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, 2002

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

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. [X]

Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Securities Exchange Act of 1934). Yes [X] No [ ]

At June 30, 2002, the aggregate market value of the voting stock held by
nonaffiliates of the registrant was approximately $490,723,296 based upon the
closing price of its common stock on the New York Stock Exchange Composite tape.
At February 28, 2003, there were 64,608,233 shares of the registrant's common
stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant's Proxy Statement pertaining to the 2003 Annual
Meeting of Stockholders are incorporated by reference into Part III hereof. The
Company intends to file such Proxy Statement no later than 120 days after the
end of the fiscal year covered by this Form 10-K.
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TESORO PETROLEUM CORPORATION

ANNUAL REPORT ON FORM 10-K

TABLE OF CONTENTS

PART I
Items 1 and 2. Business and Properties..................................... 2
Business Developments..................................... 2
Refining Segment.......................................... 2
Retail Segment............................................ 11
Other..................................................... 13
Competition and Other..................................... 13
Government Regulation and Legislation..................... 14
Employees................................................. 16
Properties................................................ 16
Executive Officers of the Registrant...................... 17
Board of Directors of the Registrant...................... 19
Risk Factors.............................................. 19
Item 3. Legal Proceedings........................................... 25
Item 4. Submission of Matters to a Vote of Security Holders......... 25
PART II
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters....................................... 25
Item 6. Selected Financial Data..................................... 27
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations................................. 30
Business Overview......................................... 30
Business Strategy......................................... 31
Results of Operations..................................... 33
Capital Resources and Liquidity........................... 40
Accounting Standards...................................... 50
Forward-Looking Statements................................ 53
Item 7A. Quantitative and Qualitative Disclosures about Market
Risk...................................................... 55
Item 8. Financial Statements and Supplementary Data................. 56
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure.................................. 94
PART III
Item 10. Directors and Executive Officers of the Registrant.......... 94
Item 11. Executive Compensation...................................... 94
Item 12. Security Ownership of Certain Beneficial Owners and
Management................................................ 94
Item 13. Certain Relationships and Related Transactions.............. 94
Item 14. Controls and Procedures..................................... 94
PART IV
Item 15. Exhibits, Financial Statement Schedules and Reports on Form
8-K....................................................... 95
Signatures and Certifications............................................... 101

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 53.

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

ITEMS 1 AND 2. BUSINESS AND PROPERTIES

We are an independent refiner and marketer with two major operating
segments -- (1) refining crude oil and other feedstocks and selling petroleum
products in bulk and wholesale markets ("Refining") and (2) selling motor fuels
and convenience products and services in the retail market ("Retail"). Through
our Refining segment, we manufacture products, primarily gasoline and gasoline
blendstocks, jet fuel, diesel fuel and residual fuel for sale to a wide variety
of commercial customers in the mid-continental and western United States. Our
Retail segment distributes motor fuels through a network of gas stations,
primarily under the Tesoro(R) and Mirastar(R) brands. In addition to our
Refining and Retail segments, we also market and distribute petroleum products
and provide logistical support services to the marine and offshore exploration
and production industries operating in the Gulf of Mexico.

See Notes D, E, F, G and Q of Notes to Consolidated Financial Statements in
Item 8 for additional information on our operating segments and properties.

We were incorporated in Delaware in 1968. Our principal executive offices
are located at 300 Concord Plaza Drive, San Antonio, Texas 78216-6999 and our
telephone number is (210) 828-8484. Our website can be found at
www.tesoropetroleum.com. We make available free of charge through our Internet
website our annual report on Form 10-K, quarterly reports on Form 10-Q, current
reports on Form 8-K, and amendments to those reports filed or furnished pursuant
to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, as
soon as reasonably practicable after we electronically file such material with,
or furnish it to, the SEC. YOU MAY ALSO RECEIVE A COPY OF THE COMPANY'S ANNUAL
REPORT ON FORM 10-K, INCLUDING THE FINANCIAL STATEMENTS, FREE OF CHARGE BY
WRITING TO TESORO PETROLEUM CORPORATION, ATTENTION: INVESTOR RELATIONS, 300
CONCORD PLAZA DRIVE, SAN ANTONIO, TEXAS 78216-6999.

BUSINESS DEVELOPMENTS

On May 17, 2002, we acquired a 168,000 barrel-per-day ("bpd") refinery
located in Martinez, California in the San Francisco Bay area along with 70
associated retail sites in northern California. The cash purchase price for
these refinery and retail assets was approximately $923 million, including
approximately $130 million for feedstock, refined product and other inventories.
In addition, we issued to the seller two ten-year junior subordinated notes with
face amounts aggregating $150 million and a present value of approximately $61
million at the acquisition date.

In June 2002, we announced a goal to reduce debt by $500 million by the end
of 2003. As part of this debt reduction, we set a goal to generate net proceeds
of $200 million through asset sales. Furthermore, our senior secured credit
facility required us to consummate one or more asset sales or equity offerings
resulting in the receipt of cumulative net proceeds of at least $200 million by
March 31, 2003. In December 2002, we sold our product pipeline system in North
Dakota and Minnesota and the 70 retail stations acquired in northern California
in May 2002 and completed a sale/lease-back transaction for 30 company-operated
retail stations in Alaska, Hawaii, Idaho and Utah. Through these and other
miscellaneous sales, we satisfied the asset sales requirement under our senior
secured credit facility with the receipt of net proceeds totaling approximately
$207 million in December 2002 and have reduced our term debt by $140 million
(including a $16.3 million prepayment in January 2003).

REFINING SEGMENT

OVERVIEW

We own and operate six petroleum refineries, which are located in
California ("California" region), Alaska and Washington ("Pacific Northwest"
region), Hawaii ("Mid-Pacific" region) and North Dakota and Utah
("Mid-Continent" region), and sell refined products to a wide variety of
customers in the mid-continental and western United States. During 2002,
products from our refineries accounted for approximately 82% of our refined
product sales volumes, with the remaining 18% purchased from other refiners and
suppliers.

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Our six refineries have a combined rated crude oil capacity of 558,000 bpd.
We operate the largest refineries in Hawaii and Utah, the second largest
refinery in Alaska, the only refinery in North Dakota and the second largest
refinery in northern California. Capacity and throughput rates of crude oil and
other feedstocks by refinery are as follows:

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(a) Throughput volumes in 2002 included the California refinery since we
acquired it on May 17, 2002, averaged over 365 days. Throughput for the
California refinery averaged over the 229 days we owned it in 2002 was
150,800 bpd.

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

We reduced throughput rates at several of our refineries in 2002 in
response to market conditions. Major scheduled refinery maintenance
("turnarounds") temporarily reduced throughput at our California and Washington
refineries in 2002 and at our Hawaii refinery in 2000. At our 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.

In 2002, we received 31% of our crude oil input from domestic sources
(other than Alaska), 30% from Alaska's North Slope, 7% from Alaska's Cook Inlet
and 32% from foreign sources (including 9% from Canada). As shown in the table
below, in 2002, approximately 49% of our total refining throughput was heavy
crude oil, compared with 45% in 2001. We define "heavy" crude oil as Alaska
North Slope or crude oil with an

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American Petroleum Institute specific gravity of 32 or less. Actual throughput
of crude oil and other feedstocks is summarized below:

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(a) Throughput volumes in 2002 included the California refinery since we
acquired it on May 17, 2002, averaged over 365 days. Throughput for the
California refinery averaged over the 229 days we owned it in 2002 was
150,800 bpd.

(b) Throughput volumes in 2001 included the Mid-Continent refineries since we
acquired them on September 6, 2001, averaged over 365 days. Throughput for
these refineries averaged over the 117 days that we owned them in 2001 was
105,000 bpd.

We purchase crude oil and other feedstock for the refineries through term
agreements and in the spot market. We purchase Alaska North Slope, California
San Joaquin, Alaska Cook Inlet, 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 U.S. flag tankers, two of which are double-hulled and
one is double-bottomed, to transport crude oil and refined products. During
2002, we extended the term charters on two of these ships to July 2010 and
extended the charter on the third ship to July 2003. In February 2003, we
chartered a fourth ship, a foreign flag tanker, through January 2004, primarily
to carry crude oil from Southeast Asia to our Hawaii refinery. This term charter
will reduce our use of spot charters and carry approximately 20% of our cargoes
from Southeast Asia. We also charter three tugs and two product barges for our
Hawaii operations

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over varying terms ending in 2005 through 2009 with options to renew. We also
charter other tankers and ocean-going barges on a short-term basis to transport
crude oil and refined products.

Our refining 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 refining yield, in
volume and as a percentage, is summarized below:

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

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

We currently operate refined product terminals in the following locations:

- California -- Martinez and Stockton;

- Washington -- Anacortes, Port Angeles and Vancouver;

- Alaska -- Anchorage and Kenai;

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

- North Dakota -- Mandan;

- Utah -- Salt Lake City; and

- Idaho -- Boise and Burley.

As discussed above under "Business Developments", in December 2002, we sold
our product pipeline extending from Mandan, North Dakota to Minneapolis,
Minnesota and terminals in Jamestown, North Dakota and Moorhead, Sauk Centre and
Minneapolis/St. Paul, Minnesota.

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.

CALIFORNIA REFINERY

Refining. Our California refinery, located in Martinez on 2,206 acres of
land approximately 30 miles east of San Francisco, is a highly complex refinery
with a rated crude oil capacity of 168,000 bpd. Major product upgrading units at
the refinery include fluid catalytic cracking ("FCC"), fluid coker,
hydrocracking, naphtha reforming, vacuum distillation, hydrotreating and
alkylation units. These units enable the refinery to produce a high proportion
of motor fuels, including cleaner-burning California Air Resources Board
("CARB") gasoline and CARB diesel products as well as conventional gasoline and
diesel. Other products produced at the refinery include liquefied petroleum gas,
coke, fuel oil, decant oil and other residual products. A major turnaround of
the refinery, including the fluid coker, began in the fourth quarter of 2001 and
was completed in the first quarter of 2002, prior to our ownership. We completed
a turnaround of the refinery's larger crude unit in the second quarter of 2002.
The next scheduled turnaround is for the hydrocracker in the fourth quarter of
2004.

Following our purchase of the California refinery, we continued a project
that will increase our capacity to produce CARB gasoline at the refinery by up
to 20,000 bpd or approximately 30%. This project will enable us to comply with
California regulations to phase out the use of the oxygenate known as MTBE,
currently expected to be effective on January 1, 2004. We spent approximately
$60 million through December 31, 2002 and expect to spend an additional $17
million to complete the project in the first quarter of 2003.

Crude Oil Supply. Our California refinery's crude oil is sourced primarily
from California and Alaska, with the remainder purchased on a spot basis from
foreign sources. We purchase approximately 65% of the refinery's crude oil under
term contracts which are primarily short-term agreements at market-related
prices.

Transportation. The California refinery has waterborne access that enables
us to ship products and receive crude oil through our Amorco wharf and to ship
and receive refined product through our Golden Eagle wharf. The Amorco wharf has
a depth of 40 feet and is capable of handling vessels of up to 188,500 dead

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weight tons ("DWT"). The Golden Eagle wharf has a depth of 40 feet with mooring
capacity to handle vessels weighing up to 105,000 DWT and measuring up to 810
feet in length. The refinery also has access to California crude oils through
third-party Unocap, Shell and KLM pipelines. In addition, the refinery can
receive crude oil through a third-party terminal at Martinez and can ship
refined products from the refinery through the Kinder Morgan product pipeline
system.

Terminals. We operate a refined product terminal at Stockton, California,
and distribute products at our Martinez, California terminal by barge. In
addition, we distribute products through third-party terminals and truck racks
in our market areas. Fuel distributed through third-party terminals also is
supplied by our refineries and through purchases and exchange arrangements with
other refining and marketing companies. Under an agreement which expires in
September 2004, we lease approximately 500,000 barrels of storage capacity with
waterborne access in southern California.

PACIFIC NORTHWEST REFINERIES

Washington

Refining. Our Washington refinery, located in Anacortes on the Puget Sound
on 917 acres of land about 60 miles north of Seattle, has a total rated crude
oil capacity of 108,000 bpd. Major product upgrading units at the refinery
include the FCC, alkylation, hydrotreating, vacuum distillation and catalytic
reforming units. The FCC and other product upgrading units enable the Washington
refinery to produce approximately 75% of its output as light products, including
gasoline (including cleaner-burning CARB gasoline), diesel and jet fuel. Actual
yields depend on the mix of crude oil and other feedstock throughput. The FCC
unit also can upgrade heavy vacuum gas oils from our Alaska and Hawaii
refineries and other suppliers. We completed a turnaround of the FCC and
alkylation units in the first quarter of 2002. The next scheduled turnaround is
for the crude distillation and reformer units in the fourth quarter of 2004.

We completed a heavy oil conversion project at our Washington refinery at
the end of the first quarter 2002, which enables 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.

Crude Oil Supply. The Washington refinery's crude oil is sourced primarily
from Alaska, Canada and Southeast Asia. We purchase approximately 75% of the
refinery's crude oil under term contracts which are primarily short-term
agreements with market-related prices. The Washington refinery acquires
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. Our Washington
refinery ships products (gasoline, jet fuel and diesel) through a third-party
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. We also
deliver gasoline through a neighboring refinery's truck rack, and we distribute
diesel fuel through a truck rack at our refinery. We also deliver refined
products through our marine terminal to ships and barges. We ship our fuel oil
production by water and our propane and asphalt by truck and rail.

Terminals. We operate refined product terminals at Port Angeles and
Vancouver, Washington. These terminals are supplied primarily by our Pacific
Northwest refineries. In addition, we distribute products through third-party
terminals and truck racks in our market areas. 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. Our Alaska refinery is located near Kenai on 488 acres of land
approximately 70 miles southwest of Anchorage and adjacent to the Cook Inlet
where it has access to Alaskan and imported crude oil

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supplies. The refinery has a total rated crude oil capacity of 72,000 bpd. Major
product upgrading units include the vacuum distillation, distillate
hydrocracking, hydrotreating and catalytic reforming units. The Alaska refinery
produces liquefied petroleum gas, gasoline and gasoline blendstocks, jet fuel,
diesel fuel, heating oil, liquid asphalt, heavy oils and residual products. 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 of all
major process units is scheduled for the second quarter of 2003.

Crude Oil Supply. The Alaska refinery primarily runs Alaska Cook Inlet
crude oil. To a lesser extent, the refinery runs Alaska North Slope and other
crude oils. We purchase substantially all of the crude oil for the Alaska
refinery under term contracts, of which approximately 72% are short-term
agreements and approximately 28% are agreements for terms greater than one year,
in each case with market-related prices.

Transportation. We deliver crude oil by tanker to the Alaska refinery
through our Kenai Pipe Line Company marine terminal, which is a common carrier
and marine dock facility. We also receive crude oil through our 24-mile pipeline
connecting our marine terminal with some of the Cook Inlet producing fields. Our
marine terminal is also used to load refined products on tankers and barges. We
also own and operate a common-carrier petroleum products pipeline, which runs
from the Alaska refinery to our terminal facilities in Anchorage and to the
Anchorage airport. This 71-mile, 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.

Terminals. We operate refined product terminals at Kenai and Anchorage,
Alaska. These terminals are supplied by the Alaska refinery. In addition, we
distribute products through third-party terminals and truck racks in our market
areas. 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. Our Hawaii refinery, located at Kapolei on 131 acres of land 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. Major product upgrading units include the
vacuum distillation, distillate hydrocracking, hydrotreating, visbreaking and
catalytic reforming units. We completed a scheduled maintenance turnaround in
the third quarter of 2000, and the next turnaround of all major units is
scheduled for the first quarter of 2004.

Crude Oil Supply. The Hawaii refinery's crude oil supply is sourced
primarily from Alaska and Southeast Asia. We purchase approximately 55% of the
refinery's crude oil under term contracts which are primarily short-term
agreements with market-related prices. We purchase the remaining 45% on the spot
market. The percentages of crude oil purchased under term contracts and in the
spot market vary based on market conditions.

Transportation. Crude oil is transported to Hawaii by tankers and
discharged through our single-point mooring terminal approximately 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
military facilities at several locations. We also distribute refined products to
commercial customers through third-party terminals at Honolulu International
Airport and Honolulu Harbor and by barge to Tesoro-owned and third-party
terminal facilities on the islands of 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. Fuel distributed through these terminals
is supplied primarily by our refinery.

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MID-CONTINENT REFINERIES

North Dakota

Refining. Our North Dakota refinery is located near Mandan 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. Major product upgrading units
at the refinery include the FCC, reforming, hydrotreating and alkylation units.
The North Dakota refinery's primary products include gasoline, diesel fuel and
jet fuel. A maintenance turnaround of all major process units is scheduled at
the North Dakota refinery in the fourth quarter of 2003.

Crude Oil Supply. The North Dakota refinery's crude oil supply is
primarily local Williston Basin sweet crude oil. Although the current tariff
structure makes local crude oil more economical, the refinery also has access to
other sources of crude oil, including Canadian crude oil. We purchase
approximately 75% of the refinery's crude oil under term contracts which are
primarily short-term agreements with market-related prices.

Transportation. We own a crude oil pipeline system consisting of over 700
miles of pipeline that delivers all of the crude oil supply to our North Dakota
refinery. Our crude oil pipeline system is configured to gather crude oil from
the local Williston Basin and adjacent production areas in North Dakota and
Montana and transport it to our North Dakota refinery and to regional points
where there is additional demand. Our crude oil pipeline system is a common
carrier subject to regulation by various local, state and federal agencies,
including the Federal Energy Regulatory Commission.

In December 2002, we sold our product pipeline extending from Mandan, North
Dakota to Minneapolis, Minnesota and our terminals in Jamestown, North Dakota
and Moorhead, Sauk Centre and Minneapolis/ St. Paul, Minnesota, together with a
five-mile, 5,000 bpd pipeline to the Burlington Northern rail yard in Bismarck,
North Dakota. We will continue to distribute our products through the pipeline
under a tariff arrangement with the new owner, Kaneb Pipe Line Partners, L.P.
("Kaneb"). The product pipeline system distributes approximately 85% of our
North Dakota refinery's production. All gasoline and distillate products
produced at our refinery, with the exception of railroad-spec diesel fuel, can
be shipped through the pipeline to Kaneb's terminals.

Terminals. Our terminal at the North Dakota refinery connects to the Kaneb
product pipeline system and terminals located in North Dakota and Minnesota. We
distribute products from our North Dakota refinery to customers primarily
through these third-party terminals.

Offtake Agreements. In connection with the 2001 acquisition of the North
Dakota refinery, we entered into certain offtake agreements with BP plc ("BP")
for a portion of our refined products. We sold an average of 23,000 bpd of
refined products in 2002 under the offtake agreements. In 2002, BP received
approximately 67% of the committed product through the Minneapolis/St. Paul
terminal with the remainder distributed through the Moorhead and Sauk Centre,
Minnesota terminals. The offtake agreements for the Moorhead and Sauk Centre,
Minnesota terminals expire in September 2004. The offtake agreement for the
Minneapolis/ St. Paul terminal expires in September 2006 with declining volumes
in each of the last three years. Volumes under the offtake agreements are
subject to further reductions under certain conditions. Sales prices under the
offtake agreements are based on market prices at the time of sale.

Utah

Refining. Our Utah refinery is located in Salt Lake City on 145 acres of
land. The 55,000 bpd refinery supplies products to the Utah, Idaho and eastern
Washington marketing areas. The Utah refinery's primary products include
gasoline, diesel fuel and jet fuel. Major product upgrading units include the
FCC, reforming, hydrotreating and alkylation units. We began a maintenance
turnaround of the crude distillation and reforming units in March 2003 which is
expected to be completed in early April 2003.

Crude Oil Supply. The Utah refinery processes low-sulfur crude oils and
has the flexibility to process various crude oils. As local crude oil supplies
decline, local capacity can be replaced with Canadian light sweet

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or Syncrude. We purchase approximately 90% of the refinery's crude oil under
term contracts which are primarily short-term agreements with market-related
prices.

Transportation. Our refinery receives Canadian and Rocky Mountain crude
oil by pipeline and truck from fields in Utah, Colorado, Wyoming and Canada.
Local crude oils are delivered primarily through the Amoco "U" Pipeline.
Canadian crude oil and other domestic crude oils are delivered primarily through
another third-party pipeline system. We distribute the refinery's production
through a system of both owned and third-party terminals and third-party
pipeline connections primarily in Utah, Idaho and eastern Washington, with some
product delivered in Nevada and Wyoming.

Terminals. In addition to sales at the refinery, we distribute product
through the Chevron Pipeline to the two terminals we own at Boise and Burley,
Idaho and to two terminals we lease in Pocatello, Idaho and Pasco, Washington.

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
products that we manufacture and products purchased or received on exchange from
third parties. Our refined product sales in the Refining segment, including
intersegment sales to our Retail operations, consisted of the following:

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

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

Gasoline and Gasoline Blendstocks. We sell gasoline and gasoline
blendstocks in both the bulk and wholesale markets in the mid-continental and
western United States (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 supply a major
oil company through a product exchange agreement, under which we provide
gasoline in Alaska in exchange for gasoline delivered to us on the U.S. West
Coast. We also supply another major oil company in Alaska and Hawaii through a
gasoline sales agreement. We also sell, at wholesale, to unbranded distributors
and high-volume retailers. We distribute product through Tesoro-owned and
third-party terminals and truck racks. 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.

Jet Fuel. Our refineries are major suppliers of commercial jet fuel to
passenger and cargo airlines in Alaska and Hawaii. We also supply jet fuel to
airports on the U.S. West Coast. We, along with other marketers, purchase
additional quantities of jet fuel to supply Alaska, Hawaii and the U.S. West
Coast

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markets. We primarily market commercial jet fuel at airports in Anchorage,
Honolulu and other Hawaiian island locations, as well as at other airports in
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. The production of
diesel fuel by refiners in our market areas is generally in balance with demand.
As a result of variations in seasonal demand, we ship diesel fuel to or from our
Alaska and Hawaii operations.

Heavy Oil and Residual Products. Our California, 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 vacuum gas oil and
vacuum tower bottoms. Vacuum gas oils are further processed in the Alaska and
Hawaii refinery hydrocrackers, where they are converted into jet fuel, gasoline
blendstocks and diesel fuel. Our California refinery further processes light
cycle oil and vacuum oils through the hydrocracker, where they are converted
into gasoline blendstocks and diesel fuel. Vacuum gas oil and deasphalted vacuum
residua are used primarily as FCC feedstock at our Washington refinery where
they are upgraded to gasoline and diesel fuel. We use vacuum tower bottoms to
produce liquid asphalt, fuel oil and marine bunker fuel at our Mid-Pacific and
Pacific Northwest refineries. We sell the remaining 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 Alaska and the Pacific Northwest, demand for liquid asphalt is seasonal
because mild weather conditions are needed for highway construction. At our
California refinery, we produce petroleum coke as a by-product of upgrading
vacuum tower bottoms in the fluid coking unit. We sell the petroleum coke to
industrial end-users.

We have marine fuel marketing operations through leased facilities at Port
Angeles and Seattle, Washington, and Portland, Oregon, and through owned and
leased facilities in Hawaii. Marine fuels sold from these locations are supplied
principally by our refineries. See "Other" below for our marine services
operations on the U.S. Gulf Coast, which we plan to integrate with our wholesale
marketing and terminal operations during 2003.

Sales of Purchased Products. In the normal course of business, we purchase
refined products manufactured by others for resale to customers. We purchase
these products, primarily gasoline, jet fuel, diesel fuel and industrial and
marine fuel blendstocks, mainly in the spot market. Sales of these products
represented approximately 18% of total volumes we sold in 2002. We conduct our
gasoline and diesel fuel purchase and resale activity primarily on the U.S. West
Coast. Our jet fuel activity primarily consists of supplying markets in Alaska,
California and Hawaii.

RETAIL SEGMENT

Our Retail segment sells gasoline and diesel fuel 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-operated sites and agreements with third-party branded
distributors (or "jobber/dealers"). As of December 31, 2002, our Retail segment
included a network of 593 branded retail stations (under the Tesoro(R) and
Mirastar(R) brands), including 234 Tesoro-operated retail gasoline stations and
359 jobber/dealer stations in the mid-continental and western United States. Our
retail network provides a committed outlet for a portion of the motor fuels
produced at our refineries. Currently, we have adopted a flat to modest growth
strategy for our Retail segment that will focus on selected jobber investments
in certain of

11

our markets. We do not expect to build any new retail stations in 2003. The
following table summarizes our retail operations as of and for the years ended
December 31, 2002, 2001 and 2000:

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

(a) Tesoro-operated stations included 31 in Alaska, 33 in Hawaii, 47 in
Washington, 40 in Utah and 83 in several other western states at December
31, 2002.

(b) At December 31, 2002, the branded jobber/dealer stations included 88 in
Alaska, 22 in California, 34 in Idaho, 71 in Utah, 60 in North Dakota, 44
in Washington and 40 in several other western states. The decrease in
jobber/dealer stations during 2002 was primarily due to approximately 150
BP/Amoco jobber/dealer stations (included in the Mid-Continent acquisition)
that did not rebrand to the Tesoro(R) brand name. This decision not to
rebrand resulted in us no longer being those jobber/dealer stations'
exclusive supplier under the terms of the acquisition agreement.

(c) The average number of Tesoro-operated stations in 2002 included 70 stations
in northern California that were purchased in May 2002 (with our California
refinery) and sold in December 2002.

We developed our Mirastar(R) 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

12

a site's lease for additional terms of five years. Wal-Mart has the sole option
to determine the availability of future sites. Pursuant to the terms of the
agreement, Wal-Mart nominates certain sites and we have the right to accept or
reject the opportunity to build a retail station at each such site, provided
that we only have the right to reject up to an aggregate of 30% of the total
number of nominated sites. Wal-Mart is not obligated to nominate a specific site
or a certain number of sites for us. We are not obligated to pay for the right
to accept or reject such nominated sites, we have not paid any up-front money
for the right to accept or reject nominated sites and we are not obligated to
accept a specific nominated site. The agreement does not create an exclusive
relationship between Wal-Mart and us, and Wal-Mart is not prohibited from
offering a site to our competitors in the 17 states covered by the agreement. If
we accept a Wal-Mart nominated site, then the parameters and terms set forth in
the agreement relating to the development of sites will govern. As of December
31, 2002, we had 78 Mirastar stations in operation and no sites under
construction. We have no plans to build new Mirastar sites in 2003.

Many of our Tesoro-operated stations include 2-Go Tesoro(R) brand
convenience stores that sell a wide variety of merchandise items. Our revenues
from merchandise sales and other services, such as carwashes, totaled $132
million in 2002, $71 million in 2001 and $55 million in 2000.

OTHER

In addition to our Refining and Retail segments, we market and distribute
petroleum products and provide logistical support services to the marine and
offshore exploration and production industries operating in the Gulf of Mexico
under the name Tesoro Marine Services. These operations are conducted through a
network of 15 terminals located on the Texas and Louisiana coast. We also own
tugboats, barges and trucks used in these operations. We plan to integrate these
operations into our wholesale marketing and terminal operations during 2003.

COMPETITION AND OTHER

The petroleum industry is highly competitive in all phases, including the
refining of crude oil and the marketing of refined petroleum products. The
industry also competes with other industries that supply the energy and fuel
requirements of industrial, commercial and individual consumers. We compete with
a 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. In recent years,
consolidation in the refining and marketing 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 crude oil that can then be
used in our refining operations and we are not as large as a number of our
competitors that may have a competitive advantage when negotiating with crude
oil producers.

Our California and Washington refineries compete with several refineries on
the U.S. West Coast, including refineries that have higher refining capacity and
are owned by substantially larger companies. Our Hawaii refinery competes
primarily with one other refinery in Hawaii that also is located at Kapolei and
has a rated crude oil capacity of 54,000 bpd. Historically, the other refinery
produces lower volumes of jet fuel than our Hawaii refinery. The Alaska refinery
competes primarily with other refineries in Alaska and on the U.S. West Coast.
Our refining competition in Alaska includes two refineries near Fairbanks and a
refinery near Valdez. We estimate that the other refineries have a combined
capacity to process approximately 270,000 bpd of crude oil. After processing
Alaska North Slope crude oil and removing the higher-value products, these
refiners are permitted, because of their direct connection to the Trans Alaska
Pipeline System, to return the remainder of the processed crude oil 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
only refinery in North Dakota. Refineries in Wyoming, Montana, the Midwest and
the United States Gulf Coast region are the primary competitors with our North
Dakota refinery. Our Utah refinery is the largest of five refineries located in
Utah. We estimate that these other refineries have a combined capacity to
process approximately 107,500 bpd of crude oil. These five refineries (including
our Utah refinery) collectively supply

13

an estimated 70% of the gasoline and distillate products consumed in the states
of Utah and Idaho, with the remainder 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 Moorhead, Minnesota and Bismarck and Jamestown, North
Dakota. We produce jet fuel in Alaska and Hawaii, both of which periodically
require additional supplies from outside the state to meet demand.

We sell our diesel fuel production primarily on a wholesale basis,
competing with other refiners and marketers in all of our market areas. Refined
products from foreign sources, including Canada, also compete for distillate
customers in our market areas.

In connection with the 2001 acquisition of the North Dakota refinery, we
entered into offtake agreements with BP to provide us with a distribution
channel for a portion of our refined products produced at our North Dakota
refinery. We sold an average of 23,000 bpd of refined products in 2002 under
these offtake agreements. In 2002, BP received approximately 67% of this amount
through the Minneapolis/St. Paul terminal with the remainder distributed through
the Moorhead and Sauk Centre, Minnesota terminals. The offtake agreements for
the Moorhead and Sauk Centre, Minnesota terminals expire in September 2004. The
offtake agreement for the Minneapolis/St. Paul terminal expires September 2006
with declining volumes in each of the last three years. Volumes under the
offtake agreements are subject to further reductions under certain conditions.
Sales prices under the offtake agreements are based on market prices at the time
of sale.

We distribute gasoline in Alaska, California, Hawaii, Utah, Washington and
other western states through a network of Tesoro-operated retail stations and
branded and unbranded jobber/dealers. Competitive factors affecting the retail
marketing of gasoline include factors such as price, station appearance,
location and brand-name identification. We compete against independent marketing
companies and integrated oil companies when engaging in these marketing
operations.

GOVERNMENT REGULATION AND LEGISLATION

ENVIRONMENTAL CONTROLS AND EXPENDITURES

All of our operations, like those of other companies engaged in similar
business, are subject to extensive and frequently changing federal, state,
regional and local laws, regulations and ordinances relating to the protection
of the environment, including those governing emissions or discharges to the air
and water, the handling and disposal of solid and hazardous wastes and the
remediation of contamination. While we believe our facilities are in substantial
compliance with current requirements, over the next several years 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 and local
jurisdictions in which we operate. For example, under the federal Clean Air Act
we will be required to comply with the second phase of regulations establishing
Maximum Achievable Control Technologies for petroleum refineries ("Refinery MACT
II"). These regulations, promulgated in April 2002, will require additional air
emission controls for certain processing units at several of our refineries. We
expect to spend approximately $44 million in additional capital improvements at
our refineries through 2006 to comply with the Refinery MACT II standards. We
are currently evaluating a selection of control technologies to assure
operations flexibility and compatibility with long-term air emission reduction
goals.

14

Changes in fuel manufacturing standards, including those related to
gasoline and diesel fuel sulfur concentrations, also affect our operations. In
February 2000, the EPA finalized new regulations pursuant to the Clean Air Act
requiring a reduction in the sulfur content in gasoline beginning January 1,
2004. To meet the revised gasoline standard, we currently estimate we will make
capital improvements of approximately $37 million through 2006 and an additional
$15 million thereafter. This will allow all of our refineries to produce
gasoline meeting the limits imposed by the EPA. The EPA also promulgated new
regulations in January 2001 pursuant to the Clean Air Act requiring a reduction
in the sulfur content in diesel fuel manufactured for on-road consumption. In
general, the new diesel fuel standards will become effective on June 1, 2006.
Based on our latest engineering estimates, we expect to spend approximately $55
million in capital improvements through 2007 to meet the new diesel fuel
standards. These expenditures, however, do not include amounts for our Alaska
refinery where limited demand for low-sulfur diesel presently does not justify
the capital investment. We expect to meet this demand from other sources.

To meet California's CARB III gasoline requirements, including the
mandatory phase-out of the oxygenate known as MTBE, we spent approximately $60
million through December 31, 2002 on a project at our California refinery and
expect to spend an additional $17 million to complete the project in the first
quarter of 2003.

In connection with the 2001 acquisition of our North Dakota and Utah
refineries, we assumed the sellers' obligations and liabilities under a consent
decree among the United States, BP Exploration and Oil Co., Amoco Oil Company
and Atlantic Richfield Company. BP entered into this consent decree for both the
North Dakota and Utah refineries for various alleged violations. As the new
owner of these refineries, we are required to address issues including leak
detection and repair, flaring protection and sulfur recovery unit optimization.
We currently estimate that we will spend an aggregate of $7 million to comply
with this consent decree. In addition, we have agreed to indemnify the sellers
for all losses incurred in connection with the consent decree.

In connection with the 2002 acquisition of our California refinery, subject
to certain conditions, we assumed the seller's obligations pursuant to its
settlement efforts with the EPA concerning the Section 114 refinery enforcement
initiative under the Clean Air Act, except for any potential monetary penalties,
which the seller retains. We believe these obligations will not have a material
impact on our financial position.

Capital expenditures addressing other environmental issues at our
California refinery totaled approximately $12 million in 2002. Based on latest
estimates, we will need to expend additional capital for reconfiguring and
replacing above-ground storage tank systems and upgrading piping within the
refinery. These costs are currently estimated at approximately $130 million
through 2007 and an additional $90 million through 2011. Both of these estimates
are subject to further review and analysis.

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

OIL SPILL PREVENTION AND RESPONSE

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

We currently charter on a long-term and short-term basis tankers to ship
crude oil from foreign and domestic sources to our California, Mid-Pacific and
Pacific Northwest refineries. The Federal Oil Pollution

15

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 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; (3) Clean Sound
Incorporated for response actions associated with the Puget Sound, Washington
operations; and (4) Clean Bay Incorporated for response services associated with
our California refinery. In addition, for larger spill contingency capabilities,
we have entered into contracts with Marine Spill Response Corporation in Hawaii
and on the U.S. West Coast and Gulf Coast. We believe these contracts, and those
with other regional spill-response organizations that are in place on a location
by location basis, provide the additional services necessary to meet
spill-response requirements established by state and federal law.

REGULATION OF PIPELINES

Our crude oil pipeline system in North Dakota and our pipeline systems in
Alaska are common carriers subject to regulation by various 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.

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

EMPLOYEES

At December 31, 2002, we had approximately 3,940 full-time employees.
Approximately 1,060 of our employees are covered by collective bargaining
agreements that run until January 31, 2006. During the term of the agreements,
our employees have agreed not to engage in a strike, work stoppage or slowdown,
or any other interference of work production for any reason. We consider our
relations with our employees to be satisfactory.

PROPERTIES

Our principal properties are described above under the captions "Refining
Segment" and "Retail Segment". In addition, we own feedstock and refined product
storage facilities at our refinery and terminal locations. We believe that our
properties and facilities are generally adequate for our operations and that our
facilities are maintained in a good state of repair. We are the lessee under a
number of cancellable and noncancellable leases for certain properties,
including office facilities, retail facilities, transportation equipment and
various assets used to store and transport refinery feedstocks and refined
products. See Notes G and Q of Notes to Consolidated Financial Statements in
Item 8.

We conduct our retail business under the Tesoro(R), Tesoro Alaska(R),
Mirastar(R), and 2-Go Tesoro(R) brands. Our retail-marketing system under these
brands includes 593 branded retail stations, of which 234 are Tesoro-operated.

16

EXECUTIVE OFFICERS OF THE REGISTRANT

The following is a list of the Company's executive officers, their ages and
their positions with the Company at February 28, 2003.

There are no family relationships among the officers listed, and there are
no arrangements or understandings pursuant to which any of them were elected as
officers. Officers are elected annually by the Board of Directors at its first
meeting following the Annual Meeting of Stockholders. The term of each office
runs until the corresponding meeting of the Board in the next year or until a
successor shall have been elected or shall have qualified.

17

The Company's executive officers have been employed by the Company or its
subsidiaries in an executive capacity for at least the past five years, except
for those named below who have had the business experience indicated during that
period. Positions, unless otherwise specified, are with the Company.

W. Eugene Burden was named Senior Vice President, Human Resources and
Government Relations in June 2002. Prior to that, he served as President of
Tesoro Alaska Company from February 2001 to June 2002 and Senior Vice President
and President, Northwest Region of Tesoro Refining and Marketing Company from
September 2001 until June 2002. Mr. Burden served as Senior Vice President,
Government Relations of Tesoro Petroleum Companies, Inc. from September 1999 to
February 2001. Prior to joining Tesoro, he was President of Burden & Associates,
Inc., which provided consulting services to energy clients in the United States
and foreign operations, from February 1996 to September 1999.

Everett D. Lewis has been Senior Vice President, Planning and Optimization
since February 2003. Prior to that, he was Senior Vice President, Planning and
Risk Management from April 2001 to February 2003. He served as Senior Vice
President of Strategic Projects from March 1999 to April 2001 and was a
consultant to the refining and marketing industry from 1997 to 1999.

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

Susan A. Lerette has been Vice President, Communications since April 2001.
She was Director, Investor Relations from April 1999 to April 2001. From
December 1998 to April 1999, Ms. Lerette served as Manager, Investor Relations
and from 1994 until December 1998, she was Senior Financial Analyst in our
Investor Relations Department.

Otto C. Schwethelm was named Vice President and Controller in February
2003. From September 2002 to February 2003, Mr. Schwethelm served as Vice
President and Operations Controller. Prior to that, he served as Vice President,
Shared Services of Tesoro Petroleum Companies, Inc. from December 2001 to
September 2002. From November 1999 to December 2001, Mr. Schwethelm was Vice
President, Development and Business Analysis, and from August 1998 to November
1999, he was Manager, Economics of Tesoro Petroleum Companies, Inc. Prior to
joining Tesoro, he was employed by Saudi Aramco in its Internal Audit Department
from July 1991 to August 1998.

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

Rodney S. Cason has served as President of Tesoro Alaska Company since
April 2002. Prior to that, he was Vice President, Refining, from February 1998
to April 2002, and was refinery manager from May 1997 to February 1998.

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.

Joseph M. Monroe was named Senior Vice President, Supply and Distribution,
of Tesoro Refining and Marketing Company in May 2002. From January 1999 through
May 2002, Mr. Monroe served as Vice President, Pipelines and Terminals of Unocal
Corporation and as President of Unocal Pipeline Company. He served Unocal
Corporation as Managing Director of International Pipelines and Fuel Management
from May 1998 to January 1999 and as Senior Vice President of New Ventures in
Jakarta, Indonesia from July 1996 to May 1998.

James L. Taylor joined Tesoro in July 2001 as Senior Vice President,
Manufacturing, of Tesoro Refining and Marketing Company. During 2000 and 2001,
he served as General Manager, Worldwide Technical Services, of Criterion
Catalysts and Technologies. Prior to that, Mr. Taylor was with KBC Advanced
Technologies, as Job Controller from 1998 to 2000 and as Senior Consultant from
1997 to 1998.

18

Alan R. Anderson was named President of Tesoro Refining and Marketing
Company's Northern Great Plains Region in June 2002. He also serves as manager
of our North Dakota refinery. From September 2001 until June 2002, Mr. Anderson
served as Business Manager of our Northern Great Plains Region. From January
1999 to September 2001, he was employed by BP as a Commercial Manager, and from
August 1997 to January 1999 he was employed by Amoco as Business Manager at the
North Dakota refinery. From August 1997 to September 2001 he also served as
business manager for the region, which included North and South Dakota, Kansas,
Minnesota and Nebraska.

J. William Haywood joined Tesoro in May 2002 as Senior Vice President and
also became President of the California Region of Tesoro Refining and Marketing
Company in September 2002. Prior to joining Tesoro, Mr. Haywood served as
Regional Vice President of Ultramar Diamond Shamrock Corporation, responsible
for both California refineries from September 2000 to May 2002. From September
1997 to September 2000, Mr. Haywood was General Manager of the Wilmington
refinery near Los Angeles, California, for Ultramar Diamond Shamrock
Corporation.

Daniel J. Porter joined Tesoro as Senior Vice President and President of
the Northern Great Plains Region of Tesoro Refining and Marketing Company in
September 2001 and became Senior Vice President and President of our Northwest
Region in June 2002. Prior to joining Tesoro, he was Business Unit Leader at
BP's North Dakota refinery since January 1999. He was the Downstream Business
Consultant, BP Headquarters, London from January 1998 to January 1999.

Rick D. Weyen joined Tesoro as Senior Vice President and President of the
Mountain Region of Tesoro Refining and Marketing Company in September 2001. He
was Commercial Manager from January 1999 to September 2001 for BP and Supply and
Optimization Manager from 1995 to January 1999 for Amoco at the Salt Lake City
refinery.

BOARD OF DIRECTORS OF THE REGISTRANT

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

Bruce A. Smith........................... Chairman, President and Chief Executive
Officer of Tesoro Petroleum Corporation
Steven H. Grapstein...................... Lead Director of Tesoro Petroleum
Corporation; Chief Executive Officer of
Kuo Investment Company
William J. Johnson....................... Petroleum Consultant; President of JonLoc
Inc.
A. Maurice Myers......................... Chairman, President and Chief Executive
Officer of Waste Management Inc.
Donald H. Schmude........................ Retired Vice President of Texaco and
President and Chief Executive Officer of
Texaco Refining & Marketing Inc.
Patrick J. Ward.......................... Retired Chairman, President and Chief
Executive Officer of Caltex Petroleum
Corporation

RISK FACTORS

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

As of December 31, 2002, we had total consolidated indebtedness of $1.9
billion (excluding an additional $165 million available under our revolving
credit facility). We are rated BB-/B with a negative outlook, B1/ B3 with a
stable outlook and BB-/B with a negative outlook by Standard & Poor's Rating
Services, Moody's Investors Service, Inc. and Fitch Rating, respectively. Our
high degree of leverage may have important consequences, including the
following:

19

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

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

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

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

- our debt level may impact our level of discretionary capital expenditures
and related expansion opportunities; and

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

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, we may be required to sell assets, eliminate or
defer capital expenditures, refinance all or a portion of our existing debt or
obtain additional financing. We may not be able to refinance our debt, sell
assets or borrow more money on terms acceptable to us, if at all. Additionally,
our ability to incur additional debt will be restricted under the covenants
contained in our senior secured credit facility and our indentures.

OUR DEBT INSTRUMENTS IMPOSE RESTRICTIONS ON US THAT MAY ADVERSELY AFFECT OUR
ABILITY TO OPERATE OUR BUSINESS.

Our senior secured credit facility contains covenants, including a
provision that limits our capital expenditures to no more than $237.5 million
for the twelve-month period ending June 30, 2003 and $210 million for the year
2003 and annually thereafter until the ratio of our debt to capitalization falls
below 0.58 to 1.00. It also contains a prohibition of making voluntary or
optional prepayments of certain of our indebtedness until the senior secured
credit facility is repaid. Under our senior secured credit facility, we are not
permitted to declare or pay cash dividends on our common stock or repurchase
shares of our common stock through December 31, 2003. Our senior secured credit
facility requires us to comply with specified financial covenants which,
beginning with the 2003 third quarter, become more restrictive over the life of
our senior secured credit facility. Our ability to comply with these covenants,
as they currently exist or as they may be amended, may be affected by many
events beyond our control and our future operating results may not allow us to
comply with the covenants, or in the event of a default, to remedy that default.
Our failure to comply with those financial covenants or to comply with the other
restrictions contained in our senior secured credit facility could result in a
default, which could cause that indebtedness (and by reason of cross-default
provisions, indebtedness under the indentures governing our senior subordinated
notes and other indebtedness) to become immediately due and payable. If we are
unable to repay those amounts, the lenders under our senior secured credit
facility could proceed against the collateral granted to them to secure that
indebtedness. If those lenders accelerate the payment of the senior secured
credit facility, we cannot assure you that we could pay that indebtedness
immediately and continue to operate our business.

In addition, the indentures for our senior subordinated notes contain other
covenants that restrict, among other things, our ability to:

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

- incur additional indebtedness and issue preferred stock;

20

- enter into asset sales unless the proceeds from those asset sales are
used to repay debt;

- 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.

OUR HIGH LEVEL OF DEBT AFFECTS OUR ACCESS TO TRADE CREDIT.

Because of our high level of debt, combined with the recent weakness in
industry refining margins and economic uncertainty, we have experienced a
tightening of the trade credit we receive, requiring us to commit available cash
which we could otherwise use to reduce our debt. Under current economic
conditions and in light of the general uncertainty that surrounds business, we
cannot assure you that the trade credit extended to us will not be further
tightened. A significant further tightening in trade credit could result in our
business not generating sufficient cash flow to fund operations, capital
expenditures and debt service.

THE VOLATILITY OF CRUDE OIL PRICES, REFINED PRODUCT PRICES AND NATURAL GAS AND
ELECTRICAL POWER PRICES MAY HAVE A MATERIAL ADVERSE EFFECT ON OUR CASH FLOW AND
RESULTS OF OPERATIONS.

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

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

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

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

- weather conditions, earthquakes or other natural disasters;

- government regulations; and

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

Prices for refined products are influenced by the commodity price of crude
oil. Generally, an increase or decrease in the price of crude oil 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 as well as the
overall change in product prices, however, can reduce profit margins and could
have a significant impact on our refining and wholesale marketing operations and
our earnings and cash flow. Industry margins deteriorated beginning in the
fourth quarter of 2001 and continued throughout 2002, which adversely impacted
our profit margins, 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 natural gas and
electrical power used by our refineries and other operations have increased
manufacturing and operating costs and will continue to impact production

21

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.

OUR BUSINESS IS IMPACTED BY RISKS INHERENT IN PETROLEUM REFINING OPERATIONS.

The operation of refineries, pipelines and product terminals is inherently
subject to spills, discharges or other releases of petroleum or hazardous
substances. If any of these events has previously occurred or occurs in the
future in connection with any of our refineries, pipelines or product terminals
other than events for which we are indemnified, we will be liable for all costs
and penalties associated with their remediation under federal, state and 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.

We 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
California, 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 California, Washington, Hawaii, Alaska
and the U.S. Gulf Coast. 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.

THE DANGERS INHERENT IN OUR OPERATIONS AND THE POTENTIAL LIMITS ON INSURANCE
COVERAGE COULD EXPOSE US TO POTENTIALLY SIGNIFICANT LIABILITY COSTS.

Our operations are subject to hazards and risks inherent in refining
operations and in transporting and storing crude oil and refined products, such
as fires, natural disasters, explosions, pipeline ruptures and spills and
mechanical failure of equipment at our or third-party facilities, any of which
can result in environmental pollution, personal injury claims and other damage
to our properties and the properties of others. In addition, we operate six
petroleum refineries, any of which could experience a major accident, be damaged
by severe weather or other natural disaster, or otherwise be forced to shut
down. Any such unplanned shutdown could have a material adverse effect on our
results of operations and financial condition as a whole. In addition, because
of past incidents that occurred while the California refinery was under previous
ownership, the cost to insure the refinery may remain substantially above
industry norms. 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.

22

OUR OPERATIONS ARE SUBJECT TO GENERAL ENVIRONMENTAL RISKS, EXPENSES AND
LIABILITIES WHICH COULD AFFECT OUR RESULTS OF OPERATIONS.

From time to time we have been, and presently are, subject to litigation
and investigations with respect to environmental and related matters. We may
become involved in further litigation or other proceedings, or we may be held
responsible in any existing or future litigation or proceedings, the costs of
which could be material.

We have in the past operated service stations with underground storage
tanks in various jurisdictions, and currently operate service stations that have
underground storage tanks in Hawaii, Alaska and 16 states in the mid-continental
and western United States. Federal and state regulations and legislation govern
the storage tanks and compliance with these requirements can be costly. The
operation of underground storage tanks also poses certain other risks, including
damages associated with soil and groundwater contamination. Leaks from
underground storage tanks which may occur at one or more of our service
stations, or which may have occurred at our previously operated service
stations, may impact soil or groundwater and could result in fines or civil
liability for us.

All of our operations, like those of other companies engaged in similar
business, to some degree, are subject to extensive and frequently changing
federal, state, regional and local laws, regulations and ordinances relating to
the protection of the environment, including those governing emissions or
discharges to the air and water, the handling and disposal of solid and
hazardous wastes and the remediation of contamination. The failure to comply
with these regulations can lead, among other things, to civil and criminal
penalties and, in some circumstances, the temporary or permanent curtailment or
shutdown of all or part of our operations in one or more of our facilities. The
nature of our business exposes us to risks of liability due to the production,
processing and refining, storage, transportation, and disposal of materials that
can cause contamination or personal injury if released into the environment. Our
operations are inherently subject to accidental spills, discharges or other
releases of petroleum or hazardous substances that could make us responsible for
cleanup costs and related penalties or liable to governmental entities or
private parties. This may involve 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. In addition, we 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. The transportation of
crude oil and refined product over water involves risk and subjects us to the
provisions of the Federal Oil Pollution Act of 1990 and related state
regulations, which require that most oil refining, transport and storage
companies maintain and update various oil spill prevention and oil spill
contingency plans.

Consistent with the experience of all U.S. refineries, environmental laws
and regulations have raised operating costs and necessitated significant capital
investments at our refineries. We believe that existing physical facilities at
our refineries are substantially adequate to maintain compliance with existing
applicable laws and regulatory requirements. However, potentially material
expenditures could be required in the future. For example, we may be required to
comply with evolving environmental and health and safety laws, regulations or
requirements that may be adopted or imposed in the future or to address
information or conditions that may be discovered in the future and that require
a response. Several recently passed regulations will require us to complete the
following projects at our refineries prior to the effective date of the related
requirements and regulations:

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

- Changes that are required to address a ban on the gasoline additive MTBE
in California; and

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

23

TERRORIST ATTACKS AND THREATS OR ACTUAL WAR, INCLUDING PARTICULARLY WAR WITH
IRAQ, MAY NEGATIVELY IMPACT OUR BUSINESS.

Our business is affected by general economic conditions and fluctuations in
consumer confidence and spending, which can decline as a result of numerous
factors outside of our control, such as actual or threatened terrorist attacks
and acts of war. Terrorist attacks in the United States, as well as events
occurring in response to or in connection with them, including future terrorist
attacks against U.S. targets, rumors or threats of war, actual conflicts
involving the United States or its allies, including particularly war with Iraq,
or military or trade disruptions impacting our suppliers or our customers or
energy markets generally, may adversely impact our operations. As a result,
there could be delays or losses in the delivery of supplies and raw materials to
us, delays in our delivery of refined products, decreased sales of our products
(especially sales to our customers that purchase jet fuel) and extension of time
for payment of accounts receivable from our customers (especially our customers
in the airline industry). Strategic targets such as energy-related assets (which
could include refineries such as ours) may be at greater risk of future
terrorist attacks than other targets in the United States. These occurrences
could significantly impact energy prices, including prices for our crude oil and
refined products, and have a material adverse impact on the margins from our
refining and wholesale marketing operations. In addition, disruption or
significant increases in energy prices could result in government-imposed price
controls. Any one of, or a combination of, these occurrences could have a
material adverse effect on our business.

IF WE ARE UNABLE TO MAINTAIN AN ADEQUATE SUPPLY OF FEEDSTOCKS, OUR RESULTS OF
OPERATIONS MAY BE ADVERSELY AFFECTED.

We may not continue to have an adequate supply of feedstocks, primarily
crude oil, available to our six refineries to sustain our current level of
refining operations. If additional crude oil becomes necessary at one or more of
our refineries, we intend to implement available alternatives that are most
advantageous under then prevailing conditions. Implementation of some
alternatives could require the consent or cooperation of third parties and other
considerations beyond our control. In particular, the North Dakota refinery is
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 our crude oil pipeline system. If outside
events cause an inadequate supply of crude oil, or if our crude oil pipeline
system transports lower volumes of crude oil, our anticipated revenues could
decrease. If we are unable to obtain supplemental crude oil volumes, or are only
able to obtain these volumes at uneconomic prices, our results of operations
could be adversely affected.

WE ARE SUBJECT TO INTERRUPTIONS OF SUPPLY AND INCREASED COSTS AS A RESULT OF OUR
RELIANCE ON THIRD-PARTY TRANSPORTATION OF CRUDE OIL AND REFINED PRODUCTS.

Our Washington refinery receives all of its Canadian crude oil through
pipelines operated by third parties. During 2002, we also delivered
approximately 62,000 bpd of gasoline, diesel and jet fuel through third-party
pipelines. Our Hawaii and Alaska refineries receive most of their crude oil and
transport a substantial portion of refined products through ships and barges.
Our Mid-Continent refineries receive substantially all of their crude oil and
deliver substantially all of their products through pipelines. Our California
refinery receives approximately half of its crude oil through pipelines and the
balance through marine vessels. Substantially all of our California refinery's
production is delivered through third-party pipelines, ships and barges. In
addition to environmental risks discussed above, we could experience an
interruption of supply or an increased cost to deliver refined products to
market if the ability of the pipelines or vessels to transport crude oil or
refined products is upset because of accidents, governmental regulation or
third-party action. A prolonged upset of the ability of a pipeline or vessels to
transport crude oil or product could have a material adverse effect on our
business, financial condition and results of operations.

24

OUR OPERATING RESULTS ARE SEASONAL AND GENERALLY ARE LOWER IN THE FIRST AND
FOURTH QUARTERS OF THE YEAR.

Demand for gasoline is higher during the spring and summer months than
during the winter months due to seasonal increases in highway traffic. As a
result, our operating results for the first and fourth quarters are generally
lower than for those in the second and third quarters.

ITEM 3. LEGAL PROCEEDINGS

None.

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

None.

PART II

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

Our common stock is listed under the symbol "TSO" on the New York Stock
Exchange and the Pacific Exchange. The per share market price ranges for our
common stock on the New York Stock Exchange during 2002 and 2001 are summarized
below:

At February 28, 2003, there were approximately 2,650 holders of record of
our 64,608,233 outstanding shares of common stock. We have not paid dividends on
our common stock since 1986 and our Board of Directors has no present plans to
pay dividends on our common stock. For information regarding restrictions on
future dividend payments and stock repurchase program, see Management's
Discussion and Analysis of Financial Condition and Results of Operations in Item
7 and Notes G and H of Notes to Consolidated Financial Statements in Item 8.

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

The 2003 Annual Meeting of Stockholders will be held at 8:00 A.M. Mountain
time on Thursday, May 1, 2003, at the Four Seasons Hotel, 10600 East Crescent
Moon Drive, Scottsdale, Arizona. Holders of Common Stock of record at the close
of business on March 12, 2003 are entitled to notice of and to vote at the
annual meeting.

25

The following table summarizes, as of December 31, 2002, certain
information regarding equity compensation to our employees, officers, directors
and other persons under our equity compensation plans.

EQUITY COMPENSATION PLAN INFORMATION

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

(a) The Key Employee Stock Option Plan (the "1999 Plan") was approved by our
board of directors in November 1999. The 1999 Plan provides for the
granting of stock options to eligible persons we employ who are not our
executive officers. Under the 1999 Plan, we may grant stock options to
acquire a total of 800,000 shares. We may grant stock options at not less
than the fair market value (as defined in the 1999 Plan) on the date the
options are granted, and the stock options generally become exercisable
after one year in 25 percent annual increments. The options expire ten
years after the date of grant. Our board of directors may amend, terminate
or suspend the 1999 Plan at any time.

26

ITEM 6. SELECTED FINANCIAL DATA

The following table sets forth certain selected consolidated financial and
operating data of Tesoro as of the end of and for each of the five years in the
period ended December 31, 2002. The selected consolidated financial information
presented below has been derived from our historical financial statements. Our
financial results include the results of our California operations since mid-May
2002 and our Mid-Continent operations since September 2001. The following table
should be read in conjunction with Management's Discussion and Analysis of
Financial Condition and Results of Operations in Item 7 and our Consolidated
Financial Statements, including the Notes thereto, in Item 8.

(table continued on following page)

27

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

(a) In 2002, we incurred charges of $20 million primarily for bridge financing
fees and integration costs associated with the acquisition of the
California refinery ($12 million aftertax or $0.20 per share). In 2001, we
incurred charges of $12 million for financing fees and integration costs,
primarily associated with the acquisition of our Mid-Continent refineries
($7 million aftertax or $0.17 per share). In 1998, we incurred a pretax
charge of $19 million for special incentive compensation ($12 million
aftertax or $0.40 per share).

28

(b) In December 1999, we sold our oil and gas exploration and production
operations and recorded an aftertax gain of $39 million from the sale of
these operations. In 1998, these operations incurred pretax writedowns of
oil and gas properties of $68 million ($43 million aftertax) and recognized
pretax income from receipt of contingency funds of $21 million ($13 million
aftertax).

(c) In 1998, extraordinary losses on debt extinguishments, net of income tax
benefits, were $4 million ($0.15 per basic and diluted share).

(d) The assumed conversion of our Premium Income Equity Securities 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. These securities automatically converted into shares of
common stock in July 2001, which eliminated our $12 million annual
preferred dividend requirement.

(e) At December 31, 2002, cash and cash equivalents included $16 million which
was used to prepay term loans in January 2003, as required by our senior
secured credit facility.

(f) During 2002, we issued $450 million in principal amount of 9 5/8% senior
subordinated notes due 2012 and two 10-year junior subordinated notes with
face amounts totaling $150 million, completed a public offering of 23
million shares and amended and restated our senior secured credit facility,
primarily to fund the acquisition of the California refinery assets. In
conjunction with the acquisitions of the Mid-Continent refineries, we
issued $215 million in principal amount of 9 5/8% senior subordinated notes
due 2008 and entered into a senior secured credit facility in 2001. In
conjunction with acquisitions in 1998, we refinanced our then existing
indebtedness and issued 9% senior subordinated notes due 2008 and
additional equity securities, including common stock and Premium Income
Equity Securities that are included in stockholders' equity.

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

(h) Capital expenditures exclude amounts to fund acquisitions in the Refining
segment and Retail segment in 2002, 2001 and 1998 and exclude amounts for
refinery turnaround spending and other major maintenance.

(i) Volumes for 2002 include amounts from the California refinery since we
acquired it on May 17, 2002, averaged over 365 days. Throughput and yield
for the California refinery averaged over the 229 days of operation that we
owned it were 150,800 bpd and 160,000 bpd, respectively. Volumes for 2001
include amounts from the Mid-Continent operations since we acquired them on
September 6, 2001, averaged over 365 days. Throughput and yield for these
refineries averaged over the 117 days that we owned them in 2001 were
105,000 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 365 days.

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

29

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 53 AND "RISK FACTORS" ON PAGE 19 FOR A
DISCUSSION OF THE FACTORS THAT COULD CAUSE ACTUAL RESULTS TO DIFFER MATERIALLY
FROM THOSE PROJECTED IN THESE STATEMENTS.

BUSINESS OVERVIEW

Our earnings, cash flows from operations and liquidity depend upon many
factors, including producing and selling refined products at margins above fixed
and variable expenses. The prices of crude oil and refined products have
fluctuated substantially in our markets. Our operating results can be
significantly influenced by the timing of changes in crude oil costs and how
quickly refined product prices adjust to reflect these changes. These price
fluctuations depend on numerous factors beyond our control, including the demand
for crude oil, gasoline and other refined products, which is subject to, among
other things, changes in the economy and the level of foreign and domestic
production of crude oil and refined products, worldwide political conditions,
threatened or actual terrorist incidents or acts of war, availability of crude
oil and refined product imports, the infrastructure to transport crude oil and
refined products, weather conditions, earthquakes and other natural disasters,
seasonal variation, government regulations and local factors, including market
conditions and the level of operations of other refineries in our markets. As a
result of these factors, margin fluctuations during any reporting period can
have a significant impact on our results of operations, cash flows, liquidity
and financial position.

During 2002, the refining industry in our market areas experienced the
lowest refined product margins since 1998. A warm winter in the Northeast
depressed distillate margins throughout the country and jet fuel demand declined
dramatically following the events of September 11, 2001. This in turn led U.S.
and foreign refiners to reduce distillate and jet fuel production with a
corresponding increase in gasoline output. The resulting levels of gasoline
produced exceeded gasoline demand increases, leading to lower gasoline margins.
The industry experienced rapidly rising crude oil prices due to tensions with
Iraq during 2002 and political instability in Venezuela during the 2002 fourth
quarter. These factors led to industry refining margins in our market areas that
were significantly below our five-year average (January 1, 1998 through December
31, 2002). We determine our "five-year average" by comparing gasoline, diesel
and jet fuel prices to crude oil prices in our market areas, with volumes
weighted according to our typical refinery yields. We experienced net losses in
each of the 2002 quarters resulting from weak industry margins and additional
interest and financing costs related to our acquisitions of the California
refinery in May 2002 and the Mid-Continent refineries in September 2001. In
connection with these acquisitions, our total debt increased by approximately
$1.7 billion from June 30, 2001 to June 30, 2002. In addition, the ratings of
our senior secured credit facility and senior subordinated notes were
downgraded. We have also experienced a tightening of the trade credit we
receive, which has required us to issue an increased amount of letters of credit
and make early payments and prepayments to certain suppliers.

Despite the weak margin environment, we generated cash flows from
operations of $58 million in 2002 and reduced term debt by $140 million
(including a $16.3 million prepayment in January 2003) following the acquisition
of the California refinery by selling over $200 million in assets, eliminating
or deferring capital expenditures, reducing expenses, achieving operating
synergies and reducing inventories. As of December 31, 2002, we had $110 million
in cash, no borrowings under the revolving credit facility and, with $60 million
in letters of credit outstanding, had total unused credit available of $165
million and a total debt to capitalization ratio of 69%.

We believe the industry conditions that led to low margins in 2002 have
improved, and if this improvement continues and margins remain at or near the
five-year average for the remainder of 2003, we believe we will comply with the
financial covenants of our senior secured credit facility in 2003. Industry
margins in 2003 in most of our market areas have averaged above our five-year
average (as described above). The winter in the Northeast has been extremely
cold in 2003, increasing demand and margins for distillates

30

throughout the country. Jet fuel demand has slowly improved and now approaches
pre-September 11, 2001 levels. Gasoline supply is expected to tighten due to
numerous factors, including changes in gasoline specifications and the voluntary
phase-out of MTBE in California.

However, if industry margins in our market areas drop below our five-year
average for any substantial period of time or if we find it necessary to borrow
the remaining available amounts under our senior secured credit facility for
working capital purposes, including to support trade credit requirements, we
will likely need to amend our senior secured credit facility because we may not
meet certain financial covenant tests during the remainder of 2003. In addition,
our credit ratings may be further reduced and our trade credit may be further
tightened. We believe that we will be able to amend our senior secured credit
facility or obtain covenant waivers if necessary; however, we cannot provide any
assurances that we will be able to obtain such an amendment or waiver on terms
and conditions acceptable to us or at all. See also "Risk Factors" in Items 1
and 2 beginning on page 19.

To better enable us to withstand a low margin environment similar to that
experienced in 2002, our 2003 goals include the further reduction of ongoing
cash expenses and elimination or deferral of capital expenditures. Assuming
these initiatives are realized and, if necessary, we are able to amend our
senior secured credit facility or obtain covenant waivers, we believe cash flow
from operations, amounts available under our senior secured credit facility and
available cash will be adequate to meet our anticipated requirements in 2003 for
working capital, capital expenditures and scheduled payments of principal and
interest on our indebtedness.

In addition, we are pursuing discussions regarding possible financing
alternatives to replace our senior secured credit facility. If we pursue such
alternatives, we intend to seek a debt structure designed (1) to increase our
capacity to borrow for working capital needs, (2) to allow us to issue letters
of credit instead of making early payments and prepayments to certain suppliers
and apply the funds that would otherwise have been used for those payments and
prepayments to repay debt and (3) to substantially modify the financial
covenants we have under our existing senior secured credit facility. However, we
cannot provide any assurances that such financing alternatives will be available
on terms and conditions acceptable to us or at all.

BUSINESS STRATEGY

Our strategy is to create a geographically-focused, value-added refining
and marketing business that has (i) economies of scale, (ii) a low-cost
structure, (iii) superior management information systems and (iv) outstanding
employees focused on business excellence and that seeks to provide stockholders
with competitive returns in any economic environment. Our immediate focus is to
reduce our level of debt through a combination of cash flow from operations,
cost savings and revenue enhancements.

DEBT REDUCTION

In June 2002, we announced our goal to reduce debt by $500 million by the
end of 2003. As reflected in our operating results, we experienced a weak margin
environment in 2002 which negatively affected our debt reduction plans.
Nevertheless, we have repaid $140 million of term loan debt since May 2002
(including a $16.3 million prepayment in January 2003). The primary initiatives
for 2002 were (i) asset sales, (ii) capital expenditure reductions, (iii)
achievement of system-wide synergies following our acquisition of refinery
assets in California, (iv) a working capital optimization program and (v) a cost
reduction and refinery improvement program.

For 2003, we continue to pursue our goal to further reduce debt through
positive operating cash flows and cash conservation measures based on the
following strategic initiatives: (i) a cost reduction and refinery improvement
program, (ii) elimination or deferral of capital expenditures and refinery
turnaround spending, (iii) achievement of system-wide synergies from the
acquisition of our California refinery and (iv) asset sales.

31

Asset Sales

Asset sales provided the largest contribution to our debt reduction goal in
2002. We identified certain non-core asset groups to be evaluated to meet the
goal of raising $200 million, which initially included our marine services
operations, the crude oil and product pipeline systems and associated terminals
around the North Dakota refinery, and selected retail sites.

In December 2002, we sold our product pipeline extending from Mandan, North
Dakota to Minneapolis, Minnesota and terminals in Jamestown, North Dakota and
Moorhead, Sauk Centre and Minneapolis/ St. Paul, Minnesota for approximately
$100 million in cash; we completed the sale of 70 retail stations in northern
California (that we had acquired with the California refinery) for approximately
$66 million in cash; and we completed a sale/lease-back transaction for 30 of
our retail sites located in Alaska, Hawaii, Idaho and Utah for cash proceeds of
approximately $40 million. These and other miscellaneous asset sales provided
aggregate net proceeds totaling approximately $207 million. As required under
the senior secured credit facility, we used 50% of the aggregate net proceeds to
prepay term loans ($87.5 million in December 2002 and $16.3 million in January
2003). We plan to dispose of an additional $20 million of non-core assets in
2003.

Given the limited divestiture opportunities for our marine services
operations on the U.S. Gulf Coast, we plan to integrate this business with our
wholesale marketing and terminal operations during 2003. Our goal is to increase
the overall profitability of this operation as we optimize it within our
existing organization.

We have explored alternatives for our crude oil pipeline in North Dakota.
Our objective was to sell this asset while preserving the security of supply and
quality standards of our crude source for our North Dakota refinery. We have
considered several potential sale structures but have not identified a
transaction that meets our objectives. Therefore, we are no longer pursuing a
divestiture of this asset.

Reductions in Capital Expenditures and Refinery Turnaround Spending

Another initiative is to reduce capital expenditures and refinery
turnaround spending by a combined $70 million during 2002 and 2003. We spent
$243.5 million in 2002, which included $54 million in the fourth quarter. Total
capital and turnaround spending in 2002 was below the $250 million that we
targeted in June 2002 following the acquisition of the California refinery. Our
current plan is to spend approximately $164 million in 2003, including
approximately $17 million to complete the CARB III project at the California
refinery in the first quarter and approximately $42 million primarily for major
turnarounds at three of our refineries.

Achievement of Synergies

We also are focusing on pursuing new synergies from our refinery system
following the acquisition of the California refinery. During 2002, we achieved
approximately $12 million in synergies, surpassing our previously announced goal
of $10 million. During the California refinery turnaround in June 2002, we were
able to achieve benefits that otherwise would have been unavailable without the
California refinery. For example, we were able to upgrade the value of
intermediate feedstock produced by our other refineries through supply to our
California refinery during the turnaround. In addition, we have been able to
upgrade unfinished gasoline components from elsewhere in our refinery system by
blending them into finished gasoline. We believe that we will achieve the
targeted annual system synergies of $25 million by the end of 2003, largely due
to the benefits from owning the California refinery for a full year.

Working Capital Optimization

During 2002, one of our initiatives was to optimize our working capital.
Since we began this initiative in June 2002, we reduced our crude oil and
product inventories by approximately 5.5 million barrels to 17.8 million barrels
at the end of December 2002. The value of this inventory reduction exceeded our
goal to reduce working capital by $50 million by year-end 2002. We are
projecting this level of inventory at year-end 2003; however, due to seasonal
factors, we expect inventory increases at various times during the year. Our

32

effort to reduce our working capital in 2002 was partially offset by the 30% to
40% increase in crude oil prices during the fourth quarter and a shortening of
our normal payment terms to creditors.

Cost Reduction and Refinery Improvement Program

Our final initiative is to realize $75 million of operating income
improvements through cost reductions and refining improvements that do not
require significant capital investments. Our goal was to achieve $10 million of
the operating improvements by the end of 2002 and $65 million by the end of
2003. During the 2002 third and fourth quarters, we initiated programs to
consolidate our marketing organization, eliminate non-essential travel and
reduce contract labor in both operations and administration. In addition, we
made other reductions in manufacturing costs, but they were offset by higher
utility expenses. Through these programs and other efficiencies, we achieved our
goal of $10 million in operating improvements during 2002. In 2003, we expect to
further reduce administrative, marketing and operating expenses through
reorganization and related employee cost savings, achieving economies in
refinery maintenance and purchasing and cost savings from the continued
rationalization of our retail assets. See Note O of Notes to Consolidated
Financial Statements in Item 8 for information related to certain charges for
enhanced retirement plan benefits and other employee costs to be incurred in the
first quarter of 2003.

REFINING IMPROVEMENTS

CARB III Project

We anticipate that the CARB III project will increase our capacity to
produce CARB gasoline at the California refinery by up to 20,000 bpd or
approximately 30%. This project will enable us to comply with California
regulations to phase out the use of the oxygenate known as MTBE, currently
expected to be effective on January 1, 2004. We spent approximately $60 million
through December 31, 2002, and we expect to spend an additional $17 million to
complete the project in the first quarter of 2003.

Heavy Oil Conversion Project

We completed a heavy oil conversion project at our Washington refinery in
the 2002 first quarter, which enables 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. The upgraded
FCC unit, the final major component of the heavy oil conversion project, was
fully operational at the end of the first quarter of 2002. The total cost of the
project was approximately $121 million, of which $24 million was spent in 2002.

RESULTS OF OPERATIONS

SUMMARY

Our net loss for the year 2002 was $117 million ($1.93 net loss per basic
and diluted share) compared with net earnings of $88 million ($2.26 per basic
share and $2.10 per diluted share) for 2001. The net loss for 2002 was primarily
the result of weak margins in each of our operating segments and additional
interest and financing costs related to acquisitions in the second half of 2001
and in May 2002. Charges for bridge financing fees and integration costs,
primarily associated with the acquisition of the California refinery, totaled
approximately $12 million aftertax, or $0.20 per share, in 2002. Our 2002
results also included losses on asset sales and impairment of goodwill, which
totaled approximately $5 million aftertax, or $0.08 per share. In 2001, we
incurred approximately $7 million aftertax, or $0.17 per share, for financing
fees and integration costs, primarily associated with the acquisition of our
Mid-Continent refineries.

Our net earnings for the year 2001 were $88 million ($2.26 per basic share
or $2.10 per diluted share), an increase of 20% compared to net earnings of $73
million ($1.96 per basic share or $1.75 per diluted share) in 2000. The earnings
improvement in 2001 was primarily a result of increased refining throughput,
improved operating performance and incremental operating income from
acquisitions. This improvement was partially offset by expenses related to
acquisition financing and integration.

33

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

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

(a) Includes intersegment sales to our Retail segment, at prices which
approximate market, of $826 million, $334 million and $213 million in 2002,
2001 and 2000, respectively.

(b) Volumes for 2002 include amounts for the California refinery since we
acquired it on May 17, 2002, averaged over 365 days. Throughput for the
California refinery averaged over the 229 days of operation was 151
thousand bpd. Volumes for 2001 include amounts for the Mid-Continent
refineries since we acquired them on September 6, 2001 averaged over 365
days. Throughput for the Mid-Continent refineries averaged over the 117
days of operation was 105 thousand bpd.

(c) Certain previously reported amounts have been reclassified to conform to
the 2002 presentation. The value of internally-produced fuel has been
reclassified from Manufacturing Costs and is shown as a reduction in Gross
Refining Margin. The value of internally-produced fuel amounted to $1.09
per barrel, $1.18 per barrel and $0.86 per barrel for 2002, 2001 and 2000,
respectively, for the total refining segment. In addition, amortization of
refinery turnaround and major maintenance costs was reclassified from
Manufacturing Costs to Depreciation and Amortization. Major maintenance
amortization amounted to $0.16 per barrel, $0.20 per barrel and $0.24 per
barrel for 2002, 2001 and 2000, respectively, for the total refining
segment. Management uses gross refining margin per barrel to compare
profitability to other companies in the industry. Gross refining margin per
barrel is calculated by dividing gross refining margin by annual total
refining throughput. Gross refining margin per barrel may not be comparable
to similarly titled measures used by other entities.

(d) Manufacturing costs are primarily operating cash costs directly associated
with the manufacturing process and as described in (c) above, exclude
non-cash amortization of refinery turnaround and major maintenance costs
and the value of internally-produced fuel. Management uses manufacturing
costs per barrel to evaluate the efficiency of refinery operations.
Manufacturing costs per barrel may not be comparable to similarly titled
measures used by other entities.

(e) Our gross refining margin is revenues less cost of refining feedstock and
purchased products. Gross refining margin approximates total Refining
segment throughput times gross refining margin per barrel, adjusted for
changes in refined product inventory due to selling a volume and mix of
product that is different than actual volumes manufactured. Also includes
the effect of intersegment sales to the Retail segment at prices which
approximate market.

(f) Includes manufacturing depreciation per throughput barrel of approximately
$0.40, $0.28 and $0.26 for 2002, 2001 and 2000, respectively. Also includes
amortization of major maintenance costs of $0.16 per barrel, $0.20 per
barrel and $0.24 per barrel for the years ended 2002, 2001 and 2000,
respectively.

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

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

35

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

Our operating income in 2002 was also impacted negatively by the scheduled
turnarounds at our Washington and California refineries in the first and second
quarters of 2002, respectively, and unscheduled downtime at our Washington and
Utah refineries in the first quarter of 2002. During the Washington refinery
turnaround, we completed the heavy oil conversion project, which was fully
operational in March 2002. While the heavy oil conversion project contributed to
our segment operating income during the last nine months of 2002, the
contribution was less than our expectation due to the tightening of the light to
heavy crude price differential and weak refining margins.

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

Revenues from sales of refined products increased 40% to $6.4 billion in
2002, from $4.6 billion in 2001, due to increased sales volumes from the
Mid-Continent and California refineries, partly offset by lower average product
sales prices. Total product sales averaged 545 thousand bpd in 2002, an increase
of 45% from 2001, while average product prices dropped 4% to $32.25 per barrel.
The increase in other revenues was primarily due to higher crude oil resales
which totaled $314 million in 2002 compared to $239 million in 2001. Costs of
sales also increased primarily due to the additional throughput volumes from the
Mid-Continent and California refineries. During the 2002 third quarter, we
reduced certain inventory levels at our Mid-Continent refineries by
approximately 900,000 barrels from the year-end 2001 level, resulting in the
liquidation of applicable LIFO inventory quantities carried at lower costs. This
reduction in LIFO inventory is part of our working capital management program
and decreased costs of sales by approximately $5 million pretax in 2002.

Expenses, excluding depreciation, increased to $522 million in 2002,
primarily due to additional expenses of approximately $219 million from the
Mid-Continent and California refineries. Excluding these new operations, total
expenses did not change significantly from 2001. Manufacturing cost per barrel
for the California refinery is higher than our other refineries because of its
increased complexity and product upgrading capabilities. Depreciation and
amortization increased to $104 million, primarily due to additional depreciation
and amortization of $38 million from the Mid-Continent and California
refineries.

Several currently anticipated events will impact our financial results in
2003. Major maintenance turnarounds are scheduled at the Utah refinery in March
2003, the Alaska refinery in the second quarter of 2003 and the North Dakota
refinery in the fourth quarter of 2003. We anticipate that the CARB III project
at our California refinery will increase our capacity to produce CARB gasoline
at the refinery by up to 20,000 bpd or approximately 30%. Subsequent to the sale
of the products pipeline in December 2002, we have continued to distribute our
products through the pipeline. We estimate that pipeline tariffs, partly offset
by a decrease in depreciation, will reduce our annual operating income for the
North Dakota refinery by approximately $11 million.

36

2001 Compared to 2000. Operating income for the Refining segment was $226
million in 2001, an 18% increase from 2000. Our Mid-Continent operations
acquired in 2001 contributed approximately $31 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.

During the fourth quarter of 2001, however, market conditions caused
significant erosion in industry refining margins. Our weakest market was the
Pacific Northwest, where our actual gross refining margin in the 2001 fourth
quarter averaged $4.57 per barrel, reducing this region's annual 2001 margin to
$6.07 per barrel compared to $6.93 per barrel in 2000. For the full year, total
gross refining margin per barrel remained relatively flat from 2000.

On an aggregate basis, our total gross refining margin increased 12% to
$598 million in 2001 reflecting higher throughput volumes and contributions from
the Mid-Continent operations. We increased refinery throughput 3%, or 7 thousand
bpd, excluding the acquired 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 43% in 2000.

Revenues from sales of refined products in the Refining segment increased
to $4.6 billion in 2001, from $4.5 billion in 2000, due to increased sales
volumes largely offset by lower prices. Total product sales averaged 376
thousand bpd in 2001, an increase of 16% from 2000, while product prices dropped
12% to $33.50 per barrel. The decrease in other revenues was primarily due to
lower crude oil resales which totaled $239 million in 2001 compared to $277
million in 2000. Costs of sales remained flat in 2001 compared with 2000,
primarily reflecting lower prices for feedstocks and product supply offset by
higher throughput.

Expenses, excluding depreciation, increased by 9% to $309 million in 2001,
primarily due to additional operating expenses from our acquired operations and
increased throughput at our other refineries. Depreciation and amortization
increased from $58 million to $63 million, primarily reflecting the acquisition
of the Mid-Continent refinery in 2001.

37

RETAIL SEGMENT

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

(a) Includes 70 retail stations in northern California (which we had acquired
with the California refinery in May 2002) that we sold in December 2002 and
30 of our retail sites located in Alaska, Hawaii, Idaho and Utah which we
sold and leased-back in December 2002.

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

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

2002 Compared to 2001. The operating loss for our Retail segment was $12
million in 2002 compared to operating income of $25 million in 2001. Total gross
margins increased 24% to $135 million in 2002 from $109 million in 2001
reflecting increased sales volume, offset largely by lower fuel margin per
gallon. Fuel margin decreased to $0.12 per gallon in 2002 from $0.22 per gallon
in 2001, reflecting continued competitive price pressures and changes in the
geographic mix of our Retail sites. Total gallons sold increased to 790 million,
reflecting the increase in average station count to 679 in 2002 from 406 in
2001. This increase in average station count was primarily due to the
Mid-Continent operations acquired in September 2001, additional stations
acquired in the Pacific Northwest in November 2001, and the 70 retail stations
acquired with the California refinery assets in May 2002. These increases were
partially offset by approximately 150 BP/Amoco jobber/dealer stations (included
in the Mid-Continent acquisition) that did not rebrand to the Tesoro(R) brand
name. This decision not to rebrand resulted in us no longer being those
jobber/dealer stations' exclusive supplier under the terms of the acquisition
agreement. The 70 California stations, which we sold in December 2002,
contributed operating income of approximately $6 million during the period we
owned them in 2002. In addition, in December 2002, we completed a
sale/lease-back transaction for 30 of our retail sites

38

located in Alaska, Hawaii, Idaho and Utah. The related lease expense will
decrease operating income by approximately $2 million in 2003.

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

We adopted a flat to modest growth strategy for our Retail segment that
will focus on select jobber/dealer investments in certain of our markets. We do
not expect to build any new retail stations in 2003.

2001 Compared to 2000. Operating income for our Retail segment increased
to $25 million in 2001, compared to a loss of $2 million in 2000. The expansion
of our Tesoro-operated and jobber/dealer network enabled us to increase revenues
and profits in 2001. Our total gallons sold increased 84% to 396 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.

Revenues on fuel sales grew to $421 million in 2001, a 68% increase from
2000, while merchandise and other revenues increased by 27% to $70 million.
Merchandise margin, however, as a percent of sales decreased. With our increased
number of stations, expenses increased 43% to $73 million and depreciation
increased to $11 million in 2001.

OTHER

In addition to our Refining and Retail segments, we market and distribute
petroleum products and provide logistical support services to the marine and
offshore exploration and production industries operating in the Gulf of Mexico.
Operating income from these operations decreased to $2 million in 2002 from $10
million in 2001 and 2000. Lower sales volumes and service revenues contributed
to this decrease. This segment is largely dependent on the volume of offshore
oil and gas drilling, workover, construction and seismic activity. The
significant decline in industry drilling activity negatively impacted sales and
operating income during 2002.

SELLING, GENERAL AND ADMINISTRATIVE EXPENSES

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

Selling, general and administrative expenses of $104 million in 2001
increased $19 million from $85 million in 2000. This increase was partially due
to higher expenses in the Retail segment associated with the increased number of
stations in 2001. Corporate expenses accounted for $14 million of the increase
resulting largely from $6 million in acquisition and integration costs in 2001,
as well as higher employee costs and professional fees.

During 2002, we initiated programs to consolidate our marketing
organization, eliminate non-essential travel and reduce contract labor in both
operations and administration. We expect to further reduce these expenses during
2003. We will incur certain charges for enhanced retirement plan benefits and
other employee costs. The charge in the first quarter of 2003 could range from
$12 million to $24 million pretax, depending on the number of employees electing
enhanced retirement plan benefits (see Notes A and O of Notes to Consolidated
Financial Statements in Item 8 for further information).

39

LOSS ON ASSET SALES AND IMPAIRMENT

The loss on asset sales and impairment of $8 million in 2002 consisted
primarily of losses on the sale of retail stations of $7 million and an
impairment of Retail goodwill of $1 million (see Notes E and L of Notes to
Consolidated Financial Statements in Item 8).

INTEREST AND FINANCING COSTS

Interest and financing costs, net of capitalized interest, were $166
million in 2002 compared to $53 million in 2001. The increase was primarily due
to the additional debt we incurred in 2001 and 2002 in connection with our
acquisitions of the Mid-Continent and California operations. We also expensed
$13 million during the first six months of 2002 related to bridge and other
financing fees for the acquisition of the California refinery.

Interest and financing costs, net of capitalized interest, were $53 million
in 2001 compared to $33 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.

We estimate interest expense for 2003 will be approximately $190 million,
reflecting $165 million of scheduled interest payments and $25 million primarily
for amortization of deferred financing costs and debt discounts. The estimated
interest does not reflect potential borrowings under our revolving credit
facility, prepayments of debt or charges related to possible refinancing (see
Note A of Notes to Consolidated Financial Statements in Item 8). At December 31,
2002, we had $35 million of deferred financing costs related to our senior
secured credit facility. If we elect to replace or modify our senior secured
credit facility, we may be required to write-off all or a portion of these
deferred costs during the quarter in which we replace or modify the facility.

INCOME TAX PROVISION (BENEFIT)

The income tax benefit amounted to $64 million in 2002, which compares to
an income tax provision of $59 million in 2001. The benefit resulted from the
pretax losses for 2002. In 2002, we elected to carry back net operating losses
to recover income taxes paid in previous years; however, the refund of those
taxes resulted in the loss of certain tax credits. The expiration of these
credits, along with other adjustments to our estimated liabilities, resulted in
a reduced tax benefit of approximately $6 million.

The income tax provision of $59 million 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.

CAPITAL RESOURCES AND LIQUIDITY

OVERVIEW

We operate in an environment where our liquidity and capital resources are
impacted by changes in the price of crude oil and refined petroleum products,
availability of trade credit, market uncertainty and a variety of additional
factors beyond our control. These risks include, among others, the level of
consumer product demand, weather conditions, fluctuations in seasonal demand,
governmental regulations, worldwide political conditions and overall market and
economic conditions. See "Business Overview" on page 30, "Forward-Looking
Statements" on page 53 and "Risk Factors" on page 19 for further information
related to risks and other factors. Our future capital expenditures, as well as
borrowings under our senior secured credit facility and other sources of
capital, will be affected by these conditions.

Our primary sources of liquidity have been cash flows from operations,
issuance of equity and debt, borrowing availability under revolving lines of
credit, and asset sales. We ended 2002 with $110 million of cash and cash
equivalents on our balance sheet, and we had no borrowings under our revolving
credit facility and $60 million in outstanding trade letters of credit. As
previously described, we sold assets in the 2002 fourth

40

quarter from which we received net proceeds totaling $207 million. Of this
amount, $87.5 million was used to prepay term loans in December 2002. An
additional $16.3 million was included in cash at December 31, 2002 and,
subsequent to year-end, was used to prepay term debt. Because of the weakness in
industry refinery margins during 2002 and economic uncertainty, we have
experienced a tightening of the trade credit we receive. We are a significant
purchaser of crude oil and other feedstocks in our market areas, which enables
us to use various purchasing strategies, including open credit terms, early
payments, netting agreements, and to a lesser extent, prepayments of invoices.
Under current economic conditions and in light of the general uncertainty which
surrounds our business, we cannot give assurance that the trade credit extended
to us will not be further tightened. We believe that we will be able to continue
to operate at current production levels considering current market conditions,
through our management of working capital, capital expenditures, available
borrowing capacity under our revolving credit facility, available lines of trade
credit and operating cash flows. However, if credit extended to us were to
significantly tighten or our margins were to return to levels significantly
below the average levels for the last five years for an extended period of time,
our business might not be able to generate sufficient cash flow to fund
operations, capital expenditures and debt service.

CAPITALIZATION

Our capital structure at December 31, 2002 was comprised of the following
(in millions):

Debt, including current maturities:
Senior Secured Credit Facility -- Tranche A Term Loan..... $ 194
Senior Secured Credit Facility -- Tranche B Term Loan..... 724
Senior Secured Credit Facility -- Revolver................ --
9 5/8% Senior Subordinated Notes due 2012................. 450
9 5/8% Senior Subordinated Notes due 2008................. 215
9% Senior Subordinated Notes due 2008..................... 298
Junior subordinated notes................................. 67
Other debt, primarily capital leases...................... 29
------
Total debt............................................. 1,977
Common stockholders' equity................................. 888
------
Total Capitalization................................... $2,865
======

At December 31, 2002, our debt to capitalization ratio was 69% compared
with 60% at year-end 2001, primarily reflecting acquisition-related borrowings
under our senior secured credit facility and the issuance of $450 million
aggregate principal amount of 9 5/8% senior subordinated notes due 2012,
partially offset by net proceeds of $245 million from the issuance of 23 million
shares of common stock in March 2002, prepayment of term loans of $87.5 million
in December 2002 from asset sales proceeds and regularly scheduled payments of
debt.

Our senior secured credit facility and 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. Each of these
obligations is guaranteed by substantially all of our active domestic
subsidiaries.

SENIOR SECURED CREDIT FACILITY

On May 17, 2002, we amended and restated our senior secured credit facility
to increase the facility to $1.275 billion from $1.0 billion to partially fund
the acquisition of the California refinery and retail assets. The terms and
conditions of this credit facility were subsequently amended on September 30,
2002, to reflect modified financial tests. The amendment also, among other
things, increased the amount of proceeds from asset sales or equity offerings
that must be received and limits capital expenditures, both of which are
consistent with our previously announced goals. The credit facility was further
amended in December 2002,

41

giving flexibility to the terms and the timing of the required proceeds from
asset sales or equity offerings. Under the revised terms of the credit facility,
we agreed to pay certain fees and to increase the interest rate on borrowings.

The credit facility currently consists of a five-year $225 million
revolving credit facility (with a $150 million sublimit for letters of credit),
a five-year tranche A term loan and a six-year tranche B term loan. As of
December 31, 2002, we had no borrowings and $60 million in letters of credit
outstanding under the revolving credit facility, resulting in a total unused
credit available of $165 million. As of December 31, 2002, $194 million
principal amount was outstanding under the tranche A term loan and $724 million
principal amount was outstanding under the tranche B term loan. In addition to
the credit facility, we have an uncommitted letter of credit line with a bank,
under which no amounts were outstanding as of December 31, 2002.

The 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 and future active domestic subsidiaries and 66% of the
stock of our current and future foreign subsidiaries.

At December 31, 2002, interest rates were 6.77% on the tranche A term loan
and 8.5% on the tranche B term loan. Borrowings bear interest at either a base
rate (4.25% at December 31, 2002) or a eurodollar rate (1.77% at December 31,
2002), plus an applicable margin. From September 30, 2002 to March 31, 2004, the
applicable margins on the tranche A term loan and the revolving credit facility
will be 3% in the case of the base rate and 4% in the case of the eurodollar
rate and will be 3.5% in the case of the base rate and 4.5% in the case of the
eurodollar rate for the tranche B term loan. Additionally, the tranche B
eurodollar rate is deemed to be no less than 3.0%. Subsequent to March 31, 2004,
borrowing rates under the tranche A term loan and the revolving credit facility
will vary in relation to our senior debt to EBITDA ratio. The credit facility
interest rates also include an additional 1% interest rate on the tranche A term
loan, tranche B term loan and revolving credit facility from September 30, 2002
to March 31, 2004 and thereafter until our debt-to-capital ratio falls to no
greater than 0.55 to 1.00. The first additional interest payment is due
September 30, 2003 and quarterly thereafter. We are also charged various fees
and expenses in connection with the credit facility, including commitment fees
and various letter of credit fees.

The credit facility requires us to meet certain financial covenants, some
of which use a measure of cash flow called EBITDA, as defined in the credit
facility. The financial covenants specify thresholds of the following ratios
which use EBITDA: senior debt to EBITDA, EBITDA to fixed charges and EBITDA to
interest expense. The initial calculations of these ratios are to be made when
we issue our financial results for the quarter ending September 30, 2003, using
the immediately preceding four quarters. In addition, the financial covenants
set a maximum threshold for total debt to total capitalization ratio, as defined
in the credit facility, each quarter-end commencing June 30, 2002. The credit
facility requires a minimum cumulative consolidated EBITDA amount of $90 million
and $270 million for the nine-month period ending March 31, 2003 and the
twelve-month period ending June 30, 2003, respectively. The credit facility also
requires a minimum consolidated quick ratio, as defined in the credit facility,
each month-end beginning October 31, 2002 through June 30, 2003. The credit
facility limits our capital expenditure and refinery turnaround spending to no
more than $253.5 million in the year 2002, $237.5 million for the twelve-month
period ending June 30, 2003 and $210 million in the calendar year 2003 and each
year thereafter unless our debt-to-capital ratio falls below 0.58 to 1.00. Under
the terms of our senior secured credit facility, we are not permitted to declare
or pay cash dividends on our common stock or repurchase shares of our common
stock through December 31, 2003. Beginning January 1, 2004, 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. The credit facility
contains other covenants and restrictions customary in credit arrangements of
this kind. Noncompliance with the covenants constitutes an event of default and,
if not cured by a waiver or amendment, would permit the lenders to accelerate
the maturity of the credit facility, refuse to advance any additional funds
under the credit facility and exercise the lenders' remedies under the credit
facility.

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We satisfied all of the financial covenants under the credit facility for
the period ended December 31, 2002, as well as the requirement to complete asset
sales resulting in net proceeds of at least $200 million prior to March 31,
2003. Of this amount, $87.5 million was used to prepay term loans in December
2002. An additional $16.3 million, included in cash at December 31, 2002, was
used to prepay term loans in January 2003. Net proceeds from asset sales or
equity offerings received in 2003 up to the date we issue financial results for
the quarter ending September 30, 2003, are required to be applied in full to
prepay the term loans.

We believe the industry conditions that led to low margins in 2002 have
improved, which we believe will enable us to comply with the financial covenants
of our senior secured credit facility for the remainder of the year. However, if
industry margins in our market areas drop below the five-year average for any
substantial period of time or if we find it necessary to borrow the remaining
available amounts under our senior secured credit facility for working capital
purposes, including to support trade credit requirements, we will likely need to
amend our senior secured credit facility because we may not meet certain
financial covenant tests during the remainder of 2003. In addition, our credit
ratings may be further reduced and our trade credit may be further tightened. We
believe that we will be able to amend our senior secured credit facility or
obtain covenant waivers if necessary; however, we cannot provide any assurances
that we will be able to obtain such an amendment or waiver on terms and
conditions acceptable to us or at all. See also "Risk Factors" under Items 1 and
2 beginning on page 19.

In addition, we are pursuing discussions regarding possible financing
alternatives to replace our senior secured credit facility. If we pursue such
alternatives, we intend to seek a debt structure designed (1) to increase our
capacity to borrow for working capital needs, (2) to allow us to issue letters
of credit instead of making early payments and prepayments to certain suppliers
and apply the funds that would otherwise have been used for those payments and
prepayments to repay debt and (3) to substantially modify the financial
covenants we have under our existing senior secured credit facility. However, we
cannot provide any assurances that such financing alternatives will be available
on terms and conditions acceptable to us or at all.

SENIOR SUBORDINATED NOTES

In April 2002, we issued $450 million principal amount of 9 5/8% senior
subordinated notes due April 1, 2012. The 9 5/8% senior subordinated notes due
2012 have a ten-year maturity with no sinking fund requirements and are subject
to optional redemption by us beginning in April 2007 at declining premiums. In
addition, until April 1, 2005, we may redeem up to 35% of the principal amount
at a redemption price of 109.625% with proceeds of certain equity issuances.

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

Our 9% senior subordinated notes due 2008, Series B, were issued in 1998 at
a principal amount of $300 million. These notes have a ten-year maturity without
sinking fund requirements and are subject to optional redemption by us beginning
in July 2003 at declining premiums.

The indentures for our 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 and 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 certain asset sales;

- enter into transactions with affiliates;

- incur liens on assets to secure certain debt;

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- engage in certain business activities; and

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

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

JUNIOR SUBORDINATED NOTES

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

EQUITY OFFERING

On March 6, 2002, we completed a public offering of 23 million shares of
our common stock. The net proceeds from the stock offering of $245 million,
after deducting underwriting fees and offering expenses, were used to partially
fund the acquisition of the California refinery.

CASH FLOW SUMMARY

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

Net cash from operating activities during 2002 totaled $58 million,
compared to $214 million from operating activities in 2001. The decrease was
primarily due to lower earnings before depreciation and amortization and higher
expenditures for scheduled refinery turnarounds, partially offset by reduced
working capital requirements and receipt of income tax refunds. Net cash used in
investing activities of $941 million in 2002 included $932 million for the
acquisition of the California refinery and $204 million for capital
expenditures, partially offset by $207 million in proceeds from asset sales. Net
cash from financing activities of $941 million in 2002 included net proceeds of
$245 million from our equity offering, net proceeds of $441 million from our
notes offering and borrowings of $425 million under the senior secured credit
facility, partly offset by repayments of debt of $133 million and financing
costs of $37 million. Gross borrowings and repayments under revolving credit
lines amounted to $624 million during 2002. We had no outstanding borrowings
under our revolving credit facility at December 31, 2002. Working capital
totaled $446 million at December 31, 2002 compared to $340 million at year-end
2001, reflecting increases related to the acquisition of the California
refinery, cash and income taxes receivable, partly offset by reductions in
inventories.

Net cash from operating activities during 2001 totaled $214 million,
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 decrease in feedstock and refined product
prices at year-end 2001. This increase in cash flow was partially offset by an
increase in receivables from the sales activity associated with our refinery
assets in the Mid-Continent operations. Net cash used in investing activities of
$976 million

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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 notes offering, partly offset by financing costs of $21 million
and preferred dividend payments of $9 million. The preferred stock was converted
to common stock in July 2001, eliminating 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.

Net cash from operating activities during 2000 totaled $90 million.
Operations provided cash flows from earnings before depreciation and
amortization and other non-cash charges, partially offset by increased working
capital requirements. During 2000, working capital requirements increased due to
higher receivables and inventories reflecting higher prices for refinery
feedstocks and products, as well as an increase in inventory volumes. 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 $9 million. We had no outstanding
borrowings under revolving credit lines at December 31, 2000. Gross borrowings
and repayments under revolving credit lines amounted to $866 million during
2000.

HISTORICAL EBITDA

EBITDA represents earnings before interest and financing costs, interest
income, income taxes, and depreciation and amortization. EBITDA is presented
herein because it enhances an investor's understanding of our ability to satisfy
principal and interest obligations with respect to our indebtedness and to use
cash for other purposes, including capital expenditures. EBITDA is also used for
internal analysis and as a basis for several financial covenants. EBITDA should
not be considered as an alternative to net earnings (loss), earnings (loss)
before income taxes, cash flows from operating activities or any other measure
of financial performance presented in accordance with accounting principles
generally accepted in the United States ("U.S. GAAP"). EBITDA may not be
comparable to similarly titled measures used by other entities. Our EBITDA for
the years ended December 31, 2002, 2001 and 2000 were as follows (in millions):

Our EBITDA for the 2002 quarters were as follows (in millions):

45

Historical EBITDA as presented above is different than EBITDA as defined
under our senior secured credit facility. The primary differences are non-cash
postretirement benefit costs and loss on asset sales and impairment, which are
added to net earnings (loss) under the senior secured credit facility EBITDA
calculations.

CAPITAL EXPENDITURES AND REFINERY TURNAROUND SPENDING

Our capital expenditures and refinery turnaround spending totaled $243.5
million during 2002, as discussed below.

Capital Expenditures

During 2002, our capital expenditures (excluding refinery turnaround and
other major maintenance costs) totaled $204 million, which included $24 million
for completion of the heavy oil conversion project at our Washington refinery
and $41 million for retail marketing programs. In addition, we spent
approximately $77 million at our California refinery, including $60 million for
a project to meet CARB III gasoline production requirements and $9 million to
complete a nitrogen oxide emissions control project. Other capital spending was
primarily for various refinery improvements and environmental requirements.

We reduced our 2003 capital spending plan in response to the weaker
refining and retail margin environment. Our senior secured credit facility
limits our total capital expenditures and refinery turnaround spending to no
more than $237.5 million for the twelve-month period ending June 30, 2003 and
$210 million for the year 2003. We have deferred our spending plans for certain
discretionary projects while maintaining spending to meet environmental, safety,
regulatory and other operational requirements. Currently, we have adopted a flat
to modest growth strategy for the Retail segment that will focus on jobber
investments in selected markets. Therefore, we do not expect to build any new
retail sites in 2003.

Our current capital expenditure plan includes approximately $122 million in
2003 (excluding refinery turnaround and other major maintenance costs of
approximately $42 million). The capital budget for the Refining segment is $99
million, including $17 million for the completion of the CARB III project, $10
million for other clean air and fuel projects, and other projects totaling $72
million. Our Retail capital budget is $3 million for 2003. We expect to fund the
2003 capital spending program primarily from operating cash flows, including
benefits from cost reduction programs.

Refinery Turnaround and Other Major Maintenance

During 2002, we spent $40 million for refinery turnaround and other major
maintenance, including $15 million for our scheduled turnaround of certain
processing units at our California refinery in the second quarter of 2002 and
$19 million for the completion of a scheduled turnaround of the Washington
refinery in the first quarter of 2002. Amortization of refinery turnaround and
other major maintenance costs totaled $27 million in 2002. We expect to spend
approximately $42 million, primarily for major turnarounds at three of our
refineries in 2003.

We estimate our annual spending for refinery turnarounds and other major
maintenance to be as follows (in millions):

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LONG-TERM COMMITMENTS

Contractual Commitments

We have numerous contractual commitments for purchases of goods and
services arising in the ordinary course of business, debt service requirements
and lease commitments (see Notes G and Q to Consolidated Financial Statements in
Item 8). The following table summarizes these future commitments at December 31,
2002 (in millions):

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

(a) Debt includes $16 million paid in January 2003 from asset sales completed
in December 2002.

In addition to the above commitments, we have a power supply agreement at
our California refinery which requires minimum payments that vary, based on
market prices for electricity, over the next 10 years. We also anticipate we
will continue to make annual base payments of approximately $6 million from 2004
to 2010 for an MTBE facility located at our California refinery.

We lease our corporate headquarters from a limited partnership in which we
own a 50% limited interest. The initial term of the lease is through 2014 with
two five-year renewal options. Lease payments and operating costs paid to the
partnership totaled $2.1 million, $2.5 million and $1.8 million in 2002, 2001
and 2000, 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 $17 million and debt of approximately
$13 million are not included in our Consolidated Financial Statements in Item 8.

Clean Fuels and Clean Air Capital

In February 2000, the EPA finalized new regulations pursuant to the Clean
Air Act requiring reduction in the sulfur content in gasoline beginning January
1, 2004. To meet the revised gasoline standard, we currently estimate we will
make capital improvements of approximately $37 million through 2006 and an
additional $15 million thereafter. This will permit all of our refineries to
produce gasoline meeting the limits imposed by the EPA.

In January 2001, the EPA also promulgated new regulations, pursuant to the
Clean Air Act requiring a reduction in the sulfur content in diesel fuel
manufactured for on-road consumption. In general, the new diesel fuel standards
will become effective on June 1, 2006. Based on our latest engineering
estimates, we expect to spend approximately $55 million in capital improvements
through 2007 to meet these new requirements. These expenditures, however, do not
include our Alaska refinery where we have limited demand for low sulfur diesel
which presently does not justify the capital investment. We expect to meet this
demand from other sources.

We expect to spend approximately $44 million in additional capital
improvements through 2006 to comply with the Refinery MACT II regulations
promulgated in April 2002. The Refinery MACT II regulations will require new
emission controls at certain processing units at several of our refineries. We
are currently evaluating a selection of control technologies to assure
operations flexibility and compatibility with long-term air emission reduction
goals.

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To meet California's CARB III gasoline requirements, including the
mandatory phase out of using the oxygenate known as MTBE, we expect to spend
approximately $17 million in 2003 at our California refinery. The project should
be completed in the first quarter of 2003.

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

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 owned properties. At December 31, 2002, our accruals
for environmental expenses totaled approximately $40 million. Our accruals for
environmental expenses include retained liabilities for prior owned or operated
properties, refining, pipeline, terminal and marine services operations and
retail service stations. Based on currently available information, including the
participation of other parties or former owners in remediation actions, we
believe these accruals are adequate.

In connection with the 2001 acquisition of the North Dakota and Utah
refineries, we assumed the sellers' obligations and liabilities under a consent
decree among the United States, BP Exploration and Oil Co., Amoco Oil Company
and Atlantic Richfield Company. BP entered into this consent decree for both the
North Dakota and Utah refineries for various alleged violations. As the new
owner of these refineries, we are required to address issues including leak
detection and repair, flaring protection and sulfur recovery unit optimization.
We currently estimate that we will spend an aggregate of $7 million to comply
with this consent decree. In addition, we have agreed to indemnify the sellers
for all losses of any kind incurred in connection with the consent decree.

In connection with the 2002 acquisition of the California refinery, subject
to certain conditions, we assumed the seller's obligations pursuant to its
settlement efforts with the Environmental Protection Agency concerning the
Section 114 refinery enforcement initiative under the Clean Air Act, except for
any potential

48

monetary penalties, which the seller retains. We believe these obligations will
not have a material impact on our financial position.

Based on latest estimates, we will need to expend additional capital at the
California refinery for reconfiguring and replacing above ground storage tank
systems and upgrading piping within the refinery. These costs are currently
estimated at approximately $130 million through 2007 and an additional estimated
$90 million through 2011. Both of these cost estimates are subject to further
review and analysis.

In addition to these capital expenditures, the California refinery will
require expenditures related to remediation. Soil and groundwater conditions at
the California refinery may require substantial expenditures over time. Our
current estimate of costs to address environmental liabilities including soil
and groundwater conditions at the refinery in connection with various projects,
including those required pursuant to orders by the California Regional Water
Quality Control Board, is approximately $73 million, of which approximately $31
million is anticipated to be incurred through 2006 and the balance thereafter.
We believe that we will be entitled to indemnification for approximately $63
million of such costs, directly or indirectly, from former owners or operators
of the refinery (or their successors) under two separate indemnification
agreements. Additionally, if remediation expenses are incurred in excess of the
indemnification, we expect to receive coverage under one or both of the
environmental insurance policies discussed in Note D of Notes to Consolidated
Financial Statements in Item 8.

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

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

PENSION FUNDING

For all eligible employees, we provide a qualified defined benefit
retirement plan with benefits based on years of service and compensation. Our
executive security plans also provide certain executive officers and other key
personnel with supplemental death or retirement benefits based on years of
service and compensation. We contributed $16 million in 2002 and expect to
contribute $19 million and $31 million in 2003 and 2004, respectively, to these
plans. While our long-term expected return on plan assets is 8.15%, our pension
plan assets experienced losses of $3 million in 2001 and $6 million in 2002. Our
expected contributions in 2003 and 2004 are affected by returns on plan assets,
employee demographics and other factors. See Note O of Notes to Consolidated
Financial Statements in Item 8 for further discussion.

CONVERSION OF PREFERRED STOCK

On July 1, 2001, our Premium Income Equity Securities automatically
converted into 10,350,000 shares of our common stock. This conversion eliminated
$12 million in annual preferred dividend requirements. The final quarterly cash
dividends were paid on July 2, 2001.

COMMON STOCK SHARE REPURCHASE PROGRAM

During 2000, we repurchased 1,627,400 shares of common stock for
approximately $15.5 million. In 2001, we repurchased an additional 304,000
shares of our common stock for $3.5 million, bringing the cumulative shares
repurchased under the program to 1,931,400. In 2002, we did not repurchase any
shares of our common stock. Under the revised terms of our senior secured credit
facility, we are not permitted to repurchase shares of our common stock through
December 31, 2003. Beginning January 1, 2004, the terms of our senior secured
credit facility allow for the repurchase of shares of our common stock, not to
exceed $15 million in any year.

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ACCOUNTING STANDARDS

CRITICAL ACCOUNTING POLICIES

Our accounting policies are described in Note B 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. We had 17.8 million barrels of crude oil and refined product
inventories at December 31, 2002 with an average cost of $22.90 per barrel. If
refined product prices decline below the average cost, then we will be required
to write down the value of our inventories in future periods.

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

Goodwill -- As of December 31, 2002, we had $91 million of goodwill. SFAS
No. 142, "Goodwill and Other Intangible Assets" requires that goodwill is not to
be amortized but is to be tested for impairment annually or more frequently when
indicators of impairment exist. We completed the required annual test for
goodwill impairment during the fourth quarter of 2002 and recognized a loss of
$1.2 million to reduce the carrying value of goodwill in our Retail segment. The
impairment test is highly susceptible to change from period to period as it
requires management to make cash flow assumptions including, among other things,
future margins, volumes, operating costs and discount rates. Management's
assumptions regarding future margins and volumes require significant judgment as
actual margins and volumes have fluctuated in the past and are expected to
continue to do so. The impairment test performed during the fourth quarter of
2002 assumed that future margins in our geographic areas will be at five-year
average levels. We are exposed to the possibility that changes in market
conditions could result in additional impairment charges in the future.

Business Combinations -- In 2002 and 2001, we had significant acquisitions
which were accounted for as purchases, whereby the purchase prices were
allocated to the assets acquired and the liabilities assumed based upon their
respective fair market values at the dates of acquisition. Significant
management judgment is required in determining the value of these assets and
liabilities (including employee benefits, an MTBE lease obligation and
environmental matters). We engaged outside specialists to assist us in
determining the fair values of property, plant and equipment and intangible
assets. As of December 31, 2002, we had $151 million of acquired intangible
assets. The valuation of these intangible assets required us to use our judgment
including estimates with respect to their useful lives. We review acquired
intangible assets for impairment whenever events or changes in circumstances
indicate that the carrying amount of the assets may not be recoverable. The
assessment of impairment is based on the estimated undiscounted future cash
flows from operating activities compared with the carrying value of the assets.
The actual amount of impairment loss, if any, to be recorded is equal to the
amount by which the asset's carrying value exceeds its fair value. Estimates

50

of future discounted cash flows and fair value of assets require subjective
assumptions with regard to future operating results and actual results could
differ from those estimates.

Deferred Maintenance Costs -- We record the cost of major scheduled
refinery turnarounds, long-lived catalysts used in refinery process units and
periodic maintenance on ships, tugs and barges ("drydocking") as deferred
charges. 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 these major maintenance
activities to be expensed as costs are incurred. If this proposed Statement of
Position is adopted in its current form, we would be required to write off the
balance of our deferred maintenance costs which totaled $62 million at December
31, 2002 and expense future costs as incurred (see "Refinery Turnaround and
Other Major Maintenance" on page 46).

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.

Income Taxes -- As part of the process of preparing consolidated financial
statements, we must assess the likelihood that our deferred income tax assets
will be recovered through future taxable income. To the extent we believe that
recovery is not likely, a valuation allowance must be established. Significant
management judgment is required in determining any valuation allowance recorded
against net deferred income tax assets. Based on our estimates of taxable income
in each jurisdiction in which we operate and the period over which deferred
income tax assets will be recoverable, we have not recorded a valuation
allowance as of December 31, 2002. In the event that actual results differ from
these estimates or we make adjustments to these estimates in future periods, we
may need to establish a valuation allowance. As of December 31, 2002, deferred
tax assets included net operating loss carryforwards and alternative minimum tax
credits totaling $91 million.

Pension and Other Postretirement Benefits -- Accounting for pensions and
other postretirement benefits involves several assumptions and estimates
including discount rates, health care cost trends, inflation, retirement rates
and mortality rates. We must also assume a rate of return on the plan assets in
order to estimate our obligations under the plans. Due to the nature of these
calculations, we engage an outside actuarial firm to assist with the
determination of these estimates and the calculation of certain employee benefit
expenses. While we believe that the assumptions used are appropriate,
significant differences in the actual experience or significant changes in
assumptions would affect pension and other postretirement benefits costs and
obligations. See Note O of Notes to Consolidated Financial Statements in Item 8
for more information regarding costs and assumptions.

NEW ACCOUNTING STANDARDS AND DISCLOSURES

SFAS No. 143 -- On January 1, 2003, we adopted SFAS No. 143, "Accounting
for Asset Retirement Obligations", which addresses financial accounting and
reporting for legal obligations associated with the retirement of long-lived
assets. We have identified asset retirement obligations that are within the
scope of the standard, including obligations imposed by certain state laws
pertaining to closure and/or removal of storage tanks, and contractual removal
obligations included in certain lease and right-of-way agreements associated
with our retail, pipeline and terminal operations. We have estimated the fair
value of our asset retirement obligations, based in part on the terms of the
agreements and the probabilities associated with the eventual sale or other
disposition of these assets. We cannot currently make reasonable estimates of
the fair values of some retirement obligations, principally those associated
with refineries, certain pipeline rights-of-way and certain terminals, because
the related assets have indeterminate useful lives which preclude development of

51

assumptions about the potential timing of settlement dates. Such obligations
will be recognized in the period in which sufficient information exists to
estimate a range of potential settlement dates. The present value of obligations
was accrued to the extent that settlement dates could be estimated, primarily
for assets on leased sites. The effect of adopting this accounting standard at
January 1, 2003, was to increase property, plant and equipment by approximately
$0.6 million, net of accumulated amortization, increase noncurrent other
liabilities by approximately $1.7 million, and reduce net earnings for a
one-time cumulative effect charge of approximately $0.7 million, net of deferred
income taxes. The annual increase in 2003 depreciation and operating expense is
estimated to be less than $1 million.

SFAS No. 144 -- Effective January 1, 2002, we adopted 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. The provisions of SFAS No.
144, which were applied as related to our divestitures in 2002, did not have a
significant impact on our consolidated financial condition or results of
operations.

SFAS No. 145 -- In April 2002, the Financial Accounting Standards Board
("FASB") issued SFAS No. 145, "Rescission of FASB Statements No. 4, 44, and 64,
Amendment of FASB Statement No. 13 and Technical Corrections". SFAS No. 145
clarifies guidance related to the reporting of gains and losses from
extinguishment of debt and resolves inconsistencies related to the required
accounting treatment of certain lease modifications. SFAS No. 145 also amends
other existing pronouncements to make various technical corrections, clarify
meanings or describe their applicability under changed conditions. The
provisions relating to the reporting of gains and losses from extinguishment of
debt become effective for us beginning January 1, 2003. All other provisions of
this standard became effective for us as of May 15, 2002 and did not have a
significant impact on our consolidated financial condition or results of
operations.

SFAS No. 146 -- In June 2002, the FASB issued SFAS No. 146, "Accounting for
Costs Associated with Exit or Disposal Activities". SFAS No. 146 requires costs
associated with exit or disposal activities to be recognized when they are
incurred rather than at the date of a commitment to an exit or disposal plan. We
early adopted SFAS No. 146 during the 2002 third quarter and the adoption did
not have a material impact on our consolidated financial condition or results of
operations.

SFAS No. 148 -- In December 2002, the FASB issued SFAS No. 148, "Accounting
for Stock-Based Compensation -- Transition and Disclosure -- an amendment of
FASB Statement No. 123", to provide alternative methods of transition for a
voluntary change to the fair value based method of accounting for stock-based
employee compensation. In addition, SFAS No. 148 amends the disclosure
requirements of SFAS No. 123 to require prominent disclosures in both annual and
interim financial statements about the method of accounting for stock-based
employee compensation and the effect of the method used on reported results. We
have not adopted the SFAS No. 123 fair value method of accounting for
stock-based employee compensation (see Note P to Consolidated Financial
Statements in Item 8).

EITF Issue No. 02-3 -- In October 2002, the Emerging Issues Task Force
("EITF") of the FASB reached a consensus that gains and losses on derivative
instruments subject to SFAS No. 133 should be shown net in the income statement
whether or not settled physically if the derivative instruments are used for
trading purposes. We have a limited number of petroleum purchases and sales that
are within the scope of SFAS No. 133 and are used for trading purposes. Such
transactions are generally settled with physical product or crude oil
deliveries. We adopted the provisions of this EITF issue in the fourth quarter
of 2002, and all comparative financial information has been reclassified to
conform to the current presentation. There was no change in operating income
(loss), net earnings (loss), cash flow or net earnings (loss) per share for any
period as a result of adopting this EITF issue. However, revenues and cost of
sales and operating expenses were reduced by equal and offsetting amounts. For
the years ended December 31, 2002, 2001 and 2000, revenues and costs of sales
and operating expenses were reduced by approximately $105 million, $38 million

52

and $38 million, respectively, as a result of presenting these activities net in
the Statements of Consolidated Operations. The margins on these transactions
were not significant for these periods.

Proposed Statement of Position -- In 2001, the American Institute of
Certified Public Accountants ("AICPA") issued an Exposure Draft for a Proposed
Statement of Position, "Accounting for Certain Costs and Activities Related to
Property, Plant and Equipment". The proposed Statement of Position ("SOP"), as
originally written, would require major maintenance activities, such as refinery
turnarounds, to be expensed as costs are incurred. In the 2002 fourth quarter,
the AICPA announced it would be transitioning this project to the FASB, although
the AICPA may retain and address certain components of the proposed SOP. The
FASB and the AICPA have not determined which components, if any, will be
retained by the AICPA for potential issuance in a future SOP. In addition, the
FASB has not set a timetable for addressing the issues raised by the proposed
SOP. If this proposed SOP is adopted as originally written, we would be required
to write off the unamortized carrying value of deferred major maintenance costs
and expense future costs as incurred. At December 31, 2002, deferred major
maintenance costs totaled $62 million.

FIN 45 -- In November 2002, the FASB issued FASB Interpretation No. 45,
"Guarantor's Accounting and Disclosure Requirements for Guarantees, Including
Indirect Guarantees of Indebtedness of Others" ("FIN 45"). FIN 45 elaborates on
the disclosures to be made by a guarantor in its interim and annual financial
statements about its obligations under certain guarantees that it has issued. It
also clarifies that a guarantor is required to recognize, at the inception of a
guarantee, a liability for the fair value of the obligation undertaken in
issuing the guarantee. The initial recognition and initial measurement
provisions of FIN 45 are applicable on a prospective basis to guarantees issued
or modified after December 31, 2002. The disclosure requirements in FIN 45 are
effective for financial statements of interim and annual periods ending after
December 15, 2002. The adoption of this statement did not have a significant
impact on our consolidated financial statements.

FIN 46 -- In January 2003, the FASB issued Interpretation No. 46,
"Consolidation of Variable Interest Entities" ("FIN 46"), which requires the
consolidation of variable interest entities, as defined. FIN 46 applies
immediately to variable interest entities created after January 31, 2003. The
consolidation requirements apply to older entities in the first fiscal year or
interim period beginning after June 15, 2003. Certain of the disclosure
requirements apply in all financial statements issued after January 31, 2003,
regardless of when the variable interest entity was established. We believe that
FIN 46 will not require consolidation of any variable interest entities.

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

FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K includes forward-looking statements within
the meaning of the Private Securities Litigation Reform Act of 1995. These
statements are included throughout this Form 10-K, including in the sections
entitled "Business" and "Risk Factors", and relate to, among other things,
projections of refining margins, revenues, earnings, earnings per share, cash
flows, capital expenditures, working capital or other financial items,
throughput, expectations regarding the acquisitions, discussions of estimated
future revenue enhancements, potential dispositions 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 our results of our operations and whether the forward-looking
statements ultimately prove to be correct. Accordingly, these

53

forward-looking statements are qualified in their entirety by reference to the
factors described in "Risk Factors" contained in Part I, and elsewhere, in this
Annual Report on Form 10-K.

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

- changes in general economic conditions;

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

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

- changes in our cash flow from operations, liquidity and capital
requirements;

- our ability to achieve our debt reduction goal;

- our ability to meet debt covenants;

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

- reduced availability of trade credit;

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

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

- political developments in foreign countries;

- changes in our inventory levels and carrying costs;

- seasonal variations in demand for refined products;

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

- changes in fuel and utility costs for our facilities;

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

- execution of planned capital projects;

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

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

- actions of customers and competitors;

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

- earthquakes or other natural disasters affecting operations.

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

54

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, the majority of our crude oil supply
contracts are short-term in nature with market-responsive pricing provisions.
Our financial results can be affected significantly by price level changes
during the period between purchasing refinery feedstocks and selling the
manufactured refined products from such feedstocks. We also purchase refined
products manufactured by others for resale to our customers. Our financial
results can be affected significantly by price level changes during the periods
between purchasing and selling such products. Assuming all other factors
remained constant, a $1.00 per barrel change in average gross refining margins
based on our 2002 average throughput of 435 thousand bpd would change annual
pretax segment operating income and cash flows from operations by approximately
$159 million.

We maintain inventories of crude oil, intermediate products and refined
products, the values of which are subject to fluctuations in market prices. In
our Refining and Retail segments, our inventories of refinery feedstocks and
refined products totaled 17.8 million barrels and 17.2 million barrels at
December 31, 2002 and 2001, respectively. The average cost of our refinery
feedstocks and refined products at December 31, 2002 was approximately $23 per
barrel. If market prices for refined products decline to a level below the
average cost of these inventories, we may be required to write down the carrying
value of this inventory.

We periodically enter into derivative type arrangements on a limited basis,
as part of our programs to acquire refinery feedstocks at reasonable costs and
to manage margins on certain refined product sales. 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, 2002, we had open
future positions of 24,000 barrels of crude oil which expire during the first
half of 2003. Recording the fair value of these positions resulted in a
mark-to-market gain of less than $0.1 million in 2002. 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, 2002, we had $918 million of outstanding floating-rate debt
under the senior secured credit facility and $1.059 billion of fixed-rate debt.
The weighted average interest rate on the floating-rate debt was 8.1% at
December 31, 2002. The impact on annual cash flow of a 10% change in the
floating-rate for our senior secured credit facility (81 basis points) would be
approximately $7 million.

The fair market value of our fixed-rate debt at December 31, 2002 was
approximately $326 million less than its book value of $1.059 billion, based on
transactions and bid quotes for our senior subordinated notes. The fair market
value of our variable-rate debt at December 31, 2002 was approximately $73
million less than its book value of $918 million.

55

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, 2002
and 2001, and the related statements of consolidated operations, stockholders'
equity and cash flows for each of the three years in the period ended December
31, 2002. 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, 2002 and 2001, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2002 in conformity with accounting principles generally accepted in
the United States of America.

/s/ DELOITTE & TOUCHE LLP

San Antonio, Texas
February 14, 2003

56

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.

57

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.

58

TESORO PETROLEUM CORPORATION

STATEMENTS OF CONSOLIDATED STOCKHOLDERS' EQUITY
(IN MILLIONS)

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

59

TESORO PETROLEUM CORPORATION

STATEMENTS OF CONSOLIDATED CASH FLOWS
(IN MILLIONS)

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

60

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE A -- NATURE OF OPERATIONS AND BUSINESS CONDITIONS

Tesoro Petroleum Corporation ("Tesoro" or the "Company") was incorporated
in Delaware in 1968 and is an independent refiner and marketer of petroleum
products. Tesoro owns and operates six petroleum refineries in the western and
mid-continental United States with a combined rated crude oil throughput
capacity of 558,000 barrels per day ("bpd") and sells refined products to a wide
variety of customers primarily in the western and mid-continental United States.
Tesoro markets products to wholesale and retail customers, as well as commercial
end-users. Tesoro's retail business includes a network of 593 branded retail
stations operated by the Company or independent dealers.

The Company's earnings, cash flows from operations and liquidity depend
upon many factors, including producing and selling refined products at margins
above fixed and variable expenses. The prices of crude oil and refined products
have fluctuated substantially in the Company's markets. The Company's operating
results can be significantly influenced by the timing of changes in crude oil
costs and how quickly refined product prices adjust to reflect these changes.
These price fluctuations depend on numerous factors beyond the Company's
control, including the demand for crude oil, gasoline and other refined
products, which is subject to, among other things, changes in the economy and
the level of foreign and domestic production of crude oil and refined products,
worldwide political conditions, threatened or actual terrorist incidents or acts
of war, availability of crude oil and refined product imports, the
infrastructure to transport crude oil and refined products, weather conditions,
earthquakes and other natural disasters, seasonal variation, government
regulations and local factors, including market conditions and the level of
operations of other refineries in the Company's markets. As a result of these
factors, margin fluctuations during any reporting period can have a significant
impact on the Company's results of operations, cash flows, liquidity and
financial position.

During 2002, the refining industry in the Company's market areas
experienced the lowest refined product margins since 1998 and margins that were
significantly below the Company's five-year average (from January 1, 1998
through December 31, 2002). The Company determines the "five-year average" by
comparing gasoline, diesel and jet fuel prices to crude oil prices in the
Company's market areas, with volumes weighted according to the Company's typical
refinery yields. The Company experienced net losses in each of the 2002 quarters
resulting from weak industry margins and additional interest and financing costs
related to the Company's acquisitions of the California refinery in May 2002 and
the Mid-Continent refineries in September 2001. In connection with these
acquisitions, the Company's total debt increased by approximately $1.7 billion
from June 30, 2001 to June 30, 2002. In addition, the ratings of the Company's
senior secured credit facility and senior subordinated notes were downgraded.
The Company has also experienced a tightening of the trade credit it receives,
which has required it to issue an increased amount of letters of credit and make
early payments and prepayments to certain suppliers.

Despite the weak margin environment, the Company generated cash flows from
operations of $58 million in 2002 and reduced term debt by $140 million
(including a $16.3 million prepayment in January 2003) following the acquisition
of the California refinery by selling over $200 million in assets, eliminating
or deferring capital expenditures, reducing expenses, achieving operating
synergies and reducing inventories. As of December 31, 2002, the Company had
$110 million in cash, no borrowings under the revolving credit facility and,
with $60 million in letters of credit outstanding, had total unused credit
available of $165 million and a total debt to capitalization ratio of 69%.

Management believes the industry conditions that led to low margins in 2002
have improved, and if this improvement continues and margins remain at or near
the five-year average for the remainder of 2003, management believes the Company
will comply with the financial covenants of the Company's senior secured credit
facility in 2003. Industry margins in 2003 in most of the Company's market areas
have averaged above the Company's five-year average (as described above).

61

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

However, if industry margins in the Company's market areas drop below the
five-year average for any substantial period of time or if the Company finds it
necessary to borrow the remaining available amounts under its senior secured
credit facility for working capital purposes, including to support trade credit
requirements, the Company will likely need to amend its senior secured credit
facility because it may not meet certain financial covenant tests during the
remainder of 2003. In addition, the Company's credit ratings may be further
reduced and its trade credit may be further tightened. Management believes that
the Company will be able to amend its senior secured credit facility or obtain
covenant waivers if necessary; however, management cannot provide any assurances
that the Company will be able to obtain such an amendment or waiver on terms and
conditions acceptable to the Company or at all.

To better enable the Company to withstand a low margin environment similar
to that experienced in 2002, management's 2003 goals are to further reduce
ongoing cash expenses and eliminate or defer capital expenditures. Assuming
these initiatives are realized and, if necessary, the Company is able to amend
its senior secured credit facility or obtain covenant waivers, management
believes cash flow from operations, amounts available under the Company's senior
secured credit facility and available cash will be adequate to meet the
Company's anticipated requirements in 2003 for working capital, capital
expenditures and scheduled payments of principal and interest on its
indebtedness.

In addition, management is pursuing discussions regarding possible
financing alternatives to replace the Company's senior secured credit facility.
If the Company pursues such alternatives, management intends to seek a debt
structure designed (1) to increase the Company's capacity to borrow for working
capital needs, (2) to allow the Company to issue letters of credit instead of
making early payments and prepayments to certain suppliers and apply the funds
that would otherwise have been used for those payments and prepayments to repay
debt and (3) to substantially modify the financial covenants the Company has
under its existing senior secured credit facility. However, the Company cannot
provide any assurances that such financing alternatives will be available on
terms and conditions acceptable to management or at all.

See Notes M and O for information regarding deferred financing costs
related to the senior secured credit facility and charges for enhanced
retirement plan benefits.

NOTE B -- SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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 entities in which Tesoro has the ability to exercise
significant influence, but not control, are accounted for by the equity method,
while all other investments are carried at cost. These investments are not
material, either individually or in the aggregate, to Tesoro's financial
position, results of operations or cash flows. See Note Q for information
related to a 50% limited partnership interest which is accounted for under the
equity method.

Basis of Presentation

Certain previously reported amounts have been reclassified to conform to
the 2002 presentation. The Company has reclassified the amortization of major
maintenance refinery turnaround, catalyst and drydocking costs from costs of
sales and operating expenses to depreciation and amortization in the Statements
of Consolidated Operations (see "Other Assets" below for the amounts that were
reclassified). The Company also has reclassified revenues and costs of sales in
the Statements of Consolidated Operations to report certain crude oil and
product purchases and resales on a net basis (see "New Accounting Standards and
Disclosures -- EITF Issue No. 02-3" below for the amounts that were
reclassified).

62

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Separate financial statements of Tesoro's subsidiary guarantors are not
included herein because these subsidiary guarantors are jointly and severally
liable on the Company's outstanding senior subordinated notes and the net
assets, results of operations and equity of the subsidiary guarantors are
substantially equivalent to the net assets, results of operations and equity of
Tesoro on a consolidated basis.

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. At December 31, 2002, cash
and cash equivalents included $16.3 million which was used to prepay term loans
in January 2003 as required by the Company's senior secured credit facility (see
Note G).

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 debt and other obligations may vary from the
Company's estimates of the fair value of such items. At December 31, 2002, the
fair market value of the Company's fixed-rate debt was estimated by management
to be approximately $326 million less than its book value of $1.059 billion. At
December 31, 2002, the fair market value of the Company's variable-rate debt was
estimated by management to be approximately $73 million less than its book value
of $918 million.

Inventories

Inventories are stated at the lower of cost or market. The last-in,
first-out ("LIFO") is the primary method used to determine the cost of
inventories of crude oil and refined products in the Refining and Retail
segments. The cost of certain inventories of fuel, oxygenates and by-products
are determined using 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, 5 to 16 years for terminals, 13 to 16 years for retail
stations, 9 to 29 years for transportation assets, and 3 to 14 years for
corporate 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 $168.6 million, $57.9 million and
$33.4 million in 2002,

63

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

2001 and 2000, respectively, of which $2.5 million, $5.1 million and $0.7
million was capitalized during 2002, 2001 and 2000, 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.

Goodwill and Acquired Intangibles

Goodwill represents the excess of cost (purchase price) over the fair value
of net assets acquired. In accordance with Statement of Financial Accounting
Standards ("SFAS") No. 142, "Goodwill and Other Intangible Assets", the Company
ceased amortizing goodwill on January 1, 2002. Goodwill amortization amounted to
$2.7 million in each of 2001 and 2000 and is included in depreciation and
amortization in the Statements of Consolidated Operations. The following table
reflects reported net earnings and earnings per share in 2001 and 2000, adjusted
to exclude goodwill amortization (in millions except per share amounts):

Acquired intangibles consist primarily of air emissions credits, permits
and plans, and customer agreements and contracts which are recorded at fair
value as of the date acquired in a business combination. Amortization is
computed on a straight-line basis over estimated useful lives of 3 to 28 years.

Amortization of acquired intangibles is included in depreciation and
amortization in the Statements of Consolidated Operations.

64

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Other Assets

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 depreciation and amortization in the Statements of Consolidated
Operations and amounted to $27.2 million, $22.5 million and $23.8 million in
2002, 2001 and 2000, respectively.

Debt issuance costs related to the Company's senior secured credit facility
and its subordinated notes are deferred and amortized over the estimated terms
of each instrument. The amortization is included in interest and financing costs
in the Statements of Consolidated Operations. The Company evaluates the carrying
value of debt issuance costs when modifications are made to the related debt
instruments (see Note M).

Impairment of Long-Lived Assets

Property, plant and equipment and other long-lived assets including
acquired 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. Factors that would indicate potential impairment
include, but are not limited to, significant decreases in the market value of a
long-lived asset, a significant change in the long-lived asset's physical
condition and operating or cash flow losses associated with the use of the
long-lived asset. Goodwill balances are reviewed for impairment annually or more
frequently whenever events or changes in business circumstances indicate the
carrying values of the assets may not be recoverable.

Revenue Recognition

The Company recognizes revenues from product sales upon delivery to
customers and when all significant obligations have been satisfied. Certain
crude oil and product purchases and resales used for trading purposes are
included in revenues on a net basis. Transportation fees charged to customers
are included in revenues and the related costs are included in costs of sales in
the Statements of Consolidated Operations. In the Company's Retail segment,
Federal excise and state motor fuel taxes collected from customers and remitted
to governmental agencies are reported in revenues and in costs of sales. These
taxes, primarily related to sales of gasoline and diesel fuel, totaled $167
million, $81 million and $43 million in 2002, 2001 and 2000, respectively. In
the Company's Refining segment, excise taxes on sales are not included in
revenues and costs of sales.

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. A valuation allowance is provided for deferred tax assets if
it is more likely than not those items will either expire before the Company is
able to realize their benefit, or that future deductibility is uncertain.

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TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Stock-Based Compensation

The Company accounts for stock-based compensation using the intrinsic value
method prescribed in Accounting Principles Board ("APB") Opinion No. 25,
"Accounting for Stock Issued to Employees", and related interpretations.
Accordingly, compensation cost for stock options is measured as the excess, if
any, of the quoted market price of the Company's Common Stock at the date of
grant over the amount an employee must pay to acquire the stock. The following
table represents the effect on net earnings and earnings per share if the
Company had applied a fair value based method and recognition provisions of SFAS
No. 123, "Accounting for Stock-Based Compensation", for the grant of stock
options (in millions except per share amounts):

For purposes of the pro forma disclosures above, the estimated fair value
of stock-based compensation plans is amortized to expense primarily over the
vesting period. The fair value of each option grant was estimated on the date of
grant using the Black-Scholes option-pricing model with the following weighted-
average assumptions for 2002, 2001 and 2000, respectively: expected volatility
of 88%, 43% and 57%; risk free interest rates of 4.2%, 4.9% and 5.8%; expected
lives of seven years; and no dividend yields. The estimated average fair value
per share of options granted during 2002, 2001 and 2000 were $4.27, $6.72 and
$6.21, respectively. See Note P for further information on the Company's
stock-based employee compensation.

Derivative Instruments

The Company accounts for derivative instruments in accordance with SFAS No.
133, "Accounting for Derivative Instruments and Hedging Activities", as amended
by SFAS No. 138 and interpreted by the Derivatives Implementation Group. The
Company believes that substantially all of its supply and marketing agreements
and other commercial contracts are normal purchases and sales and that pricing
provisions in these agreements are not embedded derivatives. However, 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. These non-hedging
derivatives 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, 2002, the Company had open
future positions for 24,000 barrels of crude oil which expire during the first
half of 2003. The fair value of these positions resulted in a mark-to-market
gain of $81,000 in 2002. During 2002 and 2001, the Company did not have any
derivative instruments that were designated and accounted for as hedges.

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TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

New Accounting Standards and Disclosures

SFAS No. 143

On January 1, 2003, the Company adopted SFAS No. 143, "Accounting for Asset
Retirement Obligations", which addresses financial accounting and reporting for
legal obligations associated with the retirement of long-lived assets. The
Company has identified asset retirement obligations that are within the scope of
the standard, including obligations imposed by certain state laws pertaining to
closure and/or removal of storage tanks, and contractual removal obligations
included in certain lease and right-of-way agreements associated with the
Company's retail, pipeline and terminal operations. The Company has estimated
the fair value of its asset retirement obligations, based in part on the terms
of the agreements and the probabilities associated with the eventual sale or
other disposition of these assets. The Company cannot currently make reasonable
estimates of the fair values of some retirement obligations, principally those
associated with refineries, certain pipeline rights-of-way and certain
terminals, because the related assets have indeterminate useful lives which
preclude development of assumptions about the potential timing of settlement
dates. Such obligations will be recognized in the period in which sufficient
information exists to estimate a range of potential settlement dates. The
present value of obligations was accrued to the extent that settlement dates
could be estimated, primarily for assets on leased sites. The effect of adopting
this accounting standard at January 1, 2003, was to increase property, plant and
equipment by approximately $0.6 million, net of accumulated amortization,
increase noncurrent other liabilities by approximately $1.7 million, and reduce
net earnings for a one-time cumulative effect charge of approximately $0.7
million, net of deferred income taxes. The estimated annual increase in 2003
depreciation and operating expense is estimated to be less than $1 million.

SFAS No. 144

Effective January 1, 2002, the Company adopted 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 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 provisions of SFAS No.
144, which were applied to the Company's divestitures in 2002, did not have a
significant impact on the Company's consolidated financial condition or results
of operations (see Note E).

SFAS No. 145

In April 2002, the Financial Accounting Standards Board ("FASB") issued
SFAS No. 145, "Rescission of FASB Statements No. 4, 44, and 64, Amendment of
FASB Statement No. 13 and Technical Corrections". SFAS No. 145 clarifies
guidance related to the reporting of gains and losses from extinguishment of
debt and resolves inconsistencies related to the required accounting treatment
of certain lease modifications. SFAS No. 145 also amends other existing
pronouncements to make various technical corrections, clarify meanings or
describe their applicability under changed conditions. The provisions relating
to the reporting of gains and losses from extinguishment of debt become
effective for the Company beginning January 1, 2003. All other provisions of
this standard became effective for the Company as of May 15, 2002 and did not
have a significant impact on the Company's consolidated financial condition or
results of operations.

SFAS No. 146

In June 2002, the FASB issued SFAS No. 146, "Accounting for Costs
Associated with Exit or Disposal Activities". SFAS No. 146 requires costs
associated with exit or disposal activities to be recognized when they are
incurred rather than at the date of a commitment to an exit or disposal plan.
The Company early adopted SFAS No. 146 during the 2002 third quarter, which did
not have a material impact on the Company's consolidated financial condition or
results of operations.

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TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

SFAS No. 148

In December 2002, the FASB issued SFAS No. 148, "Accounting for Stock-Based
Compensation -- Transition and Disclosure -- an amendment of FASB Statement No.
123", to provide alternative methods of transition for a voluntary change to the
fair value based method of accounting for stock-based employee compensation. In
addition, SFAS No. 148 amends the disclosure requirements of SFAS No. 123 to
require prominent disclosures in both annual and interim financial statements
about the method of accounting for stock-based employee compensation and the
effect of the method used on reported results. The Company has not adopted the
fair value method of accounting for stock-based employee compensation under SFAS
No. 123. See "Stock-Based Compensation" discussed above and Note P.

EITF Issue No. 02-3

In October 2002, the Emerging Issues Task Force ("EITF") of the FASB
reached a consensus that gains and losses on derivative instruments subject to
SFAS No. 133 should be shown net in the income statement whether or not settled
physically if the derivative instruments are used for trading purposes. The
Company has a limited number of petroleum purchases and sales that are within
the scope of SFAS No. 133 and are used for trading purposes. Such transactions
are generally settled with physical product or crude oil deliveries. The Company
adopted the provisions of this EITF issue in the fourth quarter of 2002, and all
comparative financial information has been reclassified to conform to the
current presentation. There was no change in the Company's results of
operations, cash flows or financial position for any period as a result of
adopting this EITF issue. However, revenues and cost of sales and operating
expenses were reduced by equal and offsetting amounts. For the years ended
December 31, 2002, 2001 and 2000, revenues and costs of sales and operating
expenses were reduced by approximately $105.5 million, $37.9 million and $37.6
million, respectively, as a result of presenting these activities net in the
Statements of Consolidated Operations. The margins on these transactions were
not significant for these periods.

Proposed Statement of Position

In 2001, the American Institute of Certified Public Accountants ("AICPA")
issued an Exposure Draft for a Proposed Statement of Position, "Accounting for
Certain Costs and Activities Related to Property, Plant and Equipment". The
proposed Statement of Position ("SOP"), as originally written, would require
major maintenance activities, such as refinery turnarounds, to be expensed as
costs are incurred. In the 2002 fourth quarter, the AICPA announced it would be
transitioning this project to the FASB, although the AICPA may retain and
address certain components of the proposed SOP. The FASB and the AICPA have not
determined which components, if any, will be retained by the AICPA for potential
issuance in a future SOP. In addition, the FASB has not set a timetable for
addressing the issues raised by the proposed SOP. If this proposed SOP is
adopted as originally written, the Company would be required to write off the
unamortized carrying value of deferred major maintenance costs and to expense
future costs as incurred. At December 31, 2002, deferred major maintenance
costs, which are included in noncurrent other assets -- other in the
Consolidated Balance Sheets, totaled $62.1 million.

FIN 45

In November 2002, the FASB issued Interpretation No. 45, "Guarantor's
Accounting and Disclosure Requirements for Guarantees, Including Indirect
Guarantees of Indebtedness of Others" ("FIN 45"). FIN 45 elaborates on the
disclosures to be made by a guarantor in its interim and annual financial
statements about its obligations under certain guarantees that it has issued. It
also clarifies that a guarantor is required to recognize, at the inception of a
guarantee, a liability for the fair value of the obligation undertaken in
issuing the guarantee. The initial recognition and initial measurement
provisions of FIN 45 are applicable on a prospective basis to guarantees issued
or modified after December 31, 2002. The disclosure requirements in

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TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

FIN 45 are effective for financial statements of interim and annual periods
ending after December 15, 2002. The adoption of FIN 45 did not have a
significant impact on the Company's consolidated financial statements.

FIN 46

In January 2003, the FASB issued Interpretation No. 46, "Consolidation of
Variable Interest Entities" ("FIN 46"), which requires the consolidation of
variable interest entities, as defined. FIN 46 applies immediately to variable
interest entities created after January 31, 2003. The consolidation requirements
apply to older entities in the first fiscal year or interim period beginning
after June 15, 2003. Certain of the disclosure requirements apply to all
financial statements issued after January 31, 2003, regardless of when the
variable interest entity was established. The Company believes that FIN 46 will
not result in the consolidation of any variable interest entities.

NOTE C -- EARNINGS (LOSS) PER SHARE

Basic earnings (loss) per share are determined by dividing net earnings
(loss) 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. The assumed conversion of common stock equivalents produced
anti-dilutive results for 2002 and was not included in the calculation of
diluted earnings per share. For 2001 and 2000, the effects of potentially
dilutive shares, principally the maximum shares which would have been issued
assuming conversion of Preferred Stock at the beginning of the period and stock
options, were considered in the dilutive calculation. The Preferred Stock was
converted into 10.35 million shares of Common Stock in July 2001. Earnings
(loss) per share calculations are presented below (in millions except per share
amounts):

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TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

NOTE D -- ACQUISITIONS

California Assets Acquisition

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

In connection with the acquisition of the California Assets, the Company
assumed certain related liabilities and obligations (including costs associated
with employee benefits, a lease obligation and environmental matters), subject
to specific levels of indemnification. As part of the preliminary purchase price
allocation, which remains subject to change, the Company has recorded
approximately $112 million related to these liabilities. These liabilities
include, subject to certain exceptions, certain of the seller's obligations,
liabilities, costs and expenses for environmental compliance matters relating to
the assets, including certain known and unknown obligations, liabilities, costs
and expenses arising or incurred prior to, on or after the closing date. See
Note Q for further information on environmental matters related to the
California Assets.

The Company also assumed and took 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. In addition, upon the acquisition of the California Assets, the Company
took assignment from the seller of two environmental insurance policies. The
policies provide $140 million of coverage in excess of a $50 million indemnity
covering certain environmental liabilities.

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TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The purchase price was allocated to the assets acquired and liabilities
assumed based upon their respective estimated fair market values at the date of
acquisition. The accompanying financial statements reflect the preliminary
purchase price allocation, which is subject to change pending completion of
independent appraisals and other evaluations. The accompanying financial
statements include the results of operations of the California Assets since the
date of acquisition. The preliminary purchase price allocation, including direct
costs incurred in the California Assets acquisition, is as follows (in
millions):

Inventories................................................. $150
Property, plant and equipment............................... 848
Acquired intangibles........................................ 88
Other assets................................................ 19
Accrued liabilities......................................... (20)
Other liabilities........................................... (92)
----
Total purchase price................................... $993
====

Property, plant and equipment includes amounts allocated to the 70 northern
California retail sites that approximated the cash proceeds the Company received
upon selling these sites in December 2002 (see Note E). The acquired intangibles
of $88 million consist primarily of air emissions credits and have a
weighted-average useful life of approximately 27 years. Other liabilities
include obligations for employee benefits, environmental costs and a lease
termination obligation. The lease termination obligation of $32 million reflects
the operating lease payments from 2004 to 2010 on an MTBE facility located at
the refinery. Current governmental regulations require that the use of MTBE be
phased out by the end of 2003. The Company expects to complete a project in the
first quarter of 2003 which will allow the Company to phase out MTBE by December
31, 2003 and cease operating the leased facility. The lease termination
obligation is classified as noncurrent because the Company anticipates that it
will continue making the lease payments through the life of the lease.

The following unaudited pro forma financial information for the years ended
December 31, 2002 and 2001 gives effect to the acquisition of the California
Assets and related financings, including (i) the March 2002 public offering of
23 million shares of common stock, (ii) additional borrowings under the senior
secured credit facility and (iii) the issuance of the 9 5/8% senior subordinated
notes due 2012 (see Notes G and H below), as if each had occurred at the
beginning of the periods presented. This pro forma information is based on
historical data (in millions except per share amounts) and the Company believes
it is not indicative of the results of future operations.

Mid-Continent Acquisition

On September 6, 2001, the Company acquired two refineries in North Dakota
and Utah and related storage, distribution and retail assets. The acquired
assets included a 60,000 bpd refinery in Mandan, North Dakota and a 55,000 bpd
refinery in Salt Lake City, Utah. The Company also acquired a product pipeline
extending from Mandan, North Dakota to Minneapolis, Minnesota and terminals in
Jamestown, North Dakota and Moorhead, Sauk Centre and Minneapolis/St. Paul,
Minnesota ("Product Pipeline System"). The

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TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

acquired assets also included related bulk storage facilities 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 ("Crude Oil Pipeline System") on November 1, 2001.
The Crude Oil Pipeline System is the primary crude supply carrier for the
Company's North Dakota refinery. The purchase of the Crude Oil Pipeline System,
Product 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 and to
diversify its earnings and geographic exposure. The Company paid $756 million in
cash (including $83 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 million.

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

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 financial statements include the results of operations of the
Mid-Continent Acquisition since the dates of acquisition. During 2002,
independent appraisals and other evaluations were completed and the Company
finalized the purchase price allocation resulting in a decrease of $2.9 million
in goodwill, an increase of $1.9 million in employee benefit obligations and an
increase of $4.9 million in deferred tax assets. No other significant
adjustments to the preliminary 2001 allocations were necessary.

In December 2002, the Company sold the Product Pipeline System for $100
million in cash (see Note E).

Retail

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 E -- DIVESTITURES

In June 2002, the Company announced a goal to reduce debt by the end of
2003. As part of this debt reduction, the Company set a goal to generate net
proceeds of $200 million through asset sales. Furthermore, the Company's senior
secured credit facility, as amended in September and December 2002, required the
Company to consummate one or more asset sales or equity offerings resulting in
the receipt of cumulative net proceeds of at least $200 million by March 31,
2003.

On December 26, 2002, the Company sold its product pipeline extending from
Mandan, North Dakota to Minneapolis, Minnesota and terminals in Jamestown, North
Dakota and Moorhead, Sauk Centre and Minneapolis/St. Paul, Minnesota for $100
million in cash. The Company's gain on the sale of these assets was immaterial.
The Company will continue to distribute products from its North Dakota refinery
through the product pipeline under a tariff arrangement with the new owner.

In December 2002, the Company sold 70 retail stations in northern
California for $66 million in cash, including inventories. The Company acquired
these stations in May 2002 as part of the California Assets

72

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

acquisition. The Company recognized a loss on the sale of $2.5 million. The
Company will continue to sell products to a majority of the stations under a
two-year unbranded supply agreement. The Company retained responsibility for all
environmental liabilities at the stations arising prior to the date of sale.

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

In total, the Company received net proceeds aggregating approximately $207
million from these and other miscellaneous sales in December 2002. Of these
proceeds, $87.5 million was used to prepay term loans in December 2002. An
additional $16.3 million, included in cash at December 31, 2002, was used to
prepay term loans in January 2003. See Note G for further information related to
the requirements of the senior secured credit facility and use of proceeds.

Initially, the Company also considered the sale of its marine services
operations and the Crude Oil Pipeline System. Given the limited divestiture
opportunities for the marine services operation, management plans to integrate
this business with the Company's wholesale marketing and terminal operations
during 2003. With respect to the Crude Oil Pipeline System, management has
explored alternatives, but is no longer pursuing a divestiture of this asset.

NOTE F -- OPERATING SEGMENTS

The Company's revenues are derived from two major operating segments: (i)
Refining and (ii) Retail. Management has identified these segments for managing
operations and investing activities. The Refining segment owns and operates six
petroleum refineries located in California, Washington, Hawaii, Alaska, North
Dakota and Utah. These refineries manufacture gasoline and gasoline blendstocks,
jet fuel, diesel fuel, residual fuel oils and other refined products. These
products, together with products purchased from third parties, are sold at
wholesale through terminal facilities and other locations, primarily in Alaska,
California, Nevada, Hawaii, Idaho, Minnesota, North Dakota, Utah, Oregon and
Washington. The Refining segment also sells petroleum products to unbranded
marketers and occasionally exports products to other markets in the Asia/
Pacific area. The Retail segment sells gasoline, diesel fuel and convenience
store items through Company-operated retail stations and branded jobber/dealers
in 18 western states from Minnesota to Alaska and Hawaii. Retail operates under
the Tesoro(R) and Mirastar(R) brands. The Company's Mirastar(R) brand has been
developed exclusively for use at Wal-Mart stores in an agreement covering 17
western states. The Company also markets and distributes petroleum products and
other supplies and provides services primarily to the marine and offshore
exploration and production industries operating in the Gulf of Mexico. These
operations, which are conducted through terminals along the Texas and Louisiana
Gulf Coast, are reported as "Other" in the tables below.

The operating segments follow the accounting policies used for the
Company's Consolidated Financial Statements as described in the summary of
significant policies in Note B. Management evaluates the performance of its
segments and allocates resources based primarily on segment operating income.
Segment operating income includes those revenues and expenses that are directly
attributable to management of the respective segment. Intersegment sales are
primarily from Refining to Retail made at prevailing market rates. Income taxes,
interest and financing costs, interest income, corporate general and
administrative expenses and loss on asset sales and impairment are not included
in determining segment operating income. Identifiable assets are those utilized
by the segment. Corporate assets are principally cash, income taxes receivable
and other assets that are not associated with a specific operating segment.

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TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Segment information as of and for each of the three years in the period
ended December 31, 2002 is as follows (in millions):

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

(a) Excludes asset acquisitions of $932 million in 2002 and $783 million in
2001 (see Note D).

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TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

NOTE G -- DEBT

Debt at December 31, 2002 and 2001 consisted of the following (in
millions):

Aggregate maturities of outstanding debt for each of the five years
following December 31, 2002 were as follows: 2003 -- $70.0 million;
2004 -- $53.8 million; 2005 -- $53.8 million; 2006 -- $65.0 million; and
2007 -- $683.8 million. Maturities in 2003 include $16.3 million in required
prepayments resulting from proceeds from assets sales (see Note E). Gross
borrowings and repayments under revolving credit lines and interim facilities
amounted to $624 million, $958 million and $866 million in 2002, 2001 and 2000,
respectively.

Senior Secured Credit Facility

On May 17, 2002, the Company amended and restated its senior secured credit
facility to increase the facility to $1.275 billion from $1.0 billion to
partially fund the acquisition of the California Assets. The terms and
conditions of this credit facility were subsequently amended on September 30,
2002 to reflect modified financial tests. The amendment also, among other
things, increased the amount of proceeds from asset sales or equity offerings
the Company must receive and limits capital expenditures. The credit facility
was further amended in December 2002 (as amended, the "Credit Facility"), giving
flexibility to the terms and the timing of the required proceeds from asset
sales or equity offerings. Under the revised terms of the Credit Facility, the
Company agreed to pay certain fees and to increase the interest rate on
borrowings.

The Credit Facility currently consists of a five-year $225 million
revolving credit facility (with a $150 million sublimit for letters of credit),
a five-year tranche A term loan and a six-year tranche B term loan. As of
December 31, 2002, the Company had no borrowings and $60 million in letters of
credit outstanding under the revolving credit facility, resulting in total
unused credit available of $165 million. In addition to the

75

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Credit Facility, the Company has a $12 million uncommitted letter of credit line
with a bank, under which no amounts were outstanding as of December 31, 2002.

The 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 and future active
domestic subsidiaries and 66% of the stock of the Company's current and future
foreign subsidiaries.

At December 31, 2002, interest rates were 6.77% on the tranche A term loan
and 8.5% on the tranche B term loan. Borrowings bear interest at either a base
rate (4.25% at December 31, 2002) or a eurodollar rate (1.77% at December 31,
2002), plus an applicable margin. From September 30, 2002 to March 31, 2004, the
applicable margins on the tranche A term loan and the revolving credit facility
will be 3% in the case of the base rate and 4% in the case of the eurodollar
rate and 3.5% in the case of the base rate and 4.5% in the case of the
eurodollar rate for the tranche B term loan. Additionally, the tranche B
eurodollar rate is deemed to be no less than 3.0%. Subsequent to March 31, 2004,
borrowing rates under the tranche A term loan and the revolving credit facility
will vary in relation to the Company's senior debt to EBITDA ratio. The Credit
Facility interest rates also include an additional 1% interest rate on the
tranche A term loan, tranche B term loan and revolving credit facility from
September 30, 2002 to March 31, 2004 and thereafter until the Company's
debt-to-capital ratio falls to no greater than 0.55 to 1.00. The first
additional interest payment is due September 30, 2003 and quarterly thereafter.
The Company is charged various fees and expenses in connection with the Credit
Facility, including commitment fees and various letter of credit fees.

The Credit Facility requires the Company to meet certain financial
covenants, some of which use a measure of cash flow called EBITDA, as defined in
the Credit Facility. The financial covenants specify thresholds of the following
ratios which use EBITDA: senior debt to EBITDA, EBITDA to fixed charges and
EBITDA to interest expense. The initial calculations of these ratios are to be
made when the Company issues its financial results for the quarter ending
September 30, 2003, using the immediately preceding four quarters. In addition,
the financial covenants set a maximum threshold for total debt to total
capitalization ratio, as defined in the Credit Facility, each quarter-end
commencing June 30, 2002. The Credit Facility requires a minimum cumulative
consolidated EBITDA amount of $90 million and $270 million for the nine-month
period ending March 31, 2003 and the twelve-month period ending June 30, 2003,
respectively. The Credit Facility also requires a minimum consolidated quick
ratio, as defined in the Credit Facility, each month-end beginning October 31,
2002 through June 30, 2003. The Credit Facility limits the Company's capital
expenditures and refinery turnaround spending to no more than $253.5 million in
the year 2002, $237.5 million for the twelve-month period ending June 30, 2003
and $210 million in the calendar year 2003 and each year thereafter unless the
Company's debt-to-capital ratio falls below 0.58 to 1.00. Under the terms of the
Credit Facility, the Company is not permitted to declare or pay cash dividends
on the Company's common stock or repurchase shares of its common stock through
December 31, 2003. Beginning January 1, 2004, the terms allow for payment of
cash dividends on the Company's common stock and repurchase of shares of its
common stock, not to exceed $15 million in any year. The Credit Facility
contains other covenants and restrictions customary in credit arrangements of
this kind. Noncompliance with the covenants constitutes an event of default and,
if not cured by a waiver or amendment, would permit the lenders to accelerate
the maturity of the Credit Facility, refuse to advance any additional funds
under the Credit Facility and exercise the lenders' remedies under the Credit
Facility, and by reason of cross-default provisions, indebtedness under the
Company's indentures and other indebtedness could also become immediately due
and payable.

The Company satisfied all of the financial covenants under the Credit
Facility for the period ended December 31, 2002, as well as the requirement to
complete asset sales resulting in net proceeds of at least $200 million prior to
March 31, 2003 (see Note E). In December 2002, $87.5 million of the asset sales
proceeds were used to prepay term loans. An additional $16.3 million, included
in cash at year-end, was used

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TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

to prepay term loans in January 2003, and therefore was included in current
maturities of long-term debt as of December 31, 2002. Net proceeds from asset
sales or equity offerings received in 2003 up to the date the Company issues
financial results for the quarter ending September 30, 2003, are required to be
applied in full to prepay the term loans.

See Note A for information on a proposed refinancing and other matters.

9 5/8% Senior Subordinated Notes Due 2012

In April 2002, the Company issued $450 million principal amount of 9 5/8%
Senior Subordinated Notes due April 1, 2012 ("9 5/8% Notes Due 2012"). The
9 5/8% Notes Due 2012 have a ten-year maturity with no sinking fund requirements
and are subject to optional redemption by the Company after five years at
declining premiums. In addition, the Company, for the first three years, may
redeem up to 35% of the principal amount at a redemption price of 109.625% with
proceeds of certain equity issuances. The indenture for the 9 5/8% Notes Due
2012 contains covenants and restrictions which are customary for notes of this
nature. The restrictions under the indenture are less restrictive than those in
the 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 9 5/8% Notes Due 2012 are guaranteed by
substantially all of the Company's active domestic subsidiaries. The proceeds
from the 9 5/8% Notes Due 2012 and accrued interest were used to partially fund
the acquisition of the California Assets.

9 5/8% Senior Subordinated Notes Due 2008

In November 2001, the Company issued $215 million principal amount of
9 5/8% Senior Subordinated Notes due November 1, 2008 ("9 5/8% Notes Due 2008").
The 9 5/8% Notes Due 2008 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 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%
Notes Due 2008 contains covenants and restrictions which are customary for notes
of this nature. The restrictions under the indenture are less restrictive than
those in the 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 9 5/8% Notes Due 2008 are guaranteed by
substantially all of the Company's active domestic subsidiaries.

9% Senior Subordinated Notes Due 2008

In 1998, the Company issued $300 million principal amount of 9% Senior
Subordinated Notes due 2008, Series B ("9% Notes Due 2008"). The 9% Notes Due
2008 have a ten-year maturity without sinking fund requirements and are subject
to optional redemption by the Company beginning in July 2003 at declining
premiums. The indenture for the 9% Notes Due 2008 contains covenants and
restrictions which are customary for notes of this nature. The restrictions
under the indenture are less restrictive than those in the 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% Notes Due 2008 is 9.16%, after
giving effect to the discount at the date of issue. The 9% Notes Due 2008 are
guaranteed by substantially all of the Company's active domestic subsidiaries.

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TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Junior Subordinated Notes

In connection with the California Assets acquisition, the Company issued to
the seller two ten-year junior subordinated notes with face amounts aggregating
$150 million. The notes consist of: (i) a $100 million junior subordinated note,
due July 2012, which is non-interest bearing for the first five years and
carries a 7.5% interest rate for the remaining five-year period, and (ii) a $50
million junior subordinated note, due July 2012, which has no interest payment
in year one and bears interest at 7.47% for the second through the fifth years
and 7.5% for years six through ten. The two junior subordinated notes with face
amounts of $100 million and $50 million were initially recorded at a combined
present value of approximately $61 million, discounted at rates of 15.625% and
14.375%, respectively. The discount is being amortized over the terms of the
notes.

Capital Leases

On December 31, 2002, the Company sold and leased-back 30 retail stations
under leases with initial terms of 17 years, with four 5-year renewal options.
The portions of the leases attributable to land were classified as operating
leases, while the portions attributable to depreciable buildings and equipment
were classified as capital leases with a present value of minimum lease payments
totaling $23.2 million. In addition, the Company has other capital leases for
tugs and barges used in the transportation of petroleum products.

At December 31, 2002 and 2001, the cost of assets under capital leases was
$35.3 million gross (accumulated amortization of $7.6 million) and $9.3 million
gross (accumulated amortization of $3.7 million), respectively. Capital lease
obligations included in debt totaled $28.8 million and $6.6 million at December
31, 2002 and 2001, respectively. Amortization of the cost of assets under
capital leases is included in depreciation and amortization in the Statements of
Consolidated Operations.

Future minimum annual lease payments as of December 31, 2002 for capital
leases were as follows (in millions):

2003........................................................ $ 4.5
2004........................................................ 4.5
2005........................................................ 4.4
2006........................................................ 4.1
2007........................................................ 3.8
Thereafter.................................................. 35.9
-----
Total minimum lease payments........................... 57.2
Less amount representing interest........................... 28.4
-----
Capital lease obligations.............................. $28.8
=====

NOTE H -- STOCKHOLDERS' EQUITY

In March 2002, the Company completed a public offering of 23 million shares
of Common Stock. The net proceeds from the stock offering of $245.1 million,
after deducting underwriting fees and offering expenses, were used to partially
fund the acquisition of the California Assets.

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

The Company was authorized to repurchase up to 3 million shares of Common
Stock, which may be used to meet employee benefit plan requirements and for
other corporate purposes. In 2000, the Company

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TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

repurchased 1.6 million shares of Common Stock for $15.5 million. In 2001, the
Company repurchased an additional 304,000 shares of its Common Stock for $3.5
million, bringing the cumulative shares repurchased under the program to
1,931,400. In 2002, the Company did not repurchase any shares under the program.
Under the terms of the Credit Facility, the Company is not permitted to declare
or pay cash dividends on the Company's Common Stock or repurchase shares of its
Common Stock through December 31, 2003. Beginning January 1, 2004, the terms
allow for payment of cash dividends on the Company's Common Stock and repurchase
of shares of its Common Stock, not to exceed $15 million in any year.

See Note P for information relating to stock-based compensation and Common
Stock reserved for exercise of options.

NOTE I -- INCOME TAXES

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

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TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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, 2002 and 2001 are summarized as follows
(in millions):

The realization of deferred tax assets is dependent upon the Company's
ability to generate future taxable income. Although realization is not assured,
the Company believes it is more likely than not that the deferred tax assets
will be realized and therefore no valuation allowance was recorded at December
31, 2002.

The acquisition of the California Assets in 2002 did not result in any net
deferred tax assets or liabilities. In 2001, the Mid-Continent Acquisition
described in Note D 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. The net deferred federal and state tax assets were increased by
$4.3 million and $0.6 million, respectively, in 2002 in connection with the
finalization of the purchase price allocation.

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

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TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

As of December 31, 2002, the Company had approximately $158 million of
Federal net operating loss carryforwards that expire in 2022 and $36 million of
alternative minimum tax credits that can be carried forward indefinitely.

The filing of the 2001 tax returns and the carryback of the 2001 net
operating loss resulted in the receipt of $48 million of refunds during 2002. In
2002, the Company incurred additional net operating losses, a portion of which
were carried back to previous years. The Company's election to carryback the
2002 net operating losses resulted in the loss of $3.9 million of tax credits
claimed in earlier years. Income taxes receivable of $41.9 million at December
31, 2002 have been collected in the first quarter of 2003.

NOTE J -- 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 prepayments, 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 $3.7 million and $3.2 million at December 31, 2002 and
2001, respectively.

NOTE K -- INVENTORIES

Components of inventories at December 31, 2002 and 2001 were as follows (in
millions):

At December 31, 2002 and 2001, inventories valued using LIFO were lower
than replacement cost by approximately $120 million and $3 million,
respectively. During 2002, 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 $5 million and a decrease in net loss of approximately $3
million, or $0.05 per share, during 2002.

NOTE L -- GOODWILL AND ACQUIRED INTANGIBLES

SFAS No. 142, "Goodwill and Other Intangible Assets", requires that
goodwill and other intangibles determined to have an indefinite life are no
longer to be amortized but are to be tested for impairment at least annually.
See Note B for the effects of the amortization of goodwill in 2001 and 2000.
Upon adoption of SFAS No. 142, the Company ceased amortizing goodwill and
determined through the required transitional test that its goodwill was not
impaired as of January 1, 2002. The Company completed the required annual test
for goodwill impairment during the fourth quarter of 2002. Based on the annual
test, the Company recognized a loss of $1.2 million to reduce the carrying value
of goodwill in the Retail segment. The impairment is included in loss on asset
sales and impairment in the Statements of Consolidated Operations. The fair
value of the reporting unit was estimated using the expected present value of
future cash flows. The impairment resulted from a change in strategy which
reduced the estimated future performance of the reporting unit.

The annual evaluation of goodwill impairment involves significant estimates
made by management in determining the fair value of reporting units. These
estimates are susceptible to change from period to period

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

because management must make assumptions about future cash flows, profitability
and other items. It is reasonably possible that changes in estimates could have
a material impact in the carrying amount of goodwill in future periods.

The net carrying values of goodwill by operating segments at December 31,
2002 and 2001 were as follows (in millions):

The decrease of $2.9 million in the Refining segment goodwill during 2002
reflects the finalization of the purchase price allocation for the Mid-Continent
assets acquired in September 2001. As discussed above, the decrease of $1.2
million in the Retail segment goodwill was due to an impairment loss recognized
in the fourth quarter of 2002.

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

The intangible assets as of December 31, 2002 included amounts attributable
to the California refinery acquired in May 2002. Those amounts are preliminary,
pending completion of independent appraisals. Reductions in the gross carrying
amounts of customer agreements and contracts and other intangibles reflect the
finalization of the purchase price allocation for the Mid-Continent Acquisition.

The weighted average lives of acquired intangible assets are as follows:
air emission credits -- 28 years; refinery permits and plans -- 22 years;
customer agreements and contracts -- 14 years; and other intangible assets -- 12
years.

Amortization expense of acquired intangible assets other than goodwill
amounted to $8.8 million and $2.7 million for the years ended December 31, 2002
and 2001, respectively. Estimated aggregate amortization expense for each of the
following five years is as follows: 2003 -- $10 million; 2004 -- $10 million;
2005 -- $9 million; 2006 -- $8 million; and 2007 -- $6 million. These estimates
are preliminary, pending completion of independent appraisals of the California
refinery.

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TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

NOTE M -- OTHER ASSETS

Other assets consisted of the following at December 31, 2002 and 2001 (in
millions):

At December 31, 2002, the Company had outstanding notes receivable totaling
approximately $2.4 million from an Executive Vice President and a Senior Vice
President of the Company. The notes are non-interest bearing and require annual
principal payments over terms of five to six years. Two of the notes were issued
on June 12, 2002 and one was assumed by the Company in connection with the May
17, 2002 acquisition of the California refinery.

As discussed in Note A, the Company is pursuing discussions regarding
possible financing alternatives to replace its senior secured credit facility.
If the Company elects to replace or modify its senior secured credit facility,
it may be required to write-off all or a portion of the senior secured credit
facility debt issuance costs ($34.9 million at December 31, 2002) during the
quarter in which the Company replaces or modifies the facility.

NOTE N -- ACCRUED LIABILITIES

The Company's current accrued liabilities and noncurrent other liabilities
as shown in the Consolidated Balance Sheets at December 31, 2002 and 2001
included the following (in millions):

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TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

NOTE O -- 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. The Company contributed $13 million in 2002 and expects to contribute
$17 million in 2003. Retirement plan assets are primarily comprised of common
stock and bond funds.

The Company's executive security plans ("ESP Plans") provide certain
executive officers and other key personnel with supplemental death or retirement
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 contributed $3 million in 2002 and expects to contribute $2 million
in 2003.

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

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.

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TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Changes in benefit obligations, plan assets and the funded status of the
pension plans and other postretirement benefits, reconciled to amounts in the
Consolidated Balance Sheets as of December 31, 2002 and 2001, are presented
below (in millions):

At December 31, 2002, the accumulated benefit obligation of the Retirement
Plan exceeded the fair value of plan assets and the Company recognized an
additional minimum liability and an intangible asset of $6.6 million.

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.

In the first quarter of 2003, the Company offered voluntary enhanced
retirement benefits to 91 qualified employees. These enhanced benefits, which
are being offered for only a short period of time, will result in additional
liabilities and a charge to expense upon acceptance of the offers in the 2003
first quarter. The

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TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

amount, which cannot presently be determined because it depends upon the number
of acceptances, could range from $12 million to $24 million pretax.

SFAS No. 132 requires companies to disclose the aggregate benefit
obligation and plan assets of all plans in which the obligations exceed assets.
At December 31, 2002, the projected benefit obligations, accumulated benefit
obligations and fair values of plan assets aggregated $165.6 million, $113.8
million and $55.8 million, respectively, combined for the Retirement Plan, the
unfunded ESP Plan and the Directors' Retirement Plan. 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 these plans in total. The assets of the Funded ESP Plan
exceeded its accumulated benefit obligation at year-end 2002 and 2001.

The components of pension and postretirement benefit expense included in
the Consolidated Statements of Operations for the years ended December 31, 2002,
2001 and 2000 were as follows (in millions):

Significant assumptions included in the estimation of the Company's pension
and other postretirement benefits obligations are as follows:

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. 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):

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TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Thrift Plan and Retail Savings Plan

The Company sponsors an employee thrift plan ("Thrift Plan") that 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. The maximum matching contribution is 6% for employees
covered by the collective bargaining agreement at the California refinery.
Participants may transfer out of Tesoro's Common Stock at any time, but are
limited to four such transfers each calendar year. The Company's contributions
to the Thrift Plan amounted to $11.1 million, $6.5 million and $5.4 million
during 2002, 2001 and 2000, respectively, of which $2.4 million and $3.4 million
consisted of treasury stock reissuances in 2002 and 2001, respectively. There
were no similar reissuances in 2000.

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 $0.4 million and $0.2
million during 2002 and 2001, respectively, of which $0.1 million consisted of
treasury stock reissuances in both 2002 and 2001.

NOTE P -- 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, 2002, the Company had 7,536,427
shares of unissued Common Stock reserved for these employee incentive stock
plans and non-employee director plan.

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 2002 Annual Meeting of Stockholders held in June 2002,
an amendment was approved by the stockholders which increased the number of
shares available for grant under the 1993 Plan from 5,250,000 to 7,250,000.
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 25% or 33% increments per year and expire ten
years from the date of grant. Subject to stockholder approval, the Board of
Directors expects to extend the expiration date of the 1993 Plan from September
15, 2003 to September 15, 2008. At December 31, 2002, the Company had 1,262,614
shares available for future grants under the 1993 Plan.

The 1999 Plan 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 that 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

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TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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, 2002, the
Company had 50,500 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 nonqualified stock options to
eligible non-employee directors of the Company. At the Company's 2002 Annual
Meeting of Stockholders held in June 2002, an amendment was approved by the
stockholders which increased the number of shares available for grant under the
1995 Plan from 150,000 to 300,000. 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, 2002, the Company had 121,000 options
outstanding and 156,000 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):

The following table summarizes information about stock options outstanding
under all plans at December 31, 2002 (shares in thousands):

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TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

At December 31, 2002, 2001 and 2000, exercisable stock options totaled 3.8
million, 3.1 million and 2.4 million, respectively.

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. Retiring directors who are committee
chairpersons receive an additional $5,000 credit to their accounts. Certain
non-employee directors also received a credit in their 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 a
credit of $299,000 in 2002 and expenses of $144,000 and $201,000 in 2001 and
2000, 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 with a term of ten years at 100% of the fair
value of the Company's Common Stock on the grant date, or $16.9844 per share. At
December 31, 2002, 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. No compensation expense has been recognized related
to this award.

Pro Forma

For information related to the pro forma effects had compensation cost been
determined based on fair values at the grant dates of awards in accordance with
SFAS No. 123, see Note B.

NOTE Q -- COMMITMENTS AND CONTINGENCIES

Operating Leases

The Company has various noncancellable operating leases related to land,
buildings, equipment, retail facilities and ship charters. These leases have
remaining primary terms up to 25 years, with terms of certain rights-of-way
extending up to 28 years, and generally contain multiple renewal options.

In December 2002, the Company sold and leased back 30 retail stations under
leases with initial terms of 17 years, and four 5-year renewal options. The
portion of each lease attributed to land has been classified as an operating
lease, while the portion attributed to depreciable buildings and equipment has
been classified as a capital lease (see Note G).

The Company has 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.

The Company has long-term charters through July 2010 for two U.S. flagged
ships, used to transport crude oil and products. The aggregate annual
commitments on these charters total $25 million to $29 million

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TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

over the remaining term, which include operating expenses that increase annually
from $13 million to $16 million over the remaining period.

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 in 2001.

The Company leases its corporate headquarters from a limited partnership,
in which the Company owns a 50% limited interest. The initial term of the lease
is through 2014 with two five-year renewal options. Included in total rent
expense below are lease payments and operating costs paid to the partnership
totaling $2.1 million, $2.5 million and $1.8 million in 2002, 2001 and 2000,
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 $17 million and debt of approximately $13
million are not included in the accompanying Consolidated Financial Statements.

Future minimum annual lease payments as of December 31, 2002, for operating
leases having initial or remaining noncancellable lease terms in excess of one
year were as follows (in millions):

Total rental expense for short-term and long-term operating leases,
excluding marine charters, amounted to approximately $46 million in 2002, $34
million in 2001, and $26 million in 2000. 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. Total marine
charter expense was $54 million in 2002, $40 million in 2001 and $42 million in
2000. For information related to capital leases, see Note G.

Other Commitments

In the normal course of business, the Company has long-term commitments to
purchase services, such as electricity, water, hydrogen, nitrogen, oxygen and
sulfuric acid for use by certain of its refineries. The minimum annual payments
under these contracts are estimated to total $26 million in 2003, $25 million in
2004, $14 million in 2005, $14 million in 2006, and $14 million in 2007. The
remaining minimum commitment totals approximately $37 million over 10 years. The
Company also has a power supply agreement at the California refinery which
requires minimum payments that vary, based on market prices for electricity,
over the next 10 years. The Company paid approximately $57 million, $15 million
and $14 million in 2002, 2001 and 2000, respectively, under these contracts.

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

90

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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.

In the normal course of business, the Company is subject to audits by
Federal, state and local taxing authorities. Audit examinations have resulted in
proposed adjustments that are subject to further appeal. It is possible that
such audits could result in claims against the Company in excess of liabilities
currently recorded. Management believes, however, that the ultimate resolution
of these matters will not materially affect the Company's consolidated financial
position or results of operations.

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.

Environmental Remediation Liabilities

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

Soil and groundwater conditions at the California refinery may require
substantial expenditures over time. The Company's current estimate of costs to
address environmental liabilities including soil and groundwater conditions at
the refinery in connection with various projects, including those required
pursuant to orders by the California Regional Water Quality Control Board, is
approximately $73 million, of which approximately $31 million is anticipated to
be incurred through 2006 and the balance thereafter. The Company believes that
it will be entitled to indemnification for approximately $63 million of such
costs, directly or indirectly, from former owners or operators of the refinery
(or their successors) under two separate indemnification agreements.
Additionally, if remediation expenses are incurred in excess of the
indemnification, the Company expects to receive coverage under one or both of
the environmental insurance policies discussed in Note D.

In connection with the acquisition of the Hawaii refinery, the Company
received an indemnity from the seller for environmental costs arising out of
conditions which existed at or prior to the Hawaii refinery acquisition. This
indemnification, which is in effect until 2008, has $4.4 million remaining as of
December 31, 2002.

The Company is currently involved in remedial responses and has incurred
cleanup expenditures associated with environmental matters at a number of other
sites, including certain of its owned properties. At December 31, 2002, the
Company's accruals for environmental expenses totaled approximately $40 million.
The Company's accruals for environmental expenses include retained liabilities
for prior owned or operated properties, refining, pipeline, terminal and marine
services operations and retail service stations. Based on currently available
information, including the participation of other parties or former owners in
remediation actions, the Company believes these accruals are adequate.

91

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Environmental Capital

In February 2000, the EPA finalized new regulations pursuant to the Clean
Air Act requiring reduction in the sulfur content in gasoline beginning January
1, 2004. To meet this revised gasoline standard, the Company currently estimates
it will make capital improvements of approximately $37 million through 2006 and
an additional $15 million thereafter. This will permit all of the Company's
refineries to produce gasoline meeting the limits imposed by the EPA.

The EPA also promulgated new regulations in January 2001 pursuant to the
Clean Air Act requiring a reduction in the sulfur content in diesel fuel
manufactured for on-road consumption. In general, the new diesel fuel standards
will become effective on June 1, 2006. Based on the latest engineering
estimates, the Company expects to spend approximately $55 million in capital
improvements through 2007. These expenditures, however, do not include the
Alaska refinery where the Company has limited demand for low sulfur diesel which
presently does not justify the capital investment. The Company expects to meet
this demand from other sources.

The Company expects to spend approximately $44 million in additional
capital improvements through 2006 to comply with the second phase of the Maximum
Achievable Control Technologies standard for petroleum refineries ("Refinery
MACT II"), promulgated in April 2002. The Refinery MACT II regulations require
new emission controls at certain processing units at several of the Company's
refineries. The Company is currently evaluating a selection of control
technologies to assure operations flexibility and compatibility with long-term
air emission reduction goals.

To meet California's CARB III gasoline requirements, including the
mandatory phase out of using the oxygenate known as MTBE, the Company expects to
spend approximately $17 million in 2003 at the California refinery. The project
should be completed in the first quarter of 2003.

In connection with the 2001 acquisition of the North Dakota and Utah
refineries, the Company assumed the sellers' obligations and liabilities under a
consent decree among the United States, BP Exploration and Oil Co., Amoco Oil
Company and Atlantic Richfield Company. BP entered into this consent decree for
both the North Dakota and Utah refineries for various alleged violations. As the
new owner of these refineries, the Company is required to address issues,
including leak detection and repair, flaring protection and sulfur recovery unit
optimization. The Company currently estimates it will spend an aggregate of $7
million to comply with this consent decree. In addition, the Company has agreed
to indemnify the sellers for all losses of any kind incurred in connection with
the consent decree.

In connection with the 2002 acquisition of the California refinery, subject
to certain conditions, the Company also assumed the seller's obligations
pursuant to its settlement efforts with the Environmental Protection Agency
concerning the Section 114 refinery enforcement initiative under the Clean Air
Act, except for any potential monetary penalties, which the seller retains. The
Company believes these obligations will not have a material impact on its
financial position.

Based on latest estimates, the Company will need to expend additional
capital at the California refinery for reconfiguring and replacing above ground
storage tank systems and upgrading piping within the refinery. These costs are
currently estimated at approximately $130 million through 2007 and an additional
estimated $90 million through 2011. Both of these cost estimates are subject to
further review and analysis by the Company.

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

92

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Other Matters

Union Oil Company of California has asserted claims against other refining
companies for infringement of patents related to the production of certain
reformulated gasoline. The Company's California refinery produces grades of
gasoline that might be subject to similar claims. Since the validity of those
patents is now being re-examined by the U.S. Patent Office, the Company has not
paid or accrued liabilities for patent royalties that might be related to
production at the California refinery.

NOTE R -- QUARTERLY FINANCIAL DATA (UNAUDITED)

Certain previously reported amounts have been reclassified to conform to
the 2002 presentation, principally the reclassification of revenues and cost of
sales to report certain crude oil and product purchases and resales on a net
basis (see Note B).

The results above include the California Assets operations since mid-May
2002 and the Mid-Continent operations since September 2001.

During the fourth quarter of 2002, the Company incurred a loss on assets
sales and impairment totaling $7.9 million, primarily related to the sale of 70
retail stations in northern California and the sale/lease-back of 30 retail
stations (see Note E). Also during the fourth quarter of 2002, the Company's
income tax benefit was reduced by $6.0 million due to the loss of tax credits
claimed in earlier years and other adjustments to estimated liabilities (see
Note I).

93

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

Information required under this Item will be contained in the Company's
2003 Proxy Statement, incorporated herein by reference. See also Executive
Officers of the Registrant under Business in Item 1 hereof.

ITEM 11. EXECUTIVE COMPENSATION

Information required under this Item will be contained in the Company's
2003 Proxy Statement, incorporated herein by reference.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

Information required under this Item will be contained in the Company's
2003 Proxy Statement, incorporated herein by reference.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Information required under this Item will be contained in the Company's
2003 Proxy Statement, incorporated herein by reference.

ITEM 14. CONTROLS AND PROCEDURES

Within the 90 days prior to the filing date of this report, we carried out
an evaluation, under the supervision and with the participation of our
management, including the Chief Executive Officer and Chief Financial Officer,
of the effectiveness of the design and operation of our disclosure controls and
procedures pursuant to Rule 13a-14 of the Securities Exchange Act of 1934, as
amended (the "Exchange Act"). Based upon that evaluation, the Chief Executive
Officer and Chief Financial Officer concluded that our disclosure controls and
procedures are effective in alerting them on a timely basis to material
information relating to the Company required to be included in our periodic
filings under the Exchange Act. Subsequent to the date of this evaluation, there
have been no significant changes in our internal controls or in other factors
that could significantly affect internal controls, nor were any corrective
actions required with regard to significant deficiencies or material weaknesses.

94

PART IV

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

(A) 1. FINANCIAL STATEMENTS

The following Consolidated Financial Statements of Tesoro Petroleum
Corporation and its subsidiaries are included in Part II, Item 8 of this Form
10-K:

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.

3. EXHIBITS

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

* 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 January 6, 2003, a Current Report on Form 8-K was filed under Item 5,
Other Events, reporting that the Company had issued press releases announcing
that the Company had (i) entered into a second amendment of its senior secured
credit facility, (ii) sold 70 retail stations in northern California, (iii) sold
its product pipeline system in North Dakota and Minnesota and (iv) completed a
sale/lease-back transaction for 30 company-operated retail stations in Alaska,
Hawaii, Idaho and Utah. The amendment to the senior secured credit facility and
five Press Releases issued in December 2002 were filed as Exhibits under Item 7
of this Form 8-K. No financial statements were filed with this Current Report.

100

SIGNATURES

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

TESORO PETROLEUM CORPORATION

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

Dated: March 21, 2003

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.

101

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

I, Bruce A. Smith, certify that:

1. I have reviewed this annual report on Form 10-K of Tesoro Petroleum
Corporation;

2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this annual
report;

3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this annual report;

4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:

a. Designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities,
particularly during the period in which this annual report is being
prepared;

b. Evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date of this
annual report (the "Evaluation Date"); and

c. Presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;

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

a. All significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to record,
process, summarize and report financial data and have identified for the
registrant's auditors any material weaknesses in internal controls; and

b. Any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's internal
controls; and

6. The registrant's other certifying officers and I have indicated in this
annual report whether or not there were significant changes in internal controls
or in other factors that could significantly affect internal controls subsequent
to the date of our most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses.

/s/ BRUCE A. SMITH
--------------------------------------
Bruce A. Smith
Principal Executive Officer

Date: March 21, 2003

102

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

I, Gregory A. Wright, certify that:

1. I have reviewed this annual report on Form 10-K of Tesoro Petroleum
Corporation;

2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this annual
report;

3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this annual report;

4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:

a. Designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities,
particularly during the period in which this annual report is being
prepared;

b. Evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date of this
annual report (the "Evaluation Date"); and

c. Presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;

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

a. All significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to record,
process, summarize and report financial data and have identified for the
registrant's auditors any material weaknesses in internal controls; and

b. Any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's internal
controls; and

6. The registrant's other certifying officers and I have indicated in this
annual report whether or not there were significant changes in internal controls
or in other factors that could significantly affect internal controls subsequent
to the date of our most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses.

/s/ GREGORY A. WRIGHT
--------------------------------------
Gregory A. Wright
Principal Financial Officer

Date: March 21, 2003

103

INDEX TO EXHIBITS

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

+ 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.