e10vk

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 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 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 Securities Exchange Act of 1934). Yes þ No o

At June 30, 2003, the aggregate market value of the voting stock held by nonaffiliates of the registrant was approximately $441,286,640 based upon the closing price of its common stock on the New York Stock Exchange Composite tape. At March 1, 2004, there were 64,992,899 shares of the registrant’s common stock outstanding.

Portions of the registrant’s Proxy Statement pertaining to the 2004 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.

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 47.

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 Petroleum Corporation and its subsidiaries.

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. 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.tesoropetroleum.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 Petroleum Corporation, Attention: Investor Relations, 300 Concord Plaza Drive, San Antonio, Texas 78216-6999.

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.

We purchase crude oil and other feedstocks for our refineries from various domestic and foreign sources through term agreements with renewal provisions and in the spot market. Prices under the term agreements fluctuate with market prices.

To provide secure shipping capacity, we term-charter three U.S. flag tankers, which are double-hulled, and one foreign-flag tanker, which is single-hulled, to transport crude oil and refined products over terms ending in 2004 and 2010. We also charter three tugs and two product barges for our Hawaii operations over varying terms ending in 2005 through 2009 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 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 arrangements with other refining and marketing companies.

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:

Major scheduled refinery maintenance (“turnarounds”) temporarily reduced throughput 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 2001 due to processing other feedstocks in addition to crude oil.

In 2003, we received 66% of our crude oil input from domestic sources (including 30% from Alaska’s North Slope) and 34% from foreign sources (including 10% from Canada). Approximately 58% of our total refining throughput was heavy crude oil in 2003, compared with 49% in 2002 and 45% in 2001. We define “heavy” crude oil as Alaska North Slope or crude oil with an American Petroleum Institute specific gravity of 32 or less. Actual throughput volumes are summarized below (in thousand bpd):

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 liquid asphalt. Our refining yields, in volumes are summarized below (in thousand bpd):

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. Major product upgrading units at the refinery include fluid catalytic cracking (“FCC”), fluid coker, hydrocracking, naphtha reforming, vacuum distillation, hydrotreating and alkylation units. These units enable the refinery to produce a high proportion of motor fuels, including cleaner-burning California Air Resources Board (“CARB”) gasoline and CARB diesel, as well as conventional gasoline and diesel. We completed a project at our California refinery in March 2003 that allows the refinery to produce at least 90,000 bpd of CARB gasoline components. This project enabled us to comply with California regulations to phase out the use of the oxygenate MTBE, by January 1, 2004. The refinery also produces heavy fuel oils, liquefied petroleum gas and petroleum coke.

Crude Oil Supply. We source our California refinery’s crude oil primarily from California and Alaska, and to a lesser extent from foreign locations. We purchase approximately 80% of the refinery’s crude oil under term contracts, which are primarily short-term agreements with market-related prices, and we purchase the remainder in the spot market.

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. 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.

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. Major product upgrading units at the refinery include the FCC, alkylation, hydrotreating, vacuum distillation and naphtha reforming units, which enable our Washington refinery to produce a high proportion of light products, such as gasoline (including components for cleaner-burning CARB gasoline), diesel and jet fuel. The refinery also produces heavy fuel oils, liquefied petroleum gas and liquid asphalt.

Crude Oil Supply. We source our Washington refinery’s crude oil primarily from Alaska, Canada and other foreign locations. We purchase approximately 65% of the refinery’s crude oil under term contracts, which are primarily short-term agreements with market-related prices. 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.

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. The pipeline and the marine terminal are each capable of providing 100% of our Washington refinery’s feedstock needs. 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 refinery. We deliver refined products through our marine terminal to ships and barges, and we also sell liquefied petroleum gas and liquid 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

Refining. Our Alaska refinery is located near Kenai on the Cook Inlet on 488 acres approximately 70 miles southwest of Anchorage. The refinery has a total rated crude oil capacity of 72,000 bpd, and its product upgrading units include vacuum distillation, distillate hydrocracking, hydrotreating and naphtha reforming units. Our Alaska refinery produces gasoline and gasoline blendstocks, jet fuel, diesel fuel, heating oil, heavy fuel oils, liquefied petroleum gas and liquid asphalt.

Crude Oil Supply. Our Alaska refinery processes crude oil primarily from the Alaska Cook Inlet, Alaska North Slope and, to a lesser extent, foreign locations. We purchase substantially all of the crude oil for the Alaska refinery under term contracts with market-related prices, of which approximately 25% are short-term agreements and approximately 75% are agreements for terms greater than one year.

Transportation. We deliver crude oil by tanker to the Alaska refinery through our Kenai Pipe Line Company marine terminal, which is a common carrier and marine dock facility. We also receive crude oil through our 24-mile pipeline connecting our marine terminal 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.

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.

Refining. Our 95,000 bpd Hawaii refinery, located at Kapolei on 131 acres about 22 miles west of Honolulu, produces gasoline and gasoline blendstocks, jet fuel, diesel fuel, heavy fuel oils, liquefied petroleum gas and liquid asphalt. Major product upgrading units include the vacuum distillation, hydrocracking, hydrotreating, visbreaking and naphtha reforming units.

Crude Oil Supply. We supply the Hawaii refinery with crude oil primarily from Alaska, Southeast Asia and other foreign sources. We purchase approximately 40% of our refinery’s crude oil under term contracts, which are primarily short-term agreements with market-related prices. We purchase the remaining 60% on the spot market. The percentages of crude oil purchased under term contracts and in the spot market vary, based on market conditions.

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.

Refining. Our 60,000 bpd North Dakota refinery, located near Mandan on 960 acres, produces gasoline, diesel fuel and jet fuel. Major product upgrading units at the refinery include the FCC, naphtha reforming, hydrotreating and alkylation units.

Crude Oil Supply. We supply our North Dakota refinery primarily with Williston Basin sweet crude oil. The refinery also can access other supplies, including Canadian crude oil. We purchase substantially all of the refinery’s crude oil under contracts, which are primarily short-term agreements with market-related prices.

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 Federal Energy Regulatory Commission (“FERC”). We distribute approximately 85% of our refinery’s production through a third-party 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 16,000 bpd of refined products in 2003 under the offtake agreements. In 2003, BP received approximately 69% of the committed product through the Minneapolis/ St. Paul terminal with the remainder distributed through terminals at Moorhead and Sauk Centre, Minnesota. The offtake agreements for the Moorhead and Sauk Centre terminals expire in September 2004. The offtake agreement for the Minneapolis/ St. Paul terminal expires in September 2006 with declining volumes in each of the last three years, and volumes may be reduced further under certain conditions. Sales prices under the offtake agreements are based on market prices at the time of sale.

Refining. Our 55,000 bpd Utah refinery, located in Salt Lake City on 145 acres, produces gasoline, diesel fuel and jet fuel. Major product upgrading units include the FCC, naphtha reforming, hydrotreating and alkylation units.

Crude Oil Supply. Our Utah refinery processes low-sulfur crude oils and has the flexibility to process various other crude oils. As local crude oil supplies decline, we can replace them with Canadian light sweet crude oil or syncrude. We purchase substantially all of the refinery’s crude oil under contracts, which are primarily short-term agreements with market-related prices.

Transportation. Our Utah refinery receives crude oil by third-party pipelines and trucks 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.

Our refining segment sells refined products, including gasoline and gasoline blendstocks, jet fuel, diesel fuel, heavy oil and residual products in both the bulk and wholesale markets. We sell products that we manufacture and products purchased or received on exchange from third parties. Our refined product sales in the refining segment, including intersegment sales to our retail operations, consisted of:

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. We purchase additional quantities of jet fuel to supply Alaska, Hawaii and the U.S. West Coast 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 liquid asphalt for paving materials in Hawaii, Alaska and Washington. In Alaska and the Pacific Northwest, demand for liquid 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 diesel fuel and other products that are sold outside of our refineries’ local markets.

Our retail segment sells 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 to retail customers through company-operated sites and agreements with third-party branded distributors (or “jobber/dealers”). As of December 31, 2003, our retail segment included a network of 557 branded retail stations (under the Tesoro® and Mirastar® brands), including 226 company-operated retail gasoline stations and 331 jobber/dealer stations. 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:

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 refining capacity and are owned by substantially larger companies. 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, Utah, Washington and other western 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.

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, over the next several years our facilities will 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. For example, under the federal Clean Air Act we are required to comply with the second phase of regulations establishing Maximum Achievable Control Technologies for petroleum refineries (“Refinery MACT II”). These regulations require new emission controls at certain processing units at our refineries. We expect to spend approximately $45 million in capital improvements at our refineries through 2006 to comply with the Refinery MACT II standards.

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 a reduction in the sulfur content in gasoline beginning January 1, 2004. To meet the revised gasoline standard, we currently estimate we will make capital improvements of approximately $38 million through 2008 and an additional $8 million thereafter. This will permit each of our six refineries to produce gasoline meeting the sulfur limits imposed by the EPA. EPA regulations related to the Clean Air Act also require a reduction in the sulfur content in diesel fuel manufactured for on-road consumption. In general, the new diesel fuel standards will become effective on June 1, 2006. Based on our latest engineering estimates and spending to date, we expect to spend approximately $54 million in capital improvements through 2006 to meet the new diesel fuel standards, which does not include the potential impact of the recent EPA proposed rule for the sulfur content of off-road diesel fuel.

To meet California’s CARB III gasoline requirements, including the mandatory phase-out of the oxygenate known as MTBE, we spent approximately $60 million in 2002, and an additional $17 million in 2003 on a project at our California refinery. We completed the project in March 2003, enabling the refinery to produce at least 90,000 bpd of CARB gasoline components.

In connection with the 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., Amoco Oil Company and Atlantic Richfield Company. BP entered into this consent decree for both the North Dakota and Utah refineries for various alleged violations. As the owner of these refineries, we are required to address issues, including leak detection and repair, flaring protection and sulfur recovery unit optimization. We currently estimate that we will spend $7 million to comply with this consent decree in addition to estimated expenditures of $16 million during 2004 for the installation of new emission control equipment at the North Dakota refinery to meet MACT II regulations described above. 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 its settlement efforts with the EPA concerning the Section 114 refinery enforcement initiative under the Clean Air Act, except for any potential monetary penalties, which the seller retains. We believe these obligations will not have a material impact on our financial position.

Capital expenditures addressing other environmental issues at our California refinery totaled $8 million in 2003. Based on latest estimates, we will need to expend additional capital for reconfiguring and replacing aboveground storage tank systems and upgrading piping within the refinery. These costs are currently estimated at approximately $92 million through 2008. 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, terminals and retail gasoline stations (operating and

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.

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.

At December 31, 2003, we had approximately 3,570 full-time employees. Approximately 1,050 of our employees are covered by collective bargaining agreements that run until January 31, 2006. We consider our relations with our employees to be satisfactory.

Our principal properties are described above under the captions “Refining Segment” and “Retail Segment”. 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, transportation equipment and various assets used to store and transport refinery 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 557 branded retail stations, of which 226 are company-operated.

The following is a list of the Company’s executive officers, their ages and their positions with the Company at March 1, 2004.

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 Tesoro’s 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.

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.

W. Eugene Burden was named Senior Vice President, Human Resources and Government Relations in June 2002. Prior to that, he served as 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. Prior to joining Tesoro, he was President of Burden & Associates, Inc., which provided consulting services to energy clients from February 1996 to September 1999.

Everett D. Lewis has been Senior Vice President, Planning and Optimization since February 2003. Prior to that, he was 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 and was a consultant to the refining and marketing industry from 1997 to 1999.

Susan A. Lerette has been Vice President, Communications since April 2001. She was Director, Investor Relations from April 1999 to April 2001. From December 1998 to April 1999, Ms. Lerette served as Manager, Investor Relations.

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, and from August 1998 to November 1999, he was Manager, Economics of Tesoro Petroleum Companies, Inc.

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. From June 1998 to December 1999, Mr. Spendlove served as Director, Investor Relations of Ultramar Diamond Shamrock Corporation.

Rodney S. Cason has served as President of Tesoro Alaska Company since April 2002. Prior to that, he was Vice President, Refining, from February 1998 to April 2002.

William J. Finnerty was named Senior Vice President, Supply and Distribution of Tesoro Refining and Marketing Company 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.

Joseph M. Monroe was named Senior Vice President, Strategic Planning and Business Development of Tesoro Petroleum Companies, Inc. in February 2004. From May 2002 to February 2004, Mr. Monroe served as Senior Vice President, Supply and Distribution, of Tesoro Refining and Marketing Company. From January 1999 through May 2002, he served as Vice President, Pipelines and Terminals of Unocal Corporation and as President of Unocal Pipeline Company.

James L. Taylor joined Tesoro in July 2001 as Senior Vice President, Manufacturing, of Tesoro Refining and Marketing Company. During 2000 and 2001, he served as General Manager, Worldwide Technical Services, of Criterion Catalysts and Technologies. Prior to that, Mr. Taylor was with KBC Advanced Technologies as Job Controller from 1998 to 2000.

Alan R. Anderson was named Senior Vice President and President of Tesoro Refining and Marketing Company’s Northern Great Plains Region in June 2002. He also serves as manager of our North Dakota

refinery. From September 2001 until June 2002, Mr. Anderson served as Business Manager of our Northern Great Plains Region. At the North Dakota refinery, he was the BP Commercial Manager from January 1999 to September 2001 and the Amoco Business Manager from August 1997 to January 1999. From August 1997 to September 2001 he also served as business manager for the BP/ Amoco region, including North and South Dakota, Kansas, Minnesota and Nebraska.

J. William Haywood 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 both 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.

Daniel J. Porter joined Tesoro as Senior Vice President and President of the Northern Great Plains Region of Tesoro Refining and Marketing Company in September 2001 and became Senior Vice President and President of our Northwest Region in June 2002. Prior to joining Tesoro, he was Business Unit Leader at BP’s North Dakota refinery since January 1999.

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.

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 financial results.

The rising costs of natural gas and electrical power used by our refineries and other operations have increased 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, 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.

Our operations are inherently subject to accidental spills, discharges or other releases of petroleum or hazardous substances that may make us liable to governmental entities or private parties under federal, state or local environmental laws, as well as under common law. These may involve contamination associated with facilities that we currently own or operate, facilities that we formerly owned or operated, and facilities to which we sent wastes or by-products for treatment or disposal and other contamination. Accidental discharges may occur in the future; future action may be taken in connection with past discharges; governmental agencies may assess damages or penalties against us in connection with any past or future contamination; or third parties may assert claims against us for damages allegedly arising out of any past or future contamination.

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 environmental pollution, 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.

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 Hawaii, Alaska and 16 other 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


	•	Upgrades to sulfur removal capabilities, which are required to comply with mandates adopted by the EPA to reduce the sulfur content of diesel fuel and gasoline; and

	•	Changes that will be required to comply with the terms of a settlement agreement with the EPA of alleged violations by previous owners of certain provisions of the federal Clean Air Act of 1990 (the “Clean Air Act”) at our Mid-Continent refineries and a potential settlement at our California refinery.

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.

We have a significant amount of debt that has limited and could further limit our flexibility in operating our business or limit our access to funds we may need to grow our business.

As of December 31, 2003, we had total consolidated indebtedness of $1.6 billion, and our high degree of financial leverage may have important consequences, including the following:


	•	our debt level makes us more vulnerable to the impact of economic downturns and adverse developments in our business;

	•	our debt level could limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;

	•	our debt level affects our level of discretionary capital expenditures, related expansion opportunities and acquisitions;

	•	a substantial portion of our cash flow is used to pay interest on debt, which reduces the funds that otherwise would be available for operations and future business opportunities; and

	•	our debt level may place us at a competitive disadvantage to our less leveraged competitors.

Our ability to meet our debt obligations, refinance our debt obligations and fund capital expenditures will depend on our future performance, which will be affected by general economic, financial, competitive, legislative, regulatory and other factors beyond our control. If we are unable to generate sufficient cash flow from operations or to borrow sufficient funds, we may be required to eliminate or defer capital expenditures, refinance all or a portion of our existing debt or obtain additional financing. We may not be able to refinance our debt or borrow more money on terms acceptable to us, if at all. Additionally, our ability to incur additional debt will be restricted under the covenants contained in our credit agreement and our indentures.

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.

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.

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 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.

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. On March 1, 2004, the court granted Tosco’s motion to compel arbitration of our claims for these environmental conditions. We had previously initiated arbitration proceedings against Tosco in December 2003, seeking damages, indemnity and a declaration that Tosco is responsible for certain other environmental liabilities arising from Tosco’s former operations at the California refinery. In response to our arbitration claims, Tosco filed counterclaims in the Contra Costa Superior Court suit alleging that we are contractually responsible for those certain other environmental liabilities at the California refinery. We intend to vigorously prosecute our claims against Tosco and to oppose Tosco’s claims against us.

We are a defendant in eleven pending cases alleging MTBE contamination in groundwater. The plaintiffs 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. All but one of these cases were filed after September 30, 2003 in anticipation of a draft federal energy bill that contained provisions for MTBE liability protection. We are being sued primarily 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. We believe we have defenses to these claims and intend to vigorously defend the lawsuits.

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 Anacortes, Washington refinery. The NWAPA alleged that the refinery emitted sulfur oxides in excess of the permitted allowable limit. Although the NOV did not indicate what remedies the NWAPA is seeking, NWAPA has informally indicated that it may assess a monetary penalty for the alleged violation.

Our common stock is listed under the symbol “TSO” on the New York Stock Exchange and the Pacific Exchange. The per share market price ranges for our common stock on the New York Stock Exchange during 2003 and 2002 are summarized below:

At March 1, 2004, there were approximately 2,520 holders of record of our 64,992,899 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 repurchase program, 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 2004 annual meeting of stockholders will be held at 8:00 A.M. Mountain Standard Time on Tuesday, May 11, 2004, at the Four Seasons Hotel, 10600 East Crescent Moon Drive, Scottsdale, Arizona. Holders of common stock of record at the close of business on March 22, 2004 are entitled to notice of and to vote at the annual meeting.

The following table summarizes, as of December 31, 2003, certain information regarding equity compensation to our employees, officers, directors and other persons under our equity compensation plans.

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, 2003. 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.


		benefits and $5.5 million aftertax ($0.08 per share) for the termination of our funded executive security plan. In 2002, we incurred charges of $8 million aftertax ($0.14 per share) for bridge financing fees associated with the acquisition of the California refinery, $5 million aftertax ($0.08 per share) for losses on asset sales and impairment of goodwill, $5 million aftertax ($0.08 per share) for severance and integration costs, and $6 million ($0.10 per share) for a reduction in previously recognized income tax credits due to income tax refund claims. Also in 2002, we reduced costs of sales by $3 million aftertax ($0.05 per share) due to a LIFO inventory liquidation. 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)		In December 1999, we sold our oil and gas exploration and production operations and recorded an aftertax gain of $39 million from the sale, which is included in earnings from discontinued operations.

(c)		The assumed conversion of our mandatorily convertible preferred stock into 10.35 million shares of our common stock produced anti-dilutive results in 1999 and therefore was not included in the diluted calculations of earnings per share. These securities automatically converted into shares of common stock in July 2001, which eliminated our $12 million annual preferred dividend requirement.

(d)		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 9 5/8% senior subordinated notes due 2012 and two 10-year junior subordinated notes with face amounts totaling $150 million, completed a public offering of 23 million shares, and amended and restated our previous credit facility, primarily to fund the acquisition of the California refinery. In 2001, we issued $215 million of 9 5/8% senior subordinated notes due 2008 and entered into a senior secured credit facility, primarily to finance the acquisitions of the Mid-Continent refineries.

(e)		We have not paid dividends on our common stock since 1986.

(f)		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.

(g)		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 bpd and 160 thousand bpd, 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 thousand bpd and 109 thousand bpd, respectively.

(h)		Sources of total refined product sales include products manufactured at the refineries and products purchased from third parties.

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 47 and “Risk Factors” on page 18 for a discussion of the factors that could cause actual results to differ materially from those projected in these statements.

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 operational excellence and that seeks 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.

In 2003, we achieved the following significant results, which are further described below under “Results of Operations” and “Capital Resources and Liquidity”:


	•	Increased net earnings by $193 million to $76 million in 2003, compared to a net loss of $117 million in 2002, reflecting improved refined product margins, together with a full year of operations from our California refinery, which we acquired in May 2002.

	•	Increased cash flows from operations by $389 million to $447 million from $58 million in 2002, also reflecting the improved product margins and a full year of California refinery operations.

	•	Achieved our $500 million debt reduction goal set in June 2002, reducing our debt-to-capitalization ratio to 62% at year-end, compared to 69% at the end of 2002.

	•	Replaced our former senior secured credit agreement with a new agreement that provides more financing flexibility, lower interest rates and the ability to accelerate debt reduction.

	•	Reduced capital and refinery turnaround spending by $92 million to $152 million in 2003, compared to $244 million in 2002, while maintaining environmental, safety, and regulatory and operational requirements.

	•	Continued to rationalize our asset base by selling certain non-core and under-performing assets.


	•	Improving profitability from operations by achieving greater operating efficiencies;

	•	Using increased cash flows from operations to further reduce debt and interest expense; and

	•	Using capital and turnaround spending to meet EPA Clean Air Act standards and maintain safe, reliable operations.

We believe that the improved industry conditions in 2003 should continue into 2004. Factors that should positively impact industry margins in 2004 include heavy scheduled industry turnaround activity in the western “PADD V” region, improved economic fundamentals in the U.S. and the Far East, and tighter product specifications, including changes in gasoline specifications and the elimination of the MTBE oxygenate in California.

We believe that our cash flows from operations and amounts available under our credit agreement will be adequate to fund our operations, capital spending and debt service requirements. Our earnings and cash flows

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

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. The net earnings for 2003 were primarily the result of improved product margins and the full-year contribution at our California refinery operations. 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. 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.

Our net loss for the year 2002 was $117 million ($1.93 per basic and diluted share) compared with net earnings of $88 million ($2.26 per basic share and $2.10 per diluted share) for 2001. The net loss for 2002 was primarily the result of weak margins in each of our operating segments and additional interest and financing costs related to acquisitions in the second half of 2001 and in May 2002. In 2001, we incurred approximately $7 million aftertax, or $0.17 per share, for financing fees and integration costs, primarily associated with the acquisition of our Mid-Continent refineries.

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.


		during 2002, certain inventory quantities were reduced resulting in the liquidation of applicable LIFO 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 $0.59, $0.56 and $0.48 for 2003, 2002 and 2001, respectively.

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

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 refining margins in all of our regions and additional throughput volumes from the California refinery, which added an additional 61 thousand bpd 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. Gross margins per barrel in our Pacific Northwest and Mid-Continent regions increased 51% and 36%, respectively. 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. While gross margins in our Mid-Pacific region increased 16%, they remained depressed as compared to our other regions. 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. Overall, industry margins during 2003 in our market areas averaged slightly above our five-year average (January 1, 1998 through December 31, 2002). We determine our “five-year average” by comparing gasoline, diesel and jet fuel prices to crude oil prices in our market areas, with volumes weighted according to our typical refinery yields, excluding heavy fuel oils. 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 product sales prices. Total product sales averaged 557 thousand bpd in 2003, as compared to 545 thousand bpd 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 inclusion of the California refinery for the full year.

Refinery throughput and yields in 2004 will be affected by a major maintenance turnaround of certain units at the California refinery in the fourth quarter. We currently expect total refinery throughput to average approximately 500-510 thousand bpd in 2004.

2002 Compared to 2001 — Operating income from our refining segment decreased by $153 million to $73 million in 2002, compared to $226 million in 2001. Our results for 2002 and 2001 included amounts from acquired operations since the dates of acquisition. We acquired the Mid-Continent operations in September 2001 and the California refinery in mid-May 2002. The acquired California operations contributed approximately $37 million to our refining operating income during 2002. Operating income for the Mid-Continent operations increased to $34 million in 2002 from $31 million in 2001 due to the full year of operation, largely offset by weaker refined product margins.

The $153 million decrease in our operating income was primarily due to weak refined product margins in 2002. Margins began to decline in the fourth quarter of 2001 and remained low throughout 2002. Our total gross refining margins averaged $4.38 per barrel, a 25% decrease from 2001, reflecting lower margins in all of our comparable regions, partly offset by California’s additional margin contribution in 2002. The gross margins on a per-barrel basis in our Pacific Northwest, Mid-Pacific and Mid-Continent regions declined 33%, 43% and 42%, respectively, compared to 2001. Industry margins declined primarily due to above average inventory levels for finished products, rising crude oil prices and increased competition from product imports. The industry experienced rapidly rising crude oil prices due to tensions with Iraq during 2002 and political instability in Venezuela during the 2002 fourth quarter. Reduced jet fuel demand and weak economic conditions in the United States and abroad impacted overall industry inventory levels and margins for distillates. Gasoline demand remained strong during 2002 and trended higher than the 2001 level. The increased demand, however, was met with high industry gasoline production levels and increased competition from product imports. Our margins were also negatively impacted by the tightening of the price differential between heavy crude oil and light crude oil. This primarily affected our Pacific Northwest and California regions where the Washington and California refineries are designed to increase earnings by converting heavier, usually less expensive crude oils into higher value products. Our operating income in 2002 was also impacted negatively by the scheduled turnarounds at our Washington and California refineries in the first and second quarters of 2002, respectively, and unscheduled downtime at our Washington and Utah refineries in the first quarter of 2002.

On an aggregate basis, our total gross refining margin increased 17% from 2001 to $699 million in 2002, reflecting additional volumes from the Mid-Continent and California refineries, which added 162 thousand bpd to our total refining throughput in 2002 compared to 2001. Throughput rates were reduced by 7% at our other refineries to 239 thousand bpd in 2002 from 256 thousand bpd in 2001 in response to the weak margin environment in 2002.

Revenues from sales of refined products increased 40% to $6.4 billion in 2002, from $4.6 billion in 2001, due to additional sales volumes from the Mid-Continent and California refineries, partly offset by lower average product sales prices. Total product sales averaged 545 thousand bpd in 2002, an increase of 45% from 2001, while average product prices dropped 4% to $32.25 per barrel. The increase in other revenues was primarily due to higher crude oil resales which totaled $314 million in 2002 compared to $239 million in 2001. Costs of sales also increased primarily due to the additional throughput volumes from the Mid-Continent and California refineries.

Expenses, excluding depreciation, increased to $522 million in 2002, primarily due to additional expenses of approximately $219 million from the Mid-Continent and California refineries. Excluding these new operations, total expenses did not change significantly from 2001. Depreciation and amortization increased to $104 million, primarily due to additional depreciation and amortization of $38 million from the Mid-Continent and California refineries.


(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, 2003

OR

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

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


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)


Title of each class		Name of each exchange on which registered

Common Stock, $0.16 2/3 par value		New York Stock Exchange Pacific Exchange


PART I
Items 1 and 2.	Business and Properties		2
		Refining Segment	2
		Retail Segment	10
		Competition and Other	11
		Government Regulation and Legislation	12
		Employees	13
		Properties	14
		Executive Officers of the Registrant	15
		Board of Directors of the Registrant	17
		Risk Factors	18
Item 3.	Legal Proceedings		22
Item 4.	Submission of Matters to a Vote of Security Holders		22
PART II
Item 5.	Market for Registrant’s Common Equity and Related Stockholder Matters		23
Item 6.	Selected Financial Data		24
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		27
		Business Strategy and Overview	27
		Results of Operations	28
		Capital Resources and Liquidity	35
		Accounting Standards	45
		Forward-Looking Statements	47
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk		49
Item 8.	Financial Statements and Supplementary Data		51
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		87
Item 9A.	Controls and Procedures		87
PART III
Item 10.	Directors and Executive Officers of the Registrant		87
Item 11.	Executive Compensation		87
Item 12.	Security Ownership of Certain Beneficial Owners and Management		87
Item 13.	Certain Relationships and Related Transactions		87
Item 14.	Principal Accountant Fees and Services		87
PART IV
Item 15.	Exhibits, Financial Statement Schedules and Reports on Form 8-K		88
Signatures			95
Amendment #1 to Amended/Restated Credit Agreement
Amendment #2 to Amended/Restated Credit Agreement
Amended/Restated Employment Agreement - B.A. Smith
Management Stability Agreement with W.J. Finnerty
Code of Business Conduct and Ethics
Subsidiaries of the Company
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


			Rated
			Crude Oil		Throughput (bpd)
			Capacity
Refinery			(bpd)		2003		2002		2001

California (a)
	California			168,000		156,400		94,600		—
Pacific Northwest
	Washington			108,000		112,300		104,000		119,400
	Alaska			72,000		48,800		53,000		50,000
Mid-Pacific
	Hawaii			95,000		79,700		81,900		87,100
Mid-Continent (b)
	North Dakota			60,000		47,500		51,400		17,100
		Utah		55,000		43,500		50,100		16,500

		Total Refinery (a)(b)		558,000		488,200		435,000		290,100

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents


(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.

(b)		Throughput volumes in 2001 included the Mid-Continent refineries since we acquired them on September 6, 2001, averaged over 365 days. Throughput for these refineries averaged over the 117 days that we owned them in 2001 was 53,500 bpd in North Dakota and 51,500 bpd in Utah.


(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.

(b)		Refining yield in 2001 included the Mid-Continent refineries since we acquired them on September 6, 2001, averaged over 365 days. Refining yield for these refineries averaged over the 117 days we owned them in 2001 was 108,700 bpd.


			2003		2002(a)		2001(b)

Product Sales (thousand bpd)
	Gasoline and gasoline blendstocks			280		264		161
	Jet fuel			84		94		81
	Diesel fuel			121		115		73
	Heavy oils, residual products and other			72		72		61

		Total Product Sales		557		545		376


(a)		Sales volumes for 2002 include amounts for the California operations since their acquisition on May 17, 2002, averaged over 365 days.

(b)		Sales volumes for 2001 include amounts for the Mid-Continent operations since their acquisition on September 6, 2001, averaged over 365 days.


(a)		Company-operated stations included 29 in Alaska, 36 in Hawaii, 44 in Washington, 39 in Utah and 78 in several other western and mid-continental states at December 31, 2003.

(b)		At December 31, 2003, the jobber/dealer stations included 82 in Alaska, 18 in California, 32 in Idaho, 63 in North Dakota, 61 in Utah, 38 in Washington and 37 in several other western states. The decrease in jobber/dealer stations during 2002 was primarily due to BP/ Amoco branded stations, included in the Mid-Continent acquisition, that did not rebrand to Tesoro®. As a result of their decisions not to rebrand, we are no longer the exclusive supplier for those jobber/dealer stations.

(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.


Name	Age		Position	Position Held Since

Bruce A. Smith		60	Chairman of the Board of Directors, President and Chief Executive Officer		June 1996
William T. Van Kleef		52	Executive Vice President and Chief Operating Officer		July 1998
James C. Reed, Jr.		59	Executive Vice President, General Counsel and Secretary		September 1995
Thomas E. Reardon		57	Executive Vice President, Corporate Resources		November 1999
Gregory A. Wright		54	Executive Vice President and Chief Financial Officer		December 2003
W. Eugene Burden		55	Senior Vice President, Human Resources and Government Relations		June 2002
Everett D. Lewis		56	Senior Vice President, Planning and Optimization		February 2003
Susan A. Lerette		45	Vice President, Communications		April 2001
Otto C. Schwethelm		49	Vice President and Controller		February 2003
G. Scott Spendlove		40	Vice President, Finance and Treasurer		May 2003
Rodney S. Cason		54	President, Tesoro Alaska Company		April 2002
Stephen L. Wormington		59	Executive Vice President, Marketing, Tesoro Refining and Marketing Company		September 2002
William J. Finnerty		55	Senior Vice President, Supply and Distribution, Tesoro Refining and Marketing Company		February 2004
Joseph M. Monroe		49	Senior Vice President, Strategic Planning and Business Development, Tesoro Petroleum Companies, Inc.		February 2004
James L. Taylor		50	Senior Vice President, Manufacturing, Tesoro Refining and Marketing Company		July 2001
Alan R. Anderson		48	Senior Vice President and President, Northern Great Plains Region, Tesoro Refining and Marketing Company		June 2002
J. William Haywood		51	Senior Vice President and President, California Region, Tesoro Refining and Marketing Company		September 2002
Daniel J. Porter		48	Senior Vice President and President, Northwest Region, Tesoro Refining and Marketing Company		June 2002


Bruce A. Smith		Chairman, President and Chief Executive Officer of Tesoro Petroleum Corporation
Steven H. Grapstein		Lead Director of Tesoro Petroleum Corporation; Chief Executive Officer of Kuo Investment Company
William J. Johnson		Petroleum Consultant; President of JonLoc Inc.
A. Maurice Myers		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


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


ITEM 5.	MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS



	2003						2002

Quarters Ended	High			Low			High			Low

March 31	$	7	7/16	$	3	3/8	$	15	19/64	$	11	1/2
June 30	$	8	35/64	$	6	29/64	$	14	35/64	$	5	5/8
September 30	$	9	27/64	$	6	21/32	$	7	47/64	$	2	13/32
December 31	$	15	1/8	$	8	9/16	$	5	13/64	$	1	15/64


ITEMS 1 AND 2.	BUSINESS AND PROPERTIES


	Washington


	Alaska


	Hawaii


(a)		The Key Employee Stock Option Plan was approved by our board of directors in November 1999 and provides for stock option grants to eligible employees who are not our executive officers. We granted stock options to purchase 797,000 shares of common stock, which become exercisable one year after grant in 25 percent annual increments. The options expire ten years after the date of grant. Our board of directors has suspended any future grants under this plan.



			Years Ended December 31,

			2003			2002			2001			2000			1999


			(Dollars in millions except per share amounts)
Statement of Operations Data
Total Revenues			$	8,846		$	7,119		$	5,182		$	5,067		$	3,000

Earnings (Loss) from Continuing Operations, Net of Income Taxes(a)			$	76		$	(117	)	$	88		$	73		$	32
Earnings from Discontinued Operations, Net of Income Taxes(b)				—			—			—			—			43

Net Earnings (Loss)				76			(117	)		88			73			75
Preferred Dividend Requirements(c)				—			—			6			12			12

Net Earnings (Loss) Applicable to Common Stock			$	76		$	(117	)	$	82		$	61		$	63

Earnings (Loss) per Share:
	Continuing Operations —
		Basic	$	1.18		$	(1.93	)	$	2.26		$	1.96		$	0.62
		Diluted	$	1.17		$	(1.93	)	$	2.10		$	1.75		$	0.62
	Net Earnings (Loss) —
		Basic	$	1.18		$	(1.93	)	$	2.26		$	1.96		$	1.94
		Diluted	$	1.17		$	(1.93	)	$	2.10		$	1.75		$	1.92
Weighted Shares Outstanding (millions):
		Basic		64.6			60.5			36.2			31.2			32.4
		Diluted(c)(d)		65.1			60.5			41.9			41.8			32.8
Balance Sheet Data
Current Assets			$	1,024		$	1,054		$	878		$	630		$	612
Property, Plant and Equipment, Net			$	2,252		$	2,303		$	1,522		$	781		$	732
Total Assets			$	3,661		$	3,759		$	2,662		$	1,544		$	1,487
Current Liabilities			$	687		$	608		$	539		$	382		$	322
Total Debt(d)			$	1,609		$	1,977		$	1,147		$	311		$	418
Stockholders’ Equity(d)(e)			$	965		$	888		$	757		$	670		$	623
Current Ratio				1.5:1			1.7:1			1.6:1			1.6:1			1.9:1
Working Capital			$	337		$	446		$	339		$	248		$	290
Total Debt to Capitalization(d)				62	%		69	%		60	%		32	%		40	%
Common Stock Outstanding (millions of shares)(c)(d)(e)				64.8			64.6			41.4			30.9			32.4
Book Value Per Common Share			$	14.89		$	13.74		$	18.28		$	16.39		$	14.14


(a)		In 2003, we incurred charges of $23 million aftertax ($0.35 per share) for the write-off of unamortized debt issuance costs, $6 million aftertax ($0.09 per share) for losses on the sale of Marine Services assets and certain retail asset impairments, $6 million aftertax ($0.09 per share) for voluntary early retirement


ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS


(a)		Includes intersegment sales to our retail segment, at prices which approximate market, of $696 million, $826 million and $334 million in 2003, 2002 and 2001, respectively.

(b)		In 2002, the Washington and California refineries experienced reduced throughput during planned major maintenance turnarounds. In 2003, throughput was reduced at each of the Alaska, North Dakota and Utah refineries during planned major maintenance turnarounds.

(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 bpd and 160 thousand bpd, respectively. Volumes and margins for 2001 include amounts for the Mid-Continent refineries since acquisition on September 6, 2001 averaged over 365 days. Throughput and yield for the Mid-Continent refineries averaged over the 117 days of operation were 105 thousand bpd and 109 thousand bpd, respectively.

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

(e)		Management uses gross refining margin per barrel to compare profitability to other companies in the industry. Gross refining margin per barrel is calculated by dividing gross refining margin by total refining throughput and may not be calculated similarly by other companies. Management uses manufacturing costs per barrel to evaluate the efficiency of refinery operations. Manufacturing costs per barrel may not be comparable to similarly titled measures used by other companies.

(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,