TESORO PETROLEUM CORP /NEW/ - 10-K Annual Report

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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

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FORM 10-K

(MARK ONE)

[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2001

OR

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

FOR THE TRANSITION PERIOD FROM .... TO ....

COMMISSION FILE NUMBER 1-3473

TESORO PETROLEUM CORPORATION
(Exact name of registrant as specified in its charter)

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

300 CONCORD PLAZA DRIVE, SAN ANTONIO, TEXAS 78216-6999
(Address of principal executive offices) (Zip Code)

REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE:
210-828-8484

SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:

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 [X] No [ ]

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. [ ]

At February 1, 2002, the aggregate market value of the voting stock held by
nonaffiliates of the registrant was approximately $566,044,885 based upon the
closing price of its common stock on the New York Stock Exchange Composite tape.
At February 1, 2002, there were 41,445,297 shares of the registrant's common
stock outstanding.

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TESORO PETROLEUM CORPORATION

ANNUAL REPORT ON FORM 10-K

TABLE OF CONTENTS

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.

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PART I

ITEM 1. BUSINESS

We are an independent refiner and marketer with three operating
segments -- (1) refining crude oil and other feedstocks and selling petroleum
products in bulk and wholesale markets ("Refining"), (2) selling motor fuels and
convenience products and services in the retail market ("Retail") and (3)
providing petroleum products and logistics services to the marine and offshore
exploration and production industries ("Marine Services"). Through our Refining
segment, we manufacture products including primarily gasoline and gasoline
blendstocks, jet fuel, diesel fuel and residual fuel for sale to a wide variety
of commercial customers in the United States and countries in the Pacific Rim.
Our Retail segment distributes gasoline through a retail network of gas stations
under the Tesoro, Mirastar, Tesoro Alaska and other brands. Our Marine Services
segment markets and distributes a broad range of petroleum products, chemicals
and supplies and provides logistical support services to the marine and offshore
exploration and production industries operating in the Gulf of Mexico. We are
evaluating various strategic opportunities (including a possible sale of all or
a part of this business) to capitalize on the value of our Marine Service
assets.

See Note D of Notes to Consolidated Financial Statements in Item 8 for
additional segment information.

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.

REFINERY AND RETAIL GROWTH

On September 6, 2001, we acquired two refineries in North Dakota and Utah
and related storage, distribution and retail assets from certain affiliates of
BP p.l.c. ("BP"). The acquired assets include a 60,000 barrels per day ("bpd")
refinery in Mandan, North Dakota and a 55,000 bpd refinery in Salt Lake City,
Utah. The acquired assets also include related bulk storage facilities, eight
product distribution terminals, and retail assets consisting of 42 retail
stations and contracts to supply a jobber network of over 280 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
("Pipeline System") from certain affiliates of BP on November 1, 2001. The
Pipeline System is the primary crude supply carrier for our Mandan, North Dakota
refinery. We assumed certain liabilities and obligations (including costs
associated with transferred employees and environmental matters) related to the
acquired assets, subject to specified levels of indemnification. The
Mid-Continent Acquisition enabled us to increase the size and scope of our
operations and diversify our earnings and geographic exposure. The Mid-Continent
Acquisition increased our number of refineries from three to five, with
aggregate crude oil refining capacity rising from 275,000 bpd to 390,000 bpd. We
paid $756.1 million in cash (including $83.0 million for hydrocarbon
inventories) for these assets.

In November 2001, we acquired 46 retail fueling facilities, including 37
retail stations with convenience stores and nine commercial cardlock facilities,
located in Washington, Oregon and Idaho from a privately-held company based in
Seattle, Washington.

PENDING ACQUISITION OF THE GOLDEN EAGLE ASSETS

We entered into a sale and purchase agreement with Ultramar Inc., a
subsidiary of Valero Energy Corporation, on February 4, 2002, which was amended
on February 20, 2002. We agreed to acquire the 168,000 bpd Golden Eagle refinery
located in Martinez, California near the San Francisco Bay Area along with 70
associated retail sites throughout northern California (collectively, the
"Golden Eagle Assets"). The purchase price for the Golden Eagle Assets is $995
million plus the value of feedstock and refined product inventories at closing,
assumed to be $130 million.

We expect the pending acquisition of the Golden Eagle Assets to increase
our combined rated crude oil capacity by more than 40% to 558,000 bpd. In
addition, we expect our branded retail network will expand to approximately 750
locations, including nearly 100 stations in California. We intend to close the
pending acquisition of the Golden Eagle Assets, which is subject to customary
conditions and approval by the Federal

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Trade Commission and the Attorneys General of the States of California and
Oregon, in April 2002. We intend to finance the acquisition with a combination
of debt (including an amendment to our senior secured credit facility) and
public or private equity.

In addition to paying the purchase price for the Golden Eagle Assets, upon
the closing of the acquisition, we have agreed to assume a substantial portion
of the seller's obligations, responsibilities, liabilities, costs and expenses
arising out of or incurred in connection with the operation of the Golden Eagle
Assets. This includes, subject to certain exceptions, certain of the seller's
obligations, liabilities, costs and expenses for violations of environmental
compliance matters relating to the assets, including certain known and unknown
obligations, liabilities, costs and expenses arising or incurred prior to, on or
after the closing date. Subject to certain conditions, we also have agreed to
assume the seller's obligations pursuant to its settlement efforts with the
Environmental Protection Agency ("EPA") concerning the Section 114 refinery
enforcement initiative under the Clean Air Act, except for any potential
monetary penalties, which the seller will retain. See "Environmental Controls
and Expenditures -- Pending Acquisition of Golden Eagle Assets."

Following the closing of the pending acquisition of the Golden Eagle
Assets, we also will assume and take assignment of certain of the seller's
obligations and rights (including certain indemnity rights) arising out of or
related to the agreement pursuant to which the seller purchased the refinery in
2000 from Tosco Corporation. The seller has agreed to use commercially
reasonable efforts to persuade Phillips Petroleum Company, as successor to Tosco
Corporation ("Phillips"), to consent to this assignment, including the seller's
rights to indemnification of up to $50 million on environmental matters existing
prior to the seller's acquisition of the Golden Eagle Assets. If the seller
cannot obtain a consent from Phillips, the seller has agreed to provide us with
a "back-to-back" indemnity that will indemnify us against any liability for
which the seller is entitled to recover under the corresponding indemnity. The
seller's indemnity, however, is non-recourse to the seller and is limited to
amounts the seller actually receives from Phillips, less any legal or other
enforcement costs the seller incurs. Therefore, the indemnification that we may
be entitled to receive may not be sufficient to cover any losses or damages we
incur.

REFINING SEGMENT

OVERVIEW

We currently own and operate petroleum refineries in Alaska and Washington
(the "Pacific Northwest"), Hawaii (the "Mid-Pacific") and North Dakota and Utah
(the "Mid-Continent") and sell refined products to a wide variety of customers
in the mid-continental and western continental United States, Hawaii, Alaska and
countries in the Pacific Rim. During 2001, products from our refineries
accounted for approximately 79% of our sales volumes, with the remaining 21%
purchased from other refiners and suppliers.

Our five refineries have a combined rated crude oil capacity of 390,000
bpd. We operate the largest refineries in Hawaii and Utah, the second largest
refinery in Alaska and the only refinery in North Dakota. Capacity and actual
throughput rates of crude oil and other feedstocks by refinery are as follows:

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(a) Throughput volumes include the Mid-Continent refineries since we acquired
them on September 6, 2001, averaged over 365 days. Throughput averaged over
the 117 days that we owned the Mid-Continent refineries in 2001 was 53,500
bpd in North Dakota and 51,500 bpd in Utah. Prior to 2001, we believe that
annual throughput averaged 50,600 bpd and 54,500 bpd at the North Dakota
refinery in 2000 and 1999, respectively, and 51,100 bpd and 50,700 bpd at
the Utah refinery in 2000 and 1999, respectively.

At the Washington refinery, throughput was higher than the rated crude oil
capacity in 2001 and 2000 due to operational improvements and the processing of
other feedstocks in addition to crude oil. Throughput at the Alaska refinery has
been below capacity levels, reflecting supply, demand and marketing economics in
the region. Scheduled refinery maintenance turnarounds temporarily reduced
throughput in Utah in 2001 and 2000, in Hawaii and North Dakota in 2000 and in
Washington and Alaska in 1999.

In 2001, our refinery system received 13% of its crude oil input from
domestic mid-continental sources, 40% from foreign sources (including 16% from
Canada), 33% from Alaska's North Slope, 11% from Alaska's Cook Inlet and 3% from
other sources. As shown in the table below, in 2001, approximately 45% of our
total refinery system throughput was heavy crude oil, compared with 42% in 2000.
Actual throughput of crude oil and other feedstocks are summarized below:

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(a) Throughput volumes include 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
105,000 bpd. Prior to 2001, we believe that annual throughput at the
Mid-Continent refineries averaged 101,700 bpd in 2000 and 105,200 bpd in
1999.

We purchase feedstock for the refineries through term agreements and in the
spot market. We purchase Alaska Cook Inlet, Alaska North Slope, Canadian and
North Dakota crude oils from several suppliers under term agreements with
renewal provisions. Prices under the term agreements fluctuate with market
prices.

We term charter three double-hull U.S. flag tankers to transport crude oil
and refined products. One of the charters has a three-year primary term that
began in May 2000 and two one-year renewal options. In March 2001, we entered
into a charter for a double-hull sister ship for a two-year initial term with an
option to renew for an additional year. In the second half of 2001, we entered
into a one-year term charter on a third

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U.S. flag vessel. We also charter other tankers and ocean-going barges on a
short-term basis to transport crude oil and petroleum products.

Our refinery system yield consists primarily of gasoline and gasoline
blendstocks, jet fuel, diesel fuel and residual fuel oil. We also manufacture
other products, including liquefied petroleum gas and liquid asphalt. Our
refinery system yield, in volume and as a percentage, is summarized below:

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

We operate refined product terminals in the following states:

- Alaska -- Anchorage and Kenai;

- California -- Port Hueneme and Stockton;

- Hawaii -- on the islands of Hawaii, Kauai, Maui and Oahu;

- Idaho -- Boise and Burley;

- Minnesota -- Minneapolis/St. Paul, Moorehead and Sauk Center;

- North Dakota -- Jamestown and Mandan;

- Utah -- Salt Lake City; and

- Washington -- Anacortes, Port Angeles and Vancouver.

In addition, we distribute products through third-party terminals and truck
racks in our market areas. Terminals we operate are supplied primarily by our
refineries. Fuel distributed through third-party terminals

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also is supplied by our refineries and through purchases and exchange
arrangements with other refining and marketing companies.

PACIFIC NORTHWEST REFINERIES

Washington

Refining. The Washington refinery, located in Anacortes on the Puget
Sound, about 60 miles north of Seattle, includes fluid catalytic cracking
("FCC"), alkylation, hydrotreating, vacuum distillation and catalytic reformer
units. The FCC and other product upgrade units enable the Washington refinery to
produce about 75% to 85% of its output as gasoline (including cleaner-burning
CARB gasoline), diesel and jet fuel, depending on the mix of crude oil and other
feedstock throughput. The FCC unit also can upgrade heavy vacuum gas oils from
the Alaska and Hawaii refineries and other suppliers. In December 1999, the
Washington refinery completed the installation of a distillate treater that
increased production of low-sulfur diesel and jet fuels. A turnaround of the FCC
and alkylation units is expected to be completed during the first quarter of
2002.

We commenced a heavy oil conversion project at our Washington refinery in
2000, which will enable us to process a larger proportion of lower-cost heavy
crude oils, to manufacture a larger proportion of higher-value gasoline and to
reduce production of lower-value heavy products. We expect to spend
approximately $116 million (including capitalized interest) for this project, of
which $97 million has been spent through December 31, 2001. The de-asphalting
unit, one of the major components of the heavy oil conversion project, has been
in operation since late September 2001. The upgrade of the FCC unit, the final
major component of the heavy oil conversion project, is in progress and we
expect it to be fully operational by the end of the first quarter of 2002.

Crude Oil Supply. The Washington refinery's crude oil is sourced primarily
from Alaska, Canada and Southeast Asia. We receive crude oil from Canada at the
Washington refinery through a third-party pipeline system. Other feedstock is
delivered by tanker at the Washington refinery's marine terminal at Anacortes.
We supply intermediate feedstocks, primarily heavy vacuum gas oil, from some of
our other refineries and by spot market purchases from third-party refineries.

Transportation. The Washington refinery receives crude oil from Canada
through the 24-inch, third-party Transmountain Pipeline, which originates in
Edmonton, Canada. We receive other crude oil through the Washington refinery's
marine terminal. The pipeline and the marine terminal are each capable of
providing 100% of the Washington refinery's feedstock needs. During 2001, the
Washington refinery shipped approximately 24,000 bpd of high-value products
(gasoline, jet fuel and diesel) via the third-party Olympic pipeline system,
which serves the Seattle, Washington area with 16-inch and 20-inch lines and
continues to Portland, Oregon with a 14-inch line. In February 2002, the Olympic
pipeline system increased its tariff rate by 24.3%. We have challenged the
interim tariff and, if successful, will receive a rebate for pipeline tariffs we
pay after February 1, 2002, equal to the difference between the interim rate and
the final approved rate. We also deliver gasoline through a neighboring
refinery's truck rack, and we distribute some diesel fuel through a truck rack
at our refinery. We also ship products by barge and ship. The Washington
refinery can deliver significant volumes of products through our marine terminal
to ships and barges. We ship all of the fuel oil production by water. Propane
and asphalt are shipped by both truck and rail.

Terminals. We operate refined product terminals at Port Angeles and
Vancouver, Washington and at Stockton and Port Hueneme, California. In addition,
we distribute products through third-party terminals and truck racks in our
market areas. Terminals we operate are supplied primarily by our refineries.
Fuel distributed through third-party terminals also is supplied by our
refineries and through purchases and exchange arrangements with other refining
and marketing companies.

Alaska

Refining. The Alaska refinery is located near Kenai, Alaska, approximately
70 miles southwest of Anchorage, where it has access to Alaskan and imported
crude oil supplies. The Alaska refinery produces

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liquefied petroleum gas, gasoline and gasoline blendstocks, jet fuel, diesel
fuel, heating oil, liquid asphalt, heavy oils and residual products. The
refinery has a total rated crude oil capacity of 72,000 bpd and is the second
largest refinery in the state. We completed a scheduled maintenance turnaround
of all major process units at the Alaska refinery in the second quarter of 2001,
and the next turnaround is scheduled for the second quarter of 2003.

Crude Oil Supply. The Alaska refinery runs primarily the Alaska Cook Inlet
crude oil that is produced close to the refinery. To a lesser extent, the
refinery also runs Alaska North Slope and other crude oils. We deliver crude oil
by tanker to the Alaska refinery through the Kenai Pipe Line Company marine
terminal, which is a Tesoro-owned common carrier and marine dock facility, and
to the Kenai Pipe Line Company marine terminal by pipeline connected directly
with some of the Cook Inlet producing fields.

Transportation. We own and operate a common-carrier petroleum products
pipeline, which runs from the Alaska refinery to our terminal facilities in
Anchorage and to the Anchorage airport. This ten-inch diameter pipeline has the
capacity to transport approximately 40,000 bpd of products and allows us to
transport light products to the terminal facilities throughout the year,
regardless of weather conditions. We also own and operate a common-carrier
pipeline and Kenai Pipe Line Company marine terminal, adjacent to the Alaska
refinery, for unloading crude oil feedstocks and loading product inventory on
tankers and barges.

Terminals. We operate refined product terminals at Kenai and Anchorage,
Alaska. In addition, we distribute products through third-party terminals and
truck racks in our market areas. The terminals we operate are supplied primarily
by our refineries. Fuel distributed through third-party terminals also is
supplied by our refineries and through purchases and exchange arrangements with
other refining and marketing companies.

MID-PACIFIC REFINERY

Hawaii

Refining. The Hawaii refinery, located at Kapolei in an industrial park 22
miles west of Honolulu, produces liquified petroleum gas, gasoline and gasoline
blendstocks, jet fuel, diesel fuel and fuel oil. The refinery has a total rated
crude oil capacity of 95,000 bpd and is the largest refinery in the state. Major
product upgrade units include the distillate hydrocracker, vacuum distillation
and catalytic reformer units. We completed a planned maintenance turnaround in
September 2000, and the next major turnaround is scheduled for the third quarter
of 2003.

Crude Oil Supply. The Hawaii refinery's crude oil supply is sourced
primarily from Alaska, Australia and Southeast Asia. We receive crude oil for
the Hawaii refinery through our single-point mooring terminal and pipeline
system that also can be used for receiving and loading refined products.

Transportation. Crude oil is transported to Hawaii by tankers and
discharged through our single-point mooring terminal, about 1.5 miles offshore
from the Hawaii refinery. Three underwater pipelines connect the single-point
mooring terminal to the Hawaii refinery to allow crude oil and products to be
transferred to the Hawaii refinery and to load products from the Hawaii refinery
to ships and barges. We distribute refined products to customers on the island
of Oahu through a pipeline system, which includes connections to the military at
several locations. We also distribute refined products to commercial customers
via 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 Maui, Kauai and Hawaii. Our product pipelines connect the Hawaii refinery to
Barbers Point Harbor, 2.5 miles away, which is able to accommodate barges and
product tankers up to 800 feet in length and reduces traffic at the single-point
mooring terminal.

Terminals. We operate refined product terminals in Hawaii on the islands
of Hawaii, Kauai, Maui and Oahu. In addition, we distribute products through
third-party terminals and truck racks in our market areas. Terminals we operate
are supplied primarily by our refineries. Fuel distributed through third-party
terminals also is supplied by our refineries and through purchases and exchange
arrangements with other refining and marketing companies.

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MID-CONTINENT REFINERIES

North Dakota

Refining. The North Dakota refinery is located near Mandan, North Dakota
on 960 acres of land. The 60,000 bpd refinery is the only one in the state and
serves both in-state needs and those of neighboring Minnesota. The refinery
produces a slate of high-value products derived primarily from local crude oil
supplies in the Williston Basin and also some Canadian crude oil, which both
reach the refinery through the Pipeline System. The North Dakota refinery
produces approximately 60% gasoline, 30% distillates and 10% other products. A
maintenance turnaround is scheduled at the North Dakota refinery in the third
quarter of 2003.

Crude Oil Supply. The North Dakota refinery's crude oil is sourced
primarily from local Williston Basin sweet crude oil. Although the current
tariff structure makes local crude oil more economic, the refinery also has
access to other sources of crude oil.

The Pipeline System consists of over 700 miles of pipeline and delivers all
of the North Dakota refinery's crude oil requirements as well as some crude oil
requirements to regional points where there is additional demand. The Pipeline
System is configured to gather crude oil from the local Williston Basin and
adjacent production areas in North Dakota and Montana and transport it to the
North Dakota refinery. The Pipeline System is a common carrier transporting
crude oil subject to regulation by various local, state and federal agencies,
including the Federal Energy Regulatory Commission. We have entered into a
transition services agreement (as amended) for BP to operate the Pipeline System
on our behalf until December 15, 2002.

Transportation. Our refined product pipeline system distributes
approximately 85% of the North Dakota refinery's product. The main product
pipeline is approximately 430 miles and has a capacity of approximately 50,000
bpd. All gasoline and distillate products produced at the North Dakota refinery,
with the exception of railroad-spec diesel fuel, can be shipped on the line to
downstream terminals. An additional pipeline provides railroad-spec diesel fuel
via a five-mile, 5,000 bpd pipeline to the Burlington Northern rail yard in
Bismark, North Dakota. We have entered into a transition services agreement (as
amended) for BP to operate the refined products pipeline on our behalf until
December 15, 2002.

Terminals. The main product pipeline of our refined product pipeline
system connects the refinery to five owned product marketing terminals located
in: (1) Mandan, at the North Dakota refinery; (2) Jamestown, North Dakota; (3)
Moorehead, Minnesota; (4) Sauk Center, Minnesota; and (5) the Minneapolis/ St.
Paul, Minnesota area. Total capacity for all five terminals is 2,830,000
barrels.

Offtake Agreements. In connection with the Mid-Continent Acquisition, we
entered into certain offtake agreements with BP for a portion of our refined
products produced at these refineries. The offtake agreements related to the
North Dakota refinery commit approximately 30,470 bpd (which represents
approximately 59% of the historical three-year average production of 51,770 bpd)
of the North Dakota refinery product for each of the first three years. In years
four and five the commitment is reduced. Volumes related to the Minneapolis/ St.
Paul terminal, committed over five years, will decline after year three. BP
initially will receive approximately 68% of the committed product via the
Minneapolis/St. Paul terminal with the remainder distributed through the other
Minnesota and North Dakota terminals. These agreements provide a stable
distribution channel for our product, while allowing time to form relationships
and seek new outlets for future product distribution. Sales prices under the
offtake agreements are based on market prices at the time of sale.

Utah

Refining. The Utah refinery is located in Salt Lake City. The 55,000 bpd
refinery is the largest in the state of Utah and is well-positioned to supply
products to the growing Utah and Idaho marketing areas. The refinery produces a
high-value product slate from Canadian and Rocky Mountain crude oil, which it
receives via pipeline and truck from fields in Utah, Colorado, Wyoming and
Canada. The Utah refinery's primary products include gasoline, diesel fuel and
jet fuel, which are shipped via pipeline, rail car or truck to markets in Utah,
Idaho, Wyoming, Nevada, Oregon and Washington. A maintenance turnaround is
scheduled at the Utah refinery in the first quarter of 2003.

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Crude Oil Supply. The Utah refinery processes a low sulfur crude oil slate
and has the flexibility to process different crude oils. As local crude oil
supplies decline, local capacity can be replaced with Canadian Light Sweet or
Syncrude. Local crude oils are delivered primarily via the Amoco "U" Pipeline.
Canadian crude oil and other domestic crudes are delivered primarily through
another pipeline system. The price of local crude oil is primarily based on the
Canadian import alternative.

Transportation. The Utah refinery's products are distributed through a
system of both owned and third-party terminals and third-party pipeline
connections primarily in Utah and Idaho, with some incremental product to
Nevada, Washington and Wyoming.

Terminals. In addition to sales at the refinery, we distribute product
through the Chevron Pipeline to the two terminals we own at Boise and Burley,
Idaho and to two terminals we lease from Northwest Terminalling Company in
Pocatello, Idaho and Pasco, Washington. Total storage capacity for the three
owned terminals, including the Salt Lake City terminal, is 2,467,000 barrels. In
addition, the two leased terminals have an aggregate allocated throughput
capacity of 10,000 bpd.

Offtake Agreements. The offtake agreements for the Utah refinery represent
approximately 6,750 bpd of refined product produced (approximately 14% of the
historical three year-average production of 48,560 bpd) for periods ranging from
two years to three years, depending on the terminal. The commitment under the
agreements has limited gasoline volumes since we acquired substantially all of
BP's retail assets in the region. A majority of the product under the agreements
will be distributed through the Salt Lake City terminal. Sales prices under the
offtake agreements are based on market prices at the time of sale.

WHOLESALE MARKETING

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. Sources of our product sales include our
refinery system yield, products drawn from inventory balances and products
purchased from third parties. Our refined products sales in the Refining
segment, including intersegment sales to our Retail operations, consisted of the
following:

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

In August 2001, we opened an office in Long Beach, California to provide
supply and marketing activities in California and the southwestern United
States. Our goal is to establish a marketing operation in California capable of
providing us and other independent marketers in California with a competitive
and secure supply of products. To further these objectives, we lease
approximately 500,000 barrels of storage capacity with waterborne access in
southern California through September 2004.

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 (including Alaska and Hawaii). The demand for gasoline is
seasonal in a majority 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 the mid-continental and western United States. We also sell, at
wholesale, to unbranded jobbers. We distribute product through Tesoro-owned and
third-party terminals and truck racks.

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Although our marketing strategy in Hawaii and Alaska is to maximize in-state
sales, gasoline and gasoline components produced in excess of market demand may
be shipped to the U.S. West Coast or exported to other markets, principally in
the Asia/Pacific area.

We sell CARB quality blendstocks in the wholesale bulk market, generally at
higher values than conventional gasoline. We continue to evaluate several
additional projects at our existing refineries to increase our production
capacity of CARB products. In April 2001, we entered into a nonexclusive license
agreement that allows us to make and sell gasoline subject to patents held by
Union Oil Company of California, a subsidiary of Unocal Corporation. This
agreement removes uncertainty regarding patent royalties as we expand production
and marketing of cleaner-burning gasoline.

Jet Fuel. We are a major supplier of commercial jet fuel to passenger and
cargo airlines in Alaska and Hawaii and on the U.S. West Coast. We, along with
other marketers, import jet fuel into Alaska, Hawaii and the U.S. West Coast. We
primarily market commercial jet fuel at airports in Anchorage, Honolulu and
other Hawaiian island locations, as well as at major airports throughout the
western United States.

Diesel Fuel. We sell our diesel fuel production primarily on a wholesale
basis for marine, transportation, industrial and agricultural purposes, as well
as for home heating. We sell lesser amounts to end-users through marine
terminals and for power generation in Hawaii and Washington. Generally, the
production of diesel fuel by refiners in Alaska, Hawaii and our market areas in
the western United States is typically in balance with demand. As a result of
seasonal demand swings, we import and export diesel fuel from Alaska and Hawaii.
See "Government Regulation and Legislation -- Environmental Controls and
Expenditures" for a discussion of the effect of governmental regulations on the
production of low-sulfur diesel fuel.

Heavy Oil and Residual Products. Our Mid-Pacific and Pacific Northwest
refineries have vacuum units that use atmospheric crude oil tower bottoms as a
feedstock and further process these volumes into light vacuum gas oil, medium
vacuum gas oil, heavy vacuum gas oil and vacuum tower bottoms. Light vacuum gas
oil and medium vacuum gas oil are further processed in the Alaska and Hawaii
hydrocrackers, where they are converted into jet fuel, gasoline blendstocks and
diesel fuel. Heavy vacuum gas oil is used primarily as an FCC feedstock at the
Washington refinery where it is upgraded to gasoline and diesel fuel. The vacuum
tower bottoms are used to produce liquid asphalt, fuel oil and marine bunker
fuel. We sell heavy fuel oils to other refineries, electric power producers and
marine and industrial end-users. We sell our liquid asphalt for paving materials
in Alaska, Hawaii and Washington. In the Pacific Northwest, demand for liquid
asphalt is seasonal because mild weather conditions are needed for highway
construction.

We have marine fuel marketing operations and leased facilities at Port
Angeles and Seattle, Washington, and Portland, Oregon. Marine fuels sold from
these locations are supplied principally by our Pacific Northwest refineries.

Sales of Purchased Products. In the normal course of business, we purchase
refined products manufactured by others for resale to customers. The products,
primarily gasoline, jet fuel, diesel fuel and industrial and marine fuel
blendstocks are purchased primarily in the spot market. Sales of these products
represented approximately 21% of total volumes we sold in 2001. We conduct our
gasoline and diesel fuel purchase and resale activity primarily on the U.S. West
Coast. The jet fuel activity primarily consists of imports into Alaska and
California.

RETAIL SEGMENT

Our Retail segment sells gasoline and diesel in retail markets in the
mid-continental and western United States (including Alaska and Hawaii). 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 Tesoro-owned and operated sites and agreements with
third-party, branded jobbers. As of December 31, 2001, our Retail business
included a network of 677 branded retail stations (under the Tesoro, Mirastar,
Tesoro Alaska and other brands), including 213 Tesoro-owned retail gasoline
stations and 464 jobber/dealer stations

11

in the mid-continental and western United States. The following table summarizes
our retail operations as of and for the years ended December 31, 2001, 2000 and
1999:

- ---------------

(a) We acquired these stations in recent acquisitions and are in the process of
rebranding them to the Tesoro brand.

(b) Tesoro-owned stations included 30 in Alaska, 35 in Hawaii, 47 in Washington,
37 in Utah, 11 in North Dakota and 53 in other western states at December
31, 2001.

We developed our Mirastar brand to be used exclusively under an agreement
with Wal-Mart whereby we build and operate retail fueling facilities on parking
lots of selected Wal-Mart store locations. Our relationship with Wal-Mart covers
17 western states. Each of the sites under our agreement with Wal-Mart is
subject to a ground lease with a ten-year primary term and two options,
exercisable at our discretion, to extend a site's lease for additional terms of
five years. As of December 31, 2001, we had 55 Mirastar stations in operation, 4
Mirastar stations under construction and 53 sites in various stages of
development or evaluation. The availability of future sites is determined solely
at Wal-Mart's option, but decisions concerning the development of a Mirastar
station at a site are determined solely by us. We expect to construct an
additional 50 to 60 stations in each of 2002 and 2003. Our average cost of
constructing a standard Mirastar station with four fuel dispensers is
approximately $550,000. The average investment in Mirastar stations will
increase in the future with the construction of stations having more than four
fuel dispensers.

Many of our Tesoro-owned stations include convenience stores with the "2-Go
Tesoro" brand that sell a wide variety of merchandise items or kiosks that sell
limited amounts of merchandise. Our revenues from

12

merchandise sales and other services, such as carwashes, totaled $70.6 million
in 2001, $55.4 million in 2000 and $51.6 million in 1999.

The Mid-Continent Acquisition has created economic benefits for our retail
platform by providing a source of proprietary gasoline supply and additional
opportunities for our expanded retail network. In addition, in November 2001, we
acquired 46 retail fueling facilities, including 37 retail stations with
convenience stores and nine commercial card lock facilities, located in
Washington, Oregon and Idaho from a privately-held company. Our agreement with
Wal-Mart provides us with additional growth opportunities to build and operate
retail fueling facilities under the Mirastar brand on sites at selected Wal-Mart
store locations in the western United States.

MARINE SERVICES SEGMENT

OVERVIEW

Our Marine Services segment markets and distributes a broad range of
petroleum products, chemicals and supplies and provides logistical support
services to the marine and offshore exploration and production industries
operating in the Gulf of Mexico. These operations are conducted through a
network of 15 terminals located on the Texas Gulf Coast in Freeport, Galveston,
Harbor Island, Houston, Port O'Connor and Sabine Pass, and along the Louisiana
Gulf coast in Amelia, Berwick, Cameron, Intracoastal City, Port Fourchon and
Venice. We also own tugboats, barges and trucks used in the Marine Services
operations.

We are evaluating various strategic opportunities (including a possible
sale of all or a part of this business) to capitalize on the value of our Marine
Services assets. Our Marine Services business accounted for approximately 5% of
our operating income for the year ended December 31, 2001.

FUELS AND LUBRICANTS

Marine Services markets and distributes fuels and lubricants to offshore
drilling rigs, offshore production platforms, and various ships engaged in
seismic surveys. Marine Services also provides petroleum products to the Gulf of
Mexico fishing industry, tugboats and barges using the Intracoastal Canal System
along the Gulf of Mexico and to ships entering various ports in Texas and
Louisiana. Marine Services obtains its supply of fuel from local area refiners.
Total gallons of fuel, primarily diesel fuel, sold by this segment amounted to
approximately 171 million, 170 million and 148 million in 2001, 2000 and 1999,
respectively.

We are a distributor of major brands of marine lubricants and greases,
offering a full spectrum of brands. Total sales of lubricants amounted to
approximately two million gallons in each of the years 2001, 2000 and 1999.

LOGISTICAL SERVICES

Through many of its Gulf Coast terminals, Marine Services provides
full-service shore-based support for offshore drilling rigs and production
platforms. These services include cranes, forklifts and loading docks for supply
boats serving the offshore exploration and production industry. In addition,
Marine Services provides warehousing, office space, living quarters, helicopter
landing pads and long-term parking for offshore workers. Marine Services
terminals also serve as "one-stop shops" for a full range of offshore
exploration and production services. Products and services, such as drilling
muds, environmental services, and equipment repair and fabrication, are provided
through a variety of arrangements with "tenant partners".

COMPETITION AND OTHER

The petroleum industry is highly competitive in all phases, including the
refining of crude oil, the marketing of refined petroleum products and the
marine services business. The industry also competes with other industries that
supply the energy and fuel requirements of industrial, commercial and individual
consumers. We compete with a substantial number of major integrated oil
companies and other companies having greater financial and other resources.
These competitors have a greater ability to bear the economic risks inherent in
all phases of the industry. The recent consolidation experienced in the refining
and marketing
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industry has reduced the number of competitors; however, it has not reduced
overall competition. In addition, unlike many of our competitors, we do not
produce large volumes of crude oil that can then be used in connection with our
refining operations. Other larger competitors, although they do not produce
crude oil, may have a competitive advantage as larger purchasers when
negotiating with crude oil producers.

The refining and marketing industries are highly competitive, with prices
of feedstocks and products being the principal factors in competition. Our
Washington refinery competes with several refineries on the U.S. West Coast,
including refineries that have higher refining capacity than the Washington
refinery and that are owned by substantially larger companies. Our Hawaii
refinery competes primarily with one other refinery in Hawaii that also is
located at Kapolei and that has a rated capacity of 54,000 bpd of crude oil.
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 one refinery near Valdez. We estimate that the
other refineries have a combined capacity to process approximately 270,000 bpd
of crude oil. After processing the 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 back 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 directly connected to
the Trans Alaska Pipeline System, and we, therefore, cannot return our
lower-value products to the Trans Alaska Pipeline System. Our North Dakota
refinery is the sole refinery in North Dakota. Refineries in Wyoming, Montana,
the Midwest and the United States Gulf Coast region are the primary competitors
to our North Dakota refinery. The Utah refinery is the largest of five
refineries located in Utah. We estimate that the other refineries have a
combined capacity to process approximately 107,500 bpd of crude oil. These five
refineries collectively supply an estimated 70% of the gasoline and distillate
products consumed in the states of Utah and Idaho. The bulk of the remainder is
imported from refineries in Wyoming and Montana.

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, jet fuel sales are concentrated in Salt Lake
City. 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 Moorehead, Minnesota and Bismark, North Dakota. We
produce jet fuel in Alaska and Hawaii, both of which must import product to meet
demand.

Our Refining segment sells its diesel fuel primarily on a wholesale basis,
competing with other refiners and marketers in all of its market areas. Refined
products from foreign sources also compete for distillate markets in our market
areas.

We are a distributor of gasoline in Alaska, Hawaii, Utah, Washington and
other western states through a network of Tesoro-operated retail stations and
branded and unbranded jobbers. We supply a major oil company through a product
exchange agreement, whereby gasoline in Alaska is provided in exchange for
gasoline delivered to us on the U.S. West Coast. We also supply one of these
major oil companies in Alaska and Hawaii through a gasoline sales agreement.

In connection with the Mid-Continent Acquisition, we entered into certain
offtake agreements with BP to provide us with a distribution channel for a
portion of our refined products produced at these refineries. The offtake
agreements related to the North Dakota refinery commit approximately 30,470 bpd
(which represents approximately 59% of the historical three-year average
production of 51,770 bpd) of the North Dakota refinery product for each of the
first three years. In years four and five, the commitment is reduced. Volumes
related to the Minneapolis/St. Paul terminal, committed over five years, will
decline after year three. BP initially will receive approximately 68% of the
committed product via the Minneapolis/St. Paul terminal with

14

the remainder distributed through the other Minnesota and North Dakota
terminals. The offtake agreements for the Utah refinery represent approximately
6,750 bpd of refined product produced (approximately 14% of the historical three
year-average production of 48,560 bpd) for periods ranging from two years to
three years, depending on the terminal.

Competitive factors affecting the retail marketing of gasoline include
factors such as price and quality, together with station appearance, location
and brand-name identification. We compete with other petroleum companies,
distributors and other developers for new locations. We compete against
independent marketing companies and integrated oil companies when engaging in
these marketing operations.

Demand for services and products offered by Marine Services is
significantly affected by the level of oil and gas exploration, development and
production in the Gulf of Mexico. Various factors, including general economic
conditions, demand for and prices of oil and natural gas, availability of
equipment and materials, and government regulations and energy policies cause
exploration and development activity to fluctuate and directly impact the
revenues of Marine Services. We believe the principal competitive factors
affecting the Marine Services operations are location of facilities,
availability of logistical support services, experience of personnel and
dependability of service. The market for Marine Services' products and services,
particularly diesel fuel, is highly competitive and price sensitive.

GOVERNMENT REGULATION AND LEGISLATION

ENVIRONMENTAL CONTROLS AND EXPENDITURES

All of our operations, to some degree, are affected by federal, state,
regional and local laws, regulations and ordinances relating to the protection
of the environment. While we believe our facilities generally are in substantial
compliance with current requirements, over the next several years we expect our
facilities will be engaged in meeting new requirements being adopted and
promulgated by the U.S. Environmental Protection Agency and the states in which
we operate. Under the federal Clean Air Act, as amended in 1990, for example, we
will need to comply with the second phase of regulations establishing Maximum
Achievable Control Technologies for petroleum refineries ("Refinery MACT II").
These regulations, promulgated in January 2001, will require additional air
emission controls for certain processing units at several of our refineries. We
expect to spend approximately $35 million in additional 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, affect our operations. Starting
January 1, 2004, the sulfur content in gasoline must be reduced to meet the new
fuel manufacturing standard for gasoline. We expect to make approximately $65
million in capital improvements through 2006 and $15 million in years after 2006
to meet the new gasoline fuel standards. In December 2000, the EPA announced
additional standards for allowable sulfur concentrations in highway diesel
fuels. The "ultra low sulfur diesel" standards will, in general, become
effective on June 1, 2006. We expect to spend approximately $35 million in
capital improvements through 2006 and $30 million in years after 2006 to meet
the new diesel fuel standards.

In connection with the Mid-Continent Acquisition, 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 the Mid-Continent refineries for various
alleged violations. As the new owner of these refineries, we are required to
address issues including leak detection and repair, flaring protection and
sulfur recovery unit optimization. We estimate we will have to spend an
aggregate of $18 million to comply with this consent decree. In addition, we
have agreed to indemnify the sellers for all losses of any kind incurred in
connection with or related to the consent decree.

During 2001, we spent approximately $7 million on environmental capital
projects. We anticipate we will make additional capital improvements of
approximately $9 million in 2002, primarily for improvements to storage tanks,
tank farm secondary containment and pipelines.

Conditions that require additional expenditures may exist for various of
our sites, including, but not limited to, our refineries, tank farms, retail
gasoline stations (operating and closed locations) and petroleum

15

product terminals, and for compliance with the Clean Air Act and other state and
federal regulations. We currently cannot determine the amount of these future
expenditures.

ENVIRONMENTAL CONTROLS AND EXPENDITURES-PENDING ACQUISITION OF GOLDEN EAGLE
ASSETS

In addition, the Golden Eagle Assets will require substantial expenditures
to address upcoming "clean fuels" requirements, including California regulations
to phase out the use of the oxygenate known as MTBE by the end of 2002. The
seller of the Golden Eagle Assets has begun construction of a project at the
refinery that we expect will enable us to conform with CARB III gasoline
specifications scheduled to be effective on January 1, 2003. Based upon a review
by an independent engineering firm, we believe that this project will cost a
total of $122 million, a portion of which has been or will be paid by the
seller. We expect to spend approximately $103 million in 2002 and 2003 to
complete this project. Furthermore, we expect that the project will be
substantially complete by the end of 2002. We also expect to spend approximately
$24 million by 2006 at the Golden Eagle refinery to meet the "ultra low sulfur
diesel" standards.

The Golden Eagle Assets are also subject to extensive environmental
requirements. We anticipate that capital expenditures addressing environmental
issues at the refinery such as controls on emission of nitrogen oxides and
piping upgrades required to be made pursuant to orders from California's
Regional Water Quality Control Board with jurisdiction over the refinery, and
requirements as a result of a pending settlement of a lawsuit by a citizens'
group concerning coke dust emissions from the refinery's Pittsburg Dock loading
facility, will total approximately $32 million during 2002. Although some
portion of these costs are being and will continue to be incurred by the seller
of the Golden Eagle Assets prior to the closing of the transaction, a
substantial portion of the work will remain undone after the closing, the costs
of which we will incur. In addition, we estimate that we will incur $96 million
in environmental capital expenditures at the refinery for similar projects from
2003 through 2006 and $90 million beyond 2006.

In addition, soil and groundwater conditions at the Golden Eagle refinery
(including the Amorco terminal and the coke terminal) may entail substantial
expenditures over time. Although existing information is limited, our
preliminary estimate of costs to address soil and groundwater conditions at the
refinery in connection with various projects, including those required pursuant
to orders by the California Regional Water Quality Control Board, is
approximately $66 million, of which approximately $43 million is anticipated to
be incurred through 2006 and the balance afterwards. We believe we will be
entitled to indemnification, directly or indirectly, from former owners or
operators of the refinery (or their successors) under two separate
indemnification agreements, for approximately $59 million of such costs. We
cannot assure you that any indemnification will be realized.

Additionally, soil and groundwater conditions at approximately 50 of the 70
retail stations to be acquired through the pending acquisition of the Golden
Eagle Assets may require expenditures of approximately $6 million in the
aggregate pursuant to orders and regulations set by the California Regional
Water Quality Control Board. We also expect to spend approximately $3 million in
the aggregate on capital improvements to meet new California vapor control
equipment at each of the retail facilities.

OIL SPILL PREVENTION AND RESPONSE

The Federal Oil Pollution Act of 1990 and related state regulations include
requirements 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 releases and to minimize potential impacts should a release
occur.

We currently charter, on a long-term and short-term basis, tankers and
barges for shipment of crude oil from foreign and domestic sources to our
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 an amount equal to 50,000 barrels of
16

crude oil for a tanker carrying fewer than 500,000 barrels or 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 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 in Hawaii and in the Gulf Coast
region. 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 THE PIPELINE SYSTEM

The Pipeline System and the refined product pipeline systems in Alaska,
North Dakota and Minnesota are common carriers subject to regulation by various
local, state and federal agencies including the Federal Energy Regulatory
Commission ("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. New and changed
rates must be filed with the FERC, which may investigate their lawfulness upon
protest or on its own initiative. The FERC may suspend the effectiveness of the
new rates for up to seven months. If the suspension expires before completion of
the investigation, the rates go into effect, but the pipeline can be required to
refund to shippers, with interest, any difference between the level the FERC
determines to be lawful and the filed rates under investigation. Rates that have
become final and effective may be challenged by complaint to the FERC filed by a
shipper or on the FERC's own initiative. The party filing the complaint may
recover reparations for the two-year period prior to the complaint, if the FERC
finds the rate to be unlawful.

The intrastate operations of the Pipeline System are subject to regulation
by the North Dakota Public Services Commission. The intrastate operations of our
Alaska products pipeline are subject to regulation by the Alaska Public
Utilities Commission. Like the FERC, the state regulatory authorities require
that shippers be notified of proposed intrastate tariff increases and have an
opportunity to protest the increases. The North Dakota Public Services
Commission also files with the state authorities copies of interstate tariff
changes 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, 2001, we had approximately 3,290 employees. Approximately
220 employees and 270 employees at the Washington and Mid-Continent refineries,
respectively, are covered by collective bargaining agreements which ran until
January 31, 2002. In November 2001, eligible employees at our Mid-Pacific
refinery voted to be represented by a collective bargaining representative.
Although the collective bargaining agreements expired on January 31, 2002, we
have entered into an agreement with our employees represented by these
agreements that we will adopt the "Industry Pattern Agreement" approved by the
union, a major oil company (Exxon/Mobil, BP/Amoco, Shell or Chevron/Texaco) and
accepted by any two additional companies (Phillips/Tosco, Conoco or CITGO). Our
employees have agreed not to engage in a strike, work stoppage or slowdown, or
any other intentional interference of work production for any reason. However,
with respect to our Hawaii operations, this agreement not to strike or engage in
a work stoppage expires on July 1, 2002. We consider our relations with our
employees to be satisfactory.

See also the list of Directors and Executive Officers of the Registrant
listed in Item 10 herein.

17

RISK FACTORS AND INVESTMENT CONSIDERATIONS

WE HAVE A SUBSTANTIAL AMOUNT OF DEBT THAT COULD LIMIT OUR FLEXIBILITY IN
OPERATING OUR BUSINESS OR LIMIT OUR ACCESS TO FUNDS WE NEED TO GROW OUR
BUSINESS.

As of December 31, 2001, our total consolidated indebtedness was $1,146.9
million (including the outstanding 9% Senior Subordinated Notes due 2008 and
9 5/8% Senior Subordinated Notes due 2008, but excluding an additional $174
million available under our revolving credit facility). Following our
announcement of the pending acquisition of the Golden Eagle Assets, we were put
on credit watch by the rating agencies. Furthermore, we also will be required to
incur a substantially increased amount of indebtedness to consummate the pending
acquisition of the Golden Eagle Assets. Our high degree of leverage may have
important consequences, including the following:

- we may have difficulties obtaining additional or favorable financing for
capital expenditures, working capital, acquisitions or other purposes;

- a substantial portion of our cash flow will be used to make debt service
payments, which will reduce the funds that would otherwise be available
to us for operations and future business opportunities;

- 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 may place us at a competitive disadvantage to our less
leveraged competitors;

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

- our floating rate debt level makes us more vulnerable to the impact of an
increase in interest rates.

Our ability to meet our expenses and debt obligations, to refinance our
debt obligations and to 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.

Our business may not generate sufficient cash flow, or we may not be able
to borrow funds under our senior secured credit facility, in an amount
sufficient to enable us to service our indebtedness or make capital
expenditures. If we are unable to generate sufficient cash flow from operations
or to borrow sufficient funds to service our debt, we may be required to sell
assets, reduce capital expenditures, refinance all or a portion of our existing
debt or obtain additional financing. We may not be able to sell assets,
refinance our debt or borrow more money on terms acceptable to us, if at all.
Additionally, the covenants contained in our senior secured credit facility and
our indentures restrict our ability to incur additional debt.

THE VOLATILITY OF CRUDE OIL PRICES, REFINED PRODUCT PRICES AND FUEL AND UTILITY
SERVICE PRICES MAY HAVE A MATERIAL ADVERSE EFFECT ON OUR CASH FLOW AND RESULTS
OF OPERATIONS.

Our refining and wholesale marketing earnings and cash flows from
operations depend on the margin above fixed and variable expenses (including the
cost of refinery feedstocks) 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;

- worldwide political conditions;

- availability of crude oil and refined product imports;

- marketing of alternative and competing fuels;

18

- government regulations; and

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

Our sale prices for 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, 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 and our earnings and cash flows. In addition, we maintain
inventories of crude oil, intermediate products and refined products, the values
of which are subject to rapid fluctuation in market prices. Also, crude oil
supply contracts are generally term contracts with market-responsive pricing
provisions. We purchase our refinery feedstocks prior to selling the refined
products manufactured. 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 could
have a material adverse effect on our business, financial condition and results
of operations.

The rising costs and unpredictable availability of fuel and utility
services used by our refineries and other operations have increased operating
costs and will continue to impact production and delivery of products. Fuel and
utility prices have been and will continue to be affected by supply and demand
for fuel and utility services in both local and regional markets.

THE PENDING ACQUISITION OF THE GOLDEN EAGLE ASSETS IS SUBJECT TO CLOSING
CONDITIONS THAT COULD PREVENT US FROM ACQUIRING THE ASSETS ON THE SCHEDULED
TIMETABLE OR AT ALL, AND WE COULD LOSE OUR $53.75 MILLION EARNEST MONEY DEPOSIT.

We entered into a sale and purchase agreement on February 4, 2002 for the
Golden Eagle Assets, which was amended on February 20, 2002. If the acquisition
is not consummated by May 31, 2002 and the failure to close is a result of our
default (including default because of our failure to obtain adequate financing
for the acquisition) under the sale and purchase agreement, we will forfeit our
$53.75 million earnest money deposit. In addition to customary closing
conditions, the consummation of the acquisition is subject to approval by the
Federal Trade Commission and the Attorneys General of the States of California
and Oregon. The failure to obtain these approvals or to meet the customary
closing conditions could delay or prevent the consummation of the acquisition.

WE COULD FACE SIGNIFICANT EXPOSURE TO LIABILITIES THAT WE HAVE ASSUMED OR AGREED
TO ASSUME IN CONNECTION WITH THE MID-CONTINENT ACQUISITION AND, FOLLOWING
CLOSING, THE ACQUISITION OF THE GOLDEN EAGLE ASSETS.

We have assumed or agreed to assume a substantial portion of the sellers'
obligations, responsibilities, liabilities, costs and expenses arising out of or
incurred in connection with the Mid-Continent refineries. This includes, subject
to certain exceptions, certain of the sellers' obligations, liabilities, costs
and expenses for violations of health, safety and environmental laws relating to
the assets, including certain known and unknown obligations, liabilities, costs
and expenses arising or incurred prior to, on or after the closing date. We also
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 the Mid-Continent
refineries for various alleged violations. As the new owner of these refineries,
we are required to address issues including leak detection and repair, flaring
protection and sulfur recovery unit optimization. We estimate we will have to
spend an aggregate of $18 million to comply with this consent decree. In
addition, we have agreed to indemnify the sellers for all losses of any kind
incurred in connection with or related to these assumed liabilities.

In addition to paying the purchase price for the Golden Eagle Assets, upon
the closing of the acquisition of the Golden Eagle Assets, we have agreed to
assume a substantial portion of the seller's obligations, responsibilities,
liabilities, costs and expenses arising out of or incurred in connection with
the operation of the Golden Eagle Assets. This includes, subject to certain
exceptions, certain of the seller's obligations, liabilities,
19

costs and expenses for environmental compliance matters relating to the assets,
including certain known and unknown obligations, liabilities, costs and expenses
arising or incurred prior to, on or after the closing date. Subject to certain
conditions, we also have agreed to assume 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 will retain.

Following the closing of the pending acquisition of the Golden Eagle
Assets, we also will assume and take assignment of certain of the seller's
obligations and rights (including certain indemnity rights) arising out of or
related to the agreement pursuant to which the seller purchased the refinery in
2000. The seller has agreed to use commercially reasonable efforts to persuade
Phillips to consent to this assignment. If the seller cannot obtain a consent
from Phillips, the seller has agreed to provide us with a "back-to-back"
indemnity that will indemnify us against any liability for which the seller is
entitled to recover under the corresponding indemnity. The seller's indemnity,
however, is non-recourse to the seller and is limited to amounts the seller
actually receives from Phillips, less any legal or other enforcement costs the
seller incurs. Therefore, the indemnification that we may be entitled to receive
may not be sufficient to cover any losses or damages we incur.

The operation of refineries and pipelines is inherently subject to spills,
discharges or other releases of petroleum or hazardous substances. If any of
these events occurred or occurs in connection with the Mid-Continent Acquisition
assets or the pending acquisition of the Golden Eagle Assets, other than events
for which we are indemnified, we will be liable for all costs and penalties
associated with their remediation under federal, state or local environmental
laws or common law, and will be liable for property damage to third parties
caused by contamination from releases and spills. The penalties and clean-up
costs that we could have to pay for releases or spills, or the amounts that we
could 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.

The operation of the Mid-Continent and Golden Eagle refineries is and will
continue to be subject to hazards and risks inherent in refining operations and
in transporting and storing crude oil and refined products, including fires,
natural disasters, explosions, pipeline ruptures and spills and mechanical
failure of equipment. Any of these events can result in environmental pollution
and property damage. Our assumption of liability for these events that occurred
before closing could expose us to significant and costly liabilities, the
payment of which could have a material adverse effect on our business, financial
condition and results of operations.

THE GOLDEN EAGLE REFINERY MAY NOT CURRENTLY MEET OUR SAFETY STANDARDS, WHICH
COULD CAUSE US TO INCUR POTENTIALLY SIGNIFICANT LIABILITY FOR ANY FUTURE
HAZARDS.

The Golden Eagle refinery may not currently meet our internal safety and
environmental standards. We anticipate that it could take several years of
continued focus on improving the reliability and maintenance of the Golden Eagle
refinery before it will comply with our internal safety requirements. Therefore,
we may be required to spend a higher amount on capital expenditures for the
Golden Eagle refinery than for our other refineries. In addition, because of
past incidents at the Golden Eagle refinery, we may face a significantly
increased financial burden in obtaining sufficient property and liability
insurance.

AS A RESULT OF THE MID-CONTINENT ACQUISITION, WE HAVE SIGNIFICANT PIPELINE
CAPACITY AND VARIOUS OBLIGATIONS WITH WHICH WE MAY BE INEXPERIENCED OR
UNFAMILIAR.

Prior to the Mid-Continent Acquisition, we did not own refineries or
pipelines in the mid-continent region and had no experience in operating
pipelines in those states. In addition, the Pipeline System significantly
increased the quantity of crude oil pipeline which we own and operate. Our
management is more experienced at operating refineries than pipelines, so we may
face regulatory and operational matters with which we are unfamiliar. While we
have entered into transition services agreements (as amended) for BP to operate
the refined products pipeline and the crude oil Pipeline System on our behalf
until December 15, 2002, our current knowledge level, infrastructure and
employees may not be sufficient to efficiently operate the Pipeline System if we
are required to suddenly take over its operation. In addition, we have entered
into agreements with BP pursuant to which BP has agreed to purchase some of the
products from the Utah refinery and a majority of

20

the products from the North Dakota refinery. If, however, BP fails to purchase
these products under the agreements, we currently are unfamiliar with customers
in those markets and we would suffer losses in revenue until we find third-party
purchasers.

INTEGRATING OUR OPERATIONS WITH THE MID-CONTINENT ACQUISITION ASSETS AND, IF
ACQUIRED, THE GOLDEN EAGLE ASSETS, MAY STRAIN OUR RESOURCES.

The significant expansion of our business and operations, both in terms of
geography and magnitude resulting from the Mid-Continent Acquisition and the
pending acquisition of the Golden Eagle Assets, may strain our administrative,
operational and financial resources. The integration of the Golden Eagle Assets
will require the dedication of management resources that may temporarily detract
attention from our day-to-day business or hinder our integration of the Pipeline
System. These types of demands and uncertainties could have a material adverse
effect on our business, financial condition and results of operations. We may
not be able to manage the combined operations and assets effectively or realize
any of the anticipated benefits of the Pipeline System or the pending
acquisition of the Golden Eagle Assets.

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 terrorist attacks and acts of war.
Recent 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, may adversely impact our operations. As a result,
there could be delays or losses in the delivery of supplies and raw materials to
us, 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 have an adverse impact on energy
prices, including prices for our crude oil and refined products, and an 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. It is possible that any or a combination of
these occurrences could have a material adverse effect on our business.

COMPLIANCE WITH VARIOUS ENVIRONMENTAL REQUIREMENTS COULD INCREASE THE COST OF
OPERATING OUR BUSINESS.

All of our operations are subject to extensive requirements relating to air
emissions, water discharges, waste management and other environmental matters
that can entail costly compliance measures. For example, we currently anticipate
that revised standards for low sulfur content in gasoline and highway diesel
fuel will require us to spend approximately $100 million through 2006 and $45
million in years after 2006 to comply with regulations that will be applicable
to several of our currently owned refineries at various dates (depending on the
refinery and the fuel involved) between 2004 and 2010, and that other air
emissions and environmental requirements will require us to spend at least an
additional $60 million through 2006. In addition, the Golden Eagle Assets will
require substantial expenditures to address upcoming "clean fuels" requirements,
including California regulations to phase out the use of the oxygenate known as
MTBE, by the end of this year. Based upon a review by an independent engineering
firm, we believe that clean fuels costs at the Golden Eagle refinery will cost a
total of $122 million, a portion of which has been or will be paid by the
seller. We expect to spend approximately $103 million in 2002 and 2003 to
complete this project. Furthermore, we expect that the project will be
substantially complete by the end of 2002. We also expect to spend approximately
$24 million by 2006 at the Golden Eagle refinery to meet the "ultra low sulfur
diesel" standards. The measures we anticipate for achieving compliance with
these and other obligations may not be sufficient to meet these requirements or
our compliance costs may significantly exceed current estimates. If we fail to
meet environmental requirements, we may be subject to administrative, civil and
criminal proceedings by state and

21

federal authorities, as well as civil proceedings by environmental groups and
other individuals, which could result in substantial fines and penalties against
us as well as orders that could limit or halt our operations.

The Golden Eagle Assets are also subject to extensive environmental
requirements. We anticipate that capital expenditures addressing environmental
issues at the refinery such as controls on emission of nitrogen oxides and
piping upgrades required to be made pursuant to orders from California's
Regional Water Quality Control Board with jurisdiction over the refinery, and
requirements as a result of a pending settlement of a lawsuit by a citizens'
group concerning coke dust emissions from the refinery's Pittsburg Dock loading
facility, will total approximately $32 million during 2002. Although some
portion of these costs are being and will continue to be incurred by the seller
of the Golden Eagle Assets prior to the closing of the transaction, a
substantial portion of the work will remain undone after the closing, the costs
of which we will incur. In addition, we estimate that we will incur
approximately $96 million in additional environmental capital expenditures at
the refinery for similar projects from 2003 through 2006 and $90 million beyond
2006.

In addition, soil and groundwater conditions at the Golden Eagle refinery
(including the Amorco terminal and the coke terminal) may entail substantial
expenditures over time. Although existing information is limited, our
preliminary estimate of costs to address soil and groundwater conditions at the
refinery in connection with various projects, including those required pursuant
to orders by the California Regional Water Quality Control Board, is
approximately $66 million, of which approximately $43 million is anticipated to
be incurred through 2006 and the balance afterwards. We believe we will be
entitled to indemnification, directly or indirectly, from former owners or
operators of the refinery (or their successors) under two separate
indemnification agreements, for approximately $59 million of such costs. We
cannot assure you that any indemnification will be realized.

Additionally, soil and groundwater conditions at approximately 50 of the 70
retail stations to be acquired through the pending acquisition of the Golden
Eagle Assets may require expenditures of approximately $6 million in the
aggregate pursuant to orders and regulations set by the California Regional
Water Quality Control Board. We also expect to spend approximately $3 million in
the aggregate on capital improvements to meet new California vapor control
equipment at each of the retail facilities.

Our Refining and Marine Services segments operate in environmentally
sensitive coastal waters, where tanker, pipeline and refined product
transportation operations are closely regulated by local and federal agencies
and monitored by environmental interest groups. Our Mid-Pacific and Pacific
Northwest refineries import crude oil feedstocks by tanker. Transportation of
crude oil and refined product over water involves inherent risk and subjects us
to the provisions of the Federal Oil Pollution Act of 1990 and state laws in
Washington, Hawaii, Alaska and the U.S. Gulf Coast. The Golden Eagle refinery
will be subject to the same federal and to California laws governing the
transportation of crude oil and refined products over water. 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 product 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 we currently own or operate, facilities 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.

From time to time we have been, and presently are, subject to litigation
and investigations with respect to environmental and related matters. We may
become involved in further litigation or other proceedings, or we
22

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 in
Hawaii, Alaska and 16 states in the mid-continental and western United States
that have underground storage tanks. 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 at one or more of our service stations may
occur, or previously operated service stations may impact soil or groundwater
that could result in fines or civil liability for us.

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. 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.

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 five 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
landlocked and does not have a diversity of pipelines to allow us to transport
crude oil to it. The North Dakota refinery, therefore, is completely dependent
upon the delivery of crude oil through the Pipeline System. If outside events
cause an inadequate supply of crude oil, or if the 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 through
pipelines operated by third parties. During 2001, we also delivered
approximately 24,000 bpd of finished transportation fuels products 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 Mid-Continent refineries receive substantially all of their
crude oil through pipelines. 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 product 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.

ITEM 2. PROPERTIES

See information appearing under Item 1, Business, herein and Notes C, D and
O of Notes to Consolidated Financial Statements in Item 8.

23

ITEM 3. LEGAL PROCEEDINGS

Environmental. As previously reported, on August 24, 1998, an estimated
117-barrel oil spill occurred at the offshore single point mooring facility of
our subsidiary, Tesoro Hawaii Corporation ("Tesoro Hawaii"), at Barbers Point on
the island of Oahu. To resolve certain claims relating to alleged injuries to
natural resources, lost recreational use of natural resources and violations of
the State Clean Water Act resulting from the oil spill, Tesoro Hawaii, the
United States of America and the State of Hawaii entered into a Consent Decree,
which was entered by the United States District Court for the District of Hawaii
on October 22, 2001. Under the Consent Decree, Tesoro Hawaii was required to
carry out a net removal project on the island of Kauai, pay a penalty of $15,000
to the State of Hawaii and pay $565,000 to compensate for natural resources and
a supplemental environmental project. Tesoro Hawaii has made all of these
payments. In addition, the Consent Decree requires Tesoro Hawaii to reimburse
federal and state natural resources trustees up to $110,000 for natural resource
trustees assessment and oversight costs.

We are currently involved with the EPA regarding a waste disposal site near
Abbeville, Louisiana, at which we have been named a potentially responsible
party under the Federal Comprehensive Environmental Response, Compensation and
Liability Act (also known as CERCLA or Superfund). Although the Superfund law
may impose joint and several liability upon each party at the site, we expect
the extent of our allocated financial contributions for cleanup to be de minimis
based upon the number of companies, volumes of waste involved and total
estimated costs to close the site. We believe, based on these considerations and
discussions with the EPA, our liability at the Abbeville site will not exceed
$25,000.

Other. On May 31, 2000, we and certain of our officers were named
defendants in a lawsuit filed in the United States District Court, Western
District of Texas, San Antonio Division, brought by Group One Limited that
sought to certify as a class, all persons or entities who purchased our
securities during the period from January 3, 2000 through May 3, 2000. Three
other identical lawsuits were filed in the same court. The lawsuits, which were
consolidated, alleged that the defendants issued false and misleading
information regarding our financial condition and operations, which artificially
inflated the market price of our securities during the period from January 3,
2000 through May 3, 2000. On November 30, 2001, these claims were dismissed with
prejudice.

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

None.

24

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 2001 and 2000 are summarized
below:

At February 1, 2002, there were approximately 2,700 holders of record of
our 41,445,297 outstanding shares of common stock. We have not paid dividends on
our common stock since 1986. For information regarding our stock repurchase
program and restrictions on future dividend payments, see Management's
Discussion and Analysis of Financial Condition and Results of Operations in Item
7 and Notes F and G of Notes to Consolidated Financial Statements in Item 8. The
Board of Directors has no present plans to pay dividends on our common stock.
However, from time to time, the Board of Directors reevaluates the feasibility
of declaring future dividends on our common stock, subject to covenants in our
indentures and our senior secured credit facility limiting our ability to pay
dividends.

As discussed in Note G of Notes to Consolidated Financial Statements in
Item 8, all of our Premium Income Equity Securities ("PIES(SM)") automatically
converted into 10,350,000 shares of common stock on July 1, 2001. The final
quarterly cash dividends on the PIES(SM) were paid on July 2, 2001.

25

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 six years in the
period ended December 31, 2001. Separate financial statements of our subsidiary
guarantors are not included herein because our subsidiary guarantors are jointly
and severally liable on our outstanding debentures and the aggregate net assets,
earnings and equity of the subsidiary guarantors are substantially equivalent to
the net assets, earnings and equity of Tesoro on a consolidated basis. The
selected consolidated financial information presented below has been derived
from our historical financial statements. 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,
including the Notes thereto, in Item 8. Financial results of acquired operations
have been included in the amounts below since their acquisition.

27

- ---------------

(a) In 1998, we incurred a pretax charge of $19 million for special incentive
compensation ($12.0 million aftertax).

(b) In December 1999, we sold our oil and gas exploration and production
operations and recorded an aftertax gain of $39.1 million from the sale of
these operations. In 1998, these operations incurred pretax writedowns of
oil and gas properties of $68.3 million ($43.2 million aftertax) and
recognized pretax income from receipt of contingency funds of $21.3 million
($13.4 million aftertax). The discontinued operations included $60 million
in pretax income ($42 million aftertax) from termination of a natural gas
contract in 1996.

(c) Extraordinary losses on debt extinguishments, net of income tax benefits,
were $4.4 million ($0.15 per basic and diluted share) and $2.3 million
($0.09 per basic and diluted share) in 1998 and 1996, respectively.

(d) The assumed conversion of our PIES(SM) into 10.35 million shares of our
common stock for 1999 and 1998 produced anti-dilutive results and therefore
was not included in the diluted calculations of earnings per share. The
PIES(SM) automatically converted into shares of common stock in July 2001,
which eliminated our $12 million annual preferred dividend requirement.

(e) In September 2001, we entered into a senior secured credit facility. We
subsequently issued $215 million principal amount of our 9 5/8% Senior
Subordinated Notes to repay a term loan under the senior secured credit
facility (see Note F of Notes to Consolidated Financial Statements in Item
8). In conjunction with acquisitions in 1998, we refinanced our then
existing indebtedness and issued 9% Senior Subordinated Notes and
additional equity securities, including our common stock and PIES(SM) that
are included in stockholders' equity. On July 1, 2001, the PIES(SM)
automatically converted into 10.35 million shares of our common stock.

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

(g) EBITDA, ROCE (return on capital employed) and free cash flow are measures
we use for internal analysis and in presentations to analysts, investors
and lenders. The calculations of these measures are not based on accounting
principles generally accepted in the United States ("U.S. GAAP") and should
not be considered as alternatives to net earnings or cash flows from
operating activities (which are determined in accordance with U.S. GAAP),
as indicators of operating performance or as measures of liquidity. EBITDA
represents earnings before extraordinary items, interest and financing
costs, interest income, income taxes and depreciation and amortization
(including oil and gas property write-downs in 1998). We compute ROCE by
dividing aftertax earnings before interest and special charges by average
capital employed. Average capital employed includes current assets and net
fixed assets, less cash, accounts payable and accrued liabilities. Special
charges included special incentive compensation of $12.0 million aftertax
in 1998 and employee termination, restructuring and other costs of $4.6
million in 1996. We define free cash flow as EBITDA from continuing
operations before special charges, less capital expenditures, payments of
interest, income taxes and Preferred Stock dividends, and the difference
between turnaround expenditures and related amortization. EBITDA and free
cash flow have been restated from our previously reported amounts for
reclassifications of interest income. EBITDA, ROCE and free cash flow may
not be comparable to similarly titled measures used by other entities.

(h) Capital expenditures exclude amounts to fund acquisitions in the Refining
segment and Retail segment in 2001 and 1998 and in the Marine Services
segment in 1996.

(i) 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 105,000 and 108,700 bpd, respectively. Volumes for 1998 include
amounts from the Hawaii operations (acquired in May 1998) and the
Washington refinery (acquired in August 1998) since their dates of
acquisition, averaged over the full year.

(j) Sources of total product sales in the Refining segment include products
manufactured at the refineries, products from inventory balances and
products purchased from third parties for resale.

28

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 AND INVESTMENT
CONSIDERATIONS" ON PAGE 18 FOR A DISCUSSION OF THE FACTORS THAT COULD CAUSE
ACTUAL RESULTS TO DIFFER MATERIALLY FROM THOSE PROJECTED IN THESE STATEMENTS.

WE HAVE ENDEAVORED TO PROVIDE A MORE THOROUGH DISCUSSION OF OUR
EXPECTATIONS AND GOALS IN THIS SECTION, AND WE ANTICIPATE THAT WE WILL CONTINUE
TO DO THE SAME IN MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS IN THE FUTURE. HOWEVER, EXPECTATIONS AND GOALS MAY
CHANGE DURING INTERIM PERIODS OF TIME. WE DO NOT INTEND TO, AND YOU SHOULD NOT
EXPECT THAT WE WILL, UPDATE THE INFORMATION CONTAINED HEREIN DURING ANY SUCH
INTERIM PERIOD.

STRATEGY

Our goal is to create value by: (i) maximizing our earnings, cash flows and
return on capital by reducing costs, increasing efficiencies and optimizing
existing assets and (ii) increasing our competitiveness by expanding our size
and market presence through a combination of internal growth initiatives and
selective acquisitions that are accretive to earnings and cash flows and provide
significant operational synergies. We are acquiring and developing assets that
we believe will have a competitive advantage in connected markets which should
lower our operating, transportation and distribution costs and provide a market
penetration with competitive prices. We consider connected markets to include
markets that are connected to our refining operations by pipelines, trucks,
railcars, vessels or other means of conveyance as well as markets that, while
not physically connected, are joined by means of exchange supply agreements
between participants in those markets. We have a long-term goal of achieving a
12% aftertax return on capital employed. During 2001 and 2000, we achieved a
9.1% and 9.5% aftertax return on capital employed, respectively.

We are also focused on improving profitability in our Refining segment by
enhancing processing capabilities, strengthening our wholesale marketing
activities and improving supply and transportation logistics. Our retail
operations are an important component of our corporate strategy as they provide
a ratable offtake for our products at higher margins than products sold at
wholesale. We are using the North Dakota refinery and related assets as a
platform for retail expansion in the Minneapolis/St. Paul market and the Utah
refinery to expand our proprietary supply to the eastern Washington state
market, offering us further retail expansion opportunities. The Marine Services
segment seeks to optimize existing operations through ongoing development of
customer services and cost management. As part of this strategy, we continue to
assess our existing asset base to maximize returns and financial flexibility
through market diversification and related acquisitions. We are evaluating
various strategic opportunities to capitalize on the value of the Marine
Services assets, including a possible sale of all or a part of this business.

We believe the refining and marketing industry has experienced a
significant level of asset redeployment and consolidation. We have grown and
taken advantage of the economies of scale from this consolidation. We more than
tripled our refining capacity in 1998 when we acquired the Hawaii and Washington
refineries and improved our financial condition and performance through our
focus on the refining and retail business. In 2001, with the completion of the
Mid-Continent Acquisition, our asset base grew to a total of five refineries
with a rated crude oil capacity of 390,000 bpd and over 650 retail gasoline
stations. The Mid-Continent Acquisition increased our size and the scope of our
operations and diversified our earnings and geographic exposure. We believe that
the Mid-Continent Acquisition will improve our ability to supply markets in
areas that we had previously targeted for commercial and retail marketing
expansion, including our Mirastar program. In addition, in November 2001, we
acquired 46 retail fueling facilities, including 37 retail stations with
convenience stores and nine commercial card lock facilities, located in
Washington, Oregon and Idaho from a privately-held company based in Seattle,
Washington.

We entered into a sale and purchase agreement with Ultramar Inc., a
subsidiary of Valero Energy Corporation, on February 4, 2002, which was amended
on February 20, 2002. We agreed to acquire the 168,000 bpd Golden Eagle refinery
located in Martinez, California along with 70 associated retail sites
29

throughout northern California. This transaction, which is subject to approval
by the Federal Trade Commission and the offices of the Attorneys General of the
States of California and Oregon as well as other customary conditions, is
anticipated to close in April 2002. The purchase price for the Golden Eagle
Assets is $995 million plus the value of inventory at closing, assumed to be
$130 million. We intend to finance the acquisition with a combination of debt
(including through an amendment to our senior secured credit facility) and
public or private equity. We also believe that the Golden Eagle Assets will be
immediately accretive to our earnings.

In addition to paying the purchase price for the Golden Eagle Assets, upon
the closing of the acquisition, we have agreed to assume a substantial portion
of the seller's obligations, responsibilities, liabilities, costs and expenses
arising out of or incurred in connection with the operation of the Golden Eagle
Assets. This includes, subject to certain exceptions, certain of the seller's
obligations, liabilities, costs and expenses for violations of environmental
compliance matters relating to the assets, including certain known and unknown
obligations, liabilities, costs and expenses arising or incurred prior to, on or
after the closing date. Subject to certain conditions, we also have agreed to
assume 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 monetary penalties, which the seller will retain.

Following the closing of the pending acquisition of the Golden Eagle
Assets, we also will assume and take assignment of certain of the seller's
obligations and rights (including certain indemnity rights) arising out of or
related to the agreement pursuant to which the seller purchased the refinery in
2000. The seller has agreed to use commercially reasonable efforts to persuade
Phillips to consent to this assignment. If the seller cannot obtain a consent
from Phillips, the seller has agreed to provide us with a "back-to-back"
indemnity that will indemnify us against any liability for which the seller is
entitled to recover under the corresponding indemnity. The seller's indemnity,
however, is non-recourse to the seller and is limited to amounts the seller
actually receives from Phillips, less any legal or other enforcement costs the
seller incurs. Therefore, the indemnification that we may be entitled to receive
may not be sufficient to cover any losses or damages we incur.

For further information related to the Mid-Continent Acquisition and the
pending acquisition of the Golden Eagle Assets, see Notes C and Q of Notes to
Consolidated Financial Statements in Item 8 herein.

REFINING IMPROVEMENTS

Heavy Oil Conversion Project

Our manufacturing strategy focuses on improving refinery reliability and
safety, improving refining processes and controlling manufacturing costs. We
commenced a heavy oil conversion project at our Washington refinery in 2000,
which will enable us to process a larger proportion of lower-cost heavy crude
oils, to manufacture a larger proportion of higher-value gasoline, and to reduce
production of lower-value heavy products. We expect to spend approximately $116
million (including capitalized interest) for this project, of which $97 million
had been spent through December 31, 2001. The de-asphalting unit, one of the
major components of the heavy oil conversion project, has been in operation
since late September 2001. The upgrade of the fluid catalytic cracking unit, the
final major component of the heavy oil conversion project, is expected to be
fully operational by the end of the first quarter of 2002. We estimate that the
total heavy oil conversion project will increase annual operating profit by $30
million to $40 million (estimated $15 million to $20 million in 2002). The
actual profit to be contributed by the heavy oil conversion project is subject
to several factors, including, among others, refinery throughput, market values
of light and heavy refined products, availability of economic heavy feedstocks,
price differentials between light and heavy crude oils and operating expenses,
including fuel and utility costs.

Other

In addition to the heavy oil conversion project, we have implemented
programs to improve refinery reliability and safety. We have also implemented
programs to control manufacturing costs by upgrading process control systems,
consolidating refinery equipment purchasing and improving our ability to respond
to volatile changes in the cost of utilities at the Washington refinery.
30

RETAIL GROWTH

As of December 31, 2001, our Retail segment included a network of 677
branded retail stations (under the Tesoro, Mirastar, Tesoro Alaska and other
brands), including 213 Tesoro-owned retail gasoline stations and 464 jobber
stations (third-party retail distributors) in the western and mid-continental
United States. These numbers include over 300 retail stations acquired in the
Mid-Continent Acquisition and 46 retail fueling facilities acquired from a
Seattle, Washington company in November 2001. We are in the process of
rebranding the exterior signage for our acquired Tesoro-owned stations.

We developed our Mirastar brand to be used exclusively under an agreement
with Wal-Mart whereby we build and operate retail fueling facilities on parking
lots of selected Wal-Mart store locations. Our relationship with Wal-Mart covers
17 western states. Each of the sites under our agreement with Wal-Mart is
subject to a ground lease with a ten-year primary term and two options,
exercisable at our discretion, to extend a site's lease for additional terms of
five years. At December 31, 2001, we had 55 Mirastar stations in operation.
Though dependent on Wal-Mart to offer sites, we expect to construct an
additional 50 to 60 stations in each of 2002 and 2003. The average cost of
constructing a standard Mirastar station with four fuel dispensers is
approximately $550,000. The average investment in Mirastar stations will
increase in the future with the construction of stations having more than four
fueling dispensers.

Excluding acquisitions, our capital spending in the Retail segment totaled
$43 million in 2001.

BUSINESS ENVIRONMENT

We operate in an environment where our results and cash flows are sensitive
to volatile changes in energy prices. Fluctuations in the costs of crude oil and
other refinery feedstocks and the price of refined products can result in
changes in margins from the Refining and Retail segments, as prices received for
refined products may not keep pace with changes in feedstock costs. As part of
our marketing program, we purchase refined products for sale to customers.
Changes in price levels of crude oil and refined products can result in changes
in margins on such activities. Energy prices, together with volume levels, also
determine the carrying value of crude oil and refined product inventory. We use
the last-in, first-out ("LIFO") method of accounting for inventories of crude
oil and refined products in our Refining and Retail segments. This method
results in inventory carrying amounts that may be less than current values and
costs of sales that more closely represent current costs.

We maintain inventories of crude oil, intermediate products and refined
products, the values of which are subject to fluctuations in market prices. In
our Refining and Retail segments, our inventories of refinery feedstocks and
refined products totaled 17.2 million barrels and 11.9 million barrels at
December 31, 2001 and 2000, respectively. The weighted average cost of the 5.3
million barrel increase, primarily due to the purchase of inventories in the
Mid-Continent Acquisition on September 6, 2001, was $28.52 per barrel. Sales
that result in a reduction in LIFO inventories during 2002 could have a per
barrel cost of sales in excess of the current cost of sales during 2002. The
average cost of our refinery feedstocks and refined product inventories as of
December 31, 2001 was $23.14 per barrel. We may be required to write down the
carrying value of this inventory if market prices for refined products decline
from year-end 2001 levels to a level below the average cost of these
inventories.

Changes in crude oil and natural gas prices also influence the level of
drilling activity in the Gulf of Mexico. Our Marine Services segment, whose
customers include offshore drilling contractors and related industries, can be
impacted by significant fluctuations in crude oil and natural gas prices. The
Marine Services segment uses the first-in, first-out ("FIFO") method of
accounting for inventories of fuels. Changes in fuel prices can significantly
affect inventory valuations and costs of sales.

For further information on commodity price and interest rate risks, see
Quantitative and Qualitative Disclosures About Market Risk in Item 7A herein.

31

RESULTS OF OPERATIONS

SUMMARY

Our net earnings for the year 2001 were $88.0 million ($2.26 per basic
share or $2.10 per diluted share), an increase of 20% compared to year ago net
earnings of $73.3 million ($1.96 per basic share or $1.75 per diluted share).
The improvement in earnings was primarily a result of higher refined product
margins, increased refining throughput, improved operating performance and
incremental operating income from acquisitions. This improvement was partially
offset by expenses related to the acquisition financing and integration. Of the
$2.10 earnings per diluted share, our Mid-Continent operations and other
recently acquired retail operations contributed $0.14 per share.

Our 2000 net earnings of $73.3 million compare to earnings from continuing
operations of $32.2 million ($0.62 per basic and diluted share) in 1999. The
earnings improvement during 2000, as compared to 1999, reflected a higher level
of operating income resulting from higher refined product margins and increased
throughput levels, partly offset by higher operating expenses. The Marine
Services segment's operating income reached a record level in 2000, reflecting a
recovery in sales volumes from depressed 1999 levels, as well as effective cost
management. Our 1999 net earnings of $75.0 million ($1.94 per basic share or
$1.92 per diluted share) included results from our former exploration and
production operations. These discontinued operations contributed $42.8 million
to net earnings ($1.32 per basic share or $1.30 per diluted share) in 1999,
including an aftertax gain of $39.1 million from the sale of these operations.

A discussion and analysis of the factors contributing to our results of
operations are presented below. The accompanying Consolidated Financial
Statements and related Notes, together with the following information, are
intended to provide investors with a reasonable basis for assessing our
operations, but should not serve as the only criteria for predicting our future
performance.

REFINING SEGMENT

- ---------------

* Gross refining margins have been revised from previously reported refinery
system product spread to reclassify margins from retail sales into the
Retail segment.

(a) Includes intersegment sales to our Retail segment at prices which
approximate market of $333.9 million, $212.9 million and $139.3 million in
2001, 2000 and 1999, respectively.

(b) Throughput includes the Mid-Continent refineries since their acquisition on
September 6, 2001 averaged over 365 days. Throughput averaged over the 117
days owned by us was 105,000 bpd.

(c) Approximates total refinery system throughput times the gross refining
margin, adjusted for changes in refined product inventory due to selling a
volume and mix of product that is different than actual volumes
manufactured. Refined product inventories totaled 10.3 million barrels, 7.0
million barrels and 5.8 million barrels at December 31, 2001, 2000 and
1999, respectively. In 2001, the Washington refinery increased product
inventory to meet demand during the turnaround in the first quarter of 2002
and inventories were rebuilt at refineries and terminals acquired from BP
in September 2001.

(d) Includes manufacturing costs per throughput barrel of $3.10, $2.85 and
$2.98 for 2001, 2000 and 1999, respectively. Manufacturing costs included
non-cash amortization of maintenance turnaround costs of $18.5 million,
$20.1 million and $14.2 million in 2001, 2000 and 1999, respectively.
Manufacturing costs also include costs of internally-produced fuel.

(e) Includes manufacturing depreciation per throughput barrel of approximately
$0.28, $0.26 and $0.32 for 2001, 2000 and 1999, respectively.

(f) Sources of total product sales included products manufactured at the
refineries, products drawn from inventory balances and products purchased
from third parties. Gross margins on total product sales included margins
on sales of manufactured and purchased products and the effects of
inventory changes.

2001 Compared to 2000. Operating income for the Refining segment was
$224.5 million in 2001, an 18% increase from 2000. Our newly-acquired operations
in the Mid-Continent contributed approximately $32 million to segment operating
income. The increase was also driven by stronger refined product margins and
higher refinery throughput from our Mid-Pacific refinery and higher throughput
levels at our Pacific Northwest refineries. The improvement in our total
refinery system margins was partially offset by increases in operating expenses.

During the fourth quarter of 2001, the industry experienced the lowest
spreads since 1999, as market conditions caused significant margin erosion. Our
weakest market was the Pacific Northwest, where our actual gross refining margin
in the 2001 fourth quarter averaged $5.82 per barrel, reducing this region's
annual 2001 margin to $7.42 per barrel compared to $7.89 per barrel last year.
Our Mid-Pacific gross refining margin improved during the fourth quarter of 2001
to $6.95 per barrel, increasing the region's annual 2001 margin to $5.85 per
barrel, compared to $4.80 per barrel in 2000. The 2001 fourth quarter gross
margin for our Mid-Continent refineries declined to $6.90 per barrel. For our
total refinery system, gross refining margin increased to $7.04 per barrel, a 3%
increase from the $6.84 per barrel in 2000. We attribute this improvement to the
continued success of our efforts to optimize our refinery system and to reduce
our logistics costs throughout our asset base.

While weak product demand existed in the latter part of 2001, jet fuel
margins in Alaska were fairly stable, compared with 2000, as air cargo demand
was comparable to last year. Conversely, in Hawaii, jet fuel demand was lower
due to reduced passenger flights. The loss of demand was largely offset by
reduced imports into Hawaii.

Revenues from sales of refined products in the Refining segment increased
to $4,625.2 million in 2001, from $4,499.3 million in 2000, due to increased
sales volumes largely offset by lower prices. Total product sales averaged
376,300 bpd in 2001, an increase of 17% from 2000, while product prices dropped
12% to $33.67 per

33

barrel. The decrease in other revenues was primarily due to lower crude oil
resales which totaled $255.4 million in 2001 compared to $314.6 million in 2000.
The decrease in costs of sales reflected primarily lower prices for feedstocks
and product supply.

Gross refining margin increased 18% to $721.2 million in 2001 reflecting
higher product spread and volumes. The increase in refinery margin included
contributions from the Mid-Continent operations. We increased refinery
throughput 3%, or 7,000 bpd, excluding the new operations, as compared to 2000.
In addition, we were able to process a higher percentage of lower cost heavy
crude oil, which represented 45% of refinery throughput in 2001, compared with
42% in 2000.

Expenses, excluding depreciation, increased by 18% to $456.0 million in
2001, primarily due to additional operating expenses from our new operations,
increased throughput at our other refineries, higher costs for utilities and
fuel, and increased employee costs. Depreciation and amortization increased to
$40.7 million, primarily due to the new operations and timing of capital
improvement projects during 2001.

The completion of our heavy oil conversion project at the Washington
refinery by the end of the first quarter of 2002 will enable us to process a
larger proportion of lower-cost heavy crude oils, to manufacture a larger
proportion of higher-volume gasoline, and to reduce production of lower-value
heavy products. The de-asphalting unit, one of the major components of the heavy
oil conversion project, has been in operation since late September 2001. The
upgrade of the FCC unit, the final major component of the heavy oil conversion
project, is expected to be fully operational by the end of the first quarter of
2002. Management estimates that the total heavy oil conversion project would
increase annual operating income by $30 million to $40 million (estimated $15
million to $20 million in 2002). The actual profit to be contributed by the
heavy oil conversion project is subject to several factors, including, among
others, refinery throughput, market values of light and heavy refined products,
availability of economic heavy feedstocks, price differential between light and
heavy crude oils and operating expenses.

A turnaround of certain units at the Washington refinery is in progress and
will be completed during the first quarter of 2002. We estimate the turnaround
will cause throughput for the Pacific Northwest refineries to decline to about
150,000 bpd in the first quarter of 2002, as compared to 159,800 bpd in the
first quarter of 2001.

2000 Compared to 1999. Operating income for the Refining segment increased
69% during 2000 to $190.8 million. This improvement was driven by a combination
of stronger refined product margins and higher refinery throughput. Industry
product supply concerns and tight product inventories contributed to strong West
Coast margins. We were able to capitalize on these conditions by operating our
refineries at historically high rates. The level of refinery throughput
reflected high levels of operational reliability without compromising our safety
program. The improvement in gross refinery margins was partially offset by
higher operating expenses.

Revenues from sales of refined products in the Refining segment increased
62% in 2000, primarily due to higher product prices and increases in sales
volumes. Our average product sales prices increased 52% to $38.12 per barrel in
2000 from $25.08 per barrel in 1999. Total product sales increased to an average
of 322,500 bpd during 2000 from 302,800 bpd in 1999. Other revenues increased
during 2000 primarily due to crude oil resales of $314.6 million in 2000
compared to $16.6 million in 1999. This increase in crude oil resales resulted
from a term agreement with one of our crude oil suppliers. The increase in cost
of sales reflected higher costs of refinery feedstocks and purchased products
due to higher prices as well as higher volumes.

Our gross refining margins improved to $611.3 million in 2000 from $508.8
million in 1999, reflecting a 16% increase in refinery system gross margin to
$6.84 per barrel and a 7% increase in refinery throughput to 249,500 bpd. The
improvement in refinery margins was partly due to the higher throughput levels
combined with strong market conditions. In addition, during 2000, our refinery
margins benefitted from our initiatives and focus on profit improvement
programs. In manufacturing, a flexible feedstock supply enabled us to process a
higher percentage of lower-cost heavy crude oil, which represented 42% of
refinery throughput in 2000 compared with 35% in 1999. This percentage increase
in heavy crude oil partly offset the impact of higher prices for refinery
feedstocks, while minimally affecting our yield of light, higher-value products,
which

34

declined less than 2%. The investment in the distillate treater, which was
placed in service at the Washington refinery in December 1999, was a
contributing factor in maintaining those yields. We estimate that this
investment added approximately $12 million of incremental operating income in
2000. In marketing, we altered our gasoline blending process to market
higher-value CARB quality blendstocks, rather than including these materials in
the finished gasoline pool. The flexibility to sell these products added an
estimated $10 million to operating income in 2000, as compared to the values
received from sales of conventional gasoline.

Expenses, excluding depreciation, increased by 6% to $386.7 million in 2000
from $363.7 million in 1999. This increase was primarily attributable to the
impact of higher refinery throughput and increased costs for refinery utilities
and fuel. In addition, expenses increased for state and local taxes because of
higher product values and maintenance turnaround costs. Savings associated with
our cost reduction program partly offset these higher expenses.

Electricity rates at the Washington refinery increased from an average of
$35 per megawatt hour in 1999 to an average of $104 per megawatt hour in 2000
(including an average of $205 per megawatt hour in the fourth quarter of 2000),
resulting in an aggregate increase in electricity costs from $6 million in 1999
to $18 million in 2000.

Expenses included non-cash amortization of refinery turnaround costs of
$20.1 million and $14.2 million in 2000 and 1999, respectively. The increase in
2000 was due, in part, to the accelerated turnaround of certain refinery units.
The Hawaii crude unit turnaround was moved from 2001 and combined with the
September 2000 hydrocracker turnaround to avoid a temporary reduction in
throughput in 2001.

RETAIL SEGMENT

- ---------------

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

2001 Compared to 2000. Operating income for our Retail segment increased
to $24.9 million in 2001, compared to a loss of $1.7 million in 2000. The
expansion of our Tesoro-owned and jobber-dealer network enabled us to increase
revenues and profits in 2001.

35

Our total gallons sold increased 84% to 395.8 million, while our fuel
margin increased by 29% to $0.22 per gallon. Our average station count during
2001 of 406 represents a 56% increase from 260 in 2000. At year-end 2001, we had
677 branded retail sites in operation and 213 of these sites were Tesoro-owned
(under the Tesoro, Mirastar, Tesoro Alaska and other brands).

Revenues on fuel sales grew to $420.6 million in 2001, a 69% increase from
2000, while merchandise and other revenues increased by 27% to $70.6 million.
Merchandise margin, however, as a percent of sales decreased. With our increased
number of stations, expenses increased 45% to $73.2 million and depreciation
increased to $11.1 million in 2001.

2000 Compared to 1999. Operating results for our Retail segment decreased
to a loss of $1.7 million in 2000 compared to income of $12.4 million in 1999.
Rising refining wholesale prices in the industry reduced retail margins in 2000
which negatively impacted our Retail profit. In addition, our operating results
were negatively impacted by higher expenses as we were building our retail
infrastructure and developing our retail marketing team. Expenses increased 42%
in 2000, compared to 1999, while total fuel volumes only increased by 8%.

MARINE SERVICES SEGMENT

We are evaluating various strategic opportunities (including a possible
sale of all or a part of this business) to capitalize on the value of our Marine
Services assets.

2001 Compared to 2000. Marine Services operating income decreased by $0.5
million during 2001 from 2000. Included in 2000 was other income of $1.2 million
from settlement of a service contract. Excluding this income, operating income
for the 2001 period improved by $0.7 million, or 8%. Higher sales volumes and
service revenues experienced in the first part of 2001 contributed to this
improvement. The Marine Services segment is largely dependent on the volume of
oil and gas drilling, workover, construction and seismic activity in the U.S.
Gulf of Mexico. The significant decline in industry drilling activity negatively
impacted our Marine Services sales and operating income in the later part of
2001.

Revenues decreased $14.3 million during 2001 reflecting lower fuel sales
prices, partly offset by higher services revenues. The decrease in costs of
sales during 2001 reflected lower prices for fuel supply.

2000 Compared to 1999. Operating income for Marine Services improved 76%
to a record $10.4 million in 2000 from $5.9 million in 1999, primarily due to
higher fuel sales volumes and service revenues. The higher fuel sales volumes
and service revenues reflected increased customer exploration and development
activities in the U.S. Gulf of Mexico, compared with 1999. Operating revenues
increased 67% to $185.2 million in 2000
36

from $111.2 million in 1999, reflecting higher fuel volumes and prices, and
service revenues. The increase in cost of sales also reflected the higher fuel
sales volumes and prices. In 2000, we realized other income of $1.2 million from
settlement of a service contract and $0.4 million from the sale of excess real
estate. Operating expenses in 2000, as compared to 1999, increased due mainly to
the higher sales activities.

SELLING, GENERAL AND ADMINISTRATIVE EXPENSES

Selling, general and administrative expenses of $104.2 million in 2001
increased $19.0 million from $85.2 million in 2000. This increase was partially
due to higher expenses in the Refining and Retail segments associated with the
Mid-Continent Acquisition and other growth initiatives. Corporate expenses
accounted for $13 million of the increase resulting largely from $6 million in
acquisition integration costs in 2001, as well as higher employee costs and
professional fees.

In 2000, selling, general and administrative expenses increased by $10.2
million from the 1999 level. Corporate expenses were $40.3 million in 2000,
compared with $34.1 million in 1999. The $6.2 million increase in 2000 was
primarily due to higher employee costs associated with business development and
growth.

INTEREST AND FINANCING COSTS

Interest and financing costs, net of capitalized interest, were $52.8
million in 2001 compared to $32.7 million in 2000. This increase was primarily
due to the additional debt we incurred in 2001 and to costs of approximately $6
million related to acquisition financing. Lower interest rates in 2001 partially
mitigated the impact of the increased debt levels.

Interest and financing costs were $32.7 million in 2000, compared with
$37.6 million in 1999. The $4.9 million decrease in 2000 primarily reflected
lower borrowings. Proceeds from sales of our exploration and production
operations were used to repay debt in December 1999 and in March 2000. The
benefits from these debt repayments were partly offset by higher interest rates
on variable-rate debt and additional borrowings to finance an increase in
working capital.

INCOME TAX PROVISION

The income tax provision of $58.9 in 2001 increased 17%, as compared to
2000, primarily reflecting the increase in pretax earnings. The combined Federal
and state effective income tax rate was approximately 40% in both 2001 and 2000.

Income taxes on continuing operations increased to $50.2 million in 2000,
from $19.0 million in 1999, primarily due to the higher pretax earnings from
continuing operations. Our combined Federal and state effective income tax rate
increased to 40% in 2000 from 37% in 1999. The 1999 tax rate benefited from
amendments to prior year returns. See Note H of Notes to Consolidated Financial
Statements in Item 8 for further information on income taxes and Note E for
income taxes related to discontinued operations.

DISCONTINUED OPERATIONS

Earnings from discontinued operations in 1999 of $42.8 million (net of
income tax expense of $29.6 million), or $1.30 per diluted share, included $3.7
million of aftertax operating results and a $39.1 million aftertax gain on the
sale of our exploration and production operations. See Note E of Notes to
Consolidated Financial Statements in Item 8 for further information related to
discontinued operations.

CAPITAL RESOURCES AND LIQUIDITY

We operate in an environment where our liquidity and capital resources are
impacted by changes in the supply of and demand for crude oil and refined
petroleum products, 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, the price and availability of alternative fuels and
overall market and economic conditions. See "Forward-Looking Statements" on page
47 for further information related to risks and other factors. Our future
capital expenditures,
37

as well as borrowings under our senior secured credit facility and other sources
of capital, will be affected by these conditions.

OVERVIEW

Our primary sources of liquidity are cash flows from operations and
borrowing availability under revolving lines of credit. We expect our capital
requirements to include non-discretionary capital expenditures, working capital
and debt service. We believe available capital resources will be adequate to
meet our capital requirements for existing operations. However, we will be
required to seek additional funding, including the incurrence of additional debt
and equity, to finance the pending acquisition of the Golden Eagle Assets. We
have a universal shelf registration statement for debt or equity securities to
be used for acquisitions or general corporate purposes. At December 31, 2001,
the amount available under the shelf registration was $343 million.

As previously described, we entered into a sale and purchase agreement with
Ultramar, Inc., a subsidiary of Valero Energy Corporation, on February 4, 2002,
which was amended on February 20, 2002. The transaction, which is subject to
federal and state approvals, is anticipated to close in April 2002. Under the
terms of the Golden Eagle purchase agreement, we have paid a $53.75 million
earnest money deposit in February 2002. If the acquisition is not consummated by
May 31, 2002 and the failure to close is a result of our default, including our
failure to obtain the necessary financing, we will forfeit our earnest money
deposit.

At closing, we will pay a purchase price of $995 million, less our deposit,
plus the value of inventory at closing, assumed to be $130 million. We intend to
finance the acquisition with a combination of debt (including an amendment to
our senior secured credit facility) and public or private equity.

CAPITALIZATION

Our capital structure at December 31, 2001 was comprised of the following
(in millions):

Debt and other obligations outstanding, including current
maturities:
Senior Secured Credit Facility -- Term Loans.............. $ 625
9 5/8% Senior Subordinated Notes due 2008................. 215
9% Senior Subordinated Notes due 2008..................... 298
Other senior debt and obligations......................... 9
------
Total debt and other obligations.................. 1,147
Common stockholders' equity................................. 757
------
Total Capitalization.............................. $1,904
======

At December 31, 2001, our debt to capitalization ratio was 60% compared
with 32% at year-end 2000, primarily reflecting our issuance of the 9 5/8%
senior subordinated notes and term loans outstanding under our senior secured
credit facility, which we used to fund the Mid-Continent Acquisition as well as
working capital and capital expenditure requirements. Following our announcement
of the pending acquisition of the Golden Eagle Assets, we were put on credit
watch by the rating agencies. We will be required to incur a substantially
increased amount of indebtedness to consummate the pending acquisition of the
Golden Eagle Assets. See "Risk Factors and Investment Considerations -- we have
a substantial amount of debt that could limit our flexibility in operating our
business or limit our access to funds we need to grow our business" in Item 1,
hereto.

Our senior secured credit facility, 9% senior subordinated notes and 9 5/8%
senior subordinated notes impose various restrictions and covenants on us that
could potentially limit our ability to respond to market conditions, to raise
additional debt or equity capital, or to take advantage of business
opportunities. Our senior secured credit facility, 9% senior subordinated notes
and 9 5/8% senior subordinated notes are guaranteed by substantially all of our
active domestic subsidiaries.

38

The indentures relating to the 9% senior subordinated notes and 9 5/8%
senior subordinated notes contain covenants that 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;

- enter into asset sales;

- enter into transactions with affiliates;

- incur liens on assets to secure certain debt;

- engage in certain business activities; and

- engage in certain mergers or consolidations and transfers of assets.

The indentures limit our subsidiaries' ability to create restrictions on
making certain payments and distributions. In addition, our senior secured
credit facility contains other and more restrictive covenants, including the
prohibition on making voluntary or optional prepayments of certain of our
indebtedness, including the notes. Under our senior secured credit facility, we
are required to comply with specified financial covenants, including maintaining
specified levels of consolidated leverage and interest and fixed charge
coverages and limiting our debt to capital ratio. These financial ratios become
more restrictive over the life of our senior secured credit facility. For
further information on our capital structure, see Notes F and G of Notes to
Consolidated Financial Statements in Item 8.

SENIOR SECURED CREDIT FACILITY

Our senior secured credit facility, as amended, consists of a five-year
$175 million revolving credit facility (with a $90 million sublimit for letters
of credit), a five-year $85 million tranche A term loan, a five-year $90 million
delayed draw term loan (used to fund the purchase of the Pipeline System), and a
six-year $450 million tranche B term loan. At December 31, 2001, we had no
borrowings and $0.8 million in letters of credit outstanding under the revolving
credit facility. Total unused credit available under the revolving credit
facility at December 31, 2001 was $174.2 million.

Our senior secured credit facility is guaranteed by substantially all of
our active domestic subsidiaries and is secured by substantially all of our
material present and future assets as well as all material present and future
assets of our domestic subsidiaries (with certain exceptions for pipeline,
retail and marine services assets) and is additionally secured by a pledge of
all of the stock of all current active and future domestic subsidiaries and 66%
of the stock of our current and future foreign subsidiaries.

The senior secured credit facility requires us to maintain specified levels
of interest and fixed charge coverage and sets limitations on our
debt-to-capital and leverage ratios. It also contains other covenants and
restrictions customary in credit arrangements of this kind. The terms allow for
payment of cash dividends on our common stock and repurchase of shares of our
common stock, not to exceed $15 million in any year.

Borrowing rates under our senior secured credit facility are based on a
pricing grid. Borrowings bear interest at either a base rate (4.75% at December
31, 2001) or a eurodollar rate (ranging from 2.10% to 2.14% at December 31,
2001), plus an applicable margin. The applicable margin at December 31, 2001 for
the tranche A term loan, the delayed draw term loan and the revolving credit
facility was 1.25% in the case of the base rate and 2.25% in the case of the
eurodollar rate. The applicable margin for the tranche B term loan was 1.75% in
the case of the base rate and 2.75% in the case of the eurodollar rate.
Additionally, the tranche B eurodollar rate is deemed to be no less than 3.0%.
These margins are the highest margins applicable to the respective base and
eurodollar rates and will vary in relation to ratios of our consolidated total
debt to consolidated EBITDA, as defined in our senior secured credit facility.
In addition, at any time during which the senior secured credit facility is
rated at least BBB- by Standard & Poor's Rating Services and Baa3 by Moody's
Investors Service, Inc., each applicable margin, other than in one instance with
respect to the tranche B term loan, will be reduced by 0.125%. We are also
charged various fees and expenses in connection with the senior secured credit
facility, including commitment fees and various letter of credit fees.
39

We intend to amend the senior secured credit facility prior to closing the
pending acquisition of the Golden Eagle Assets (see Note Q of Notes to
Consolidated Financial Statements in Item 8).

SENIOR SUBORDINATED NOTES

In November 2001, we issued $215 million aggregate principal amount of
9 5/8% senior subordinated notes due November 1, 2008. The 9 5/8% senior
subordinated notes have a seven-year maturity with no sinking fund requirements
and are subject to optional redemption by us after four years at declining
premiums. For the first three years, we may redeem up to 35% of the aggregate
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
an aggregate principal amount of $300 million. These notes have a ten-year
maturity without sinking fund requirements and are subject to optional
redemption by us after five years at declining premiums.

The indentures for both the 9 5/8% and 9% senior subordinated notes contain
covenants and restrictions which are customary for notes of this nature. These
covenants and restrictions are less restrictive than those under the senior
secured credit facility. The senior subordinated notes are guaranteed by
substantially all of our active domestic subsidiaries.

CASH FLOW SUMMARY

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

Net cash from operating activities during 2001 totaled $214 million,
compared to $90 million in 2000. The increase was primarily due to higher
earnings before depreciation and amortization and lower working capital
requirements associated with the dramatic drop in feedstock and refined product
prices at year-end 2001. This increase was partially offset by increased sales
activity associated with our new refinery assets in the Mid-Continent
operations. Net cash used in investing activities of $977 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 the senior secured credit facility and net proceeds of $210
million from our debt 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 our annual $12 million preferred
dividend requirement. Gross borrowings and repayments under revolving credit
lines and interim facilities amounted to $958 million during 2001. We had no
outstanding borrowings under our revolving credit facility at December 31, 2001.

Working capital totaled $340 million at December 31, 2001 compared to $248
million at year-end 2000. Included in working capital at year-end 2001 were cash
and cash equivalents of $52 million, compared with $14 million at year-end 2000.

Net cash from operating activities during 2000 totaled $90 million,
compared to $85 million from continuing operations in 1999. This improvement was
primarily due to higher earnings before depreciation and amortization and other
non-cash charges, partially offset by increased working capital requirements.
Increases in receivables and inventories reflected higher prices for refinery
feedstocks and products, as well as an increase in inventory volumes, compared
with year-end 1999. Net cash used in investing activities of $88 million in 2000
included capital expenditures of $94 million, partly offset by proceeds from
sales of assets. Net cash used in financing activities of $130 million in 2000
included repayments of debt totaling $106 million, repurchase of treasury stock
of $15 million and payments of dividends on preferred stock of

40

$9 million. We had no outstanding borrowings under revolving credit lines at
December 31, 2000 or 1999. Gross borrowings and repayments under revolving
credit lines amounted to $866 million during 2000.

During 1999, net cash from operating activities totaled $113 million, $85
million from continuing operations and $28 million from discontinued operations.
Continuing operations provided cash flows from earnings before depreciation and
amortization and other non-cash charges partially offset by increased working
capital requirements. During 1999, working capital requirements increased due to
higher receivables arising in part from higher commodity prices, partially
offset by corresponding changes in payables and a reduction in inventory levels.
Net cash from investing activities of $166 million in 1999 was provided by net
proceeds of $309 million from the sale of assets, primarily the exploration and
production operations, partially offset by capital expenditures of $85 million
for continuing operations and $56 million for discontinued operations. Net cash
used in financing activities of $149 million in 1999 primarily represented
repayments of debt of $184 million and payments of dividends on preferred stock
of $15 million. These uses of cash in financing activities were partially offset
by the issuance of $50 million of debt in January 1999. Gross repayments under a
revolving credit line amounted to $550 million, while gross borrowings amounted
to $489 million.

CAPITAL SPENDING

For 2001, our capital expenditures totaled $210 million, which were funded
primarily from our cash flows from operations of $214 million (or 82% of our
2001 EBITDA). Capital expenditures during 2001 included $74 million for the
heavy oil conversion project (bringing the cumulative costs spent through
December 31, 2001 to $97 million with $19 million remaining to be spent in 2002)
and $43 million for our retail marketing program. Other capital spending was
primarily for natural gas-fueled generators (which were subsequently sold for
$15 million and leased back in the 2001 fourth quarter), modernization of
refinery control systems and other system upgrades.

For 2002, our capital budget totals $150 million (including a full year of
requirements for the Mid-Continent operations, but excluding the impact of the
pending acquisition of the Golden Eagle Assets) and represents a lower
percentage of our expected 2002 cash flows compared to 2001. The capital budget
for the Refining segment is $72 million, including $29 million of economic
capital ($19 million for completing the heavy oil conversion project and $10
million for other projects), $26 million of sustaining capital and $17 million
of compliance capital. Our Retail capital budget is $57 million for 2002, with
our Mirastar program accounting for approximately 60% of the budget. We estimate
that we will build 50 to 60 additional Mirastar sites during 2002. The remainder
of the Retail capital budget is divided between other Tesoro-owned stores and
the expansion of our branded jobber/dealer network. We estimate that $87 million
of the total $150 million will be discretionary capital spending, while the
remaining $63 million will be for non-discretionary projects. We plan to fund
our capital program in 2002 with internally-generated cash flows from operations
and borrowings under our senior secured credit facility.

However, the volatility of certain commodities prices could reduce our cash
flows from operations. See "Risk Factors and Investment Considerations -- The
volatility of crude oil prices, refined product prices and fuel and utility
service prices may have a material adverse effect on our cash flow and results
of operations" in Item 1 hereto.

If the pending acquisition of the Golden Eagle Assets is consummated, we
expect our capital spending for 2002 would increase by approximately $128
million, primarily for environmental, regulatory and safety matters. We expect
to fund these expenditures primarily with cash flows from operations.

MAJOR MAINTENANCE COSTS

We completed our scheduled turnaround of the Alaska refinery in the second
quarter of 2001 at a cost of approximately $10 million. A scheduled turnaround
of certain processing units, with an estimated cost of approximately $20
million, is currently in progress at our Washington refinery and will be
completed during the first quarter of 2002. Amortization of turnaround costs,
other major maintenance projects and catalysts totaled $22 million in 2001.

41

We estimate refinery turnaround costs to be as follows (in millions):

If the pending acquisition of the Golden Eagle Assets is consummated, we
expect that our turnaround and catalyst costs will increase by approximately $30
million and $3 million in 2002 and 2003, respectively.

LONG-TERM COMMITMENTS

Unless the context otherwise indicates, the following discussion of our
long-term commitments does not include any commitments we may incur as a result
of the pending acquisition of the Golden Eagle Assets.

Contractual Commitments

We have numerous contractual commitments for purchases of goods and
services arising in the ordinary course of business, debt service requirements
and operating lease commitments (see Notes F and O to Consolidated Financial
Statements in Item 8). The following table summarizes these commitments at
December 31, 2001 (in millions):

We lease our corporate headquarters from a limited partnership in which we
own a 50% limited partnership interest. The initial term of the lease is 15
years with two five-year renewal options. Lease payments and operating costs
paid to the partnership totaled $2.5 million, $1.8 million and $0.5 million in
2001, 2000 and 1999, 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, the partnership's
assets, primarily land and buildings, totaling approximately $18 million and
debt of approximately $14 million are not included in our Consolidated Financial
Statements in Item 8.

Clean Fuels and Clean Air Capital

We continue to evaluate certain new revisions to the Clean Air Act
regulations which will require a reduction in the sulfur content in gasoline by
January 1, 2004. To meet the revised gasoline standard, we expect to make
capital improvements of approximately $65 million in the aggregate through 2006
and $15 million in years after 2006.

The EPA has also announced new standards that will require a reduction in
sulfur content in diesel fuel manufactured for on-road consumption. In general,
the new diesel fuel standards will become effective on June 1, 2006. We expect
to spend approximately $35 million capital improvements through 2006 and $30
million in years after 2006 to meet the new diesel fuel standards.

42

We expect to spend approximately $35 million in the aggregate for
additional capital improvements at our refineries through 2006 to comply with
the second phase of Refinery MACT II which was signed into law in January 2001.
We expect that the Refinery MACT II regulations will require new emission
controls at certain processing units at several of our refineries. We are
currently evaluating a selection of control technologies to assure operations
flexibility and compatibility with long-term air emission reduction goals.

Estimated capital expenditures (excluding the pending acquisition of the
Golden Eagle Assets) described above to comply with the Clean Fuel and Clean Air
Act are summarized in the table below (in millions).

In addition, the Golden Eagle Assets will require substantial expenditures
to address upcoming "clean fuels" requirements including California regulations
to phase out the use of the oxygenate known as MTBE, by the end of 2002. We
expect that we will have to spend approximately $103 million in 2002 and 2003 to
complete this project. We also expect to spend approximately $24 million by 2006
at the Golden Eagle refinery to meet the "ultra low sulfur diesel" standards.

Other Environmental Matters

Extensive federal, state and local environmental laws and regulations
govern our operations. These laws, which change frequently, regulate the
discharge of materials into the environment and may require us to remove or
mitigate the environmental effects of the disposal or release of petroleum or
chemical substances at various sites, install additional controls, or make other
modifications or changes in use for certain emission sources. We are currently
involved in remedial responses and have incurred cleanup expenditures associated
with environmental matters at a number of sites, including certain of our own
properties. At December 31, 2001, our accruals for environmental expenses
totaled $38 million. Based on currently available information, including the
participation of other parties or former owners in remediation actions, we
believe these accruals are adequate.

In connection with the Mid-Continent Acquisition, we assumed the sellers'
obligations and liabilities under a consent decree among the United States, BP
Exploration and Oil Co., Amoco Oil Company and Atlantic Richfield Company. BP
entered into this consent decree for both the North Dakota and Utah refineries
for various alleged violations. As the new owner of these refineries, we are
required to address issues including leak detection and repair, flaring
protection and sulfur recovery unit optimization. We estimate that we will spend
an aggregate of $18 million to comply with this consent decree. In addition, we
have agreed to indemnify the sellers for all losses of any kind incurred in
connection with the consent decree.
43

We anticipate that we will make additional capital improvements of
approximately $9 million in 2002, primarily for improvements to storage tanks,
tank farm secondary containment and pipelines. During 2001, we spent
approximately $7 million on environmental capital projects. These amounts for
2002 and 2001 are included in "Capital Spending" discussed above.

Conditions that require additional expenditures may transpire for our
various sites, including, but not limited to, our refineries, tank farms, retail
gasoline stations (operating and closed locations) and petroleum product
terminals, and for compliance with the Clean Air Act and other state and federal
requirements. We cannot currently determine the amount of these future
expenditures.

We anticipate that, following consummation of the pending acquisition of
the Golden Eagle Assets, capital expenditures addressing environmental issues at
the Golden Eagle refinery such as controls on emission of nitrogen oxides and
piping upgrades required to be made pursuant to orders from California's
Regional Water Quality Control Board with jurisdiction over the refinery, and
requirements as a result of a pending settlement of a lawsuit by a citizens'
group concerning coke dust emissions from the refinery's Pittsburg Dock loading
facility, will total approximately $32 million during 2002. Although some
portion of these costs are being and will continue to be incurred by the seller
of the Golden Eagle Assets prior to the closing of the transaction, a
substantial portion of the work will remain undone after the closing, the costs
of which we will incur. We will need to spend additional amounts for capital
expenditures at the Golden Eagle refinery in subsequent years and we may choose
to spend additional discretionary amounts.

For further information on environmental matters and other contingencies,
see Note O of Notes to Consolidated Financial Statements in Item 8 and Legal
Proceedings in Item 3.

CONVERSION OF PREFERRED STOCK

On July 1, 2001, our PIES(SM) automatically converted into 10,350,000
shares of our common stock. This conversion eliminated $12 million in annual
preferred dividend requirements. We paid the final quarterly cash dividends on
the PIES(SM) on July 2, 2001.

COMMON STOCK SHARE REPURCHASE PROGRAM

In February 2000, our Board of Directors authorized the repurchase of up to
3 million shares of our common stock. Under the program, we may make repurchases
from time to time in the open market and through privately-negotiated
transactions. Purchases depend on price, market conditions and other factors and
have been made primarily from internally-generated cash flows. We may use the
stock to meet employee benefit plan requirements and other corporate purposes.
During 2000, we repurchased 1,627,400 shares of common stock for approximately
$15.5 million, or an average cost per share of $9.54. In 2001, we repurchased an
additional 304,000 shares of our common stock at an average cost of $11.50 per
share, or an aggregate of approximately $3.5 million, bringing the cumulative
shares repurchased under the program to 1,931,400.

PRELIMINARY FIRST QUARTER AND ANNUAL EXPECTATIONS

On February 21, 2002, we announced that due to continued deterioration in
market fundamentals and the ongoing scheduled turnaround of our Washington
refinery, we expect first quarter 2002 earnings to be below breakeven levels.

We believe that industry spreads are well below historical levels in all
our refining regions. Industry spreads for the first seven weeks of 2002
averaged about $2.75 per barrel below the average spread seen during the fourth
quarter of 2001. Normal seasonal factors make first quarter profitability more
unpredictable, since margins for the first two months are typically weak.

March is generally the strongest month of the quarter, as gasoline demand
and margins improve. We reported that the predictability of March 2002 results
are compounded by the uncertain near-term seasonal demand growth and the
Washington turnaround that is scheduled to be completed in mid-March 2002.

44

We anticipate if the current industry margin environment persists that
earnings could be below the current First Call consensus of a loss of $0.09 per
share. Notwithstanding the uncertain first quarter outlook, we believe seasonal
gasoline demand and announced industry throughput reductions will reduce
inventory levels and improve margins. While we anticipate margin improvement, we
do not believe margins will be as strong as 2000 and 2001 margins levels.

With the full year benefit of the Mid-Continent Acquisition, the start up
of our heavy oil project in March 2002 and the completion of the pending
acquisition of the Golden Eagle Assets, we believe that 2002 earnings per share
will be stronger than the $2.10 per share earned in 2001.

ACCOUNTING STANDARDS

CRITICAL ACCOUNTING POLICIES

Our accounting policies are described in Note A to Notes to Consolidated
Financial Statements in Item 8. We prepare our Consolidated Financial Statements
in conformity with accounting principles generally accepted in the United States
of America ("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 most
critical in understanding the judgments that are involved in preparing our
financial statements and the uncertainties that could impact our results of
operations, financial condition and cash flows.

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 carrying value of these inventories is sensitive to volatile
market prices. At December 31, 2001, the replacement cost (or market value) of
our crude oil and refined product inventories exceeded its carrying value by
only $3 million. We had 17.2 million barrels of crude oil and refined product
inventories at December 31, 2001 with an average cost of $23.14 per barrel. If
the market value of these inventories had been $1 per barrel lower at December
31, 2001, we would have been required to write down the value of our inventories
by $14 million. If refined product prices decline from the year-end 2001 levels,
then we may be required to write down the value of our inventories in future
periods.

Goodwill and Intangible Assets -- In June 2001, the Financial Accounting
Standards Board ("FASB") issued Statement of Financial Accounting Standards
("SFAS") No. 141, "Business Combinations" and SFAS No. 142, "Goodwill and Other
Intangible Assets". SFAS No. 141 requires the purchase method of accounting for
all business combinations and that certain acquired intangible assets in a
business combination be recognized as assets separate from goodwill. SFAS No.
142 requires that goodwill and other intangibles determined to have an
indefinite life are no longer to be amortized but are to be tested for
impairment at least annually. We have applied SFAS No. 141 in our preliminary
allocation of the purchase price of the Mid-Continent Acquisition. Accordingly,
we identified and allocated a value to intangible assets totaling $68 million
related to refinery permits and plans, agreements with jobbers, customer
contracts and refinery technology. The valuation of these intangible assets
required us to use our judgment. We also recorded goodwill related to the
Mid-Continent Acquisition of $35 million. The annual impairment testing required
by SFAS No. 142 will also require us to use our judgment and could require us to
write down the carrying value of our goodwill and other intangible assets in
future periods.

Deferred Maintenance Costs -- We record the cost of major scheduled
refinery maintenance ("turnarounds"), catalysts used in refinery process units
and periodic maintenance on ships, tugs and barges ("drydocking") as deferred
charges. We amortize these deferred charges over the expected periods of
benefit, generally ranging from two to four years. The American Institute of
Certified Public Accountants has issued an Exposure Draft for a Proposed
Statement of Position, "Accounting for Certain Costs and Activities Related to
Property, Plant and Equipment", which would require major maintenance activities
to be expensed as costs are incurred. If this proposed Statement of Position is
adopted in its current form, we will be required to write off the balance of our
deferred maintenance costs which totaled $44 million at December 31, 2001 and
expense future costs as incurred (see "Major Maintenance Costs" on page 41).

45

Contingencies -- We account for contingencies in accordance with SFAS
No. 5, "Accounting for Contingencies". SFAS No. 5 requires that we record an
estimated loss from a loss contingency when information available prior to
issuance of our financial statements indicates that it is probable that an asset
has been impaired or a liability has been incurred at the date of the financial
statements and the amount of the loss can be reasonably estimated. Accounting
for contingencies such as environmental, legal and income tax matters requires
us to use our judgment. While we believe that our accruals for these matters are
adequate, if the actual loss from a loss contingency is significantly different
than the estimated loss, our results of operations may be over or understated.

NEW ACCOUNTING STANDARDS AND DISCLOSURES

In June 2001, FASB issued SFAS No. 141, "Business Combinations", and SFAS
No. 142, "Goodwill and Other Intangible Assets". SFAS No. 141 requires the
purchase method of accounting for all business combinations initiated after June
30, 2001 and that certain acquired intangible assets in a business combination
be recognized as assets separate from goodwill. SFAS No. 142 requires that
goodwill and other intangibles that are determined to have an indefinite life
are no longer to be amortized but are to be tested for impairment at least
annually. SFAS No. 142 requires that an impairment test related to the carrying
values of existing goodwill be completed within the first six months of 2002.
Impairment losses on existing goodwill, if any, would be recorded as the
cumulative effect of a change in accounting principle as of the beginning of
2002. SFAS Nos. 141 and 142 apply to the Mid-Continent Acquisition (see Note C
of Notes to Consolidated Financial Statements in Item 8). We are currently
evaluating the impact these standards will have on our future results of
operations and financial condition. We believe that the carrying amount of our
goodwill has not been impaired although the detailed evaluations required by
SFAS No. 142 have not been completed.

In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset
Retirement Obligations". SFAS No. 143 requires an asset retirement obligation to
be recorded at fair value during the period incurred and an equal amount
recorded as an increase in the value of the related long-lived asset. The
capitalized cost is depreciated over the useful life of the asset and the
obligation is accreted to its present value each period. SFAS No. 143 is
effective for us beginning January 1, 2003 with earlier adoption encouraged. We
are currently evaluating the impact the standard will have on our future results
of operations and financial condition.

In August 2001, the FASB issued SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets". SFAS No. 144 retains the
requirement to recognize an impairment loss only where the carrying value of a
long-lived asset is not recoverable from its undiscounted cash flows and to
measure such loss as the difference between the carrying amount and fair value
of the assets. SFAS No. 144, among other things, changes the criteria that have
to be met to classify an asset as held-for-sale and requires that operating
losses from discontinued operations be recognized in the period that the losses
are incurred rather than as of the measurement date. SFAS No. 144 became
effective beginning January 1, 2002. We are currently evaluating the impact the
standard may have on our future results of operations and financial condition.

For further information related to new accounting standards and
disclosures, see Note A of Notes to Consolidated Financial Statements in Item 8.

46

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, including in the sections
entitled "Business" and "Risk Factors and Investment Considerations", and relate
to, among other things, projections of revenues, earnings, earnings per share,
cash flows, capital expenditures or other financial items, throughput,
expectations regarding the Mid-Continent Acquisition, expectations regarding the
pending acquisition of the Golden Eagle Assets, discussions of estimated future
revenue enhancements and cost savings. These statements also relate to our
business strategy, goals and expectations concerning our market position, future
operations, margins, profitability, liquidity and capital resources. We have
used the words "anticipate", "believe", "could", "estimate", "expect", "intend",
"may", "plan", "predict", "project", "will" and similar terms and phrases to
identify forward-looking statements in this 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 the results of our operations and whether the forward-looking
statements ultimately prove to be correct. Accordingly, these forward-looking
statements are qualified in their entirety by reference to the factors described
in "Risk Factors and Investment Considerations" contained in Part I, and
elsewhere, in this Annual Report on Form 10-K.

Actual results and trends in the future may differ materially depending on
a variety of factors including, but not limited to:

- changes in general economic conditions;

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

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

- changes in our cash flow from operations, liquidity and capital
requirements resulting from the pending acquisition of the Golden Eagle
Assets;

- our ability to consummate the pending acquisition of the Golden Eagle
Assets;

- our ability to (1) successfully integrate acquisitions, including the
Pipeline System and retail assets and the pending acquisition of the
Golden Eagle Assets, and (2) identify and complete future strategic
acquisitions;

- fluctuations in our stock price, including fluctuations as a result of
the announcement of the pending acquisition of the Golden Eagle Assets;

- adverse changes in the ratings assigned to our trade credit and debt
instruments;

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

- the direct or indirect effects on our business resulting from terrorist
incidents or acts of war;

- political developments in foreign countries;

- changes in our inventory levels;

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

- changes in fuel and utility costs for our facilities;

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

- execution of planned capital projects;

47

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

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

- actions of customers and competitors;

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

- earthquakes or other natural disasters affecting operations.

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

COMMODITY PRICE RISKS

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

The prices at which we sell our refined products are influenced by the
commodity price of crude oil. Generally, an increase or decrease in the price of
crude oil results in a corresponding increase or decrease in the price of
gasoline and other refined products. The timing of the relative movement of the
prices, however, can impact profit margins which could significantly affect our
earnings and cash flows. In addition, crude oil supply contracts generally are
short-term in nature with market-responsive pricing provisions. We normally
purchase refinery feedstocks prior to selling the refined products manufactured.
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.

We maintain inventories of crude oil, intermediate products and refined
products, the values of which are subject to fluctuations in market prices. In
our Refining and Retail segments, our inventories of refinery feedstocks and
refined products totaled 17.2 million barrels and 11.9 million barrels at
December 31, 2001 and 2000, respectively. The weighted average cost of the 5.3
million barrel increase, primarily due to the purchase of inventories in the
Mid-Continent Acquisition on September 6, 2001, was $28.52 per barrel. Sales
that result in a reduction in LIFO inventories during 2002 could have a per
barrel cost of sales in excess of the current cost of sales during 2002. The
average cost of our refinery feedstocks and refined product inventories as of
December 31, 2001 was $23.14 per barrel. We may be required to write down the
carrying value of this inventory if market prices for refined products decline
from year-end 2001 levels to a level below the average cost of these
inventories.

48

We periodically enter into derivative type arrangements on a limited basis,
as part of our programs to acquire refinery feedstocks at reasonable costs and
to manage margins on certain refined product sales. We also engage in limited
non-hedging activities which are marked to market with changes in the fair value
of the derivative recognized in earnings. At December 31, 2001, we had open
price swap transactions for 200,000 barrels of gasoline which settle in the
first quarter of 2002. Recording the fair value of these swaps resulted in a
mark-to-market loss of $39,000 in 2001. 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, 2001, we had $625 million of outstanding floating-rate debt
under the senior secured credit facility and $522 million of fixed-rate debt.
The weighted average interest rate on the floating-rate debt was 5.35% at
December 31, 2001. The impact on annual cash flow of a 10% change in the
floating-rate for our senior secured credit facility (54 basis points) would be
approximately $3 million.

The fair market value of our fixed-rate debt at December 31, 2001 was
approximately $12 million more than its book value of $522 million, based on
recent transactions and bid quotes for our senior subordinated notes due 2008.

Interest rates have trended downwards in 2001 and presently are at
historically low levels. Future increases in interest rates would increase our
expenses and may affect our ability to access capital markets for additional
financing.

49

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, 2001
and 2000, and the related statements of consolidated operations, stockholders'
equity and cash flows for each of the three years in the period ended December
31, 2001. 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, 2001 and 2000, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2001 in conformity with accounting principles generally accepted in
the United States of America.

/s/ DELOITTE & TOUCHE LLP

San Antonio, Texas
January 29, 2002
(February 20, 2002 as to Note Q, Subsequent Event)

50

TESORO PETROLEUM CORPORATION

STATEMENTS OF CONSOLIDATED OPERATIONS
(IN MILLIONS EXCEPT PER SHARE AMOUNTS)

The accompanying notes are an integral part of these consolidated financial
statements.
51

TESORO PETROLEUM CORPORATION

CONSOLIDATED BALANCE SHEETS
(DOLLARS IN MILLIONS EXCEPT PER SHARE AMOUNTS)

The accompanying notes are an integral part of these consolidated financial
statements.
52

TESORO PETROLEUM CORPORATION

STATEMENTS OF CONSOLIDATED STOCKHOLDERS' EQUITY
(IN MILLIONS)

The accompanying notes are an integral part of these consolidated financial
statements.
53

TESORO PETROLEUM CORPORATION

STATEMENTS OF CONSOLIDATED CASH FLOWS
(IN MILLIONS)

The accompanying notes are an integral part of these consolidated financial
statements.
54

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE A -- SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Description and Nature of Business

Tesoro Petroleum Corporation ("Tesoro" or the "Company") was incorporated
in Delaware in 1968 and is an independent refiner and marketer of petroleum
products and provider of marine logistics services. Tesoro owns and operates
five petroleum refineries in the western and mid-continental United States with
a combined rated crude oil capacity of 390,000 barrels per day and sells refined
products to a wide variety of customers in the western and mid-continental
United States and other countries on the Pacific Rim. Tesoro markets products to
wholesale and retail customers, as well as commercial end-users. Tesoro's retail
business includes a network of 677 branded retail stations. The Company also
operates a network of terminals along the Texas and Louisiana Gulf Coast that
provides fuel and logistical support services to the marine and offshore
exploration and production industries.

Tesoro's operations can be influenced by domestic and international,
political, legislative and regulatory environments. In addition, significant
changes in the prices or availability of crude oil and refined products could
have a significant impact on results of operations, cash flows and financial
position of the Company.

Principles of Consolidation

The accompanying Consolidated Financial Statements include the accounts of
Tesoro and its subsidiaries. All significant intercompany accounts and
transactions have been eliminated. Investments in 50% or less owned entities are
accounted for using the equity method.

Basis of Presentation

Certain previously reported amounts have been reclassified to conform to
the 2001 presentation. The Company has reclassified corporate general and
administrative expenses and other expenses to selling, general and
administrative, which is included as a charge to operating income in the
Statements of Consolidated Operations. In addition, the Company has reclassified
segment information to report the following segments: (i) Refining, (ii) Retail
and (iii) Marine Services (see Note D).

Unless otherwise stated, the Notes to Consolidated Financial Statements
exclude discontinued operations (see Note E).

Use of Estimates

Preparation of the Company's Consolidated Financial Statements in
conformity with accounting principles generally accepted in the United States of
America ("U.S. GAAP") requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities and disclosures of
contingent assets and liabilities at the date of the financial statements and
the reported amounts of revenues and expenses during the year. Actual results
could differ from those estimates.

Cash and Cash Equivalents

The Company considers 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. The Company's policy is to invest cash in conservative,
highly-rated instruments and to invest in various financial institutions to
limit the amount of credit exposure in any one institution. The Company monitors
the credit standing of these financial institutions.

55

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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 maturity of these instruments. The
carrying amounts of the Company's variable rate debt approximates fair value.
The carrying amounts of the Company's fixed-rate debt and other obligations may
vary from the Company's estimates of the fair value of such items. At December
31, 2001, the fair market value of the Company's fixed-rate debt was estimated
by management to be approximately $12 million more than its book value of $522
million.

Inventories

Inventories are stated at the lower of cost or market. The last-in,
first-out ("LIFO") method is used to determine the cost of inventories of crude
oil and refined products in the Refining and Retail segments. The cost of fuel
at Marine Services terminals is determined on the first-in, first-out ("FIFO")
method. The carrying value of petroleum inventories is sensitive to volatile
market prices. Merchandise and materials and supplies are valued at average
cost, not in excess of market value.

Property, Plant and Equipment

Additions to property, plant and equipment and major improvements and
modifications are capitalized at cost. Depreciation of property, plant and
equipment is generally computed on the straight-line method based upon the
estimated useful life of each asset. The weighted average lives range from 27 to
28 years for refineries, 6 to 16 years for terminals, 11 to 16 years for retail
stations, 9 to 29 years for transportation assets, and 3 to 13 years for
corporate and other assets.

The Company capitalizes interest on major projects during extended
construction periods. Such interest is allocated to property, plant and
equipment and amortized over the estimated useful lives of the related assets.
Interest and financing costs incurred totaled $57.9 million, $33.4 million and
$38.2 million in 2001, 2000 and 1999, respectively, of which $5.1 million, $0.7
million and $0.6 million was capitalized during 2001, 2000 and 1999,
respectively.

Environmental Expenditures

Environmental expenditures that extend the life or increase the capacity of
facilities, or expenditures that mitigate or prevent environmental contamination
that is yet to occur, are capitalized. Expenditures that relate to an existing
condition caused by past operations, and which do not contribute to current or
future revenue generation, are expensed. Liabilities are recorded when
environmental assessments and/or remedial efforts are probable. Cost estimates
are based on the expected timing and 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
the Company's 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 the Company's
commitment to a formal plan of action. Estimated liabilities are not discounted
to present value.

Other Assets

The cost over the fair value of net assets acquired, or goodwill (excluding
goodwill related to the 2001 acquisitions, as discussed in Note C) is amortized
by the straight-line method over 28 years for Refining and Retail assets, and 20
years for Marine Services assets. Goodwill amortization, which amounted to $2.7
million in 2001, is included in depreciation and amortization in the Statements
of Consolidated Operations. Goodwill will not be amortized in years subsequent
to 2001 as required by Statement of Financial Accounting Standards ("SFAS") No.
142, "Goodwill and Other Intangible Assets".

56

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Intangible assets other than goodwill consist primarily of purchased
intangible assets which are stated at fair value as of the date acquired in a
business combination, less accumulated amortization. Amortization is computed on
a straight-line basis over estimated useful lives of 3 to 28 years. Amortization
of intangible assets other than goodwill is primarily included in depreciation
and amortization in the Statements of Consolidated Operations.

Refinery processing units are shut down periodically for major scheduled
maintenance, or turnarounds. Certain catalysts are used in refinery process
units for periods exceeding one year. Also, ships, tugs and barges are drydocked
for periodic maintenance. Turnaround, catalyst and drydocking costs are deferred
and amortized on a straight-line basis over the expected periods of benefit
generally ranging from 23 to 48 months. Amortization of such deferred costs is
included in costs of sales and operating expenses in the Statements of
Consolidated Operations.

Debt issuance costs are deferred and amortized over the estimated terms of
each instrument.

Impairment of Long-Lived Assets

Property, plant and equipment and other long-lived assets, such as goodwill
and intangible assets, are reviewed for impairment whenever events or changes in
business circumstances indicate the carrying values of the assets may not be
recoverable. Impairment losses would be recorded when the undiscounted cash
flows estimated to be generated by those assets are less than the carrying
amount of those assets.

Revenue Recognition

The Company recognizes revenues from product sales and services upon
delivery to customers and when all significant obligations have been satisfied.

Shipping and Handling Fees and Costs

Shipping and handling fees charged to customers are included in revenues
and the related costs are included in costs of sales and operating expenses in
the Statements of Consolidated Operations.

Excise Taxes

Revenues and costs of sales and operating expenses included $81 million and
$43 million of federal excise and state motor fuel taxes collected from
customers and remitted to governmental agencies in 2001 and 2000, respectively.
These taxes were primarily related to sales of gasoline and diesel in the Retail
segment.

Income Taxes

Deferred tax assets and liabilities are recognized for future income tax
consequences attributable to differences between financial statement carrying
amounts of assets and liabilities and their respective tax bases. Measurement of
deferred tax assets and liabilities is based on enacted tax rates expected to
apply to taxable income in the years in which those temporary differences are
expected to be recovered or settled. The effect on deferred tax assets and
liabilities of a change in tax rates is recognized in the period that includes
the enactment date.

Stock-Based Compensation

The Company accounts for stock-based compensation using the intrinsic value
method prescribed in Accounting Principles Board ("APB") Opinion No. 25,
"Accounting for Stock Issued to Employees," and related interpretations.
Accordingly, compensation cost for stock options is measured as the excess, if
any, of

57

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

the quoted market price of the Company's Common Stock at the date of grant over
the amount an employee must pay to acquire the stock (see Note N).

Derivative Instruments

Effective January 1, 2001, the Company adopted SFAS No. 133, "Accounting
for Derivative Instruments and Hedging Activities," as amended by SFAS No. 138.
SFAS No. 133, as amended and interpreted, establishes accounting and reporting
standards for derivative instruments, including certain derivative instruments
embedded in other contracts, and for hedging activities. SFAS No. 133 requires
all derivatives to be recorded on the balance sheet at fair value. The
accounting for changes in the fair value of a derivative depends on the intended
use of the derivative and the designation if in a hedging relationship. The
adoption of SFAS No. 133 did not have a significant impact on the Company's
financial condition, results of operations or cash flows.

The Company 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. The Company also
engages in limited non-hedging derivatives which are marked to market with
changes in the fair value of the derivatives recognized in earnings in the
Statements of Consolidated Operations and the carrying amounts included in other
current assets or accrued liabilities in the Consolidated Balance Sheets. At
December 31, 2001, the Company had open price swap transactions for 200,000
barrels of gasoline which will settle in the first quarter of 2002. Recording
the fair value of these swaps resulted in a mark-to-market loss of $39,000 in
2001. As of December 31, 2001, the Company did not have any derivative
instruments that were designated and accounted for as hedges. The Company
believes that substantially all of its supply and marketing agreements are
normal purchases and sales and that pricing provisions in other agreements are
not embedded derivatives.

New Accounting Standards and Disclosures

SFAS No. 141 and SFAS No. 142

In June 2001, the Financial Accounting Standards Board ("FASB") issued SFAS
No. 141, "Business Combinations," and SFAS No. 142, "Goodwill and Other
Intangible Assets." SFAS No. 141 requires the purchase method of accounting for
all business combinations initiated after June 30, 2001 and that certain
acquired intangible assets in a business combination be recognized as assets
separate from goodwill. 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. SFAS No. 142 requires
that an impairment test related to the carrying values of existing goodwill be
completed within the first six months of 2002. Impairment losses on existing
goodwill, if any, would be recorded as the cumulative effect of a change in
accounting principle as of the beginning of 2002. SFAS No. 141 and 142 apply to
the acquisitions in 2001 discussed in Note C. The Company believes that the
carrying amount of its goodwill has not been impaired although the detailed
evaluations required by SFAS 142 have not been completed.

SFAS No. 143

In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset
Retirement Obligations." SFAS No. 143 requires an asset retirement obligation to
be recorded at fair value during the period incurred and an equal amount
recorded as an increase in the value of the related long-lived asset. The
capitalized cost is depreciated over the useful life of the asset and the
obligation is accreted to its present value each period. SFAS No. 143 is
effective for the Company beginning January 1, 2003 with earlier adoption
encouraged. The Company is currently evaluating the impact the standard will
have on its future results of operations and financial condition.

58

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

SFAS No. 144

In August 2001, the FASB issued SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets", effective beginning January 1,
2002. SFAS No. 144 retains the requirement to recognize an impairment loss only
where the carrying value of a long-lived asset is not recoverable from its
undiscounted cash flows and to measure such loss as the difference between the
carrying amount and fair value of the asset. SFAS No. 144, among other things,
changes the criteria that have to be met to classify an asset as held-for-sale
and requires that operating losses from discontinued operations be recognized in
the period that the losses are incurred rather than as of the measurement date.
The Company adopted the accounting standard effective January 1, 2002 which did
not have a significant impact on the Company's financial condition or results of
operations. For information regarding the Company's evaluation of strategic
opportunities for the Marine Services segment, see Note D.

Proposed Statement of Position

The American Institute of Certified Public Accountants has issued an
Exposure Draft for a Proposed Statement of Position, "Accounting for Certain
Costs and Activities Related to Property, Plant and Equipment" which would
require major maintenance activities to be expensed as costs are incurred. If
this proposed Statement of Position is adopted in its current form, the Company
will be required to write off the balance of deferred maintenance costs, which
totaled $44.1 million at December 31, 2001, and expense future costs as
incurred.

NOTE B -- EARNINGS PER SHARE

Basic earnings per share are determined by dividing net earnings applicable
to Common Stock by the weighted average number of common shares outstanding
during the period. The calculation of diluted earnings per share takes into
account the effects of potentially dilutive shares outstanding during the
period, principally the maximum shares which would have been issued assuming
conversion of Preferred Stock at the beginning of the period and stock options.
The assumed conversion of Preferred Stock to Common Stock produced anti-
dilutive results in 1999, and, in accordance with SFAS No. 128, "Earnings per
Share," was not included in the dilutive calculation. The Preferred Stock was
converted into 10.35 million shares of Common Stock in July 2001. Earnings per
share calculations are presented below (in millions except per share amounts):

59

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

NOTE C -- ACQUISITIONS AND EXPANSIONS

Acquisitions of Mid-Continent Refineries and Related Retail Operations

On September 6, 2001, the Company acquired two refineries in North Dakota
and Utah and related storage, distribution and retail assets from certain
affiliates of BP p.l.c. ("BP"). The acquired assets include a 60,000 barrels per
day ("bpd") refinery in Mandan, North Dakota and a 55,000 bpd refinery in Salt
Lake City, Utah. The acquired assets also include related bulk storage
facilities, eight product distribution terminals, and retail assets consisting
of 42 retail stations and contracts to supply a jobber network of over 280
retail stations. In connection with the acquisition of the North Dakota
refinery, the Company purchased the North Dakota-based, common-carrier crude oil
pipeline and gathering system ("Pipeline System") from certain affiliates of BP
on November 1, 2001. The Pipeline System is the primary crude supply carrier for
the Company's Mandan, North Dakota refinery. The purchase of the Pipeline System
and the acquisition of the North Dakota and Utah refineries and related storage,
distribution and retail assets are collectively referred to as the
"Mid-Continent Acquisition." The Mid-Continent Acquisition enables the Company
to increase the size and scope of its operations, diversify its earnings and
geographic exposure, and build a platform for additional growth. The Company
paid $756.1 million in cash (including $83.0 million for hydrocarbon
inventories) for these assets. The purchase price was determined through a
competitive bid process. In addition, the Company incurred direct costs related
to this transaction of $8.4 million. The Mid-Continent Acquisition was funded
through borrowings under a new senior secured credit facility and a senior
subordinated notes offering (see Note F).

In connection with the Mid-Continent Acquisition, Tesoro assumed certain
liabilities and obligations (including costs associated with transferred
employees and environmental matters) related to the acquired assets, subject to
specified levels of indemnification. These include, subject to certain
exceptions, certain of the sellers' obligations, liabilities, costs and expenses
for violations of health, safety and environmental laws relating to the assets,
including certain known and unknown obligations, liabilities, costs and expenses
arising or incurred prior to, on or after the closing dates. In addition, the
Company has agreed to indemnify the sellers

60

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

for all losses of any kind incurred in connection with or related to these
assumed liabilities. See Note O for environmental matters related to the
Mid-Continent Acquisition.

Under SFAS No. 141, "Business Combinations", the Mid-Continent Acquisition
was accounted for as a purchase, whereby the purchase price was allocated to the
assets acquired and liabilities assumed based upon their respective fair market
values at the date of acquisition. The accompanying financial statements reflect
the preliminary purchase price allocation, which remains subject to change
pending completion of independent appraisals and other evaluations. The 2001
financial statements include the results of operations of the Mid-Continent
Acquisition since the dates of acquisition.

The preliminary purchase price allocation as of December 31, 2001,
including direct costs incurred in the Mid-Continent Acquisition, is as follows
(in millions):

Inventories................................................. $127.5
Property, plant and equipment............................... 582.5
Goodwill.................................................... 34.7
Other intangible assets..................................... 67.9
Deferred turnaround costs................................... 10.6
Net deferred tax assets..................................... 9.1
Product exchange payable.................................... (32.6)
Accrued liabilities......................................... (10.6)
Other liabilities........................................... (24.6)
------
Total purchase price...................................... $764.5
======

The acquired other intangible assets of $67.9 million have a
weighted-average useful life of approximately 19 years. The other intangible
assets consist of refinery permits and plans totaling $23.9 million (27 year
weighted-average life), jobber agreements totaling $23.5 million (20 year
weighted-average life), customer contracts totaling $16.7 million (5 year
weighted-average life), and refinery technology totaling $3.8 million (28 year
weighted-average life). The Company recorded $34.7 million of goodwill, of which
$21.0 million is expected to be deductible for tax purposes. The goodwill was
preliminarily assigned to the Refining and Retail segments in the amounts of
$25.7 million and $9.0 million, respectively.

The following unaudited pro forma financial information for the years ended
December 31, 2001 and 2000 gives effect to (i) the Mid-Continent Acquisition,
(ii) the financing of the Company's Senior Secured Credit Facility, as amended,
and (iii) the issuance of the 9 5/8% Senior Subordinated Notes (see Note F), as
if each had occurred at the beginning of the periods presented. This pro forma
information is not necessarily indicative of the results of future operations.

Refining Expansions

During 2000, the Company commenced a heavy oil conversion project at its
Washington refinery which will enable the Company to process a larger proportion
of lower-cost heavy crude oils, to manufacture a larger

61

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

proportion of higher-value gasoline and to reduce production of lower-value
heavy products. The project, which is estimated to cost approximately $116
million (including capitalized interest), is expected to be completed by the end
of the first quarter of 2002. The Company's capital spending totaled
approximately $97 million through 2001 for this project.

Retail Expansions

In January 2000, the Company entered into an agreement with Wal-Mart
Stores, Inc. ("Wal-Mart") to build and operate retail fueling facilities on
sites at selected existing and future Wal-Mart store locations in the western
United States. The Company introduced the new "Mirastar" brand which is used
exclusively in its program with Wal-Mart. Capital spending for the Mirastar
sites and other retail projects, including costs of Company-owned and operated
facilities and expansion of Tesoro's branded jobber/dealer network, totaled
approximately $43 million and $31 million during 2001 and 2000, respectively. In
addition, in November 2001, the Company acquired 46 retail fueling facilities,
including 37 retail stations with convenience stores and nine commercial card
lock facilities, located in Washington, Oregon and Idaho.

NOTE D -- OPERATING SEGMENTS

The Company's revenues are derived from three operating segments: (i)
Refining, (ii) Retail and (iii) Marine Services. Management has identified these
segments for managing operations and investing activities. During the fourth
quarter of 2001, management began evaluating separate financial information of
the Company's retail operations in assessing performance and allocating
resources, reflecting the Company's retail growth through internal expansion,
the acquisition of retail sites from BP in September 2001 and the acquisition of
certain other retail sites. The Company has reclassified previously reported
segment information to present the Retail segment separately from the Refining
segment.

Refining currently owns and operates five petroleum refineries located in
Alaska and Washington (the "Pacific Northwest"), Hawaii (the "Mid-Pacific") and
North Dakota and Utah (the "Mid-Continent"). These refineries manufacture
gasoline and gasoline blendstocks, jet fuel, diesel fuel, heavy oils and other
refined products. These products, together with products purchased from third
parties, are sold at wholesale through terminal facilities and other locations,
primarily in Alaska, California, Hawaii, Idaho, Minnesota, North Dakota, Utah
and Washington. Refining also sells petroleum products to unbranded marketers
and occasionally exports products to other markets in the Asia/Pacific area.

Retail sells gasoline, diesel fuel and convenience store items through
Company-owned retail stations and branded jobber/dealers in 18 western states
from Minnesota to Alaska and Hawaii. Retail operates under the Tesoro, Mirastar
and other brands. Mirastar sites have been developed exclusively for Wal-Mart
stores in an agreement covering seventeen western states. Other branded
jobber/dealers are part of the retail system acquired from BP in September 2001.

Marine Services markets and distributes petroleum products, water, drilling
mud and other supplies and services primarily to the marine and offshore
exploration and production industries operating in the Gulf of Mexico. This
segment operates through terminals along the Texas and Louisiana Gulf Coast. The
Company is evaluating various strategic opportunities to capitalize on the value
of the Marine Services assets, including a possible sale of all or a part of
this business.

The operating segments follow the same accounting policies used for the
Company's Consolidated Financial Statements and described in the summary of
significant policies in Note A. Management evaluates the performance of its
segments and allocates resources based on segment operating income and EBITDA,
as described below.

Segment operating income includes those revenues and expenses that are
directly attributable to management of the respective segment. Intersegment
sales are primarily from Refining to Retail made at
62

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

prevailing market rates. Income taxes, interest and financing costs, interest
income and corporate general and administrative expenses are not included in
determining segment operating income.

EBITDA represents earnings before extraordinary items, interest and
financing costs, interest income, income taxes, and depreciation and
amortization. While not purporting to reflect any U.S. GAAP measurement of the
Company's operations or cash flows, EBITDA is used by management for additional
analysis. Operating segment EBITDA is equal to segment operating income before
depreciation and amortization related to each segment. Identifiable assets are
those assets utilized by the segment. Corporate assets are principally cash and
other assets that are not associated with an operating segment.

Segment information as of and for each of the three years in the period
ended December 31, 2001 is as follows (in millions):

63

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

- ---------------

(a) Excluding refining and retail asset acquisitions of $783.4 million in 2001
(see Note C).

64

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

NOTE E -- DISCONTINUED OPERATIONS

In December 1999, the Company completed the sales of its domestic and
Bolivian exploration and production operations. The net cash proceeds of
approximately $307 million were used primarily to reduce debt in 1999 and early
2000. Earnings from discontinued operations for the year ended December 31, 1999
were as follows (in millions):

Operating Results from Discontinued Operations:
Revenues.................................................. $65.4
Costs and expenses........................................ 44.6
Allocated interest expense................................ 10.6
-----
Results of operations, pretax.......................... 10.2
Income tax expense........................................ 6.5
-----
Results of operations, aftertax........................ 3.7
-----
Gain from Sales of Discontinued Operations:
Gain, pretax.............................................. 62.2
Income tax expense........................................ 23.1
-----
Gain, aftertax............................................ 39.1
-----
Total Discontinued Operations........................ $42.8
=====

NOTE F -- DEBT AND OTHER OBLIGATIONS

Debt and other obligations at December 31, 2001 and 2000 consisted of the
following (in millions):

At December 31, 2001, aggregate maturities of outstanding debt and other
obligations for each of the five years following December 31, 2001 were as
follows: 2002 -- $34.4 million; 2003 -- $40.6 million; 2004 -- $40.7 million;
2005 -- $40.7 million; and 2006 -- $49.3 million. Gross borrowings and
repayments under revolving credit lines and interim facilities amounted to $958
million during 2001 and $866 million during 2000. In 1999, gross repayments
under a revolving credit line amounted to $550 million, while gross borrowings
amounted to $489 million.

Senior Secured Credit Facility

In September 2001, the Company entered into a senior secured credit
facility (the "Senior Secured Credit Facility"). The Senior Secured Credit
Facility replaced the Company's previous unsecured credit facility which
provided for $250 million in total commitments. The Senior Secured Credit
Facility, as amended, consists of a five-year $175 million revolving credit
facility (with a $90 million sublimit for letters of credit), a five-year $85
million tranche A term loan, a five-year $90 million delayed draw term loan
(used to

65

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

fund the purchase of the Pipeline System), a six-year $450 million tranche B
term loan and a $200 million capital markets term loan. In November 2001, the
Company repaid the $200 million capital markets term loan with the proceeds of
the 9 5/8% Senior Subordinated Notes, as described below. At December 31, 2001,
the Company had no borrowings and $0.8 million in letters of credit outstanding
under the revolving credit facility. Total unused credit available under the
revolving credit facility at December 31, 2001 was $174.2 million.

The Senior Secured Credit Facility is guaranteed by substantially all of
the Company's active domestic subsidiaries and is secured by substantially all
of the Company's material present and future assets as well as all material
present and future assets of the Company's domestic subsidiaries (with certain
exceptions for pipeline, retail and marine services assets), and is additionally
secured by a pledge of all of the stock of all current active and future
domestic subsidiaries and 66% of the stock of the Company's current and future
foreign subsidiaries.

The Senior Secured Credit Facility requires the Company to maintain
specified levels of interest and fixed charge coverage and sets limitations on
the Company's debt-to-capital and leverage ratios. It also contains other
covenants and restrictions customary in credit arrangements of this kind. The
terms allow for payment of cash dividends on the Company's Common Stock and
repurchases of shares of its Common Stock, not to exceed $15 million in any
year.

Borrowings rates under the senior secured credit facility are based on a
pricing grid. Borrowings bear interest at either a base rate (4.75% at December
31, 2001) or a eurodollar rate (ranging from 2.10% to 2.14% at December 31,
2001), plus an applicable margin. The applicable margin at December 31, 2001 for
the tranche A term loan, the delayed draw term loan and the revolving credit
facility is 1.25% in the case of the base rate and 2.25% in the case of the
eurodollar rate. The applicable margin for the tranche B term loan is 1.75% in
the case of the base rate and 2.75% in the case of the eurodollar rate.
Additionally, the tranche B eurodollar rate is deemed to be no less than 3.0%.
These margins are the highest margins applicable to the respective base and
eurodollar rates and will vary in relation to ratios of the Company's
consolidated total debt to consolidated EBITDA, as defined in the Senior Secured
Credit Facility. In addition, at any time during which the Senior Secured Credit
Facility is rated at least BBB- by Standard and Poor's Rating Services and Baa3
by Moody's Investors Service, Inc., each applicable margin will be reduced by
0.125%. The Company is also charged various fees and expenses in connection with
the Senior Secured Credit Facility, including commitment fees and various letter
of credit fees.

9 5/8% Senior Subordinated Notes

In November 2001, the Company issued $215 million aggregate principal
amount of 9 5/8% senior subordinated notes due November 1, 2008 ("9 5/8% Senior
Subordinated Notes"). The 9 5/8% Senior Subordinated Notes have a seven-year
maturity with no sinking fund requirements and are subject to optional
redemption by the Company after four years at declining premiums. The Company,
for the first three years, may redeem up to 35% of the aggregate principal
amount at a redemption price of 109.625% with net cash proceeds of one or more
equity offerings. The indenture for the 9 5/8% Senior Subordinated Notes
contains covenants and restrictions which are customary for notes of this
nature. The restrictions under the indenture are less restrictive than those in
the Senior Secured Credit Facility. To the extent the Company's fixed charge
coverage ratio, as defined in the indenture, allows for the incurrence of
additional indebtedness, the Company is allowed to pay cash dividends on Common
Stock and repurchase shares of Common Stock. The proceeds from the 9 5/8% Senior
Subordinated Notes were used to repay the indebtedness incurred under the
capital markets term loan, to pay accrued interest on the capital markets term
loan, to pay certain fees and expenses related to the 9 5/8% Senior Subordinated
Notes and for general corporate purposes. The 9 5/8% Senior Subordinated Notes
are guaranteed by substantially all of the Company's active domestic
subsidiaries.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

9% Senior Subordinated Notes

In 1998, the Company issued $300 million aggregate principal amount of 9%
Senior Subordinated Notes due 2008, Series B ("9% Senior Subordinated Notes").
The 9% Senior Subordinated Notes have a ten-year maturity without sinking fund
requirements and are subject to optional redemption by the Company after five
years at declining premiums. The indenture for the 9% Senior Subordinated Notes
contains covenants and restrictions which are customary for notes of this
nature. The restrictions under the indenture are less restrictive than those in
the Senior Secured Credit Facility. To the extent the Company's fixed charge
coverage ratio, as defined in the indenture, allows for the incurrence of
additional indebtedness, the Company is allowed to pay cash dividends on Common
Stock and repurchase shares of Common Stock. The effective interest rate on the
9% Senior Subordinated Notes is 9.16%, after giving effect to the discount at
the date of issue. The 9% Senior Subordinated Notes are guaranteed by
substantially all of the Company's active domestic subsidiaries.

Capital Leases

Capital leases are primarily for tugs and barges used in transportation of
petroleum products in Hawaii. At December 31, 2001 and 2000, the cost of fixed
assets under capital leases was $9.3 million gross (accumulated amortization of
$3.7 million) and $10.0 million gross (accumulated amortization of $3.1
million), respectively. Capital lease obligations included in debt totaled $6.6
million and $7.7 million at December 31, 2001 and 2000, respectively.

NOTE G -- STOCKHOLDERS' EQUITY

The Company has a universal shelf registration statement ("Shelf
Registration") for debt or equity securities to be used for acquisitions or
general corporate purposes. At December 31, 2001, the amount available under the
Shelf Registration was $343 million.

In July 1998, the Company issued 10,350,000 Premium Income Equity
Securities ("PIES(SM)"), representing fractional interests in the Company's
7.25% Mandatorily Convertible Preferred Stock, for gross proceeds of $165
million. Effective July 1, 2001, the PIES(SM) automatically converted into
10,350,000 shares of Common Stock. The final quarterly cash dividends on the
PIES(SM) were paid on July 2, 2001.

In February 2000, the Company's Board of Directors authorized the
repurchase of up to 3 million shares of Common Stock. Under the program, the
Company may make repurchases from time to time in the open market and through
privately-negotiated transactions. Purchases depend on price, market conditions
and other factors and have been made primarily from internally-generated cash
flow. The stock may be used to meet employee benefit plan requirements and other
corporate purposes. During the year ended December 31, 2000, the Company
repurchased 1.6 million shares of Common Stock for $15.5 million, or an average
cost per share of $9.54. In 2001, the Company repurchased an additional 304,000
shares of its Common Stock at an average cost of $11.50 per share, or an
aggregate of approximately $3.5 million, bringing the cumulative shares
repurchased under the program to 1,931,400.

See Note F for information concerning restrictions on the repurchase of
Common Stock and Note N for information relating to stock-based compensation and
Common Stock reserved for exercise of options.

67

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

NOTE H -- INCOME TAXES

The income tax provision on earnings from continuing operations for the
years ended December 31, 2001, 2000 and 1999 included the following (in
millions):

Deferred income taxes and benefits are provided 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, 2001 and 2000 are summarized as follows
(in millions):

In 2001, the Mid-Continent Acquisition described in Note C resulted in net
deferred federal tax assets of $8.0 million and net deferred state tax assets of
$1.1 million as of the dates of acquisition.

68

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The reconciliation of income tax expense at the U.S. statutory rate to the
income tax expense pertaining to continuing operations is as follows (in
millions):

The Company's income tax returns are subject to examinations by federal,
state and local tax authorities. The Company believes that it has made adequate
provisions for income taxes that may become payable with respect to examinations
of open tax years.

NOTE I -- RECEIVABLES

Concentrations of credit risk with respect to accounts receivable are
influenced by the large number of customers comprising the Company's customer
base and their dispersion across various industry groups and geographic areas of
operations. The Company performs ongoing credit evaluations of its customers'
financial condition and in certain circumstances requires letters of credit or
other collateral arrangements. The Company's allowance for doubtful accounts is
reflected as a reduction of receivables in the Consolidated Balance Sheets and
amounted to $3.2 million and $2.1 million at December 31, 2001 and 2000,
respectively.

NOTE J -- INVENTORIES

Components of inventories at December 31, 2001 and 2000 were as follows (in
millions):

At December 31, 2001 and 2000, inventories valued using LIFO were lower
than replacement cost by approximately $3 million and $120 million,
respectively. During 1999, certain inventory quantities were reduced, resulting
in a liquidation of applicable LIFO inventory quantities carried at lower costs
prevailing in previous years. This LIFO liquidation resulted in a decrease in
cost of sales of $8.4 million and an increase in earnings from continuing
operations of approximately $5.3 million aftertax, or $0.16 per share, during
1999.

69

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

NOTE K -- OTHER ASSETS

Other assets consisted of the following at December 31, 2001 and 2000 (in
millions):

NOTE L -- ACCRUED LIABILITIES

The Company's current accrued liabilities and noncurrent other liabilities
as shown in the Consolidated Balance Sheets at December 31, 2001 and 2000
included the following (in millions):

NOTE M -- BENEFIT PLANS

Pension and Other Postretirement Benefits

The Company sponsors defined benefit pension plans, including an employee
retirement plan, executive security plans and a non-employee director retirement
plan.

For all eligible employees, the Company provides a qualified
noncontributory retirement plan ("Retirement Plan"). Plan benefits are based on
years of service and compensation. The Company'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. Retirement plan assets are primarily comprised of common stock and
bond funds.

The Company's executive security plans ("ESP Plans") provide executive
officers and other key personnel with supplemental death or retirement plan
benefits. Such benefits are provided by two nonqualified, noncontributory plans
and are based on years of service and compensation. The Company makes
contributions to one plan, the "Funded ESP Plan", based upon estimated
requirements. Assets of the Funded ESP plan consist of a group annuity contract.

The Company had previously established an unfunded non-employee director
retirement plan ("Director Retirement Plan") which provided eligible directors
retirement payments upon meeting certain age and other requirements. In 1997,
the Director Retirement Plan was frozen with accrued benefits of current
directors transferred to the Company's Board of Directors Phantom Stock Plan
("Phantom Stock Plan") (see

70

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Note N). After the amendment and transfer, only those retired directors or
beneficiaries who had begun to receive benefits remained participants in the
Director Retirement Plan.

SFAS No. 132, "Employers' Disclosures about Pensions and Other
Postretirement Benefits," requires the Company to disclose the aggregate
projected benefit obligations, accumulated benefit obligations and fair value of
plan assets for pension plans with accumulated benefit obligations in excess of
plan assets. At December 31, 2001, the projected benefit obligations,
accumulated benefit obligations and fair values of plan assets aggregated $112.8
million, $86.3 million and $57.6 million, respectively, for three of the plans.
The assets of the Funded ESP Plan exceeded its accumulated benefit obligation at
year-end 2001. At December 31, 2000, the projected benefit obligations,
accumulated benefit obligations and fair values of plan assets aggregated $92.9
million, $71.5 million and $62.3 million, respectively, for three of the plans.
The assets of the Funded ESP Plan exceeded its accumulated benefit obligation at
year-end 2000.

The Company provides to retirees who were participating in the Company's
group insurance program at retirement, health care and, to those who qualify,
life insurance benefits. Health care is provided 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. The
Company funds its share of the cost of postretirement health care and life
insurance benefits on a pay-as-you go basis.

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):

71

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Financial information related to the Company's pension plans and other
postretirement benefits is presented below (in millions except percentages):

In 2001, the Company announced amendments to the pension plan by adding a
lump-sum distribution option and enhanced early retirement provisions for
long-term employees. These changes, along with changes to comply with new
regulations, increased the Company's pension benefit obligation by $9 million
and postretirement benefit obligation by $2 million during 2001.

72

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The weighted average annual assumed rate of increase in the per capita cost
of covered health care benefits was assumed to be 7.25% for retirees younger
than 65 for 2001, decreasing gradually to 5% by the year 2010, and an initial
9.1% for retirees 65 and older, decreasing gradually to 5.5% by the year 2010
and remaining level thereafter.

Thrift Plan and Retail Savings Plan

The Company sponsors an employee thrift plan ("Thrift Plan") which provides
for contributions, subject to certain limitations, by eligible employees into
designated investment funds with a matching contribution by the Company.
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 the Company's 100% matching contribution, from
a maximum of 6% to 7% of the employee's eligible earnings, with at least 50% of
the Company's matching contribution directed for initial investment in Common
Stock of the Company. Participants may transfer out of Tesoro's Common Stock at
any time, but are limited to four such transfers each calendar year. The
Company's contributions amounted to $6.5 million, $5.4 million and $6.8 million
during 2001, 2000 and 1999, respectively, of which $3.4 million consisted of
treasury stock reissuances in 2001. There were no similar reissuances in 2000 or
1999.

Effective January 1, 2001, the Company 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, the Company 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 Common Stock of the Company. Participants may transfer out of
Tesoro's Common Stock at any time, but are limited to four such transfers each
calendar year. The Company's contributions amounted to $0.1 million during 2001.

NOTE N -- STOCK-BASED COMPENSATION

Incentive Stock Plans

The Company has three employee incentive stock plans, the Key Employee
Stock Option Plan, as amended ("1999 Plan"), the Amended and Restated Executive
Long-Term Incentive Plan ("1993 Plan") and Amended Incentive Stock Plan of 1982
("1982 Plan"). In addition, the Company has the 1995 Non-Employee Director Stock
Option Plan ("1995 Plan"). At December 31, 2001, the Company had 5,387,177
shares of unissued Common Stock reserved for these employee incentive stock
plans and non-employee director plan.

73

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Under the 1993 Plan, shares of Common Stock may be granted in a variety of
forms, including restricted stock, incentive stock options, nonqualified stock
options, stock appreciation rights and performance share and performance unit
awards. At the Company's 2000 Annual Meeting of Stockholders held in May 2000,
an amendment was approved by the shareholders which increased the number of
shares available for grant under the 1993 Plan from 4,250,000 to 5,250,000.
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 20%, 25% or 33% increments per year and expire ten
years from the date of grant. The 1993 Plan will expire, unless earlier
terminated, as to the issuance of awards in the year 2003. At December 31, 2001,
the Company had 439,040 shares available for future grants under the 1993 Plan.

In November 1999, the Company's Board of Directors approved the 1999 Plan
which provides for the granting of stock options to eligible persons employed by
the Company who are not executive officers of the Company. Under the 1999 Plan,
the total number of stock options which may be granted is 800,000 shares. Stock
options may be granted at not less than the fair market value on the date the
options are granted and generally become exercisable after one year in 25%
increments. The options expire after ten years from the date of grant. The Board
of Directors may amend, terminate or suspend the 1999 Plan at any time. At
December 31, 2001, the Company had 81,000 shares available for future grants
under the 1999 Plan.

The 1982 Plan expired in 1994 as to issuance of stock appreciation rights,
stock options and stock awards; however, grants made before the expiration date,
that have not been fully exercised, remain outstanding pursuant to their terms.

The 1995 Plan provides for the grant of up to an aggregate of 150,000
nonqualified stock options to eligible non-employee directors of the Company.
These automatic, non-discretionary stock options are granted at an exercise
price equal to the fair market value per share of the Company's Common Stock as
of the date of grant. The term of each option is ten years, and an option first
becomes exercisable six months after the date of grant. The 1995 Plan will
terminate as to issuance of stock options in February 2005. At December 31,
2001, the Company had 111,000 options outstanding and 16,000 shares available
for future grants under the 1995 Plan.

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

At December 31, 2001, 2000 and 1999, exercisable stock options totaled 3.1
million, 2.4 million and 2.0 million, respectively.
74

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The following table summarizes information about stock options outstanding
under all plans at December 31, 2001 (shares in thousands):

Phantom Stock Plan

Under the Phantom Stock Plan, a yearly credit of $7,250 is made in units to
an account ("Account") of each non-employee director, based upon the closing
market price of the Company's Common Stock on the date of credit. In addition, a
director may elect to have the value of his cash retainer fee deposited
quarterly into the Account in units. Certain non-employee directors also
received a credit in their Account 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 the amount, if any, by which the
market value of the Company's Common Stock changes, is payable in cash at
termination (if vested with three years of service) or at retirement, death or
disability. The Company's results of operations included expense of $144,000,
$201,000 and $44,000 in 2001, 2000 and 1999, respectively, related to the
Phantom Stock Plan.

Phantom Stock Agreement

The chief executive officer of the Company holds 175,000 phantom stock
options, which were granted in 1997 at 100% of the fair value of the Company's
Common Stock on the grant date, or $16.9844 per share. At December 31, 2001, all
of the 175,000 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
1993 Plan.

Incentive Compensation

In October 1998, the Company's Board of Directors unanimously approved the
1998 Performance Incentive Compensation Plan ("Performance Plan"), which is
intended to advance the best interests of the Company and its stockholders by
directly targeting Company performance to align with the ninetieth percentile
historical stock-price growth rate for the Company's peer group. In addition,
the Performance Plan will provide the Company's employees with additional
compensation, contingent upon achievement of the targeted objectives, thereby
encouraging them to continue in the employ of the Company. Under the Performance
Plan, targeted objectives are comprised of the fair market value of the
Company's Common Stock equaling or exceeding an average of $35 per share ("First
Performance Target") and $45 per share ("Second Performance Target") on any 20
consecutive trading days during a period commencing on October 1, 1998 and
ending on the earlier of September 30, 2002, or the date on which the Second
Performance Target is achieved. No costs will be recorded until the First
Performance Target is reached.

75

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Pro Forma Information on Stock-Based Compensation

The Company applies APB Opinion No. 25 and related interpretations in
accounting for its stock-based compensation. Had compensation cost been
determined based on the fair value at the grant dates for awards in accordance
with SFAS No. 123, "Accounting for Stock-Based Compensation," the Company's pro
forma net earnings in 2001, 2000 and 1999 would have been $85.3 million ($2.19
per basic share, $2.04 per diluted share), $68.9 million ($1.82 per basic share,
$1.65 per diluted share), and $71.4 million ($1.83 per basic share, $1.81 per
diluted share), respectively. The fair value of each option grant was estimated
on the date of grant using the Black-Scholes option-pricing model with the
following weighted-average assumptions: expected volatility of 43%, 57% and 48%;
risk free interest rates of 4.9%, 5.8% and 6.1%; expected lives of seven years;
and no dividend yields. The estimated average fair value per share of options
granted during 2001, 2000 and 1999 were $6.72, $6.21 and $7.48, respectively.

NOTE O -- COMMITMENTS AND CONTINGENCIES

Operating Leases

The Company has various noncancellable operating leases related to
buildings, equipment, property, retail facilities, and ship charters. These
leases have remaining primary terms generally up to ten years, with terms of
certain rights-of-way extending up to 29 years, and generally contain multiple
renewal options.

During January 2000, the Company entered into an agreement with Wal-Mart to
build and operate retail fueling facilities on sites at selected existing and
future Wal-Mart store locations in the western United States. Under the
agreement with Wal-Mart, each site is subject to a lease with a ten-year primary
term and an option, exercisable at the Company's discretion, to extend a site's
lease for two additional terms of five years each.

To transport crude oil and refined products, the Company charters two ships
which have primary terms of three and two years. The aggregate annual cost for
these charters is approximately $22 million ending in 2003 with two one-year
options for one ship and a single one-year option for the other ship. The
Company entered into a one-year term charter on a third ship in the second half
of 2001 with an annual cost of approximately $11 million.

In the fourth quarter of 2001, the Company sold 18 gas-fired power
generators that had been purchased and installed at the Washington refinery. At
the same time, the Company leased back these generators for a three-year term.
The lease contains extension and purchase options at fair market value. The
annual lease commitments, included in the table below, amount to $3.1 million
for each of the three years. The $15 million cost to purchase the generators was
reported in capital expenditures, and the $15 million proceeds from their sale
is reported as proceeds from asset sales in the Statement of Consolidated Cash
Flows.

The Company leases its corporate headquarters from a limited partnership in
which the Company owns a 50% limited partnership interest. The initial term of
the lease is 15 years with two five-year renewal options. Included in total rent
expense below are lease payments and operating costs paid to the partnership
totaling $2.5 million, $1.8 million and $0.5 million in 2001, 2000 and 1999,
respectively. The Company accounts for its interest in the partnership using the
equity method of accounting. As such, the partnership's assets, primarily land
and buildings, totaling approximately $18 million and debt of approximately $14
million are not included in the accompanying Consolidated Financial Statements.

76

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Future minimum annual lease payments as of December 31, 2001, for operating
leases having initial or remaining noncancellable lease terms in excess of one
year, including the Wal-Mart leases, ship charters and corporate headquarters,
were as follows (in millions):

2002........................................................ $ 52.7
2003........................................................ 37.1
2004........................................................ 26.7
2005........................................................ 21.3
2006........................................................ 20.7
Remainder................................................... 141.1

Total rental expense for short-term and long-term leases, excluding marine
charters, amounted to approximately $34 million in 2001, $26 million in 2000,
and $27 million in 1999. Total marine charter expense was $32 million in 2001,
$34 million in 2000 and $37 million in 1999. In addition, the Company leases
tugs and barges for its Hawaii operations under capital leases (see Note F)
whereby the Company pays operating costs, such as personnel, repairs,
maintenance and drydocking costs, which amounted to approximately $8 million in
2001. The Company also enters into various short-term charters for vessels to
transport refined products from the Company's refineries and terminals and to
deliver products to customers.

Other Commitments

In the normal course of business, the Company has long-term commitments to
purchase services, such as electricity, water, oxygen and sulfuric acid for use
by certain of its refineries. The minimum annual payments under these contracts
are estimated to total $11.6 million in 2002, $12.2 million in 2003, $12.2
million in 2004, $3.4 million in 2005, and $3.0 million in 2006. The remaining
minimum commitment totals approximately $31.1 million over 10 years.

Environmental and Other Matters

The Company is a party to various litigation and contingent loss
situations, including environmental and income tax matters, arising in the
ordinary course of business. The Company has made accruals in accordance with
SFAS No. 5, "Accounting for Contingencies," in order to provide for these
matters. The ultimate effects of these matters cannot be predicted with
certainty, and related accruals are based on management's best estimates,
subject to future developments. Although the resolution of certain of these
matters could have a material adverse impact on interim or annual results of
operations, the Company believes that the outcome of these matters will not
result in a material adverse effect on its liquidity or consolidated financial
position.

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

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

77

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

In connection with the acquisition of the Hawaii refinery in 1998,
affiliates of BHP and the Company executed a separate environmental agreement,
whereby the BHP affiliates indemnified the Company for environmental costs
arising out of conditions which existed at or prior to closing. This
indemnification, which is in effect until 2008, is subject to a maximum limit of
$9.5 million ($4.4 million remaining as of December 31, 2001). Under the
environmental agreement, the first $5.0 million of these liabilities was the
responsibility of the BHP affiliates and the next $6.0 million will be shared on
the basis of 75% by the BHP affiliates and 25% by the Company. Certain
environmental claims arising out of prior operations will not be subject to the
$9.5 million limit or the ten-year time limit. The indemnity obligation of the
BHP affiliates is guaranteed by BHP.

Under the agreement related to the acquisition of the Washington refinery
in 1998, an affiliate of Shell generally agreed to indemnify the Company for
environmental liabilities at the Washington refinery arising out of conditions
which existed at or prior to the closing date and identified by the Company
prior to August 1, 2001. The Company did not identify any environmental
liabilities prior to August 1, 2001 subject to the indemnity.

The Company is also involved in remedial responses and has incurred cleanup
expenditures associated with environmental matters at a number of sites,
including certain of its owned properties. At December 31, 2001, the Company's
accruals for environmental expenses totaled $38 million. Based on currently
available information, including the participation of other parties or former
owners in remediation actions, the Company believes these accruals are adequate.

The Company continues to evaluate certain new revisions to the Clean Air
Act regulations which will require a reduction in the sulfur content in gasoline
by January 1, 2004. To meet the revised gasoline standard, the Company expects
to make capital improvements of approximately $65 million in the aggregate
through 2006 and $15 million in years after 2006.

The EPA has also announced new standards that will require a reduction in
sulfur content in diesel fuel manufactured for on-road consumption. In general,
the new diesel fuel standards will become effective on June 1, 2006. The Company
expects to spend approximately $35 million in capital improvements through 2006
and $30 million in years after 2006 to meet the new diesel fuel standards.

The Company expects to spend approximately $35 million in the aggregate in
capital improvements at its refineries over the next four years to comply with
the second phase of Maximum Achievable Control Technologies for petroleum
refineries ("Refinery MACT II") which was signed into law in January 2001.
Management expects that the Refinery MACT II regulations will require new
emission controls at certain processing units at several of the Company's
refineries. The Company is currently evaluating a selection of control
technologies to assure operations flexibility and compatibility with long-term
air emission reduction goals.

In connection with the Mid-Continent Acquisition, the Company assumed the
sellers' obligations and liabilities under a consent decree among the United
States, BP Exploration and Oil Co., Amoco Oil Company and Atlantic Richfield
Company. BP entered into this consent decree for both the North Dakota and Utah
refineries for various alleged violations. As the new owner of these refineries,
the Company is required to address issues including leak detection and repair,
flaring protection and sulfur recovery unit optimization. The Company estimates
it will spend an aggregate of $18 million at the Mid-Continent refineries to
comply with this consent decree. In addition, the Company has agreed to
indemnify the sellers for all losses of any kind incurred in connection with the
consent decree.

The Company anticipates it will make additional capital improvements of
approximately $9 million in 2002 primarily for improvements to storage tanks,
tank farm secondary containment and pipelines. During 2001, the Company spent
approximately $7 million on environmental capital projects.

78

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Conditions that require additional expenditures may transpire for various
Company sites, including, but not limited to, the Company's refineries, tank
farms, retail gasoline stations (operating and closed locations) and petroleum
product terminals, and for compliance with the Clean Air Act and other state,
federal and local requirements. The Company cannot currently determine the
amount of such future expenditures.

See Note N for information related to special incentive compensation.

NOTE P -- QUARTERLY FINANCIAL DATA (UNAUDITED)

The third and fourth quarters of 2001 include the results of operations of
the Mid-Continent Acquisition since the dates of acquisition.

NOTE Q -- SUBSEQUENT EVENT

The Company entered into a sale and purchase agreement with Ultramar Inc.,
a subsidiary of Valero Energy Corporation, on February 4, 2002, which was
amended on February 20, 2002. The Company agreed to acquire the 168,000
barrel-per-day Golden Eagle refinery located in Martinez, California near the
San Francisco Bay Area along with 70 associated retail sites throughout northern
California (collectively, the "Golden Eagle Assets"). The transaction, which is
subject to approval by the Federal Trade Commission and the offices of the
Attorneys General of the States of California and Oregon as well as other
customary conditions, is anticipated to close in April 2002. Under the terms of
the Golden Eagle Agreement, the Company paid a $53.75 million earnest money
deposit in February 2002. If the acquisition is not consummated by May 31, 2002
and the failure to close is a result of the Company's default (including default
because of the Company's

79

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

failure to obtain adequate financing for the acquisition) under the sale and
purchase agreement, the Company will forfeit its earnest money deposit.

At closing, the Company will pay the seller a cash purchase price of $995
million, less the deposit plus the value of inventory at closing, currently
estimated to be $130 million. The Company intends to finance the acquisition
with a combination of debt (including an amendment to the senior secured credit
facility) and public or private equity.

In addition to paying the purchase price for the Golden Eagle Assets, upon
the closing of the acquisition, the Company has agreed to assume a substantial
portion of the seller's obligations, responsibilities, liabilities, costs and
expenses arising out of or incurred in connection with the operation of the
Golden Eagle Assets. This includes, subject to certain exceptions, certain of
the seller's obligations, liabilities, costs and expenses for violations of
environmental laws relating to the assets, including certain known and unknown
obligations, liabilities, costs and expenses arising or incurred prior to, on or
after the closing date. Subject to certain conditions, the Company has also
agreed to assume 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
will retain.

Following the closing of the pending acquisition of the Golden Eagle
Assets, the Company also will assume and take assignment of certain of the
seller's obligations and rights (including certain indemnity rights) arising out
of or related to the agreement pursuant to which the seller purchased the
refinery in 2000. The seller has agreed to use commercially reasonable efforts
to persuade Phillips Petroleum Company, as successor to Tosco Corporation
("Phillips"), to consent to this assignment. If the seller cannot obtain a
consent from Phillips, the seller has agreed to provide the Company with a
"back-to-back" indemnity that will indemnify the Company against any liability
for which the seller is entitled to recover under the corresponding indemnity.
The seller's indemnity, however, is non-recourse to the seller and is limited to
amounts the seller actually receives from Phillips, less any legal or other
enforcement costs the seller incurs. Therefore, the indemnification that the
Company may be entitled to receive may not be sufficient to cover any losses or
damages that are incurred.

80

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

None.

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

The following is a list of our directors, executive officers, their ages
and their position with Tesoro at February 1, 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 its first
meeting following the Annual Meeting of Stockholders, each to hold office until

81

the corresponding meeting of the Board in the next year or until a successor
shall have been elected or shall have qualified.

Bruce A. Smith has been Chairman of the Board of Directors, President and
Chief Executive Officer of Tesoro since June 1996. He has been a director of
Tesoro since July 1995. Mr. Smith was President and Chief Executive Officer of
Tesoro from September 1995 to June 1996; Executive Vice President, Chief
Financial Officer and Chief Operating Officer of Tesoro from July 1995 to
September 1995; and Executive Vice President responsible for Exploration and
Production and Chief Financial Officer of Tesoro from September 1993 to July
1995; and Vice President and Chief Financial Officer of Tesoro from September
1992 to September 1993.

Steven H. Grapstein has been Chief Executive Officer of Kuo Investment
Company and subsidiaries ("Kuo"), an international investment group, since
January 1997. From September 1985 to January 1997, Mr. Grapstein was a Vice
President of Kuo. He is also a director of several of the Kuo companies. Mr.
Grapstein has been a Vice President of Oakville N.V., a Kuo subsidiary, since
1989.

James F. Clingman, Jr. is President and Chief Operating Officer of H.E.
Butt Grocery Company ("H-E-B"). He also serves on the grocery firm's Board of
Directors. Mr. Clingman joined H-E-B in 1975 as a district manager and has held
a number of management positions with increasing responsibility since then. He
was elected to his current positions in 1996.

William J. Johnson has been a petroleum consultant since 1994 and
President, director and sole shareholder of JonLoc Inc., a private oil and gas
company, since 1994. Mr. Johnson previously served as President, Chief Operating
Officer and director of Apache Corporation, a publicly held, independent oil and
gas company. Mr. Johnson is on the Board of Directors of Devon Energy
Corporation, a publicly held company engaged in oil and gas exploration,
development and production, and the acquisition of producing properties.

Raymond K. Mason, Sr. served as Chairman of the Board of Directors of
American Banks of Florida, Inc., from 1978 to 1998.

A. Maurice Myers serves as President, Chairman and Chief Executive Officer
of Waste Management Inc., Houston. He joined Waste Management in November 1999
after holding the same positions at Yellow Corporation since 1996. Earlier, he
served as President and Chief Executive Officer of America West Airlines from
January 1994 to 1996 and held executive positions at Aloha Airlines. Mr. Myers
is on the Board of Directors of Waste Management, Inc. and Hawaiian Electric
Industries.

Donald H. Schmude has 36 years of experience in the energy industry with
Texaco and Star Enterprise, a Texaco and Saudi Aramco joint venture. Prior to
his retirement from Texaco in 1994, he was Vice President of Texaco and
President and Chief Executive Officer of Texaco Refining & Marketing Inc. in
Houston, Texas and Los Angeles, California. He also served as Vice President of
Texaco, Inc., Special Projects, in Anacortes, Washington, and held various
refinery engineering, planning and marketing positions.

Patrick J. Ward has 47 years of experience in international energy
operations with Caltex Petroleum Corporation, a 50/50 joint venture of Chevron
Corp. and Texaco, Inc., engaged in the business of refining and marketing. Prior
to his retirement in 1995, he was Chairman, President and Chief Executive
Officer of Caltex, positions he had held since 1990. Mr. Ward served on the
Board of Directors of Caltex from 1989 to 1995.

Murray L. Weidenbaum, an economist and educator, has been the Mallinckrodt
Distinguished University Professor at Washington University in St. Louis,
Missouri, since 1971. He was Chairman of the University's Center for the Study
of American Business from 1975 to 2000, when its name was changed to the
Weidenbaum Center on the Economy, Government, and Public Policy. He now serves
as Honorary Chairman of the Center.

William T. Van Kleef has been Executive Vice President and Chief Operating
Officer since July 1998. He was named Executive Vice President in September
1996. He was elected Senior Vice President and Chief Financial Officer in
September 1995. He joined Tesoro as Vice President and Treasurer in 1993.

82

James C. Reed, Jr. has been Executive Vice President, General Counsel and
Secretary since September 1995. He served as Senior Vice President, General
Counsel and Secretary from June 1994 to September 1995 and Vice President,
General Counsel and Secretary from October 1993 to June 1994. He was Vice
President, Assistant General Counsel and Assistant Secretary from February 1990
to October 1993 and Assistant General Counsel from August 1982 to February 1990.

Thomas E. Reardon has been Executive Vice President, Corporate Resources
since November 1999. From May 1998 to November 1999, he served as Senior Vice
President, Corporate Resources. From September 1995 to May 1998, he served as
Vice President, Human Resources and Environmental and, before that, was Vice
President, Human Resources and Environmental Services of Tesoro Petroleum
Companies, Inc., a subsidiary of Tesoro, from October 1994 to September 1995.
Prior to that time, he served as Vice President, Human Resources of Tesoro
Petroleum Companies, Inc. from February 1990 to October 1994.

Everett D. Lewis has been Senior Vice President, Planning and Risk
Management since April 2001. He served as Senior Vice President of Strategic
Projects from March 1999 to April 2001, and served as a senior consultant with
EDL Associates from 1997 to 1999. Prior to that time, he was the Project
Executive of Refining and Marketing at Transworld Oil from 1993 to 1996. He has
more than 30 years of experience in the refining industry in refinery
operations, international business and project development.

Gregory A. Wright has been Senior Vice President and Chief Financial
Officer since April 2001. He served as Vice President, Finance and Treasurer
from May 1998 to April 2001. He was Vice President and Treasurer from September
1995 to May 1998. He also served as Vice President, Corporate Communications
from February 1995 to September 1995. Prior to that time, he served as Vice
President, Corporate Communications of Tesoro Petroleum Companies, Inc. from
January 1995 to February 1995.

Sharlene S. Fey has been Vice President and Controller since April 2001.
She previously had served as Assistant Controller, Corporate of Tesoro Petroleum
Companies, Inc. since 1994.

G. Scott Spendlove has been Vice President, Finance, since January 2002.
Prior to joining Tesoro, he served as Vice President, Corporate Planning and
Investor Relations of Ultramar Diamond Shamrock Corp. from December 1999 to
December 2001. From June 1998 to December 1999, Mr. Spendlove served as
Director, Investor Relations; and from January 1997 to June 1998, as Manager,
Corporate Finance of Ultramar Diamond Shamrock Corp.

Sharon L. Layman has been Vice President and Treasurer since November 1999.
Ms. Layman was Assistant Treasurer from February 1990 to November 1999.

W. Eugene Burden was named Senior Vice President and President, Northwest
Region of Tesoro Refining and Marketing Company in September 2001. He has also
served as President of Tesoro Alaska Company, a subsidiary of Tesoro, since
February 2001. He 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 in the United States and foreign
operations, from February 1996 to September 1999.

Faye W. Kurren has been President of Tesoro Hawaii Corporation since May
1998. Prior to that, she was Vice President, Operations Planning, Supply and
International Marketing of BHP Hawaii Inc. from March 1996 to May 1998. She
served as Vice President, General Counsel of BHP Hawaii Inc. from February 1995
to March 1996.

Donald A. Nyberg has been President of Tesoro Marine Services, LLC since
November 1996. Mr. Nyberg was Vice President, Strategic Planning, of MAPCO Inc.
from January 1996 to November 1996. He served as President and Chief Executive
Officer of Marya Resources from August 1994 to January 1996.

Jerry H. Mouser was named Executive Vice President, Commercial Marketing of
Tesoro Refining and Marketing Company in April 2001. He previously served as
Senior Vice President of New Business Ventures from June 2000 to July 2001.
Prior to joining Tesoro, he was with KBC Advanced Technologies plc, Weybridge,
England as President, Worldwide Sales and Marketing from 1997 to 2000;
President, Americas from 1994 to 1996; and a director and a member of the
Executive Committee from 1994 to 2000. Mr. Mouser
83

has over 30 years experience in both operational and senior management
assignments in the energy industry with companies such as E-Z Serve Inc.,
Enterprise Products Co. and Marathon Oil Co.

Stephen L. Wormington has served as Executive Vice President, Supply and
Distribution, of Tesoro Refining and Marketing Company since May 1998. Prior to
that, he was President of Tesoro Alaska Company from September 1995 until May
1998. He was Vice President, Supply and Operations Coordination for Tesoro
Alaska from April 1995 until September 1995. He joined Tesoro in January 1995 as
General Manager, Strategic Projects.

Richard M. Parry has been Vice President, Retail of Tesoro Refining and
Marketing Company, a subsidiary of Tesoro, since June 1999. Mr. Parry was Vice
President, Marketing & Sales of Tesoro Hawaii Corporation from May 1998 to June
1999. He served as Vice President, Marketing & Sales of BHP Hawaii Inc. from
December 1997 to May 1998 and Vice President, Trading and Marketing, of BHP
Hawaii Inc. from December 1994 to December 1997.

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. Mr. Porter had more than 23 years of experience with BP. He has
been Business Unit Leader of the North Dakota refinery since January 1999. He
was the Downstream Business Consultant, BP Headquarters, London from January
1998 to January 1999 and Manager, BP Oil Europe Manufacturing, Supply &
Distribution Strategy & Planning, Brussels, Belgium from March 1996 to January
1998.

James L. Taylor joined Tesoro in July 2001 as Senior Vice President of
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 and as Senior Consultant from 1997 to 1998.
From 1996 to 1997, he was a consultant for Amoco Oil Company's refinery in
Whiting, Indiana.

Rick D. Weyen joined Tesoro as Senior Vice President and President of the
Mountain Region of Tesoro Refining and Marketing Company in September 2001. Mr.
Weyen has over 20 years of experience in the industry. He was Commercial Manager
from 1999 to 2001 and Supply and Optimization Manager from 1995 to 1999 for BP
at the Salt Lake City refinery. Prior to that, Mr. Weyen served as Operations
Manager at the Salt Lake City refinery from 1992 to 1995.

SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE

Section 16(a) of the Exchange Act requires our directors, executive
officers and holders of more than 10 percent of our voting stock to file with
the SEC initial reports of ownership and reports of changes in ownership of our
common stock or other of our equity securities. Except as described below, we
believe that during the fiscal year ended December 31, 2001, our directors,
executive officers and holders of more than 10 percent of our voting stock
complied with all Section 16(a) filing requirements. Steven H. Grapstein and
Sharon L. Layman owned, directly or indirectly, 104,000 PIES(SM) and 680
PIES(SM), respectively. On July 1, 2001, our PIES(SM) automatically converted
into shares of our common stock. Mr. Grapstein and Ms. Layman each failed to
file a Form 4 upon the conversion of the PIES(SM) into shares of our common
stock, but each subsequently reported such conversions on a Form 5 filed on
February 13, 2002.

ITEM 11. EXECUTIVE COMPENSATION

COMPENSATION OF DIRECTORS

Each member of the Board of Directors who is not an officer of Tesoro
receives (i) a base retainer of $18,000 per year, (ii) an additional $2,000 for
each meeting of the Board of Directors or any committee thereof attended in
person, including committee meetings held on the same day as a meeting of the
Board of Directors, and (iii) $1,000 for each telephone meeting in which the
member participates. The non-executive Vice Chairman of the Board of Directors
receives $25,000 per year for his service. In addition, the Chairmen of the
Audit, Compensation, and Governance Committees each receives $5,000 per year for
his service in such

84

positions. We provide group life insurance benefits in the amount of $100,000
and accidental death and dismemberment insurance up to a maximum of $350,000 for
each of the members of the Board of Directors who are not our employees. The
premium for such insurance ranged from $178 to $2,064 for each of these
directors during fiscal year 2001.

One-half of each of the director's annual retainer is paid in our common
stock on an annual basis. Within 30 days after the annual meeting of our
stockholders at which the director is elected, we issue a number of shares equal
to one-half of the annual retainer in effect on the date of such meeting divided
by the average of the closing prices for our common stock, as reported on the
NYSE composite tape, for the ten trading days prior to such annual meeting. For
any person elected to be a director between annual meetings, we will issue a pro
rata number of shares for the time they will serve as a director during such
year. The shares of our common stock issued to the directors will be held by us
and will not be sold, pledged or otherwise disposed of and the shares will not
be delivered to the directors until the earliest of (i) the first anniversary
date of the annual meeting which immediately preceded the issuance of such
shares or (ii) the next succeeding annual meeting of the stockholders or (iii)
the date on which the person ceases to be a director; provided that, in the case
of clause (iii), if the person ceases to be a director for any reason other than
death or disability, the number of shares delivered shall be reduced pro rata
for the period of time from termination as a director to the first anniversary
date of the immediately preceding annual meeting of the stockholders. The
directors have full voting rights with respect to such shares of our common
stock.

We had previously established an unfunded Non-Employee Director Retirement
Plan which provided eligible directors with retirement payments upon meeting
certain age or other requirements. However, to more closely align director
compensation with shareholders' interests, in March 1997, the Board of Directors
elected to freeze the Director Retirement Plan and transfer accrued benefits of
each participating director to an account for each director in the Tesoro
Petroleum Corporation Board of Directors Deferred Phantom Stock Plan. After the
amendment and transfer, only those retired directors or beneficiaries who had
begun receiving benefits remained participants in the Director Retirement Plan.
By participating in the Phantom Stock Plan, each director waives any and all
rights under the Director Retirement Plan. Under the Phantom Stock Plan, each
current and future non-employee director shall have credited to his account as
of the last day of the year a yearly accrual equal to $7,250 (limited to 15
accruals, including previous accruals of retirement benefits under the Director
Retirement Plan); and each participant who is serving as a chairman of a
committee of the Board of Directors immediately prior to his termination as
director and who has served at least three years as a director shall have an
additional $5,000 credited to his account. The Phantom Stock Plan allows for pro
rata calculations of the yearly accrual in the event a director serves for part
of a year. In addition, a participating director may elect to defer any part or
all of the cash portion of his annual director retainer into his account. Each
transfer, accrual or deferral shall be credited quarterly to the participating
director's account in units based upon the number of shares that could have been
purchased with the dollars credited based upon the closing price of our common
stock on the NYSE on the date the amount is credited. Dividends or other
distributions accrue to the participating director's account. Participating
directors are vested 100 percent at all times with respect to deferrals and, if
applicable, the chairman fee portion of his account. Participating directors
vest in the yearly accruals upon completion of three full years of service as a
member of the Board. If a participating director voluntarily resigns or is
removed from the Board prior to serving three years on the Board, he shall
forfeit all amounts not vested. If a director dies, retires, or becomes
disabled, he shall be 100 percent vested in his account without regard to
services. Distributions from the Phantom Stock Plan shall be made in cash, based
on the closing market price of our common stock on the NYSE on the business day
immediately preceding the date on which the cash distribution is to be made, and
such distributions shall be made in either a lump-sum distribution or in annual
installments not exceeding ten years. Death, disability, retirement or cessation
of status as a director of Tesoro constitute an event requiring a distribution.
Upon the death of a participating director, the participating director's
beneficiary will receive as soon as practicable the cash value of the
participating director's account as of the date of death. At December 31, 2001,
participating directors' accounts included the following units of phantom stock:
Mr. Clingman -- 529 units; Mr. Grapstein -- 8,512 units; Mr. Johnson -- 3,570
units; Mr. Mason -- 18,774 units; Mr. Myers -- 529 units; Mr. Schmude -- 3,135
units; Mr. Ward -- 5,570 units; and Mr. Weidenbaum -- 9,236 units.

85

Under the Tesoro Petroleum Corporation Board of Directors Deferred
Compensation Plan, a director electing to participate may defer between 20
percent and 100 percent of his total cash compensation for the ensuing year,
which deferred fees are credited to an interest-bearing account maintained by
us. Interest is applied to each quarter's deferral at the prime rate published
in The Wall Street Journal on the last business day of such quarter plus two
percentage points (6.75 percent at December 31, 2001). All payments under the
Deferred Compensation Plan are our sole obligation. Upon the death of a
participating director, the balance in his account under the Deferred
Compensation Plan is paid to his beneficiary or beneficiaries in one lump sum.
In the event of the disability, retirement or the removal or resignation prior
to the death, disability or retirement of a participating director, the balance
in his account will be paid to such director in ten equal annual installments.
In the event of a change of control (as "change of control" is defined in the
Deferred Compensation Plan), the balance in each participating director's
account will be distributed to him as a lump sum within 30 days after the date
of the change of control. We also have an agreement with Frost National Bank of
San Antonio, Texas, under which the Tesoro Petroleum Corporation Board of
Directors Deferred Compensation Trust was established for the sole purpose of
creating a fund to provide for the payment of deferred compensation to
participating directors under the Deferred Compensation Plan.

Our 1995 Non-Employee Director Stock Option Plan provides for the grant to
non-employee directors of automatic, non-discretionary stock options, at an
exercise price equal to the fair market value of our common stock as of the date
of grant. Under the 1995 Plan, each person serving as a non-employee director on
February 23, 1995, or elected thereafter, initially receives an option to
purchase 5,000 shares of our common stock. Thereafter, each non-employee
director, while the 1995 Plan is in effect and shares are available to grant, is
granted an option to purchase shares of our common stock (amounting to 1,000
shares prior to March 2000 and 3,000 shares thereafter) on the next day after
each annual meeting of our stockholders but not later than June 1, if no annual
meeting is held. All options under the 1995 Plan become exercisable six months
after the date of grant. The 1995 Plan will terminate as to the issuance of
stock options in February 2005. Under the 1995 Plan, two directors received
individual grants of 5,000 shares each with an exercise price of $11.260 per
share on August 1, 2001 upon their election to the Board and six directors
received individual grants of 3,000 shares each with an exercise price of
$15.180 per share on May 24, 2001. At February 1, 2002, we had 111,000 options
outstanding and 16,000 shares available for future grants under the 1995 Plan.

86

SUMMARY OF EXECUTIVE COMPENSATION

The following table contains information concerning the annual and
long-term compensation for services in all capacities to us for fiscal years
ended December 31, 2001, 2000 and 1999, of those persons who were on December
31, 2001, (i) the Chief Executive Officer and (ii) our other four most highly
compensated officers (collectively, the "named executive officers").

SUMMARY COMPENSATION TABLE

- ---------------

(a) We made no payments to the named executive officers that are reportable as
Other Annual Compensation. The aggregate amount of perquisites and other
personal benefits was less than either $50,000 or 10 percent of the total
annual salary and bonus reported for the named executive officers for all
periods shown.

(b) Amounts represent traditional stock options granted to each named executive
officer.

(c) All Other Compensation for 2001 includes amounts we contributed and
earnings on the executive officers' accounts in a supplemental retirement
plan, the Funded Executive Security Plan (see "Retirement Benefits" on page
88) of $2,978,227, $1,178,317, $1,127,816 and $407,808 for Mr. Smith, Mr.
Van Kleef, Mr. Reed and Mr. Reardon, respectively, and amounts contributed
to our Thrift Plan of $10,200 for each of the named executive officers. All
Other Compensation for 2000 includes amounts contributed by us and earnings
on the executive officers' accounts to the Funded Executive Security Plan
of $1,031,850, $608,129, $148,870 and $301,057 for Mr. Smith, Mr. Van
Kleef, Mr. Reed and Mr. Reardon, respectively; and amounts contributed to
our Thrift Plan of $10,200 for each of the named executive officers. All
Other Compensation for 1999 includes amounts contributed by us and earnings
on the executive officers' accounts in the Funded Executive Security Plan
of $1,517,927, $707,527, $953,356 and $551,837 for Mr. Smith, Mr. Van
Kleef, Mr. Reed and Mr. Reardon, respectively, and amounts contributed to
our Thrift Plan of $8,292 for Mr. Smith and $9,600 for each of the other
four named executive officers.

OPTION GRANTS IN 2001

No stock options were granted to the named executive officers during the
year ended December 31, 2001.
87

AGGREGATED OPTION/SAR EXERCISED IN 2001 AND OPTION/SAR VALUES AT DECEMBER 31,
2001

The following table reflects the number of shares acquired by exercising
options and the value received thereon by the named executive officers, the
number of unexercised stock options remaining at year-end 2001 and the potential
value thereof based on the year-end market price of our common stock of
$13.109375 per share.

- ---------------

(a) The number of exercisable options/SARs include 175,000 phantom stock
options that were granted to Mr. Smith in 1997.

RETIREMENT BENEFITS

We maintain a noncontributory qualified Retirement Plan that covers
officers and other eligible employees. Benefits under the plan are payable on a
straight life annuity basis and are based on the average monthly earnings and
years of service of participating employees. Average monthly earnings used in
calculating retirement benefits are primarily salary and bonus received by the
participating employee during the 36 consecutive months that produce the highest
average monthly rate of earnings out of the last 120 months of service.

In addition, we maintain an unfunded executive security plan, the Amended
Executive Security Plan ("Amended Plan"), for executive officers and other
defined key personnel. The Amended Plan provides for a monthly retirement income
payment during retirement equal to a percentage of a participant's Earnings.
"Earnings" is defined under the Amended Plan to mean a participant's average
monthly rate of total compensation, primarily salary and bonus earned, including
performance bonuses and incentive compensation paid after December 1, 1993, in
the form of stock awards of our common stock (excluding stock awards under the
special incentive compensation strategy and contingent awards under the 1998
Performance Incentive Compensation Plan (the "1998 Performance Plan") for the 36
consecutive calendar months within the last ten-year period which produce the
highest average monthly rate of compensation for the participant. The monthly
retirement benefit percentage is defined as the sum of 4 percent of Earnings for
each of the first ten years of employment, plus 2 percent of Earnings for each
of the next ten years of employment, plus 1 percent of Earnings for each of the
next ten years of employment. The maximum percentage is 70 percent. The Amended
Plan provides for the payment by us of the difference, if any, between (a) the
total retirement income payment calculated above and (b) the sum of retirement
income payments from our Retirement Plan and Social Security benefits.

We also maintain the Funded Executive Security Plan ("Funded Plan"), which
covers selected persons approved by the Chief Executive Officer. Participants in
the Funded Plan are also participants in the Amended Plan. The Funded Plan
provides participants with substantially the same aftertax benefits as the
Amended Plan. Advance payments are made to the extent a participant is expected
to incur a pre-retirement tax liability as a result of his participation in the
Funded Plan. The Funded Plan is funded separately for each participant on an
actuarially determined basis through a bank trust whose primary asset is an
insurance contract providing for a guaranteed rate of return for certain
periods. Amounts payable to participants from the Funded Plan reduce amounts
otherwise payable under the Amended Plan.

The following table shows the estimated annual benefits payable upon
retirement under our Retirement Plan, Amended Plan and the Funded Plan for
employees in specified compensation and years of benefit
88

service classifications without reference to any amount payable upon retirement
under the Social Security law or any amount advanced before retirement. The
estimated annual benefits shown are based upon the assumption that the plans
continue in effect and that the participant receives payments for life. As of
January 1, 2002, the federal tax law generally limits maximum annual retirement
benefits payable by the Retirement Plan to any employee to $160,000, adjusted
annually to reflect increases in the cost of living. However, since the Amended
Plan and the Funded Plan are not qualified under Section 401 of the Internal
Revenue Code of 1986, as amended (the "Code"), it is possible for certain
retirees to receive annual benefits in excess of this statutory limitation.

The years of benefit service as of December 31, 2001, for the named
executive officers were as follows: Mr. Smith, 9 years; Mr. Van Kleef, 8 years;
Mr. Reed, 27 years; Mr. Wormington, 6 years; and Mr. Reardon, 21 years.

In addition to the retirement benefits described above, the Amended Plan
provides for a pre-retirement death benefit payable over eight years of four
times a participant's annual base pay as of December 1 preceding a participant's
date of death, less the amount payable from the Funded Plan at the date of
death. The amount payable from the Funded Plan at death is based on the
actuarial value of the participant's vested accrued benefit, payable in 96
monthly installments or as a life annuity if a surviving spouse is the
designated beneficiary.

EMPLOYMENT CONTRACTS, MANAGEMENT STABILITY AGREEMENTS AND CHANGE-IN-CONTROL
ARRANGEMENTS

Under an employment agreement dated November 1, 1997, as amended effective
October 28, 1998, Mr. Smith is employed at an annual base salary of $770,000.
Mr. Smith's employment agreement is for a term of three years and renews for an
additional year on the first of November of each year, unless we terminate the
agreement in accordance with its terms. Under separate employment agreements,
also effective October 28, 1998, Mr. Van Kleef and Mr. Reed are employed at
annual base salaries of $470,000 and $400,000, respectively. Messrs. Van Kleef's
and Reed's employment agreements each have a term of two years and renew for an
additional year on the twenty-third day of October of each year, unless we
terminate the agreement in accordance with its terms. In addition to their base
salaries, each of the employment agreements for the above executives provides
that we shall establish an annual incentive compensation strategy for executive
officers in which each executive shall be entitled to participate in a manner
consistent with his position with us and the evaluations of his performance by
the Board of Directors or any appropriate committee thereof. The target
incentive bonus under the 2001 annual incentive compensation strategy was a

89

percentage of the respective executive officer's annual base salary and was 75
percent for Mr. Smith, 70 percent for Mr. Van Kleef and 55 percent for Mr. Reed.
Each of the employment agreements also provides that the executive will receive
an annual amount ("flexible perquisite amount") to cover various business-
related expenses such as dues for country, luncheon or social clubs; automobile
expenses; and financial and tax planning expenses. The executive may elect at
any time by written notice to us to receive in cash any of such flexible
perquisite amount which has not been paid to or on behalf of the executive. The
annual flexible perquisite amount is $30,000, $20,000 and $20,000 for Mr. Smith,
Mr. Van Kleef and Mr. Reed, respectively. Each employment agreement also
provides that we will pay initiation fees for social clubs and reimburse the
executive for related tax expenses to the extent the Board of Directors, or a
duly authorized committee thereof, determines such fees are reasonable and in
our best interest.

Each of the employment agreements with Mr. Smith, Mr. Van Kleef and Mr.
Reed provides that in the event we should terminate such executive officer's
employment without cause, if he should resign his employment for "good reason"
(as "good reason" is defined in the employment agreements), or if we shall not
have offered to such executive officer prior to the termination date of his
employment agreement the opportunity to enter into a new employment agreement,
with terms, in all respects, no less favorable to the executive than the terms
of his current employment agreement, such executive will be paid a lump-sum
payment equal to (i) three times (in the case of Mr. Smith) and two times (in
the case of Messrs. Van Kleef and Reed) the sum of (a) his base salary at the
then current rate and (b) the sum of the target bonuses under all of our
incentive bonus plans applicable to such executive for the year in which the
termination occurs and (ii) if termination occurs in the fourth quarter of a
calendar year, the sum of the target bonuses under all of our incentive bonus
plans applicable to such executive for the year in which the termination occurs
prorated daily based on the number of days from the beginning of the calendar
year in which the termination occurs to and including the date of termination.
Each executive shall also receive all unpaid bonuses for the year prior to the
year in which the termination occurs and shall receive (i) for a period of two
years continuing coverage and benefits comparable to all life, health and
disability insurance plans which we from time to time make available to our
management executives and their families, (ii) a lump-sum payment equal to two
times the flexible perquisites amount, and (iii) two years additional service
credit under the Amended Plan and the Funded Plan, or successors thereto, of us
applicable to such executive on the date of termination. All unvested stock
options held by the executive on the date of the termination shall become
immediately vested and all restrictions on "restricted stock" then held by the
executive shall terminate, except for awards under the 1998 Performance Plan.

Each employment agreement further provides that, in the event such
executive officer's employment is involuntarily terminated within two years of a
change of control or if the executive officer's employment is voluntarily
terminated "for good reason," as defined in each of the employment agreements,
within two years of a change of control, he shall be paid within ten days of
such termination (i) a lump-sum payment equal to three times his base salary at
the then current rate; (ii) a lump-sum payment equal to the sum of (a) three
times the sum of the target bonuses under all of our incentive bonus plans
applicable to such executive for the year in which the termination occurs or the
year in which the change of control occurred, whichever is greater, and (b) if
termination occurs in the fourth quarter of a calendar year, the sum of the
target bonuses under all of our incentive bonus plans applicable to such
executive for the year in which the termination occurs prorated daily based on
the number of days from the beginning of the calendar year in which the
termination occurs to and including the date of termination; and (iii) a
lump-sum payment equal to the amount of any accrued but unpaid bonuses. We (or
our successor) shall also provide (i) for a period of three years continuing
coverage and benefits comparable to all of our life, health and disability plans
in effect at the time a change of control is deemed to have occurred; (ii) a
lump-sum payment equal to three times the flexible perquisites amount; and (iii)
three years additional service credit under the Amended Plan and the Funded
Plan, or successors thereto, applicable to such executive on the date of
termination. A change in control shall be deemed to have occurred if (i) there
shall be consummated (a) any consolidation or merger of us in which we are not
the continuing or surviving corporation or pursuant to which shares of our
common stock would be converted into cash, securities or other property, other
than a merger of us where a majority of the Board of Directors of the surviving
corporation are, and for a two-year period after the merger continue to be,
persons who were our directors immediately prior to the merger or were elected
as directors, or nominated for election as director, by
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a vote of at least two-thirds of the directors then still in office who were our
directors immediately prior to the merger, or (b) any sale, lease, exchange or
transfer (in one transaction or a series of related transactions) of all or
substantially all of our assets, or (ii) our shareholders shall approve any plan
or proposal for the liquidation or dissolution of us, or (iii) (A) any "person"
(as such term is used in Sections 13(d) and 14(d)(2) of the Exchange Act) other
than us or one of our subsidiaries or any employee benefit plan sponsored by us
or one of our subsidiaries, shall become the beneficial owner (within the
meaning of Rule 13d-3 under the Exchange Act) of our securities representing 20
percent or more of the combined voting power of our then outstanding securities
ordinarily (and apart from rights accruing in special circumstances) having the
right to vote in the election of directors, as a result of a tender or exchange
offer, open market purchases, privately negotiated purchases or otherwise, and
(B) at any time during a period of two years thereafter, individuals who
immediately prior to the beginning of such period constituted our Board of
Directors shall cease for any reason to constitute at least a majority thereof,
unless the election or the nomination by the Board of Directors for election by
our shareholders of each new director during such period was approved by a vote
of at least two-thirds of the directors then still in office who were directors
at the beginning of such period.

Each employment agreement further provides that if remuneration or benefits
of any form paid to them by us or any trust funded by us during or after their
employment with us are excess parachute payments as defined in Section 280G of
the Code, and are subject to the 20 percent excise tax imposed by Section 4999
of the Code, we shall pay Mr. Smith, Mr. Van Kleef and Mr. Reed a bonus no later
than seven days prior to the due date for the excise tax return in an amount
equal to the excise tax payable as a result of the excess parachute payment and
any additional federal income taxes (including any additional excise taxes)
payable by them as a result of the bonus, assuming that they will be subject to
federal income taxes at the highest individual marginal tax rate.

We have separate Management Stability Agreements ("Stability Agreements")
with Mr. Wormington and Mr. Reardon which are operative only in the event of our
change of control. The Stability Agreements provide that, if either Mr.
Wormington's or Mr. Reardon's employment is involuntarily terminated within two
years of a change of control or if either Mr. Wormington or Mr. Reardon
voluntarily terminates his employment "for good reason," as defined in the
Stability Agreements, within two years of a change of control, he shall be paid
within ten days of such termination (i) a lump-sum payment equal to two times
his base salary at the then current rate and (ii) a lump-sum payment equal to
the sum of (a) two times the sum of the target bonuses under all of our
incentive bonus plans applicable to Mr. Wormington and Mr. Reardon,
respectively, for the year in which the termination occurs or the year in which
the change of control occurred, whichever is greater, and (b) if termination
occurs in the fourth quarter of a calendar year, the sum of the target bonuses
under all of our incentive bonus plans applicable to Mr. Wormington and Mr.
Reardon, as applicable, for the year in which the termination occurs, prorated
daily based on the number of days from the beginning of the calendar year in
which the termination occurs to and including the date of termination. We (or
our successor) shall also provide continuing coverage and benefits comparable to
all of our life, health and disability plans for a period of 24 months from the
date of termination and Mr. Wormington and Mr. Reardon would each receive two
years additional service credit under the Amended Plan and the Funded Plan, or
successors thereto, applicable to such executive on the date of termination. A
change of control shall be deemed to have occurred if (i) there shall be
consummated (a) any consolidation or merger of us in which we are not the
continuing or surviving corporation or pursuant to which shares of our common
stock would be converted into cash, securities or other property, other than our
merger where a majority of the Board of Directors of the surviving corporation
are, and for a two-year period after the merger continue to be, persons who were
our directors immediately prior to the merger or were elected as directors, or
nominated for election as director, by a vote of at least two-thirds of the
directors then still in office who were our directors immediately prior to the
merger, or (b) any sale, lease, exchange or transfer (in one transaction or a
series of related transactions) of all or substantially all of our assets, or
(ii) our shareholders shall approve any plan or proposal for our liquidation or
dissolution, or (iii) (A) any "person" (as such term is used in Sections 13(d)
and 14(d)(2) of the Exchange Act) other than us or one of our subsidiaries or
any employee benefit plan sponsored by us or one of our subsidiaries, shall
become the beneficial owner (within the meaning of Rule 13d-3 under the Exchange
Act) of our securities representing 20 percent or more of the combined voting
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power of our then outstanding securities ordinarily (and apart from rights
accruing in special circumstances) having the right to vote in the election of
directors, as a result of a tender or exchange offer, open market purchases,
privately negotiated purchases or otherwise, and (B) at any time during a period
of one year thereafter, individuals who immediately prior to the beginning of
such period constituted our Board of Directors shall cease for any reason to
constitute at least a majority thereof, unless the election or the nomination by
the Board of Directors for election by our shareholders of each new director
during such period was approved by a vote of at least two-thirds of the
directors then still in office who were directors at the beginning of such
period, or (iv) there shall be, in the case of Mr. Wormington, (A) a direct or
indirect sale of all or substantially all of the assets of our refining and
marketing business, or (B) the sale of one of our subsidiaries (or affiliates)
that conducts all or substantially all of our refining and marketing business,
or (C) a merger, joint venture or other business combination involving our
refining and marketing business, and as a result of such sale of assets, sale of
stock, merger, joint venture or other business combination, we shall cease to
have the power to elect a majority of the Board of Directors (or the other
equivalent governing or managing body) of the entity which acquires, or
otherwise controls or conducts our refining and marketing business.

In order to participate in the 1998 Performance Plan, the parties to the
employment agreements and management stability agreements described above are
required to acknowledge that the rights and benefits under the 1998 Performance
Plan shall not be deemed an "incentive bonus plan" or other bonus or
compensation arrangement which shall be accelerated, multiplied or otherwise
required to be provided or enhanced under the employment agreement or management
stability agreement. The 1998 Performance Plan directly targets our performance
to align with the ninetieth percentile historical stock-price growth rate for
our peer group. In addition, the 1998 Performance Plan provides our employees
with additional compensation, contingent upon achievement of the targeted
objectives, thereby encouraging them to continue in our employ. The 1998
Performance Plan's targeted objectives are for the fair market value of our
common stock to equal or exceed an average of $35 per share and $45 per share on
any 20 consecutive trading days during a period commencing on October 1, 1998
and ending on the earlier of September 30, 2002, or the date on which the $45
per share target is achieved.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

SECURITY OWNERSHIP OF MANAGEMENT

The following table shows the beneficial ownership of our common stock
reported to us as of February 1, 2002, including shares as to which a right to
acquire ownership exists (for example, through the exercise of stock options or
stock awards) within the meaning of Rule 13d-3(d)(1) under the Exchange Act for
each director and nominee, the Chief Executive Officer, our other four most
highly compensated officers during 2001 and, as a group, such persons and other
executive officers. Unless otherwise indicated, each person or

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member of the group listed has sole voting and investment power with respect to
the shares of common stock listed.

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(a) The shares shown include 16,000; 14,000; 16,000; 12,000; 15,000; and 16,000
shares for Mr. Grapstein, Mr. Johnson, Mr. Mason, Mr. Schmude, Mr. Ward and
Dr. Weidenbaum, respectively, which such directors had the right to acquire
through the exercise of stock options on February 1, 2002, or within 60
days thereafter. The shares shown for each director also include 584 shares
of restricted common stock as payment of one-half of each director's annual
retainer for 2001 for each director listed above, except for Messrs.
Clingman and Myers which include 472 such shares. Units of phantom stock
payable in cash which have been credited to the directors under the Phantom
Stock Plan and to Mr. Smith, Mr. Van Kleef and Mr. Reed under the 1998
Performance Plan are not included in the shares shown above.

(b) The shares shown include 950,300 shares of our common stock owned by
Oakville N.V. Mr. Grapstein is an officer of Oakville N.V. As an officer,
Mr. Grapstein shares voting and investment power with respect to such
shares. In addition, the shares shown include 4,000 shares for which Mr.
Grapstein disclaims beneficial ownership held in accounts for his minor
children.

(c) The shares shown include 5,854 shares credited to Mr. Smith's account under
our Thrift Plan and 777,425 shares which Mr. Smith had the right to acquire
through the exercise of stock options on February 1, 2002, or within 60
days thereafter.

(d) The shares shown include 6,000 shares owned by P&L Family Partnership Ltd.
which Mr. Ward and his spouse control through 90 percent ownership.

(e) The shares shown include 4,915 shares credited to Mr. Van Kleef's account
under our Thrift Plan and 444,815 shares which Mr. Van Kleef had the right
to acquire through the exercise of stock options or stock awards on
February 1, 2002, or within 60 days thereafter.

(f) The shares shown include 2,654 shares credited to Mr. Reed's account under
our Thrift Plan and 256,395 shares which Mr. Reed had the right to acquire
through the exercise of stock options on February 1, 2002, or within 60
days thereafter.

(g) The shares shown include 4,026 shares credited to Mr. Wormington's account
under our Thrift Plan and 241,355 shares which Mr. Wormington had the right
to acquire through the exercise of stock options on February 1, 2002, or
within 60 days thereafter.

(h) The shares shown include 3,764 shares credited to Mr. Reardon's account
under our Thrift Plan and 181,300 shares which Mr. Reardon had the right to
acquire through the exercise of stock options on February 1, 2002, or
within 60 days thereafter. The shares shown also include 1,334 shares held
in the name of Mr. Reardon's spouse for which he disclaims beneficial
ownership.

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(i) The shares shown include 37,775 shares credited to the accounts of
executive officers and directors under our Thrift Plan and 2,305,397 shares
which directors and executive officers had the right to acquire through the
exercise of stock options on February 1, 2002, or within 60 days
thereafter. The shares shown also include 680 shares held by an executive
officer's child for which the executive officer disclaims beneficial
ownership. The shares shown also include 726 shares held in the name of an
executive officer's spouse and child, respectively, for which such
executive officer disclaims beneficial ownership.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS

The following table sets forth information from filings made with the
Securities and Exchange Commission ("SEC") as to each person or group who on
December 31, 2001 beneficially owned more than 5 percent of the outstanding
shares of our common stock.

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(a) According to Amendment No. 6 to a Schedule 13G ("Amendment No. 5") jointly
filed with the SEC, Liberty Wanger Asset Management, L.P. ("WAM") states
that it is a Delaware limited partnership and an Investment Adviser
registered under Section 203 of the Investment Advisers Act of 1940
("Investment Advisers Act") and WAM Acquisition GP, Inc. ("WAM GP") states
that it is a Delaware corporation and the General Partner of WAM. Amendment
No. 6 indicates that the shares reported therein have been acquired on
behalf of discretionary clients of WAM. According to Amendment No. 6,
persons other than WAM and WAM GP are entitled to receive all dividends
from, and proceeds from the sale of, those shares. According to Amendment
No. 6, within the meaning of Rule 13d-3 of the Exchange Act, WAM and WAM GP
beneficially own the shares shown in the table above and possess shared
power to vote or to direct the vote and shared power to dispose or direct
the disposition of these shares.

(b) According to an Amendment to a Schedule 13G (the "Amendment") filed with
the SEC, Dimensional Fund Advisors Inc. ("Dimensional") states that it is a
Delaware corporation and an investment adviser registered under the
Investment Advisers Act. In the Amendment, Dimensional states that it
furnishes investment advice to four investment companies registered under
the Investment Company Act of 1940 and serves as manager to certain other
commingled group trusts and separate accounts. These investment companies,
trusts and accounts are the "Funds." In the Amendment, Dimensional states
that in its role as investment adviser or manager, Dimensional possesses
voting and/or investment power over the 2,462,800 shares of common stock
that are owned by the Funds. Dimensional states that these securities are
owned by advisory clients, no one of which, to the knowledge of
Dimensional, owns more than five percent of the class of securities.
Dimensional disclaims beneficial ownership of such securities.

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(c) According to Amendment No. 4 to a Schedule 13G ("Amendment No. 6") jointly
filed with the SEC, Salomon Smith Barney Holdings Inc. ("SSB Holdings")
states that it is a New York corporation and Citigroup Inc. states that it
is a Delaware corporation. Citigroup Inc. is the sole stockholder of SSB
Holdings. In Amendment No. 6, each of the reporting persons show that they
have shared voting and dispositive power with respect to the securities
reported, which include shares for which the reporting persons disclaim
beneficial ownership.

(d) According to a Schedule 13G filed with the SEC, Mellon Financial
Corporation states that the shares reported on the Schedule 13G are
beneficially owned by the following direct or indirect subsidiaries of
Mellon Financial Corporation: Boston Safe Deposit and Trust Company, Mellon
Bank, N.A. (parent holding company of Founders Asset Management LLC, The
Dreyfus Corporation, Mellon Equity Associates, LLP, Laurel Capital
Advisors, LLP and Mellon Ventures, L.P.), Franklin Portfolio Associates
LLC, Mellon Capital Management Corporation, Mellon Equity Associates, LLP,
The Dreyfus Corporation (parent holding company of Dreyfus Investment
Advisors, Inc., Dreyfus Service Corporation and Dreyfus Separate Accounts)
and The Boston Company Asset Management, LLC. In the Schedule 13G, Mellon
Financial Corporation also reports that the following legal entities are
classified as parent holding companies: MBC Investments Corporation (parent
holding company of Mellon Capital Management Corporation, Mellon UK
Holdings, Mellon Ventures Fund Holding Corp. and Mellon Ventures II, L.P.),
Mellon Financial Corporation and The Boston Company, Inc. (parent holding
company of Boston Safe Deposit and Trust Company, Boston Safe Advisors,
Inc., Franklin Portfolio Associates, LLC, TBCAM Holdings, LLC, The Boston
Company Asset Management, LLC, Mellon Trust of California, Mellon Private
Trust Company, National Association, Mellon Trust of New York, LLC and
Mellon Trust of Washington). According to the Schedule 13G, Mellon
Financial Corporation has sole voting power of 2,011,571 of the shares
reported, sole dispositive power of 2,283,746 of the shares reported and
shared dispositive power of 25,800 of the shares reported.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

None

PART IV

ITEM 14. 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:

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 or notes thereto.

95

3. EXHIBITS

100

101

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* Filed herewith.

+ Identifies management contracts or compensatory plans or arrangements required
to be filed as an exhibit hereto pursuant to Item 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 24, 2001, a Current Report on Form 8-K was filed reporting under
Item 9, Regulation FD Disclosures, information related to a presentation
concerning the 9 5/8% Senior Subordinated Notes. The presentation data was filed
as an Exhibit under Item 7 of this Form 8-K.

On October 24, 2001, an Amendment No. 1 to Current Report on Form 8-K was
filed reporting under Item 2, Acquisitions or Dispositions of Assets, that the
Company completed the acquisition (as adjusted for the post-closing inventory
valuation) of certain refining and marketing assets of BP p.l.c. and certain of
its affiliates, including refineries in Salt Lake City, Utah and Mandan, North
Dakota. Included under Item 7 of this Form 8-K/A were the following: (i) Audited
Financial Statements of The North Dakota and Utah Refining and Marketing
Business of BP Corporation North America Inc. as of December 31, 1999 and 2000
and for the years ended December 31, 1998, 1999 and 2000; (ii) Unaudited
Financial Statements of The North Dakota and Utah Refining and Marketing
Business of BP Corporation North America Inc. as of June 30, 2001 and for the
six months ended June 30, 2000 and 2001; and (iii) Unaudited Pro Forma Combined
Condensed Financial Statements as of June 30, 2001, for the year ended December
31, 2000 and for the six months ended June 30, 2001. In addition, an updated
management's discussion and analysis of financial condition and results of
operations was filed under Item 9, Regulation FD Disclosures.

On November 5, 2001, an Amendment No. 2 to Current Report on Form 8-K was
filed reporting under Item 5, Other Events, that the Company completed the
acquisition of the North Dakota-based, common-carrier crude oil pipeline and
gathering system of BP p.l.c. Amended pro forma financial information was filed
as an Exhibit under Item 7 of this Form 8-K/A. In addition, the new
$1,000,000,000 Credit Agreement, Guarantee and Collateral Agreement and First
Amendment to the Credit Agreement were filed as Exhibits under Item 7 of this
Form 8-K/A.

On November 26, 2001, a Current Report on Form 8-K was filed reporting
under Item 9, Regulation FD Disclosures, information related certain
supplemental financial and operational data being transmitted through the
Company's website. The website data was filed as an Exhibit under Item 7 of this
Form 8-K. On December 3, 2001, an Amendment No. 1 to Current Report on Form 8-K
was filed restating in its entirety the Exhibit under Item 7 of this Form 8-K.

On February 4, 2002, a Current Report on Form 8-K was filed reporting under
Item 5, Other Events, information (1) updating certain supplemental financial
and operational data for both the fourth quarter and the year ended December 31,
2001 through the Company's website and (2) regarding a press release issued on
January 30, 2002 announcing the Company's earnings for the fourth quarter and
year ended December 31, 2001 and its capital spending plans for 2002. The
website data and press release were filed as Exhibits under Item 7 of this Form
8-K.

On February 5, 2002, a Current Report on Form 8-K was filed reporting under
Item 5, Other Events, information that the Company had entered into an asset
purchase agreement relating to the purchase of the Golden Eagle Assets from
Valero Energy Corporation. A Press Release issued on February 5, 2002 and
presentation data related to a conference call and webcast were filed as
Exhibits under Item 7 of this Form 8-K.

102

On February 21, 2002, a Current Report on Form 8-K was filed reporting
under Item 5, Other Events, that the Company had issued a press release
containing its first quarter 2002 earnings update. The Press Release was filed
as an Exhibit under Item 7 of this Form 8-K.

On February 21, 2002, a Current Report on Form 8-K was filed reporting
under Item 5, Other Events, that the Company had entered into an amendment to
the asset purchase agreement relating to the purchase agreement for the Golden
Eagle Assets. The Press Release announcing the amendment was filed as an Exhibit
under Item 7 of this Form 8-K.

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SIGNATURES

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

TESORO PETROLEUM CORPORATION

By /s/ BRUCE A. SMITH
-----------------------------------
Bruce A. Smith
Chairman of the Board of Directors,
President and Chief Executive
Officer
Dated: February 21, 2002

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.

104

INDEX TO EXHIBITS