435  
                   
% Heavy Crude Oil of Total Refining Throughput(d)
    50 %     58 %     49 %
                   
Yield (thousand barrels per day)(c)
                       
 
Gasoline and gasoline blendstocks
    251       239       204  
 
Jet Fuel
    66       58       64  
 
Diesel Fuel
    110       103       87  
 
Heavy oils, residual products, internally produced fuel and other
    113       107       95  
                   
     
Total Yield
    540       507       450  
                   
Refining Margin ($/throughput barrel)(e)
                       
 
California
                       
   
Gross refining margin
  $ 13.98     $ 9.63     $ 6.41  
   
Manufacturing cost before depreciation and amortization
  $ 5.07     $ 4.41     $ 4.17  
 
Pacific Northwest
                       
   
Gross refining margin
  $ 7.99     $ 6.19     $ 4.09  
   
Manufacturing cost before depreciation and amortization
  $ 2.38     $ 2.26     $ 2.05  
 
Mid-Pacific
                       
   
Gross refining margin
  $ 5.30     $ 3.30     $ 2.85  
   
Manufacturing cost before depreciation and amortization
  $ 1.51     $ 1.39     $ 1.39  
 
Mid-Continent
                       
   
Gross refining margin
  $ 7.02     $ 5.68     $ 4.17  
   
Manufacturing cost before depreciation and amortization
  $ 2.28     $ 2.52     $ 2.22  
 
Total
                       
   
Gross refining margin
  $ 9.12     $ 6.73     $ 4.38  
   
Manufacturing cost before depreciation and amortization
  $ 3.01     $ 2.85     $ 2.43  

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    2004   2003   2002
             
    (Dollars in millions except per
    barrel amounts)
Segment Operating Income
                       
 
Gross refining margin (after inventory changes)(c)(f)
  $ 1,706     $ 1,196     $ 699  
 
Expenses
                       
   
Manufacturing costs
    573       509       386  
   
Other operating expenses
    141       129       104  
   
Selling, general and administrative
    22       27       32  
   
Depreciation and amortization(g)
    130       120       104  
                   
     
Segment Operating Income
  $ 840     $ 411     $ 73  
                   
Product Sales (thousand barrels per day)(a)(h)
                       
 
Gasoline and gasoline blendstocks
    300       280       264  
 
Jet fuel
    90       84       94  
 
Diesel fuel
    133       121       115  
 
Heavy oils, residual products and other
    81       72       72  
                   
   
Total Product Sales
    604       557       545  
                   
Product Sales Margin ($/barrel)(h)
                       
 
Average sales price
  $ 52.65     $ 39.81     $ 32.25  
 
Average costs of sales
    44.74       33.99       28.75  
                   
   
Product Sales Margin
  $ 7.91     $ 5.82     $ 3.50  
                   
 
(a) Includes intersegment sales to our retail segment, at prices which approximate market, of $785 million, $696 million and $826 million in 2004, 2003 and 2002, respectively.
 
(b) We experienced reduced throughput during planned major maintenance turnarounds for the following refineries: the California refinery during 2004; the Alaska, North Dakota and Utah refineries during 2003; and the California and Washington refineries during 2002.
 
(c) Volumes and margins for 2002 include amounts for the California operations since acquisition on May 17, 2002, averaged over 365 days. Throughput and yield for the California refinery averaged over the 229 days of operation were 151 thousand barrels per day (“Mbpd”) and 160 Mbpd, respectively.
 
(d) We define “heavy” crude oil as Alaska North Slope or crude oil with an American Petroleum Institute specific gravity of 32 or less.
 
(e) Management uses gross refining margin per barrel to evaluate performance, allocate resources and compare profitability to other companies in the industry. Gross refining margin per barrel is calculated by dividing gross refining margin by total refining throughput and may not be calculated similarly by other companies. Management uses manufacturing costs per barrel to evaluate the efficiency of refinery operations and allocate resources. Manufacturing costs per barrel may not be comparable to similarly titled measures used by other companies. Investors and analysts use these financial measures to help analyze and compare companies in the industry on the basis of operating performance. These financial measures should not be considered as alternatives to segment operating income, revenues, costs of sales and operating expenses or any other measure of financial performance presented in accordance with accounting principles generally accepted in the United States of America.
 
(f) Gross refining margin is calculated as revenues less costs of feedstocks, purchased products, transportation and distribution. Gross refining margin approximates total refining segment throughput times gross refining margin per barrel, adjusted for changes in refined product inventory due to selling a volume and mix of product that is different than actual volumes manufactured. Gross refining margin also includes the effect of intersegment sales to the retail segment at prices which approximate market. In addition, during 2002, certain inventory quantities were reduced resulting in the liquidation of applicable LIFO

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inventory quantities carried at lower costs. This reduction in LIFO inventory decreased costs of sales by approximately $5 million and decreased our net loss by $3 million in 2002.
 
(g) Includes manufacturing depreciation and amortization per throughput barrel of approximately $0.61, $0.59 and $0.56 for 2004, 2003 and 2002, respectively.
 
(h) Sources of total product sales include products manufactured at the refineries and products purchased from third parties. Total product sales margin includes margins on sales of manufactured and purchased products and the effects of inventory changes.

      2004 Compared to 2003 — Operating income from our refining segment increased to $840 million in 2004 compared to $411 million in 2003. The $429 million increase in our operating income primarily resulted from significantly higher refined product margins, combined with higher throughput levels and product sales volumes. Our total gross refining margin per barrel increased 36% to $9.12 per barrel in 2004 compared to $6.73 per barrel in 2003, reflecting higher per-barrel refining margins in all of our regions. Industry margins on a national basis improved primarily due to increased demand and below average inventory levels for finished products. Improved economic fundamentals in the U.S. and Far East resulted in increased demand and margins for finished products and reduced finished product inventory levels. Heavy refining industry turnaround activity in the PADD V region during the first quarter of 2004 reduced finished product inventory levels on the U.S. West Coast. Furthermore, U.S. West Coast gasoline supplies tightened in part due to the elimination of the oxygenate MTBE. Margins were lower in all of our refining regions excluding California for the fourth quarter of 2004, compared to the third quarter, primarily due to lower seasonal demand for refined products and higher average crude oil prices. While refining margins in the California region increased during the fourth quarter as compared to the third quarter, we were unable to fully capture these margins due to scheduled downtime at the California refinery as discussed below.
      On an aggregate basis, our total gross refining margins increased from $1.2 billion in 2003 to $1.7 billion in 2004, reflecting higher per-barrel gross refining margins in all of our regions and higher total refining throughput volumes. Total refining throughput averaged 520 Mbpd in 2004, an increase of 32 Mbpd or 7% from 2003, despite scheduled turnarounds at our California refinery, which were completed during the 2004 fourth quarter, and unscheduled downtime in the 2004 first quarter due to a short-term power outage and accelerated maintenance of the hydrogen plant. Primarily due to the scheduled and unscheduled downtime at the California refinery, the percentage of lower cost heavy crude oil that we processed of total refining throughput decreased from 58% in 2003 to 50% in 2004. We estimate that our refining operating income would have been approximately $65 million higher during the 2004 fourth quarter, and approximately $34 million higher during the 2004 third quarter had the California refinery been fully operational. In addition, our refining margins at our Pacific Northwest refineries were negatively impacted during the 2004 third and fourth quarters as the increased differential between light and heavy crude oil depressed the margins for heavy fuel oils. In 2003, our Alaska, North Dakota and Utah refineries experienced reduced throughput during planned major maintenance turnarounds.
      Revenues from sales of refined products increased 43% to $11.6 billion in 2004, from $8.1 billion in 2003, primarily due to significantly higher average product sales prices and slightly higher product sales volumes. Our average product prices increased 32% to $52.65 per barrel and total product sales increased by 8% to average 604 Mbpd in 2004 from 2003. Costs of sales also increased primarily due to higher average feedstock prices and slightly higher product sales volumes as compared with 2003. Expenses, excluding depreciation and amortization, increased to $736 million in 2004, from $665 million in 2003, primarily due to increased maintenance, utilities and employee costs of approximately $57 million. We estimate that the scheduled turnarounds at our California refinery described above resulted in additional operating expenses of approximately $10 million in 2004, included in the estimated $65 million of lower refining operating income described above.
      Refining throughput and yields in 2005 will be affected by scheduled major maintenance turnarounds at our California and Washington refineries in the first quarter and the Hawaii refinery in the second quarter. In addition, refining throughput was reduced during January 2005 due to unscheduled downtime at our California refinery. We estimate that our refining operating income was impacted negatively by approximately $8 million. We currently expect total refining throughput to average approximately 520 to 525 Mbpd in 2005.

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      2003 Compared to 2002 — Operating income from our refining segment was $411 million in 2003 compared to $73 million in 2002. Our results for 2003 included a complete year of operating income from the California refinery acquired in mid-May 2002. The California operations contributed approximately $214 million to our refining operating income during 2003 compared to approximately $37 million during 2002.
      Our total gross refining margin increased from $699 million ($4.38 per barrel) in 2002 to $1.2 billion ($6.73 per barrel) in 2003, reflecting higher per-barrel gross refining margins in all of our regions and additional throughput volumes from the California refinery, which added an additional 61 Mbpd to our total refining throughput in 2003 compared to 2002. Furthermore, U.S. West Coast gasoline supplies tightened partially due to changes in gasoline specifications related to the phase-out of MTBE in California. Our Pacific Northwest margins also improved compared to 2002 when, during the first quarter, the Washington refinery was in a major maintenance turnaround and its heavy oil conversion project was being completed. The percentage of lower cost heavy crude oil that we processed of total refining throughput increased from 49% in 2002 to 58% in 2003, primarily reflecting the additional throughput from the California refinery and completion of our heavy oil conversion project at our Washington refinery. Industry margins on a national basis remained volatile during 2003; however, they improved compared to 2002, primarily due to increased demand and below average inventory levels for finished products. The cold winter in 2003 increased demand and margins for distillates during the first quarter. Also, maintenance and operating problems at several other refineries in the industry reduced overall industry finished product inventory levels in 2003. During 2002, the refining industry in our market areas experienced the lowest refined product margins since 1998. Margins were lower in all of our refining regions for the fourth quarter of 2003, compared to the third quarter, due to low seasonal demand for refined products and rapidly rising crude oil prices.
      Revenues from sales of refined products increased 26% to $8.1 billion in 2003, from $6.4 billion in 2002, due to increased sales volumes from the California refinery and higher average product sales prices. Total product sales averaged 557 Mbpd in 2003, as compared to 545 Mbpd in 2002, and average product prices increased 23% to $39.81 per barrel. Costs of sales also increased due to the additional volumes from the California refinery and higher average prices for refinery feedstocks and purchased product supplies compared with 2002.
      Expenses, excluding depreciation, increased to $665 million in 2003, from $522 million in 2002, primarily due to additional operating expenses of approximately $123 million from the California refinery and increased costs for utilities, revenue-based taxes and performance bonus expense. Depreciation and amortization increased to $120 million, primarily due to operating the California refinery for the full year.

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Retail Segment
                               
    2004   2003   2002
             
    (Dollars in millions except
    per gallon amounts)
Revenues(a)
                       
 
Fuel
  $ 863     $ 797     $ 920  
 
Merchandise and other
    131       121       132  
                   
   
Total Revenues
  $ 994     $ 918     $ 1,052  
                   
Fuel Sales (millions of gallons)(a)
    510       568       790  
Fuel Margin ($/gallon)(b)
  $ 0.16     $ 0.18     $ 0.12  
Merchandise Margin (in millions)(a)
  $ 35     $ 31     $ 35  
Merchandise Margin (percent of sales)
    28 %     27 %     27 %
Average Number of Stations (during the period)(a)
                       
 
Company-operated
    222       229       260  
 
Branded jobber/ dealer
    316       346       419  
                   
   
Total Average Retail Stations
    538       575       679  
                   
Segment Operating Income (Loss)
                       
 
Gross Margins
                       
   
Fuel(c)
  $ 79     $ 101     $ 95  
   
Merchandise and other non-fuel margin
    39       35       40  
                   
     
Total gross margins
    118       136       135  
 
Expenses
                       
   
Operating expenses
    76       71       99  
   
Selling, general and administrative
    26       30       31  
   
Depreciation and amortization
    18       19       17  
                   
     
Segment Operating Income (Loss)
  $ (2 )   $ 16     $ (12 )
                   
 
(a) In December 2002, we sold 70 company-operated stations that were acquired in May 2002 with the California refinery. In 2002, 150 BP/Amoco branded independent jobber/ dealer stations acquired in the Mid-Continent acquisition did not rebrand to Tesoro®.
 
(b) Management uses fuel margin per gallon to compare profitability to other companies in the industry. Fuel margin per gallon is calculated by dividing fuel gross margin by fuel sales volumes and may not be calculated similarly by other companies. Investors and analysts use fuel margin per gallon to help analyze and compare companies in the industry on the basis of operating performance. This financial measure should not be considered as an alternative to segment operating income and revenues or any other financial measure of financial performance presented in accordance with accounting principles generally accepted in the United States of America.
 
(c) Includes the effect of intersegment purchases from our refining segment at prices which approximate market.
      2004 Compared to 2003 — The operating loss for our retail segment was $2 million in 2004 compared to operating income of $16 million in 2003. Total gross margins decreased to $118 million during 2004 from $136 million in 2003, reflecting lower fuel margins per gallon and lower sales volumes. Fuel margin decreased to $0.16 per gallon in 2004 from $0.18 per gallon in 2003, reflecting higher average prices of purchased fuel. Total gallons sold decreased to 510 million from 568 million, reflecting the decrease in average station count to 538 in 2004 from 575 in 2003 due to our continued rationalization of retail assets.

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      Revenues on fuel sales increased to $863 million in 2004 from $797 million in 2003, reflecting increased sales prices, primarily offset by lower sales volumes. Costs of sales increased in 2004 due to higher average prices of purchased fuel, partly offset by lower sales volumes. Operating, selling, general and administrative expenses remained flat in 2004, as compared to 2003.
      2003 Compared to 2002 — Operating income for our retail segment improved by $28 million to $16 million in 2003, compared to an operating loss of $12 million in 2002. Total gross margins were $136 million in 2003 compared to $135 million in 2002 reflecting higher fuel margin per gallon, largely offset by lower sales volumes. Fuel margin increased to $0.18 per gallon in 2003 from $0.12 per gallon in 2002, reflecting increased demand, lower inventories and our efforts to improve operations. Total gallons sold decreased to 568 million, reflecting the decrease in average station count to 575 in 2003 from 679 in 2002. The decrease primarily was due to selling 70 company-operated stations in December 2002 (acquired with the California refinery in mid-May 2002) and the fact that 150 BP/Amoco branded independent jobber/ dealer stations (included in the 2001 acquisition of the Mid-Continent refining and retail assets) did not rebrand to the Tesoro® brand.
      Revenues on fuel sales decreased to $797 million in 2003, from $920 million in 2002, reflecting lower sales volumes from fewer stations, partly offset by increased sales prices. Costs of sales also decreased in 2003 due to lower sales volumes, partly offset by higher prices of purchased fuel. The decrease in operating, selling, general and administrative expenses to $101 million in 2003 from $130 million in 2002 reflects our initiatives to reduce expenses and the decrease in average station count.
Marine Services
      In December 2003, we sold substantially all of the physical assets of marine services. Operating income increased to $6 million during 2003 from $2 million in 2002, reflecting higher sales volume and margins, and lower operating expenses. These operations depended largely on the volume of oil and gas drilling, workover, construction and seismic activity in the Gulf of Mexico. See Note D and Note E in our consolidated financial statements in Item 8 for information related to our sale of marine services in 2003 and summarized financial information, respectively.
Selling, General and Administrative Expenses
      Selling, general and administrative expenses of $152 million in 2004 increased from $138 million in 2003. The increase was primarily due to an additional $20 million for stock-based and other incentive-based compensation, as well as higher professional fees of approximately $11 million for projects related to driving business excellence. During 2003, we incurred charges totaling $17 million for voluntary early retirement benefits, severance costs and the termination of our funded executive security plan. During the fourth quarter of 2004, we expensed $2 million associated with the announced retirement of certain executive officers. The 2005 first quarter will include charges totaling approximately $10 million, primarily related to the termination of certain executive officers. See Notes A and O of the consolidated financial statements in Item 8 for further information regarding the adoption of the fair value method of accounting for stock options during 2004 and other stock-based awards granted in 2004.
      Selling, general and administrative expenses of $138 million in 2003 increased from $133 million in 2002. The increase was due to retirement and plan termination charges, as discussed above, totaling $17 million. Excluding these charges, we reduced selling, general and administrative expenses by approximately $12 million, through our cost reduction initiatives. This reduction in expense was net of employees’ performance bonuses in 2003, which were not awarded in 2002.
Loss on Asset Sales and Impairments
      The loss on asset sales and impairments of $14 million in 2004 consisted primarily of the write-off of certain refinery assets that were replaced in connection with the California refinery turnaround of $8 million and the impairment of certain retail assets. During 2003, the loss on asset sales and impairments of $17 million consisted primarily of the loss on the sale of marine services assets of $8 million, the write-off of certain

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refinery assets that were replaced, and the impairment of certain retail assets. During 2002, the loss on asset sales and impairments of $8 million consisted primarily of losses on the sale of retail stations and an impairment of retail goodwill. See Note D in our consolidated financial statements in Item 8.
Interest and Financing Costs
      Interest and financing costs were $167 million in 2004 compared to $212 million in 2003. The $45 million decrease in 2004 was due primarily to lower interest expense associated with debt reduction during 2004 and 2003 totaling $778 million. The decrease was also due to the write-off of $36 million of unamortized debt issuance costs in 2003 in connection with the replacement of our previous credit facility and voluntary prepayments of other debt. The decrease during 2004 was partly offset by debt prepayment and financing costs totaling $23 million, primarily associated with our voluntary debt prepayments totaling $397.5 million.
      Interest and financing costs were $212 million in 2003 compared to $163 million in 2002. The increase was due primarily to the write-off of $36 million of unamortized debt issuance costs, as discussed above, as well as interest on additional debt that we incurred in May 2002 to finance the acquisition of our California refinery.
Income Tax Provision (Benefit)
      The income tax provision amounted to $219 million in 2004 compared to $47 million in 2003. The increase reflects significantly higher earnings before income taxes. The income tax benefit of $64 million in 2002 reflects the pretax loss for 2002. The combined federal and state effective income tax rates were approximately 40%, 38% and 35% in 2004, 2003 and 2002, respectively. The increase in our federal and state effective income tax rate during 2004 was primarily due to a change in California state tax law, which eliminated an investment tax credit that had been available in previous years. In 2002, we elected to carry back net operating losses to recover income taxes paid in previous years; however, the refund of those taxes resulted in the loss of certain tax credits. The expiration of these credits, along with other adjustments to our estimated liabilities, resulted in a reduced tax benefit of approximately $6 million in 2002.
CAPITAL RESOURCES AND LIQUIDITY
Overview
      We operate in an environment where our capital resources and liquidity 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 geo-political conditions and overall market and economic conditions. See “Forward-Looking Statements” on page 45 and “Risk Factors” on page 15 for further information related to risks and other factors. Future capital expenditures, as well as borrowings under our credit agreement and other sources of capital, may be affected by these conditions.
      Our primary sources of liquidity have been cash flows from operations and borrowing availability under revolving lines of credit. We ended 2004 with $185 million of cash and cash equivalents, no borrowings under our revolving credit facility, and $409 million in available borrowing capacity under our credit agreement after $341 million in outstanding letters of credit. Our letters of credit outstanding at December 31, 2004 increased from $232 million at the end of 2003 due to increased foreign crude oil purchases and higher average feedstock prices. We prepaid our $297.5 million outstanding principal balance of our 9% senior subordinated notes and $100 million of our then outstanding $197.5 million senior secured term loans during 2004. The prepayments will result in annual pretax interest savings of approximately $34 million. Since May 2002, including the debt prepayments during 2004, we have reduced debt by nearly $900 million, decreasing our debt to capitalization ratio from 69% at June 30, 2002 to 48% at December 31, 2004. We believe available capital resources will be adequate to meet our capital expenditures, working capital and debt service requirements.

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Capitalization
      Our capital structure at December 31, 2004 was comprised of (in millions):
             
Debt, including current maturities:
       
 
Credit Agreement — Revolving Credit Facility
  $  
 
Senior Secured Term Loans
    97.0  
 
8% Senior Secured Notes Due 2008
    372.3  
 
95/8% Senior Subordinated Notes Due 2012
    429.0  
 
95/8% Senior Subordinated Notes Due 2008
    211.0  
 
Junior subordinated notes due 2012
    83.2  
 
Capital lease obligations and other
    25.8  
       
   
Total debt
    1,218.3  
Stockholders’ equity
    1,327.1  
       
   
Total Capitalization
  $ 2,545.4  
       
      At December 31, 2004, our debt to capitalization ratio was 48%, compared to 62% at year-end 2003, reflecting voluntary prepayments and scheduled payments of debt totaling $401 million and net earnings of $328 million during 2004.
      Our credit agreement, senior secured term loans and senior notes impose various restrictions and covenants as described below that could potentially limit our ability to respond to market conditions, raise additional debt or equity capital, or take advantage of business opportunities.
Credit Agreement
      In September 2004, we amended our credit agreement to (i) increase its capacity an additional $100 million to $750 million, (ii) modify the amount of permitted restricted payments and subordinated debt repayments and (iii) reduce the applicable margins on revolver borrowings. In addition, the amendment provides the flexibility to obtain up to $250 million in letters of credit outside of the credit agreement for foreign crude oil purchases. The credit agreement was previously amended in May 2004 to increase its capacity by $150 million to $650 million and to extend the term by one year to June 2007.
      The credit agreement currently provides for borrowings (including letters of credit) up to the lesser of the agreement’s total capacity, $750 million as amended, or the amount of a periodically adjusted borrowing base ($813 million as of December 31, 2004), consisting of Tesoro’s eligible cash and cash equivalents, receivables and petroleum inventories, as defined. As of December 31, 2004, we had no borrowings and $341 million in letters of credit outstanding under the revolving credit facility, resulting in total unused credit availability of $409 million, or 55% of the eligible borrowing base. Borrowings under the revolving credit facility bear interest at either a base rate (5.25% at December 31, 2004) or a eurodollar rate (2.49% at December 31, 2004), plus an applicable margin. The applicable margins at December 31, 2004 were 0.25% in the case of the base rate and 2.00% in the case of the eurodollar rate and vary based on credit facility availability. Letters of credit outstanding under the revolving credit facility incur fees at an annual rate tied to the eurodollar rate applicable margin, in the range of 1.75% to 2.00% at December 31, 2004.
      The credit agreement contains covenants and conditions that, among other things, limit our ability to pay cash dividends, incur indebtedness, create liens and make investments. Tesoro is also required to maintain specified levels of fixed charge coverage and tangible net worth. We are not required to maintain the fixed charge coverage ratio if unused credit availability exceeds 15% of the eligible borrowing base. The credit agreement is guaranteed by substantially all of Tesoro’s active subsidiaries and is secured by substantially all of Tesoro’s cash and cash equivalents, petroleum inventories and receivables.

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Senior Secured Term Loans
      In April 2003, we entered into $200 million senior secured term loans and in September 2004, we voluntarily prepaid $100 million of our senior secured term loans at a prepayment premium of 3%. The prepayment resulted in a pretax charge during 2004 of $5 million, comprising $3 million for the 3% prepayment premium and $2 million for the write-off of unamortized debt issuance costs. As a result of the prepayment, the term loan will mature in October 2007, prior to its original maturity date of April 2008. Principal payments of the term loans are repaid in quarterly installments of $500,000 through April 2007, and the remaining principal payments of $48 million and $44 million are payable in July 2007 and October 2007, respectively. The term loans are subject to optional redemption by Tesoro at premiums of 3% through April 14, 2005, 1% from April  15, 2005 to April 14, 2006, and at par thereafter.
      The term loans contain covenants and restrictions that are less restrictive than those in the credit agreement. The term loans and the 8% senior secured notes, described below, are equally secured by substantially all of the Tesoro’s refining property, plant and equipment and are guaranteed by substantially all of Tesoro’s active subsidiaries. The interest rate on the term loans at December 31, 2004 was 7.99%. Borrowings under the term loans bear interest at either a base rate (5.25% at December 31, 2004) or a eurodollar rate (2.49% at December 31, 2004), plus an applicable margin. The applicable margins for the term loans were 4.5% in the case of the base rate and 5.5% in the case of the eurodollar rate at December 31, 2004.
8% Senior Secured Notes Due 2008
      In April 2003, Tesoro issued $375 million aggregate principal amount of 8% senior secured notes due April 15, 2008. The notes have a five-year maturity with no sinking fund requirements and are subject to optional redemption by Tesoro, beginning April 15, 2006, at a premium of 4% through April 14, 2007, and at par thereafter. We have the right to redeem up to 35% of the aggregate principal amount at a redemption price of 108% with proceeds from certain equity issuances through April 15, 2006. The indenture for the notes contains covenants and restrictions that are customary for notes of this nature and are similar to the covenants in the indentures for Tesoro’s senior subordinated notes. The notes and the term loans are equally secured by substantially all of Tesoro’s refining property, plant and equipment and are guaranteed by substantially all of Tesoro’s active subsidiaries. The notes were issued at 98.994% of par, resulting in net proceeds of $371.2 million before debt issuance costs. The effective interest rate on the notes is 8.25%, after giving effect to the discount.
Senior Subordinated Notes
      In April 2002, we issued $450 million principal amount of 95/8% senior subordinated notes due April 1, 2012. The notes have a ten-year maturity with no sinking fund requirements and are subject to optional redemption by Tesoro beginning April 1, 2007 at premiums of 4.8% through March 31, 2008, 3.2% from April 1, 2008 to March 31, 2009, 1.6% from April 1, 2009 to March 31, 2010, and at par thereafter.
      In November 2001, we issued $215 million principal amount of 95/8% senior subordinated notes due November 1, 2008. The notes have a seven-year maturity with no sinking fund requirements and are subject to optional redemption by Tesoro beginning November 1, 2005 at premiums of 4.8% through October 31, 2006, 2.4% from November 1, 2006 to October 31, 2007, and at par thereafter.
      The indentures for our senior subordinated notes contain covenants and restrictions which are customary for notes of this nature. These covenants and restrictions limit, among other things, our ability to:
  •  pay dividends and other distributions with respect to our capital stock and purchase, redeem or retire our capital stock;
 
  •  incur additional indebtedness and issue preferred stock;
 
  •  sell assets unless the proceeds from those sales are used to repay debt or are reinvested in our business;
 
  •  incur liens on assets to secure certain debt;

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  •  engage in certain business activities;
 
  •  engage in certain merger or consolidations and transfers of assets; and
 
  •  enter into transactions with affiliates.
      The indentures also limit our subsidiaries’ ability to create restrictions on making certain payments and distributions. The senior subordinated notes are guaranteed by substantially all of our active domestic subsidiaries.
Junior Subordinated Notes Due 2012
      In connection with our acquisition of the California refinery, we issued to the seller two ten-year junior subordinated notes with face amounts aggregating $150 million. The notes consist of: (i) a $100 million junior subordinated note, due July 2012, which is non-interest bearing through May 16, 2007 and carries a 7.5% interest rate thereafter, and (ii) a $50 million junior subordinated note, due July 2012, which bears interest at 7.47% from May 17, 2003 through May 16, 2007 and 7.5% thereafter. The junior subordinated notes were recorded initially at a combined present value of approximately $61 million, discounted at a rate of 15.625% and 14.375%, respectively. The discount is being amortized over the term of the notes.
Cash Flow Summary
      Components of our cash flows are set forth below (in millions):
                           
    2004   2003   2002
             
Cash Flows From (Used In):
                       
 
Operating Activities
  $ 685     $ 447     $ 58  
 
Investing Activities
    (174 )     (70 )     (941 )
 
Financing Activities
    (403 )     (410 )     941  
                   
Increase (Decrease) in Cash and Cash Equivalents
  $ 108     $ (33 )   $ 58  
                   
      Net cash from operating activities during 2004 totaled $685 million, compared to $447 million from operating activities in 2003. The increase was primarily due to significantly improved earnings. Net cash used in investing activities of $174 million in 2004 was primarily for capital expenditures. Net cash used in financing activities of $403 million in 2004 primarily reflects the debt prepayments made during the year. Gross borrowings and repayments under the revolving credit facility amounted to $112 million during 2004, all of which occurred during the 2004 first quarter. Working capital totaled $401 million at December 31, 2004 compared to $337 million at December 31, 2003, as a result of increases in cash and cash equivalents, receivables and inventories, partially offset by increases in payables, attributable to increases in sales volumes and crude and product prices.
      Net cash from operating activities during 2003 totaled $447 million, compared to $58 million from operating activities in 2002. The increase was primarily due to improved earnings before depreciation and amortization, the collection of income tax refunds and lower working capital requirements. Net cash used in investing activities of $70 million in 2003 was primarily for capital expenditures partially offset by proceeds from the sale of marine services assets. Net cash used in financing activities of $410 million in 2003 was primarily for voluntary debt prepayments under a previous term loan, other debt repayments, and financing costs related to the credit agreement. Gross borrowings and repayments under revolving credit lines amounted to $1.0 billion during 2003. Working capital totaled $337 million at December 31, 2003 compared to $446 million at December 31, 2002, reflecting an increase in accounts payable and accrued liabilities of $145 million, partly offset by decreases in the current maturities of debt and income taxes receivable. The increase in our accounts payable reflects the decrease in early payments and prepayments on crude oil and product purchases as a result of our increased use of letters of credit.
      Net cash from operating activities during 2002 totaled $58 million. Net cash used in investing activities of $941 million in 2002 included $932 million for the acquisition of the California refinery and $204 million for

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capital expenditures, partially offset by $207 million in proceeds from asset sales. Net cash from financing activities of $941 million in 2002 included net proceeds of $245 million from our equity offering, net proceeds of $441 million from our notes offering and borrowings of $425 million under our previous senior secured credit facility, partly offset by repayments of debt of $133 million and financing costs of $37 million. Gross borrowings and repayments under revolving credit lines amounted to $624 million during 2002.
Historical EBITDA
      EBITDA represents earnings before interest and financing costs, income taxes, and depreciation and amortization. We present EBITDA because we believe some investors and analysts use EBITDA to help analyze our liquidity including 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 by some investors and analysts to analyze and compare companies on the basis of operating performance. EBITDA is also used for internal analysis and as a component of the fixed charge coverage financial covenant in our 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 of America. EBITDA may not be comparable to similarly titled measures used by other entities. Our annual historical EBITDA reconciled to net cash from operating activities was (in millions):
                             
    2004   2003   2002
             
Net Cash from Operating Activities
  $ 685.3     $ 447.3     $ 57.8  
Changes in Assets and Liabilities
    (45.6 )     (95.1 )     (5.6 )
Deferred Income Taxes
    (102.4 )     (55.5 )     (3.3 )
Stock-based Compensation
    (14.2 )            
Loss on Asset Sales and Impairments
    (14.1 )     (16.9 )     (8.4 )
Amortization and Write-off of Debt Issuance Costs and Discounts
    (27.0 )     (55.5 )     (26.8 )
Depreciation and Amortization
    (154.1 )     (148.2 )     (130.7 )
                   
 
Net Earnings (Loss)
  $ 327.9     $ 76.1     $ (117.0 )
 
Add Income Tax Provision (Benefit)
    218.7       47.0       (64.3 )
 
Add Interest and Financing Costs, Net
    166.6       211.7       162.6  
                   
   
Operating Income (Loss)
    713.2       334.8       (18.7 )
 
Add Depreciation and Amortization
    154.1       148.2       130.7  
                   
   
EBITDA
  $ 867.3     $ 483.0     $ 112.0  
                   
      Historical EBITDA as presented above differs from EBITDA as defined under our credit agreement. The primary differences are non-cash postretirement benefit costs and loss on asset sales and impairments, which are added to net earnings (loss) under the credit agreement EBITDA calculations.
Capital Expenditures and Refinery Turnaround Spending
      Our capital expenditures and refinery turnaround spending totaled $229 million during 2004, compared to $152 million in 2003 as discussed below.
Capital Expenditures
      During 2004, our capital expenditures (excluding refinery turnaround and other major maintenance costs), totaled $179 million, primarily for various clean air, clean fuels and other environmental projects of $83 million and refinery improvements at our California refinery of $56 million, which included control systems modernization totaling $12 million. Other capital spending was primarily for various refinery

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improvements. See “Environmental and Other” below for additional information regarding capital spending for our clean air, clean fuels and other environmental projects.
      Based on our latest estimate, we expect our capital expenditures to total approximately $225 to $235 million in 2005 (excluding refinery turnaround and other major maintenance costs of approximately $55 million). The capital budget for the refining segment is $185 million, including $85 million for clean air and clean fuel projects, $25 million for control systems modernization and tank reconstruction projects at the California refinery, and other refining projects totaling $75 million. Our retail capital budget is $15 million for 2005. We expect to fund the 2005 capital spending program from cash flows from operations.
Refinery Turnaround and Other Major Maintenance
      During 2004, we spent $50 million for refinery turnarounds and other major maintenance, including $46 million for our scheduled refinery turnarounds. We expect to spend approximately $55 million in 2005 for refinery turnarounds and other major maintenance, including $48 million for scheduled refinery turnarounds primarily at our California, Washington and Hawaii refineries. Based on our latest estimates, we expect our annual spending for refinery turnarounds to be as follows (in millions):
                                                   
    2004                    
Refinery   Actual   2005   2006   2007   2008   2009
                         
California
  $ 42     $ 23     $ 33     $ 50     $ 6     $ 27  
Washington
    2       14       4       22       2       1  
Alaska
                9                   9  
Hawaii
    2       9       3       2       1        
North Dakota
          1       2             2       17  
Utah
          1       12       2       8        
                                     
 
Total
  $ 46     $ 48     $ 63     $ 76     $ 19     $ 54  
                                     
Long-Term Commitments
Contractual Commitments
      We have numerous contractual commitments for purchases of crude oil feedstocks, services associated with the operation of our refineries, debt service, pension obligations and leases (see Notes F, N and P in our consolidated financial statements in Item 8). We also have contractual commitments for capital spending requirements related primarily to refinery improvements and environmental projects.
      The following table summarizes our annual contractual commitments as of December 31, 2004 (in millions):
                                                   
Contractual Obligation   2005   2006   2007   2008   2009   Thereafter
                         
Long-term debt obligations(1)
  $ 105     $ 105     $ 198     $ 674     $ 53     $ 710  
Capital lease obligations
    4       4       4       3       3       33  
Operating lease obligations(2)
    111       78       75       64       54       168  
Purchase obligations(3)
    2,989       388                          
Other long-term obligations(4)
    81       80       57       29       18       42  
Capital expenditure obligations
    100                                
Projected pension contributions(5)
    12       16       29       28       28        
                                     
 
Total Contractual Obligations
  $ 3,402     $ 671     $ 363     $ 798     $ 156     $ 953  
                                     
 
(1)  Includes maturities of principal and estimated interest payments, excluding capital lease obligations. Interest on our floating-rate debt was estimated using the stated interest rate at December 31, 2004.

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Amounts and timing may be different from our estimated commitments due to potential voluntary debt prepayments and interest rate fluctuations.
 
(2)  Represents our future minimum lease commitments for operating leases. Lease commitments for 2005 include lease arrangements with initial terms of less than one year.
 
(3)  Represents an estimate of our contractual purchase commitments for the supply of crude oil feedstocks, with remaining terms ranging from three months to 2 years. Prices under these term agreements fluctuate with market-responsive pricing provisions. To estimate our annual commitments under these contracts, we estimated crude oil prices using actual market prices, ranging from $29 per barrel to $42 per barrel, as of December 31, 2004, and volumes based on the contract’s minimum purchase requirements. We also purchase additional crude oil feedstocks under short-term renewable contracts and in the spot market, which are not included in the table above.
 
(4)  Represents long-term commitments to purchase services, including chemical supplies and power. These purchase obligations are based on the contract’s minimum volume requirements. We estimated our commitments to purchase power at our California refinery, which has variable pricing provisions, using estimated future market prices. Actual purchases of electricity at our California refinery typically exceed the required minimum volumes. These commitments also include annual lease payments of $6 million through 2010 for a deactivated MTBE plant at our California refinery.
 
(5)  Amounts are subject to change based on the performance of the assets in the plan, the discount rate used to determine the obligation, and other actuarial assumptions. See “Critical Accounting Policies” for further information related to our pension plan. We are unable to project benefit contributions beyond 2009.

      We lease our corporate headquarters from a limited partnership in which we own a 50% limited interest. The initial term of the lease is through 2014 with two five-year renewal options. Our lease payments and operating costs paid to the partnership totaled $3.3 million, $3.2 million and $3.1 million in 2004, 2003 and 2002, respectively, and our future lease commitments are included in operating leases in the table above. We account for our interest in the partnership using the equity method of accounting. As such, we do not include the partnership’s assets, primarily land and buildings, totaling approximately $17 million and debt of approximately $13 million, in our consolidated financial statements.
Environmental and Other
      Tesoro 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 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 Liabilities
      As previously reported, we were involved with the EPA regarding a waste disposal site near Abbeville, Louisiana. Tesoro was named a potentially responsible party under the Federal Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA” or “Superfund”) at this location. The site was removed from the EPA’s National Priority List and the EPA entered into a settlement with third parties to remediate the site. Based on these considerations and recent discussions with the EPA, we believe that the likelihood that this matter will have any impact on our results of operations or financial position is remote.
      We are currently involved in remedial responses and have incurred and expect to continue to incur cleanup expenditures associated with environmental matters at a number of sites, including certain of our owned properties. At December 31, 2004, our accruals for environmental expenses totaled approximately $34 million. Our accruals for environmental expenses include retained liabilities for previously owned or operated properties, refining, pipeline and terminal operations and retail service stations. We believe these accruals are adequate, based on currently available information, including the participation of other parties or former owners in remediation action.

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      We are continuing to negotiate a settlement of approximately 70 Notices of Violation (“NOVs”) issued by the Bay Area Air Quality Management District. The NOVs allege various violations of air quality requirements at the California refinery between May 2002 and February 2004. Reserves for the settlement of the NOVs are included in the accruals of $34 million referenced above. We have established reserves for this matter which are not material and we believe that the resolution of this matter will not have a material adverse effect on our financial position or results of operations.
      On March 3, 2005 we finalized a settlement with the Bay Area Air Quality Management District and the Contra Costa County District Attorney’s office concerning three NOVs we received in March 2004 in response to odor incidents at our California refinery. We have agreed to pay a civil penalty of $225,000 to resolve this matter. Reserves for the settlement of the NOVs are included in the accruals of $34 million referenced above.
Other Environmental Matters
      In the ordinary course of business, we become party to or otherwise involved in lawsuits, administrative proceedings and governmental investigations, including environmental, regulatory and other matters. Large and sometimes unspecified damages or penalties may be sought from us in some matters for which the likelihood of loss may be reasonably possible but the amount of loss is not currently estimable, and some matters may require years for us to resolve. As a result, we have not established reserves for these matters and we cannot provide assurance that an adverse resolution of one or more of the matters described below during a future reporting period will not have a material adverse effect on our financial position or results of operations in future periods. However, on the basis of existing information, we believe that the resolution of these matters, individually or in the aggregate, will not have a material adverse effect on our financial position or results of operations.
      As previously disclosed, we were a defendant in seven pending cases alleging MTBE contamination in groundwater. During the 2004 fourth quarter, we were named as a defendant in seven additional pending cases, of which we obtained a dismissal without prejudice in four of these cases in February 2005. The plaintiffs in each of the remaining 10 pending cases, all in California, are generally water providers, governmental authorities and private well owners alleging that refiners and suppliers of gasoline containing MTBE are liable for manufacturing or distributing a defective product. We are being sued as a refiner, supplier and marketer of gasoline containing MTBE along with other refining industry companies. The suits generally seek individual, unquantified compensatory and punitive damages and attorney’s fees, but we cannot estimate the amount or the likelihood of the ultimate resolution of these matters at this time, and accordingly, we have not established a reserve for these cases. We believe we have defenses to these claims and intend to vigorously defend the lawsuits.
      Soil and groundwater conditions at our California refinery may require substantial expenditures over time. In connection with our acquisition of the California refinery from Ultramar, Inc. in May 2002, Ultramar assigned certain of its rights and obligations that Ultramar had acquired from Tosco Corporation in August of 2000. Tosco assumed responsibility and contractually indemnified us for up to $50 million for certain environmental liabilities arising from operations at the refinery prior to August of 2000, which are identified prior to August 31, 2010 (“Pre-Acquisition Operations”). Based on existing information, we currently estimate that the environmental liabilities arising from Pre-Acquisition Operations are approximately $41 million, including soil and groundwater conditions at the refinery in connection with various projects and including those required by the California Regional Water Quality Control Board and other government agencies. If we incur remediation liabilities in excess of the environmental liabilities for Pre-Acquisition Operations indemnified by Tosco, we expect to be reimbursed for such excess liabilities under certain environmental insurance policies. The policies provide $140 million of coverage in excess of the $50 million indemnity covering environmental liabilities arising from Pre-Acquisition Operations. Because of Tosco’s indemnification and the environmental insurance policies, we have not established a reserve for environmental liabilities arising out of the Pre-Acquisition Operations. In December 2003, we initiated arbitration proceedings against Tosco seeking damages, indemnity and a declaration that Tosco is responsible for the environmental liabilities arising from Pre-Acquisition Operations at our California refinery.

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      In November 2003, we filed suit in Contra Costa County Superior Court against Tosco alleging that Tosco misrepresented, concealed and failed to disclose certain additional environmental conditions at our California refinery. The court granted Tosco’s motion to compel arbitration of our claims for these certain additional environmental conditions. In the arbitration proceedings we initiated against Tosco in December 2003, we are also seeking a determination that Tosco is liable for investigation and remediation of these certain additional environmental conditions, the amount of which is currently unknown and therefore a reserve has not been established, and which may not be covered by the $50 million indemnity for environmental liabilities arising from Pre-Acquisition Operations. In response to our arbitration claims, Tosco filed counterclaims in the Contra Costa County Superior Court action alleging that we are contractually responsible for certain environmental liabilities at our California refinery, including certain liabilities arising from Pre-Acquisition Operations. In February 2005, the parties agreed to stay the arbitration proceedings for a period of 90 days to pursue settlement discussions. In the event we are unable to reach settlement, we intend to vigorously prosecute our claims against Tosco and to oppose Tosco’s claims against us, although we cannot provide assurance that we will prevail.
      During the first quarter of 2005, we began settlement discussions with the California Air Resources Board (“CARB”) concerning an NOV we received in October 2004. The NOV, issued by CARB, alleges we offered for sale eleven batches of gasoline in California that did not meet CARB’s gasoline exhaust emission limits. As of December 31, 2004, we could not estimate the amount of any penalties that might be associated with this NOV and accordingly, we did not establish a reserve for this matter. We disagree with factual allegations in the NOV and believe that the ultimate resolution of this matter with CARB will not have a material adverse effect on our financial position or results of operations.
Environmental Capital Expenditures
      EPA regulations related to the Clean Air Act require reductions in the sulfur content in gasoline, which began January 1, 2004. To meet the revised gasoline standard, we spent approximately $11 million in 2004, and we currently estimate we will make additional capital improvements of approximately $37 million through 2009. This will permit each of our six refineries to produce gasoline meeting the sulfur limits imposed by the EPA.
      EPA regulations related to the Clean Air Act also require reductions in the sulfur content in diesel fuel manufactured for on-road consumption. In general, the new on-road diesel fuel standards will become effective on June 1, 2006. In May 2004, the EPA issued a rule regarding the sulfur content of non-road diesel fuel. The requirements to reduce non-road diesel sulfur content will become effective in phases between 2007 and 2010. We have not determined if we will invest the capital necessary to manufacture low sulfur diesel for the non-road market in Alaska, and we are continuing to evaluate potential projects to manufacture additional non-road low sulfur diesel at our Hawaii refinery. Our California, Washington and North Dakota refineries will not require additional capital spending for non-road low sulfur diesel. We spent $31 million in 2004 to meet low sulfur diesel standards, and based on our latest engineering estimates, we now expect to spend approximately $45 million in additional capital improvements through 2006.
      To comply with the Maximum Achievable Control Technologies standard for petroleum refineries (“Refinery MACT II”), we spent $20 million during 2004, primarily to complete the installation of new emission control equipment at our North Dakota refinery. We expect to spend approximately $17 million in additional capital improvements in 2006 at our Washington refinery.

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      Estimated capital expenditures described above to comply with the Clean Air Act are summarized in the table below (in millions).
                                                       
    2004                    
    Actual   2005   2006   2007   2008   2009
                         
Lower Sulfur Gasoline
                                               
 
Alaska
  $     $     $     $     $     $  
 
Hawaii
                                   
 
Washington
    8       15                          
 
North Dakota
    3       14                          
 
Utah
                            2       6  
 
California
                                   
                                     
   
Total For Lower Sulfur Gasoline
    11       29                   2       6  
                                     
Lower Sulfur Diesel
                                               
 
Alaska
                                   
 
Hawaii
          4                          
 
Washington
    8       17       3                    
 
North Dakota
    2       5                          
 
Utah
    19       5                          
 
California
    2       7       4                    
                                     
   
Total For Lower Sulfur Diesel
    31       38       7                    
                                     
Refinery MACT II
                                               
 
Alaska
                                   
 
Hawaii
                                   
 
Washington
    6       16       1                    
 
North Dakota
    14                                
 
Utah
                                   
 
California
                                   
                                     
   
Total For Refinery MACT II
    20       16       1                    
                                     
     
Total
  $ 62     $ 83     $ 8     $     $ 2     $ 6  
                                     
      In connection with the 2001 acquisition of our North Dakota and Utah refineries, Tesoro assumed the sellers’ obligations and liabilities under a consent decree among the United States, BP Exploration and Oil Co. (“BP”), Amoco Oil Company and Atlantic Richfield Company. BP entered into this consent decree for both the North Dakota and Utah refineries for various alleged violations. As the owner of these refineries, Tesoro is required to address issues, including leak detection and repair, flaring protection and sulfur recovery unit optimization. We currently estimate we will spend $5 million over the next three years to comply with this consent decree. We also agreed to indemnify the sellers for all losses of any kind incurred in connection with the consent decree.
      In connection with the 2002 acquisition of our California refinery, subject to certain conditions, Tesoro also assumed the seller’s obligations pursuant to settlement efforts with the EPA concerning the Section 114 refinery enforcement initiative under the Clean Air Act, except for any potential monetary penalties, which the seller retains. We believe these obligations will not have a material impact on Tesoro’s financial position or results of operations.
      We 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. For these related projects at our

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California refinery, we spent $10 million during 2004, and we estimate that we may spend an additional $90 million through 2010. This cost estimate is subject to further review and analysis.
      Conditions may develop that cause increases or decreases in future expenditures for our various sites, including, but not limited to, our refineries, tank farms, retail gasoline stations (operating and closed locations) and petroleum product terminals, and for compliance with the Clean Air Act and other federal, state and local requirements. We 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. Our California refinery produces grades of gasoline that may be subject to similar claims. We have not paid or accrued liabilities for patent royalties that may be related to our California refinery’s production, since the U.S. Patent Office and the Federal Trade Commission are evaluating the validity of those patents. We believe that the resolution of this matter will not have a material adverse effect on our financial position or results of operations.
      For further information on environmental matters and other contingencies, see Note P in our consolidated financial statements in Item 8.
Pension Funding
      For all eligible employees, we provide a qualified defined benefit retirement plan with benefits based on years of service and compensation. Our long-term expected return on plan assets is 8.5%, and our pension plan assets experienced a return of $12 million in 2004 and $14 million in 2003. We contributed $53 million in 2004 and currently project to contribute $12 million in 2005, $16 million in 2006, $29 million in 2007 and $28 million in 2008 and $28 million in 2009. We are unable to project benefit contributions beyond 2009. Future contributions are affected by returns on plan assets, employee demographics and other factors. See Note N in our consolidated financial statements in Item 8 for further discussion.
Claims Against Third-Parties
      Beginning in the early 1980s, Tesoro Hawaii Corporation, Tesoro Alaska Company and other fuel suppliers entered a series of long-term, fixed-price fuel supply contracts with the U.S. Defense Energy Support Center (“DESC”). Each of the contracts contained a provision for price adjustments by the DESC. However, the Federal Acquisition Regulations (“FAR”) limit how prices may be adjusted, and we and many of the other suppliers in separate suits in the Court of Federal Claims currently are seeking relief from the DESC’s price adjustments. We and the other suppliers allege that the DESC’s price adjustments violated FAR by not adjusting the price of fuel based on changes to the suppliers’ established prices or costs, as FAR requires. We and the other suppliers seek recovery of approximately $3 billion in underpayment for fuel. Our share of the underpayment currently totals approximately $165 million, plus interest. The Court of Federal Claims granted partial summary judgment in our favor, held that the DESC’s fuel prices were illegal, and rejected the DESC’s assertion that we waived our right to a remedy by entering into the contracts. However, some of the other judges in the same court ruled on the cross-motions for other suppliers in conflict with the holding for us. As a result, we petitioned the Court of Appeals for the Federal Circuit to review its claims, and oral arguments in the appeal were held on January 10, 2005. We are seeking the Court of Appeals’ validation that the price adjustments were illegal and that we did not waive our right to sue when we entered into the contracts. We expect to receive the written decision from the Court of Appeals during the second quarter of 2005, but we cannot predict how the court will rule in this litigation.
      In December of 1996, Tesoro Alaska Company filed a protest of the intrastate rates charged for the transportation of its crude oil through the Trans Alaska Pipeline System (“TAPS”). Our protest asserted that the TAPS intrastate rates were excessive and should be reduced. The Regulatory Commission of Alaska (“RCA”) opened RCA Docket No. P-97-4 to consider our protest of the intrastate rates for the years 1997 through 2000. Through RCA’s Order P-97-4(151), the RCA set just and reasonable final rates for the years 1997 through 2000, and held that we are entitled to receive approximately $52 million in refunds, including

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interest through the expected conclusion of appeals in December 2007. RCA Order P-97-4(151) is currently on appeal, and we cannot give any assurances of when or whether we will prevail in the appeal.
      In December 2002, the RCA opened Docket No. P-03-4 to consider the justness and reasonableness of the proposed intrastate rates for TAPS for 2001-2003. Through the RCA’s Order P-03-4(34) (“Order 34”), the RCA rejected the TAPS Carriers’ proposed intrastate rate increases and maintained the permanent rate of $1.96 to the Valdez Marine Terminal. Order 34 is currently on appeal to the Alaska Superior Court (Case No. 3AN-04-8780 CI) and the TAPS Carriers did not move to stay Order 34 to prevent the rate decrease. The rate decrease has been in effect since June 2003.
      If the RCA’s decision is upheld on appeal, we could be entitled to refunds resulting from our shipments from January 2001 through mid-June 2003. If the RCA’s decision is not upheld on appeal, we could have to pay additional shipping charges resulting from our shipments from mid-June 2003 through December 2004. We cannot give any assurances of when or whether we will prevail in the appeal. We also believe that, should we not prevail on appeal, the amount of additional shipping charges cannot reasonably be estimated since it is not possible to estimate the permanent rate which the RCA could set, and the appellate courts approve, for each year. In addition, depending upon the level of such rates, there is a reasonable possibility that any refunds for the period January 2001 through mid-June 2003, could offset some or all of any repayments due for the period mid-June 2003 through December 2004.
ACCOUNTING STANDARDS
Critical Accounting Policies
      Our accounting policies are described in Note A in our consolidated financial statements in Item 8. We prepare our consolidated financial statements in conformity with accounting principles generally accepted in the United States of America, which require us 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 year. Actual results could differ from those estimates. We consider the following policies to be the most critical in understanding the judgments that are involved in preparing our financial statements and the uncertainties that could impact our financial condition and results of operations.
      Receivables — Our trade receivables are stated at their invoiced amounts, less an allowance for potentially uncollectible amounts. We monitor the credit and payment experience of our customers and manage our loss exposure through our credit policies and procedures. The estimated allowance for doubtful accounts is based on our general loss experience and identified loss exposures on individual accounts. Although actual losses have not been significant to our results of operations, economic conditions and the related credit environment could change, and actual losses could vary from estimates.
      Inventory — Our inventories are stated at the lower of cost or market. We use the LIFO method to determine the cost of our crude oil and refined product inventories. The LIFO cost of these inventories is usually much less than current market value, however a significant decline in market values of petroleum products could impair the carrying values of these inventories. We had 21.8 million barrels of crude oil and refined product inventories at December 31, 2004 with an average cost of approximately $26 per barrel on a LIFO basis. If refined product prices decline below the average cost, then we would be required to write down the value of our inventories in future periods.
      Property, Plant and Equipment — We calculate depreciation and amortization using the straight-line method based on estimated useful lives and salvage values of our assets. When assets are placed into service, we make estimates with respect to their useful lives that we believe are reasonable. However, factors such as maintenance levels, economic conditions impacting the demand for these assets, and regulation or environmental matters could cause us to change our estimates, thus impacting the future calculation of depreciation and amortization. We evaluate property, plant and equipment for potential impairment by identifying whether indicators of impairment exist and, if so, assessing whether the assets are recoverable from estimated future undiscounted cash flows. The actual amount of impairment loss, if any, to be recorded is equal to the amount

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by which the asset’s carrying value exceeds its fair value. Estimates of future undiscounted cash flows and fair value of assets require subjective assumptions with regard to several factors, including an assessment of market conditions and future operating results. Actual results could differ from those estimates.
      Goodwill and Acquired Intangibles — As of December 31, 2004, we had $89 million of goodwill included in Other Noncurrent Assets. Goodwill is not amortized, but is tested for impairment annually or more frequently when indicators of impairment exist. We review the recorded value of our goodwill for impairment annually during the fourth quarter, or sooner if events or changes in circumstances indicate the carrying amount may exceed fair value. Recoverability is determined by comparing the estimated fair value of a reporting unit to the carrying value, including the related goodwill, of that reporting unit. We use the present value of expected net cash flows to determine the estimated fair value of our reporting units. In 2003, we wrote off the marine services goodwill of $2.4 million in connection with the sale of that operation. In connection with the 2002 annual impairment review, we recognized a loss of $1.2 million to reduce the carrying value of goodwill in our retail segment. The impairment test is susceptible to change from period to period as it requires us to make cash flow assumptions including, among other things, future margins, volumes, operating costs and discount rates. Our assumptions regarding future margins and volumes require significant judgment as actual margins and volumes have fluctuated in the past and will likely continue to do so. For the impairment test performed during the fourth quarter of 2004, we assumed that future margins in our geographic areas will approximate our five-year average levels. Changes in market conditions could result in impairment charges in the future.
      As of December 31, 2004, we included $127 million of acquired intangible assets in Other Noncurrent Assets. The valuation of these intangible assets required us to use our judgment, including estimates with respect to their useful lives. We review acquired intangible assets for impairment whenever events or changes in circumstances indicate that the carrying amount of the assets may not be recoverable. The assessment of impairment is based on the estimated undiscounted future cash flows from operating activities, compared with the carrying value of the assets. The actual amount of impairment loss, if any, to be recorded is equal to the amount by which the asset’s carrying value exceeds its fair value. Estimates of future undiscounted cash flows and fair values of assets require subjective assumptions with regard to several factors, including an assessment of market conditions, discount rates and future operating results. Actual results could differ from those estimates.
      Deferred Maintenance Costs — We record the cost of major scheduled refinery turnarounds, long-lived catalysts used in refinery process units, and periodic maintenance on ships, tugs and barges (“drydocking”) as deferred charges in Other Noncurrent Assets which totaled $99 million at December 31, 2004. We amortize these deferred charges over the expected periods of benefit, generally ranging from two to six years. In September 2003, the American Institute of CPAs Accounting Standards Executive Committee (“AcSEC”) approved for issuance a Statement of Position (“SOP”), “Accounting for Certain Costs and Activities Related to Property, Plant and Equipment,” subject to clearance by the FASB, which would have required these major maintenance activities to be expensed as costs are incurred. On April 14, 2004, the FASB unanimously decided not to approve the issuance of the proposed SOP. AcSEC has stated that they will not spend any further time on this project, and the FASB currently does not have definitive plans to consider the issues addressed in the proposed SOP.
      Contingencies — We record an estimated loss from a contingency when information available before issuing our financial statements indicates that (a) it is probable that an asset has been impaired or a liability has been incurred at the date of the financial statements and (b) the amount of the loss can be reasonably estimated. We are required to use our judgment to account for contingencies such as environmental, legal and income tax matters. While we believe that our accruals for these matters are adequate, the actual loss may differ from our estimated loss, and we would record the necessary adjustments in future periods. We do not record the benefits of contingent recoveries or gains until the amount is determinable and recovery is assured.
      Income Taxes — As part of the process of preparing consolidated financial statements, we must assess the likelihood that our deferred income tax assets will be recovered through future taxable income. To the extent we believe that recovery is not likely, a valuation allowance must be established. Significant

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management judgment is required in determining any valuation allowance recorded against net deferred income tax assets. Based on our estimates of taxable income in each jurisdiction in which we operate and the period over which deferred income tax assets will be recoverable, we have not recorded a valuation allowance as of December 31, 2004. In the event that actual results differ from these estimates or we make adjustments to these estimates in future periods, we may need to establish a valuation allowance.
      Pension and Other Postretirement Benefits — Accounting for pensions and other postretirement benefits involves several assumptions and estimates including discount rates, health care cost trends, inflation, retirement rates and mortality rates. We must also assume a rate of return on funded pension plan assets in order to estimate our obligations under our defined benefit plans. Due to the nature of these calculations, we engage an actuarial firm to assist with the determination of these estimates and the calculation of certain employee benefit expenses. We record a liability for the cost of the plans based on the actuarially determined amounts, less any plan assets. While we believe that the assumptions used are appropriate, significant differences in the actual experience or significant changes in assumptions would affect pension and other postretirement benefits costs and obligations. A one-percentage-point change in the expected return on plan assets and discount rate for the pension plans would have had the following effects in 2004 (in millions):
                   
    1-Percentage-   1-Percentage-
    Point Increase   Point Decrease
         
Expected Rate of Return
               
 
Effect on net periodic pension expense
  $ (1.2 )   $ 1.2  
Discount Rate
               
 
Effect on net periodic pension expense
  $ (2.4 )   $ 2.8  
 
Effect on projected benefit obligation
  $ (18.4 )   $ 21.7  
      See Note N in our consolidated financial statements in Item 8 for more information regarding costs and assumptions.
New Accounting Standards and Disclosures
      See Note A in our consolidated financial statements in Item 8.
FORWARD-LOOKING STATEMENTS
      This Annual Report on Form 10-K includes forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. These statements are included throughout this Form 10-K and relate to, among other things, expectations regarding refining margins, revenues, cash flows, capital expenditures, turnaround expenses, and other financial items. These statements also relate to our business strategy, goals and expectations concerning our market position, future operations, margins and profitability. 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 Annual Report on Form 10-K.
      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;

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  •  changes in our cash flow from operations;
 
  •  changes in the cost or availability of third-party vessels, pipelines and other means of transporting feedstocks and products;
 
  •  disruptions due to equipment interruption or failure at our facilities or third-party facilities;
 
  •  actions of customers and competitors;
 
  •  changes in capital requirements or in execution of planned capital projects;
 
  •  direct or indirect effects on our business resulting from actual or threatened terrorist incidents or acts of war;
 
  •  political developments in foreign countries;
 
  •  changes in our inventory levels and carrying costs;
 
  •  seasonal variations in demand for refined products;
 
  •  changes in fuel and utility costs for our facilities;
 
  •  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;
 
  •  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 “Competition and Other” on page 10 and “Risk Factors” on page 15. All future written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by the previous statements. We undertake no obligation to update any information contained herein or to publicly release the results of any revisions to any forward-looking statements that may be made to reflect events or circumstances that occur, or that we become aware of, after the date of this Annual Report on Form 10-K.
ITEM 7A. 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 managing risks arising from transactions and commitments related to the sale and purchase of energy commodities.
Commodity Price Risks
      Our earnings and cash flows from operations depend on the margin above fixed and variable expenses (including the costs of crude oil and other feedstocks) at which we are able to sell refined products. The prices of crude oil and refined products have fluctuated substantially in recent years. These prices depend on many factors, including the demand for crude oil, gasoline and other refined products, which in turn depend on, among other factors, changes in the economy, the level of foreign and domestic production of crude oil and refined products, worldwide political conditions, the availability of imports of crude oil and refined products, the marketing of alternative and competing fuels and the impact of government regulations. The prices we receive for refined products are also affected by local factors such as local market conditions and the level of operations of other refineries in our markets.
      The prices at which we sell our refined products are influenced by the commodity price of crude oil. Generally, an increase or decrease in the price of crude oil results in a corresponding increase or decrease in the price of gasoline and other refined products. The timing of the relative movement of the prices, however, can impact profit margins which could significantly affect our earnings and cash flows. In addition, the

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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 2004 average throughput of 520 thousand bpd, would change annual pretax operating income by approximately $190 million.
      We maintain inventories of crude oil, intermediate products and refined products, the values of which are subject to fluctuations in market prices. Our inventories of refinery feedstocks and refined products totaled 21.8 million barrels and 18.8 million barrels at December 31, 2004 and 2003, respectively. The average cost of our refinery feedstocks and refined products at December 31, 2004 was approximately $26 per barrel on a LIFO basis, compared to market prices of approximately $46 per barrel. If market prices for refined products decline to a level below the average cost of these inventories, we would be required to write down the carrying value of our inventory.
      Tesoro periodically enters into derivative arrangements primarily to manage exposure to commodity price risks associated with the purchase of crude oil. To manage these risks, we typically enter into exchange-traded futures and options and over-the-counter swaps, generally with durations of one year or less. We mark to market our non-hedging derivative instruments and recognize the changes in their fair values in earnings. We include the carrying amounts of our derivatives in other current assets or accrued liabilities in the consolidated balance sheets. We did not designate or account for any derivative instruments as hedges during the years ended 2004, 2003 or 2002. During 2004, we settled futures, options and other over-the-counter contracts of approximately 42 million barrels of crude oil and refined products, which due to significant price volatility resulted in losses of $53 million. At December 31, 2004, we had open net futures contracts and swap positions of 529,000 barrels and 587,000 barrels, respectively, which will expire at various times during 2005. We recorded the fair value of these positions, which resulted in a mark-to-market gain of $1.6 million at December 31, 2004.
Interest Rate Risk
      At December 31, 2004, we had $97.0 million of outstanding floating-rate debt under our senior secured term loans and $1.1 billion of fixed-rate debt. The interest rate on our floating-rate debt was 7.99% at December 31, 2004, 5.5% of which was fixed. The impact on annual cash flow of an additional 1% (100 basis points) in the floating-rate component for our senior secured term loans would be approximately $1 million.
      The fair market values of our senior secured loans, senior secured notes and senior subordinated notes are based on transactions and bid quotes. The fair market value of our junior subordinated notes and capital lease obligations approximate their carrying values. The fair market values of our fixed and variable rate debt were approximately $110 million and $3 million, respectively, more than their carrying values at December 31, 2004.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
Tesoro Corporation
      We have audited the accompanying consolidated balance sheets of Tesoro Corporation and subsidiaries (the “Company”) as of December 31, 2004 and 2003, and the related statements of consolidated operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2004. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
      We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
      In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Tesoro Corporation and subsidiaries as of December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004, in conformity with accounting principles generally accepted in the United States of America.
      As discussed in Note A to the consolidated financial statements, as of January 1, 2004, the Company changed its method of accounting for stock options.
      We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 2, 2005, expressed an unqualified opinion on management’s assessment of the effectiveness of the Company’s internal control over financial reporting and an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
/s/ deloitte & touche llp
San Antonio, Texas
March 2, 2005

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TESORO CORPORATION
STATEMENTS OF CONSOLIDATED OPERATIONS
                           
    Years Ended December 31,
     
    2004   2003   2002
             
    (In millions except per share amounts)
REVENUES
  $ 12,262.2     $ 8,845.7     $ 7,119.3  
COSTS AND EXPENSES:
                       
 
Costs of sales and operating expenses
    11,228.5       8,207.8       6,865.7  
 
Selling, general and administrative expenses
    152.3       138.0       133.2  
 
Depreciation and amortization
    154.1       148.2       130.7  
 
Loss on asset sales and impairments
    14.1       16.9       8.4  
                   
OPERATING INCOME (LOSS)
    713.2       334.8       (18.7 )
Interest and financing costs, net
    (166.6 )     (211.7 )     (162.6 )
                   
EARNINGS (LOSS) BEFORE INCOME TAXES
    546.6       123.1       (181.3 )
Income tax provision (benefit)
    218.7       47.0       (64.3 )
                   
NET EARNINGS (LOSS)
  $ 327.9     $ 76.1     $ (117.0 )
                   
NET EARNINGS (LOSS) PER SHARE
                       
 
Basic
  $ 5.01     $ 1.18     $ (1.93 )
 
Diluted
  $ 4.76     $ 1.17     $ (1.93 )
WEIGHTED AVERAGE COMMON SHARES
                       
 
Basic
    65.5       64.6       60.5  
 
Diluted
    68.9       65.1       60.5  
The accompanying notes are an integral part of these consolidated financial statements.

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TESORO CORPORATION
CONSOLIDATED BALANCE SHEETS
                       
    December 31,
     
    2004   2003
         
    (Dollars in millions
    except per share amounts)
ASSETS
CURRENT ASSETS
               
 
Cash and cash equivalents
  $ 184.8     $ 77.2  
 
Receivables, less allowance for doubtful accounts
    528.4       414.6  
 
Inventories
    615.7       487.3  
 
Prepayments and other
    64.5       44.9  
             
   
Total Current Assets
    1,393.4       1,024.0  
             
PROPERTY, PLANT AND EQUIPMENT
               
 
Refining
    2,602.5       2,451.1  
 
Retail
    225.1       231.4  
 
Corporate and other
    66.2       58.8  
             
      2,893.8       2,741.3  
 
Less accumulated depreciation and amortization
    (590.2 )     (489.8 )
             
   
Net Property, Plant and Equipment
    2,303.6       2,251.5  
             
OTHER NONCURRENT ASSETS
               
 
Goodwill
    88.7       88.7  
 
Acquired intangibles, net
    127.2       138.6  
 
Other, net
    162.2       158.5  
             
   
Total Other Noncurrent Assets
    378.1       385.8  
             
     
Total Assets
  $ 4,075.1     $ 3,661.3  
             
 
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
               
 
Accounts payable
  $ 686.6     $ 431.8  
 
Accrued liabilities
    302.7       251.7  
 
Current maturities of debt
    3.4       3.5  
             
   
Total Current Liabilities
    992.7       687.0  
             
DEFERRED INCOME TAXES
    292.9       179.2  
OTHER LIABILITIES
    247.5       224.4  
DEBT
    1,214.9       1,605.3  
COMMITMENTS AND CONTINGENCIES (Note P)
               
STOCKHOLDERS’ EQUITY
               
 
Common stock, par value $0.162/3; authorized 100,000,000 shares; 68,261,949 shares issued (66,458,008 in 2003)
    11.4       11.0  
 
Additional paid-in capital
    728.7       690.6  
 
Retained earnings
    608.9       281.0  
 
Unearned compensation
    (10.7 )      
 
Treasury stock, 1,438,524 common shares (1,701,768 in 2003), at cost
    (11.2 )     (17.2 )
             
   
Total Stockholders’ Equity
    1,327.1       965.4  
             
     
Total Liabilities and Stockholders’ Equity
  $ 4,075.1     $ 3,661.3  
             
The accompanying notes are an integral part of these consolidated financial statements.

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TESORO CORPORATION
STATEMENTS OF CONSOLIDATED STOCKHOLDERS’ EQUITY
                                                           
    Common Stock   Additional           Treasury Stock
        Paid-In   Retained   Unearned    
    Shares   Amount   Capital   Earnings   Compensation   Shares   Amount
                             
    (In millions)
AT JANUARY 1, 2002
    43.4     $ 7.2     $ 448.4     $ 321.9     $       (2.0 )   $ (20.5 )
 
Net loss
                      (117.0 )                  
 
Issuance of common stock
    23.0       3.8       241.3                          
 
Shares issued for stock options and benefit plans
                0.1                   0.2       2.4  
                                           
AT DECEMBER 31, 2002
    66.4       11.0       689.8       204.9             (1.8 )     (18.1 )
 
Net earnings
                      76.1                    
 
Shares issued for stock options and benefit plans
    0.1             0.8                   0.1       0.9  
                                           
AT DECEMBER 31, 2003
    66.5       11.0       690.6       281.0             (1.7 )     (17.2 )
 
Net earnings
                      327.9                    
 
Shares issued for stock options and benefit plans
    1.1       0.3       21.1                   0.3       6.0  
 
Tax benefits on stock options exercised
                4.4                          
 
Restricted stock grants
    0.7       0.1       12.6             (12.7 )            
 
Restricted stock amortization
                            2.0              
                                           
AT DECEMBER 31, 2004
    68.3     $ 11.4     $ 728.7     $ 608.9     $ (10.7 )     (1.4 )   $ (11.2 )
                                           
The accompanying notes are an integral part of these consolidated financial statements

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TESORO CORPORATION
STATEMENTS OF CONSOLIDATED CASH FLOWS
                               
    Years Ended December 31,
     
    2004   2003   2002
             
    (In millions)
CASH FLOWS FROM (USED IN) OPERATING ACTIVITIES
                       
 
Net earnings (loss)
  $ 327.9     $ 76.1     $ (117.0 )
 
Adjustments to reconcile net earnings (loss) to net cash from operating activities:
                       
 
Depreciation and amortization
    154.1       148.2       130.7  
 
Amortization of debt issuance costs and discounts
    17.7       19.3       14.2  
 
Write-off of unamortized debt issuance costs and discount
    9.3       36.2       12.6  
 
Loss on asset sales and impairments
    14.1       16.9       8.4  
 
Stock-based compensation
    14.2              
 
Deferred income taxes
    102.4       55.5       3.3  
 
Other changes in non-current assets and liabilities
    (13.9 )     (42.6 )     (38.0 )
 
Changes in current assets and current liabilities:
                       
   
Receivables
    (115.8 )     1.2       (49.8 )
   
Income taxes receivable
    1.9       38.4       (19.4 )
   
Inventories
    (128.6 )     (26.0 )     115.9  
   
Prepayments and other
    (16.4 )     (16.3 )     (20.7 )
   
Accounts payable and accrued liabilities
    318.4       140.4       17.6  
                   
     
Net cash from operating activities
    685.3       447.3       57.8  
                   
CASH FLOWS FROM (USED IN) INVESTING ACTIVITIES
                       
 
Capital expenditures
    (179.4 )     (101.1 )     (203.5 )
 
Acquisitions
                (931.5 )
 
Proceeds from asset sales
    4.9       31.2       207.4  
 
Other
          (0.1 )     (13.1 )
                   
     
Net cash used in investing activities
    (174.5 )     (70.0 )     (940.7 )
                   
CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES
                       
 
Proceeds from debt offerings, net of issuance costs of $11.2 in 2003 and $9.4 in 2002
          360.0       440.6  
 
Borrowings under term loans
          350.0       425.0  
 
Proceeds from Common Stock offering, net of issuance costs of $13.7
                245.1  
 
Debt refinanced
          (721.2 )      
 
Repayments of debt
    (400.9 )     (376.7 )     (133.0 )
 
Other financing costs
    (15.1 )     (22.7 )     (36.9 )
 
Proceeds from stock options exercised
    12.8       0.7        
                   
     
Net cash from (used in) financing activities
    (403.2 )     (409.9 )     940.8  
                   
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
    107.6       (32.6 )     57.9  
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR
    77.2       109.8       51.9  
                   
CASH AND CASH EQUIVALENTS, END OF YEAR
  $ 184.8     $ 77.2     $ 109.8  
                   
SUPPLEMENTAL CASH FLOW DISCLOSURES
                       
 
Interest paid, net of capitalized interest
  $ 141.7     $ 156.7     $ 114.3  
 
Income taxes paid (refunded)
  $ 52.9     $ (50.7 )   $ (48.0 )
The accompanying notes are an integral part of these consolidated financial statements.

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TESORO CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE A — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Description and Nature of Business
      Tesoro Corporation (“Tesoro”) was incorporated in Delaware in 1968 and is an independent refiner and marketer of petroleum products. We own and operate six petroleum refineries in the western and mid-continental United States with a combined rated crude oil throughput capacity of 558,000 barrels per day (“bpd”), and we sell refined products to a wide variety of customers. We market products to wholesale and retail customers, as well as commercial end-users. Our retail business includes a network of 506 branded retail stations operated by Tesoro or independent dealers.
      Tesoro’s 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 have been significantly influenced by the timing of changes in crude oil costs and how quickly refined product prices adjust to reflect these changes. These price fluctuations depend on numerous factors beyond our control, including the demand for crude oil, gasoline and other refined products, which is subject to, among other things, changes in the economy and the level of foreign and domestic production of crude oil and refined products, worldwide political conditions, threatened or actual terrorist incidents or acts of war, availability of crude oil and refined product imports, the infrastructure to transport crude oil and refined products, weather conditions, earthquakes and other natural disasters, seasonal variations, 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.
Principles of Consolidation and Basis of Presentation
      The accompanying consolidated financial statements include the accounts of Tesoro and its subsidiaries. All intercompany accounts and transactions have been eliminated. Investments in entities in which we have the ability to exercise significant influence, but not control, are accounted for using the equity method, while other investments are carried at cost. These investments are not material, either individually or in the aggregate, to Tesoro’s financial position, results of operations or cash flows. See Note P for information related to a 50% limited partnership interest, which we account for using the equity method.
      Separate financial statements of Tesoro’s subsidiary guarantors are not included because these subsidiary guarantors are jointly and severally liable for Tesoro’s outstanding senior secured term loans, senior secured notes and senior subordinated notes. Further, net assets, results of operations and equity of the subsidiary guarantors are substantially equivalent to Tesoro’s consolidated net assets, results of operations and equity.
Use of Estimates
      We prepare Tesoro’s consolidated financial statements in conformity with accounting principles generally accepted in the United States of America (“U.S. GAAP”), which 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 year. We review our estimates on an ongoing basis, based on currently available information. Changes in facts and circumstances may result in revised estimates and actual results could differ from those estimates.

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TESORO CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Cash and Cash Equivalents
      We consider all highly-liquid instruments, such as temporary cash investments, with a maturity of three months or less at the time of purchase to be cash equivalents. Cash equivalents are stated at cost, which approximates market value.
Financial Instruments
      The carrying amounts of financial instruments, including cash and cash equivalents, receivables, accounts payable and certain accrued liabilities, approximate fair value because of the short maturities of these instruments. The carrying amounts of Tesoro’s debt and other obligations may vary from our estimates of the fair value of such items. We estimate that the fair market value of Tesoro’s fixed-rate debt at December 31, 2004, was approximately $110 million more than its total book value of $1.1 billion. We estimate that the fair market value of the Company’s variable-rate debt at December 31, 2004, was approximately $3 million more than its book value of $97 million.
Inventories
      Inventories are stated at the lower of cost or market. We use last-in, first-out (“LIFO”) as the primary method to determine the cost of crude oil and refined product inventories in our refining and retail segments. We determine the carrying value of inventories of oxygenates and by-products using the first-in, first-out (“FIFO”) cost method. We value merchandise and materials and supplies at average cost.
Property, Plant and Equipment
      We capitalize the cost of additions, major improvements and modifications to property, plant and equipment. We compute depreciation of property, plant and equipment on the straight-line method, based on the estimated useful life of each asset. The weighted average lives range from 26 to 27 years for refineries, 8 to 16 years for terminals, 12 to 16 years for retail stations, 5 to 29 years for transportation assets and 4 to 17 years for corporate assets. We record property under capital leases at the present value of minimum lease payments using Tesoro’s incremental borrowing rate. We amortize property under capital leases over the term of each lease.
      We capitalize interest as part of the cost of major projects during extended construction periods. Tesoro incurred total interest and financing costs of $175.4 million, $215.3 million and $168.6 million in 2004, 2003 and 2002, respectively, of which $4.3 million, $2.7 million and $2.5 million was capitalized during 2004, 2003 and 2002, respectively.
Asset Retirement Obligations
      We accrue for asset retirement obligations, primarily for assets on leased sites, in the period in which the obligations are incurred. We accrue these costs at estimated fair value. When the related liability is initially recorded, we capitalize the cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted to its settlement value and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, we recognize a gain or loss for any difference between the settlement amount and the liability recorded. We have identified asset retirement obligations, 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

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TESORO CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
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. At both December 31, 2004 and 2003, our liability for asset retirement obligations amounted to approximately $1 million.
Environmental Expenditures
      We capitalize environmental expenditures that extend the life or increase the capacity of facilities, as well as expenditures that mitigate or prevent environmental contamination that is yet to occur. We charge to expense costs that relate to an existing condition caused by past operations and that do not contribute to current or future revenue generation. We record liabilities when environmental assessments and/or remedial efforts are probable and can be reasonably estimated. Cost estimates are based on the expected timing and the extent of remedial actions required by applicable governing agencies, experience gained from similar sites on which environmental assessments or remediation have been completed, and the amount of our anticipated liability considering the proportional liability and financial abilities of other responsible parties. Generally, the timing of these accruals coincides with the completion of a feasibility study or our commitment to a formal plan of action. Estimated liabilities are not discounted to present value.
Goodwill and Acquired Intangibles
      Goodwill represents the excess of cost (purchase price) over the fair value of net assets acquired. Under Statement of Financial Accounting Standards (“SFAS”) No. 142, “Goodwill and Other Intangible Assets,” we ceased amortizing goodwill on January 1, 2002. Acquired intangibles consist primarily of air emissions credits, permits and plans, and customer agreements and contracts, which we recorded at fair value as of the date acquired. We compute amortization on a straight-line basis over estimated useful lives of 2 to 28 years, and we include amortization of acquired intangibles in depreciation and amortization expense.
Other Assets
      We periodically shut down refinery processing units for major scheduled maintenance, or turnarounds. Certain catalysts are used in refinery process units for periods exceeding one year. Also, we drydock ships, tugs and barges for periodic maintenance. We defer turnaround, catalyst and drydocking costs and amortize the costs on a straight-line basis over the expected periods of benefit, generally ranging from 2 to 6 years. Amortization of such deferred costs, which is included in depreciation and amortization expense, amounted to $34.0 million, $30.9 million and $27.2 million in 2004, 2003 and 2002, respectively. In 2004, the Financial Accounting Standards Board (“FASB”) decided not to approve the issuance of a Statement of Position (“SOP”) proposed by the American Institute of CPAs. The proposed SOP would have required major maintenance activities, such as refinery turnarounds, to be expensed as incurred. See New Accounting Standards and Disclosures below for further information.
      We defer debt issuance costs related to our credit agreement and senior notes and amortize the costs over the estimated terms of each instrument. We include the amortization in interest and financing costs in our statements of consolidated operations. We evaluate the carrying value of debt issuance costs when modifications are made to the related debt instruments (see Note F).
Impairment of Long-Lived Assets
      We review property, plant and equipment and other long-lived assets, including acquired intangible assets for impairment whenever events or changes in business circumstances indicate the carrying values of the assets may not be recoverable. We would record impairment losses if the undiscounted cash flows estimated to be generated by those assets were less than the carrying amount of those assets. Factors that would indicate potential impairment include, but are not limited to, significant decreases in the market value of a long-lived

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TESORO CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
asset, a significant change in the long-lived asset’s physical condition, and operating or cash flow losses associated with the use of the long-lived asset. We review goodwill balances for impairment annually or more frequently, if events or changes in business circumstances indicate the carrying values of the assets may not be recoverable.
Revenue Recognition
      We recognize revenues from product sales upon delivery to customers, which is the point at which title to the products is transferred, and when payment has either been received or collection is reasonably assured. We include certain crude oil and product purchases and resales used for trading purposes in revenues on a net basis. Nonmonetary product and crude oil exchange transactions, commonly called buy/ sell transactions, which are entered into primarily to optimize our refinery supply requirements, are included in cost of sales and operating expense on a net basis. We include transportation fees charged to customers in revenues, and we include the related costs in costs of sales in our statements of consolidated operations. In our retail segment, revenues and costs of sales include federal excise and state motor fuel taxes collected from customers and remitted to governmental agencies. These taxes, primarily related to sales of gasoline and diesel fuel, totaled $123 million, $128 million and $167 million in 2004, 2003 and 2002, respectively. In our refining segment, excise taxes on sales are not included in revenues and costs of sales.
Income Taxes
      We record deferred tax assets and liabilities for future income tax consequences that are attributable to differences between financial statement carrying amounts of assets and liabilities and their income tax bases. We base the measurement of deferred tax assets and liabilities on enacted tax rates that we expect will apply to taxable income in the year when we expect to settle or recover those temporary differences. We recognize the effect on deferred tax assets and liabilities of any change in income tax rates in the period that includes the enactment date. We provide a valuation allowance for deferred tax assets if it is more likely than not that those items will either expire before we are able to realize their benefit or their future deductibility is uncertain.
Stock-Based Compensation
      Effective January 1, 2004, we adopted the preferable fair value method of accounting for our stock options, as prescribed in SFAS No. 123, “Accounting for Stock-Based Compensation.” We selected the “modified prospective method” of adoption described in SFAS No. 148, “Accounting for Stock-Based Compensation — Transition and Disclosure.” We recognized compensation cost for our stock options as if the fair value method had been applied from its original effective date, resulting in pretax charges for the year ended December 31, 2004 of $8.4 million. See New Accounting Standards and Disclosures below for further information.
      Prior to January 1, 2004, we accounted for stock options using the intrinsic value method prescribed in Accounting Principles Board (“APB”) Opinion No. 25, “Accounting for Stock Issued to Employees,” and related interpretations. Under the intrinsic value method, we did not recognize compensation costs for our stock options as all options granted had an exercise price equal to the market value of the underlying common stock on the date of grant.

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TESORO CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
      The following table represents the effect on net earnings and earnings per share as if we had applied the fair value method and recognition provisions of SFAS No. 123 to our stock options during 2003 and 2002 (in millions except per share amounts):
                 
    2003   2002
         
Reported net earnings (loss)
  $ 76.1     $ (117.0 )
Deduct total stock-based employee compensation expense determined under fair value based methods for all awards, net of related tax effects
    (3.2 )     (3.8 )
             
Pro forma net earnings (loss)
  $ 72.9     $ (120.8 )
             
Net earnings (loss) per share:
               
Basic, as reported
  $ 1.18     $ (1.93 )
Basic, pro forma
  $ 1.13     $ (2.00 )
Diluted, as reported
  $ 1.17     $ (1.93 )
Diluted, pro forma
  $ 1.12     $ (2.00 )
      See Note O for further information on Tesoro’s stock-based employee compensation plans.
Derivative Instruments
      We account for derivative instruments in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended and interpreted. Tesoro periodically enters into derivative arrangements primarily to manage exposure to commodity price risks associated with the purchase of crude oil. To manage these risks, we typically enter into exchange-traded futures and options and over-the-counter swaps, generally with durations of one year or less.
      We mark to market our non-hedging derivative instruments and recognize the changes in their fair values in earnings. We include the carrying amounts of our derivatives in other current assets or accrued liabilities in the consolidated balance sheets. During 2004, we settled futures, options and other over-the-counter contracts of approximately 42 million barrels of crude oil and refined products, which due to significant price volatility resulted in losses of $53 million. At December 31, 2004, we had open net futures contracts and swap positions of 529,000 barrels and 587,000 barrels, respectively, which will expire at various times during 2005. We recorded the fair value of these positions, which resulted in a mark-to-market gain of $1.6 million at December 31, 2004. We did not designate or account for any derivative instruments as hedges during 2004, 2003 or 2002.
New Accounting Standards and Disclosures
FAS 106-1 and FAS 106-2
      Tesoro sponsors a postretirement health care plan that provides prescription drug benefits. In December 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the “Act”) was passed. The Act introduces a prescription drug benefit under Medicare (Medicare Part D), as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare Part D. In January 2004, the FASB issued FASB Staff Position No. FAS 106-1, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” (“FAS 106-1”), which became effective for us as of December 31, 2003 and permitted an election to reflect the effects of the Act immediately or defer recognition of the Act until more definitive guidance was issued. In May 2004, the FASB issued FASB Staff Position No. FAS 106-2 (“FAS 106-2”) which provides guidance for the accounting of the federal subsidy. Further, the new accounting standard required FAS 106-1 to be superseded upon the effective date of FAS 106-2, which was

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TESORO CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
July 1, 2004 for Tesoro. In accordance with FAS 106-1 and FAS 106-2, we deferred recognition of the Act through June 30, 2004. On July 1, 2004, we elected the “prospective application” of adoption for the recognition of the federal subsidy as defined in FAS 106-2. The effect of recognizing the federal subsidy in accordance with FAS 106-2 will result in an annual reduction of postretirement benefit expense of approximately $1 million. See Note N for further information.
FIN 46 and FIN 46(R)
      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. Our implementation of FIN 46 did not result in the consolidation of any variable interest entities. In December 2003, the FASB issued Interpretation No. 46 (Revised) (“FIN 46(R)”), which provides additional guidance related to accounting for variable interest entities and became effective for us at the end of the 2004 first quarter. Implementation of FIN 46(R) did not require consolidation of any variable interest entities.
Statement of Position
      In September 2003, the American Institute of CPAs Accounting Standards Executive Committee (“AcSEC”) approved for issuance an SOP, “Accounting for Certain Costs and Activities Related to Property, Plant and Equipment,” subject to clearance by the FASB. In April 2004, the FASB unanimously decided not to approve the issuance of the proposed SOP. The proposed SOP would have, among other provisions, required major maintenance activities, such as refinery turnarounds, to be expensed as incurred. AcSEC has stated they will not spend any further time on this project, and the FASB currently does not have definitive plans to consider the issues addressed in the proposed SOP.
SFAS No. 123 (Revised 2004)
      In December 2004, the FASB issued SFAS No. 123 (Revised 2004), “Share-Based Payment,” which is a revision of SFAS No. 123, and supersedes APB Opinion No. 25. Among other items, SFAS No. 123 (Revised 2004) eliminates the use of APB Opinion No. 25 and the intrinsic value method of accounting, and requires companies to recognize the cost of employee services received in exchange for awards of equity instruments, based on the grant date fair value of those awards, in the financial statements. The effective date of SFAS No. 123 (Revised 2004) is the first reporting period beginning after June 15, 2005, although early adoption is allowed. Effective January 1, 2004, we began to recognize compensation expense for our stock options using the fair value method of accounting as described in SFAS No. 123, “Accounting for Stock-Based Compensation.” SFAS No. 123 (Revised 2004) will require Tesoro to also adopt the fair value method for our outstanding phantom stock options. See Note O for further information on Tesoro’s stock-based employee compensation plans. We adopted the provisions of SFAS No. 123 (Revised 2004) on January 1, 2005, which did not have a material impact on our financial position or results of operations.
SFAS No. 153
      In December 2004, the FASB issued SFAS No. 153, “Exchanges of Nonmonetary Assets — An Amendment of APB Opinion No. 29, Accounting for Nonmonetary Transactions.” SFAS 153 eliminates the exception from fair value measurement for nonmonetary exchanges of similar productive assets in paragraph 21(b) of APB Opinion No. 29, “Accounting for Nonmonetary Transactions,” and replaces it with an exception for exchanges that do not have commercial substance. SFAS 153 specifies that a nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. SFAS 153 is effective for fiscal periods beginning after June 15, 2005 and is required to be adopted by Tesoro beginning on January 1, 2006. We are currently evaluating this standard, although we do not believe it will have a material impact on our financial position or results of operations.

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TESORO CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
     EITF Issue No. 4-13
      The Emerging Issues Task Force (EITF) is currently considering EITF Issue No. 4-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty” which will determine whether buy/sell arrangements should be accounted for at historical cost and whether these arrangements should be reported on a gross or net basis. Buy/ sell arrangements are typically contractual arrangements where the buy and sell agreements are entered into in contemplation of one another with the same counterparty. The SEC has questioned the gross treatment of these types of arrangements. Tesoro reports all buy/ sell arrangements on a net basis. Therefore, if EITF Issue No. 4-13 were to require companies to report buy/ sell arrangements on a net basis, it would have no effect on our financial position or results of operations.
NOTE B — EARNINGS (LOSS) PER SHARE
      We compute basic earnings (loss) per share by dividing net earnings (loss) by the weighted average number of common shares outstanding during the period. Diluted earnings per share include the effects of potentially dilutive shares, principally common stock options and restricted stock outstanding during the period. The assumed conversion of common stock options produced anti-dilutive results for 2002 and, therefore, was not included in the calculations of diluted loss per share. Earnings (loss) per share calculations are presented below (in millions, except per share amounts):
                           
    2004   2003   2002
             
Basic:
                       
 
Net earnings (loss)
  $ 327.9     $ 76.1     $ (117.0 )
                   
 
Weighted average common shares outstanding
    65.5       64.6       60.5  
                   
 
Basic Earnings (Loss) Per Share
  $ 5.01     $ 1.18     $ (1.93 )
                   
Diluted:
                       
 
Net earnings (loss)
  $ 327.9     $ 76.1     $ (117.0 )
                   
 
Weighted average common shares outstanding
    65.5       64.6       60.5  
 
Dilutive effect of assumed exercise of stock options and awards (anti-dilutive in 2002)
    3.4       0.5        
                   
 
Total diluted shares
    68.9       65.1       60.5  
                   
 
Diluted Earnings (Loss) Per Share
  $ 4.76     $ 1.17     $ (1.93 )
                   
NOTE C — ACQUISITION
      On May 17, 2002, we acquired a 168,000 bpd refinery located in Martinez, California in the San Francisco Bay area along with 70 associated retail sites throughout northern California. The cash purchase price for these assets was $923 million, including $130 million for feedstock, refined products and other inventories. In addition, Tesoro issued to the seller two ten-year junior subordinated notes with face amounts aggregating $150 million, and a present value at the acquisition date of approximately $61 million (see Note F). We incurred direct costs related to this transaction of $9 million. The purchase price was allocated to the acquired assets and assumed liabilities based on their respective estimated fair market values at the date of acquisition, based on an independent appraisal. The accompanying financial statements include the results of operations of the California assets since the date of acquisition in 2002.

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TESORO CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
NOTE D — DIVESTITURES
      On December 23, 2003, we sold substantially all of the physical assets, including inventories, of our marine services operations for $32 million in cash. Tesoro recognized a pretax loss on the sale of $8 million. We included this charge in loss on asset sales and impairments in our statements of consolidated operations due to the immateriality of marine services operations as compared to our historical and ongoing refining and retail operations.
      On December 26, 2002, we sold our product pipeline extending from Mandan, North Dakota to Minneapolis, Minnesota and terminals in North Dakota and Minnesota for $100 million in cash. Tesoro’s gain on the sale of these assets was immaterial. We continue to distribute products from our North Dakota refinery through the product pipeline under a tariff arrangement, which expires in 2012.
      In December 2002, we sold 70 retail stations in northern California for $66 million in cash, including inventories. We purchased these stations in May 2002 as part of the California refinery acquisition and we retain responsibility for all environmental liabilities at the stations arising prior to their sale. We recognized a pretax loss on the sale of $2.5 million. We continue to sell products to a majority of the stations under an unbranded supply agreement, which expires in 2005 with short-term renewable provisions thereafter.
      On December 31, 2002, we completed a sale/ lease-back transaction for 30 of our retail stations located in Alaska, Hawaii, Idaho and Utah for cash proceeds of $40 million. We recognized a pretax loss on the sale of $4 million. The leases are for land, buildings and certain equipment and have an initial term of 17 years with four 5-year renewal options. The portion of the leases attributable to land is accounted for as an operating lease, while the portion attributable to buildings and equipment is accounted for as a capital lease (see Notes F and P).
NOTE E — OPERATING SEGMENTS
      The Company’s revenues are derived from two operating segments: (i) refining and (ii) retail. Our refining segment owns and operates six petroleum refineries located in California, Washington, Alaska, Hawaii, North Dakota and Utah. These refineries manufacture gasoline and gasoline blendstocks, jet fuel, diesel fuel, residual fuel oils and other refined products. We sell these products, together with products purchased from third parties, at wholesale through terminal facilities and other locations, primarily in Alaska, California, Nevada, Hawaii, Idaho, Minnesota, North Dakota, Utah, Oregon and Washington. Our refining segment also sells petroleum products to unbranded marketers and occasionally exports products to other markets in the Asia/ Pacific area. Our retail segment sells gasoline, diesel fuel and convenience store items through company-operated retail stations and branded jobber/dealers in 18 western states from Minnesota to Alaska and Hawaii. Retail operates under the Tesoro®, Mirastar® and 2-Go Tesoro® brands. We developed our Mirastar® brand exclusively for use at Wal-Mart stores in an agreement covering 17 western states. Prior to 2004, we also had revenues from our marine services operations, which marketed and distributed petroleum products, supplies and services to the marine and offshore exploration and production industries operating in the Gulf of Mexico. We sold substantially all of the marine services physical assets in December 2003 (see Note D).
      The operating segments adhere to the accounting policies used for Tesoro’s consolidated financial statements, as described in the summary of significant accounting policies in Note A. We evaluate the performance of our segments and allocate 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 are primarily from refining to retail made at prevailing market rates. Income taxes, interest and financing costs, corporate general and administrative expenses and losses on asset sales and impairments are not included in determining segment operating income. Identifiable assets are those utilized by the segment. Corporate assets are principally cash and other assets that are not associated with a specific operating segment.

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TESORO CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
      Segment information as of and for each of the three years ended December 31, 2004 is as follows (in millions):
                               
    2004   2003   2002
             
Revenues
                       
 
Refining:
                       
   
Refined products
  $ 11,633.2     $ 8,098.3     $ 6,425.7  
   
Crude oil resales and other(a)
    419.3       370.3       334.6  
 
Retail:
                       
   
Fuel
    863.5       797.5       920.4  
   
Merchandise and other
    130.8       120.6       132.1  
 
Marine Services
          155.4       132.2  
 
Intersegment sales from Refining to Retail
    (784.6 )     (696.4 )     (825.7 )
                   
     
Total Revenues
  $ 12,262.2     $ 8,845.7     $ 7,119.3  
                   
Segment Operating Income (Loss)
                       
 
Refining
  $ 840.3     $ 411.1     $ 72.9  
 
Retail
    (2.0 )     15.7       (12.3 )
 
Marines Services
          6.3       2.3  
                   
     
Total Segment Operating Income
    838.3       433.1       62.9  
 
Corporate and Unallocated Costs
    (111.0 )     (81.4 )     (73.2 )
 
Loss on Asset Sales and Impairments
    (14.1 )     (16.9 )     (8.4 )
                   
     
Operating Income (Loss)(b)
    713.2       334.8       (18.7 )
 
Interest and Financing Costs, Net
    (166.6 )     (211.7 )     (162.6 )
                   
     
Earnings (Loss) Before Income Taxes
  $ 546.6     $ 123.1     $ (181.3 )
                   
Depreciation and Amortization
                       
 
Refining
  $ 129.9     $ 120.4     $ 104.2  
 
Retail
    17.6       19.2       16.9  
 
Marine Services
          2.0       3.1  
 
Corporate
    6.6       6.6       6.5  
                   
   
Total Depreciation and Amortization
  $ 154.1     $ 148.2     $ 130.7  
                   
Capital Expenditures(c)
                       
 
Refining
  $ 166.6     $ 97.4     $ 150.9  
 
Retail
    3.2       1.2       40.6  
 
Marine Services
          0.7       2.5  
 
Corporate
    9.6       1.8       9.5  
                   
   
Total Capital Expenditures
  $ 179.4     $ 101.1     $ 203.5  
                   
Identifiable Assets
                       
 
Refining
  $ 3,543.9     $ 3,183.2     $ 3,118.1  
 
Retail
    241.0       261.4       287.8  
 
Marine Services
          21.1       68.4  
 
Corporate
    290.2       195.6       284.5  
                   
   
Total Assets
  $ 4,075.1     $ 3,661.3     $ 3,758.8  
                   
 
(a) To balance or optimize our refinery supply requirements, we sell certain crude oil that we purchase under our supply contracts.

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TESORO CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(b) Operating income in 2003 included charges of $8.4 million, included in corporate and unallocated costs, for the termination of Tesoro’s funded executive security plan (see Note N) and $9.0 million in voluntary early retirement benefits and severance costs. The $9.0 million charge included $2.6 million in refining, $1.3 million in retail, $0.4 million in marine services and $4.7 million in corporate.
 
(c) Excludes asset acquisitions of $932 million in 2002 (see Note C) and refinery turnaround and other major maintenance costs of $50.0 million, $51.5 million and $40.6 million in 2004, 2003 and 2002, respectively.
NOTE F — DEBT
      At December 31, 2004 and 2003, debt consisted of (in millions):
                   
    2004   2003
         
Credit Agreement — Revolving Credit Facility
  $     $  
Senior Secured Term Loans
    97.0       199.0  
8% Senior Secured Notes Due 2008 (net of unamortized discount of $2.7 in 2004 and $3.3 in 2003)
    372.3       371.7  
95/8% Senior Subordinated Notes Due 2012
    429.0       429.0  
95/8% Senior Subordinated Notes Due 2008
    211.0       211.0  
9% Senior Subordinated Notes Due 2008 (net of unamortized discount of $1.8)
          295.7  
Junior subordinated notes due 2012 (net of unamortized discount of $66.8 in 2004 and $75.0 in 2003)
    83.2       75.0  
Capital lease obligations and other
    25.8       27.4  
             
 
Total debt
    1,218.3       1,608.8  
Less current maturities
    3.4       3.5  
             
 
Debt, less current maturities
  $ 1,214.9     $ 1,605.3  
             
      The aggregate maturities of Tesoro’s debt for each of the five years following December 31, 2004 were: 2005 — $3.4 million; 2006 — $3.4 million; 2007 — $94.2 million; 2008 — $587.1 million; and 2009 — $1.0 million.
Credit Agreement
      In September 2004, we amended our credit agreement to (i) increase its capacity an additional $100 million to $750 million, (ii) modify the amount of permitted restricted payments and subordinated debt repayments and (iii) reduce the applicable margins on revolver borrowings. In addition, the amendment provides the flexibility to obtain up to $250 million in letters of credit outside of the credit agreement for foreign crude oil purchases. The credit agreement was previously amended in May 2004 to increase its capacity by $150 million to $650 million and to extend the term by one year to June 2007.
      The credit agreement currently provides for borrowings (including letters of credit) up to the lesser of the agreement’s total capacity, $750 million as amended, or the amount of a periodically adjusted borrowing base ($813 million as of December 31, 2004), consisting of Tesoro’s eligible cash and cash equivalents, receivables and petroleum inventories, as defined. As of December 31, 2004, we had no borrowings and $341 million in letters of credit outstanding under the revolving credit facility, resulting in total unused credit availability of $409 million or 55% of the eligible borrowing base. Borrowings under the revolving credit facility bear interest at either a base rate (5.25% at December 31, 2004) or a eurodollar rate (2.49% at December 31, 2004), plus an applicable margin. The applicable margins at December 31, 2004 were 0.25% in the case of the base rate and 2.00% in the case of the eurodollar rate and vary based on credit facility availability. Letters of credit

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TESORO CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
outstanding under the revolving credit facility incur fees at an annual rate tied to the eurodollar rate applicable margin, in the range of 1.75% to 2.00% at December 31, 2004.
      The credit agreement contains covenants and conditions that, among other things, limit our ability to pay cash dividends, incur indebtedness, create liens and make investments. Tesoro is also required to maintain specified levels of fixed charge coverage and tangible net worth. We are not required to maintain the fixed charge coverage ratio if unused credit availability exceeds 15% of the eligible borrowing base. The credit agreement is guaranteed by substantially all of Tesoro’s active subsidiaries and is secured by substantially all of Tesoro’s cash and cash equivalents, petroleum inventories and receivables.
9% Senior Subordinated Notes Due 2008
      In July 2004, we voluntarily prepaid the remaining $297.5 million outstanding principal balance of the 9% senior subordinated notes at a call premium of 3%. The prepayment resulted in a pretax charge during 2004 of $16 million, comprising $9 million for the 3% call premium and $7 million for the write-off of unamortized debt issuance and discount costs.
Senior Secured Term Loans
      In April 2003, we entered into $200 million senior secured term loans and in September 2004, we voluntarily prepaid $100 million of our senior secured term loans at a prepayment premium of 3%. The prepayment resulted in a pretax charge during 2004 of $5 million, comprising $3 million for the 3% prepayment premium and $2 million for the write-off of unamortized debt issuance costs. As a result of the prepayment, the term loans will mature in October 2007, prior to its original maturity date of April 2008. Principal payments of the term loans are repaid in quarterly installments of $500,000 through April 2007, and the remaining principal payments of $48 million and $44 million are payable in July 2007 and October 2007, respectively. The term loans are subject to optional redemption by Tesoro at premiums of 3% through April 14, 2005, 1% from April 15, 2005 to April 14, 2006, and at par thereafter.
      The term loans contain covenants and restrictions that are less restrictive than those in the credit agreement. The term loans and the 8% senior secured notes, described below, are equally secured by substantially all of the Tesoro’s refining property, plant and equipment and are guaranteed by substantially all of Tesoro’s active subsidiaries. The interest rate on the term loans at December 31, 2004 was 7.99%. Borrowings under the term loans bear interest at either a base rate (5.25% at December 31, 2004) or a eurodollar rate (2.49% at December 31, 2004), plus an applicable margin. The applicable margins for the term loans were 4.5% in the case of the base rate and 5.5% in the case of the eurodollar rate at December 31, 2004.
8% Senior Secured Notes Due 2008
      In April 2003, Tesoro issued $375 million aggregate principal amount of 8% senior secured notes due April 15, 2008. The notes have a five-year maturity with no sinking fund requirements and are subject to optional redemption by Tesoro, beginning April 15, 2006, at a premium of 4% through April 14, 2007, and at par thereafter. We have the right to redeem up to 35% of the aggregate principal amount at a redemption price of 108% with proceeds from certain equity issuances through April 15, 2006. The indenture for the notes contains covenants and restrictions that are customary for notes of this nature and are similar to the covenants in the indentures for Tesoro’s senior subordinated debt. The notes and the term loans are equally secured by substantially all of Tesoro’s refining property, plant and equipment and are guaranteed by substantially all of Tesoro’s active subsidiaries. The notes were issued at 98.994% of par, resulting in net proceeds of $371.2 million before debt issuance costs. The effective interest rate on the notes is 8.25%, after giving effect to the discount.

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TESORO CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
95/8% Senior Subordinated Notes Due 2012
      In April 2002, Tesoro issued $450 million principal amount of 95/8% senior subordinated notes due April 1, 2012. These notes have a ten-year maturity with no sinking fund requirements and are subject to optional redemption by Tesoro, beginning April 1, 2007 at premiums of 4.8% through March 31, 2008, 3.2% from April 1, 2008 to March 31, 2009, 1.6% from April 1, 2009 to March 31, 2010, and at par thereafter. The indenture for these notes contains covenants and restrictions which are customary for notes of this nature. To the extent Tesoro’s fixed charge coverage ratio, as defined in the indenture, allows us to incur additional debt, we are allowed to pay cash dividends on common stock and repurchase shares of common stock, subject to limitations in our credit agreement. The notes are guaranteed by substantially all of Tesoro’s active domestic subsidiaries.
95/8% Senior Subordinated Notes Due 2008
      In November 2001, Tesoro issued $215 million principal amount of 95/8% senior subordinated notes due November 1, 2008. These notes have a seven-year maturity with no sinking fund requirements and are subject to optional redemption by Tesoro, beginning November 1, 2005 at premiums of 4.8% through October 31, 2006, 2.4% from November 1, 2006 to October 31, 2007, and at par thereafter. The indenture for these notes contains covenants and restrictions which are customary for notes of this nature. To the extent Tesoro’s fixed charge coverage ratio, as defined in the indenture, allows us to incur additional debt, we are allowed to pay cash dividends on common stock and repurchase shares of common stock, subject to limitations in our credit agreement. The notes are guaranteed by substantially all of Tesoro’s active domestic subsidiaries.
Junior Subordinated Notes Due 2012
      In connection with our acquisition of the California refinery, Tesoro issued to the seller two ten-year junior subordinated notes with face amounts totaling $150 million. The notes consist of: (i) a $100 million junior subordinated note, due July 2012, which is non-interest bearing through May 16, 2007, and carries a 7.5% interest rate thereafter, and (ii) a $50 million junior subordinated note, due July 2012, which bears interest at 7.47% from May  17, 2003 through May 16, 2007 and 7.5% thereafter. We initially recorded these two notes at a combined present value of approximately $61 million, discounted at rates of 15.625% and 14.375%, respectively. We are amortizing the discount over the term of the notes.
Capital Lease Obligations
      Our capital lease obligations comprise primarily of 30 retail stations that we sold and leased-back in 2002 with initial terms of 17 years, with four 5-year renewal options (See Note D). We classified the portions of the leases attributable to land as operating leases, and we classified the portions attributable to depreciable buildings and equipment as capital leases. The combined present value of minimum lease payments totaled $23.2 million at December 31, 2004. Tesoro also has other capital leases for tugs and barges used to transport petroleum products, over varying terms ending in 2005 through 2010, in which the combined present value of minimum lease payments totaled $2.5 million at December 31, 2004.
      At December 31, 2004 and 2003, the total cost of assets under capital leases was $34.6 million gross (accumulated amortization of $11.8 million) and $34.7 million gross (accumulated amortization of $9.6 million), respectively. Capital lease obligations included in debt totaled $25.7 million and $27.4 million at December 31, 2004 and 2003, respectively. We include amortization of the cost of assets under capital leases in depreciation and amortization.

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TESORO CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
      Future minimum annual lease payments, including interest, as of December 31, 2004 for capital leases were (in millions):
           
2005
  $ 3.9  
2006
    3.9  
2007
    3.5  
2008
    3.4  
2009
    3.1  
Thereafter
    32.8  
       
 
Total minimum lease payments
    50.6  
Less amount representing interest
    24.9  
       
 
Capital lease obligations
  $ 25.7  
       
NOTE G — STOCKHOLDERS’ EQUITY
      In March 2002, Tesoro completed a public offering of 23 million shares of common stock. We used the net proceeds from the stock offering of $245.1 million, after deducting underwriting fees and offering expenses, to partially fund our acquisition of the California refinery.
      Our credit agreement, senior secured notes and senior subordinated notes each limit our ability to pay cash dividends or repurchase stock. The limitation in each of our debt agreements is based on limits on restricted payments (as defined in our debt agreements), which include dividends, stock repurchases or voluntary prepayments of subordinate debt. The aggregate amount of restricted payments cannot exceed an amount defined in each of the debt agreements.
      See Note O for information relating to stock-based compensation and common stock reserved for exercise of options.
NOTE H — INCOME TAXES
      The income tax provision (benefit) was comprised of (in millions):
                             
    2004   2003   2002
             
Current:
                       
 
Federal
  $ 103.9     $ (8.5 )   $ (60.8 )
 
State
    12.4             (6.8 )
Deferred:
                       
 
Federal
    77.8       53.5       8.5  
 
State
    24.6       2.0       (5.2 )
                   
   
Income Tax Provision (Benefit)
  $ 218.7     $ 47.0     $ (64.3 )
                   

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TESORO CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
      We provide deferred income taxes and benefits for differences between financial statement carrying amounts of assets and liabilities and their respective tax bases. Temporary differences and the resulting deferred tax liabilities and assets at December 31, 2004 and 2003 were (in millions):
                   
    2004   2003
         
Current Deferred Federal Tax Assets and Liabilities:
               
 
LIFO inventory
  $ (43.1 )   $ (27.6 )
 
Alternative minimum tax credits
    37.6        
 
Accrued pension and other postretirement benefits
          6.3  
 
Other accrued employee costs
    4.9       4.8  
 
Accrued environmental remediation liabilities
    2.9       4.0  
 
Other accrued liabilities
    4.1       (1.2 )
Current Deferred State Tax Asset (Liability), Net
    (3.3 )     5.5  
             
 
Current Deferred Tax Asset (Liability), Net
  $ 3.1     $ (8.2 )
             
Noncurrent Deferred Federal Tax Assets and Liabilities:
               
 
Accelerated depreciation and property related items
  $ (350.1 )   $ (276.5 )
 
Deferred maintenance costs, including refinery turnarounds
    (30.5 )     (23.5 )
 
Amortization of intangible assets
    (26.1 )     (33.2 )
 
Net operating loss carry forwards
          77.0  
 
Accrued pension and other postretirement benefits
    61.5       51.7  
 
Alternative minimum tax credits
    58.6       27.4  
 
Accrued environmental remediation liabilities
    6.1       5.9  
 
Other
    22.0       10.6  
Noncurrent Deferred State Tax Liability, Net
    (34.4 )     (18.6 )
             
 
Noncurrent Deferred Tax Liability, Net
  $ (292.9 )   $ (179.2 )
             
      The realization of deferred tax assets depends on Tesoro’s ability to generate future taxable income. Although realization is not assured, we believe it is more likely than not that we will realize the deferred tax assets, and therefore, we did not record a valuation allowance as of December 31, 2004 or 2003.
      The reconciliation of income tax expense (benefit) at the U.S. statutory rate to the income tax expense (benefit) follows (in millions):
                           
    2004   2003   2002
             
Income Taxes (Benefit) at U.S. Federal Statutory Rate
  $ 191.4     $ 43.1     $ (63.5 )
Effect of:
                       
 
State income taxes, net of federal income tax effect
    23.9       5.9       (7.8 )
 
Expired tax credits
                3.9  
 
State tax credits, net
    (0.5 )     (4.6 )      
 
Other
    3.9       2.6       3.1  
                   
Income Tax Provision (Benefit)
  $ 218.7     $ 47.0     $ (64.3 )
                   
      As of December 31, 2004, Tesoro had approximately $96.2 million of alternative minimum tax credits that we carry forward indefinitely and no Federal net operating loss carry-forwards. Our filing of the 2002 and 2001 tax returns and the carryback of the net operating losses for both years resulted in the receipt of refunds

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TESORO CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
of $51 million and $48 million during 2003 and 2002, respectively. However, our election to carry back the 2002 net operating losses resulted in the loss of $3.9 million of tax credits claimed in earlier years.
NOTE I — RECEIVABLES
      Concentrations of credit risk with respect to accounts receivable are influenced by the large number of customers comprising Tesoro’s customer base and their dispersion across various industry groups and geographic areas of operations. We perform ongoing credit evaluations of our customers’ financial condition, and in certain circumstances, require prepayments, letters of credit or other collateral arrangements. We include an allowance for doubtful accounts as a reduction in our trade receivables, which amounted to $4.6 million and $4.3 million at December 31, 2004 and 2003, respectively.
NOTE J — INVENTORIES
      Components of inventories at December 31, 2004 and 2003 were (in millions):
                   
    2004   2003
         
Crude oil and refined products, at LIFO cost
  $ 559.9     $ 430.1  
Oxygenates and by-products, at the lower of FIFO cost or market
    5.5       9.7  
Merchandise
    9.1       7.4  
Materials and supplies
    41.2       40.1  
             
 
Total Inventories
  $ 615.7     $ 487.3  
             
      Inventories valued at LIFO cost were less than replacement cost by approximately $385 million and $210 million, at December 31, 2004 and 2003, respectively. During 2002, we reduced certain inventories resulting in a decrease in LIFO inventory quantities, which had been carried at lower costs prevailing in previous years. This LIFO inventory liquidation decreased our costs of sales by $5 million and the net loss by approximately $3 million, or $0.05 per share, in 2002.
NOTE K — GOODWILL AND ACQUIRED INTANGIBLES
      SFAS No. 142 requires that goodwill and other intangibles determined to have an indefinite life are no longer to be amortized but are to be tested for impairment at least annually. We review the recorded value of goodwill for impairment during the fourth quarter of each year, or sooner if events or changes in circumstances indicate the carrying amount may exceed fair value. Our annual evaluation of goodwill impairment requires us to make significant estimates to determine the fair value of our reporting units. Our estimates may change from period to period because we must make assumptions about future cash flows, profitability and other matters. It is reasonably possible that future changes in our estimates could have a material effect on the carrying amount of goodwill. Goodwill included $84.0 million in refining and $4.7 million in retail at both December 31, 2004 and 2003.

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TESORO CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
      The following table provides the gross carrying amount and accumulated amortization for each major class of acquired intangible assets, excluding goodwill (in millions):
                                                   
    December 31, 2004   December 31, 2003
         
    Gross       Net   Gross       Net
    Carrying   Accumulated   Carrying   Carrying   Accumulated   Carrying
    Amount   Amortization   Value   Amount   Amortization   Value
                         
Air emissions credits
  $ 98.7     $ 9.7     $ 89.0     $ 98.7     $ 6.2     $ 92.5  
Refinery permits and plans
    11.0       1.8       9.2       11.0       1.2       9.8  
Customer agreements and contracts
    39.8       17.4       22.4       39.8       11.3       28.5  
Other intangibles
    9.2       2.6       6.6       12.7       4.9       7.8  
                                     
 
Total
  $ 158.7     $ 31.5     $ 127.2     $ 162.2     $ 23.6     $ 138.6  
                                     
      The weighted average estimated lives of acquired intangible assets are: air emission credits — 28 years; refinery permits and plans — 22 years; customer agreements and contracts — 14 years; and other intangible assets — 19 years. Amortization expense of acquired intangible assets amounted to $11.4 million, $10.3 million and $8.8 million for the years ended December 31, 2004, 2003 and 2002, respectively. Our estimated amortization expense for each of the following five years is: 2005 — $8 million; 2006 — $7 million; 2007 — $6 million; 2008 — $6 million; and 2009 — $6 million.
NOTE L — OTHER NONCURRENT ASSETS
      Other noncurrent assets at December 31, 2004 and 2003 consisted of (in millions):
                   
    2004   2003
         
Deferred maintenance costs, including refinery turnarounds, net of amortization
  $ 98.8     $ 82.8  
Debt issuance costs, net of amortization
    31.3       43.5  
Intangible pension asset
    6.0       4.2  
Notes receivable from employees
    2.3       2.5  
Other assets, net of amortization
    23.8       25.5  
             
 
Total Other Assets
  $ 162.2     $ 158.5  
             
      In May 2002, in connection with the acquisition of our California refinery, Tesoro assumed two non-interest bearing notes due from an employee who subsequently become an executive officer with remaining terms of 4 and 6 years, which totaled approximately $0.7 million and $0.8 million at December 31, 2004 and 2003, respectively.

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TESORO CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
NOTE M — ACCRUED LIABILITIES
      The Company’s current accrued liabilities and noncurrent other liabilities at December 31, 2004 and 2003 included (in millions):
                     
    2004   2003
         
Accrued Liabilities — Current:
               
 
Taxes other than income taxes, primarily excise taxes
  $ 103.5     $ 73.0  
 
Income taxes payable
    60.8       3.7  
 
Employee costs
    53.8       51.9  
 
Interest
    27.6       40.3  
 
Pension benefits
          32.3  
 
Other
    57.0       50.5  
             
   
Total Accrued Liabilities — Current
  $ 302.7     $ 251.7  
             
Other Liabilities — Noncurrent:
               
 
Pension and other postretirement benefits
  $ 175.3     $ 157.4  
 
MTBE facility lease termination obligation
    22.2       29.5  
 
Other
    50.0       37.5  
             
   
Total Other Liabilities — Noncurrent
  $ 247.5     $ 224.4  
             
      As part of our California refinery acquisition in 2002, we acquired an operating lease for an MTBE production facility. We accrued the termination obligation because California state regulations required the phase-out of MTBE by December 31, 2003. We have not terminated the lease and expect to make payments throughout the remaining term of the lease ending in 2010.
NOTE N — BENEFIT PLANS
Pension and Other Postretirement Benefits
      Tesoro sponsors defined benefit pension plans, including a funded employee retirement plan, an unfunded executive security plan and an unfunded non-employee director retirement plan. We provide a qualified noncontributory retirement plan for all eligible employees. Benefits are based on years of service and compensation. Although Tesoro has no minimum required contribution obligation to its pension plan under applicable laws and regulations in 2005, we expect to contribute $12 million to the plan in 2005. We contributed $53 million in 2004. Plan assets are primarily comprised of common stock and bond funds.
      Tesoro’s unfunded executive security plan provides certain executive officers and other key personnel with supplemental death or retirement benefits. These benefits are provided by a nonqualified, noncontributory plan and are based on years of service and compensation. During December 2003, we terminated our funded executive security plan, resulting in a write-off of unamortized prepaid pension costs of $6.9 million and a plan curtailment contribution of $1.5 million. We made additional contributions of $2.9 million to the funded plan in 2003.

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TESORO CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
      Tesoro had previously established an unfunded non-employee director retirement plan that provided eligible directors retirement payments upon meeting certain age and other requirements. In 1997, that plan was frozen with accrued benefits of current directors transferred to the board of directors phantom stock plan (see Note O). After the amendment and transfer, only those retired directors or beneficiaries who had begun to receive benefits remained participants in the previous plan.
      Tesoro provides to retirees who met certain service requirements and were participating in our group insurance program at retirement, health care benefits and, to those who qualify, life insurance benefits. Health care is available to qualified dependents of participating retirees. These benefits are provided through unfunded, defined benefit plans or through contracts with area health-providers on a premium basis. The health care plans are contributory, with retiree contributions adjusted periodically, and contain other cost-sharing features such as deductibles and coinsurance. The life insurance plan is noncontributory. We fund Tesoro’s share of the cost of postretirement health care and life insurance benefits on a pay-as-you go basis.
      Our retiree medical plan provides prescription drug benefits, which were affected by the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the “Act”), signed in to law in December 2003. The Act introduces a prescription drug benefit under Medicare (Medicare Part D), as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare Part D. In May 2004, the FASB issued FASB Staff Position No. FAS 106-2 (“FAS 106-2”), “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003,” which provides guidance for the accounting of the federal subsidy. On July 1, 2004, we elected the “prospective application” of adoption for the recognition of the federal subsidy as defined in FAS 106-2. The effect of recognizing the federal subsidy in accordance with FAS 106-2 will result in an annual reduction of postretirement benefit expense of approximately $1 million, of which approximately $500,000 was recognized during 2004. The effect of the subsidy resulted in a $10 million reduction in our benefit obligation as of December 31, 2004, and is reflected in the table below as an actuarial gain in other postretirement benefits. We expect to receive approximately $200,000 annually in federal subsidy receipts for the years 2006 through 2009 and an aggregate $1.5 million for the years 2010 through 2014.

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TESORO CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
      We use December 31 as the measurement date for all of our defined benefit pension plans. Changes in benefit obligations, plan assets and the funded status of the pension plans and other postretirement benefits, reconciled to amounts in the consolidated balance sheets as of December 31, 2004 and 2003, were (in millions):
                                     
        Other Postretirement
    Pension Benefits   Benefits
         
    2004   2003   2004   2003
                 
Change in benefit obligations:
                               
 
Benefit obligations at beginning of year
  $ 181.3     $ 184.7     $ 137.2     $ 138.3  
 
Service cost
    16.1       15.0       7.6       7.9  
 
Interest cost
    11.5       11.1       8.1       7.8  
 
Actuarial (gain) loss
    19.1       (4.1 )     (0.8 )     (15.7 )
 
Benefits paid
    (9.9 )     (33.3 )     (2.6 )     (1.6 )
 
Curtailments and settlements
    (0.6 )                  
 
Plan amendments
          1.5              
 
Special termination benefits
          6.4             0.5  
                         
   
Benefit obligations at end of year
    217.5       181.3       149.5       137.2  
                         
Change in plan assets:
                               
 
Fair value of plan assets at beginning of year
    74.5       72.8              
 
Actual return on plan assets
    11.6       13.8              
 
Employer contributions
    53.4       21.2              
 
Benefits paid
    (9.9 )     (33.3 )            
                         
   
Fair value of plan assets at end of year
    129.6       74.5              
                         
Funded status
    (87.9 )     (106.8 )     (149.5 )     (137.2 )
Unrecognized prior service cost
    11.1       9.3       2.0       2.2  
Unrecognized net actuarial loss
    43.8       34.9       11.2       12.0  
                         
   
Accrued benefit cost
  $ (33.0 )   $ (62.6 )   $ (136.3 )   $ (123.0 )
                         
Amounts included in consolidated balance sheets:
                               
 
Accrued and other liabilities
  $ (39.0 )   $ (66.8 )   $ (136.3 )   $ (123.0 )
 
Intangible asset
    6.0       4.2              
                         
   
Net amount recognized
  $ (33.0 )   $ (62.6 )   $ (136.3 )   $ (123.0 )
                         
      The combined accumulated benefit obligations for our retirement plans was $168.8 million and $141.3 million at December 31, 2004 and 2003, respectively. At December 31, 2004 and 2003, the accumulated benefit obligation of the employee retirement and executive security plan exceeded the fair value of plan assets, and we recognized an additional minimum liability and an intangible asset of $6.0 million and $4.2 million, respectively. In 2003, Tesoro offered voluntary enhanced retirement benefits to certain qualified employees. These enhanced benefits resulted in an increase to the pension benefit obligation of $1.4 million and a charge to expense of $6.4 million.

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TESORO CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
      The components of pension and postretirement benefit expense included in the consolidated statements of operations for the years ended December 31, 2004, 2003 and 2002 were (in millions):
                                                     
        Other Postretirement
    Pension Benefits   Benefits
         
    2004   2003   2002   2004   2003   2002
                         
Components of net periodic benefit expense:
                                               
 
Service cost
  $ 16.1     $ 15.0     $ 13.5     $ 7.6     $ 7.9     $ 6.1  
 
Interest cost
    11.5       11.1       10.9       8.1       7.8       7.1  
 
Expected return on plan assets
    (6.8 )     (7.0 )     (6.6 )                  
 
Amortization of prior service cost
    1.7       1.1       1.0       0.2       0.2       0.2  
 
Recognized net actuarial loss
    2.1       5.1       3.6             0.2       0.3  
 
Curtailments and settlements
          8.4       (0.2 )                  
 
Special termination benefits
    (0.7 )     6.4                   0.5        
                                     
   
Net periodic benefit expense
  $ 23.9     $ 40.1     $ 22.2     $ 15.9     $ 16.6     $ 13.7  
                                     
      Significant assumptions included in estimating Tesoro’s pension and other postretirement benefits obligations were:
                                                   
        Other Postretirement
    Pension Benefits   Benefits
         
    2004   2003   2002   2004   2003   2002
                         
Projected Benefit Obligation:
                                               
Assumed weighted average % as of December 31:
                                               
 
Discount rate
    5.75       6.25       6.34       5.75       6.25       6.50  
 
Rate of compensation increase
    3.43       3.78       4.12                    
Net Periodic Pension Cost:
                                               
Assumed weighted average % as of December 31:
                                               
 
Discount rate
    6.25       6.05       6.97       6.25       6.50       7.25  
 
Rate of compensation increase
    3.89       4.32       5.00                    
 
Expected return on plan assets
    8.50       8.04       8.17                    
      The expected return on plan assets reflects the weighted-average of the expected long-term rates of return for the broad categories of investments held in the plans. The expected long-term rate of return is adjusted when there are fundamental changes in expected returns on the plan’s investments.
      The assumed health care cost trend rates used to determine the projected postretirement benefit obligation are as follows:
                 
    2004   2003
         
Health care cost trend rate assumed for next year
    7.86 %     8.43 %
Rate to which the cost trend rate is assumed to decline
    5.00 %     5.00 %
Year that the rate reaches the ultimate trend rate
    2010       2010  

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TESORO CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
      Assumed health care cost trend rates have a significant effect on the amounts reported for the health care and life insurance plans. A one-percentage-point change in assumed health care cost trend rates could have the following effects (in millions):
                 
    1-Percentage-Point   1-Percentage-Point
    Increase   Decrease
         
Effect on total of service and interest cost components
  $ 3.1     $ (2.4 )
Effect on postretirement benefit obligations
  $ 26.9     $ (21.1 )
      Our pension plans follow an investment return approach in which investments are allocated to broad investment categories, including equities, debt and real estate, to maximize the long-term return of the plan assets at a prudent level of risk. The target allocations for the pension plan’s assets were 70% equity securities (with sub-category allocation targets), 24% debt securities and 6% real estate. The weighted-average asset allocations in our pension plans, at December 31, 2004 and 2003, were:
                   
    Plan Assets
    at
    December 31,
     
Asset Category   2004   2003
         
Equity Securities
    72 %     66 %
Debt Securities
    23       25  
Real Estate
    5       8  
Other
          1  
             
 
Total
    100 %     100 %
             
      Our other postretirement benefit plans contained no assets at December 31, 2004 and 2003.
      The following estimated future benefit payments, which reflect expected future service, as appropriate, are expected to be paid in the years indicated (in millions):
                 
        Other
    Pension   Postretirement
    Benefits   Benefits
         
2005
  $ 12.6     $ 3.3  
2006
    14.2       3.9  
2007
    16.8       4.4  
2008
    19.4       5.1  
2009
    22.7       5.8  
2010-2014
    142.0       41.8  
Thrift Plan and Retail Savings Plan
      Tesoro sponsors an employee thrift plan that provides for contributions, subject to certain limitations, by eligible employees into designated investment funds with a matching contribution by Tesoro. Employees may elect tax-deferred treatment in accordance with the provisions of Section 401(k) of the Internal Revenue Code. Tesoro matches 100% of employee contributions, up to 7% of the employee’s eligible earnings, with at least 50% of the matching contribution directed for initial investment in Tesoro’s common stock. The maximum matching contribution is 6% for employees covered by the collective bargaining agreement at the California refinery. Effective January 1, 2004, participants may transfer out of Tesoro’s common stock at any time, on an unlimited basis. Tesoro’s contributions to the thrift plan amounted to $13.3 million, $11.4 million and $11.1 million during 2004, 2003 and 2002, respectively, of which $5.9 million, $0.9 million and $2.4 million consisted of treasury stock reissuances in 2004, 2003 and 2002, respectively.

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TESORO CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
      Tesoro sponsors a savings plan, in lieu of the thrift plan, for eligible retail employees who have completed one year of service and have worked at least 1,000 hours within that time. Eligible employees receive a mandatory employer contribution equal to 3% of eligible earnings. If employees elect to make pretax contributions, Tesoro also contributes an employer match contribution equal to $0.50 for each $1.00 of employee contributions, up to 6% of eligible earnings. At least 50% of the matching employer contributions must be directed for initial investment in Tesoro common stock. Effective January 1, 2004, participants may transfer out of Tesoro’s common stock at any time, on an unlimited basis. Tesoro’s contributions amounted to $0.4 million during 2004, 2003 and 2002, of which $0.1 million consisted of treasury stock reissuances in 2004 and 2002.
     NOTE O — STOCK-BASED COMPENSATION
      Effective January 1, 2004, we adopted the preferable fair value method of accounting for stock options, as prescribed in SFAS No. 123. We selected the “modified prospective method” of adoption described in SFAS No. 148 recognizing compensation cost as if the fair value method of SFAS No. 123 had been applied from its original effective date. The adoption of this standard resulted in pretax charges for the year ended December 31, 2004 of $8.4 million, including $1.7 million associated with the announced retirement of certain executive officers. See Note A for information related to the pro forma effects, had compensation cost been determined based on fair values at the grant dates of awards during 2003 and 2002 in accordance with SFAS No. 123. Effective January  1, 2005, we adopted the provisions of SFAS No. 123 (Revised 2004), “Share-Based Payment,” which requires compensation cost related to all employee stock-based awards to be expensed equal to the fair value of the award on the grant date. SFAS No. 123 (Revised 2004) will require Tesoro to adopt the fair value method for our outstanding phantom stock options.
Incentive Stock Plans
      We have two employee incentive stock plans, the Amended and Restated Executive Long-Term Incentive Plan and the Key Employee Stock Option Plan, as amended. Tesoro also has the 1995 Non-Employee Director Stock Option Plan, as amended. At December 31, 2004, Tesoro had 7,621,862 shares of unissued common stock reserved for these plans.
      Under the Amended and Restated Executive Long-Term Incentive Plan, shares of common stock may be granted in a variety of forms, including restricted stock, nonqualified stock options, stock appreciation rights and performance share and performance unit awards. Stock options may be granted at exercise prices not less than the fair market value on the date the options are granted. The options granted generally become exercisable after one year in 25% or 33% annual increments and expire ten years from the date of grant. At Tesoro’s annual meeting of stockholders held in May 2004, an amendment was approved by the stockholders to (i) increase the total number of shares available for grant under the plan from 7,250,000 shares to 9,250,000 shares, (ii) increase from 750,000 to 1,500,000 the limitation on the total number of those shares that may be granted as restricted stock during the life of the plan and include within the limitation grants of performance shares and performance units, and (iii) expressly provide that options granted under the plan may not be repriced without stockholder approval. The plan will expire, unless earlier terminated, as to the issuance of awards in September 2008. At December 31, 2004, Tesoro had 1,467,352 shares available for future grants under this plan.
      The Key Employee Stock Option Plan provided stock option grants to eligible employees who were not executive officers of Tesoro. We granted stock options to purchase 797,000 shares of common stock, of which 356,550 shares were outstanding at December 31, 2004, which become exercisable one year after grant in 25% annual increments. The options expire ten years after the date of grant. The board of directors has suspended any future grants under this plan.

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TESORO CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
      The 1995 Non-Employee Director Stock Option Plan provides for the grant of nonqualified stock options to eligible non-employee directors of Tesoro. These automatic, non-discretionary stock options are granted at an exercise price equal to the fair market value per share of Tesoro’s common stock at the date of grant. The term of each option is ten years, and an option becomes exercisable six months after it is granted. At Tesoro’s annual meeting of stockholders held in May 2004, an amendment was approved by the stockholders to increase the number of shares available for issuance of options from 300,000 to 450,000 and to extend the expiration date of this plan to February 23, 2010. At December 31, 2004, Tesoro had 127,000 options outstanding and 268,000 shares available for future grants under this plan.
      A summary of stock option activity for all plans is set forth below (shares in thousands):
                   
    Number of    
    Options   Weighted-Average
    Outstanding   Exercise Price
         
Outstanding January 1, 2002
    4,851.1     $ 12.57  
 
Granted
    1,368.0       8.20  
 
Exercised
    (0.7 )     10.03  
 
Forfeited or expired
    (151.1 )     12.58  
             
Outstanding December 31, 2002
    6,067.3       11.59  
 
Granted
    570.5       8.08  
 
Exercised
    (72.3 )     9.74  
 
Forfeited or expired
    (296.2 )     11.16  
             
Outstanding December 31, 2003
    6,269.3       11.31  
 
Granted
    767.6       26.88  
 
Exercised
    (1,143.1 )     11.23  
 
Forfeited or expired
    (7.3 )     15.22  
             
Outstanding December 31, 2004
    5,886.5     $ 13.35  
             
      The following table summarizes information about stock options outstanding under all plans at December 31, 2004 (shares in thousands):
                                         
    Options Outstanding    
        Options Exercisable
        Weighted-Average        
    Number   Remaining   Weighted-Average   Number   Weighted-Average
Range of Exercise Prices   Outstanding   Contractual Life   Exercise Price   Exercisable   Exercise Price
                     
$3.87 to 6.00
    626.7       7.9 years     $ 4.62       406.7     $ 4.64  
$6.01 to 12.12
    1,912.0       6.2 years       9.23       1,459.2       9.59  
$12.13 to 17.86
    2,576.2       4.4 years       14.50       2,322.9       14.63  
$17.87 to 23.95
    341.0       9.3 years       23.66       27.0       20.30  
$23.96 to 29.38
    430.6       9.5 years       29.35              
                               
$3.87 to 29.38
    5,886.5       6.0 years       13.35       4,215.8       11.96  
                               
      At December 31, 2004, 2003 and 2002, exercisable stock options totaled 4.2 million, 4.4 million and 3.8 million, respectively. The weighted-average exercise price for our exercisable stock options amounted to $11.96, $12.40 and $13.00 at December 31, 2004, 2003 and 2002, respectively.
      We amortize the estimated fair value of stock options granted over the vesting period using the straight-line method. The estimated average fair value per share of options granted during 2004, 2003 and 2002 was

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TESORO CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
$13.01, $6.73 and $4.35, respectively. We estimated the fair value of each option on the date of grant using the Black-Scholes option-pricing model with the following weighted-average assumptions:
                         
    Historical   Pro forma
         
    2004   2003   2002
             
Expected life (years)
    7       7       7  
Expected volatility
    43 %     118 %     88 %
Risk-free interest rate
    4.3 %     3.4 %     4.2 %
Non-Employee Director Phantom Stock Plan
      Under the Non-Employee Director Phantom Stock Plan, a yearly credit of $7,250 is made in units to an account of each non-employee director, based upon the closing market price of Tesoro’s common stock on the date of credit, which vests with three years of service. A director also may elect to have the value of his cash retainer fee deposited quarterly into the account as units that are immediately vested. Retiring directors who are committee chairpersons receive an additional $5,000 credit to their accounts. Certain non-employee directors also received a credit in their accounts in 1997, arising from the transfer of their lump-sum accrued benefit under the frozen Director Retirement Plan. The value of each vested account balance, which is a function of changes in market value of the Tesoro’s common stock, is payable in cash commencing at termination or at retirement, death or disability. Payments may be made as a total distribution or in annual installments, not to exceed ten years. Our results of operations included an expense of $1,107,000 in 2004, an expense of $536,000 in 2003, and a credit of $299,000 in 2002, related to the Non-Employee Director Phantom Stock Plan.
Restricted Stock
      Pursuant to our Amended and Restated Executive Long-term Incentive Plan, we may grant restricted shares of our common stock to eligible employees subject to certain terms and conditions. In March 2004, we issued 250,000 shares of restricted stock to our chief executive officer pursuant to a December 2003 award. The shares were awarded at a grant date value of $13.18 per share and vest in 20% annual increments beginning in February 2005, assuming continued employment at the vesting dates. In connection with our chief executive officer’s employment contract, we also issued an additional 250,000 shares of restricted stock during 2004 to match common stock he purchased during 2004. The matching restricted shares vest in December 2008, assuming continued employment at that date. In addition to the restricted shares issued to our chief executive officer as described above, we issued an additional 158,150 shares of restricted stock to our chief executive officer and other executives during the 2004 third quarter. These restricted shares vest in annual increments ratably over three years beginning in 2005, assuming continued employment at the vesting dates. The weighted-average grant-date fair value of the 408,150 restricted stock grants in 2004 was $23.08.
      The total amount of restricted shares that can be awarded, pursuant to the Amended and Restated Executive Long-term Incentive Plan, is 1,500,000 shares of which 1,008,150 shares had been issued through December 31, 2004. The aggregate fair value of restricted stock on the dates of award of $12.7 million, based on the fair market price of our common stock at the date of grant, was recorded in the consolidated balance sheet as unearned compensation, a separate component of stockholders’ equity, and is being amortized on a straight-line basis over the applicable vesting periods. During 2004, amortization related to our restricted stock totaled $2.0 million.
Phantom Stock Options
      Pursuant to our Amended and Restated Long-term Incentive Plan, Tesoro’s chief executive officer also holds 175,000 phantom stock options, which were granted in 1997 with a term of ten years at 100% of the fair

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TESORO CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
value of Tesoro’s common stock on the grant date, or $16.9844 per share. At December 31, 2004, all of the phantom stock options were exercisable. Upon exercise, the chief executive officer would be entitled to receive, in cash, the difference between the fair market value of the common stock on the date of the phantom stock option grant and the fair market value of common stock on the date of exercise. At the discretion of the Compensation Committee of the Board of Directors, these phantom stock options may be converted to traditional stock options under the executive long-term incentive plan. Total compensation expense recognized for this award during 2004 amounted to approximately $3 million. No compensation expense had been recorded for this award prior to 2004, as our stock price had not exceeded the grant date price for this award.
NOTE P — COMMITMENTS AND CONTINGENCIES
Operating Leases
      Tesoro has various cancellable and noncancellable operating leases related to land, office and retail facilities, ship charters and equipment and other facilities used in the storage, transportation, production and sale of feedstocks and refined products. These leases have remaining primary terms up to 39 years, with terms of certain rights-of-way extending up to 26 years, and generally contain multiple renewal options.
      We have long-term charters through 2010 for two U.S. flagged ships, used to transport crude oil and products. The aggregate annual commitments on these charters total $27 million to $29 million over the remaining terms, including operating expenses that increase annually from $14 million to $16 million.
      Tesoro has operating leases for most of its retail gas station sites with primary remaining terms up to 39 years, and generally containing renewal options. Our aggregate annual lease commitments for the sites total approximately $8 million to $11 million over the next five years. These leases include the 30 retail stations that we sold and leased back in 2002 with initial terms of 17 years and four five-year renewal options (See Note D). We classified the portion of each lease attributable to land as an operating lease, and the portion attributable to depreciable buildings and equipment as a capital lease (See Note F). Tesoro also has an agreement with Wal-Mart to build and operate retail gas stations at selected existing and future Wal-Mart stores in the western United States. Under the agreement, each site is subject to a lease with a ten-year primary term and an option, exercisable at our discretion, to extend a site’s lease for two additional five-year options.
      We lease Tesoro’s corporate headquarters from a limited partnership, in which Tesoro owns a 50% limited interest. The initial lease term is through 2014 with two five-year renewal options. Our total rent expense includes lease payments and operating costs paid to the partnership totaling $3.3 million, $3.2 million and $3.1 million in 2004, 2003 and 2002, respectively. We account for Tesoro’s interest in the partnership using the equity method of accounting, and our consolidated balance sheets do not include the partnership’s assets, primarily land and buildings, totaling approximately $17 million and debt of approximately $13 million.
      Tesoro’s minimum annual lease payments as of December 31, 2004, for operating leases having initial or remaining noncancellable lease terms in excess of one year were (in millions):
                         
    Ship        
    Charters   Other   Total
             
2005
  $ 26.9     $ 54.9     $ 81.8  
2006
    27.7       50.1       77.8  
2007
    28.1       46.4       74.5  
2008
    28.5       35.0       63.5  
2009
    28.9       24.6       53.5  
Thereafter
    12.5       155.1       167.6  

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TESORO CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
      Total rental expense for short-term and long-term operating leases, excluding marine charters, amounted to approximately $44 million in 2004, $49 million in 2003, and $46 million in 2002. We also enter into various short-term charters for vessels to transport refined products to and from our refineries and terminals and to deliver products to customers. Total marine charter expense was $68 million in 2004, $61 million in 2003 and $54 million in 2002. See Note F for information related to capital leases.
Purchase Obligations and Other Commitments
      Tesoro’s contractual purchase commitments consist primarily of crude oil supply contracts for our refineries from several suppliers with noncancellable remaining terms ranging up to two years with renewal provisions. Prices under the term agreements fluctuate with market prices. Assuming actual market crude oil prices as of December 31, 2004, ranging from $29 per barrel to $42 per barrel, our minimum crude supply commitments, for the next two years would approximate $3.0 billion in 2005 and $388 million in 2006. We also purchase crude oil at market prices under short-term renewable agreements and in the spot market. In addition to these purchase commitments, we also have contractual capital spending commitments, primarily for refinery improvements and environmental projects totaling approximately $100 million in 2005.
      We also have long-term take-or-pay commitments to purchase services associated with the operation of our refineries, primarily for chemical supplies. We also will make annual payments of approximately $6 million through 2010 for a deactivated MTBE plant located at our California refinery. The present value of these future lease payments was included in accrued liabilities in the consolidated balance sheets (see Note M). The minimum annual payments under our service contracts, including lease payments for the deactivated MTBE plant, are estimated to total $35 million in 2005, $32 million in 2006, $30 million in 2007, $29 million in 2008, and $18 million in 2009. The remaining minimum commitment totals approximately $42 million over 8 years. We also have a power supply agreement through 2012 at the California refinery, which requires minimum payments through 2007 that vary based on market prices for electricity. Assuming estimated future market prices of electricity, minimum payments for the next three years would approximate $46 million in 2005, $48 million in 2006 and $27 million in 2007. Tesoro paid approximately $92 million, $92 million and $57 million in 2004, 2003 and 2002, respectively, under these take-or-pay contracts.
Environmental and Other Matters
      We are a party to various litigation and contingent loss situations, including environmental and income tax matters, arising in the ordinary course of business. Where required, we have made accruals in accordance with SFAS No. 5, “Accounting for Contingencies,” in order to provide for these matters. We cannot predict the ultimate effects of these matters with certainty, and we have made related accruals based on our best estimates, subject to future developments. We believe that the outcome of these matters will not result in a material adverse effect on our liquidity and consolidated financial position, although the resolution of certain of these matters could have a material adverse impact on interim or annual results of operations.
      Tesoro is subject to audits by federal, state and local taxing authorities in the normal course of business. It is possible that tax audits could result in claims against Tesoro in excess of recorded liabilities. We believe, however, that when these matters are resolved, they will not materially affect Tesoro’s consolidated financial position or results of operations.
      Tesoro 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 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.

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TESORO CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Environmental Liabilities
      As previously reported, we were involved with the EPA regarding a waste disposal site near Abbeville, Louisiana. Tesoro was named a potentially responsible party under the Federal Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA” or “Superfund”) at this location. The site was removed from the EPA’s National Priority List and the EPA entered into a settlement with third parties to remediate the site. Based on these considerations and recent discussions with the EPA, we believe that the likelihood that this matter will have any impact on our results of operations or financial position is remote.
      We are currently involved in remedial responses and have incurred and expect to continue to incur cleanup expenditures associated with environmental matters at a number of sites, including certain of our owned properties. At December 31, 2004, our accruals for environmental expenses totaled approximately $34 million. Our accruals for environmental expenses include retained liabilities for previously owned or operated properties, refining, pipeline and terminal operations and retail service stations. We believe these accruals are adequate, based on currently available information, including the participation of other parties or former owners in remediation action.
      We are continuing to negotiate a settlement of approximately 70 Notices of Violation (“NOVs”) issued by the Bay Area Air Quality Management District. The NOVs allege various violations of air quality requirements at the California refinery between May 2002 and February 2004. Reserves for the settlement of the NOVs are included in the accruals of $34 million referenced above. We have established reserves for this matter which are not material and we believe that the resolution of this matter will not have a material adverse effect on our financial position or results of operations.
      On March 3, 2005 we finalized a settlement with the Bay Area Air Quality Management District and the Contra Costa County District Attorney’s office concerning three NOVs we received in March 2004 in response to odor incidents at our California refinery. We have agreed to pay a civil penalty of $225,000 to resolve this matter. Reserves for the settlement of the NOVs are included in the accruals of $34 million referenced above.
Other Environmental Matters
      In the ordinary course of business, we become party to or otherwise involved in lawsuits, administrative proceedings and governmental investigations, including environmental, regulatory and other matters. Large and sometimes unspecified damages or penalties may be sought from us in some matters for which the likelihood of loss may be reasonably possible but the amount of loss is not currently estimable, and some matters may require years for us to resolve. As a result, we have not established reserves for these matters and we cannot provide assurance that an adverse resolution of one or more of the matters described below during a future reporting period will not have a material adverse effect on our financial position or results of operations in future periods. However, on the basis of existing information, we believe that the resolution of these matters, individually or in the aggregate, will not have a material adverse effect on our financial position or results of operations.
      As previously disclosed, we were a defendant in seven pending cases alleging MTBE contamination in groundwater. During the 2004 fourth quarter, we were named as a defendant in seven additional pending cases, of which we obtained a dismissal without prejudice in four of these cases in February 2005. The plaintiffs in each of the remaining 10 pending cases, all in California, are generally water providers, governmental authorities and private well owners alleging that refiners and suppliers of gasoline containing MTBE are liable for manufacturing or distributing a defective product. We are being sued as a refiner, supplier and marketer of gasoline containing MTBE along with other refining industry companies. The suits generally seek individual, unquantified compensatory and punitive damages and attorney’s fees, but we cannot estimate the amount or the likelihood of the ultimate resolution of these matters at this time, and accordingly,

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TESORO CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
we have not established a reserve for these cases. We believe we have defenses to these claims and intend to vigorously defend the lawsuits.
      Soil and groundwater conditions at our California refinery may require substantial expenditures over time. In connection with our acquisition of the California refinery from Ultramar, Inc. in May 2002, Ultramar assigned certain of its rights and obligations that Ultramar had acquired from Tosco Corporation in August of 2000. Tosco assumed responsibility and contractually indemnified us for up to $50 million for certain environmental liabilities arising from operations at the refinery prior to August of 2000, which are identified prior to August 31, 2010 (“Pre-Acquisition Operations”). Based on existing information, we currently estimate that the environmental liabilities arising from Pre-Acquisition Operations are approximately $41 million, including soil and groundwater conditions at the refinery in connection with various projects and including those required by the California Regional Water Quality Control Board and other government agencies. If we incur remediation liabilities in excess of the environmental liabilities for Pre-Acquisition Operations indemnified by Tosco, we expect to be reimbursed for such excess liabilities under certain environmental insurance policies. The policies provide $140 million of coverage in excess of the $50 million indemnity covering environmental liabilities arising from Pre-Acquisition Operations. Because of Tosco’s indemnification and the environmental insurance policies, we have not established a reserve for environmental liabilities arising out of the Pre-Acquisition Operations. In December 2003, we initiated arbitration proceedings against Tosco seeking damages, indemnity and a declaration that Tosco is responsible for the environmental liabilities arising from Pre-Acquisition Operations at our California refinery.
      In November 2003, we filed suit in Contra Costa County Superior Court against Tosco alleging that Tosco misrepresented, concealed and failed to disclose certain additional environmental conditions at our California refinery. The court granted Tosco’s motion to compel arbitration of our claims for these certain additional environmental conditions. In the arbitration proceedings we initiated against Tosco in December 2003, we are also seeking a determination that Tosco is liable for investigation and remediation of these certain additional environmental conditions, the amount of which is currently unknown and therefore a reserve has not been established, and which may not be covered by the $50 million indemnity for environmental liabilities arising from Pre-Acquisition Operations. In response to our arbitration claims, Tosco filed counterclaims in the Contra Costa County Superior Court action alleging that we are contractually responsible for certain environmental liabilities at our California refinery, including certain liabilities arising from Pre-Acquisition Operations. In February 2005, the parties agreed to stay the arbitration proceedings for a period of 90 days to pursue settlement discussions. In the event we are unable to reach settlement, we intend to vigorously prosecute our claims against Tosco and to oppose Tosco’s claims against us, although we cannot provide assurance that we will prevail.
      During the first quarter of 2005, we began settlement discussions with the California Air Resources Board (“CARB”) concerning an NOV we received in October 2004. The NOV, issued by CARB, alleges we offered for sale eleven batches of gasoline in California that did not meet CARB’s gasoline exhaust emission limits. As of December 31, 2004, we could not estimate the amount of any penalties that might be associated with this NOV and accordingly, we did not establish a reserve for this matter. We disagree with factual allegations in the NOV and believe that the ultimate resolution of this matter with CARB will not have a material adverse effect on our financial position or results of operations.
Environmental Capital Expenditures
      EPA regulations related to the Clean Air Act require reductions in the sulfur content in gasoline, which began January 1, 2004. To meet the revised gasoline standard, we spent approximately $11 million in 2004, and we currently estimate we will make additional capital improvements of approximately $37 million through 2009. This will permit each of our six refineries to produce gasoline meeting the sulfur limits imposed by the EPA.

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TESORO CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
      EPA regulations related to the Clean Air Act also require reductions in the sulfur content in diesel fuel manufactured for on-road consumption. In general, the new on-road diesel fuel standards will become effective on June 1, 2006. In May 2004, the EPA issued a rule regarding the sulfur content of non-road diesel fuel. The requirements to reduce non-road diesel sulfur content will become effective in phases between 2007 and 2010. We have not determined if we will invest the capital necessary to manufacture low sulfur diesel for the non-road market in Alaska, and we are continuing to evaluate potential projects to manufacture additional non-road low sulfur diesel at our Hawaii refinery. Our California, Washington and North Dakota refineries will not require additional capital spending for non-road low sulfur diesel. We spent $31 million in 2004 to meet low sulfur diesel standards, and based on our latest engineering estimates, we now expect to spend approximately $45 million in additional capital improvements through 2006.
      To comply with the Maximum Achievable Control Technologies standard for petroleum refineries (“Refinery MACT II”), we spent $20 million during 2004, primarily to complete the installation of new emission control equipment at our North Dakota refinery. We expect to spend approximately $17 million in additional capital improvements in 2006 at our Washington refinery.
      In connection with the 2001 acquisition of our North Dakota and Utah refineries, Tesoro assumed the sellers’ obligations and liabilities under a consent decree among the United States, BP Exploration and Oil Co. (“BP”), Amoco Oil Company and Atlantic Richfield Company. BP entered into this consent decree for both the North Dakota and Utah refineries for various alleged violations. As the owner of these refineries, Tesoro is required to address issues, including leak detection and repair, flaring protection and sulfur recovery unit optimization. We currently estimate we will spend $5 million over the next three years to comply with this consent decree. We also agreed to indemnify the sellers for all losses of any kind incurred in connection with the consent decree.
      In connection with the 2002 acquisition of our California refinery, subject to certain conditions, Tesoro also assumed the seller’s obligations pursuant to settlement efforts with the EPA concerning the Section 114 refinery enforcement initiative under the Clean Air Act, except for any potential monetary penalties, which the seller retains. We believe these obligations will not have a material impact on Tesoro’s financial position or results of operations.
      We 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. For these related projects at our California refinery, we spent $10 million during 2004, and we estimate that we may spend an additional $90 million through 2010. This cost estimate is subject to further review and analysis.
      Conditions may develop that cause increases or decreases in future expenditures for our various sites, including, but not limited to, our refineries, tank farms, retail gasoline stations (operating and closed locations) and petroleum product terminals, and for compliance with the Clean Air Act and other federal, state and local requirements. We 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. Our California refinery produces grades of gasoline that may be subject to similar claims. We have not paid or accrued liabilities for patent royalties that may be related to our California refinery’s production, since the U.S. Patent Office and the Federal Trade Commission are evaluating the validity of those patents. We believe that the resolution of this matter will not have a material adverse effect on our financial position or results of operations.

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TESORO CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Claims Against Third-Parties
      Beginning in the early 1980s, Tesoro Hawaii Corporation, Tesoro Alaska Company and other fuel suppliers entered a series of long-term, fixed-price fuel supply contracts with the U.S. Defense Energy Support Center (“DESC”). Each of the contracts contained a provision for price adjustments by the DESC. However, the Federal Acquisition Regulations (“FAR”) limit how prices may be adjusted, and we and many of the other suppliers in separate suits in the Court of Federal Claims currently are seeking relief from the DESC’s price adjustments. We and the other suppliers allege that the DESC’s price adjustments violated FAR by not adjusting the price of fuel based on changes to the suppliers’ established prices or costs, as FAR requires. We and the other suppliers seek recovery of approximately $3 billion in underpayment for fuel. Our share of the underpayment currently totals approximately $165 million, plus interest. The Court of Federal Claims granted partial summary judgment in our favor, held that the DESC’s fuel prices were illegal, and rejected the DESC’s assertion that we waived our right to a remedy by entering into the contracts. However, some of the other judges in the same court ruled on the cross-motions for other suppliers in conflict with the holding for us. As a result, we petitioned the Court of Appeals for the Federal Circuit to review its claims, and oral arguments in the appeal were held on January 10, 2005. We are seeking the Court of Appeals’ validation that the price adjustments were illegal and that we did not waive our right to sue when we entered into the contracts. We expect to receive the written decision from the Court of Appeals during the second quarter of 2005, but we cannot predict how the court will rule in this litigation.
      In December of 1996, Tesoro Alaska Company filed a protest of the intrastate rates charged for the transportation of its crude oil through the Trans Alaska Pipeline System (“TAPS”). Our protest asserted that the TAPS intrastate rates were excessive and should be reduced. The Regulatory Commission of Alaska (“RCA”) opened RCA Docket No. P-97-4 to consider our protest of the intrastate rates for the years 1997 through 2000. Through RCA’s Order P-97-4(151), the RCA set just and reasonable final rates for the years 1997 through 2000, and held that Tesoro is entitled to receive approximately $52 million in refunds, including interest through the expected conclusion of appeals in December 2007. RCA Order P-97-4(151) is currently on appeal, and we cannot give any assurances of when or whether we will prevail in the appeal.
      In December 2002, the RCA opened Docket No. P-03-4 to consider the justness and reasonableness of the proposed intrastate rates for TAPS for 2001-2003. Through the RCA’s Order P-03-4(34) (“Order 34”), the RCA rejected the TAPS Carriers’ proposed intrastate rate increases and maintained the permanent rate of $1.96 to the Valdez Marine Terminal. Order 34 is currently on appeal to the Alaska Superior Court (Case No. 3AN-04-8780 CI) and the TAPS Carriers did not move to stay Order 34 to prevent the rate decrease. The rate decrease has been in effect since June 2003.
      If the RCA’s decision is upheld on appeal, Tesoro could be entitled to refunds resulting from our shipments from January 2001 through mid-June 2003. If the RCA’s decision is not upheld on appeal, Tesoro could have to pay additional shipping charges resulting from our shipments from mid-June 2003 through December 2004. We cannot give any assurances of when or whether we will prevail in the appeal. We also believe that, should we not prevail on appeal, the amount of additional shipping charges cannot reasonably be estimated since it is not possible to estimate the permanent rate which the RCA could set, and the appellate courts approve, for each year. In addition, depending upon the level of such rates, there is a reasonable possibility that any refunds for the period January 2001 through mid-June 2003, could offset some or all of any repayments due for the period mid-June 2003 through December 2004.

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TESORO CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
NOTE Q — QUARTERLY FINANCIAL DATA (UNAUDITED)
                                             
    Quarters    
        Total
    First   Second   Third   Fourth   Year
                     
    (In millions except per share amounts)
2004
                                       
 
Revenues
  $ 2,429.9     $ 3,155.0     $ 3,288.5     $ 3,388.8     $ 12,262.2  
 
Operating Income
  $ 126.6     $ 395.7     $ 160.6     $ 30.3     $ 713.2  
 
Net Earnings (Loss)
  $ 50.4     $ 213.1     $ 64.6     $ (0.2 )   $ 327.9  
 
Net Earnings Per share:
                                       
   
Basic
  $ 0.78     $ 3.26     $ 0.98     $ 0.00     $ 5.01  
   
Diluted
  $ 0.75     $ 3.11     $ 0.93     $ 0.00     $ 4.76  
2003
                                       
 
Revenues
  $ 2,286.1     $ 2,116.4     $ 2,330.0     $ 2,113.2     $ 8,845.7  
 
Operating Income
  $ 79.5     $ 67.1     $ 159.6     $ 28.6     $ 334.8  
 
Net Earnings (Loss)
  $ 20.4     $ (7.0 )   $ 70.6     $ (7.9 )   $ 76.1  
 
Net Earnings (Loss) Per Share:
                                       
   
Basic
  $ 0.32     $ (0.11 )   $ 1.09     $ (0.12 )   $ 1.18  
   
Diluted
  $ 0.32     $ (0.11 )   $ 1.09     $ (0.12 )   $ 1.17  
      During the fourth quarter of 2004, we incurred stock-based compensation expenses related to the announced retirement of certain executive officers totaling $1.7 million. During the 2003 fourth quarter, we terminated our funded executive security plan, resulting in a charge of $8.4 million, of which $6.9 million was a non-cash write-off of unamortized prepaid pension costs (See Note N). Also during the fourth quarter of 2003, we recorded pretax charges of $1.4 million for impairment losses on certain retail stations.

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
      None.
ITEM 9A. CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
      We carried out an evaluation required by the Securities Exchange Act of 1934, as amended (the “Exchange Act”), under the supervision and with the participation of our management, including the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15 under the Exchange Act as of the end of the year. Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures are effective in alerting them on a timely basis to material information relating to the Company and required to be included in our periodic filings under the Exchange Act. During the fourth quarter of 2004, there have been no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Management Report on Internal Control over Financial Reporting
      We, as management of Tesoro Corporation and its subsidiaries (the “Company”), are responsible for establishing and maintaining adequate internal control over financial reporting as defined in the Securities Exchange Act of 1934, Rule 13a-15(f). The Company’s internal control system is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles in the United States of America.
      Due to its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.
      Management assessed the effectiveness of internal controls over financial reporting as of December 31, 2004, using the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control — Integrated Framework. Based on such assessment, we believe that as of December 31, 2004, the Company’s internal control over financial reporting is effective. The independent registered public accounting firm of Deloitte & Touche LLP, as auditors of the Company’s consolidated financial statements, has issued an attestation report on management’s assessment of the effectiveness of the Company’s internal control over financial reporting, included herein.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
Tesoro Corporation
      We have audited management’s assessment, included in the accompanying Management Report on Internal Control over Financial Reporting, that Tesoro Corporation and subsidiaries (the “Company”) maintained effective internal control over financial reporting as of December 31, 2004, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.
      We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.
      A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
      Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
      In our opinion, management’s assessment that the Company maintained effective internal control over financial reporting as of December 31, 2004, is fairly stated, in all material respects, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

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      We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2004 of the Company and our report dated March 2, 2005, expressed an unqualified opinion on those financial statements.
/s/ deloitte & touche llp
San Antonio, Texas
March 2, 2005

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ITEM 9B.     OTHER INFORMATION
      None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
      Information required under this Item will be contained in the Company’s 2005 Proxy Statement, incorporated herein by reference. See also Executive Officers of the Registrant under Business in Item 1 hereof.
      In February 2004, the Board of Directors of Tesoro adopted a code of business conduct and ethics for senior financial executives (“Code of Ethics”). You can access our Code of Ethics on our website at www.tsocorp.com, and you may receive a copy, free of charge by writing to Tesoro Corporation, Attention: Investor Relations, 300 Concord Plaza Drive, San Antonio, Texas 78216-6999.
ITEM 11. EXECUTIVE COMPENSATION
      Information required under this Item will be contained in the Company’s 2005 Proxy Statement, incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
      Information required under this Item will be contained in the Company’s 2005 Proxy Statement, incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
      Information required under this Item will be contained in the Company’s 2005 Proxy Statement, incorporated herein by reference.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
      Information required under this Item will be contained in the Company’s 2005 Proxy Statement, incorporated herein by reference.
PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
      (a)1. Financial Statements
      The following consolidated financial statements of Tesoro Corporation and its subsidiaries are included in Part II, Item 8 of this Form 10-K:
         
    Page
     
Report of Independent Registered Public Accounting Firm
    48  
Statements of Consolidated Operations — Years Ended December 31, 2004, 2003 and 2002
    49  
Consolidated Balance Sheets — December 31, 2004 and 2003
    50  
Statements of Consolidated Stockholders’ Equity — Years Ended December 31, 2004, 2003 and 2002
    51  
Statements of Consolidated Cash Flows — Years Ended December 31, 2004, 2003 and 2002
    52  
Notes to Consolidated Financial Statements
    53  

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      2. Financial Statement Schedules
      No financial statement schedules are submitted because of the absence of the conditions under which they are required or because the required information is included in the consolidated financial statements.
      3. Exhibits
             
Exhibit        
Number       Description of Exhibit
         
  2.1       Stock Sale Agreement, dated March 18, 1998, among the Company, BHP Hawaii Inc. and BHP Petroleum Pacific Islands Inc. (incorporated by reference herein to Exhibit 2.1 to Registration Statement No. 333-51789).
  2.2       Stock Sale Agreement, dated May 1, 1998, among Shell Refining Holding Company, Shell Anacortes Refining Company and the Company (incorporated by reference herein to the Company’s Quarterly Report on Form 10-Q for the period ended March 31, 1998, File No. 1-3473).
  2.3       Asset Purchase Agreement, dated July 16, 2001, by and among the Company, BP Corporation North America Inc. and Amoco Oil Company (incorporated by reference herein to Exhibit 2.1 to the Company’s Current Report on Form 8-K filed on September 21, 2001, File No. 1-3473).
  2.4       Asset Purchase Agreement, dated July 16, 2001, by and among the Company, BP Corporation North America Inc. and Amoco Oil Company (incorporated by reference herein to Exhibit 2.2 to the Company’s Current Report on Form 8-K filed on September 21, 2001, File No. 1-3473).
  2.5       Asset Purchase Agreement, dated July 16, 2001, by and among the Company, BP Corporation North America Inc. and BP Pipelines (North America) Inc. (incorporated by reference herein to Exhibit 2.1 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2001, File No. 1-3473).
  2.6       Sale and Purchase Agreement for Golden Eagle Refining and Marketing Assets, dated February 4, 2002, by and among Ultramar Inc. and Tesoro Refining and Marketing Company, including First Amendment dated February 20, 2002 and related Purchaser Parent Guaranty dated February 4, 2002, and Second Amendment dated May 3, 2002 (incorporated by reference herein to Exhibit 2.12 to the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2001, File No. 1-3473, and Exhibit 2.1 to the Company’s Current Report on Form 8-K filed on May 9, 2002, File No. 1-3473).
  3.1       Restated Certificate of Incorporation of the Company (incorporated by reference herein to Exhibit 3 to the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 1993, File No. 1-3473).
  3.2       By-Laws of the Company, as amended through February 2, 2005 (incorporated by reference herein to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on February 8, 2005, File No. 1-3473).
  3.3       Amendment to Restated Certificate of Incorporation of the Company adding a new Article IX limiting Directors’ Liability (incorporated by reference herein to Exhibit 3(b) to the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 1993, File No. 1-3473).
  3.4       Certificate of Designation Establishing a Series A Participating Preferred Stock, dated as of December 16, 1985 (incorporated by reference herein to Exhibit 3(d) to the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 1993, File No. 1-3473).
  3.5       Certificate of Amendment, dated as of February 9, 1994, to Restated Certificate of Incorporation of the Company amending Article IV, Article V, Article VII and Article VIII (incorporated by reference herein to Exhibit 3(e) to the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 1993, File No. 1-3473).
  3.6       Certificate of Amendment, dated as of August 3, 1998, to Certificate of Incorporation of the Company, amending Article IV, increasing the number of authorized shares of Common Stock from 50,000,000 to 100,000,000 (incorporated by reference herein to Exhibit 3.1 to the Company’s Quarterly Report on Form 10-Q for the period ended September 30, 1998, File No. 1-3473).

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Exhibit        
Number       Description of Exhibit
         
  3 .7     Certificate of Ownership of Merger merging Tesoro Merger Corp. into Tesoro Petroleum Corporation and changing the name of Tesoro Petroleum Corporation to Tesoro Corporation, dated November 8, 2004 (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed on November 9, 2004).
  4 .1     Form of Coastwide Energy Services Inc. 8% Convertible Subordinated Debenture (incorporated by reference herein to Exhibit 4.3 to Post-Effective Amendment No. 1 to Registration No. 333-00229).
  4 .2     Debenture Assumption and Conversion Agreement dated as of February 20, 1996, between the Company, Coastwide Energy Services, Inc. and CNRG Acquisition Corp. (incorporated by reference herein to Exhibit 4.4 to Post-Effective Amendment No. 1 to Registration No. 333-00229).
  4 .3     Indenture, dated as of July 2, 1998, between Tesoro Petroleum Corporation and U.S. Bank Trust National Association, as Trustee (incorporated by reference herein to Exhibit 4.4 to Registration Statement No. 333-59871).
  4 .4     Form of 9% Senior Subordinated Notes due 2008 and 9% Senior Subordinated Notes due 2008, Series B (incorporated by reference herein to Exhibit 4.5 to Registration Statement No. 333-59871).
  4 .5     Indenture, dated as of November 6, 2001, between Tesoro Petroleum Corporation and U.S. Bank Trust National Association, as Trustee (incorporated by reference herein to Exhibit 4.8 to Registration Statement No. 333-75056).
  4 .6     Form of 95/8% Senior Subordinated Notes due 2008 and 95/8% Senior Subordinated Notes due 2008, Series B (incorporated by reference herein to Exhibit 4.7 to Registration Statement No. 333-92468).
  4 .7     Indenture, dated as of April 9, 2002, between Tesoro Escrow Corp. and U.S. Bank National Association, as Trustee (incorporated by reference herein to Exhibit 4.9 to Registration Statement No. 333-84018).
  4 .8     Supplemental Indenture, dated as of May 17, 2002, among Tesoro Escrow Corp., Tesoro Corporation, the subsidiary guarantors and U.S. Bank National Association, as Trustee (incorporated by reference herein to Exhibit 4.10 to Registration Statement No. 333-92468).
  4 .9     Form of 95/8% Senior Subordinated Notes due 2012 (incorporated by reference herein to Exhibit 4.10 to Registration Statement No. 333-84018).
  4 .10     Indenture, dated as of April 17, 2003, between Tesoro Petroleum Corporation and The Bank of New York (incorporated by reference herein to Exhibit 4.8 to Registration Statement No. 333-105783).
  4 .11     First Supplemental Indenture to the 8% Senior Secured Notes due 2008, dated as of June 23, 2004 among Tesoro Petroleum Corporation and The Bank of New York, as trustee (incorporated by reference herein to Exhibit 4.2 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2004, File No. 1-3473).
  4 .12     Credit and Guaranty Agreement related to Senior Secured Term Loans Due 2008, dated as of April 17, 2003, among Tesoro Petroleum Corporation, certain subsidiary guarantors, Goldman Sachs Credit Partners L.P., as Administrative Agent, and Goldman Sachs Credit Partners L.P., as Sole Lead Arranger, Sole Bookrunner and Syndication Agent (incorporated by reference herein to Exhibit 4.11 to Registration Statement No. 333-105783).
  4 .13     First Amendment, dated as of March 15, 2004, to the Credit and Guaranty Agreement of the Senior Secured Term Loans Due 2008, among Tesoro Petroleum Corporation, certain subsidiary guarantors, Goldman Sachs Credit Partners L.P., as Administrative Agent, Sole Lead Arranger, Sole Bookrunner and Syndication Agent (incorporated by reference herein to Exhibit 4.1 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2004, File No. 1-3473).

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Exhibit        
Number       Description of Exhibit
         
  4.14       Pledge and Security Agreement related to Senior Secured Term Loans Due 2008 and 8% Senior Secured Notes due 2008, dated as of April 17, 2003, among Tesoro Petroleum Corporation, certain subsidiary guarantors and Wilmington Trust Company, as Collateral Agent (incorporated by reference herein to Exhibit 4.12 to Registration Statement No. 333-105783).
  4.15       Collateral Agency Agreement related to Senior Secured Term Loans Due 2008 and 8% Senior Secured Notes due 2008, dated as of April 17, 2003, among Tesoro Petroleum Corporation, certain subsidiary guarantors, Goldman Sachs Credit Partners L.P., The Bank of New York Trust Company and Wilmington Trust Company (incorporated by reference herein to Exhibit 4.13 to Registration Statement No. 333-105783).
  4.16       Control Agreement related to Senior Secured Tem Loans due 2008 and 8% Senior Secured Notes due 2008, dated as of May 16, 2003, among Tesoro Petroleum Corporation, Wilmington Trust Company, as Collateral Agent, and Frost Bank, as Depositary Agent (incorporated by reference herein to Exhibit 4.14 to Registration Statement No. 333-105783).
  10.1       Security Agreement dated as of April 17, 2003, by and between the Company, certain of its subsidiary parties thereto and Bank One NA as Agent (incorporated by reference herein to Exhibit 10.44 to Amendment No. 1 to Registration Statement No. 333-105783).
  10.2       Third Amended and Restated Credit Agreement, dated as of May 25, 2004, among the Company, Bank of America, N.A. (the syndication agent), Wells Fargo Foothill, LLC (the documentation agent), Bank One, NA (the administrative agent) and a syndicate of banks, financial institutions and other entities (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2004, File No. 1-3473).
  10.3       Amendment No. 1 to the Third Amended and Restated Credit Agreement, dated as of September 29, 2004 among the Company, Bank One N.A. (the administrative agent) and a syndicate of banks, financial institutions and other entities (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on September 30, 2004, File No. 1-3473).
  10.4       Affirmation of Loan Documents dated as of September 29, 2004, by and between the Company, certain of its subsidiary parties thereto and Bank One N.A. as administrative agent (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed on September 30, 2004, File No. 1-3473).
  10.5       Second Amendment to the Company’s Amended and Restated Executive Long-Term Incentive Plan effective as of May 1, 2003 (incorporated by reference herein to Exhibit 10.33 to Registration Statement No. 333-105783).
  10.6       $100 million Promissory Note, dated as of May 17, 2002, payable by the Company to Ultramar Inc. (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on May 24, 2002, File No. 1-3473).
  10.7       $50 million Promissory Note, dated as of May 17, 2002, payable by the Company to Ultramar Inc. (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on May 24, 2002, File No. 1-3473).
  †10.8       The Company’s Amended Executive Security Plan, as amended through November 13, 1989 for executive officers and key personnel (incorporated by reference herein to Exhibit 10(f) to the Company’s Annual Report on Form 10-K for the fiscal year ended September 30, 1990, File No. 1-3473).
  †10.9       Sixth Amendment to the Company’s Amended Executive Security Plan dated effective March 6, 1991 (incorporated by reference herein to Exhibit 10(g) to the Company’s Annual Report on Form 10-K for the fiscal year ended September 30, 1991, File No. 1-3473).
  †10.10       Seventh Amendment to the Company’s Amended Executive Security Plan dated effective December 8, 1994 (incorporated by reference herein to Exhibit 10(f) to the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 1994, File No. 1-3473).
  †10.11       Eighth Amendment to the Company’s Amended Executive Security Plan dated effective June 6, 1996 (incorporated by reference herein to Exhibit 10.5 to the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 1998, File No. 1-3473).

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Exhibit        
Number       Description of Exhibit
         
  †10.12       Ninth Amendment to the Company’s Amended Executive Security Plan dated effective October 1, 1998 (incorporated by reference herein to Exhibit 10.6 to the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 1998, File No. 1-3473).
  †10.13       Amended and Restated Employment Agreement between the Company and Bruce A. Smith dated December 3, 2003 (incorporated by reference to Exhibit 10.14 to the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2003, File No. 1-3473).
  †10.14       Employment Agreement between the Company and Gregory A. Wright dated as of August 26, 2004 (incorporated by reference herein to Exhibit 10.4 to the Company’s Current Report on Form 8-K filed on August 31, 2004, File No. 1-3473).
  †10.15       Employment Agreement between the Company and William J. Finnerty dated as of February 2, 2005 (incorporated by reference herein to Exhibit 10.1 to the Company’s Current Report on Form 8-K/A filed on February 8, 2005, File No. 1-3473).
  †10.16       Employment Agreement between the Company and Everett D. Lewis dated as of February 2, 2005 (incorporated by reference herein to Exhibit 10.2 to the Company’s Current Report on Form 8-K/A filed on February 8, 2005, File No. 1-3473).
  †10.17       Management Stability Agreement between the Company and W. Eugene Burden dated November 6, 2002 (incorporated by reference herein to Exhibit 10.23 to the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2002, File No. 1-3473).
  †10.18         Management Stability Agreement between the Company and J. William Haywood dated November 6, 2002 (incorporated by reference herein to Exhibit 10.32 to the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2002, File No. 1-3473).
  †10.19       Management Stability Agreement between the Company and Joseph M. Monroe dated November 6, 2002 (incorporated by reference herein to Exhibit 10.30 to the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2002, File No. 1-3473).
  †10.20       Management Stability Agreement between the Company and Stephen L. Wormington dated November 6, 2002 (incorporated by reference herein to Exhibit 10.20 to the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2002, File No. 1-3473).
  †10.21       Management Stability Agreement between the Company and G. Scott Spendlove dated January 24, 2002 (incorporated by reference herein to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2002, File No. 1-3473).
  †10.22       Management Stability Agreement between the Company and Claude A. Flagg dated February 2, 2005 (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on February 8, 2005, File No. 1-3473).
  †10.23       Amended and Restated Management Stability Agreement between the Company and Susan A. Lerette dated February 2, 2005 (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on February 8, 2005, File No. 1-3473).
  †10.24       Management Stability Agreement between the Company and Charles S. Parrish dated February 2, 2005 (incorporated by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K filed on February 8, 2005, File No. 1-3473).
  †10.25       Amended and Restated Management Stability Agreement between the Company and Otto C. Schwethelm dated February 2, 2005 (incorporated by reference to Exhibit 10.4 to the Company’s Current Report on Form 8-K filed on February 8, 2005, File No. 1-3473).
  †10.26       Consulting Agreement between the Company and James C. Reed, Jr. dated effective March 1, 2005 (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on March 3, 2005, File No. 1-3473).
  †10.27       Consulting Agreement between the Company and Thomas E. Reardon dated effective March 1, 2005 (incorporated by reference herein to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on March 3, 2005, File No. 1-3473).
  †10.28       Copy of the Company’s Key Employee Stock Option Plan dated November 12, 1999 (incorporated by reference herein to Exhibit 10.3 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2002, File No. 1-3473).

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Exhibit        
Number       Description of Exhibit
         
  †10.29       Copy of the Company’s Amended and Restated Executive Long-Term Incentive Plan, as amended through May 25, 2000 (Company’s Registration Statement No. 333-39070 filed on Form S-8).
  †10.30       Amendment to the Company’s Amended and Restated Executive Long-Term Incentive Plan effective as of June 20, 2002 (incorporated by reference herein to Exhibit 10.31 to the (incorporated by reference herein to Exhibit 10.31 to the Company’s Registration Statement No. 333-92468).
  †10.31       Third Amendment to the Company’s Amended and Restated Executive Long-Term Incentive Plan effective as of May 11, 2004 (incorporated by reference to Exhibit 4.16 to the Company’s Registration statement No. 333-120716).
  †10.32       Copy of the Company’s Non-Employee Director Retirement Plan dated December 8, 1994 (incorporated by reference herein to Exhibit 10(t) to the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 1994, File No. 1-3473).
  †10.33       Amended and Restated 1995 Non-Employee Director Stock Option Plan, as amended through March 15, 2000 (incorporated by reference herein to Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2002, File No. 1-3473).
  †10.34       Amendment to the Company’s Amended and Restated 1995 Non-Employee Director Stock Option Plan (incorporated by reference herein to Exhibit 10.41 to the Company’s Registration Statement No. 333-92468).
  †10.35       Amendment to the Company’s 1995 Non-Employee Director Stock Option Plan effective as of May 11, 2004 (incorporated by reference to Exhibit 4.19 to the Company’s Registration Statement No. 333-120716).
  †10.36       Copy of the Company’s Board of Directors Deferred Compensation Plan dated February 23, 1995 (incorporated by reference herein to Exhibit 10(u) to the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 1994, File No. 1-3473).
  †10.37       Copy of the Company’s Board of Directors Deferred Compensation Trust dated February 23, 1995 (incorporated by reference herein to Exhibit 10(v) to the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 1994, File No. 1-3473).
  †10.38       Copy of the Company’s Board of Directors Deferred Phantom Stock Plan (incorporated by reference herein to Exhibit 10 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 1997, File No. 1-3473).
  †10.39       Phantom Stock Option Agreement between the Company and Bruce A. Smith dated effective October 29, 1997 (incorporated by reference herein to Exhibit 10.20 to the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 1997, File No. 1-3473).
  10.40       Form of Indemnification Agreement between the Company and its officers and directors (incorporated by reference herein to Exhibit B to the Company’s Proxy Statement for the Annual Meeting of Stockholders held on February 25, 1987, File No. 1-3473).
  10.41       Letter dated May 5, 2002 from the Company to the State of California Department of Justice, Office of Attorney General (incorporated by reference to Exhibit 10.3 to the Company’s Current Report on For 8-K filed on May 24, 2002, File No. 1-3473; portions of this document have been omitted pursuant to a request for confidential treatment).
  14.1        Code of Business Conduct and Ethics for Senior Financial Executives (incorporated by reference to Exhibit 14.1 to the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2003, File No. 1-3473).
  *21.1        Subsidiaries of the Company.
  *23.1        Consent of Deloitte & Touche LLP.
  *31.1        Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
  *31.2        Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
  *32.1        Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
  *32.2        Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

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Filed herewith.
†  Identifies management contracts or compensatory plans or arrangements required to be filed as an exhibit hereto pursuant to Item 15(a)(3) of Form 10-K.
      Schedules not listed above are omitted because of the absence of the conditions under which they are required or because the information required by such omitted schedules is set forth in the financial statements or the notes thereto.
      Copies of exhibits filed as part of this Form 10-K may be obtained by stockholders of record at a charge of $0.15 per page, minimum $5.00 each request. Direct inquiries to the Corporate Secretary, Tesoro Corporation, 300 Concord Plaza Drive, San Antonio, Texas, 78216-6999.

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SIGNATURES
      Pursuant to the requirements of Section 13 or 15(d) 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 CORPORATION
  By:  /s/ BRUCE A. SMITH
 
 
  Bruce A. Smith
  Chairman of the Board of Directors,
  President and Chief Executive Officer
Dated: March 4, 2005
      Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
             
Signature   Title   Date
         
 
/s/ BRUCE A. SMITH
 
Bruce A. Smith
  Chairman of the Board of Directors, President and Chief Executive Officer (Principal Executive Officer)   March 4, 2005
 
/s/ GREGORY A. WRIGHT
 
Gregory A. Wright
  Executive Vice President and Chief Financial Officer
(Principal Financial Officer)
  March 4, 2005
 
/s/ OTTO C. SCHWETHELM
 
Otto C. Schwethelm
  Vice President and Controller
(Principal Accounting Officer)
  March 4, 2005
 
/s/ STEVEN H. GRAPSTEIN
 
Steven H. Grapstein
  Lead Director   March 4, 2005
 
/s/ ROBERT W. GOLDMAN
 
Robert W. Goldman
  Director   March 4, 2005
 
/s/ WILLIAM J. JOHNSON
 
William J. Johnson
  Director   March 4, 2005
 
/s/ A. MAURICE MYERS
 
A. Maurice Myers
  Director   March 4, 2005
 
/s/ DONALD H. SCHMUDE
 
Donald H. Schmude
  Director   March 4, 2005
 
/s/ PATRICK J. WARD
 
Patrick J. Ward
  Director   March 4, 2005

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