Edgar Filing: TESORO PETROLEUM CORP /NEW/

e10vk

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K


(Mark One)
þ		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

		For the fiscal year ended December 31, 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 ............

Commission File Number 1-3473

TESORO PETROLEUM CORPORATION

(Exact name of registrant as specified in its charter)


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

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

Registrant’s telephone number, including area code:

210-828-8484

Securities registered pursuant to Section 12(b) of the Act:


Title of each class		Name of each exchange on which registered

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

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that 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.

DOCUMENTS INCORPORATED BY REFERENCE

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.

TESORO PETROLEUM CORPORATION

ANNUAL REPORT ON FORM 10-K

TABLE OF CONTENTS


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

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.

PART I


ITEMS 1 AND 2.	BUSINESS AND PROPERTIES

We are an independent refiner and marketer with two major operating segments — (1) refining crude oil and other feedstocks and selling petroleum products in bulk and wholesale markets (“refining”) and (2) selling motor fuels and convenience products in the retail market (“retail”). Through our refining segment, we manufacture products, primarily gasoline and gasoline blendstocks, jet fuel, diesel fuel and heavy fuel oils for sale to a wide variety of commercial customers in the mid-continental and western United States. Our retail segment distributes motor fuels through a network of gas stations, primarily under the Tesoro® and Mirastar® brands. See Notes C, D, E and P in our consolidated financial statements in Item 8 for additional information on our operating segments and properties.

We were incorporated in Delaware in 1968. 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.

REFINING SEGMENT

Overview

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:


			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


(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.

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):



			2003					2002					2001

			Volume		%			Volume		%			Volume		%

California
	Heavy crude			148		95	%		89		94	%		—		—
	Light crude			2		1			—		—			—		—
	Other feedstocks			6		4			6		6			—		—

		Total		156		100	%		95		100	%		—		—

Pacific Northwest
	Heavy crude			85		53	%		74		47	%		78		46	%
	Light crude			70		43			75		48			83		49
	Other feedstocks			6		4			8		5			8		5

		Total		161		100	%		157		100	%		169		100	%

Mid-Pacific
	Heavy crude			51		64	%		49		60	%		53		61	%
	Light crude			29		36			33		40			34		39

		Total		80		100	%		82		100	%		87		100	%

Mid-Continent
	Light crude			87		96	%		97		96	%		34		100	%
	Other feedstocks			4		4			4		4			—		—

		Total		91		100	%		101		100	%		34		100	%

Total Refining Throughput
	Heavy crude			284		58	%		212		49	%		131		45	%
	Light crude			188		39			205		47			151		52
	Other feedstocks			16		3			18		4			8		3

		Total		488		100	%		435		100	%		290		100	%

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):



			2003					2002					2001

			Volume		%			Volume		%			Volume		%

California (a)
	Gasoline and gasoline blendstocks			99		60	%		62		62	%		—		—
	Diesel fuel			38		23			22		22			—		—
	Heavy oils, residual products, internally produced fuel and other			29		17			16		16			—		—

		Total		166		100	%		100		100	%		—		—

Pacific Northwest
	Gasoline and gasoline blendstocks			72		43	%		68		42	%		73		42	%
	Jet fuel			26		16			28		17			28		16
	Diesel fuel			26		16			24		15			30		17
	Heavy oils, residual products, internally produced fuel and other			42		25			42		26			44		25

		Total		166		100	%		162		100	%		175		100	%

Mid-Pacific
	Gasoline and gasoline blendstocks			19		24	%		20		24	%		20		23	%
	Jet fuel			23		28			26		31			27		31
	Diesel fuel			14		17			12		15			14		16
	Heavy oils, residual products, internally produced fuel and other			25		31			25		30			27		30

		Total		81		100	%		83		100	%		88		100	%

Mid-Continent (b)
	Gasoline and gasoline blendstocks			49		52	%		54		51	%		18		52	%
	Jet fuel			9		9			10		10			4		11
	Diesel fuel			25		27			29		28			9		26
	Heavy oils, residual products, internally produced fuel and other			11		12			12		11			4		11

		Total		94		100	%		105		100	%		35		100	%

Total Refining Yield (a)(b)
	Gasoline and gasoline blendstocks			239		47	%		204		45	%		111		37	%
	Jet fuel			58		12			64		15			59		20
	Diesel fuel			103		20			87		19			53		18
	Heavy oils, residual products, internally produced fuel and other			107		21			95		21			75		25

		Total		507		100	%		450		100	%		298		100	%


(a)		Refining yield in 2002 included the California refinery since we acquired it on May 17, 2002, averaged over 365 days. Refining yield for the California refinery averaged over the 229 days we owned it was 160,000 bpd.

(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.

California Refinery

Refining. Our California refinery, located in Martinez on 2,206 acres about 30 miles east of San Francisco, is a highly complex refinery with a rated crude oil capacity of 168,000 bpd. 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.

Pacific Northwest Refineries


	Washington

Refining. Our Washington refinery, located in Anacortes on the Puget Sound on 917 acres about 60 miles north of Seattle, has a total rated crude oil capacity of 108,000 bpd. 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

and truck racks in our market areas, supplied by our refinery and through purchases and exchange arrangements with other refining and marketing companies.


	Alaska

Refining. Our Alaska refinery is located near Kenai on the Cook Inlet on 488 acres approximately 70 miles southwest of Anchorage. 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.

Mid-Pacific Refinery


	Hawaii

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.

Mid-Continent Refineries


	North Dakota

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.


	Utah

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.

Wholesale Marketing and Product Distribution

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:


			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.

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.

RETAIL SEGMENT

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:


			2003			2002			2001

Number of Branded Retail Stations (end of period)
Tesoro® —
	Company-operated			146			154			138
	Jobber/dealer			331			359			183
Mirastar® —
	Company-operated			78			78			55
Other —
	Company-operated			2			2			20
	Jobber/dealer			—			—			281
Total Branded Retail Stations —
	Company-operated(a)			226			234			213
	Jobber/dealer(b)			331			359			464

		Total		557			593			677

Average Number of Branded Stations (during year)
	Company-operated(c)			229			260			132
	Jobber/dealer			346			419			274

		Total Average Retail Stations		575			679			406

Total Fuel Volume (millions of gallons)
	Company-operated			309			418			210
	Jobber/dealer			259			372			186

		Total Fuel Volumes		568			790			396

Average Fuel Volume Per Month Per Station (thousands of gallons)
	Company-operated			112			134			133
	Jobber/dealer			62			74			57
	Total stations			82			97			81
Fuel Revenues (in millions)
	Company-operated		$	519		$	594		$	248
	Jobber/dealer			278			326			173

		Total Fuel Revenues	$	797		$	920		$	421

Merchandise and Other Revenues (in millions)			$	121		$	132		$	71
Merchandise Margin				27	%		27	%		30	%


(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.

COMPETITION AND OTHER

The petroleum industry is highly competitive in all phases, including the purchase of crude oil and the marketing of refined petroleum products. The industry also competes with other industries that supply the energy and fuel requirements of industrial, commercial and individual consumers. In recent years, consolidation in the refining and marketing industry has reduced the number of competitors; however, it has not reduced overall competition. We compete with a number of major integrated oil companies and other companies that have greater financial and other resources. These competitors have a greater ability to bear the economic risks inherent in all phases of the industry. In addition, unlike many of our competitors, we do not produce crude oil for use in our refining operations, and we are not as large as many of our competitors who may have a competitive advantage when negotiating with crude oil producers.

Our California and Washington refineries compete with several refineries on the U.S. West Coast, including refineries that have greater 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.

GOVERNMENT REGULATION AND LEGISLATION

Environmental Controls and Expenditures

All of our operations, like those of other companies engaged in similar businesses, are subject to extensive and frequently changing federal, state, regional and local laws, regulations and ordinances relating to the protection of the environment, including those governing emissions or discharges to the air and water, the handling and disposal of solid and hazardous wastes and the remediation of contamination. While we believe our facilities are in substantial compliance with current requirements, 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

closed locations), and for compliance with the Clean Air Act and other federal, state and local requirements. We cannot currently determine the amount of these future expenditures.

Oil Spill Prevention and Response

We operate in environmentally sensitive coastal waters, where tanker, pipeline and refined product transportation operations are closely regulated by federal, state and local agencies and monitored by environmental interest groups. The transportation of crude oil and refined product over water involves risk and subjects us to the provisions of the Federal Oil Pollution Act of 1990 and related state regulations, which require that most oil refining, transport and storage companies maintain and update various oil spill prevention and oil spill contingency plans. We have submitted these plans and received federal and state approvals necessary to comply with the Federal Oil Pollution Act of 1990 and related regulations. Our oil spill prevention plans and procedures are frequently reviewed and modified to prevent oil and product releases and to minimize potential impacts should a release occur.

We currently charter tankers to ship crude oil from foreign and domestic sources to our California, Mid-Pacific and Pacific Northwest refineries. The Federal Oil Pollution Act of 1990 requires, as a condition of operation, that we demonstrate the capability to respond to the “worst case discharge” to the maximum extent practicable. As an example, the State of Alaska requires us to provide spill-response capability to contain or control and cleanup amounts equal to 50,000 barrels of crude oil for a tanker carrying fewer than 500,000 barrels and 300,000 barrels for a tanker carrying more than 500,000 barrels. To meet these requirements, we have entered into contracts with various parties to provide spill response services. We have entered into spill-response agreements with (1) Cook Inlet Spill Prevention and Response, Incorporated (for which we fund approximately 65% of expenditures) and Alyeska Pipeline Service Company for spill-response services in Alaska, (2) Clean Islands Council for response services throughout the State of Hawaii, and (3) Clean Sound Incorporated for response actions associated with the Puget Sound, Washington operations. In addition, for larger spill contingency capabilities, we have entered into contracts with Marine Spill Response Corporation for Hawaii, the San Francisco Bay and Puget Sound. We believe these contracts, and those with other regional spill-response organizations that are in place on a location by location basis, provide the additional services necessary to meet spill-response requirements established by state and federal law.

Regulation of Pipelines

Our crude oil pipeline system in North Dakota and our pipeline systems in Alaska are common carriers subject to regulation by various federal, state and local agencies, including the FERC under the Interstate Commerce Act. The Interstate Commerce Act provides that, to be lawful, the rates of common carrier petroleum pipelines must be “just and reasonable” and not unduly discriminatory.

The intrastate operations of our crude oil pipeline system are subject to regulation by the North Dakota Public Services Commission. The intrastate operations of our Alaska pipelines are subject to regulation by the Alaska Public Utilities Commission. Like the FERC, the state regulatory authorities require that we notify shippers of proposed intrastate tariff increases and they have an opportunity to protest the increases. The North Dakota Public Services Commission also files with the state authorities copies of interstate tariff charges filed with the FERC. In addition to challenges to new or proposed rates, challenges to intrastate rates that have already become effective are permitted by complaint of an interested person or by independent action of the appropriate regulatory authority.

EMPLOYEES

At December 31, 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.

PROPERTIES

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.

EXECUTIVE OFFICERS OF THE REGISTRANT

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


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

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.

BOARD OF DIRECTORS OF THE REGISTRANT

The following is a list of the Company’s Board of Directors:


Bruce A. Smith		Chairman, President and Chief Executive Officer of Tesoro 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

RISK FACTORS

The volatility of crude oil prices, refined product prices and natural gas and electrical power prices may have a material adverse effect on our cash flow and results of operations.

Our earnings and cash flows from our refining and wholesale marketing operations depend on a number of factors, including fixed and variable expenses (including the cost of refinery feedstocks) and the margin above those expenses at which we are able to sell refined products. In recent years, the prices of crude oil and refined products have fluctuated substantially. These prices depend on numerous factors beyond our control, including the demand for crude oil, gasoline and other refined products, which are subject to, among other things:


	•	changes in the economy and the level of foreign and domestic production of crude oil and refined products;

	•	threatened or actual terrorist incidents, acts of war, and other worldwide political conditions;

	•	availability of crude oil and refined products and the infrastructure to transport crude oil and refined products;

	•	weather conditions, earthquakes or other natural disasters;

	•	government regulations; and

	•	local factors, including market conditions and the level of operations of other refineries in our markets.

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

or conditions that may be discovered in the future and that require a response. Several regulations will require us to complete the following capital projects at our refineries:


	•	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.


ITEM 3.	LEGAL PROCEEDINGS

In the ordinary course of business, we become party to or otherwise involved in lawsuits, administrative proceedings and governmental investigations, including environmental, regulatory and other matters. Large and sometimes unspecified damages or penalties may be sought from us in some matters, and some matters may require years for us to resolve. We cannot provide assurance that an adverse resolution of one or more of the matters described below during a future reporting period will not have a material adverse effect on our 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.


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

None.

PART II


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

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



	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

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.

Equity Compensation Plan Information

Number of Securities

Remaining Available for

Future Issuance under

Number of Securities to be

Weighted-Average Exercise

Equity Compensation

Issued upon Exercise of

Price of Outstanding

Plans (Excluding

Outstanding Options,

Options, Warrants and

Securities Reflected in

Plan Category

Warrants and Rights

Rights

the Second Column)

Equity compensation plans approved by security holders

5,658,070

11.42

755,102

Equity compensation plans not approved by security holders(a)

611,200

10.31

174,750

Total

6,269,270

11.31

929,852


(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.


ITEM 6.	SELECTED FINANCIAL DATA

The following table sets forth certain selected consolidated financial and operating data of Tesoro as of the end of and for each of the five years in the period ended December 31, 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.



			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

(table continued on following page)



			Years Ended December 31,

			2003			2002			2001			2000			1999


			(Dollars in millions)
Cash Flows From (Used In)
	Operating Activities		$	447		$	58		$	214		$	90		$	113
	Investing Activities			(70	)		(941	)		(976	)		(88	)		166
	Financing Activities(d)			(410	)		941			800			(130	)		(149	)

	Increase (Decrease) in Cash and Cash
		Equivalents	$	(33	)	$	58		$	38		$	(128	)	$	130

Capital Expenditures(f)
	Continuing operations		$	101		$	204		$	210		$	94		$	85
	Discontinued operations			—			—			—			—			56

		Total Capital Expenditures	$	101		$	204		$	210		$	94		$	141

Operating Data
Refining Throughput (thousands of bpd)(g) —
	California			156			95			—			—			—
	Pacific Northwest
		Washington		112			104			119			117			98
		Alaska		49			53			50			48			49
	Mid-Pacific
		Hawaii		80			82			87			84			87
	Mid-Continent
		North Dakota		48			51			17			—			—
		Utah		43			50			17			—			—

		Total Refining Throughput		488			435			290			249			234

Refining Yield (thousands of bpd)(g) —
	Gasoline and gasoline blendstocks			239			204			111			95			93
	Jet fuel			58			64			59			58			58
	Diesel fuel			103			87			53			39			33
	Heavy oils, residual products, internally produced fuel and other			107			95			75			65			60

		Total Refining Yield		507			450			298			257			244

Product Sales (thousands of bpd)(g)(h) —
	Gasoline and gasoline blendstocks			280			264			161			135			124
	Jet fuel			84			94			81			76			76
	Diesel fuel			121			115			73			54			47
	Heavy oils, residual products and other			72			72			61			58			56

		Total Product Sales		557			545			376			323			303

Retail Fuel Sales (millions of gallons)				568			790			396			215			199
Number of Retail Stations (end of period)				557			593			677			276			244


(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


		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.


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

Those statements in this section that are not historical in nature should be deemed forward-looking statements that are inherently uncertain. See “Forward-Looking Statements” on page 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.

BUSINESS STRATEGY AND OVERVIEW

Our strategy is to create a geographically-focused, value-added refining and marketing business that has (i) economies of scale, (ii) a low-cost structure, (iii) superior management information systems and (iv) outstanding employees focused on 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.

For 2004, our goals are focused on:


	•	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.

RESULTS OF OPERATIONS

Summary

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.

Refining Segment


				2003		2002		2001


				(Dollars in millions except per
				barrel amounts)
Revenues
	Refined products(a)			$	8,098	$	6,426	$	4,603
	Crude oil resales and other				370		335		248

		Total Revenues		$	8,468	$	6,761	$	4,851

Refining Throughput (thousand barrels per day)(b)
	California(c)				156		95		—
	Pacific Northwest
			Washington		112		104		119
			Alaska		49		53		50
	Mid-Pacific
			Hawaii		80		82		87
	Mid-Continent (c)
			North Dakota		48		51		17
			Utah		43		50		17

			Total Refining Throughput		488		435		290

% Heavy Crude Oil of Total Refinery Throughput (d)					58		49		45

Yield (thousand barrels per day) (c)
	Gasoline and gasoline blendstocks				239		204		111
	Jet Fuel				58		64		59
	Diesel Fuel				103		87		53
	Heavy oils, residual products, internally produced fuel and other				107		95		75

		Total Yield			507		450		298

Refining Margin ($/throughput barrel)(e)
	California
		Gross refining margin		$	9.63	$	6.41	$	—
		Manufacturing cost before depreciation and amortization		$	4.41	$	4.17	$	—
	Pacific Northwest
		Gross refining margin		$	6.19	$	4.09	$	6.07
		Manufacturing cost before depreciation and amortization		$	2.26	$	2.05	$	1.89
	Mid-Pacific
		Gross refining margin		$	3.30	$	2.85	$	4.96
		Manufacturing cost before depreciation and amortization		$	1.39	$	1.39	$	1.27
	Mid-Continent
		Gross refining margin		$	5.68	$	4.17	$	7.25
		Manufacturing cost before depreciation and amortization		$	2.52	$	2.22	$	2.07
	Total
		Gross refining margin		$	6.73	$	4.38	$	5.87
		Manufacturing cost before depreciation and amortization		$	2.85	$	2.43	$	1.72


				2003		2002		2001


				(Dollars in millions except per
				barrel amounts)
Segment Operating Income
	Gross refining margin (after inventory changes) (c)(f)			$	1,196	$	699	$	598
	Expenses
		Manufacturing costs			509		386		182
		Other operating expenses			129		104		101
		Selling, general and administrative			27		32		26
		Depreciation and amortization(g)			120		104		63

			Segment Operating Income	$	411	$	73	$	226

Product Sales (thousand barrels per day)(a)(h)
	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

Product Sales Margin ($/barrel)(h)
	Average sales price			$	39.81	$	32.25	$	33.50
	Average costs of sales				33.99		28.75		29.17

		Product Sales Margin		$	5.82	$	3.50	$	4.33


(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,


		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.

Retail Segment


				2003			2002			2001


				(Dollars in millions except
				per gallon amounts)
Revenues (a)
	Fuel			$	797		$	920		$	421
	Merchandise and other				121			132			70

		Total Revenues		$	918		$	1,052		$	491

Fuel Sales (millions of gallons)(a)					568			790			396
Fuel Margin ($/gallon)(b)				$	0.18		$	0.12		$	0.22
Merchandise Margin (in millions)(a)				$	31		$	35		$	20
Merchandise Margin (percent of sales)					27	%		27	%		30	%
Average Number of Stations (during the period)(a)
	Company-operated				229			260			132
	Branded jobber/dealer				346			419			274

		Total Average Retail Stations			575			679			406

Segment Operating Income (Loss)
	Gross Margins
		Fuel(c)		$	101		$	95		$	87
		Merchandise and other non-fuel margin			35			40			22

			Total gross margins		136			135			109
	Expenses
		Operating expenses			71			99			53
		Selling, general and administrative			30			31			20
		Depreciation and amortization			19			17			11

			Segment Operating Income (Loss)	$	16		$	(12	)	$	25


(a)		In December 2002, we sold 70 company-operated stations that were acquired in May 2002 with the California refinery.

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

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

2003 Compared to 2002 — Operating income for our retail segment improved by $28 million to $16 million in 2003, compared to an operating loss of $12 million in 2002. Total gross margins were $136 million in 2003 compared to $135 million in 2002 reflecting higher fuel margin per gallon, largely offset by lower sales volume. Fuel margin increased to $0.18 per gallon in 2003 from $0.12 per gallon in 2002, reflecting increased demand, lower inventories and our efforts to improve operations. Total gallons sold decreased to 568 million, reflecting the decrease in average station count to 575 in 2003 from 679 in 2002. The decrease primarily was due to selling 70 company-operated stations in December 2002 (acquired with the California refinery in mid-May 2002) and the fact that 150 BP/ Amoco branded independent jobber/dealer stations (included in the 2001 acquisition of the Mid-Continent refining and retail assets) did not rebrand to the Tesoro® brand.

Revenues on fuel sales decreased to $797 million in 2003, from $920 million in 2002, reflecting lower sales volumes from fewer stations, partly offset by increased sales prices. Costs of sales also decreased in 2003 due to lower sales volumes, partly offset by higher prices of purchased fuel. The decrease in operating, selling, general and administrative expenses to $101 million in 2003 from $130 million in 2002 reflects our initiatives to reduce expenses and the decrease in average station count. Depreciation increased to $19 million in 2003, compared to $17 million in 2002, reflecting the placement of new assets into service in 2002 and accelerated depreciation for certain assets written off during 2003.

2002 Compared to 2001 — The operating loss for our retail segment was $12 million in 2002 compared to operating income of $25 million in 2001. Total gross margins increased 24% to $135 million in 2002 from $109 million in 2001, reflecting increased sales volume, offset largely by lower fuel margin per gallon. Fuel margin decreased to $0.12 per gallon in 2002 from $0.22 per gallon in 2001, reflecting continued competitive price pressures and changes in the geographic mix of our retail sites. Total gallons sold increased to 790 million, reflecting the increase in average station count to 679 in 2002 from 406 in 2001, primarily due to the Mid-Continent operations acquired in September 2001, additional stations acquired in the Pacific Northwest in November 2001, and 70 retail stations acquired with the California refinery assets in May 2002. As a part of our debt reduction initiative, we sold the 70 California stations in December 2002, which contributed approximately $6 million to operating income during the period we owned them in 2002.

Revenues on fuel sales increased to $920 million in 2002, from $421 million in 2001, while merchandise and other revenues increased by 89% to $132 million. Merchandise margin decreased, however, as a percent of sales, reflecting changes in the mix of merchandise offerings. With our increased number of stations, expenses increased to $130 million and depreciation increased to $17 million in 2002.

Marine Services

In December 2003, we sold substantially all of the physical assets of Marine Services for $32 million, including inventories, and we recognized a pretax loss on the sale of $8 million. Proceeds from the sale were used for general corporate purposes. Marine Services operations had become increasingly immaterial, as compared to our primary refining and retail operations, and we believe that the sale of Marine Services assets is not significant to the historical or ongoing analysis or comparability of our primary operating results or financial position.

Operating income increased to $6 million during 2003, reflecting higher sales volume and margins, and lower operating expenses. In 2002, operating income decreased to $2 million from $10 million in 2001 primarily due to lower sales volumes and service revenues. These operations depended largely on the volume of oil and gas drilling, workover, construction and seismic activity in the Gulf of Mexico. See Note E in our consolidated financial statements in Item 8 for summarized financial information related to Marine Services.

Selling, General and Administrative Expenses

Selling, general and administrative expenses of $138 million in 2003 increased from $133 million in 2002. The increase was due to charges totaling $17 million for voluntary early retirement benefits, severance costs and the termination of our funded executive security plan. Excluding these charges, we reduced selling, general and administrative expenses by approximately $12 million, through our cost reduction initiatives. This reduction in expense was net of employees’ performance bonuses in 2003, while no bonuses were awarded in 2002. As discussed above, our refining and retail segment expenses decreased as a result of our focus on cost reduction initiatives during 2003.

Selling, general and administrative expenses of $133 million in 2002 increased from $104 million in 2001. The increase was due partially to higher expenses in the refining and retail segments associated with the purchases of refinery and marketing assets in the last half of 2001 and May 2002. Corporate expenses accounted for $12 million of the increase during 2002, resulting from higher acquisition and integration costs, employee costs and professional fees.

Loss on Asset Sales and Impairments

The loss on asset sales and impairments of $17 million in 2003 consisted primarily of the loss on the sale of Marine Services of $8 million, the write-off of certain refinery assets that were replaced, and the impairment of certain retail assets. During 2002, the loss on asset sales and impairments of $8 million consisted primarily of losses on the sale of retail stations and an impairment of retail goodwill. See Notes D and K in our consolidated financial statements in Item 8.

Interest and Financing Costs

Interest and financing costs were $212 million in 2003 compared to $163 million in 2002. The increase was due primarily to the write-off of $36 million of unamortized debt issuance costs in connection with the replacement of our previous credit facility and voluntary prepayments of other debt, as well as interest on additional debt that we incurred in May 2002 to finance the acquisition of our California refinery.

Interest and financing costs were $163 million in 2002 compared to $52 million in 2001. The increase was due primarily to the additional debt we incurred in 2001 and 2002 in connection with our acquisitions of the Mid-Continent and California operations. We also expensed $13 million in 2002 related to bridge and other financing fees for the acquisition of the California refinery.

Income Tax Provision (Benefit)

The income tax provision amounted to $47 million in 2003 compared to an income tax benefit of $64 million in 2002. The provision reflects pretax earnings for 2003, while the benefit reflects the pretax loss for 2002. The income tax provision of $59 million in 200l reflects pretax earnings in that year at a slightly higher combined effective income tax rate. The combined federal and state effective income tax rates were approximately 38%, 35% and 40% in 2003, 2002 and 2001, respectively. In 2002, we elected to carry back net operating losses to recover income taxes paid in previous years; however, the refund of those taxes resulted in the loss of certain tax credits. The expiration of these credits, along with other adjustments to our estimated liabilities, resulted in a reduced tax benefit of approximately $6 million in 2002.

CAPITAL RESOURCES AND LIQUIDITY

Overview

We operate in an environment where our capital resources and liquidity are impacted by changes in the price of crude oil and refined petroleum products, availability of trade credit, market uncertainty and a variety of additional factors beyond our control. These risks include, among others, the level of consumer product demand, weather conditions, fluctuations in seasonal demand, governmental regulations, worldwide political conditions and overall market and economic conditions. See “Business Strategy and Overview” on page 27, “Forward-Looking Statements” on page 47 and “Risk Factors” on page 18 for further information related to risks and other factors. Our future capital expenditures, as well as borrowings under our credit agreement and other sources of capital, will be affected by these conditions. Nevertheless, 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. We recovered income tax refunds in 2003 and 2002, and due to net operating loss carry-forwards, we expect to pay no more than a minimum amount of federal income taxes in 2004.

Our primary sources of liquidity have been cash flows from operations and borrowing availability under revolving lines of credit. We ended 2003 with $77 million of cash and cash equivalents, no borrowings under our revolving credit facility, and $268 million in available borrowing capacity under our credit agreement after $232 million in outstanding letters of credit. During 2003, we reduced total debt by $377 million primarily through voluntary repayments, partly offset by $9 million of debt discount accretion. As further described below, we replaced our previous credit facility in April 2003, including our related term loans, by entering into a new credit agreement, including a $500 million revolving line of credit, and issuing $375 million in 8% senior secured notes and $200 million in floating-rate senior secured term loans.

Under our new credit agreement, we used the increased letter of credit capacity to replace early payments and prepayments on crude and product purchases. We had $232 million in letters of credit outstanding at the end of 2003 compared to $85 million at March 31, 2003. Prior to entering into our new credit agreement, prepayments and early payments had increased to approximately $156 million at March 31, 2003, compared to prepayments of $16 million at December 31, 2003.

Capitalization

On April 17, 2003, Tesoro replaced its $1.275 billion senior secured credit facility with a new credit agreement, senior secured term loans and 8% senior secured notes due 2008. We expensed $36 million of unamortized debt issuance costs in 2003, in connection with the extinguishment of the prior credit facility and voluntary prepayments of other debt, including the voluntary prepayment of the $150 million term loan, described below under “Credit Agreement.”

Our capital structure at December 31, 2003 was comprised of (in millions):


Debt, including current maturities:
	Credit Agreement — Revolving Credit Facility		$	—
	Senior Secured Term Loans Due 2008			199
	8% Senior Secured Notes Due 2008			372
	9 5/8% Senior Subordinated Notes Due 2012			429
	9 5/8% Senior Subordinated Notes Due 2008			211
	9% Senior Subordinated Notes Due 2008			296
	Junior subordinated notes due 2012			75
	Capital lease obligations and other			27

		Total debt		1,609
Stockholders’ equity				965

		Total Capitalization	$	2,574

At December 31, 2003, our debt to capitalization ratio was 62%, compared to 69% at year-end 2002, primarily reflecting total debt repayments of $377 million and net earnings of $76 million during 2003. In 2004, we intend to further reduce debt through expected improvements in earnings and cash flows from operations.

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

Credit Agreement

On April 17, 2003, Tesoro entered into a new credit agreement, including a $500 million revolving credit facility maturing in June 2006 and a $150 million term loan maturing in April 2007. The credit agreement, together with the net proceeds of the $200 million senior secured term loans and $375 million of 8% senior secured notes discussed below, replaced our prior credit facility. In addition, $25 million of the proceeds were used to repurchase 9 5/8% senior subordinated notes. We voluntarily prepaid the $150 million term loan in 2003.

The credit agreement currently provides for borrowings (including letters of credit) up to the lesser of $500 million or the amount of a periodically adjusted borrowing base ($648 million as of December 31, 2003), consisting of Tesoro’s eligible cash and cash equivalents, receivables and petroleum inventories, as defined. As of December 31, 2003, we had no borrowings and $232 million in letters of credit outstanding under the revolving credit facility, resulting in total unused credit availability of $268 million, or 54% of the eligible borrowing base.

The credit agreement contains covenants and conditions that, among other things, limit our ability to pay cash dividends, incur indebtedness, create liens and make investments. Tesoro is also required to maintain specified levels of fixed charge coverage and tangible net worth. Beginning with the quarter ending March 31, 2004, we will not be required to maintain the fixed charge coverage ratio if unused credit availability exceeds 15% of the eligible borrowing base. The credit agreement is guaranteed by substantially all of Tesoro’s active subsidiaries and is secured by substantially all of Tesoro’s cash and cash equivalents, petroleum inventories and receivables.

Borrowings under the credit agreement bear interest at either a base rate (4.0% at December 31, 2003) or a eurodollar rate (ranging from 1.15% to 1.17% at December 31, 2003), plus an applicable margin. The applicable margins at December 31, 2003 for the revolving credit facility were 1.0% in the case of the base rate and 2.75% in the case of the eurodollar rate. Letters of credit outstanding under the revolving credit facility incur fees at an annual rate equal to the eurodollar rate applicable margin for the revolving credit facility. The applicable margins under the revolving credit facility vary based on credit availability levels. In January 2004, the revolving credit facility eurodollar rate applicable margin was reduced from 2.75% to 2.25%, based on the 2003 fourth quarter credit availability levels.

Senior Secured Term Loans

On April 17, 2003, we entered into new $200 million senior secured term loans due April 15, 2008. The term loans are subject to optional redemption by Tesoro beginning April 15, 2004 at premiums of 3% through April 14, 2005, 1% from April 15, 2005 to April 14, 2006, and at par thereafter. The term loans contain covenants and restrictions that are less restrictive than those in the credit agreement. The term loans and the 8% senior secured notes, described below, are equally secured by substantially all of the Tesoro’s refining property, plant and equipment and are guaranteed by substantially all of Tesoro’s active subsidiaries. Interest rates were 6.65% to 6.67% on the term loans at December 31, 2003. Borrowings under the term loans bear interest at either a base rate (4.0% at December 31, 2003) or a eurodollar rate (ranging from 1.15% to 1.17% at December 31, 2003), plus an applicable margin. The applicable margins for the term loans were 4.5% in the case of the base rate and 5.5% in the case of the eurodollar rate at December 31, 2003.

8% Senior Secured Notes Due 2008

On April 17, 2003, Tesoro issued $375 million aggregate principal amount of 8% senior secured notes due April 15, 2008 through a private offering. On July 29, 2003, we completed an exchange of substantially all of the outstanding notes for 8% senior secured notes due 2008 that had been registered under the Securities Act of 1933. The notes have a five-year maturity with no sinking fund requirements and are subject to optional redemption by Tesoro, beginning April 15, 2006, at a premium of 4% through April 14, 2007, and at par thereafter. We have the right to redeem up to 35% of the aggregate principal amount at a redemption price of 108% with proceeds from certain equity issuances through April 15, 2006. The indenture for the notes contains covenants and restrictions that are customary for notes of this nature and are similar to the covenants in the indentures for Tesoro’s senior subordinated notes. The notes and the term loans are equally secured by substantially all of Tesoro’s refining property, plant and equipment and are guaranteed by substantially all of Tesoro’s active subsidiaries. The notes were issued at 98.994% of par, resulting in net proceeds of $371.2 million before debt issuance costs. The effective interest rate on the notes was 8.25%, after giving effect to the discount.

Senior Subordinated Notes

In April 2002, we issued $450 million principal amount of 9 5/8% senior subordinated notes due April 1, 2012. The 9 5/8% senior subordinated notes due 2012 have a ten-year maturity with no sinking fund requirements and are subject to optional redemption by us beginning April 1, 2007 at premiums of 4.8% through March 31, 2008, 3.2% from April 1, 2008 to March 31, 2009, 1.6% from April 1, 2009 to March 31, 2010, and at par thereafter. In addition, until April 1, 2005, we have the right to redeem up to 35% of the principal amount at a redemption price of 109.625% with proceeds of certain equity issuances.

In November 2001, we issued $215 million principal amount of 9 5/8% senior subordinated notes due November 1, 2008. The 9 5/8% senior subordinated notes due 2008 have a seven-year maturity with no sinking fund requirements and are subject to optional redemption by us beginning November 1, 2005 at premiums of 4.8% through October 31 2006, 2.4% from November 1, 2006 to October 31, 2007, and at par thereafter. In addition, until November 1, 2004, we have the right to redeem up to 35% of the principal amount at a redemption price of 109.625% with the net cash proceeds of one or more equity offerings.

Our 9% senior subordinated notes due 2008, Series B, were issued in 1998 at a principal amount of $300 million. These notes have a ten-year maturity without sinking fund requirements and are subject to optional redemption by us at premiums of 4.5% through June 30, 2004, 3% from July 1, 2004 through June 30, 2005, 1.5% from July 1, 2005 through June 30, 2006, and at par thereafter.

The indentures for our senior subordinated notes contain covenants and restrictions which are customary for notes of this nature. These covenants and restrictions limit, among other things, our ability to:


	•	pay dividends and other distributions with respect to our capital stock and purchase, redeem or retire our capital stock;

	•	incur additional indebtedness and issue preferred stock;

	•	sell assets unless the proceeds from those sales are used to repay debt or are invested in our business;

	•	incur liens on assets to secure certain debt;

	•	engage in certain business activities;

	•	engage in certain merger or consolidations and transfers of assets; and

	•	enter into transactions with affiliates.

The indentures also limit our subsidiaries’ ability to create restrictions on making certain payments and distributions. The senior subordinated notes are guaranteed by substantially all of our active domestic subsidiaries.

Junior Subordinated Notes Due 2012

In connection with our acquisition of the California refinery, we issued to the seller two ten-year junior subordinated notes with face amounts aggregating $150 million. The notes consist of: (i) a $100 million junior subordinated note, due July 2012, which is non-interest bearing through May 16, 2007 and carries a 7.5% interest rate thereafter, and (ii) a $50 million junior subordinated note, due July 2012, which bears interest at 7.47% from May 17, 2003 through May 16, 2007 and 7.5% thereafter. The junior subordinated notes were recorded initially at a combined present value of approximately $61 million, discounted at a rate of 15.625% and 14.375%, respectively. The discount is being amortized over the term of the notes.

Cash Flow Summary

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


		2003			2002			2001

Cash Flows From (Used In):
	Operating Activities	$	447		$	58		$	214
	Investing Activities		(70	)		(941	)		(976	)
	Financing Activities		(410	)		941			800

Increase (Decrease) in Cash and Cash Equivalents		$	(33	)	$	58		$	38

Net cash from operating activities during 2003 totaled $447 million, compared to $58 million from operating activities in 2002. The increase was primarily due to improved earnings before depreciation and amortization, the collection of income tax refunds and lower working capital requirements. Net cash used in

investing activities of $70 million in 2003 was primarily for capital expenditures partially offset by proceeds from the sale of Marine Services assets. Net cash used in financing activities of $410 million in 2003 was primarily for voluntary debt prepayments under the term loan, other debt repayments, and financing costs related to the new credit agreement. Gross borrowings and repayments under revolving credit lines amounted to $1.0 billion during 2003. Working capital totaled $337 million at December 31, 2003 compared to $446 million at December 31, 2002, reflecting an increase in accounts payable and accrued liabilities of $145 million, partly offset by decreases in the current maturities of debt and income taxes receivable. The increase in our accounts payable reflects the decrease in early payments and prepayments on crude oil and product purchases as a result of our increased use of letters of credit.

Net cash from operating activities during 2002 totaled $58 million, compared to $214 million from operating activities in 2001. The decrease was primarily due to lower earnings before depreciation and amortization and higher expenditures for scheduled refinery turnarounds, partially offset by reduced working capital requirements and income tax refunds. Net cash used in investing activities of $941 million in 2002 included $932 million for the acquisition of the California refinery and $204 million for capital expenditures, partially offset by $207 million in proceeds from asset sales. Net cash from financing activities of $941 million in 2002 included net proceeds of $245 million from our equity offering, net proceeds of $441 million from our notes offering and borrowings of $425 million under our previous senior secured credit facility, partly offset by repayments of debt of $133 million and financing costs of $37 million. Gross borrowings and repayments under revolving credit lines amounted to $624 million during 2002. Working capital totaled $446 million at December 31, 2002 compared to $340 million at year-end 2001, reflecting increases related to the acquisition of the California refinery, cash and income taxes receivable, partly offset by reductions in inventories.

Net cash from operating activities during 2001 totaled $214 million, including the results from our Mid-Continent operations acquired in September 2001. Net cash used in investing activities of $976 million in 2001 included $783 million for acquisitions and $210 million for capital expenditures, partially offset by proceeds from asset sales. Net cash from financing activities of $800 million in 2001 included net borrowings of $625 million under our previous senior secured credit facility and net proceeds of $210 million from our notes offering, partly offset by financing costs of $21 million and preferred dividend payments of $9 million. The preferred stock was converted to common stock in July 2001, eliminating the preferred dividend requirement. Gross borrowings and repayments under revolving credit lines and interim facilities amounted to $958 million during 2001.

Historical EBITDA

EBITDA represents earnings before interest and financing costs, income taxes, and depreciation and amortization. We present EBITDA because we believe investors use EBITDA to help analyze our ability to satisfy principal and interest obligations with respect to our indebtedness and to use cash for other purposes, including capital expenditures. EBITDA is also used for internal analysis and as a component of the fixed charge coverage financial covenant in our new credit agreement. EBITDA should not be considered as an alternative to net earnings (loss), earnings (loss) before income taxes, cash flows from operating activities or any other measure of financial performance presented in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”). EBITDA may not be comparable to similarly titled measures used by other entities. Our annual historical EBITDA was (in millions):


		2003		2002			2001

Net Earnings (Loss)		$	76.1	$	(117.0	)	$	88.0
Add Income Tax Provision (Benefit)			47.0		(64.3	)		58.9
Add Interest and Financing Costs, Net			211.7		162.6			51.8

	Operating Income (Loss)		334.8		(18.7	)		198.7
Add Depreciation and Amortization			148.2		130.7			79.9

	EBITDA	$	483.0	$	112.0		$	278.6

Historical EBITDA as presented above differs from EBITDA as defined under our credit agreement. The primary differences are non-cash postretirement benefit costs and loss on asset sales and impairments, which are added to net earnings (loss) under the credit agreement EBITDA calculations.

Capital Expenditures and Refinery Turnaround Spending

Our capital expenditures and refinery turnaround spending totaled $152 million during 2003, compared to $244 million in 2002 as discussed below.


	Capital Expenditures

We revised our 2003 capital spending plan in response to the weaker refining and retail margin environment experienced in 2002. We reduced or deferred our spending plans for certain discretionary projects while maintaining spending to meet environmental, safety, regulatory and other operational requirements. The reduced capital plan primarily related to the deferral of discretionary economic refinery projects and minimal spending for retail projects, while 2002 spending included $60 million for the California refinery CARB III project, $24 million for the completion of the heavy oil project at our Washington refinery and $41 million for developing retail operations. Our 2003 total spending, relating to environmental, safety, regulatory and turnarounds, remained comparable to amounts expended during 2002. During 2003, our capital expenditures (excluding refinery turnaround and other major maintenance costs), totaled $101 million, which included $11 million for completion of the FCC riser project at the North Dakota refinery, $17 million for the completion of the CARB III project at our California refinery and $9 million for clean air and MACT II environmental projects. Other capital spending was primarily for various refinery improvements and other environmental requirements.

We expect our capital expenditures to approximate $160 million to $170 million in 2004 (excluding refinery turnaround and other major maintenance costs of approximately $51 million). The capital budget for the refining segment is $160 million, including $13 million for control systems modernization at the California refinery, $54 million for clean air and clean fuel projects (including $16 million for a wet gas scrubber project at the North Dakota refinery), and other projects totaling $93 million. Our retail capital budget is $6 million for 2004. We expect to fund the 2004 capital spending program from operating cash flows.


	Refinery Turnaround and Other Major Maintenance

During 2003, we spent $51 million for refinery maintenance turnaround, including $6 million for our scheduled turnaround of certain processing units at our Utah refinery in the first quarter of 2003, $8 million for the completion of a scheduled turnaround of the Alaska refinery in the second quarter of 2003 and $19 million for the completion of a scheduled turnaround at the North Dakota refinery during September-October 2003. Amortization of refinery turnaround and other major maintenance costs totaled $31 million in 2003. We expect to spend approximately $51 million in 2004, primarily for a major turnaround at our California refinery. Amortization of refinery turnaround and other major maintenance costs will total approximately $35 million in 2004. We estimate our annual spending for refinery maintenance turnarounds to be as follows (in millions):


			2003
			Actual		2004		2005		2006		2007		2008

Refinery
	California		$	15	$	42	$	41	$	36	$	61	$	25
	Washington			2		6		9		2		22		1
	Alaska			8		—		—		10		—		—
	Hawaii			1		2		13		3		—		16
	North Dakota			19		1		2		1		—		—
	Utah			6		—		—		12		2		8

		Total	$	51	$	51	$	65	$	64	$	85	$	50

Long-Term Commitments


	Contractual Commitments

We have numerous contractual commitments for purchases of crude oil feedstocks, services arising in the ordinary course of business, debt service and pension obligation requirements and leases (see Notes F, N and P in our consolidated financial statements in Item 8). We also have contractual commitments for capital spending requirements related primarily to refinery improvements and environmental projects. The following table summarizes our estimated future commitments at December 31, 2003 (in millions):


Contractual Obligation		2004		2005		2006		2007		2008		Thereafter

Long-term debt obligations(1)		$	137	$	137	$	137	$	234	$	1,095	$	763
Capital lease obligations(2)			4		4		4		4		3		35
Operating lease obligations(3)			83		62		56		55		53		210
Estimated purchase obligations(4)			1,379		629		281		—		—		—
Other long-term obligations(5)			79		74		75		54		27		58
Estimated capital project spending commitments			22		—		—		—		—		—
Projected pension contributions(6)			37		32		29		29		28		—

	Total Contractual Obligations	$	1,741	$	938	$	582	$	376	$	1,206	$	1,066


(1)	Includes maturities of principal and estimated interest payments, excluding capital lease obligations. Interest on floating-rate debt was estimated using the actual weighted average interest rate at December 31, 2003. We expect amounts and timing to change as interest rates fluctuate and we voluntarily repay debt.

(2)	Includes amounts classified as interest.

(3)	Represents our future minimum lease commitments for operating leases, including marine charters.

(4)	Represents an estimate of our contractual purchase commitments for the supply of crude oil feedstocks, with remaining terms ranging up to three years. Prices under these term agreements fluctuate with market-responsive pricing provisions. Crude oil prices were estimated using actual market prices, ranging from $30 per barrel to $33 per barrel, as of December 31, 2003. We purchase additional crude oil feedstocks under short-term renewable contracts and in the spot market.

(5)	Represents future long-term commitments to purchase services, such as electricity, water, hydrogen, nitrogen, oxygen and sulfuric acid, and future annual lease commitments of $6 million through 2010 for a deactivated MTBE plant at our California refinery. We estimated our electricity commitments at our California refinery, which have variable pricing provisions, using estimated future market prices provided from a third-party market analysis. Actual purchases of electricity at our California refinery typically exceed the required minimum volumes.

(6)	Amounts are subject to change based on the performance of the assets in the plan, the discount rate used to determine the obligation, and other actuarial assumptions. See “Critical Accounting Policies” for further information related to our pension plan. We are unable to project benefit contributions beyond 2008.

We lease our corporate headquarters from a limited partnership in which we own a 50% limited interest. The initial term of the lease is through 2014 with two five-year renewal options. Our lease payments and operating costs paid to the partnership totaled $3.2 million, $3.1 million and $2.6 million in 2003, 2002 and 2001, respectively, and our future commitments are included in operating leases in the table above. We account for our interest in the partnership using the equity method of accounting. As such, we do not include the partnership’s assets, primarily land and buildings, totaling approximately $17 million and debt of approximately $13 million, in our consolidated financial statements.

Environmental

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


	Environmental Remediation Liabilities

We are currently involved in remedial responses and have incurred and expect to continue to incur cleanup expenditures associated with environmental matters at a number of sites, including certain of our own properties. At December 31, 2003, our accruals for environmental expenses totaled approximately $36 million. Our accruals for environmental expenses include retained liabilities for previously owned or operated properties, refining, pipeline, terminal and marine services operations and retail service stations. Based on currently available information, including the participation of other parties or former owners in remediation actions, we believe these accruals are adequate.

Soil and groundwater conditions at our California refinery may require substantial expenditures over time. In connection with our acquisition of the California refinery from Ultramar, Inc. in May 2002, Ultramar assigned certain of its rights and obligations that Ultramar had acquired from Tosco Corporation in August of 2000. Tosco assumed responsibility and indemnified us for up to $50 million for certain environmental liabilities arising from operations at the refinery prior to August of 2000 (“Pre-Acquisition Operations”). Based on existing information, we currently estimate that the environmental liabilities arising from Pre-Acquisition Operations are approximately $41 million, including soil and groundwater conditions at the refinery in connection with various projects and including those required by the California Regional Water Quality Control Board and other government agencies. If we incur remediation liabilities in excess of the environmental liabilities for Pre-Acquisition Operations indemnified by Tosco, we expect to be reimbursed for such excess liabilities under certain environmental insurance policies. The policies provide $140 million of coverage in excess of the $50 million indemnity covering environmental liabilities arising from Pre-Acquisition Operations. In December 2003, we initiated arbitration proceedings against Tosco seeking damages, indemnity and a declaration that Tosco is responsible for the environmental liabilities arising from Pre-Acquisition Operations at our California refinery.

In November 2003, we filed suit in Contra Costa County Superior Court against Tosco alleging that Tosco misrepresented, concealed and failed to disclose certain additional environmental conditions at our California refinery. On March 1, 2004, the court granted Tosco’s motion to compel arbitration of our claims for these certain additional environmental conditions. In the arbitration proceedings we initiated against Tosco in December 2003, we are also seeking a determination that Tosco is liable for investigation and remediation of these certain additional environmental conditions, the amount of which is unknown at this time and which may not be covered by the $50 million indemnity for environmental liabilities arising from Pre-Acquisition Operations. In response to our arbitration claims, Tosco filed counterclaims in the Contra Cost Superior Court action alleging that we are contractually responsible for certain environmental liabilities at our California refinery, including certain liabilities arising from Pre-Acquisition Operations. We intend to vigorously prosecute our claims against Tosco and to oppose Tosco’s claims against us, although we cannot provide assurance that we will prevail.


	Environmental Capital

EPA regulations related to the Clean Air Act require a reduction in the sulfur content in gasoline beginning January 1, 2004. To meet the revised gasoline standard, we currently estimate we will make capital improvements of approximately $38 million through 2008 and an additional $8 million beyond 2008. This will permit each of our six refineries to produce gasoline meeting the sulfur limits imposed by the EPA.

approximately $54 million in capital improvements through 2006, which does not include the potential impact of the recent EPA proposed rule for the sulfur content off off-road diesel fuel.

We expect to spend approximately $45 million in capital improvements through 2006 to comply with the Refinery MACT II regulations. These regulations require new emission controls at certain processing units at our refineries, including approximately $16 million at the North Dakota refinery and $29 million at the Washington refinery.

Estimated capital expenditures described above to comply with the Clean Air Act are summarized in the table below (in millions).


			2003												Beyond
			Actual		2004		2005		2006		2007		2008		2008

Lower Sulfur Gasoline
	Alaska		$	—	$	—	$	—	$	—	$	—	$	—	$	—
	Hawaii			—		—		—		—		—		—		—
	Washington			2		10		6		10		4		—		—
	North Dakota			—		—		—		8		—		—		—
	Utah			—		—		—		—		—		—		8
	California			—		—		—		—		—		—		—

		Total For Lower Sulfur Gasoline		2		10		6		18		4		—		8

Lower Sulfur Diesel
	Alaska			—		—		—		—		—		—		—
	Hawaii			—		—		—		—		—		—		—
	Washington			—		5		14		1		—		—		—
	North Dakota			—		2		4		—		—		—		—
	Utah			4		10		8		—		—		—		—
	California			—		3		7		—		—		—		—

		Total For Lower Sulfur Diesel		4		20		33		1		—		—		—

Refinery MACT II				3		24		19		2		—		—		—
California CARB III Gasoline				17		—		—		—		—		—		—

		Total	$	26	$	54	$	58	$	21	$	4	$	—	$	8

In connection with the 2001 acquisition of the North Dakota and Utah refineries, we assumed the sellers’ obligations and liabilities under a consent decree among the United States, BP Exploration and Oil Co., Amoco Oil Company and Atlantic Richfield Company. BP entered into this consent decree for both the North Dakota and Utah refineries for various alleged violations. As the owner of these refineries, we are required to address issues, including leak detection and repair, flaring protection and sulfur recovery unit optimization. We currently estimate that we will spend $7 million to comply with this consent decree in addition to estimated expenditures of $16 million in 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 the California refinery, subject to certain conditions, we assumed the seller’s obligations pursuant to its settlement efforts with the EPA concerning the Section 114 refinery enforcement initiative under the Clean Air Act, except for any potential monetary penalties, which the seller retains. We believe these obligations will not have a material impact on our financial position.

We will need to expend additional capital at the California refinery for reconfiguring and replacing above-ground storage tank systems and upgrading piping within the refinery. We estimate that we may spend up to $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, retail gasoline stations (operating and closed locations) and petroleum product terminals, and for compliance with the Clean Air Act and other federal, state and local requirements. We cannot currently determine the amounts of these future expenditures.

For further information on environmental matters and other contingencies, see Note P in our consolidated financial statements in Item 8.

Pension Funding

For all eligible employees, we provide a qualified defined benefit retirement plan with benefits based on years of service and compensation. During 2003, we terminated the funded executive security plan resulting in a write-off of unamortized prepaid pension costs of $7 million and a plan curtailment contribution of $1 million. Our long-term expected return on plan assets is 8.5%, and our pension plan assets experienced a return of $14 million in 2003 and a loss of $6 million in 2002. We contributed $21 million in 2003 and expect to contribute $37 million in 2004 and $32 million in 2005 to these plans. Our expected contributions are affected by returns on plan assets, employee demographics and other factors. See Note N in our consolidated financial statements in Item 8 for further discussion.

Claims Against Third-Parties

Beginning in the early 1980’s, Tesoro Hawaii Corporation, Tesoro Alaska Company and other fuel suppliers entered a series of long-term, fixed-price fuel supply contracts with the U.S. Defense Energy Support Center (“DESC”). Each of the contracts contained an adjustable price that permitted the DESC to adjust prices. However, the Federal Acquisition Regulations (“FAR”) limits how prices may be adjusted. Tesoro and many of the other suppliers in separate suits in the Court of Federal Claims currently are seeking relief from the DESC’s price adjustments. Tesoro and the other suppliers allege that the DESC’s price adjustments violated FAR by not adjusting the price of fuel based on changes to the suppliers’ established prices or costs, as FAR requires. Tesoro and the other suppliers seek recovery of over $2.5 billion in underpayment for fuel. Tesoro’s share of the underpayment currently totals approximately $165 million although approximately $20 million of this amount is still pending at the administrative claims level. The DESC responded to Tesoro’s and the other suppliers’ claims by moving for partial summary judgment. In response, Tesoro and the other suppliers cross-moved for partial summary judgment. The Court of Federal Claims granted partial summary judgment for Tesoro, held that the DESC’s fuel prices were illegal, and rejected the DESC’s assertion that Tesoro waived its right to a remedy by entering the contracts. However, some of the other judges in the same court ruled on the cross-motions for other suppliers in conflict with the holding for Tesoro. As a result, Tesoro petitioned the Court of Appeals for the Federal Circuit to review its claims. Tesoro is seeking the Court of Appeals validation that the price adjustments were illegal and Tesoro did not waive its right to sue when it entered the contracts. Tesoro expects the appeal process to take approximately nine months and for the court to issue its decision by the end of 2004, but we cannot predict the outcome of our claims against the DESC.

In December of 1996, Tesoro Alaska Company filed a protest of the intrastate rates charged for the transportation of its crude oil through the Trans Alaska Pipeline Company. Tesoro’s protest asserted that the TAPS intrastate rates were excessive and should be reduced. The Regulatory Commission of Alaska (“RCA”) opened RCA Docket No. P-97-4 to consider Tesoro’s protest of the intrastate rates for the years 1997 through 2000. Through RCA’s Order P-97-4(151), the RCA set just and reasonable final rates for the years 1997 through 2000, and held that Tesoro is entitled to receive approximately $41 million in refunds, including interest calculated as of December 31, 2003. RCA Order P-97-4(151) is currently on appeal, and we cannot give any assurances of when or whether we will prevail in the appeal.

ACCOUNTING STANDARDS

Critical Accounting Policies

Our accounting policies are described in Note A in our consolidated financial statements in Item 8. We prepare our consolidated financial statements in conformity with U.S. GAAP, which require us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the year. Actual results could differ from those estimates. We consider the following policies to be the most critical in understanding the judgments that are involved in preparing our financial statements and the uncertainties that could impact our financial condition and results of operations.

Receivables — Our trade receivables are stated at their invoiced amounts, less an allowance for potentially uncollectible amounts. We monitor the credit and payment experience of our customers and manage our loss exposure through our credit policies and procedures. The estimated allowance for doubtful accounts is based on our general loss experience and identified loss exposures on individual accounts. Although actual losses have not been significant to our results of operations, economic conditions and the related credit environment could change, and actual losses could vary from estimates.

Inventory — Our inventories are stated at the lower of cost or market. We use the LIFO method to determine the cost of our crude oil and refined product inventories. The LIFO cost of these inventories is usually much less than current market value, however a significant decline in market values of petroleum products could impair the carrying values of these inventories. We had 18.8 million barrels of crude oil and refined product inventories at December 31, 2003 with an average cost of approximately $24 per barrel. If refined product prices decline below the average cost, then we would be required to write down the value of our inventories in future periods.

Property, Plant and Equipment — We calculate depreciation and amortization based on estimated useful lives and salvage values of our assets. When assets are placed into service, we make estimates with respect to their useful lives that we believe are reasonable. However, factors such as maintenance levels, economic conditions impacting the demand for these assets, and regulation or environmental matters could cause us to change our estimates, thus impacting the future calculation of depreciation and amortization. We evaluate property, plant and equipment for potential impairment by identifying whether indicators of impairment exist and, if so, assessing whether the assets are recoverable from estimated future undiscounted cash flows. The actual amount of impairment loss, if any, to be recorded is equal to the amount by which the asset’s carrying value exceeds its fair value. Estimates of future undiscounted cash flows and fair value of assets require subjective assumptions with regard to future operating results, and actual results could differ from those estimates.

Goodwill and Acquired Intangibles — As of December 31, 2003, we had $89 million of goodwill included in Other Noncurrent Assets. Goodwill is not amortized but is tested for impairment annually or more frequently when indicators of impairment exist. We review the recorded value of our goodwill for impairment during the fourth quarter of each year, or sooner if events or changes in circumstances indicate the carrying amount may exceed fair value. Recoverability is determined by comparing the estimated fair value of a reporting unit to the carrying value, including the related goodwill, of that reporting unit. We use the present value of expected net cash flows to determine the estimated fair value of our reporting units. In 2003, we wrote off the Marine Services goodwill of $2.4 million in connection with the sale of that operation. In connection with the 2002 annual impairment review, we recognized a loss of $1.2 million to reduce the carrying value of goodwill in our retail segment. The impairment test is susceptible to change from period to period as it requires us to make cash flow assumptions including, among other things, future margins, volumes, operating costs and discount rates. Our assumptions regarding future margins and volumes require significant judgment as actual margins and volumes have fluctuated in the past and will likely continue to do so. For the impairment test performed during the fourth quarter of 2003, we assumed that future margins in our geographic areas will be at our five-year average levels. Changes in market conditions could result in impairment charges in the future.

As of December 31, 2003, we included $139 million of acquired intangible assets in Other Noncurrent Assets. The valuation of these intangible assets required us to use our judgment, including estimates with respect to their useful lives. We review acquired intangible assets for impairment whenever events or changes in circumstances indicate that the carrying amount of the assets may not be recoverable. The assessment of impairment is based on the estimated undiscounted future cash flows from operating activities, compared with the carrying value of the assets. The actual amount of impairment loss, if any, to be recorded is equal to the amount by which the asset’s carrying value exceeds its fair value. Estimates of future undiscounted cash flows and fair values of assets require subjective assumptions with regard to future operating results, and actual results could differ from those estimates.

Deferred Maintenance Costs — We record the cost of major scheduled refinery turnarounds, long-lived catalysts used in refinery process units, and periodic maintenance on ships, tugs and barges (“drydocking”) as deferred charges in Other Noncurrent Assets. We amortize these deferred charges over the expected periods of benefit, generally ranging from two to four years. The American Institute of CPAs approved for issuance a Statement of Position (“SOP”), “Accounting for Certain Costs and Activities Related to Property, Plant and Equipment,” subject to clearance by the FASB, which would require these major maintenance activities to be expensed as costs are incurred. This SOP may also require certain modifications in our accounting for the capitalization, depreciation and retirements of property, plant and equipment. The SOP, which is expected to be issued in its final form in the second quarter of 2004, would become effective January 1, 2005. If this proposed SOP is adopted in its current form, we would be required to write off the balance of our deferred maintenance costs which totaled $83 million at December 31, 2003 and expense future costs as incurred (see “Refinery Turnaround and Other Major Maintenance” on page 40).

Contingencies — We record an estimated loss from a contingency when information available before issuing our financial statements indicates that (a) it is probable that an asset has been impaired or a liability has been incurred at the date of the financial statements and (b) the amount of the loss can be reasonably estimated. We are required to use our judgment to account for contingencies such as environmental, legal and income tax matters. While we believe that our accruals for these matters are adequate, the actual loss may differ from our estimated loss, and we would record the necessary adjustments in future periods. We do not record the benefits of contingent recoveries or gains until the amount is determinable and recovery is assured.

Income Taxes — As part of the process of preparing consolidated financial statements, we must assess the likelihood that our deferred income tax assets will be recovered through future taxable income. To the extent we believe that recovery is not likely, a valuation allowance must be established. Significant management judgment is required in determining any valuation allowance recorded against net deferred income tax assets. Based on our estimates of taxable income in each jurisdiction in which we operate and the period over which deferred income tax assets will be recoverable, we have not recorded a valuation allowance as of December 31, 2003. In the event that actual results differ from these estimates or we make adjustments to these estimates in future periods, we may need to establish a valuation allowance. As of December 31, 2003, deferred tax assets included net operating loss carryforwards and alternative minimum tax credits totaling $104 million.

Pension and Other Postretirement Benefits — Accounting for pensions and other postretirement benefits involves several assumptions and estimates including discount rates, health care cost trends, inflation, retirement rates and mortality rates. We must also assume a rate of return on funded pension plan assets in order to estimate our obligations under our defined benefit plans. Due to the nature of these calculations, we engage an actuarial firm to assist with the determination of these estimates and the calculation of certain employee benefit expenses. While we believe that the assumptions used are appropriate, significant differences in the actual experience or significant changes in assumptions would affect pension and other postretirement

benefits costs and obligations. A one-percentage-point change in the expected return on plan assets and discount rate for the pension plans would have had the following effects in 2003 (in millions):


		1-Percentage-			1-Percentage-
		Point Increase			Point Decrease

Expected Rate of Return
	Effect on net periodic pension expense	$	(0.7	)	$	0.7
Discount Rate
	Effect on net periodic pension expense	$	(1.9	)	$	2.1
	Effect on projected benefit obligation	$	(15.7	)	$	17.3

See Note N in our consolidated financial statements in Item 8 for more information regarding costs and assumptions.

New Accounting Standards and Disclosures

See Note A in our consolidated financial statements in Item 8.

FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K includes forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. These statements are included throughout this Form 10-K and relate to, among other things, expectations regarding refinery throughput, refining margins, revenues, cash flows, capital expenditures, turnaround expenses, debt repayments and other financial items. These statements also relate to our business strategy, goals and expectations concerning our market position, future operations, margins, profitability and capital resources. We have used the words “anticipate”, “believe”, “could”, “estimate”, “expect”, “intend”, “may”, “plan”, “predict”, “project”, “will” and similar terms and phrases to identify forward-looking statements in this Annual Report on Form 10-K.

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

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


	•	changes in general economic conditions;

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

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

	•	changes in our cash flow from operations;

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

	•	changes in fuel and utility costs for our facilities;

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

	•	actions of customers and competitors;

	•	changes in capital requirements or in execution of planned capital projects;

	•	availability of trade credit;

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


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

	•	political developments in foreign countries;

	•	changes in our inventory levels and carrying costs;

	•	seasonal variations in demand for refined products;

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

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

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

	•	earthquakes or other natural disasters affecting operations.

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


ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Changes in commodity prices and interest rates are our primary sources of market risk. We have a risk management committee responsible for managing risks arising from transactions and commitments related to the sale and purchase of energy commodities.

Commodity Price Risks

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

The prices at which we sell our refined products are influenced by the commodity price of crude oil. Generally, an increase or decrease in the price of crude oil results in a corresponding increase or decrease in the price of gasoline and other refined products. The timing of the relative movement of the prices, however, can impact profit margins which could significantly affect our earnings and cash flows. In addition, the majority of our crude oil supply contracts are short-term in nature with market-responsive pricing provisions. Our financial results can be affected significantly by price level changes during the period between purchasing refinery feedstocks and selling the manufactured refined products from such feedstocks. We also purchase refined products manufactured by others for resale to our customers. Our financial results can be affected significantly by price level changes during the periods between purchasing and selling such products. Assuming all other factors remained constant, a $1.00 per barrel change in average gross refining margins, based on our 2003 average throughput of 488 thousand bpd, would change annual pretax segment operating income and cash flows from operations by approximately $178 million.

We maintain inventories of crude oil, intermediate products and refined products, the values of which are subject to fluctuations in market prices. Our inventories of refinery feedstocks and refined products totaled 18.8 million barrels and 17.8 million barrels at December 31, 2003 and 2002, respectively. The average cost of our refinery feedstocks and refined products at December 31, 2003 was approximately $24 per barrel on a LIFO basis, compared to market prices of approximately $36 per barrel. If market prices for refined products decline to a level below the average cost of these inventories, we would be required to write down the carrying value of our inventory.

We periodically enter into derivative type arrangements on a limited basis as part of our programs to acquire refinery feedstocks at reasonable costs and to manage margins on certain refined product sales. Gains and losses on these transactions are included in costs of sales. We also engage in limited non-hedging activities which are marked to market so that changes in the fair value of the derivative instruments are recognized in earnings. At December 31, 2003, we had net open futures positions of 2.9 million barrels of crude oil and 137,000 barrels of heating oil, which expire during the first half of 2004. At December 31, 2003, we also had open refined product price swap positions of 125,000 barrels, which expire during the first quarter of 2004. We recorded the fair values of these positions, which resulted in a mark-to-market loss of $0.9 million in 2003. We believe that any potential impact from these activities would not result in a material adverse effect on our results of operations, financial position or cash flows.

Interest Rate Risk

At December 31, 2003, we had $199 million of floating-rate debt under the senior secured term loans and $1.4 billion of fixed-rate debt. The weighted average interest rate on the floating-rate debt was 6.67% at December 31, 2003. The impact on annual cash flow of a 10% change in the floating-rate for our senior secured term loans (67 basis points) would be approximately $1.3 million.

The fair market values of our senior secured loans, senior secured notes and senior subordinated notes are based on transactions and bid quotes. We assume that the fair market value of our junior subordinated notes and capital lease obligations approximate our carrying value. The fair market values of our fixed and variable rate debt were approximately $94 million and $6 million, respectively, more than our carrying values at December 31, 2003.


ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEPENDENT AUDITORS’ REPORT

Board of Directors and Stockholders

Tesoro Petroleum Corporation

We have audited the accompanying consolidated balance sheets of Tesoro Petroleum Corporation and subsidiaries (the “Company”) as of December 31, 2003 and 2002, and the related statements of consolidated operations, stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2003. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Tesoro Petroleum Corporation and subsidiaries as of December 31, 2003 and 2002, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2003 in conformity with accounting principles generally accepted in the United States of America.

/s/ DELOITTE & TOUCHE LLP

San Antonio, Texas

March 10, 2004

TESORO PETROLEUM CORPORATION

STATEMENTS OF CONSOLIDATED OPERATIONS

(In millions, except per share amounts)



		Years Ended December 31,

		2003			2002			2001

REVENUES		$	8,845.7		$	7,119.3		$	5,181.7
COSTS AND EXPENSES:
	Costs of sales and operating expenses		8,207.8			6,865.7			4,797.1
	Selling, general and administrative expenses		138.0			133.2			104.2
	Depreciation and amortization		148.2			130.7			79.9
	Loss on asset sales and impairments		16.9			8.4			1.8

OPERATING INCOME (LOSS)			334.8			(18.7	)		198.7
Interest and financing costs, net			(211.7	)		(162.6	)		(51.8	)

EARNINGS (LOSS) BEFORE INCOME TAXES			123.1			(181.3	)		146.9
Income tax provision (benefit)			47.0			(64.3	)		58.9

NET EARNINGS (LOSS)			76.1			(117.0	)		88.0
Preferred dividend requirements			—			—			6.0

NET EARNINGS (LOSS) APPLICABLE TO COMMON STOCK		$	76.1		$	(117.0	)	$	82.0

NET EARNINGS (LOSS) PER SHARE
	Basic	$	1.18		$	(1.93	)	$	2.26
	Diluted	$	1.17		$	(1.93	)	$	2.10
WEIGHTED AVERAGE COMMON SHARES
	Basic		64.6			60.5			36.2
	Diluted		65.1			60.5			41.9

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

TESORO PETROLEUM CORPORATION

CONSOLIDATED BALANCE SHEETS

(Dollars in millions, except per share amounts)



				December 31,

				2003			2002

ASSETS
CURRENT ASSETS
	Cash and cash equivalents			$	77.2		$	109.8
	Receivables, less allowance for doubtful accounts				411.0			412.2
	Income taxes receivable				3.6			41.9
	Inventories				487.3			461.5
	Prepayments and other				44.9			28.8

		Total Current Assets			1,024.0			1,054.2

PROPERTY, PLANT AND EQUIPMENT
	Refining				2,451.1			2,363.1
	Retail				231.4			239.0
	Corporate and other				58.8			111.0

					2,741.3			2,713.1
	Less accumulated depreciation and amortization				(489.8	)		(409.7	)

		Net Property, Plant and Equipment			2,251.5			2,303.4

OTHER NONCURRENT ASSETS
	Goodwill				88.7			91.1
	Acquired intangibles, net				138.6			150.6
	Other, net				158.5			159.5

		Total Other Noncurrent Assets			385.8			401.2

			Total Assets	$	3,661.3		$	3,758.8


LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
	Accounts payable			$	431.8		$	338.6
	Accrued liabilities				251.7			199.7
	Current maturities of debt				3.5			70.0

		Total Current Liabilities			687.0			608.3

DEFERRED INCOME TAXES					179.2			128.7
OTHER LIABILITIES					224.4			227.5
DEBT					1,605.3			1,906.7
COMMITMENTS AND CONTINGENCIES (Note P)
STOCKHOLDERS’ EQUITY
	Common stock, par value $0.16 2/3; authorized 100,000,000 shares; 66,458,008 shares issued (66,379,928 in 2002)				11.0			11.0
	Additional paid-in capital				690.6			689.8
	Retained earnings				281.0			204.9
	Treasury stock, 1,701,768 common shares (1,771,695 in 2002), at cost				(17.2	)		(18.1	)

		Total Stockholders’ Equity			965.4			887.6

			Total Liabilities and Stockholders’ Equity	$	3,661.3		$	3,758.8

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

TESORO PETROLEUM CORPORATION

STATEMENTS OF CONSOLIDATED STOCKHOLDERS’ EQUITY

(In millions)



		Preferred Stock						Common Stock				Additional					Treasury Stock
												Paid-In		Retained
		Shares			Amount			Shares		Amount		Capital		Earnings			Shares			Amount

AT JANUARY 1, 2001			0.1		$	165.0			32.8	$	5.4	$	280.0	$	239.9			(1.9	)	$	(20.4	)
	Net earnings		—			—			—		—		—		88.0			—			—
	Preferred dividend requirements		—			—			—		—		—		(6.0	)		—			—
	Preferred stock conversion		(0.1	)		(165.0	)		10.3		1.7		163.3		—			—			—
	Shares repurchased and shares issued for stock options and benefit plans		—			—			0.3		0.1		5.1		—			(0.1	)		(0.1	)

AT DECEMBER 31, 2001			—			—			43.4		7.2		448.4		321.9			(2.0	)		(20.5	)
	Net loss		—			—			—		—		—		(117.0	)		—			—
	Issuance of common stock		—			—			23.0		3.8		241.3		—			—			—
	Shares issued for stock options and benefit plans		—			—			—		—		0.1		—			0.2			2.4

AT DECEMBER 31, 2002			—			—			66.4		11.0		689.8		204.9			(1.8	)		(18.1	)
	Net earnings		—			—			—		—		—		76.1			—			—
	Shares issued for stock options and benefit plans		—			—			0.1		—		0.8		—			0.1			0.9

AT DECEMBER 31, 2003			—		$	—			66.5	$	11.0	$	690.6	$	281.0			(1.7	)	$	(17.2	)

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

TESORO PETROLEUM CORPORATION

STATEMENTS OF CONSOLIDATED CASH FLOWS

(In millions)



				Years Ended December 31,

				2003			2002			2001

CASH FLOWS FROM (USED IN) OPERATING ACTIVITIES
	Net earnings (loss)			$	76.1		$	(117.0	)	$	88.0
	Adjustments to reconcile net earnings (loss) to net from cash operating activities:
	Depreciation and amortization				148.2			130.7			79.9
	Amortization of debt issuance costs and discounts				19.3			14.2			8.3
	Write-off of unamortized debt issuance costs				36.2			12.6			0.6
	Loss on asset sales and impairments				16.9			8.4			1.8
	Deferred income taxes				55.5			3.3			35.5
	Other changes in non-current assets and liabilities				(42.6	)		(38.0	)		(4.4	)
	Changes in current assets and current liabilities:
		Receivables			1.2			(49.8	)		(32.6	)
		Income taxes receivable			38.4			(19.4	)		(22.2	)
		Inventories			(26.0	)		115.9			(29.1	)
		Prepayments and other			(16.3	)		(20.7	)		1.2
		Accounts payable and accrued liabilities			140.4			17.6			87.4

			Net cash from operating activities		447.3			57.8			214.4

CASH FLOWS FROM (USED IN) INVESTING ACTIVITIES
	Capital expenditures				(101.1	)		(203.5	)		(209.5	)
	Acquisitions				—			(931.5	)		(783.4	)
	Proceeds from asset sales				31.2			207.4			20.7
	Other				(0.1	)		(13.1	)		(4.5	)

			Net cash used in investing activities		(70.0	)		(940.7	)		(976.7	)

CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES
	Proceeds from debt offerings, net of issuance costs of $11.2, $9.4 and $5.1				360.0			440.6			209.9
	Borrowings under term loans				350.0			425.0			625.0
	Proceeds from Common Stock offering, net of issuance costs of $13.7				—			245.1			—
	Debt refinanced				(721.2	)		—			—
	Repayments of debt				(376.7	)		(133.0	)		(1.1	)
	Payment of dividends on Preferred Stock				—			—			(9.0	)
	Repurchases of Common Stock				—			—			(3.5	)
	Financing costs and other				(22.0	)		(36.9	)		(21.2	)

			Net cash from (used in) financing activities		(409.9	)		940.8			800.1

INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS					(32.6	)		57.9			37.8
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR					109.8			51.9			14.1

CASH AND CASH EQUIVALENTS, END OF YEAR				$	77.2		$	109.8		$	51.9

SUPPLEMENTAL CASH FLOW DISCLOSURES
	Interest paid, net of capitalized interest			$	156.7		$	114.3		$	40.2
	Income taxes paid (refunded)			$	(50.7	)	$	(48.0	)	$	47.0

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

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE A — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES


	Description and Nature of Business

Tesoro Petroleum Corporation (“Tesoro”) was incorporated in Delaware in 1968 and is an independent refiner and marketer of petroleum products. We own and operate six petroleum refineries in the western and mid-continental United States with a combined rated crude oil throughput capacity of 558,000 barrels per day (“bpd”), and we sell refined products to a wide variety of customers, primarily in the western and mid-continental United States. We market products to wholesale and retail customers, as well as commercial end-users. Our retail business includes a network of 557 branded retail stations operated by Tesoro or independent dealers.

Tesoro’s earnings, cash flows from operations and liquidity depend upon many factors, including producing and selling refined products at margins above fixed and variable expenses. The prices of crude oil and refined products have fluctuated substantially in our markets. Our operating results have been significantly influenced by the timing of changes in crude oil costs and how quickly refined product prices adjust to reflect these changes. These price fluctuations depend on numerous factors beyond our control, including the demand for crude oil, gasoline and other refined products, which is subject to, among other things, changes in the economy and the level of foreign and domestic production of crude oil and refined products, worldwide political conditions, threatened or actual terrorist incidents or acts of war, availability of crude oil and refined product imports, the infrastructure to transport crude oil and refined products, weather conditions, earthquakes and other natural disasters, seasonal variations, government regulations and local factors, including market conditions and the level of operations of other refineries in our markets. As a result of these factors, margin fluctuations during any reporting period can have a significant impact on our results of operations, cash flows, liquidity and financial position. During 2002, the refining industry in our market areas experienced the lowest refined product margins since 1998, and we experienced net losses in each of the 2002 quarters, resulting from weak industry margins and additional interest and financing costs related to our acquisitions of our California refinery in May 2002 and our two Mid-Continent refineries in September 2001. During 2003, improved refined product margins resulted in net earnings for the year and increased cash flows from operating activities.


	Principles of Consolidation and Basis of Presentation

The accompanying consolidated financial statements include the accounts of Tesoro and its subsidiaries. All intercompany accounts and transactions have been eliminated. Investments in entities in which we have the ability to exercise significant influence, but not control, are accounted for using the equity method, while other investments are carried at cost. These investments are not material, either individually or in the aggregate, to Tesoro’s financial position, results of operations or cash flows. See Note P for information related to a 50% limited partnership interest, which we account for using the equity method.

We have reclassified certain previously reported amounts in our statements of consolidated cash flows to conform to the current presentation. Separate financial statements of Tesoro’s subsidiary guarantors are not included because these subsidiary guarantors are jointly and severally liable for Tesoro’s outstanding senior secured term loans, senior secured notes and senior subordinated notes. Further, net assets, results of operations and equity of the subsidiary guarantors are substantially equivalent to Tesoro’s consolidated net assets, results of operations and equity.


	Use of Estimates

We prepare Tesoro’s consolidated financial statements in conformity with accounting principles generally accepted in the United States of America (“U.S. GAAP”), which requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

during the year. We review our estimates on an ongoing basis, based on currently available information. Changes in facts and circumstances may result in revised estimates and actual results could differ from those estimates.


	Cash and Cash Equivalents

We consider all highly-liquid instruments, such as temporary cash investments, with a maturity of three months or less at the time of purchase to be cash equivalents. Cash equivalents are stated at cost, which approximates market value. We invest our cash in conservative, highly-rated instruments in financial institutions with strong credit standings.


	Financial Instruments

The carrying amounts of financial instruments, including cash and cash equivalents, receivables, accounts payable and certain accrued liabilities, approximate fair value because of the short maturities of these instruments. The carrying amounts of Tesoro’s debt and other obligations may vary from our estimates of the fair value of such items. We estimate that the fair market value of Tesoro’s fixed-rate debt at December 31, 2003, was approximately $94 million more than its total book value of $1.4 billion. We estimate that the fair market value of the Company’s variable-rate debt at December 31, 2003, was approximately $6 million more than its book value of $199 million.


	Inventories

Inventories are stated at the lower of cost or market. We use the last-in, first-out (“LIFO”) as the primary method to determine the cost of crude oil and refined product inventories in our refining and retail segments. We determine the carrying value of inventories of oxygenates and by-products using the first-in, first-out (“FIFO”) cost method or net realizable market value, whichever is less. We value merchandise and materials and supplies at average cost, not in excess of market value.


	Property, Plant and Equipment

We capitalize the cost of additions, major improvements and modifications to property, plant and equipment. We compute depreciation of property, plant and equipment on the straight-line method, based on the estimated useful life of each asset. The weighted average lives range from 26 to 28 years for refineries, 8 to 16 years for terminals, 13 to 16 years for retail stations, 5 to 29 years for transportation assets and 4 to 14 years for corporate assets. We record property under capital leases at the present value of minimum lease payments using Tesoro’s incremental borrowing rate. We amortize property under capital leases over the term of each lease.

We capitalize interest as part of the cost of major projects during extended construction periods. Tesoro incurred total interest and financing costs of $212.6 million, $168.6 million and $57.9 million in 2003, 2002 and 2001, respectively, of which $2.7 million, $2.5 million and $5.1 million was capitalized during 2003, 2002 and 2001, respectively.


	Asset Retirement Obligations

We accrue for asset retirement obligations, primarily for assets on leased sites, in the period in which the obligations are incurred. We accrue these costs at estimated fair value. When the related liability is initially recorded, we capitalize the cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted to its settlement value and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, we recognize a gain or loss for any difference between the settlement amount and the liability recorded. We have identified asset retirement obligations, including

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

obligations imposed by certain state laws pertaining to closure and/or removal of storage tanks, and contractual removal obligations included in certain lease and right-of-way agreements associated with our retail, pipeline and terminal operations. We have estimated the fair value of our asset retirement obligations, based in part on the terms of the agreements and the probabilities associated with the eventual sale or other disposition of these assets. We cannot currently make reasonable estimates of the fair values of some retirement obligations, principally those associated with refineries, certain pipeline rights-of-way and certain terminals, because the related assets have indeterminate useful lives which preclude development of assumptions about the potential timing of settlement dates. Such obligations will be recognized in the period in which sufficient information exists to estimate a range of potential settlement dates.


	Environmental Expenditures

We capitalize environmental expenditures that extend the life or increase the capacity of facilities, as well as expenditures that mitigate or prevent environmental contamination that is yet to occur. We charge to expense costs that relate to an existing condition caused by past operations and that do not contribute to current or future revenue generation. We record liabilities when environmental assessments and/or remedial efforts are probable and can be reasonably estimated. Cost estimates are based on the expected timing and the extent of remedial actions required by applicable governing agencies, experience gained from similar sites on which environmental assessments or remediation have been completed, and the amount of our anticipated liability considering the proportional liability and financial abilities of other responsible parties. Generally, the timing of these accruals coincides with the completion of a feasibility study or our commitment to a formal plan of action. Estimated liabilities are not discounted to present value.


	Goodwill and Acquired Intangibles

Goodwill represents the excess of cost (purchase price) over the fair value of net assets acquired. Under Statement of Financial Accounting Standards (“SFAS”) No. 142, “Goodwill and Other Intangible Assets,” we ceased amortizing goodwill on January 1, 2002. Goodwill amortization amounted to $2.7 million in 2001 and is included in depreciation and amortization in our statements of consolidated operations. The following table reflects reported net earnings and earnings per share in 2001, adjusted to exclude goodwill amortization (in millions except per share amounts):


		2001

Reported net earnings		$	88.0
Goodwill amortization, net of income taxes			2.4

Adjusted net earnings		$	90.4

Basic earnings per share:
	Reported basic earnings per share	$	2.26
	Goodwill amortization, net of income taxes		0.07

	Adjusted basic earnings per share	$	2.33

Diluted earnings per share:
	Reported diluted earnings per share	$	2.10
	Goodwill amortization, net of income taxes		0.06

	Adjusted diluted earnings per share	$	2.16

Acquired intangibles consist primarily of air emissions credits, permits and plans, and customer agreements and contracts, which we record at fair value as of the date acquired. We compute amortization on

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

a straight-line basis over estimated useful lives of 3 to 28 years, and we include amortization of acquired intangibles in depreciation and amortization expense.


	Other Assets

We periodically shut down refinery processing units for major scheduled maintenance, or turnarounds. Certain catalysts are used in refinery process units for periods exceeding one year. Also, we drydock ships, tugs and barges for periodic maintenance. We defer turnaround, catalyst and drydocking costs and amortize the costs on a straight-line basis over the expected periods of benefit, generally ranging from 23 to 48 months. Amortization of such deferred costs, which we include in depreciation and amortization expense, amounted to $30.9 million, $27.2 million and $22.5 million in 2003, 2002 and 2001, respectively. In 2003, the American Institute of CPA’s approved for issuance a Statement of Position (“SOP”) subject to clearance by the Financial Accounting Standards Board (“FASB”). The SOP, as written, would require all deferred maintenance costs to be expensed as incurred, beginning January 1, 2005. See New Accounting Standards and Disclosures below for further information.

We defer debt issuance costs related to our credit agreement and senior notes and amortize the costs over the estimated terms of each instrument. We include the amortization in interest and financing costs in our statements of consolidated operations. We evaluate the carrying value of debt issuance costs when modifications are made to the related debt instruments (See Note F).


	Impairment of Long-Lived Assets

We review property, plant and equipment and other long-lived assets, including acquired intangible assets for impairment whenever events or changes in business circumstances indicate the carrying values of the assets may not be recoverable. We would record impairment losses if the undiscounted cash flows estimated to be generated by those assets were less than the carrying amount of those assets. Factors that would indicate potential impairment include, but are not limited to, significant decreases in the market value of a long-lived asset, a significant change in the long-lived asset’s physical condition, and operating or cash flow losses associated with the use of the long-lived asset. We review goodwill balances for impairment annually or more frequently, if events or changes in business circumstances indicate the carrying values of the assets may not be recoverable.


	Revenue Recognition

We recognize revenues from product sales upon delivery to customers and when all significant obligations have been satisfied. We include certain crude oil and product purchases and resales used for trading purposes in revenues on a net basis. We include transportation fees charged to customers in revenues, and we include the related costs in costs of sales in our statements of consolidated operations. In our retail segment, revenues and costs of sales include federal excise and state motor fuel taxes collected from customers and remitted to governmental agencies. These taxes, primarily related to sales of gasoline and diesel fuel, totaled $128 million, $167 million and $81 million in 2003, 2002 and 2001, respectively. In our refining segment, excise taxes on sales are not included in revenues and costs of sales.


	Income Taxes

We record deferred tax assets and liabilities for future income tax consequences that are attributable to differences between financial statement carrying amounts of assets and liabilities and their income tax bases. We base the measurement of deferred tax assets and liabilities on enacted tax rates that we expect will apply to taxable income in the year when we expect to settle or recover those temporary differences. We recognize the effect on deferred tax assets and liabilities of any change in income tax rates in the period that includes the

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

enactment date. We provide a valuation allowance for deferred tax assets if it is more likely than not that those items will either expire before we are able to realize their benefit or their future deductibility is uncertain.


	Stock-Based Compensation

We have accounted for stock-based compensation using the intrinsic value method prescribed in Accounting Principles Board (“APB”) Opinion No. 25, “Accounting for Stock Issued to Employees,” and related interpretations. Accordingly, we have measured compensation cost for stock options as the excess, if any, of the quoted market price of Tesoro’s common stock at the date of grant over the amount an employee must pay to acquire the stock. Effective January 1, 2004, we adopted the preferable fair value method of accounting for stock-based compensation, as prescribed in SFAS No. 123, “Accounting for Stock-Based Compensation.” We selected the “modified prospective method” of adoption described in SFAS No. 148, “Accounting for Stock-based Compensation — Transition and Disclosure.” We will recognize the same compensation cost in 2004 that we would have recognized had the fair value method of SFAS No. 123 been applied from its original effective date. The effect of adopting this statement will result in an aftertax charge of approximately $3 million in 2004 based on current stock options outstanding.

The following table represents the effect on net earnings and earnings per share as if we had applied the fair value method and recognition provisions of SFAS No. 123 for previous years (in millions except per share amounts):


		2003			2002			2002

Reported net earnings (loss)		$	76.1		$	(117.0	)	$	88.0
Deduct total stock-based employee compensation expense determined under fair value based methods for all awards, net of related tax effects			(3.2	)		(3.8	)		(2.7	)

Pro forma net earnings (loss)		$	72.9		$	(120.8	)	$	85.3

Net earnings (loss) per share:
	Basic, as reported	$	1.18		$	(1.93	)	$	2.26
	Basic, pro forma	$	1.13		$	(2.00	)	$	2.19
	Diluted, as reported	$	1.17		$	(1.93	)	$	2.10
	Diluted, pro forma	$	1.12		$	(2.00	)	$	2.04

For purposes of the pro forma disclosures above, we amortized the estimated fair value of stock options granted over the vesting period using the straight-line method. We estimated the fair value of each option on the date of grant using the Black-Scholes option-pricing model with the following weighted-average assumptions for 2003, 2002 and 2001, respectively: expected volatility of 118%, 88% and 43%; risk free interest rates of 3.4%, 4.2% and 4.9%; expected lives of seven years; and no dividend yields. The estimated average fair value per share of options granted during 2003, 2002 and 2001 were $6.73, $4.35 and $6.72, respectively. See Note O for further information on Tesoro’s stock-based employee compensation plans.


	Derivative Instruments

We account for derivative instruments in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended and interpreted. We believe that substantially all of our supply and marketing agreements and other commercial contracts are normal purchases and sales and that pricing provisions in these agreements are not embedded derivatives. However, Tesoro periodically enters into derivatives arrangements, on a limited basis, as part of its programs to acquire refinery feedstocks at reasonable costs and to manage margins on certain refined product sales. We mark to market these non-hedging derivatives and recognize the changes in their fair values in earnings, and we include the carrying amounts of

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

the derivatives in other current assets or accrued liabilities in the consolidated balance sheets. At December 31, 2003, Tesoro had net open future positions for 2.9 million barrels of crude oil and 137,000 barrels of heating oil that will expire during the first half of 2004. At December 31, 2003, Tesoro also had open refined product price swap positions of 125,000 barrels which expire during the first quarter of 2004. The fair value of these positions resulted in a mark-to-market pretax loss of $0.9 million during 2003. We did not have any derivative instruments that we designated and accounted for as hedges during 2003, 2002 and 2001.


	New Accounting Standards and Disclosures


	SFAS No. 143

On January 1, 2003, we adopted SFAS No. 143, “Accounting for Asset Retirement Obligations,” which addresses financial accounting and reporting for legal obligations associated with the retirement of long-lived assets. We have identified asset retirement obligations that are within the scope of the standard, including obligations imposed by certain state laws pertaining to closure and/or removal of storage tanks, and contractual removal obligations included in certain lease and right-of-way agreements associated with our retail, pipeline and terminal operations. We have estimated the fair value of our asset retirement obligations, based in part on the terms of the agreements and the probabilities associated with the eventual sale or other disposition of these assets. We cannot currently make reasonable estimates of the fair values of certain retirement obligations, principally those associated with refineries, pipeline rights-of-way and certain products terminals, because the related assets have indeterminate useful lives which preclude our development of assumptions about the potential timing of settlement dates. We will recognize such obligations in the periods in which sufficient information exists for us to estimate a range of potential settlement dates. We accrued the present value of obligations to the extent that settlement dates could be estimated, primarily for assets on leased sites. The adoption of this accounting standard at January 1, 2003, did not have a material effect on Tesoro’s consolidated financial position or results of operations, and similarly, would not have had a material effect if the standard had been adopted in previous years.


	SFAS No. 149

In April 2003, the FASB issued SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities, which amends and clarifies financial accounting and reporting for derivative instruments and hedging activities. SFAS No. 149 is effective for contracts entered into or modified after June 30, 2003. We adopted this statement, effective July 1, 2003, and our implementation of this new standard did not have a material effect on Tesoro’s consolidated financial position or results of operations.


	SFAS No. 132 (Revised 2003)

In December 2003, we adopted SFAS No. 132 (Revised 2003), “Employees’ Disclosures about Pensions and Other Post Retirement Benefits.” The statement requires additional disclosures relating to pensions and other post-retirement benefits, which we have included in Note N.


	FAS 106-1

In December 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the “Act”) was passed. The Act introduces a prescription drug benefit under Medicare (Medicare Part D), as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare Part D. In January 2004, the FASB issued FASB Staff Position No. FAS 106-1, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug Improvement and Modernization Act of 2003” (“FAS 106-1”), which is effective for us as of December 31, 2003 and permits a one-time election to defer accounting for the effects of the Act. In accordance with FAS 106-1, we have elected to defer accounting for the effects of the Act and, as such, any measures of the

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

postretirement benefit obligations or net periodic postretirement cost in the financial statements or accompanying notes do not reflect the effects of the Act. Specific authoritative guidance on the accounting for the federal subsidy is pending and that guidance, when issued, could require us to change previously reported information. However, we believe the effect of the Act will not be material to our future results of operations and financial condition.


	FIN 46 and FIN 46®

In January 2003, the FASB issued Interpretation No. 46, “Consolidation of Variable Interest Entities” (“FIN 46”), which requires the consolidation of variable interest entities, as defined. Our implementation of FIN 46 did not result in the consolidation of any variable interest entities. In December 2003, the FASB issued Interpretation No. 46 (Revised) (“FIN 46®”), which is effective for us by the end of the 2004 first quarter and provides additional guidance related to accounting for variable interest entities. Tesoro has contractual arrangements for long-term supply of energy, certain industrial gases and certain chemicals from third-party facilities located at certain of our refineries. We are currently reviewing these contractual arrangements to determine if any of these facilities are variable interest entities that FIN 46® will require us to consolidate in our financial statements.


	EITF Issue No. 03-11

In August 2003, the FASB ratified the Emerging Issues Task Force (“EITF”) Issue No. 03-11, “Reporting Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, and Not Held for Trading Purposes.” In a related issue in 2002, the EITF reached a consensus that all realized and unrealized gains and losses on derivative instruments within the scope of SFAS No. 133 should be shown net in the statement of operations, whether or not settled physically, if the derivative instruments are held for trading purposes. However, the EITF recognized that there may be other contracts within the scope of the SFAS No. 133 that are not held for trading purposes and warrant further consideration regarding the appropriate classification of gains and losses. In EITF 03-11, the EITF clarified certain criteria to use in determining whether gains and losses related to non-trading derivative instruments should be shown net in the statement of operations. We adopted this statement, effective October 1, 2003.


	Statement of Position

In September 2003, the American Institute of CPAs approved for issuance a SOP, “Accounting for Certain Costs and Activities Related to Property, Plant and Equipment,” subject to clearance by the FASB. The SOP, upon clearance from the FASB, may require certain modifications in our accounting for the capitalization, depreciation and retirements of property, plant and equipment. It also would require major maintenance activities, such as refinery turnarounds, to be expensed as incurred. We would be required to write-off the unamortized carrying value of our deferred major maintenance costs as the cumulative effect of an accounting change, net of income tax, and to expense future costs as incurred. The SOP, which is expected to be issued in its final form in the second quarter of 2004, would become effective for Tesoro on January 1, 2005. At December 31, 2003, deferred major maintenance costs, which we include in other noncurrent assets, totaled $82.8 million.

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

NOTE B — EARNINGS (LOSS) PER SHARE

We compute basic earnings (loss) per share by dividing net earnings (loss) applicable to common stock by the weighted average number of common shares outstanding during the period. The calculations of diluted earnings per share include the effects of potentially dilutive common stock options outstanding during the period. The assumed conversion of common stock options produced anti-dilutive results for 2002 and, therefore, was not included in the calculations of diluted loss per share. For 2001, the effects of potentially dilutive shares, principally the maximum shares which would have been issued assuming conversion of preferred stock at the beginning of the period and common stock options, were included in the dilutive calculation. The preferred stock was converted into 10.35 million shares of common stock in July 2001.

Earnings (loss) per share calculations are presented below (in millions, except per share amounts):


			2003		2002			2001

Basic:
	Numerator:
		Net earnings (loss)	$	76.1	$	(117.0	)	$	88.0
		Less dividends on preferred stock		—		—			6.0

		Net earnings (loss) applicable to common stock	$	76.1	$	(117.0	)	$	82.0

	Denominator:
		Weighted average common shares outstanding		64.6		60.5			36.2

	Basic Earnings (Loss) Per Share		$	1.18	$	(1.93	)	$	2.26

Diluted:
	Numerator:
		Net earnings (loss) applicable to common stock	$	76.1	$	(117.0	)	$	82.0
		Plus impact of assumed conversion of preferred stock		—		—			6.0

		Total	$	76.1	$	(117.0	)	$	88.0

	Denominator:
		Weighted average common shares outstanding		64.6		60.5			36.2
		Dilutive effect of assumed exercise of stock options (anti-dilutive in 2002)		0.5		—			0.5
		Dilutive effect of assumed conversion of preferred stock		—		—			5.2

		Total diluted shares		65.1		60.5			41.9

		Diluted Earnings (Loss) Per Share	$	1.17	$	(1.93	)	$	2.10

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

NOTE C — ACQUISITIONS


	California Acquisition

On May 17, 2002, we acquired a 168,000 bpd refinery located in Martinez, California in the San Francisco Bay area along with 70 associated retail sites throughout northern California. The cash purchase price for these assets was $923 million, including $130 million for feedstock, refined products and other inventories. In addition, Tesoro issued to the seller two ten-year junior subordinated notes with face amounts aggregating $150 million, and a present value at the acquisition date of approximately $61 million (see Note F). The purchase price was determined as part of a competitive bid process. We incurred direct costs related to this transaction of $9 million. The California refinery increased the size and scope of our operations in California, and enables Tesoro to increase its yield of higher-value products, increase processing of heavier lower-cost crude oil, and diversify earnings and geographic exposure.

In connection with our acquisition of the California assets, Tesoro assumed certain related liabilities and obligations, including costs associated with employee benefits, leases and environmental matters, subject to specific levels of indemnification. These liabilities include, subject to certain exceptions, certain of the seller’s obligations, liabilities, costs and expenses for environmental compliance matters relating to the assets, including certain known and unknown obligations, liabilities, costs and expenses arising or incurred before, on or after the closing date. See Note P for further information on these environmental matters. Tesoro also assumed the seller’s obligations and rights (including certain indemnity rights) related to the agreement by which the seller purchased the refinery in 2000. The seller also assigned two environmental insurance policies to Tesoro. The policies provide $140 million of coverage in excess of a $50 million indemnity covering certain environmental liabilities.

We allocated the purchase price to the acquired assets and assumed liabilities based on their respective estimated fair market values at the date of acquisition. Independent appraisals and other evaluations were completed during 2003, and no significant adjustments to the preliminary 2002 allocations were necessary. The accompanying financial statements include the results of operations of the California assets since the date of acquisition in 2002.


	Mid-Continent Acquisition

On September 6, 2001, we acquired two refineries in North Dakota and Utah and related storage, distribution and retail assets. The acquired assets included a 60,000 bpd refinery near Mandan, North Dakota and a 55,000 bpd refinery in Salt Lake City, Utah. We also acquired a product pipeline system extending from Mandan, North Dakota to Minneapolis, Minnesota and four products terminals in North Dakota and Minnesota. In December 2002, we sold the product pipeline system and terminals for $100 million in cash (see Note D). The acquired assets also included related bulk storage facilities and retail assets consisting of 42 retail stations and contracts to supply a jobber network of retail stations. In connection with the acquisition of the North Dakota refinery, we purchased a North Dakota-based, common-carrier crude oil pipeline and gathering system on November 1, 2001. The crude oil pipeline system is the primary crude supply carrier for our North Dakota refinery. We paid $756 million in cash (including $83 million for hydrocarbon inventories) for these refinery, pipeline system and retail assets. In addition, we incurred direct costs related to this transaction of $8 million. We allocated the purchase price to the acquired assets and assumed liabilities based on their respective fair market values at the date of acquisition, based on an independent appraisal. The financial statements include the results of the Mid-Continent operations since the dates of acquisition in 2001.

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	Retail

In addition to the retail assets acquired in the California and Mid-Continent acquisitions, we acquired 46 retail fueling facilities, in November 2001, including 37 retail stations with convenience stores and nine commercial card lock facilities, located in Washington, Oregon and Idaho.

NOTE D — DIVESTITURES

On December 23, 2003, we sold substantially all of the physical assets, including inventories, of our Marine Services operations for $32 million. Tesoro recognized a pretax loss on the sale of $8 million. We included this charge in loss on asset sales and impairments in our statements of consolidated operations due to the immateriality of Marine Services operations as compared to our historical and ongoing refining and retail operations.

On December 26, 2002, we sold our product pipeline extending from Mandan, North Dakota to Minneapolis, Minnesota and terminals in North Dakota and Minnesota for $100 million in cash. Tesoro’s gain on the sale of these assets was immaterial. We continue to distribute products from our North Dakota refinery through the product pipeline under a tariff arrangement with the new owner.

In December 2002, we sold 70 retail stations in northern California for $66 million in cash, including inventories. We purchased these stations in May 2002 as part of the California acquisition and we retain responsibility for all environmental liabilities at the stations arising prior to their sale. We recognized a pretax loss on the sale of $2.5 million. We continue to sell products to a majority of the stations under a two-year unbranded supply agreement.

On December 31, 2002, we completed a sale/lease-back transaction for 30 of our retail stations located in Alaska, Hawaii, Idaho and Utah for cash proceeds of $40 million. We recognized a pretax loss on the sale of $4 million. The leases are for land, buildings and certain equipment and have an initial term of 17 years with four 5-year renewal options. The portion of the leases attributable to land is accounted for as an operating lease, while the portion attributable to buildings and equipment is accounted for as a capital lease (see Notes F and P).

NOTE E — OPERATING SEGMENTS

The Company’s revenues are derived from two major operating segments: (i) refining and (ii) retail. Our refining segment owns and operates six petroleum refineries located in California, Washington, Hawaii, Alaska, North Dakota and Utah. These refineries manufacture gasoline and gasoline blendstocks, jet fuel, diesel fuel, residual fuel oils and other refined products. We sell these products, together with products purchased from third parties, at wholesale through terminal facilities and other locations, primarily in Alaska, California, Nevada, Hawaii, Idaho, Minnesota, North Dakota, Utah, Oregon and Washington. Our refining segment also sells petroleum products to unbranded marketers and occasionally exports products to other markets in the Asia/ Pacific area. Our retail segment sells gasoline, diesel fuel and convenience store items through company-operated retail stations and branded jobber/dealers in 18 western states from Minnesota to Alaska and Hawaii. Retail operates under the Tesoro® and Mirastar® brands. We developed our Mirastar® brand exclusively for use at Wal-Mart stores in an agreement covering 17 western states. We also had revenues from Marine Services operations, which marketed and distributed petroleum products, supplies and services to the marine and offshore exploration and production industries operating in the Gulf of Mexico. We sold substantially all of the Marine Services physical assets in December 2003 (see Note D).

The operating segments follow the accounting policies used for the Tesoro’s consolidated financial statements, as described in the summary of significant accounting policies in Note A. We evaluate the performance of our segments and allocate resources based primarily on segment operating income. Segment operating income includes those revenues and expenses that are directly attributable to management of the

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

respective segment. Intersegment sales are primarily from refining to retail made at prevailing market rates. Income taxes, interest and financing costs, corporate general and administrative expenses and losses on asset sales and impairments are not included in determining segment operating income. Identifiable assets are those utilized by the segment. Corporate assets are principally cash, income taxes receivable and other assets that are not associated with a specific operating segment.

Segment information as of and for each of the three years ended December 31, 2003 were (in millions):


				2003			2002			2001

Revenues
	Refining:
		Refined products		$	8,098.3		$	6,425.7		$	4,603.1
		Crude oil resales and other(a)			370.3			334.6			248.3
	Retail:
		Fuel			797.5			920.4			420.6
		Merchandise and other			120.6			132.1			70.7
	Marine Services				155.4			132.2			172.9
	Intersegment sales from Refining to Retail				(696.4	)		(825.7	)		(333.9	)

			Total Revenues	$	8,845.7		$	7,119.3		$	5,181.7

Segment Operating Income
	Refining			$	411.1		$	72.9		$	225.8
	Retail				15.7			(12.3	)		25.0
	Marines Services				6.3			2.3			10.3

			Total Segment Operating Income		433.1			62.9			261.1
	Corporate and Unallocated Costs				(81.4	)		(73.2	)		(60.6	)
	Loss on Asset Sales and Impairments				(16.9	)		(8.4	)		(1.8	)

			Operating Income (Loss)		334.8			(18.7	)		198.7
	Interest and Financing Costs, Net				(211.7	)		(162.6	)		(51.8	)

			Earnings (Loss) Before Income Taxes	$	123.1		$	(181.3	)	$	146.9

Depreciation and Amortization
	Refining			$	120.4		$	104.2		$	63.1
	Retail				19.2			16.9			11.1
	Marine Services				2.0			3.1			2.9
	Corporate				6.6			6.5			2.8

		Total Capital Expenditures		$	148.2		$	130.7		$	79.9

Capital Expenditures (b)
	Refining			$	97.4		$	150.9		$	140.0
	Retail				1.2			40.6			43.2
	Marine Services				0.7			2.5			3.1
	Corporate				1.8			9.5			23.2

			Total Capital Expenditures	$	101.1		$	203.5		$	209.5


(a)		To balance or optimize our refinery supply requirements, we sell certain crude oil that we purchase under our supply contracts.

(b)		Excludes asset acquisitions of $932 million in 2002 and $783 million in 2001 (see Note C) and refinery turnaround and other major maintenance.

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Operating income in 2003 included charges of $8.4 million, included in corporate and unallocated costs, for the termination of Tesoro’s funded executive security plan. Operating income also included $9.0 million in voluntary early retirement benefits and severance costs. The $9.0 million charge included $2.6 million in refining, $1.3 million in retail, $0.4 million in Marine Services and $4.7 million in Corporate. Capital expenditures do not include major maintenance refinery turnaround, catalyst and drydocking costs of $51.5 million, $40.6 million and $21.6 million for 2003, 2002 and 2001, respectively.


			2003		2002		2001

Identifiable Assets
	Refining		$	3,183.2	$	3,118.1	$	2,164.9
	Retail			261.4		287.8		283.8
	Marine Services(a)			21.1		68.4		62.0
	Corporate			195.6		284.5		151.6

		Total Assets	$	3,661.3	$	3,758.8	$	2,662.3


(a)		In connection with the sale of Marine Services assets in December 2003, we retained certain assets, primarily trade receivables, which we are collecting.

NOTE F — DEBT

On April 17, 2003, Tesoro replaced its $1.275 billion senior secured credit facility with a new credit agreement, senior secured term loans and 8% senior secured notes due 2008. We expensed $33.3 million of unamortized debt issuance costs during the 2003 second quarter in connection with the extinguishment of the prior credit facility and voluntary prepayments of other debt. During 2003, we expensed an additional $2.9 million of unamortized debt issuance costs in connection with the voluntary prepayment of the $150 million term loan, described below under “Credit Agreement.”


	Debt and Maturities

At December 31, 2003 and 2002, debt consisted of (in millions):


		2003		2002

Credit Agreement — Revolving Credit Facility		$	—	$	—
Senior Secured Term Loans Due 2008			199.0		—
8% Senior Secured Notes Due 2008 (net of unamortized discount of $3.3)			371.7		—
Senior Secured Credit Facility — Tranche A Term Loan			—		194.2
Senior Secured Credit Facility — Tranche B Term Loan			—		723.8
9 5/8% Senior Subordinated Notes Due 2012			429.0		450.0
9 5/8% Senior Subordinated Notes Due 2008			211.0		215.0
9% Senior Subordinated Notes Due 2008 (net of unamortized discount of $1.8 in 2003 and $2.1 in 2002)			295.7		297.9
Junior Subordinated Notes Due 2012 (net of unamortized discount of $75.0 in 2003 and $83.0 in 2002)			75.0		67.0
Capital lease obligations and other			27.4		28.8

	Total debt		1,608.8		1,976.7
Less current maturities			3.5		70.0

	Debt, less current maturities	$	1,605.3	$	1,906.7

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The aggregate maturities of Tesoro’s debt for each of the five years following December 31, 2003 were: 2004 — $3.5 million; 2005 — $3.5 million; 2006 — $3.4 million; 2007 — $98.2 million; and 2008 — $980.6 million. Gross borrowings and repayments under our revolving credit lines and interim facilities amounted to $1.0 billion, $624 million and $958 million in 2003, 2002 and 2001, respectively.


	Credit Agreement

On April 17, 2003, Tesoro entered into a new credit agreement, including a $500 million revolving credit facility maturing in June 2006 and a $150 million term loan maturing in April 2007. The Credit Agreement, together with the net proceeds of the $200 million senior secured term loans and $375 million of 8% senior secured notes discussed below, replaced our prior credit facility. In addition, $25 million of the proceeds were used to repurchase 9 5/8% senior subordinated notes. We voluntarily prepaid the $150 million term loan in 2003.

The credit agreement currently provides for borrowings (including letters of credit) up to the lesser of $500 million, or the amount of a periodically adjusted borrowing base ($648 million as of December 31, 2003), consisting of Tesoro’s eligible cash and cash equivalents, receivables and petroleum inventories, as defined. As of December 31, 2003, we had no borrowings and $232 million in letters of credit outstanding under the revolving credit facility, resulting in total unused credit availability of $268 million, or 54% of the eligible borrowing base.


	Senior Secured Term Loans

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	8% Senior Secured Notes Due 2008

On April 17, 2003, Tesoro issued $375 million aggregate principal amount of 8% senior secured notes due April 15, 2008 through a private offering. On July 29, 2003, we completed an exchange of substantially all of the outstanding notes for 8% senior secured notes due 2008 that had been registered under the Securities Act of 1933. The notes have a five-year maturity with no sinking fund requirements and are subject to optional redemption by Tesoro, beginning April 15, 2006, at a premium of 4% through April 14, 2007, and at par thereafter. We have the right to redeem up to 35% of the aggregate principal amount at a redemption price of 108% with proceeds from certain equity issuances through April 15, 2006. The indenture for the notes contains covenants and restrictions that are customary for notes of this nature and are similar to the covenants in the indentures for Tesoro’s senior subordinated debt. The notes and the term loans are equally secured by substantially all of Tesoro’s refining property, plant and equipment and are guaranteed by substantially all of Tesoro’s active subsidiaries. The notes were issued at 98.994% of par, resulting in net proceeds of $371.2 million before debt issuance costs. The effective interest rate on the notes was 8.25%, after giving effect to the discount.


	9 5/8% Senior Subordinated Notes Due 2012

In April 2002, Tesoro issued $450 million principal amount of 9 5/8% Senior Subordinated Notes due April 1, 2012. These notes have a ten — year maturity with no sinking fund requirements and are subject to optional redemption by Tesoro, beginning April 1, 2007 at premiums of 4.8% through March 31, 2008, 3.2% from April 1, 2008 to March 31, 2009, 1.6% from April 1, 2009 to March 31, 2010, and at par thereafter. In addition, during the first three years, we have the right to redeem up to 35% of the principal amount at a redemption price of 109.625% with proceeds of certain equity issuances. The indenture for these notes contains covenants and restrictions which are customary for notes of this nature. To the extent Tesoro’s fixed charge coverage ratio, as defined in the indenture, allows us to incur additional debt, we are allowed to pay cash dividends on common stock and repurchase shares of common stock, subject to limitations in our credit agreement. The notes are guaranteed by substantially all of Tesoro’s active domestic subsidiaries.


	9 5/8% Senior Subordinated Notes Due 2008

In November 2001, Tesoro issued $215 million principal amount of 9 5/8% Senior Subordinated Notes due November 1, 2008. These notes have a seven-year maturity with no sinking fund requirements and are subject to optional redemption by Tesoro, beginning November 1, 2005 at premiums of 4.8% through October 31, 2006, 2.4% from November 1, 2006 to October 31, 2007, and at par thereafter. During, the first three years, we have the right to redeem up to 35% of the principal amount at a redemption price of 109.625% with net cash proceeds of one or more equity offerings. The indenture for these notes contains covenants and restrictions which are customary for notes of this nature. To the extent Tesoro’s fixed charge coverage ratio, as defined in the indenture, allows us to incur additional debt, we are allowed to pay cash dividends on common stock and repurchase shares of common stock, subject to limitations in our credit agreement. The notes are guaranteed by substantially all of Tesoro’s active domestic subsidiaries.


	9% Senior Subordinated Notes Due 2008

In 1998, Tesoro issued $300 million principal amount of 9% Senior Subordinated Notes due 2008, Series B. The notes have a ten-year maturity without sinking fund requirements and are subject to optional redemption by Tesoro at premiums of 4.5% through June 30, 2004, 3% from July 1, 2004 through June 30, 2005, 1.5% from July 1, 2005 through June 30, 2006, and at par thereafter. The indenture for these notes contains covenants and restrictions which are customary for notes of this nature. To the extent Tesoro’s fixed charge coverage ratio, as defined in the indenture, allows us to incur additional debt, we are allowed to pay cash dividends on common stock and repurchase shares of common stock, subject to limitations in our credit

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

agreement. The effective interest rate on the notes is 9.16%, after giving effect to the discount at the date of issue. The notes are guaranteed by substantially all of the Tesoro’s active domestic subsidiaries.


	Junior Subordinated Notes Due 2012

In connection with our acquisition of the California refinery, Tesoro issued to the seller two ten-year junior subordinated notes with face amounts totaling $150 million: (i) a $100 million junior subordinated note, due July 2012, which is non-interest bearing for the first five years and carries a 7.5% interest rate for the remaining five-year period, and (ii) a $50 million junior subordinated note, due July 2012, which bears interest at 7.47% for the second through the fifth years and 7.5% for years six through ten. We initially recorded these two notes at a combined present value of approximately $61 million, discounted at rates of 15.625% and 14.375%. We are amortizing the discount over the term of the notes.


	Capital Lease Obligations

Our capital lease obligations comprise primarily of 30 retail stations that we sold and leased-back in 2002 with initial terms of 17 years, with four 5-year renewal options (See Note D). We classified the portions of the leases attributable to land as operating leases, and we classified the portions attributable to depreciable buildings and equipment as capital leases. The combined present value of minimum lease payments totaled $22.9 million at December 31, 2003. Tesoro also has other capital leases for tugs and barges used to transport petroleum products, over varying terms ending in 2005 through 2009, in which the combined present value of minimum lease payments totaled $3.7 million at December 31, 2003.

At December 31, 2003 and 2002, the total cost of assets under capital leases was $34.7 million gross (accumulated amortization of $9.6 million) and $35.3 million gross (accumulated amortization of $7.6 million), respectively. Capital lease obligations included in debt totaled $27.4 million and $28.8 million at December 31, 2003 and 2002, respectively. We include amortization of the cost of assets under capital leases in depreciation and amortization.

Future minimum annual lease payments, including interest, as of December 31, 2003 for capital leases were (in millions):


2004		$	4.2
2005			4.2
2006			3.9
2007			3.5
2008			3.4
Thereafter			35.1

	Total minimum lease payments		54.3
Less amount representing interest			26.9

	Capital lease obligations	$	27.4

NOTE G — STOCKHOLDERS’ EQUITY

In March 2002, Tesoro completed a public offering of 23 million shares of common stock. We used the net proceeds from the stock offering of $245.1 million, after deducting underwriting fees and offering expenses, to partially fund our acquisition of the California refinery. In 1998, Tesoro issued mandatorily convertible preferred stock, which automatically converted into 10,350,000 shares of common stock on July 1, 2001. In 2001, we repurchased 304,000 shares of common stock for $3.5 million. In 2003 and 2002, we did not repurchase any shares.

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Our credit agreement, senior secured notes and senior subordinated notes each limit our ability to pay cash dividends or repurchase stock. The limitation in each of our debt agreements is based on limits on restricted payments (as defined in our debt agreements), which include dividends, stock repurchases or voluntary prepayments of subordinate debt. The aggregate amount of restricted payments cannot exceed an amount defined in each of the debt agreements.

See Note O for information relating to stock-based compensation and common stock reserved for exercise of options.

NOTE H — INCOME TAXES

The income tax provision (benefit) was comprised of (in millions):


			2003			2002			2001

Current:
	Federal		$	(8.5	)	$	(60.8	)	$	17.7
	State			—			(6.8	)		5.7
Deferred:
	Federal			53.5			8.5			32.9
	State			2.0			(5.2	)		2.6

		Income Tax Provision (Benefit)	$	47.0		$	(64.3	)	$	58.9

We provide deferred income taxes and benefits for differences between financial statement carrying amounts of assets and liabilities and their respective tax bases. Temporary differences and the resulting deferred tax liabilities and assets at December 31, 2003 and 2002 were (in millions):


		2003			2002

Current Deferred Federal Tax Assets and Liabilities:
	LIFO inventory	$	(27.6	)	$	(25.8	)
	Accrued pension and other postretirement benefits		6.3			5.2
	Other accrued employee costs		4.8			4.8
	Accrued environmental remediation liabilities		4.0			2.6
	Other accrued liabilities		(1.2	)		7.6
Current Deferred State Tax Assets, Net			5.5			2.4

	Current Deferred Tax Liability, Net	$	(8.2	)	$	(3.2	)

Noncurrent Deferred Federal Tax Assets and Liabilities:
	Accelerated depreciation and property related items	$	(276.5	)	$	(205.8	)
	Deferred maintenance costs, including refinery turnarounds		(23.5	)		(18.2	)
	Amortization of intangible assets		(33.2	)		(30.3	)
	Net operating loss carry forwards		77.0			55.2
	Accrued pension and other postretirement benefits		51.7			47.2
	Alternative minimum tax credit		27.4			36.1
	Accrued environmental remediation liabilities		5.9			11.6
	Other		10.6			(11.1	)
Noncurrent Deferred State Tax Liability, Net			(18.6	)		(13.4	)

	Noncurrent Deferred Tax Liability, Net	$	(179.2	)	$	(128.7	)

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The realization of deferred tax assets depends on Tesoro’s ability to generate future taxable income. Although realization is not assured, we believe it is more likely than not that we will realize the deferred tax assets, and therefore, we did not record a valuation allowance as of December 31, 2003 or 2002. The net deferred federal and state tax assets increased by $4.3 million and $0.6 million, respectively, in 2002, when we finalized the purchase price allocation of the Mid-Continent acquisition described in Note C.

The reconciliation of income tax expense (benefit) at the U.S. statutory rate to the income tax expense (benefit) follows (in millions):


		2003			2002			2001

Income Taxes (Benefit) at U.S. Federal Statutory Rate		$	43.1		$	(63.5	)	$	51.4
Effect of:
	State income taxes, net of federal income tax effect		5.9			(7.8	)		5.3
	Expired tax credits		—			3.9			—
	State tax credits, net		(4.6	)		—			—
	Other		2.6			3.1			2.2

Income Tax Provision (Benefit)		$	47.0		$	(64.3	)	$	58.9

As of December 31, 2003, Tesoro had approximately $220 million of Federal net operating loss carry-forwards that expire in 2022 and 2023 and $27 million of alternative minimum tax credits that we carry forward indefinitely. Our filing of the 2002 and 2001 tax returns and the carryback of the net operating losses for both years resulted in the receipt of refunds of $51 million and $48 million during 2003 and 2002, respectively. However, our election to carry back the 2002 net operating losses resulted in the loss of $3.9 million of tax credits claimed in earlier years.

NOTE I — RECEIVABLES

Concentrations of credit risk with respect to accounts receivable are influenced by the large number of customers comprising Tesoro’s customer base and their dispersion across various industry groups and geographic areas of operations. We perform ongoing credit evaluations of our customers’ financial condition, and in certain circumstances, require prepayments, letters of credit or other collateral arrangements. We include an allowance for doubtful accounts as a reduction in our trade receivables, which amounted to $4.3 million and $3.7 million at December 31, 2003 and 2002, respectively.

NOTE J — INVENTORIES

Components of inventories at December 31, 2003 and 2002 were (in millions):


		2003		2002

Crude oil and refined products, at LIFO cost		$	430.1	$	402.6
Oxygenates and by-products, at the lower of FIFO cost or market value			9.7		11.2
Merchandise			7.4		9.3
Materials and supplies			40.1		38.4

	Total Inventories	$	487.3	$	461.5

Inventories valued at LIFO cost were less than replacement cost by approximately $210 million and $120 million, at December 31, 2003 and 2002, respectively. During 2002, we reduced certain inventories resulting in a decrease in LIFO inventory quantities, which had been carried at lower costs prevailing in

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

previous years. This LIFO inventory liquidation decreased our costs of sales by $5 million and the net loss by approximately $3 million, or $0.05 per share, in 2002.

NOTE K — GOODWILL AND ACQUIRED INTANGIBLES

SFAS No. 142 requires that goodwill and other intangibles determined to have an indefinite life are no longer to be amortized but are to be tested for impairment at least annually. See Note A for the effects of the amortization of goodwill in 2001. We review the recorded value of goodwill for impairment during the fourth quarter of each year, or sooner if events or changes in circumstances indicate the carrying amount may exceed fair value. Our annual evaluation of goodwill impairment requires us to make significant estimates to determine the fair value of our reporting units. Our estimates may change from period to period because we must make assumptions about future cash flows, profitability and other matters. It is reasonably possible that future changes in our estimates could have a material effect on the carrying amount of goodwill.

The net carrying values of goodwill by operating segments at December 31, 2003 and 2002 were (in millions):


		2003		2002

Refining		$	84.0	$	84.0
Retail			4.7		4.7
Marine Services			—		2.4

	Total	$	88.7	$	91.1

In 2003, we wrote-off the Marine Services goodwill in connection with the sale of that operation. In 2002, we wrote-off $1.2 million of goodwill in the retail segment due to an impairment loss.

The following table provides the gross carrying amount and accumulated amortization for each major class of acquired intangible assets, excluding goodwill (in millions):



		December 31, 2003						December 31, 2002

		Gross				Net		Gross				Net
		Carrying		Accumulated		Carrying		Carrying		Accumulated		Carrying
		Amount		Amortization		Value		Amount		Amortization		Value

Air emissions credits		$	98.7	$	6.2	$	92.5	$	100.7	$	2.7	$	98.0
Refinery permits and plans			11.0		1.2		9.8		11.0		0.6		10.4
Customer agreements and contracts			39.8		11.3		28.5		39.8		6.4		33.4
Other intangibles			12.7		4.9		7.8		12.4		3.6		8.8

	Total	$	162.2	$	23.6	$	138.6	$	163.9	$	13.3	$	150.6

The weighted average estimated lives of acquired intangible assets are: air emission credits — 28 years; refinery permits and plans — 22 years; customer agreements and contracts — 14 years; and other intangible assets — 10 years. Amortization expense of acquired intangible assets other than goodwill amounted to $10.3 million, $8.8 million and $2.7 million for the years ended December 31, 2003, 2002 and 2001, respectively. Our estimated amortization expense for each of the following five years is: 2004 — $10 million; 2005 — $9 million; 2006 — $8 million; 2007 — $7 million; and 2008 — $7 million.

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

NOTE L — OTHER NONCURRENT ASSETS

Other noncurrent assets at December 31, 2003 and 2002 consisted of (in millions):


		2003		2002

Deferred maintenance costs, including refinery turnarounds, net of amortization		$	82.8	$	62.1
Debt issuance costs, net of amortization			43.5		56.4
Prepaid pension costs and intangible pension asset			4.2		14.3
Notes receivable from employees			2.5		4.3
Other assets, net of amortization			25.5		22.4

	Total Other Assets	$	158.5	$	159.5

At December 31, 2003 and 2002, Tesoro had outstanding notes receivable, due from certain executive officers, totaling approximately $0.8 million and $2.4 million, respectively. At December 31, 2003, we had one outstanding non-interest bearing note from a senior vice president with a remaining term of 5 years, which Tesoro assumed in connection with our 2002 acquisition of the California refinery. At December 31, 2002, we had two other non-interest bearing notes from an executive vice president that were paid in 2003.

NOTE M — ACCRUED LIABILITIES

The Company’s current accrued liabilities and noncurrent other liabilities at December 31, 2003 and 2002 included (in millions):


			2003		2002

Accrued Liabilities — Current:
	Taxes other than income taxes, primarily excise taxes		$	73.0	$	80.9
	Employee costs			51.9		25.6
	Interest			40.3		47.6
	Pension benefits			32.3		16.8
	Other			54.2		28.8

		Total Accrued Liabilities — Current	$	251.7	$	199.7

Other Liabilities — Noncurrent:
	Pension and other postretirement benefits		$	157.4	$	149.2
	MTBE facility lease termination obligation			29.5		31.5
	Other			37.5		46.8

		Total Other Liabilities — Noncurrent	$	224.4	$	227.5

As part of our California refinery acquisition in 2002, we acquired an operating lease for an MTBE production facility. We accrued the termination obligation because California state regulations required the phase-out of MTBE by December 31, 2003. We have not terminated the lease and expect to make payments throughout the remaining term of the lease.

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

NOTE N — BENEFIT PLANS


	Pension and Other Postretirement Benefits

Tesoro sponsors defined benefit pension plans, including an employee retirement plan, an executive security plan and a non-employee director retirement plan. We provide a qualified noncontributory retirement plan for all eligible employees. Benefits are based on years of service and compensation. Tesoro’s funding policy is to make contributions at a minimum in accordance with the requirements of applicable laws and regulations, but no more than the amount deductible for income tax purposes. We contributed $17 million in 2003, and we expect to contribute $37 million in 2004. Plan assets are primarily comprised of common stock and bond funds.

Tesoro’s unfunded executive security plan provides certain executive officers and other key personnel with supplemental death or retirement benefits. These benefits are provided by a nonqualified, noncontributory plan and are based on years of service and compensation. During December 2003, we terminated our funded executive security plan, resulting in a write-off of unamortized prepaid pension costs of $6.9 million and a plan curtailment contribution of $1.5 million. We made additional contributions of $2.9 million to the funded plan in 2003.

Tesoro had previously established an unfunded non-employee director retirement plan that provided eligible directors retirement payments upon meeting certain age and other requirements. In 1997, that plan was frozen with accrued benefits of current directors transferred to the board of directors phantom stock plan (see Note O). After the amendment and transfer, only those retired directors or beneficiaries who had begun to receive benefits remained participants in the previous plan.

Tesoro provides to retirees who were participating in our group insurance program at retirement, health care benefits and, to those who qualify, life insurance benefits. Health care is available to qualified dependents of participating retirees. These benefits are provided through unfunded, defined benefit plans or through contracts with area health-providers on a premium basis. The health care plans are contributory, with retiree contributions adjusted periodically, and contain other cost-sharing features such as deductibles and coinsurance. The life insurance plan is noncontributory. We fund Tesoro’s share of the cost of postretirement health care and life insurance benefits on a pay-as-you go basis. Our retiree medical plan provides prescription drug benefits that may be affected by the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (“the Act”), signed into law in December 2003. In January 2004, the FASB issued FASB Staff Position FAS 106-1, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003,” which permits a one-time election to defer accounting for the effects of the Act. We have elected to defer accounting for the effects of the Act and, as such, the effects of the Act on our medical plan has not been included in the measurement of our accumulated other postretirement benefit obligation or net periodic other postretirement benefit cost for 2003. Specific authoritative guidance from the FASB on the accounting for the federal subsidy is pending and that guidance, when issued, could require us to restate previously reported information and may require us to amend our plans to benefit from the Act.

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

We use December 31 as the measurement date for all of our defined benefit pension plans. Changes in benefit obligations, plan assets and the funded status of the pension plans and other postretirement benefits, reconciled to amounts in the consolidated balance sheets as of December 31, 2003 and 2002, were (in millions):



									Other Postretirement
			Pension Benefits						Benefits

			2003			2002			2003			2002

Change in benefit obligations:
	Benefit obligations at beginning of year		$	184.7		$	129.3		$	138.3		$	80.2
	Service cost			15.0			13.5			7.9			6.1
	Interest cost			11.1			10.9			7.8			7.1
	Actuarial (gain)loss			(4.1	)		23.4			(15.7	)		15.4
	Benefits paid			(33.3	)		(11.3	)		(1.6	)		(2.0	)
	Curtailments and settlements			—			(0.8	)		—			—
	Plan amendments			1.5			0.7			—			—
	Acquisitions			—			19.0			—			31.5
	Special termination benefits			6.4			—			0.5			—

		Benefit obligations at end of year		181.3			184.7			137.2			138.3

Change in plan assets:
	Fair value of plan assets at beginning of year			72.8			73.6			—			—
	Actual return on plan assets			13.8			(5.9	)		—			—
	Employer contributions			21.2			16.3			—			—
	Benefits paid			(33.3	)		(11.2	)		—			—

		Fair value of plan assets at end of year		74.5			72.8			—			—

Funded status				(106.8	)		(111.9	)		(137.2	)		(138.3	)
Unrecognized prior service cost				9.3			8.9			2.2			2.4
Unrecognized net actuarial loss				34.9			59.3			12.0			27.8

		Accrued benefit cost	$	(62.6	)	$	(43.7	)	$	(123.0	)	$	(108.1	)

Amounts included in Consolidated Balance Sheets:
	Accrued and other liabilities		$	(66.8	)	$	(58.0	)	$	(123.0	)	$	(108.1	)
	Prepaid pension costs			—			7.7			—			—
	Intangible asset			4.2			6.6			—			—

		Net amount recognized	$	(62.6	)	$	(43.7	)	$	(123.0	)	$	(108.1	)

At December 31, 2002, the accumulated benefit obligation of the employee retirement and executive security plan exceeded the fair value of plan assets, and we recognized an additional minimum liability and an intangible asset of $6.6 million, and that amount was reduced to $4.2 million as of December 31, 2003.

In 2003, Tesoro offered voluntary enhanced retirement benefits to certain qualified employees. These enhanced benefits resulted in an increase to the pension benefit obligation of $1.4 million and a charge to expense of $6.4 million.

The combined accumulated benefit obligations for our retirement plans was $141.3 million and $130.7 million at December 31, 2003 and 2002, respectively. For retirement plans with accumulated benefit

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

obligations in excess of plan assets, the following table sets forth the projected and accumulated benefit obligations and fair value of plan assets (in millions):


	2003		2002

Projected benefit obligation	$	181.2	$	165.6
Accumulated benefit obligation	$	141.3	$	113.8
Fair value of plan assets	$	74.5	$	55.8

The components of pension and postretirement benefit expense included in the consolidated statements of operations for the years ended December 31, 2003, 2002 and 2001 were (in millions):



												Other Postretirement
			Pension Benefits									Benefits

			2003			2002			2001			2003		2002		2001

Components of net periodic benefit expense:
	Service cost		$	15.0		$	13.5		$	8.3		$	7.9	$	6.1	$	2.9
	Interest cost			11.1			10.9			8.5			7.8		7.1		4.3
	Expected return on plan assets			(7.0	)		(6.6	)		(6.3	)		—		—		—
	Amortization of prior service cost			1.1			1.0			—			0.2		0.2		—
	Recognized net actuarial loss			5.1			3.6			2.8			0.2		0.3		0.2
	Curtailments and settlements			8.4			(0.2	)		—			—		—		—
	Special termination benefits			6.4			—			—			0.5		—		—

		Net periodic benefit expense	$	40.1		$	22.2		$	13.3		$	16.6	$	13.7	$	7.4

Significant assumptions included in estimating Tesoro’s pension and other postretirement benefits obligations were:



								Other Postretirement
		Pension Benefits						Benefits

		2003		2002		2001		2003		2002		2001

Projected Benefit Obligation
Assumed weighted average % as of December 31:
	Discount rate		6.25		6.34		7.18		6.25		6.50		7.25
	Rate of compensation increase		3.78		4.12		5.00		—		—		—
Net Periodic Pension Cost
Assumed weighted average % as of December 31:
	Discount rate		6.05		6.97		7.08		6.50		7.25		7.50
	Rate of compensation increase		4.32		5.00		5.32		—		—		—
	Expected return on plan assets		8.04		8.17		8.02		—		—		—

The expected return on plan assets reflects the weighted-average of the expected long-term rates of return for the broad categories of investments held in the plans. The expected long-term rate of return is adjusted when there are fundamental changes in expected returns on the plan’s investments.

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The assumed health care cost trend rates used to determine the projected postretirement benefit obligation are as follows:


	2003			2002

Health care cost trend rate assumed for next year		8.43	%		8.30	%
Rate to which the cost trend rate is assumed to decline		5.00	%		5.50	%
Year that the rate reaches the ultimate trend rate		2010			2010

Assumed health care cost trend rates have a significant effect on the amounts reported for the health care and life insurance plans. A one-percentage-point change in assumed health care cost trend rates could have the following effects (in millions):


	1-Percentage-		1-Percentage-
	Point Increase		Point Decrease

Effect on total of service and interest cost components	$	3.3	$	(2.5	)
Effect on postretirement benefit obligations	$	24.2	$	(19.6	)

Our pension plans follow an investment return approach in which investments are allocated to broad investment categories, including equities, debt and real estate, to maximize the long-term return of the plan assets at a prudent level of risk. The target allocations for the pension plan’s assets were 63% equity securities (with sub-category allocation targets), 25% debt securities and 12% real estate. The funded executive security plan, terminated in December 2003, was primarily invested in an insurance contract providing for a guaranteed rate of return for certain periods (included in “Other” in the table below). The weighted-average asset allocations in our pension plans, at December 31, 2003 and 2002, were:



		Plan Assets
		at
		December 31,

		2003			2002

Asset Category
Equity Securities			66	%		44	%
Debt Securities			25			18
Real Estate			8			14
Other			1			24

	Total		100	%		100	%

Our other postretirement benefit plans contained no assets at December 31, 2003 and 2002.


	Thrift Plan and Retail Savings Plan

Tesoro sponsors an employee thrift plan that provides for contributions, subject to certain limitations, by eligible employees into designated investment funds with a matching contribution by Tesoro. Employees may elect tax-deferred treatment in accordance with the provisions of Section 401(k) of the Internal Revenue Code. Effective November 1, 2001, the thrift plan was amended to change Tesoro’s 100% matching contribution, from a maximum of 6% to 7% of the employee’s eligible earnings, with at least 50% of the matching contribution directed for initial investment in Tesoro’s common stock. The maximum matching contribution is 6% for employees covered by the collective bargaining agreement at the California refinery. Participants may transfer out of Tesoro’s common stock at any time, on an unlimited basis, as of January 1, 2004. Tesoro’s contributions to the thrift plan amounted to $11.4 million, $11.1 million and $6.5 million during 2003, 2002 and 2001, respectively, of which $0.9 million, $2.4 million and $3.4 million consisted of treasury stock reissuances in 2003, 2002 and 2001, respectively.

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Effective January 1, 2001, Tesoro began sponsoring a new savings plan, in lieu of the thrift plan, for eligible retail employees who have completed one year of service and have worked at least 1,000 hours within that time. Eligible employees receive a mandatory employer contribution equal to 3% of eligible earnings. If employees elect to make pretax contributions, Tesoro also contributes an employer match contribution equal to $0.50 for each $1.00 of employee contributions, up to 6% of eligible earnings. At least 50% of the mandatory and matching employer contributions must be directed for initial investment in Tesoro common stock. Participants may transfer out of Tesoro’s common stock at any time, on an unlimited basis, as of January 1, 2004. Tesoro’s contributions amounted to $0.4 million, $0.4 million and $0.2 million during 2003, 2002 and 2001, respectively, of which $0.1 million and $0.1 million consisted of treasury stock reissuances in 2002 and 2001, respectively.

NOTE O — STOCK-BASED COMPENSATION

We have accounted for stock-based compensation using the intrinsic value method prescribed in APB Opinion No. 25. Effective January 1, 2004, we adopted the preferable fair value method of accounting for stock-based compensation, as prescribed in SFAS No. 123. We selected the “modified prospective method” of adoption described in SFAS No. 148. See Note A for information related to the pro forma effects, had compensation cost been determined based on fair values at the grant dates of awards in accordance with SFAS No. 123.


	Incentive Stock Plans

We have two employee incentive stock plans, the Key Employee Stock Option Plan, as amended, and the Amended and Restated Executive Long-Term Incentive Plan. Tesoro also has the 1995 Non-Employee Director Stock Option Plan. At December 31, 2003, Tesoro had 7,199,122 shares of unissued common stock reserved for these plans.

Under the Restated Executive Long-Term Incentive Plan, shares of common stock may be granted in a variety of forms, including restricted stock, nonqualified stock options, stock appreciation rights and performance share and performance unit awards. Tesoro may grant up to 7,250,000 shares under this plan. Stock options may be granted at exercise prices not less than the fair market value on the date the options are granted. The options granted generally become exercisable after one year in 25% or 33% annual increments and expire ten years from the date of grant. At Tesoro’s annual meeting of stockholders held in May 2003, an amendment was approved by the stockholders to extend the expiration date of this plan to September 15, 2008. At December 31, 2003, Tesoro had 614,102 shares available for future grants under this plan.

The Key Employee Stock Option Plan provides stock option grants to eligible employees who are not executive officers of Tesoro. We granted stock options to purchase 797,000 shares of common stock, of which 611,200 shares were outstanding at December 31, 2003, which become exercisable one year after grant in 25% annual increments. The options expire ten years after the date of grant. The board of directors has suspended any future grants under this plan.

The Director Stock Option Plan provides for the grant of 300,000 nonqualified stock options to eligible non-employee directors of Tesoro. These automatic, non-discretionary stock options are granted at an exercise price equal to the fair market value per share of Tesoro’s common stock at the date of grant. The term of each option is ten years, and an option becomes exercisable six months after it is granted. This plan will terminate as to issuance of stock options in February 2005. At December 31, 2003, Tesoro had 136,000 options outstanding and 141,000 shares available for future grants under this plan.

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

A summary of stock option activity for all plans is set forth below (shares in thousands):


		Number of
		Options			Weighted-Average
		Outstanding			Exercise Price

Outstanding January 1, 2001			5,023.2		$	12.23
	Granted		98.0			13.18
	Exercised		(249.7	)		6.12
	Forfeited or expired		(20.4	)		9.21

Outstanding December 31, 2001			4,851.1			12.57
	Granted		1,368.0			8.20
	Exercised		(0.7	)		10.03
	Forfeited or expired		(151.1	)		12.58

Outstanding December 31, 2002			6,067.3			11.59
	Granted		570.5			8.08
	Exercised		(72.3	)		9.74
	Forfeited or expired		(296.2	)		11.16

Outstanding December 31, 2003			6,269.3			11.31

The following table summarizes information about stock options outstanding under all plans at December 31, 2003 (shares in thousands):



	Options Outstanding
							Options Exercisable
			Weighted-Average
	Number		Remaining		Weighted-Average		Number		Weighted-Average
Range of Exercise Prices	Outstanding		Contractual Life		Exercise Price		Exercisable		Exercise Price

$3.86 to $7.72		715.0		8.9 years	$	4.79		256.3	$	4.97
$7.73 to $11.18		2,355.3		6.7 years		9.25		1,372.1		9.65
$11.19 to $14.94		2,139.3		5.3 years		13.30		1,753.0		13.30
$14.95 to $18.63		1,059.7		5.6 years		16.27		1,059.7		16.27

$3.86 to $18.63		6,269.3		6.3 years		11.31		4,441.1		12.40

At December 31, 2003, 2002 and 2001, exercisable stock options totaled 4.4 million, 3.8 million and 3.1 million, respectively.


	Phantom Stock Plan

Under the Phantom Stock Plan, a yearly credit of $7,250 is made in units to an account of each non-employee director, based upon the closing market price of Tesoro’s common stock on the date of credit. A director also may elect to have the value of his cash retainer fee deposited quarterly into the account as units. Retiring directors who are committee chairpersons receive an additional $5,000 credit to their accounts. Certain non-employee directors also received a credit in their accounts in 1997, arising from the transfer of their lump-sum accrued benefit under the frozen Director Retirement Plan. The value of each account balance, which is a function of increases in market value of the Tesoro’s common stock, is payable in cash at termination (if vested with three years of service) or at retirement, death or disability. Our results of operations included an expense of $536,000 in 2003, a credit of $299,000 in 2002 and an expense of $144,000 in 2001, related to the Phantom Stock Plan.

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	Other Stock-Based Compensation

In December 2003, Tesoro awarded its chief executive officer 250,000 shares of non-vested common stock. The shares were awarded at a grant date value of $13.18 per share and vest in 20% annual increments beginning in February 2005, assuming continued employment at the vesting dates. The shares will be issued and restrictively endorsed in March 2004, and will be held by Tesoro until they vest. The employment agreement also provides that Tesoro will issue up to an additional 250,000 shares of non-vested common stock to match common stock purchases by the chief executive officer. The chief executive officer purchased 125,000 shares in February 2004, and Tesoro will issue an equal number of non-vested shares in March 2004, which also will be restrictively endorsed and held by Tesoro. These matching shares vest in December 2008, assuming continued employment at that date. The related compensation expense is recognized on a straight-line basis over the vesting period.

Tesoro’s chief executive officer also holds 175,000 phantom stock options, which were granted in 1997 with a term of ten years at 100% of the fair value of Tesoro’s common stock on the grant date, or $16.9844 per share. At December 31, 2003, all of the phantom stock options were exercisable. Upon exercise, the chief executive officer would be entitled to receive, in cash, the difference between the fair market value of the common stock on the date of the phantom stock option grant and the fair market value of common stock on the date of exercise. At the discretion of the Compensation Committee of the Board of Directors, these phantom stock options may be converted to traditional stock options under the executive long-term incentive plan. No compensation expense has been recognized for this award.

NOTE P — COMMITMENTS AND CONTINGENCIES


	Operating Leases

Tesoro has various noncancellable operating leases related to land, buildings, equipment, retail facilities and ship charters. These leases have remaining primary terms up to 40 years, with terms of certain rights-of-way extending up to 27 years, and generally contain multiple renewal options.

We have long-term charters through July 2010 for two U.S. flagged ships, used to transport crude oil and products. The aggregate annual commitments on these charters total $25 million to $29 million over the remaining terms, including operating expenses that increase annually from $13 million to $16 million.

Tesoro has operating leases for most of its retail gas station sites with primary remaining terms up to 40 years, and generally containing renewal options. Our aggregate annual lease commitments for the sites are approximately $9 million over the next five years. These leases include the 30 retail stations that we sold and leased back in 2002 with initial terms of 17 years and four five-year renewal options (See Note D). We classified the portion of each lease attributable to land as an operating lease, and the portion attributable to depreciable buildings and equipment as a capital lease (See Note F). Tesoro also has an agreement with Wal-Mart to build and operate retail gas stations at selected existing and future Wal-Mart stores in the western United States. Under the agreement, each site is subject to a lease with a ten-year primary term and an option, exercisable at our discretion, to extend a site’s lease for two additional five-year options.

We lease Tesoro’s corporate headquarters from a limited partnership, in which Tesoro owns a 50% limited interest. The initial lease term is through 2014 with two five-year renewal options. Our total rent expense, presented below, includes lease payments and operating costs paid to the partnership totaling $3.2 million, $3.1 million and $2.6 million in 2003, 2002 and 2001, respectively. We account for Tesoro’s interest in the partnership using the equity method of accounting, and our consolidated balance sheets do not include the partnership’s assets, primarily land and buildings, totaling approximately $17 million and debt of approximately $13 million.

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Tesoro’s minimum annual lease payments as of December 31, 2003, for operating leases having initial or remaining noncancellable lease terms in excess of one year were (in millions):


	Ship
	Charters		Other

2004	$	30.6	$	42.8
2005		27.0		34.7
2006		27.7		28.5
2007		28.0		26.8
2008		28.5		24.6
Thereafter		43.4		166.4

Total rental expense for short-term and long-term operating leases, excluding marine charters, amounted to approximately $49 million in 2003, $46 million in 2002, and $34 million in 2001. We also enter into various short-term charters for vessels to transport refined products to and from our refineries and terminals and to deliver products to customers. Total marine charter expense was $61 million in 2003, $54 million in 2002 and $40 million in 2001. See Note F for information related to capital leases.


	Purchase Obligations and Other Commitments

Tesoro’s contractual purchase commitments consist primarily of crude oil supply contracts for our refineries from several suppliers with noncancellable remaining terms ranging up to three years with renewal provisions. Prices under the term agreements fluctuate with market prices. Assuming actual market crude oil prices as of December 31, 2003, ranging from $30 per barrel to $33 per barrel, our minimum crude supply commitments, for the next three years would approximate $1.4 billion in 2004, $629 million in 2005 and $281 million in 2006. We also purchase crude oil at market prices under short-term renewable agreements and in the spot market. In addition to these purchase commitments, we also have contractual commitments for certain capital projects related primarily to refinery improvements and environmental projects totaling $22 million for 2004.

We also have long-term commitments to purchase services, such as electricity, water, hydrogen, nitrogen, oxygen and sulfuric acid used by certain of our refineries in the normal course of business. We also will make annual payments of approximately $6 million through 2010 for a deactivated MTBE plant located at our California refinery. The present value of these future lease payments was included in accrued liabilities in the consolidated balance sheets (see Note M). The minimum annual payments under these contracts, including lease payments for the deactivated MTBE plant, are estimated to total $31 million in 2004, $29 million in 2005, $28 million in 2006, $27 million in 2007, and $27 million in 2008. The remaining minimum commitment totals approximately $58 million over 9 years. We also have a power supply agreement through 2012 at the California refinery, which requires minimum payments through 2007 that vary based on market prices for electricity. Assuming estimated future market prices of electricity based on a third-party market analysis, minimum payments for the next four years would approximate $48 million in 2004, $45 million in 2005, $47 million in 2006 and $27 million in 2007. Tesoro paid approximately $92 million, $57 million and $15 million in 2003, 2002 and 2001, respectively, under these contracts.


	Environmental and Other Matters

Tesoro is a party to various litigation and contingent loss situations, including environmental and income tax matters, arising in the ordinary course of business. Where required, we have made accruals in accordance with SFAS No. 5, “Accounting for Contingencies,” in order to provide for these matters. We cannot predict the ultimate effects of these matters with certainty, and we have made related accruals based on our best estimates, subject to future developments. We believe that the outcome of these matters will not result in a

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

material adverse effect on Tesoro’s liquidity and consolidated financial position. Although the resolution of certain of these matters could have a material adverse impact on interim or annual results of operations.

Tesoro is subject to audits by federal, state and local taxing authorities in the normal course of business. It is possible that tax audits could result in claims against Tesoro in excess of recorded liabilities. We believe, however, that when these matters are resolved, they will not materially affect Tesoro’s consolidated financial position or results of operations.

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


	Environmental Remediation Liabilities

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

We are currently involved in remedial responses and have incurred and expect to continue to incur cleanup expenditures associated with environmental matters at a number of sites, including certain of our owned properties. At December 31, 2003, our accruals for environmental expenses totaled approximately $36 million. Our accruals for environmental expenses include retained liabilities for previously owned or operated properties, refining, pipeline, terminal and marine services operations and retail gas stations. We believe these accruals are adequate, based on currently available information, including the participation of other parties or former owners in remediation action.

Tesoro also received an indemnity from the seller for environmental costs arising out of conditions that existed at or before our acquisition of the Hawaii refinery acquisition in 1998. This indemnification, which is in effect until 2008, had $4.5 million remaining as of December 31, 2003.


	Other Environmental Liabilities

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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.

In November 2003, we filed suit in Contra Costa County Superior Court against Tosco alleging that Tosco misrepresented, concealed and failed to disclose certain additional environmental conditions at our California refinery. On March 1, 2004, the court granted Tosco’s motion to compel arbitration of our claims for these certain additional environmental conditions. In the arbitration proceedings we initiated against Tosco in December 2003, we are also seeking a determination that Tosco is liable for investigation and remediation of these certain additional environmental conditions, the amount of which is currently unknown and which may not be covered by the $50 million indemnity for environmental liabilities arising from Pre-Acquisition Operations. In response to our aribitration claims, Tosco filed counterclaims in the Contra Cost Superior Court action alleging that we are contractually responsible for certain environmental liabilities at our California refinery, including certain liabilities arising from Pre-Acquisition Operations. We intend to vigorously prosecute our claims against Tosco and to oppose Tosco’s claims against us, although we cannot provide assurance that we will prevail.


	Environmental Capital

EPA regulations related to the Clean Air Act require reduction in the sulfur content in gasoline beginning, January 1, 2004. To meet the revised gasoline standard, we currently estimate we will make capital improvements of approximately $38 million through 2008 and an additional $8 million beyond 2008. 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, which does not include the potential impact of the recent EPA proposed rule for the sulfur content of off-road diesel fuel.

We expect to spend approximately $45 million in capital improvements through 2006 to comply with the Maximum Achievable Control Technologies standard for petroleum refineries (“Refinery MACT II”). These regulations require new emission controls at certain processing units at our refineries, including approximately $16 million at the North Dakota refinery and $29 million at the Washington refinery.

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

In connection with our 2001 acquisition of our North Dakota and Utah refineries, Tesoro assumed the sellers’ obligations and liabilities under a consent decree among the United States, BP Exploration and Oil Co. (“BP”), Amoco Oil Company and Atlantic Richfield Company. BP entered into this consent decree for both the North Dakota and Utah refineries for various alleged violations. As the owner of these refineries, Tesoro is required to address issues, including leak detection and repair, flaring protection and sulfur recovery unit optimization. We currently estimate we will spend $7 million to comply with this consent decree, in addition to estimated expenditures of $16 million in 2004 for the installation of new emission control equipment at the North Dakota refinery to meet the 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 our 2002 acquisition of our California refinery, subject to certain conditions, Tesoro also assumed the seller’s obligations pursuant to settlement efforts with the EPA concerning the Section 114 refinery enforcement initiative under the Clean Air Act, except for any potential monetary penalties, which the seller retains. We believe these obligations will not have a material impact on Tesoro’s financial position.

We will need to spend additional capital at the California refinery for reconfiguring and replacing above-ground storage tank systems and upgrading piping within the refinery. We estimate that we may spend up to $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 various Tesoro sites, including, but not limited to, our refineries, tank farms, retail gasoline stations (operating and closed locations) and petroleum product terminals, and for compliance with the Clean Air Act and other federal, state and local requirements. We cannot currently determine the amounts of such future expenditures.


	Other

Union Oil Company of California has asserted claims against other refining companies for infringement of patents related to the production of certain reformulated gasoline. Our California refinery produces grades of gasoline that may be subject to similar claims. We have not paid or accrued liabilities for patent royalties that may be related to our California refinery’s production, since the U.S. Patent Office and the Federal Trade Commission are evaluating the validity of those patents.

Beginning in the early 1980’s, Tesoro Hawaii Corporation, Tesoro Alaska Company and other fuel suppliers entered a series of long-term, fixed-price fuel supply contracts with the U.S. Defense Energy Support Center (“DESC”). Each of the contracts contained an adjustable price that permitted the DESC to adjust prices. However, the Federal Acquisition Regulations (“FAR”) limits how prices may be adjusted. Tesoro and many of the other suppliers in separate suits in the Court of Federal Claims currently are seeking relief from the DESC’s price adjustments. Tesoro and the other suppliers allege that the DESC’s price adjustments violated FAR by not adjusting the price of fuel based on changes to the suppliers’ established prices or costs, as FAR requires. Tesoro and the other suppliers seek recovery of over $2.5 billion in underpayment for fuel. Tesoro’s share of the underpayment currently totals approximately $165 million although approximately $20 million of this amount is still pending at the administrative claims level. The DESC responded to Tesoro’s and the other suppliers claims by moving for partial summary judgment. In response, Tesoro and the other suppliers cross-moved for partial summary judgment. The Court of Federal Claims granted partial summary judgment for Tesoro, held that the DESC’s fuel prices were illegal, and rejected the DESC’s assertion that Tesoro waived its right to a remedy by entering the contracts. However, some of the other judges in the same court ruled on the cross-motions for other suppliers in conflict with the holding for Tesoro. As a result, Tesoro petitioned the Court of Appeals for the Federal Circuit to review its claims. Tesoro is seeking the Court of Appeals validation that the price adjustments were illegal and Tesoro did not waive its right to sue when it entered the contracts. Tesoro expects the appeal process to take approximately nine months and for the court to issue its decision by the end of 2004, but we cannot predict the outcome of our claims against the DESC.

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

NOTE Q — QUARTERLY FINANCIAL DATA (UNAUDITED)



			Quarters
															Total
			First			Second			Third			Fourth			Year


			(In millions except per share amounts)
2003
	Revenues		$	2,286.1		$	2,116.4		$	2,330.0		$	2,113.2		$	8,845.7
	Operating Income		$	79.5		$	67.1		$	159.6		$	28.6		$	334.8
	Net Earnings (Loss)		$	20.4		$	(7.0	)	$	70.6		$	(7.9	)	$	76.1
	Net Earnings (Loss) Per share:
		Basic	$	0.32		$	(0.11	)	$	1.09		$	(0.12	)	$	1.18
		Diluted	$	0.32		$	(0.11	)	$	1.09		$	(0.12	)	$	1.17
2002
	Revenues		$	1,232.6		$	1,736.8		$	2,148.5		$	2,001.4		$	7,119.3
	Operating Income (Loss)		$	(63.2	)	$	9.7		$	19.4		$	15.4		$	(18.7	)
	Net Loss		$	(55.6	)	$	(17.9	)	$	(15.8	)	$	(27.7	)	$	(117.0	)
	Net Loss Per Share:
		Basic	$	(1.15	)	$	(0.28	)	$	(0.24	)	$	(0.43	)	$	(1.93	)
		Diluted	$	(1.15	)	$	(0.28	)	$	(0.24	)	$	(0.43	)	$	(1.93	)

The results above include the California refinery operations since mid-May 2002.

During the 2003 fourth quarter, we terminated our funded executive security plan, resulting in a charge of $8.4 million, of which $6.9 million was a non-cash write-off of unamortized prepaid pension costs (See Note N). Also during the fourth quarter of 2003, we recorded pretax charges of $1.4 million for impairment losses on certain retail stations.

During the fourth quarter of 2002, we incurred a loss on assets sales and impairment totaling $7.9 million, primarily related to the sale of 70 retail gas stations in northern California and the sale/lease-back of 30 retail stations (see Note D). Also during the fourth quarter of 2002, Tesoro’s income tax benefit was reduced by $6.0 million due to the loss of tax credits claimed in earlier years (see Note H).


ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.


ITEM 9A.	CONTROLS AND PROCEDURES

We carried out an evaluation required by the Securities Exchange Act of 1934, as amended (the “Exchange Act”), under the supervision and with the participation of our management, including the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15 under the Exchange Act as of the end of the year. Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures are effective in alerting them on a timely basis to material information relating to the Company and required to be included in our periodic filings under the Exchange Act. During the fourth quarter of 2003, there have been no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART III


ITEM 10.	DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

Information required under this Item will be contained in the Company’s 2004 Proxy Statement, incorporated herein by reference. See also Executive Officers of the Registrant under Business in Item 1 hereof.

In February 2004, the Board of Directors of Tesoro adopted a code of business conduct and ethics, (“Code of Ethics”) that applies to its senior financial executives. You can access our Code of Ethics on our website at www.tesoropetroleum.com. The Code of Ethics is filed as Exhibit 14.1 to this annual report.

Tesoro’s code of business conduct is available on our website and you may receive a copy, free of charge by writing to Tesoro Petroleum Corporation, Attention: Investor Relations, 300 Concord Plaza Drive, San Antonio, Texas 78216-6999.


ITEM 11.	EXECUTIVE COMPENSATION

Information required under this Item will be contained in the Company’s 2004 Proxy Statement, incorporated herein by reference.


ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

Information required under this Item will be contained in the Company’s 2004 Proxy Statement, incorporated herein by reference.


ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Information required under this Item will be contained in the Company’s 2004 Proxy Statement, incorporated herein by reference.


ITEM 14.	PRINCIPAL ACCOUNTANT FEES AND SERVICES

Information required under this Item will be contained in the Company’s 2004 Proxy Statement, incorporated herein by reference.

PART IV


ITEM 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K

(a) 1. Financial Statements

The following consolidated financial statements of Tesoro Petroleum Corporation and its subsidiaries are included in Part II, Item 8 of this Form 10-K:


	Page

Independent Auditors’ Report		51
Statements of Consolidated Operations — Years Ended December 31, 2003, 2002 and 2001		52
Consolidated Balance Sheets — December 31, 2003 and 2002		53
Statements of Consolidated Stockholders’ Equity — Years Ended December 31, 2003, 2002 and 2001		54
Statements of Consolidated Cash Flows — Years Ended December 31, 2003, 2002 and 2001		55
Notes to Consolidated Financial Statements		56

2. Financial Statement Schedules

No financial statement schedules are submitted because of the absence of the conditions under which they are required or because the required information is included in the consolidated financial statements.

3. Exhibits


Exhibit
Number				Description of Exhibit

	2	.1	—	Stock Sale Agreement, dated March 18, 1998, among the Company, BHP Hawaii Inc. and BHP Petroleum Pacific Islands Inc. (incorporated by reference herein to Exhibit 2.1 to Registration Statement No. 333-51789).
	2	.2	—	Stock Sale Agreement, dated May 1, 1998, among Shell Refining Holding Company, Shell Anacortes Refining Company and the Company (incorporated by reference herein to the Company’s Quarterly Report on Form 10-Q for the period ended March 31, 1998, File No. 1-3473).
	2	.3	—	Stock Purchase Agreement, dated as of October 8, 1999, but effective as of July 1, 1999 among the Company, Tesoro Gas Resources Company, Inc., EEX Operating LLC and EEX Corporation (incorporated by reference herein to Exhibit 2.1 to the Company’s Current Report on Form 8-K filed on January 3, 2000, File No. 1-3473)
	2	.4	—	First Amendment to Stock Purchase Agreement dated December 16, 1999, but effective as of October 8, 1999, among the Company, Tesoro Gas Resources Company, Inc., EEX Operating Company, Tesoro Gas Resources Company, Inc., EEX Operating Company, Tesoro Gas Resources Company, Inc., EEX Operating LLC and EEX Corporation (incorporated by reference herein to Exhibit 2.2 to the Company’s Current Report on Form 8-K filed on January 3, 2000, File No. 1-3473).
	2	.5	—	Purchase Agreement dated as of December 17, 1999 among the Company, Tesoro Gas Resources Company, Inc. and EEX Operating LLC (Membership Interests in Tesoro Grande LLC) (incorporated by reference herein to Exhibit 2.3 to the Company’s Current Report on Form 8-K filed on January 3, 2000, File No. 1-3473).
	2	.6	—	Purchase Agreement dated as of December 17, 1999 among the Company, Tesoro Gas Resources Company, Inc. and EEX Operating LLC (Membership Interests in Tesoro Reserves Company LLC) (incorporated by reference herein to Exhibit 2.4 to the Company’s Current Report on Form 8-K filed on January 3, 2000, File No. 1-3473).


Exhibit
Number				Description of Exhibit

	2	.7	—	Purchase Agreement dated as of December 17, 1999 among the Company, Tesoro Gas Resources Company, Inc. and EEX Operating LLC (Membership Interests in Tesoro Southeast LLC) incorporated by reference herein to Exhibit 2.5 to the Company’s Current Report on Form 8-K filed on January 3, 2000, File No. 1-3473).
	2	.8	—	Stock Purchase Agreement, dated as of November 19, 1999, by and between the Company and BG International Limited (incorporated by reference herein to Exhibit 2.1 to the Company’s Current Report on Form 8-K filed on January 13, 2000, File No. 1-3473).
	2	.9	—	Asset Purchase Agreement, dated July 16, 2001, by and among the Company, BP Corporation North America Inc. and Amoco Oil Company (incorporated by reference herein to Exhibit 2.1 to the Company’s Current Report on Form 8-K filed on September 21, 2001, File No. 1-3473).
	2	.10	—	Asset Purchase Agreement, dated July 16, 2001, by and among the Company, BP Corporation North America Inc. and Amoco Oil Company (incorporated by reference herein to Exhibit 2.2 to the Company’s Current Report on Form 8-K filed on September 21, 2001, File No. 1-3473).
	2	.11	—	Asset Purchase Agreement, dated July 16, 2001, by and among the Company, BP Corporation North America Inc. and BP Pipelines (North America) Inc. (incorporated by reference herein to Exhibit 2.1 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2001, File No. 1-3473).
	2	.12	—	Sale and Purchase Agreement for Golden Eagle Refining and Marketing Assets, dated February 4, 2002, by and among Ultramar Inc. and Tesoro Refining and Marketing Company, including First Amendment dated February 20, 2002 and related Purchaser Parent Guaranty dated February 4, 2002, and Second Amendment dated May 3, 2002 (incorporated by reference herein to Exhibit 2.12 to the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2001, File No. 1-3473, and Exhibit 2.1 to the Company’s Current Report on Form 8-K filed on May 9, 2002, File No. 1-3473).
	3	.1	—	Restated Certificate of Incorporation of the Company (incorporated by reference herein to Exhibit 3 to the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 1993, File No. 1-3473).
	3	.2	—	By-Laws of the Company, as amended through June 6, 1996 (incorporated by reference herein to Exhibit 3.2 to the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 1996, File No. 1-3473).
	3	.3	—	Amendment to Restated Certificate of Incorporation of the Company adding a new Article IX limiting Directors’ Liability (incorporated by reference herein to Exhibit 3(b) to the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 1993, File No. 1-3473).
	3	.4	—	Certificate of Designation Establishing a Series A Participating Preferred Stock, dated as of December 16, 1985 (incorporated by reference herein to Exhibit 3(d) to the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 1993, File No. 1-3473).
	3	.5	—	Certificate of Amendment, dated as of February 9, 1994, to Restated Certificate of Incorporation of the Company amending Article IV, Article V, Article VII and Article VIII (incorporated by reference herein to Exhibit 3(e) to the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 1993, File No. 1-3473).
	3	.6	—	Certificate of Amendment, dated as of August 3, 1998, to Certificate of Incorporation of the Company, amending Article IV, increasing the number of authorized shares of Common Stock from 50,000,000 to 100,000,000 (incorporated by reference herein to Exhibit 3.1 to the Company’s Quarterly Report on Form 10-Q for the period ended September 30, 1998, File No. 1-3473).
	4	.1	—	Form of Coastwide Energy Services Inc. 8% Convertible Subordinated Debenture (incorporated by reference herein to Exhibit 4.3 to Post-Effective Amendment No. 1 to Registration No. 333-00229).


Exhibit
Number				Description of Exhibit

	4	.2	—	Debenture Assumption and Conversion Agreement dated as of February 20, 1996, between the Company, Coastwide Energy Services, Inc. and CNRG Acquisition Corp. (incorporated by reference herein to Exhibit 4.4 to Post-Effective Amendment No. 1 to Registration No. 333-00229).
	4	.3	—	Indenture, dated as of July 2, 1998, between Tesoro Petroleum Corporation and U.S. Bank Trust National Association, as Trustee (incorporated by reference herein to Exhibit 4.4 to Registration Statement No. 333-59871).
	4	.4	—	Form of 9% Senior Subordinated Notes due 2008 and 9% Senior Subordinated Notes due 2008, Series B (incorporated by reference herein to Exhibit 4.5 to Registration Statement No. 333-59871).
	4	.5	—	Indenture, dated as of November 6, 2001, between Tesoro Petroleum Corporation and U.S. Bank Trust National Association, as Trustee (incorporated by reference herein to Exhibit 4.8 to Registration Statement No. 333-75056).
	4	.6	—	Form of 9 5/8% Senior Subordinated Notes due 2008 and 9 5/8% Senior Subordinated Notes due 2008, Series B (incorporated by reference herein to Exhibit 4.7 to Registration Statement No. 333-92468).
	4	.7	—	Indenture, dated as of April 9, 2002, between Tesoro Escrow Corp. and U.S. Bank National Association, as Trustee (incorporated by reference herein to Exhibit 4.9 to Registration Statement No. 333-84018).
	4	.8	—	Supplemental Indenture, dated as of May 17, 2002, among Tesoro Escrow Corp., Tesoro Petroleum Corporation, the subsidiary guarantors and U.S. Bank National Association, as Trustee (incorporated by reference herein to Exhibit 4.10 to Registration Statement No. 333-92468).
	4	.9	—	Form of 9 5/8% Senior Subordinated Notes due 2012 (incorporated by reference herein to Exhibit 4.10 to Registration Statement No. 333-84018).
	4	.10	—	Credit and Guaranty Agreement related to Senior Secured Term Loans Due 2008, dated as of April 17, 2003, among Tesoro Petroleum Corporation, certain subsidiary guarantors, Goldman Sachs Credit Partners L.P., as Administrative Agent, and Goldman Sachs Credit Partners L.P., as Sole Lead Arranger, Sole Bookrunner and Syndication Agent (incorporated by reference herein to Exhibit 4.11 to Registration Statement No. 333-105783).
	4	.11	—	Pledge and Security Agreement related to Senior Secured Term Loans Due 2008 and 8% Senior Secured Notes due 2008, dated as of April 17, 2003, among Tesoro Petroleum Corporation, certain subsidiary guarantors and Wilmington Trust Company, as Collateral Agent (incorporated by reference herein to Exhibit 4.12 to Registration Statement No. 333-105783).
	4	.12	—	Collateral Agency Agreement related to Senior Secured Term Loans Due 2008 and 8% Senior Secured Notes due 2008, dated as of April 17, 2003, among Tesoro Petroleum Corporation, certain subsidiary guarantors, Goldman Sachs Credit Partners L.P., The Bank of New York Trust Company and Wilmington Trust Company (incorporated by reference herein to Exhibit 4.13 to Registration Statement No. 333-105783).
	4	.13	—	Control Agreement related to Senior Secured Tem Loans due 2008 and 8% Senior Secured Notes due 2008, dated as of May 16, 2003, among Tesoro Petroleum Corporation, Wilmington Trust Company, as Collateral Agent, and Frost Bank, as Depositary Agent (incorporated by reference herein to Exhibit 4.14 to Registration Statement No. 333-105783).
	10	.1	—	$650,000,000 Second Amended and Restated Credit Agreement, dated as of June 17, 2003, among the Company, Goldman Sachs Credit Partners L.P. (the syndication agent), Bank One, NA (the administrative agent) and a syndicate of banks, financial institutions and other entities (incorporated by reference herein to Exhibit 10.43 to Amendment No. 1 to Registration Statement No. 333-105783).
	10	.2	—	Security Agreement dated as of April 17, 2003, by and between the Company, certain of its subsidiary parties thereto and Bank One NA as Agent (incorporated by reference herein to Exhibit 10.44 to Amendment No. 1 to Registration Statement No. 333-105783).


Exhibit
Number				Description of Exhibit

	10	.3	—	Affirmation of Security Agreement and Guarantee dated as of June 17, 2003 by certain of the Company’s subsidiary parties thereto (incorporated by reference herein to Exhibit 10.45 to Amendment No. 1 to Registration Statement No. 333-105783).
	*10	.4	—	Amendment No. 1 to the $650,000,000 Second Amended and Restated Credit Agreement, dated as of February 20, 2004, among the Company, Bank One, NA (the administrative agent) and a syndicate of banks, financial institutions and other entities.
	*10	.5	—	Amendment No. 2 to the $650,000,000 Second Amended and Restated Credit Agreement, dated as of February 20, 2004, among the Company, Bank One, NA (the administrative agent) and a syndicate of banks, financial institutions and other entities.
	10	.6	—	Second Amendment to the Company’s Amended and Restated Executive Long-Term Incentive Plan effective as of May 1, 2003 (incorporated by reference herein to Exhibit 10.33 to Registration Statement No. 333-105783).
	10	.7	—	$100 million Promissory Note, dated as of May 17, 2002, payable by the Company to Ultramar Inc. (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on May 24, 2002, File No. 1-3473).
	10	.8	—	$50 million Promissory Note, dated as of May 17, 2002, payable by the Company to Ultramar Inc. (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on May 24, 2002, File No. 1-3473).
	†10	.9	—	The Company’s Amended Executive Security Plan, as amended through November 13, 1989, and Funded Executive Security Plan, as amended through February 28, 1990, for executive officers and key personnel (incorporated by reference herein to Exhibit 10(f) to the Company’s Annual Report on Form 10-K for the fiscal year ended September 30, 1990, File No. 1-3473).
	†10	.10	—	Sixth Amendment to the Company’s Amended Executive Security Plan and Seventh Amendment to the Company’s Funded Executive Security Plan, both dated effective March 6, 1991 (incorporated by reference herein to Exhibit 10(g) to the Company’s Annual Report on Form 10-K for the fiscal year ended September 30, 1991, File No. 1-3473)
	†10	.11	—	Seventh Amendment to the Company’s Amended Executive Security Plan and Eighth Amendment to the Company’s Funded Executive Security Plan, both dated effective December 8 1994 (incorporated by reference herein to Exhibit 10(f) to the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 1994, File No. 1-3473).
	†10	.12	—	Eighth Amendment to the Company’s Amended Executive Security Plan and Ninth Amendment to the Company’s Funded Executive Security Plan, both dated effective June 6, 1996 (incorporated by reference herein to Exhibit 10.5 to the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 1998, File No. 1-3473).
	†10	.13	—	Ninth Amendment to the Company’s Amended Executive Security Plan and Tenth Amendment to the Company’s Funded Executive Security Plan, both dated effective October 1, 1998 (incorporated by reference herein to Exhibit 10.6 to the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 1998, File No. 1-3473).
	*†10	.14	—	Amended and Restated Employment Agreement between the Company and Bruce A. Smith dated December 3, 2003.
	†10	.15	—	Amended and Restated Employment Agreement between the Company and William T. Van Kleef dated as of October 28, 1998 (incorporated by reference herein to Exhibit 10.9 to the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 1998, File No. 1-3473).
	†10	.16	—	Amended and Restated Employment Agreement between the Company and James C. Reed, Jr. dated as of October 28, 1998 (incorporated by reference herein to Exhibit 10.10 to the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 1998, File No. 1-3473).
	†10	.17	—	Management Stability Agreement between the Company and Thomas E. Reardon dated November 6, 2002.


Exhibit
Number				Description of Exhibit

	†10	.18	—	Management Stability Agreement between the Company and Susan A. Lerette dated November 6, 2002.
	†10	.19	—	Management Stability Agreement between the Company and Stephen L. Wormington dated November 6, 2002.
	†10	.20	—	Management Stability Agreement between the Company and Gregory A. Wright dated November 6, 2002.
	†10	.21	—	Management Stability Agreement between the Company and W. Eugene Burden dated November 6, 2002.
	†10	.22	—	Management Stability Agreement between the Company and Everett D. Lewis dated November 6, 2002.
	†10	.23	—	Management Stability Agreement between the Company and James L. Taylor dated November 6, 2002.
	†10	.24	—	Management Stability Agreement between the Company and Daniel J. Porter dated September 6, 2001 (incorporated by reference herein to Exhibit 10.25 to Registration Statement No. 333-75056).
	†10	.25	—	Management Stability Agreement between the Company and Rick D. Weyen dated September 6, 2001 (incorporated by reference herein to Exhibit 10.26 to Registration Statement No. 333-75056).
	†10	.26	—	Management Stability Agreement between the Company and Otto C. Schwethelm dated November 6, 2002.
	†10	.27	—	Management Stability Agreement between the Company and Rodney S. Cason dated November 6, 2002.
	†10	.28	—	Management Stability Agreement between the Company and Joseph M. Monroe dated November 6, 2002.
	†10	.29	—	Management Stability Agreement between the Company and Alan R. Anderson dated November 6, 2002.
	†10	.30	—	Management Stability Agreement between the Company and J. William Haywood dated November 6, 2002.
	†10	.31	—	Management Stability Agreement between the Company and G. Scott Spendlove dated January 24, 2002 (incorporated by reference herein to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2002, File No. 1-3473.)
	*†10	.32	—	Management Stability Agreement between the Company and William J. Finnerty dated December 1, 2003.
	†10	.33	—	Copy of the Company’s Key Employee Stock Option Plan dated November 12, 1999 (incorporated by reference herein to Exhibit 10.3 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2002, File No. 1-3473.)
	†10	.34	—	Copy of the Company’s Amended and Restated Executive Long-Term Incentive Plan, as amended through May 25, 2000 (Company’s Registration Statement No. 333-39070 filed on Form S-8).
	†10	.35	—	Amendment to the Company’s Amended and Restated Executive Long-Term Incentive Plan effective as of June 20, 2002 (incorporated by reference herein to Exhibit 10.31 to the (incorporated by reference herein to Exhibit 10.31 to the Company’s Registration Statement No. 333-92468).
	†10	.36	—	Copy of the Company’s Non-Employee Director Retirement Plan dated December 8, 1994 (incorporated by reference herein to Exhibit 10(t) to the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 1994, File No. 1-3473).
	†10	.37	—	Amended and Restated 1995 Non-Employee Director Stock Option Plan, as amended through March 15, 2000 (incorporated by reference herein to Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2002, File No. 1-3473.)


Exhibit
Number				Description of Exhibit

	†10	.38	—	Amendment to the Company’s Amended and Restated 1995 Non-Employee Director Stock Option Plan (incorporated by reference herein to Exhibit 10.40 to the Company’s Registration Statement No. 333-92468).
	†10	.39	—	Copy of the Company’s Board of Directors Deferred Compensation Plan dated February 23, 1995 (incorporated by reference herein to Exhibit 10(u) to the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 1994, File No. 1-3473).
	†10	.40	—	Copy of the Company’s Board of Directors Deferred Compensation Trust dated February 23, 1995 (incorporated by reference herein to Exhibit 10(v) to the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 1994, File No. 1-3473).
	†10	.41	—	Copy of the Company’s Board of Directors Deferred Phantom Stock Plan (incorporated by reference herein to Exhibit 10 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 1997, File No. 1-3473).
	†10	.42	—	Phantom Stock Option Agreement between the Company and Bruce A. Smith dated effective October 29, 1997 (incorporated by reference herein to Exhibit 10.20 to the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 1997, File No. 1-3473).
	10	.43	—	Form of Indemnification Agreement between the Company and its officers and directors (incorporated by reference herein to Exhibit B to the Company’s Proxy Statement for the Annual Meeting of Stockholders held on February 25, 1987, File No. 1-3473).
	10	.44	—	Letter dated May 5, 2002 from the Company to the State of California Department of Justice, Office of Attorney General (incorporated by reference to Exhibit 10.3 to the Company’s Current Report on For 8-K filed on May 24, 2002, File No. 1-3473; portions of this document have been omitted pursuant to a request for confidential treatment).
	*14	.1	—	Code of Business Conduct and Ethics for Senior Financial Executives.
	*21	.1	—	Subsidiaries of the Company.
	*23	.1	—	Consent of Deloitte & Touche LLP.
	*31	.1	—	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
	*31	.2	—	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
	*32	.1	—	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
	*32	.2	—	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.


*	Filed herewith.


†	Identifies management contracts or compensatory plans or arrangements required to be filed as an exhibit hereto pursuant to Item 14(c) of Form 10-K.

Schedules not listed above are omitted because of the absence of the conditions under which they are required or because the information required by such omitted schedules is set forth in the financial statements or the notes thereto.

Copies of exhibits filed as part of this Form 10-K may be obtained by stockholders of record at a charge of $0.15 per page, minimum $5.00 each request. Direct inquiries to the Corporate Secretary, Tesoro Petroleum Corporation, 300 Concord Plaza Drive, San Antonio, Texas, 78216-6999.

(b) Reports on Form 8-K

On October 28, 2003, a Current Report on Form 8-K was filed reporting under Item 9, Regulation FD Disclosure, that the Company had issued a press release announcing an agreement to sell its Marine Services assets and reporting that earnings per share for the 2003 third quarter are expected to exceed the current First Call consensus. The press release was filed as an Exhibit under Item 7.

On November 5, 2003, a Current Report on Form 8-K was filed reporting under Item 12, Results of Operations and Financial Condition, that the Company had issued a press release reporting its third quarter 2003 earnings. The press release was filed as an Exhibit under Item 7.

On February 3, 2004, a Current Report on Form 8-K was filed reporting under Item 12, Results of Operations and Financial Condition, that the Company had issued a press release reporting its financial results for the fourth quarter and year ended December 31, 2003. The press release was filed as an Exhibit under Item 7.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized


	TESORO PETROLEUM CORPORATION


	By:	/s/ BRUCE A. SMITH



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

Dated: March 11, 2004

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.



Signature	Title	Date


/s/ BRUCE A. SMITH Bruce A. Smith	Chairman of the Board of Directors, President and Chief Executive Officer (Principal Executive Officer)	March 11, 2004

/s/ GREGORY A. WRIGHT Gregory A. Wright	Executive Vice President and Chief Financial Officer (Principal Financial Officer)	March 11, 2004

/s/ OTTO C. SCHWETHELM Otto C. Schwethelm	Vice President and Controller (Principal Accounting Officer)	March 11, 2004

/s/ STEVEN H. GRAPSTEIN Steven H. Grapstein	Lead Director	March 11, 2004

/s/ WILLIAM J. JOHNSON William J. Johnson	Director	March 11, 2004

/s/ A. MAURICE MYERS A. Maurice Myers	Director	March 11, 2004

/s/ DONALD H. SCHMUDE Donald H. Schmude	Director	March 11, 2004

/s/ PATRICK J. WARD Patrick J. Ward	Director	March 11, 2004