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, 1996

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.)

8700 TESORO DRIVE, SAN ANTONIO, TEXAS 78217-6218
(Address of Principal Executive Offices) (Zip Code)

REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE:
210-828-8484
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SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:

NAME OF EACH EXCHANGE
TITLE OF EACH CLASS ON WHICH REGISTERED
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Common Stock, $.16 2/3 par value New York Stock Exchange
Pacific Stock Exchange

SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT: None

Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [ ]
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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. [ ]
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At February 28, 1997, the aggregate market value of the voting stock held
by nonaffiliates of the registrant was approximately $283,905,638 based upon the
closing price of its shares on the New York Stock Exchange Composite tape. At
February 28, 1997, there were 26,426,333 shares of the registrant's Common Stock
outstanding.
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DOCUMENTS INCORPORATED BY REFERENCE

DOCUMENT FORM 10-K PART
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Proxy Statement for 1997 Annual Meeting Part III

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TESORO PETROLEUM CORPORATION

ANNUAL REPORT ON FORM 10-K

TABLE OF CONTENTS

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----

PART I
Item 1. Business.................................................... 3
Refining and Marketing.................................... 3
Exploration and Production................................ 6
Marine Services........................................... 12
Competition and Other..................................... 13
Government Regulation and Legislation..................... 14
Employees................................................. 17
Executive Officers of the Registrant...................... 18
Item 2. Properties.................................................. 19
Item 3. Legal Proceedings........................................... 19
Item 4. Submission of Matters to a Vote of Security Holders......... 19

PART II
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters....................................... 20
Item 6. Selected Financial Data..................................... 21
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations................................. 23
Item 8. Financial Statements and Supplementary Data................. 38
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure.................................. 69

PART III
Item 10. Directors and Executive Officers of the Registrant.......... 69
Item 11. Executive Compensation...................................... 69
Item 12. Security Ownership of Certain Beneficial Owners and
Management................................................ 69
Item 13. Certain Relationships and Related Transactions.............. 69

PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form
8-K....................................................... 69
SIGNATURES............................................................ 75

THIS ANNUAL REPORT CONTAINS STATEMENTS WITH RESPECT TO THE COMPANY'S
EXPECTATIONS OR BELIEFS AS TO FUTURE EVENTS. THESE TYPES OF STATEMENTS ARE
FORWARD-LOOKING AND SUBJECT TO UNCERTAINTIES. SEE "FORWARD-LOOKING STATEMENTS"
ON PAGE 36.

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PART I

ITEM 1. BUSINESS

Tesoro Petroleum Corporation, together with its subsidiaries ("Tesoro" or
the "Company"), is a natural resource company engaged primarily in petroleum
refining and marketing, natural gas exploration and production, marketing and
distributing of petroleum products and providing marine logistics services. The
Company was incorporated in Delaware in 1968 (a successor by merger to a
California corporation incorporated in 1939). For financial information relating
to industry segments, see Management's Discussion and Analysis of Financial
Condition and Results of Operations in Item 7 and Note B of Notes to
Consolidated Financial Statements in Item 8.

REFINING AND MARKETING

OVERVIEW

The Company conducts petroleum refining operations in Alaska and sells
refined products to a wide variety of customers in Alaska, along the U.S. West
Coast, in the Pacific Northwest and in certain Far Eastern markets, including
Russia. During 1996, products from the Company's refinery accounted for
approximately 79% of these sale volumes, including products received on exchange
in the U.S. West Coast market, with the remaining 21% being purchased from other
refiners and suppliers. The Company's purchases from other refiners and
suppliers declined in 1996 as the Company withdrew from certain California
markets which is further discussed below.

The Company's refinery, which is located in Kenai, Alaska, has a rated
throughput capacity of 72,000 barrels per day and is capable of producing
liquefied petroleum gas, gasoline, jet fuel, diesel fuel, heating oil, heavy
oils and residual products. Alaska North Slope ("ANS") and Cook Inlet crude oils
are the primary feedstocks for the refinery. To assure the availability of crude
oil to the refinery, the Company has a royalty crude oil purchase contract with
the State of Alaska ("State") (see "Crude Oil Supply" discussed below). During
1996, the refinery processed approximately 72% ANS crude oil, 25% Cook Inlet
crude oil and 3% other refinery feedstocks, which yielded refined products
consisting of approximately 26% gasoline, 41% middle distillates, 28% heavy oils
and residual products and 5% other products.

CRUDE OIL SUPPLY

The refinery is designed to process crude oil with up to 1.0% sulphur
content. As such, the refinery can process Cook Inlet, ANS and certain foreign
crude oils.

ANS Crude Oil. ANS crude oil is a heavy crude oil which contains an average
of 1.0% sulphur. In 1996, approximately 72% of the refinery's feedstock was ANS
crude oil, of which approximately 39,200 barrels per day were purchased under a
royalty crude oil purchase contract with the State. The contract with the State,
which covers the period January 1, 1996 through December 31, 1998, provides for
the purchase of approximately 40,000 barrels per day of ANS royalty crude oil
and is priced based on royalty values computed by the State. Under the contract,
the Company is required to utilize in its refinery operations volumes equal to
at least 80% of the ANS crude oil to be purchased from the State. This contract
contains provisions that, under certain conditions, allow the Company to
temporarily or permanently reduce its purchase obligation.

All ANS crude oil feedstock is delivered to the refinery by tanker through
the Kenai Pipe Line Company ("KPL") marine terminal which the Company purchased
in early 1995.

For information related to settlement of a contractual dispute with the
State in 1993, see Note I of Notes to Consolidated Financial Statements in Item
8.

Cook Inlet Crude Oil. Cook Inlet crude oil, a lighter crude oil that
contains an average of .1% sulphur, accounted for approximately 25% of the
refinery's feedstock supply in 1996. The Company obtains Cook Inlet crude oil
from several producers on the Kenai Peninsula under short-term contracts. Cook
Inlet crude oil is

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delivered by tanker through the Company's KPL marine terminal or through an
existing pipeline to the refinery.

Other Supply. In 1996, the Company's refinery obtained approximately 3% of
its feedstock supply from other sources. The other supply consisted of heavy
atmospheric gas oil ("HAGO") and foreign crude oil. The HAGO feedstock was
purchased from a local competitor's refinery and from a U.S. West Coast refinery
under short-term contracts. HAGO is a refinery by-product which generates
various light refined products with no residual fuel oil. Foreign crude oil,
purchased in spot quantities, is delivered to the refinery by tanker through the
Company's KPL marine terminal. The Company evaluates the economic viability of
processing foreign crude oil in its refinery and will occasionally purchase spot
quantities to supplement its normal crude oil supply. During 1996, the Company
imported its first cargo of crude oil from Russia.

REFINING AND MARKETING ACTIVITIES

The following table summarizes the Company's refining and marketing
operations:

YEARS ENDED DECEMBER 31,
--------------------------
1996 1995 1994
------ ------ ------

Refinery Throughput (average daily barrels)............... 47,486 50,569 46,032
====== ====== ======
Refinery Production (average daily barrels):
Gasoline................................................ 12,763 14,298 11,728
Middle distillates, including jet fuel and diesel
fuel................................................. 19,975 20,693 18,402
Heavy oils and residual products........................ 13,739 14,516 15,118
Other................................................... 2,600 2,489 2,213
------ ------ ------
Total Refinery Production....................... 49,077 51,996 47,461
====== ====== ======
Product Sales (average daily barrels):
Gasoline................................................ 17,427 24,526 23,191
Middle distillates...................................... 29,651 37,988 33,256
Heavy oils and residual products........................ 15,089 14,787 14,228
------ ------ ------
Total Product Sales............................. 62,167 77,301 70,675
====== ====== ======
Product Sales Prices ($/barrel):
Gasoline................................................ $32.72 28.21 27.03
Middle distillates...................................... $29.01 24.40 24.47
Heavy oils and residual products........................ $17.61 13.66 10.93
Number of Marketing Outlets Selling the Company's
Gasoline(1):
Alaska --
7-Eleven convenience stores (Company-operated)....... 33 32 32
Branded stations..................................... 126 99 90
Unbranded stations................................... 29 28 24
Pacific Northwest -- branded stations................... 18 10 --
------ ------ ------
Total Locations...................................... 206 169 146
====== ====== ======

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(1) Branded gasoline outlets sell the Company's gasoline under the "Tesoro
Alaska" name. Outlets that sell the Company's gasoline under a different
name are considered unbranded.

The Company's refinery production was reduced in September 1996 for a
scheduled 30-day maintenance downtime. During the maintenance period, the
hydrocracker catalyst was replaced and, beginning in the fourth quarter of 1996,
the Company was able to produce higher volumes of jet fuel, which better matches
the Company's production with demand in Alaska. To further improve the
refinery's feedstock and product slate, the Company intends to modify the
refinery hydrocracker during 1997 at an estimated cost of $17 million. In
conjunction with the modification and other initiatives, a refinery downtime of
approximately 30 days is anticipated during 1997.

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ALASKA MARKETING

Gasoline. The Company distributes gasoline to end users in Alaska, either
by retail sales through its 7-Eleven convenience store locations, by wholesale
sales through 126 branded and 29 unbranded dealers and jobbers or by deliveries
to major oil companies for their retail operations in Alaska in exchange for
gasoline delivered to the Company on the U.S. West Coast. In 1996, the Company
continued implementing initiatives to increase the Company's share of gasoline
sales in Alaska and added 31 stations to its marketing network, including its
initial expansion into Southeast Alaska with nine locations. Two uneconomic
outlets were closed in 1996. The Company holds an exclusive license agreement
for all 7-Eleven convenience stores in Alaska and operates such stores in 36
locations, 33 of which sell Company-branded gasoline. During 1996, these
convenience stores sold an average of 53,000 gallons of gasoline per day.
Gasoline produced in excess of Alaska's market demand is shipped to the U.S.
West Coast or exported to the Far East by chartered vessel.

Middle Distillates. The Company is a major supplier of commercial jet fuel
into the Alaskan marketplace, with all of its production being marketed in
Alaska to passenger and cargo airlines. The demand for jet fuel in Alaska
currently exceeds the production of all refiners in Alaska, and several
marketers, including the Company, import jet fuel into Alaska to meet excess
demand. Substantially all of the Company's diesel fuel production is sold on a
wholesale basis in Alaska primarily for marine and industrial purposes.
Generally, the production of diesel fuel by refiners in Alaska is in balance
with demand; however, because of the high variability of the demand, there are
occasions when diesel fuel is imported into or exported from Alaska. See
"Government Regulation and Legislation -- Environmental Controls" for a
discussion of the effect of governmental regulations on the production of
low-sulphur diesel fuel for on-highway use in Alaska.

Heavy Oils and Residual Products. The refinery's vacuum unit uses residual
fuel oil as a feedstock by further processing these volumes into light vacuum
gas oil ("LVGO"), heavy vacuum gas oil ("HVGO") and vacuum tower bottoms
("VTB"). The LVGO is further processed in the refinery's hydrocracker, where it
is converted into gasoline and jet fuel. HVGO is sold to refiners on the U.S.
West Coast, where it is used as a catalytic hydrocracker feedstock, while the
VTBs are generally sold on the U.S. West Coast where they are blended with light
cycle oil to produce bunker fuel.

In 1996, the Company began producing liquid asphalt, a heavy product left
after petroleum is refined into gasoline and other products. Liquid asphalt,
which is used in the manufacturing of concrete asphalt for paving, was sold to
customers in Alaska and California. This product is seasonal in the Alaska
market due to mild weather conditions needed for highway construction.

U.S. WEST COAST AND PACIFIC NORTHWEST MARKETING

In 1996, the Company conducted wholesale marketing operations, primarily in
Oregon and Washington, selling refined products in the bulk market and through
nine terminal facilities, including four owned by the Company during the year.
To a lesser extent, the Company sold refined products through numerous other
terminals to facilitate disposal of inventories in California. In 1996, these
operations sold approximately 14,000 barrels per day of refined products,
primarily gasoline and diesel fuel, of which approximately 19% was received from
major oil companies in exchange for products from the Company's refinery,
approximately 13% was received directly from the refinery and 68% was purchased
from other suppliers.

In 1996, the Company expanded its retail presence in the Pacific Northwest
by adding eight branded stations. At year-end 1996, the Company had 18 branded
gasoline distributors in Oregon and Washington. The Company will continue to
sell refined products in the Pacific Northwest through branded stations in
addition to six terminal facilities, one of which is owned by the Company.

Due to market conditions, the Company withdrew from certain West Coast
markets and initiated a plan to sell its three Company-owned facilities in
California. One of these facilities was sold in December 1996 and two facilities
remain for sale at year-end.

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TRANSPORTATION

The Company charters an American flag vessel, the Potomac Trader, whose
primary use is to transport ANS crude oil from the Trans Alaska Pipeline System
("TAPS") terminal at Valdez, Alaska to the Company's refinery. The Company
charters another American flag vessel, the Chesapeake Trader, which is used
primarily to transport heavy oils and residual products to the U.S. West Coast
and occasionally to transport feedstocks to the Company's refinery. The Potomac
Trader and Chesapeake Trader are chartered under five-year agreements expiring
in 2000. Under an agreement expiring in June 1997, the Company charters a
Russian flag vessel, the Igrim, which is used primarily to transport refined
products from the Company's refinery to the Far East. The Company plans to
continue marketing its products in the Far East and is evaluating transportation
alternatives. From time to time, the Company also charters tankers and
ocean-going barges to transport petroleum products to its customers within
Alaska, on the U.S. West Coast and in the Far East.

The Company operates a common carrier petroleum products pipeline from the
Company's refinery to its terminal in Anchorage. This ten-inch diameter pipeline
has a capacity to transport approximately 40,000 barrels of petroleum products
per day and allows the Company to transport light products to the terminal
throughout the year, regardless of weather conditions. During 1996, the pipeline
transported an average of approximately 22,000 barrels of petroleum products per
day, all of which were transported for the Company.

The Company's subsidiary, KPL, is a common carrier pipeline and marine dock
facility. By owning this facility, the Company is assured of uninterrupted use
of the dock and pipeline for unloading crude oil feedstocks and loading product
inventory on tankers and barges. During 1996, KPL transported approximately
47,200 barrels of crude oil per day and 34,100 barrels of refined products per
day, all of which were transported for the Company.

For further information on transportation in Alaska, see "Government
Regulation and Legislation -- Environmental Controls."

EXPLORATION AND PRODUCTION

OVERVIEW

The Exploration and Production segment is engaged in the exploration,
development and production of natural gas and oil, primarily in the Wilcox Trend
in South Texas and the Chaco Basin in Bolivia. In the U.S., the Company's focus
has recently shifted outside of the maturing Bob West Field in South Texas to
other areas. During 1996 and early 1997, the Exploration and Production segment
purchased interests in the Frio/Vicksburg Trend adjacent to the Wilcox Trend in
South Texas, the Cotton Valley Pinnacle Reef Play in East Texas and the Val
Verde Basin in Southwest Texas. This segment also includes the transportation of
natural gas, including the Company's production, to common carrier pipelines in
the South Texas area. In Bolivia, the Company operates through two contracts
with the Bolivian government to explore for and produce hydrocarbons. The
Company's Bolivian gas production is sold under contract to the Bolivian
government for export to Argentina. The majority of the Company's Bolivian
natural gas and oil reserves are shut-in awaiting access to gas-consuming
markets which is expected to be provided by a 1,900-mile pipeline from Bolivia
to Brazil. The pipeline is scheduled to begin construction in late 1997, with
first gas deliveries expected in 1999.

UNITED STATES

Bob West Field. The Bob West Field, which was discovered by the Company in
1990, is located in the southern part of the Wilcox Trend in Starr and Zapata
counties, Texas. The Wilcox Trend extends from Northern Mexico through South
Texas into the other Gulf Coast states. Multiple pay sands exist within the
Wilcox Trend, where extensive faulting has trapped hydrocarbons in numerous
producing zones. Continued successful development of the Bob West Field led to
the completion of 12 gross development wells during 1996. One well was being
drilled at year-end and three additional well locations, all of which are
expected to be drilled during 1997, have been selected for further development
of this 4,000-acre field. During 1996, the

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Company's net production from the Bob West Field averaged approximately 82
million cubic feet ("Mmcf") per day.

The Company's revenue interests in the Bob West Field range from 28% to 57%
and its working interests range from 33% to 70%. In addition, the Company owns a
70% interest in the field's central gas processing facility which has a capacity
of 350 Mmcf per day. The Company also owns 25% of a central compression
facility, rated at 10,000 horsepower with an estimated capacity of 150 Mmcf per
day, that was installed in the Bob West Field in late 1996. During the first two
months of operation, the Company's production in the Bob West Field increased by
approximately 9 Mmcf per day primarily as a result of the new compression
facility.

Other Areas. In addition to the continued development of the Bob West
Field, during 1996 the Company also participated in the drilling of six
exploratory wells in other portions of the Wilcox Trend in South Texas, four of
which were successfully completed as producing wells.

In December 1996, the Company purchased 25% to 50% interests in portions of
the Los Indios and La Reforma Fields, located in Hidalgo and Starr counties of
South Texas, for $15 million. The two fields are located in the Frio/Vicksburg
Trend, which lies immediately adjacent to the Wilcox Trend. The Company's
working interest covers 11,700 acres and the acquisition is over 90% natural
gas. The area is believed to have significant further development potential
beyond the current net production of 6 Mmcf equivalents ("Mmcfe") per day and
net proved reserves acquired of 20 billion cubic feet equivalents ("Bcfe"). The
acquisition includes recent three-dimensional seismic data covering nearly 50
square miles which will be used to exploit the remaining reserve potential of
the properties. Tesoro will jointly operate the fields with a private producer.

During 1996, the Company also acquired interests in the Berry R. Cox and
the West Goliad Fields for a total of $5.4 million. Both fields are located in
South Texas in the Wilcox Trend. The acquisitions consisted of ten wells
producing at initial rates totaling 6.7 Mmcfe per day. Workovers and
recompletions have increased production to a total of 9.3 Mmcfe per day at
year-end. In January 1997, one exploratory well and one development well were
drilled and completed on these prospects and these wells are producing at a
combined rate of 5.5 Mmcfe per day.

Also, in 1996, the Company purchased approximately 35,000 net undeveloped
acres for a total of $5.3 million. The acquired acreage is located in four
areas, the Cotton Valley Pinnacle Reef Play in East Texas, the Val Verde Basin
in Southwest Texas, the Frio/Vicksburg Trend in South Texas and the Wilcox Trend
in South Texas.

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Reserves. The following table shows the estimated net proved reserves,
based on evaluations prepared by Netherland, Sewell & Associates, Inc., and
gross producing wells for each of the Company's U.S. fields as of December 31,
1996, compared with certain data at December 31, 1995:

DECEMBER 31,
DECEMBER 31, 1996 1995
-------------------------------------------- ---------------
PRESENT
VALUE OF NET PROVED GAS NET PROVED GAS
PROVED GROSS RESERVES RESERVES
RESERVES(1) PRODUCTIVE --------------- ---------------
FIELD TEXAS COUNTIES ($ THOUSANDS) WELLS BCFE % BCFE %
----- -------------- ------------- ---------- ------ ----- ------ -----

Bob West............... Starr and Zapata $ 178,623 61 88.0 75% 100.0 94%
Los Indios............. Hidalgo 16,746 29 16.8 14 -- --
Lopeno................. Zapata 6,190 5 3.7 3 2.1 2
Berry R. Cox........... Webb 7,053 5 2.9 3 -- --
La Reforma............. Starr and Hidalgo 5,092 12 2.8 2 -- --
West Goliad............ Goliad 5,351 8 2.3 2 -- --
Other.................. 3,681 13 1.4 1 4.3 4
---------- --- ----- ---- ----- ----
$ 222,736 133 117.9 100% 106.4 100%
========== === ===== ==== ===== ====

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(1) Represents the discounted future net cash flows before income taxes. See
Note O of Notes to Consolidated Financial Statements in Item 8 for
additional information regarding the Company's proved reserves and
standardized measure.

Tennessee Gas Contract. In August 1996, the Supreme Court of Texas denied a
motion for rehearing by Tennessee Gas Pipeline Company ("Tennessee Gas") and
upheld all aspects of a Gas Purchase and Sales Agreement ("Tennessee Gas
Contract") which had been the subject of litigation since 1990. As provided for
in the Tennessee Gas Contract, the Company was selling a portion of the gas
produced from two 352-acre producing units in the Bob West Field pursuant to a
contract price ("Contract Price"). In 1996, approximately 12% of the Company's
total U.S. production was sold under the Tennessee Gas Contract at a Contract
Price that averaged $8.41 per thousand cubic feet ("Mcf"), representing 38% of
the Company's U.S. natural gas revenues for the year. In December 1996, the
Tennessee Gas Contract, which was to expire in January 1999, was terminated by
the parties effective October 1, 1996, and the Company began selling this gas on
the spot market. See Management's Discussion and Analysis of Financial Condition
and Results of Operations in Item 7 and Note D of Notes to Consolidated
Financial Statements in Item 8.

Gas Gathering and Transportation. The Company owns a 70% interest in the
Starr County Gathering System which consists of two ten-inch diameter pipelines
and one twenty-inch diameter pipeline that transport natural gas eight miles
from the Bob West Field to common carrier pipeline facilities. In addition, the
Company owns a 50% interest in the twenty-inch diameter Starr-Zapata natural gas
pipeline that was constructed during 1994 to transport gas 26 miles from the
Starr County Gathering System to a market hub at Fandango, Texas. The Company
does not operate either facility. During 1996, the gross average daily
throughput was 205 Mmcf per day for the Starr County Gathering System and 173
Mmcf per day for the Starr-Zapata pipeline, with approximately 50% of the
throughput consisting of the Company's working interest share of Bob West Field
production. The Starr County Gathering System receives a transportation fee of
$.06 per Mcf and the Starr-Zapata Pipeline receives a fee of $.07 per Mcf for
volumes transported.

For further information regarding the Company's U.S. operations, see Notes
B, C, N and O of Notes to Consolidated Financial Statements in Item 8.

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U.S. Operating Statistics

YEARS ENDED DECEMBER 31,
------------------------------
1996 1995 1994
------- -------- -------

Net Natural Gas Production (average daily Mcf).............. 87,654 114,490 83,796
Average Natural Gas Sales Price ($/Mcf):
Spot market(1)............................................ $ 1.95 1.34 1.48
Tennessee Gas Contract(2)................................. $ 8.41 8.41 7.93
Weighted average.......................................... $ 2.75 2.57 2.86
Average Operating Expenses ($/Mcfe):
Lease operating expenses.................................. $ .14 .11 .11
Severance taxes........................................... .03 .18 .18
------- -------- -------
Total production costs................................. .17 .29 .29
Administrative support and other.......................... .10 .06 .08
------- -------- -------
Total operating expenses............................... $ .27 .35 .37
======= ======== =======
Depletion Rate ($/Mcfe)..................................... $ .79 .69 .79
Exploratory Wells Drilled:
Productive -- Gross....................................... 4.0 5.0 3.0
Productive -- Net......................................... 1.7 1.5 1.5
Dry holes -- Gross........................................ 2.0 4.0 2.0
Dry holes -- Net.......................................... 1.0 2.1 1.1
Development Wells Drilled:
Productive -- Gross....................................... 15.0 17.0 20.0
Productive -- Net......................................... 6.3 9.7 11.1
Dry holes -- Gross........................................ 1.0 -- 1.0
Dry holes -- Net.......................................... .5 -- .4

JANUARY 31, 1997
-----------------
GROSS NET
------ -----

Productive Gas Wells(3)..................................... 133 61.0
Acreage (in thousands):
Developed................................................. 27 9
Undeveloped............................................... 109 46

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

(1) Includes effects of the Company's natural gas price agreements which
amounted to a loss of $.11 per Mcf in 1996 and a gain of $.01 per Mcf in
1995 and 1994 (see Note N of Notes to Consolidated Financial Statements in
Item 8).

(2) See Note D of Notes to Consolidated Financial Statements in Item 8 related
to the Tennessee Gas Contract.

(3) Included in total productive wells are 8 gross (.4 net) wells with multiple
completions. At January 31, 1997, the Company was participating in the
drilling of 8 gross (3.7 net) wells.

(4) Mcfe is defined as net equivalent one thousand cubic feet.

BOLIVIA

The Company's Bolivian exploration and production operations are located in
southern Bolivia near the border of Argentina, where the Company has discovered
six fields since 1976 with estimated net proved natural gas reserves of 253 Bcfe
at December 31, 1996. With gross average production of 55 Mmcfe per day in 1996,
Tesoro is one of the largest operators in Bolivia. The Company is the operator
of a joint venture that holds two Shared Risk Contracts with Yacimientos
Petroliferos Fiscales Bolivianos ("YPFB"), the Bolivian state-owned oil and gas
company.

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Bolivian Hydrocarbons Law. In 1996, a new Hydrocarbons Law was passed by
the Bolivian government that significantly impacts the Company's operations in
Bolivia. The new law, among other matters, granted the Company the option to
convert its Contracts of Operation to new Shared Risk Contracts. During 1996,
the Company signed agreements to convert its Contracts of Operation to Shared
Risk Contracts subject to recision at the option of the Company if the Company
is not satisfied with modifications to the Bolivian fiscal law. The Company
expects to complete this conversion during the first half of 1997. The new
contracts extend the Company's term of operation, provide more favorable acreage
relinquishment terms and provide for a more favorable fiscal regime of royalties
and taxes. The new contracts will extend the term of the Company's operations
for Block 18 ten additional years to the year 2017. For Block 20, the new
contract extends the Company's term 21 additional years to the year 2029 for
acreage that is in the exploration phase of the contract, and 10 additional
years to the year 2018 for an area within Block 20 that is designated as being
in the development phase of the new contract. The new contract provisions, along
with a substantial discovery during 1996, significantly increased the Company's
reserves (see Note O of Notes to Consolidated Financial Statements in Item 8).

Access To New Markets. A lack of market access has constrained natural gas
production in Bolivia. With little internal gas demand, all of the Company's
Bolivian natural gas production is sold under contract to the Bolivian
government for export to Argentina. Major developments in South America indicate
that new markets may open for the Company's production in the near future.
Progress has been made toward construction of a new 1,900-mile pipeline that
will link Bolivia's extensive gas reserves with markets in Brazil. In early
1997, a contract to supply pipe for the project was awarded. Construction is
scheduled to start in late 1997, with first gas deliveries expected in 1999.

Block 18. The Company has a 75% interest in a Shared Risk Contract, subject
to final conversion, expiring in 2017 and covering 92,625 acres in Block 18.
During 1996, the Company's net production from this block averaged 20.3 Mmcf of
gas per day and 584 barrels of condensate per day.

The new contract for Block 18 provides that the Company and its joint
venture participant will continue to be subject to a 29% participation that was
stipulated in YPFB's favor in the old contract. In addition, income taxes and
taxes on gross revenues will be paid which are expected to equal 31% of Block 18
gross revenues, leaving the Company and its joint venture participant with 40%
of Block 18 revenues, after royalties and taxes. The aftertax effect of the new
contract is essentially the same as the old contract. The Company is currently
selling all of its natural gas production from the La Vertiente, Escondido and
Taiguati Fields in Block 18 to YPFB which in turn sells the natural gas to
Yacimientos Petroliferos Fiscales, S.A. ("YPF"), a publicly-held company based
in Argentina. During 1994, the contract between YPFB and YPF was extended
through March 31, 1997, maintaining approximately the same volumes as the
previous contract. YPFB and YPF are currently negotiating a two-year contract
extension through March 1999. Currently, the Company is selling its natural gas
production to YPFB based on the volume and pricing terms in the contract between
YPFB and YPF.

Block 20. The Company has a 72.6% interest in a Shared Risk Contract,
subject to final conversion, expiring in 2029 and covering 787,313 acres in
Block 20. For Block 20, the Company and its joint venture participant will no
longer be required to pay a 19% royalty that had been required under the old
contract. Under the old contract, taxes on gross revenues were paid to the
national and local governments totaling 31% of gross revenues. Under the new
contract, a combination of income taxes and taxes on gross revenues are expected
to approximate the amount of taxes paid under the old contract. The Company is
investigating whether the Bolivian taxes can be treated as creditable for U.S.
tax purposes.

During 1996, the Company drilled two discovery wells in Bolivia. The Palo
Marcado X-4 found gas in four zones and had a combined test flow rate of 19.1
Mmcf per day. The well will be reentered in 1997 to test a fifth, deeper zone
that may also bear hydrocarbons. The discovery added 65 Bcfe of net proved
reserves for Tesoro. In 1997, a three-dimensional seismic survey is planned for
the Palo Marcado structure, as well as the shut-in Los Suris Field. A second
discovery well, the Ibibobo X-2, found hydrocarbons in two zones and was the
Company's first oil discovery in the country. Additional three-dimensional
seismic work is required to

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identify appraisal drilling sites on this structure. Both discoveries, which are
shut-in due to a lack of market, are expected to be placed on production
following completion of the Bolivia-Brazil pipeline.

Reserves. The table below shows the estimated net proved reserves, based on
evaluations prepared by Netherland, Sewell & Associates, Inc., and gross
productive wells for each of the Company's Bolivian fields as of December 31,
1996, compared with certain data at December 31, 1995. Each of the following
fields is operated by the Company:

DECEMBER 31, 1996 DECEMBER 31, 1995
----------------------------------------------------------------- --------------------
NET PROVED RESERVES
-----------------------------
OIL GAS PV-10 AFTER PV-10 AFTER
GROSS (MILLIONS (BILLION BOLIVIAN TAXES(1) BOLIVIAN TAXES(1)
PRODUCTIVE OF CUBIC TOTAL -------------------- --------------------
FIELD BLOCK WELLS BARRELS) FEET) (BCFE) ($ THOUSANDS) % ($ THOUSANDS) %
- ----- ----- ---------- --------- -------- ------ ------------- ---- ------------- ----

Palo Marcado......... 20 2 1.5 101.7 110.5 $24,667 38% $ -- --%
Escondido............ 18 5 1.3 64.8 72.8 23,330 36 15,577 58
Los Suris............ 20 2 .5 46.8 50.0 13,135 20 3,043 11
La Vertiente......... 18 5 .4 16.5 19.0 3,090 5 8,162 30
Taiguati............. 18 1 -- .7 .7 221 1 376 1
-- --- ----- ----- ------- ---- ------- ----
15 3.7 230.5 253.0 $64,443 100% $27,158 100%
== === ===== ===== ======= ==== ======= ====

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

(1) Represents the after Bolivian tax discounted future net cash flows, which
included an increase of $23 million at December 31, 1996 due to the
anticipated completion of the Bolivia-Brazil pipeline. See Notes B and O of
Notes to Consolidated Financial Statements in Item 8 for additional
information regarding the Company's proved reserves and standardized
measure.

For further information regarding the Company's Bolivian operations, see
Notes B and O of Notes to Consolidated Financial Statements in Item 8.

Bolivia Operating Statistics

YEARS ENDED DECEMBER 31,
-----------------------------
1996 1995 1994
------- ------- -------

Net Production(1):
Natural gas (average daily Mcf)...................... 20,251 18,650 22,082
Condensate (average barrels per day)................. 584 567 733
Average Sales Price:
Natural gas ($/Mcf).................................. $ 1.33 1.28 1.20
Condensate ($/barrel)................................ $ 17.98 14.39 13.28
Average Operating Expenses ($/Mcfe):
Production costs..................................... $ .10 .07 .06
Value-added taxes.................................... .05 .06 .10
Administrative support and other..................... .27 .35 .25
------- ------- -------
Total Operating Expenses..................... $ .42 .48 .41
======= ======= =======
Depletion Rate ($/Mcfe)................................ $ .15 .03 --
Exploratory Wells Drilled:
Productive -- Gross.................................. 2.0 1.0 1.0
Productive -- Net.................................... 1.5 .7 .7
Dry Holes -- Gross................................... -- -- 1.0
Dry Holes -- Net..................................... -- -- .7

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Bolivia Operating Statistics (Continued)

DECEMBER 31, 1996
-----------------
GROSS NET
----- ----

Productive Gas Wells(2)..................................... 15 11.2
Acreage (in thousands):
Developed................................................. 93 69
Undeveloped............................................... 787 571

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

(1) Represents the Company's net production before Bolivian taxes, which were
payable in-kind for the years presented.

(2) Included in total productive wells are 4 gross (3.0 net) wells with multiple
completions. At December 31, 1996, the Company was participating in the
drilling of 2 gross (1.5 net) wells.

WORLDWIDE RESERVE REPLACEMENT AND COSTS OF ADDING RESERVES

In 1996, the Company's worldwide proved reserve additions included 113 Bcfe
from discoveries, extensions and domestic purchases of proved properties (65
Bcfe from Bolivia and 48 Bcfe domestically); 36 Bcfe from extensions in the
terms of the Company's Bolivian contracts and 62 Bcfe from other changes in the
Bolivian Hydrocarbons Law; less 4 Bcfe from revisions of previous estimates.
Excluding revisions, 211 Bcfe were added for a 517% replacement of 41 Bcfe of
production. Additions were realized with an 87.5% drilling success rate during
1996, reflecting a 94% success rate on 16 development wells and a 75% success
rate on 8 exploratory wells. The Company's three-year worldwide average cost of
adding these reserves was $.53 per Mcfe. Domestically, 48 Bcfe were added for a
151% replacement of 32 Bcfe of production. The three-year average cost of adding
domestic reserves was $.94 per Mcfe. See Note O of Notes to Consolidated
Financial Statements in Item 8.

MARINE SERVICES

OVERVIEW

The Company's Marine Services segment markets and distributes a broad range
of products, including diesel fuel, lubricants, chemicals and supplies, and
provides logistical support services to the marine and offshore exploration and
production industries operating in the Gulf of Mexico through a network of 20
terminals. These deep water marine terminals are located on the Texas Gulf Coast
in Galveston, Freeport, Harbor Island, Port O'Connor, Ingleside and Sabine Pass.
The Company also operates along the Louisiana Gulf Coast with terminals in
Cameron, Intracoastal City, Morgan City, Venice, Eunice, Amelia and Harahan.
These terminals are bulkheaded and dredged to provide easy access to vessels
receiving products for delivery to customers. Products are delivered offshore
aboard vessels owned or chartered by customers, which include companies engaged
in oil and gas exploration and production, seismic evaluation, offshore
construction and other drilling-related businesses.

The Marine Services segment achieved profitability in 1996 after a merger
and restructuring that established the Company as a major marine terminal
operator in the Gulf of Mexico. In February 1996, the Company purchased 100% of
the capital stock of Coastwide Energy Services, Inc. ("Coastwide"), a company
that provided shore-based services for the offshore exploration and production
industry, for approximately 1.4 million shares of Tesoro's Common Stock and $7.7
million in cash. These operations were combined with the Company's marine
petroleum distribution operation, forming a Marine Services segment. See Note C
of Notes to Consolidated Financial Statements in Item 8.

DIESEL FUEL AND LUBRICANTS

Diesel fuel and lubricants, which are used in operations such as offshore
drilling rigs, offshore production and transmission platforms and various ships
and equipment engaged in seismic surveys, are marketed and distributed from all
20 of the Company's terminals. Through these terminals and a fleet of six
tugboats (including three owned by the Company) and 14 barges (including ten
owned by the Company), the Company serves offshore workboats, tugboats and
barges using the Intracoastal Canal System, as well as ships

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entering the ports of Houston, New Orleans, Lake Charles, Corpus Christi and
Port Arthur. Tesoro obtains its supply of diesel fuel from refiners in the Gulf
Coast area. Total gallons of diesel fuel and other refined products sold by
Marine Services amounted to 142.7 million, 112.5 million and 119.2 million in
1996, 1995 and 1994, respectively. The Company is a distributor of lubricants
and cylinder oil produced by certain major oil companies, which are delivered to
customers by trucks or barges.

SERVICES

Through nine of its terminals, the Company provides full-service
shore-based support for offshore drilling rigs and production platforms. These
quayside services include loading docks and slips for offshore supply boats. In
addition, the Company provides dispatchers and stevedores, cranes, forklifts,
warehouses, office and dormitory accommodations, helicopter landing pads and car
parking for offshore workers. Tesoro also serves as delivery points for drilling
products, primarily mud, by providing warehousing, inventory control and
delivery services. Tesoro's bunkering services operate in major ports along the
Texas and Louisiana Gulf Coast. In 1996, 1995 and 1994, revenues from services
amounted to $10.9 million, $3.1 million and $2.7 million, respectively.

COMPETITION AND OTHER

The oil and gas industry is highly competitive in all phases, including the
refining and marketing of crude oil and petroleum products and the search for
and development of oil and gas reserves. The industry also competes with other
industries that supply the energy and fuel requirements of industrial,
commercial, individual and other consumers. The Company competes with a
substantial number of major integrated oil companies and other companies having
materially greater financial and other resources. These competitors have a
greater ability to bear the economic risks inherent in all phases of the
industry. In addition, unlike the Company, many competitors also produce large
volumes of crude oil that may be used in connection with their refining
operations. The North American Free Trade Agreement has further streamlined and
simplified procedures for the importation and exportation of natural gas among
Mexico, the United States and Canada. These changes are likely to enhance the
ability of Canadian and Mexican producers to export natural gas and other
products to the United States, thereby further increasing competition for
domestic sales.

The refining and marketing businesses are highly competitive, with price
being the principal factor in competition. In the refining market, the Company's
refinery competes primarily with other refineries in Alaska and on the U.S. West
Coast. The Company's refining competition in Alaska includes a refinery situated
near Fairbanks owned by MAPCO, Inc. and two refineries situated near Valdez and
Fairbanks owned by Petro Star Inc. The Company estimates that such other
refineries have a combined capacity to process approximately 176,000 barrels per
day of crude oil. ANS crude oil is the only feedstock used in these competing
refineries. After processing the crude oil and removing the lighter-end
products, which represent approximately 30% of each barrel processed, these
refiners are permitted, because of their direct connection to the TAPS, to
return the remainder of the processed crude back into the pipeline system as
"return oil" in consideration for a fee, thereby eliminating their need to
market residual products. The Company's refinery is not directly connected to
the TAPS, and the Company, therefore, cannot return its residual products to the
TAPS. The Company's refining competition from the U.S. West Coast includes many
large, integrated oil companies that do substantial business in Alaska and have
materially greater financial and other resources. A growing number of foreign
sources also compete with the Company.

The Company's marketing business in Alaska is segmented by product line.
The Company is a substantial producer and distributor of gasoline in Alaska,
with the largest network of branded and unbranded dealers and jobbers. The
Company is a supplier to a major oil company through a product exchange
agreement, whereby gasoline in Alaska is provided in exchange for gasoline
delivered to the Company on the U.S. West Coast. Jet fuel sales are concentrated
in Anchorage, where the Company is one of the principal suppliers to the
Anchorage International Airport, which is a major hub for air cargo traffic to
the Far East. Diesel fuel is sold primarily on a wholesale basis.

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The Company's Pacific Northwest marketing business is primarily a
distribution business selling to independent dealers and jobbers outside major
urban areas. In addition, the Company sells to 18 branded gasoline distributors
in the Pacific Northwest who obtain the majority of their supply from the
Company's refinery in Alaska. The Company competes against independent marketing
companies and integrated oil companies when engaging in these marketing
operations.

Demand for services and products offered by the Company's Marine Services
segment is closely related to the level of oil and gas exploration, development
and production in the Gulf of Mexico. Various factors, including general
economic conditions, demand for and prices of natural gas, availability of
equipment and materials and government regulations and energy policies cause
exploration and development activity to fluctuate and directly impact the
revenues of the Marine Services segment. Management believes that the principal
competitive factors affecting the Marine Services operations are location of
facilities, availability of logistical support services, experience of personnel
and dependability of service. The market for the Marine Services segment's
products and services, particularly diesel fuel, is price sensitive. The Company
competes with several independent operations, and in certain locations with one
or more major mud companies who maintain their own marine terminals.

A portion of the Company's operations are conducted in foreign countries
where the Company is also subject to risks of a political nature and other risks
inherent in foreign operations. The Company's operations outside the United
States in recent years have been, and in the future may be, materially affected
by host governments through increases or variations in taxes, royalty payments,
export taxes and export restrictions and adverse economic conditions in the
foreign countries, the future effects of which the Company is unable to predict.

GOVERNMENT REGULATION AND LEGISLATION

UNITED STATES

Natural Gas Regulations. Historically, all domestic natural gas sold in
so-called "first sales" was subject to federal price regulations under the
Natural Gas Policy Act of 1978 ("NGPA"), the Natural Gas Act ("NGA"), and the
regulations and orders issued by the Federal Energy Regulatory Commission
("FERC") in implementing such Acts. Under the Natural Gas Wellhead Decontrol Act
of 1989, all remaining natural gas wellhead pricing, sales, certificate and
abandonment regulation of first sales by the FERC was terminated on January 1,
1993.

The FERC also regulates interstate natural gas pipeline transportation
rates and service conditions, which affect the marketing of gas produced by the
Company, as well as the revenues received by the Company for sales of such
natural gas. Since the latter part of 1985, through its Order Nos. 436, 500 and
636, the FERC has endeavored to make natural gas transportation more accessible
to gas buyers and sellers on an open and non-discriminatory basis, and the
FERC's efforts have significantly altered the marketing and pricing of natural
gas. A related effort has been made with respect to intrastate pipeline
operations pursuant to the FERC's authority under Section 311 of the NGPA, under
which the FERC establishes rules by which intrastate pipelines may participate
in certain interstate activities without becoming subject to full NGA
jurisdiction. These Orders have gone through various permutations, but have
generally remained intact as promulgated. The FERC considers these changes
necessary to improve the competitive structure of the interstate natural gas
pipeline industry and to create a regulatory framework that will put gas sellers
into more direct contractual relations with gas buyers than has historically
been the case.

Order No. 636, issued April 8, 1992, reflected the FERC's finding that
under the current regulatory structure, interstate pipelines and other gas
merchants, including producers, do not compete on an equal basis. The FERC
asserted that Order No. 636 was designed to equalize that marketplace. This
equalization process was implemented largely through negotiated settlements in
individual pipeline service restructuring proceedings, designed specifically to
"unbundle" those services (e.g., gathering, transportation, sales and storage)
provided by many interstate pipelines so that producers of natural gas may
secure services from the most economical source, whether interstate pipelines or
other parties. The result of the FERC initiatives has brought to an end the
interstate pipelines' traditional role as wholesalers of natural gas in favor of
providing

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only gathering, transportation and storage services for others which will buy
and sell natural gas. The FERC has issued final orders in all of the individual
pipeline restructuring proceedings and all of the interstate pipelines are now
operating under new open access tariffs.

In addition, the FERC has announced its intention to reexamine certain of
its transportation related policies, including the appropriate manner in which
interstate pipelines release transportation capacity under Order No. 636 and,
more recently, the price which shippers can charge for released capacity. The
FERC has also issued a new policy regarding the use of nontraditional methods of
setting rates for interstate gas pipelines in certain circumstances as
alternatives to cost-of service based rates. A number of pipelines have obtained
FERC authorization to charge negotiated rates as one such alternative.

Although Order No. 636 does not regulate gas producers, such as the
Company, Order No. 636 is intended to foster increased competition within all
phases of the natural gas industry. It is unclear what impact, if any, increased
competition within the natural gas industry under Order No. 636 will have on the
Company and its gas sales efforts. The U.S. Court of Appeals for the District of
Columbia Circuit has affirmed the Commission's Order No. 636 restructuring rule
and remanded certain issues for further explanation or clarification. Numerous
petitions seeking judicial review of the individual pipeline restructuring
orders are currently pending in the United States Court of Appeals for the
District of Columbia Circuit. It is not possible to predict what, if any, effect
the order on remand or the Court's decision in the individual pipeline cases
will have on the Company. The Company does not believe, however, that it will be
affected any differently than other gas producers or marketers with which it
competes.

In 1993, the FERC initiated a proceeding seeking industry-wide comments
about its role in regulating natural gas gathering performed by interstate
pipelines or their affiliates. The proceeding did not result in a proposed
rulemaking. In 1994, the FERC granted a number of interstate pipeline
applications to abandon certificated gathering facilities to non-jurisdictional
entities. Under those orders, the rates charged by these entities, which may or
may not be affiliated with the interstate pipeline, are not regulated by the
FERC. Under the individual orders, gathering services must be continued to
existing customers under "default" contracts and be provided in an open-access
and non-discriminatory manner. The District of Columbia Court of Appeals upheld
the Commission's decision to not regulate gathering rates but found that the
Commission's "default" contract requirement was unlawful as outside the
Commission's jurisdiction. The court remanded the case to the Commission and the
agency has not yet acted on remand. The U.S. Supreme Court declined to review
the D.C. Circuit's decision.

The oil and gas exploration and production operations of the Company are
subject to various types of regulation at the state and local levels. Such
regulation includes requiring drilling permits and the maintenance of bonds in
order to drill or operate wells; the regulation of the location of wells; the
method of drilling and casing of wells and the surface use and restoration of
properties upon which wells are drilled; and the plugging and abandoning of
wells. The operations of the Company are also subject to various conservation
regulations, including regulation of the size of drilling and spacing units or
proration units, the density of wells that may be drilled in a given area and
the unitization or pooling of oil and gas properties. In this regard, some
states allow the forced pooling or integration of lands and leases. In addition,
state conservation laws establish maximum rates of production from oil and gas
wells, generally prohibit the venting or flaring of gas and impose certain
requirements regarding the ratability of production. The effect of these
regulations is to limit the amounts of crude oil, condensate and natural gas the
Company can produce from its wells and the number of wells or the locations at
which the Company can drill.

Additional proposals and proceedings that might affect the natural gas
industry are considered from time to time by Congress, the FERC, state
regulatory bodies and the courts. The Company cannot predict when or if any such
proposals might become effective, or their effect, if any, on the Company's
operations. The natural gas industry historically has been very heavily
regulated; therefore, there is no assurance that the less stringent regulatory
approach recently pursued by the FERC and Congress will continue indefinitely
into the future.

Environmental Controls. Federal, state, area and local laws, regulations
and ordinances relating to the protection of the environment affect all
operations of the Company to some degree. An example of a federal environmental
law that will require operational additions and modifications is the Clean Air
Act, which was

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amended in 1990. While the Company believes that its facilities generally are in
substantial compliance with current regulatory standards for air emissions, over
the next several years the Company's facilities will be required to comply with
the new requirements being adopted and promulgated by the U.S. Environmental
Protection Agency ("EPA") and the states in which the Company operates. These
regulations will necessitate the installation of additional controls or other
modifications or changes in use for certain emission sources. Specifics as to
the cost of these requirements, at certain facilities, are still being
determined. As part of these requirements, the Company's refinery as well as
some other Company facilities will be required to submit an application for a
Clean Air Act Amendment Title V permit; dates of submittal of these applications
vary upon the implementation of the State's Title V permit program. The Company
believes it can comply with these new requirements, and in some cases already
has done so, without adversely affecting operations.

The passage of the Federal Clean Air Act Amendments of 1990 prompted
adoption of regulations by the State of Alaska obligating the Company to produce
oxygenated gasoline for delivery to the Anchorage and Fairbanks, Alaska markets
starting on November 1, 1992. Controversies surrounding the potential health
effects in Arctic regions of oxygenated gasoline containing methyl tertiary
butyl ether ("MTBE") prompted early discontinuance of the program in Fairbanks.
On October 21, 1993, the United States Congress granted the State one additional
year of exemption from requiring the use of oxygenated gasoline. In addition,
the EPA has been directed to conduct additional studies of potential health
effects of oxygenated fuel in Alaska. The State of Alaska mandated the use of
oxygenated fuels containing ethanol in the Anchorage area from November 1
through the last day of February of the succeeding year. No requirements for use
of such products in Fairbanks have been issued, but are expected. Additional
federal regulations promulgated on August 21, 1990, which went into effect on
October 1, 1993, set limits on the quantity of sulphur in on-highway diesel
fuels which the Company produces. The State filed an application with the
federal government in February 1993 for a waiver from this requirement since
only 5% of the diesel fuel sold in Alaska was for on-highway vehicles. On March
14, 1994, the EPA granted the State of Alaska a waiver from the requirements of
the EPA's low sulphur diesel fuel program, permanently exempting Alaska's remote
areas and providing a temporary exemption for areas served by the Federal Aid
Highway System until October 1, 1996. On August 19, 1996, the EPA extended the
temporary exemption until October 1, 1998. The Company estimates that
substantial capital expenditures would be required to enable the Company to
produce low-sulphur diesel fuel to meet these federal regulations. If the State
is unable to obtain a permanent waiver from the federal regulations, the Company
would discontinue sales of diesel fuel for on-highway use after October 1, 1998.
The Company estimates that such sales accounted for less than 1% of its refined
product sales in Alaska during 1996. While the Company is unable to predict the
outcome of these matters, their ultimate resolution should not have a material
impact on its operations.

Oil Spill Prevention and Response. The Federal Oil Pollution Act of 1990
("OPA 90") and related state regulations require most refining, transportation
and oil storage facilities to prepare oil spill prevention contingency plans for
use during an oil spill response. The Company has prepared and submitted these
plans for approval and, in most cases, has received federal and state approvals
necessary to meet various regulations and to avoid the potential of negative
impacts on the operation of its facilities.

The Company currently charters a tanker to transport crude oil from the
Valdez, Alaska pipeline terminal through Prince William Sound and Cook Inlet to
its refinery. In addition, the Company routinely charters, on a long-term and
short-term basis, additional tankers and barges for shipment of crude oil and
refined products through Cook Inlet, as well as other locations. OPA 90
requires, as a condition of operation, that the Company demonstrate the
capability to respond to the "worst case discharge" to the maximum extent
practicable. Alaska law requires the Company to provide spill-response
capability to contain or control, and clean-up within 72 hours, an amount equal
to 50,000 barrels for a tanker carrying fewer than 500,000 barrels of crude oil
or equal to 300,000 barrels for a tanker carrying more than 500,000 barrels. To
meet these requirements, the Company has entered into a contract with Alyeska
Pipeline Service Company ("Alyeska") to provide initial spill response services
in Prince William Sound, with the Company later to assume those responsibilities
after mutual agreement with Alyeska and State and Federal On-Scene Coordinators.
The Company has also entered into an agreement with Cook Inlet Spill Prevention
and Response, Incorporated for oil spill response

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services in Cook Inlet. The Company believes these contracts provide for the
additional services necessary to meet spill response requirements established by
Alaska and federal law.

Transportation, storage, and refining of crude oil in Alaska result in the
greatest regulatory impact, with respect to oil spill prevention and response.
Oil transportation and terminaling operations at other Company facilities also
result in compliance mandates for oil spill prevention and response. The Company
contracts with various oil spill response cooperatives or local contractors to
provide necessary oil spill response capabilities which may be required on a
location by location basis.

Regulations promulgated by the Alaska Department of Environmental
Conservation ("ADEC") would have required the installation of dike liners in
secondary containment systems for petroleum storage tanks by January 1997. Such
installation would have required the Company to make capital improvements
starting in 1996 of approximately $9.5 million. However, on December 18, 1996,
ADEC approved the Company's alternative compliance schedule which allows the
Company until the year 2002 to implement alternative secondary containment
systems for the Company's existing petroleum storage tank facilities in the
State of Alaska at a reduced cost of approximately $6 million.

Underground Storage Tanks. Regulations promulgated by the EPA on September
23, 1988, require that all underground storage tanks used for storing gasoline
or diesel fuel either be closed or upgraded not later than December 22, 1998, in
accordance with standards set forth in the regulations. The Company's service
stations subject to the upgrade requirements are limited to locations within the
State of Alaska. The Company continues to monitor, test and make physical
improvements in its current operations, which result in a cleaner environment.
The Company is required to make expenditures for removal or upgrading of
underground storage tanks at several of its current and former service station
locations by December 22, 1998; the Company expects that such expenditures
during 1997 will cost approximately $2 million.

Environmental Expenditures. The Company's capital expenditures for
environmental control purposes totaled $.7 million during 1996. The Company
anticipates that it will incur total capital expenditures for such purposes of
approximately $6 million in 1997 and $3 million in 1998. The Company also
expects to spend approximately $6 million by the year 2002 for secondary
containment systems for existing storage tanks in Alaska. For further
information regarding environmental matters, see "Legal Proceedings" in Item 3
and "Environmental Controls" and "Underground Storage Tanks" discussed above.

BOLIVIA

The Company's operations in Bolivia are subject to the Bolivian
Hydrocarbons Law and various other laws and regulations. The Hydrocarbons Law
imposes certain requirements on the Company's ability to conduct its operations
in Bolivia. In the Company's opinion, neither the Hydrocarbons Law nor other
requirements currently imposed by Bolivian laws, regulations and practices will
have a material adverse effect upon its Bolivian operations. In 1996, a new
Hydrocarbons Law was passed by the Bolivian government that significantly
impacts the Company's operation in Bolivia. For information on the Bolivian
Hydrocarbons Law and Bolivian taxation, see "Exploration and
Production -- Bolivia" discussed above.

EMPLOYEES

At December 31, 1996, the Company employed approximately 1,000 persons, of
which approximately 40 were located in foreign countries. None of the Company's
employees are represented by a union for collective bargaining purposes. The
Company considers its relations with its employees to be satisfactory.

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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, 1997.

POSITION HELD
NAME AGE POSITION SINCE
- ---- --- -------- -------------

Bruce A. Smith................. 53 Chairman of the Board of Directors, President June 1996
and Chief Executive Officer
James C. Reed, Jr.............. 52 Executive Vice President, General Counsel and September 1995
Secretary
William T. Van Kleef........... 45 Executive Vice President, Operations September 1996
Don E. Beere................... 56 Vice President, Controller April 1992
Thomas E. Reardon.............. 50 Vice President, Human Resources and September 1995
Environmental
Gregory A. Wright.............. 47 Vice President and Treasurer September 1995

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

The business experience of the Company's executive officers for the past
five years is described below. Positions, unless otherwise specified, are with
the Company.

Bruce A. Smith -- Chairman of the Board of Directors, President and Chief
Executive Officer since June 1996. President and Chief Executive Officer from
September 1995 to June 1996. Executive Vice President, Chief Financial Officer
and Chief Operating Officer from July 1995 through September 1995. Executive
Vice President responsible for Exploration and Production Operations and Chief
Financial Officer from September 1993 to July 1995. Vice President and Chief
Financial Officer from September 1992 to September 1993. Vice President and
Treasurer of Valero Energy Corporation from 1986 to 1992.

James C. Reed, Jr. -- Executive Vice President, General Counsel and
Secretary since September 1995. Senior Vice President, General Counsel and
Secretary from August 1994 to September 1995. Vice President, General Counsel
and Secretary from September 1993 to August 1994. Vice President, Secretary from
December 1992 to September 1993. Vice President, Secretary of Tesoro Petroleum
Companies, Inc., from February 1992 to December 1992. Vice President, Assistant
Secretary of Tesoro Petroleum Companies, Inc., from 1990 to 1992.

William T. Van Kleef -- Executive Vice President, Operations since
September 1996. Senior Vice President and Chief Financial Officer from September
1995 to September 1996. Vice President, Treasurer from March 1993 to September
1995. Financial Consultant from January 1992 to February 1993.

Don E. Beere -- Vice President, Controller since April 1992. Vice
President, Controller of Tesoro Petroleum Companies, Inc. from February 1992 to
April 1992. Vice President, Internal Audit and Management Systems of Tesoro
Petroleum Companies, Inc. from 1990 to 1992.

Thomas E. Reardon -- Vice President, Human Resources and Environmental
since September 1995. Vice President, Human Resources and Environmental Services
of Tesoro Petroleum Companies, Inc. from October 1994 to September 1995. Vice
President, Human Resources of Tesoro Petroleum Companies, Inc. from February
1990 to October 1994.

Gregory A. Wright -- Vice President and Treasurer since September 1995.
Vice President, Corporate Communications from February 1995 to September 1995.
Vice President, Corporate Communications of Tesoro Petroleum Companies, Inc.
from January 1995 to February 1995. Vice President, Business Develop-

18
19

ment of Valero Energy Corporation from 1994 to January 1995. Vice President,
Corporate Planning of Valero Energy Corporation from 1992 to 1994. Vice
President, Investor Relations of Valero Energy Corporation from 1989 to 1992.

ITEM 2. PROPERTIES

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

ITEM 3. LEGAL PROCEEDINGS

The Company, along with numerous other parties, has been identified by the
Environmental Protection Agency ("EPA") as a potentially responsible party
("PRP") pursuant to the Comprehensive Environmental Response, Compensation and
Liability Act ("CERCLA") for the Mud Superfund site in Abbeville, Louisiana
("Site"). The Company arranged for the disposal of a minimal amount of materials
at the Site, but CERCLA might impose joint and several liability on each PRP at
the Site. The EPA is seeking reimbursement for its response costs incurred to
date at the Site, as well as a commitment from the PRPs either to conduct future
remedial activities or to finance such activities. The extent of the Company's
allocated financial contributions to the cleanup of the site is expected to be
limited based upon the number of companies, volumes of waste involved, and an
estimated total cost of approximately $500,000 among all of the parties to close
the Site. The Company is currently involved in settlement discussions with the
EPA and other PRP's involved at the Site. The Company expects, based on these
discussions, that its liability at the Site will not exceed $25,000.

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

None.

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20

PART II

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

The principal markets on which the Company's Common Stock is traded are the
New York Stock Exchange and the Pacific Stock Exchange. The per share market
price ranges for the Company's Common Stock during 1996 and 1995 are summarized
below:

1996 1995
------------ ------------
QUARTERS HIGH LOW HIGH LOW
-------- ---- ---- ---- ----

First............................................... $ 9 1/8 8 10 5/8 8 3/4
Second.............................................. $11 5/8 8 1/4 12 9 1/2
Third............................................... $13 1/2 10 1/2 10 3/8 8
Fourth.............................................. $15 1/2 12 7/8 9 1/2 7 1/4

At February 28, 1997, there were approximately 3,700 holders of record of
the Company's 26,426,333 outstanding shares of Common Stock. The Company did not
pay dividends on its Common Stock for the periods set forth above.

For information regarding restrictions on future dividend payments, see
Management's Discussion and Analysis of Financial Condition and Results of
Operations in Item 7 and Note I of Notes to Consolidated Financial Statements in
Item 8.

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21

ITEM 6. SELECTED FINANCIAL DATA

The selected consolidated financial data should be read in conjunction with
Management's Discussion and Analysis of Financial Condition and Results of
Operations in Item 7 and the Company's Consolidated Financial Statements,
including the notes thereto, in Item 8.

YEARS ENDED DECEMBER 31,
---------------------------------------------
1996 1995 1994 1993 1992
-------- ------- ------ ------ ------
(IN MILLIONS EXCEPT PER SHARE AMOUNTS)

REVENUES
Gross Operating Revenues --
Refining and Marketing.................................... $ 745.4 771.0 687.0 687.2 810.7
Exploration and Production
U.S. oil and gas........................................ 88.4 107.3 87.5 48.4 18.2
U.S. gas transportation................................. 5.4 5.7 3.1 1.0 --
Foreign(1).............................................. 13.7 11.7 13.2 12.6 23.9
Marine Services(2)........................................ 122.5 74.5 77.9 80.7 93.1
-------- ------- ------ ------ ------
Total Gross Operating Revenues..................... 975.4 970.2 868.7 829.9 945.9
Income from Settlement of a Natural Gas Contract(3)......... 60.0 -- -- -- --
Other, Including Gain (Loss) on Asset Sales(3).............. 4.4 32.7 3.2 .5 6.4
-------- ------- ------ ------ ------
Total Revenues..................................... $1,039.8 1,002.9 871.9 830.4 952.3
======== ======= ====== ====== ======
SEGMENT OPERATING PROFIT (LOSS)(3)
Refining and Marketing.................................... $ 6.0 .7 2.4 15.2 (14.9)
Exploration and Production
U.S. oil and gas........................................ 119.1 96.9 52.1 31.4 8.9
U.S. gas transportation................................. 4.8 5.1 2.9 .9 --
Foreign(1).............................................. 8.8 7.6 9.3 8.4 20.2
Marine Services(2)........................................ 6.1 (4.4) (2.3) (3.6) (4.7)
-------- ------- ------ ------ ------
Total Segment Operating Profit..................... $ 144.8 105.9 64.4 52.3 9.5
======== ======= ====== ====== ======
EARNINGS (LOSS) BEFORE EXTRAORDINARY ITEM(4)................ $ 76.8 57.5 20.5 17.0 (65.9)
EXTRAORDINARY LOSS ON DEBT EXTINGUISHMENT, NET OF INCOME
TAXES..................................................... (2.3) (2.9) (4.8) -- --
-------- ------- ------ ------ ------
NET EARNINGS (LOSS)......................................... $ 74.5 54.6 15.7 17.0 (65.9)
======== ======= ====== ====== ======
NET EARNINGS (LOSS) APPLICABLE TO COMMON STOCK.............. $ 74.5 54.6 13.0 7.8 (75.1)
======== ======= ====== ====== ======
EARNINGS (LOSS) PER SHARE
Earnings (Loss) Before Extraordinary Item(4).............. $ 2.90 2.29 .77 .54 (5.34)
Extraordinary Loss on Debt Extinguishment, Net............ (.09) (.11) (.21) -- --
-------- ------- ------ ------ ------
Net Earnings (Loss)....................................... $ 2.81 2.18 .56 .54 (5.34)
======== ======= ====== ====== ======
AVERAGE COMMON AND COMMON EQUIVALENT SHARES OUTSTANDING
Primary................................................... 26.5 25.1 23.2 14.3 14.1
Fully Diluted............................................. 26.5 25.1 24.7 19.1 18.8
CASH FLOWS FROM (USED IN)
Operations................................................ $ 179.0 35.4 60.3 21.8 11.4
Investing................................................. (94.2) 2.4 (91.2) (23.4) (21.1)
Financing................................................. (75.9) (37.9) 8.3 (8.7) (4.5)
-------- ------- ------ ------ ------
Increase (Decrease) in Cash and Cash Equivalents........ $ 8.9 (.1) (22.6) (10.3) (14.2)
======== ======= ====== ====== ======
CAPITAL EXPENDITURES(5)
Refining and Marketing.................................... $ 11.1 9.3 32.0 7.1 3.7
Exploration and Production
U.S. oil and gas........................................ 59.7 49.4 60.4 28.6 8.9
U.S. gas transportation................................. -- .2 5.2 .7 --
Foreign(1).............................................. 6.9 3.8 -- -- .4
Marine Services and Other................................. 7.3 1.2 2.0 1.1 2.4
-------- ------- ------ ------ ------
Total Capital Expenditures......................... $ 85.0 63.9 99.6 37.5 15.4
======== ======= ====== ====== ======
BALANCE SHEET AND OTHER DATA
Current Assets............................................ $ 237.3 182.5 182.1 196.5 228.4
Property, Plant and Equipment, Net........................ $ 316.5 261.7 273.3 213.2 198.5
Total Assets.............................................. $ 582.6 519.2 484.4 434.5 446.7
Current Liabilities....................................... $ 137.8 105.0 96.2 72.0 105.8
Working Capital........................................... $ 99.5 77.5 85.9 124.5 122.6
Current Ratio............................................. 1.72:1 1.74:1 1.89:1 2.73:1 2.16:1
Long-Term Debt and Other Obligations(6)................... $ 79.3 155.0 192.2 180.7 175.5
Redeemable Preferred Stock(6)............................. $ -- -- -- 78.1 71.7
Stockholders' Equity (6)(7)............................... $ 304.1 216.5 160.7 58.5 50.7

21
22

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

(1) Represents the Company's Bolivian operations, except for 1992 which also
included a former operation in Indonesia that was sold.

(2) Beginning in February 1996, the Marine Services segment includes the results
of operations of an acquired entity (see Note C of Notes to Consolidated
Financial Statements in Item 8).

(3) Segment operating profit (loss) is gross operating revenues, gains and
losses on asset sales and other income less applicable costs of sales,
operating expenses, depreciation, depletion and other items. Income taxes,
interest expense, interest income and corporate expenses are not included in
determining operating profit. In the Exploration and Production segment,
operating profit included income of $60 million from termination of a
natural gas contract in 1996 and a gain of $33 million from the sale of
certain interests in the Bob West Field in 1995 (see Notes B, C and D of
Notes to Consolidated Financial Statements in Item 8). In addition,
operating profit included $25 million, $47 million, $39 million, $20 million
and $8 million in the years 1996, 1995, 1994, 1993 and 1992, respectively,
from the excess of the natural gas contract prices over spot market prices
(see Note D of Notes to Consolidated Financial Statements in Item 8 and
Management's Discussion and Analysis of Financial Condition and Results of
Operations in Item 7).

(4) The net loss for 1992 is after a charge of $20.6 million ($1.47 per share)
for the cumulative effect of the adoption of SFAS No. 106, "Employer's
Accounting for Postretirement Benefits Other Than Pensions" and SFAS No.
109, "Accounting for Income Taxes".

(5) Excludes acquisitions of stock.

(6) For information on the Company's recapitalization and equity offering in
1994, see Note K of Notes to Consolidated Financial Statements in Item 8.

(7) No dividends were paid on common shares during the periods presented above.

22
23

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

RESULTS OF OPERATIONS

SUMMARY

Net earnings of $74.5 million ($2.81 per share) in 1996 compare to $54.6
million ($2.18 per share) in 1995 and $15.7 million ($.56 per share) in 1994.
Noncash extraordinary losses for early extinguishment of debt amounted to $2.3
million in 1996, $2.9 million in 1995 and $4.8 million in 1994. Earnings before
extraordinary losses amounted to $76.8 million ($2.90 per share), $57.5 million
($2.29 per share) and $20.5 million ($.77 per share) in 1996, 1995 and 1994,
respectively. Comparability between the results for these years was impacted by
significant items which are highlighted in the table below (in millions except
per share amounts):

1996 1995 1994
----- ----- ----

Net Earnings as Reported.................................... $74.5 54.6 15.7
Extraordinary Loss on Debt Extinguishment, Net of Income Tax
Benefit................................................... 2.3 2.9 4.8
----- ----- ----
Earnings Before Extraordinary Item.......................... 76.8 57.5 20.5
----- ----- ----
Significant Items Affecting Comparability, Pretax:
Income from settlement of a natural gas contract (Note
D)..................................................... 60.0 -- --
Interest and reimbursement of fees and costs from
resolution of litigation (Note D)...................... 8.1 -- --
Retroactive severance tax refund.......................... 5.0 -- --
Gain (loss) on sale of assets............................. (.8) 33.5 2.4
Employee terminations and restructuring costs............. (2.9) (5.2) --
Costs of shareholder consent solicitation resolved in
April 1996............................................. (2.3) -- --
Refund from settlement of tariff issue.................... -- -- 8.5
Environmental and other................................... (2.5) -- (7.1)
----- ----- ----
Total Significant Items, Pretax........................ 64.6 28.3 3.8
Income Tax Effect...................................... 19.5 -- --
----- ----- ----
Total Significant Items, Aftertax...................... 45.1 28.3 3.8
----- ----- ----
Net Earnings Excluding Significant Items and
Extraordinary Loss................................... $31.7 29.2 16.7
===== ===== ====
Earnings Per Share:
As Reported............................................... $2.81 2.18 .56
Extraordinary Loss........................................ .09 .11 .21
Effect of Significant Items............................... (1.70) (1.13) (.16)
----- ----- ----
Excluding Significant Items and Extraordinary Loss........ $1.20 1.16 .61
===== ===== ====

As shown above, excluding the significant items, the Company's net earnings
would have been $31.7 million ($1.20 per share) in 1996, as compared to $29.2
million ($1.16 per share) in 1995 and $16.7 million ($.61 per share) in 1994.
The resulting increase in net earnings in 1996, compared to 1995, was primarily
attributable to improvements within the Company's Refining and Marketing and
Marine Services segments, each of which reported significant improvements from
the prior year. Results from the Company's Exploration and Production segment
increased, even when excluding the above items and removing the incremental
value of an above-market pricing contract (see Note D of Notes to Consolidated
Financial Statements in Item 8) from both 1996 and 1995. Additionally, at the
corporate level, initiatives implemented in the fourth quarter of 1995 helped
reduce general and administrative expenses and interest expense. These
improvements were partially offset by an increase in the Company's total
effective tax rate in 1996 as earnings subject to U.S. taxes exceeded available
net operating loss and tax credit carryforwards. When comparing 1995 to 1994,
the improvement in net earnings of approximately $12 million was primarily
attributable to increased natural gas production from the Company's exploration
and production operations in South Texas

23
24

and improvements in the Company's refining and marketing operations. In 1994,
dividend requirements on preferred stock amounted to $2.7 million (see Note K of
Notes to Consolidated Financial Statements in Item 8).

A discussion and analysis of the factors contributing to these results are
presented below. The accompanying consolidated financial statements and related
footnotes, together with the following information, are intended to provide
shareholders and other investors with a reasonable basis for assessing the
Company's operations, but should not serve as the sole criterion for predicting
the future performance of the Company. The Company conducts its operations in
the following business segments: Refining and Marketing, Exploration and
Production, and Marine Services.

REFINING AND MARKETING

1996 1995 1994
--------- --------- ---------
(DOLLARS IN MILLIONS EXCEPT PER
BARREL AMOUNTS)

GROSS OPERATING REVENUES
Refined products.......................................... $ 620.8 664.5 582.7
Other, primarily crude oil resales and merchandise........ 124.6 106.5 104.3
------- ------- -------
Gross Operating Revenues.......................... $ 745.4 771.0 687.0
======= ======= =======
OPERATING PROFIT
Gross margin -- refined products.......................... $ 94.0 85.3 85.3
Gross margin -- other..................................... 13.3 12.3 13.1
------- ------- -------
Gross margin...................................... 107.3 97.6 98.4
Operating expenses........................................ 87.9 84.7 88.2
Depreciation and amortization............................. 12.5 11.9 10.4
Other, including gain (loss) on asset sales............... (.9) (.3) 2.6
------- ------- -------
Operating Profit.................................. $ 6.0 .7 2.4
======= ======= =======
CAPITAL EXPENDITURES........................................ $ 11.1 9.3 32.0
======= ======= =======
REFINERY OPERATIONS -- THROUGHPUT (average daily barrels)... 47,486 50,569 46,032
======= ======= =======
REFINERY OPERATIONS -- PRODUCTION (average daily barrels)
Gasoline.................................................. 12,763 14,298 11,728
Middle distillates........................................ 19,975 20,693 18,402
Heavy oils and residual products.......................... 13,739 14,516 15,118
Other..................................................... 2,600 2,489 2,213
------- ------- -------
Total Refinery Production......................... 49,077 51,996 47,461
======= ======= =======
REFINERY OPERATIONS -- PRODUCT SPREAD ($/barrel)(1)
Average yield value of products manufactured.............. $ 24.61 20.35 19.48
Cost of raw materials..................................... 19.80 16.88 15.65
------- ------- -------
Refinery Product Spread........................... $ 4.81 3.47 3.83
======= ======= =======
REFINING AND MARKETING -- TOTAL PRODUCT SALES (average daily
barrels)(2)
Gasoline.................................................. 17,427 24,526 23,191
Middle distillates........................................ 29,651 37,988 33,256
Heavy oils and residual products.......................... 15,089 14,787 14,228
------- ------- -------
Total Product Sales............................... 62,167 77,301 70,675
======= ======= =======
REFINING AND MARKETING -- TOTAL PRODUCT SALES PRICES
($/barrel)
Gasoline.................................................. $ 32.72 28.21 27.03
Middle distillates........................................ $ 29.01 24.40 24.47
Heavy oils and residual products.......................... $ 17.61 13.66 10.93

24
25

1996 1995 1994
--------- --------- ---------
(DOLLARS IN MILLIONS EXCEPT PER
BARREL AMOUNTS)

REFINING AND MARKETING -- GROSS MARGINS ON TOTAL PRODUCT
SALES ($/barrel)(3)
Average sales price....................................... $ 27.28 23.55 22.59
Average costs of sales.................................... 23.15 20.53 19.67
------- ------- -------
Gross Margin...................................... $ 4.13 3.02 2.92
======= ======= =======

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

(1) Refinery product spread represents the excess of yield value of the products
manufactured at the refinery over the cost of raw materials used to
manufacture such products.

(2) Sources of total product sales include products manufactured at the
refinery, products drawn from inventory balances and products purchased from
third parties. The Company's purchases of refined products for resale were
approximately 11,600; 25,500; and 27,200 average daily barrels for 1996,
1995 and 1994, respectively.

(3) Margins on sales of purchased products, together with the effect of changes
in inventories, are included in the gross margin on total product sales.
Computations of average costs of sales per barrel in 1994 exclude the
benefits of an $8.5 million tariff refund and $1.5 million favorable
feedstock cost adjustments.

1996 Compared to 1995. Results from the Company's Refining and Marketing
segment improved during 1996 with operating profit of $6.0 million, compared to
operating profit of $.7 million in 1995. This improvement was achieved during a
year when the industry was facing rapidly rising prices in the crude oil market.
In addition, the Company's production level at the refinery was reduced in
September 1996 for a scheduled 30-day maintenance downtime. Despite these
factors, the Company was able to achieve a refinery product spread of $4.81 per
barrel for 1996, compared to $3.47 per barrel in 1995. The Company's results
were helped by its initiatives to control costs, improve its refinery product
slate and expand the marketing program for its refined products. The Company's
refined product yield values increased by 21% to $24.61 per barrel in 1996, from
$20.35 per barrel in 1995, while the Company's feedstock costs increased by 17%
to $19.80 per barrel in 1996 from $16.88 per barrel in 1995.

During 1996, the Company's production of refined products declined in total
by 6%, which included the impact of the scheduled maintenance period. Of this
decline, gasoline production decreased by 11% and middle distillates, consisting
of jet fuel and diesel fuel, decreased by only 3%. These reductions reflected
the change of a hydrocracker catalyst, during the maintenance period, which
allows for increased production of jet fuel and reduced production of gasoline,
beginning in the fourth quarter of 1996, which better matches the Company's
product supply with demand in Alaska. To further improve the refinery's
feedstock and product slate, the Company intends to modify the refinery
hydrocracker during 1997, at an estimated cost of $17 million. In conjunction
with the modification and other initiatives, a refinery downtime of
approximately 30 days is anticipated during 1997.

The Company continued its marketing efforts during 1996, adding 31
locations in Alaska and 8 locations in the Pacific Northwest, bringing the total
to 188 branded, unbranded and Company-owned retail outlets in Alaska and 18
branded stations in the Pacific Northwest. Two uneconomic outlets in these areas
were closed in 1996. In addition, the Company began producing and marketing
liquid asphalt, a heavy product remaining after the refining process, which is a
seasonal product in Alaska. Export sales of refined products, including sales to
the Russian Far East, amounted to $22.0 million in 1996 and $18.5 million in
1995.

Revenues from sales of refined products in the Company's Refining and
Marketing segment decreased in 1996 due primarily to a 20% decline in sales
volumes, partially offset by a 16% increase in average sales prices. Total
refined product sales averaged 62,167 barrels per day in 1996 as compared to
77,301 barrels per day in 1995. This decline reflected the lower production
volumes and the Company's withdrawal from certain West Coast markets during
1996, which also reduced the Company's purchases from other refiners and
suppliers to 11,600 barrels per day in 1996 as compared to 25,500 barrels per
day in 1995. The Company plans to sell its Company-owned facilities in
California. One of these facilities was sold in 1996 resulting in a loss of

25
26

$.8 million; two facilities remain for sale at year-end 1996. The Company at
times resells previously purchased crude oil, sales of which increased to $93.8
million in 1996, compared to $75.8 million in 1995, due primarily to higher
crude oil prices and in part due to sales of excess crude supply volumes during
the maintenance period. Costs of sales decreased in 1996 due to lower volumes of
refined products, partially offset by higher prices for crude oil and refined
products. Operating expenses were higher in 1996 due primarily to higher
environmental and employee costs partially offset by lower insurance costs.

Although results from the Company's Refining and Marketing segment for 1996
improved over 1995 levels, future profitability of this segment will continue to
be significantly influenced by market conditions, particularly as these
conditions influence costs of crude oil relative to prices received for sales of
refined products, and other additional factors that are beyond the control of
the Company.

1995 Compared to 1994. The Refining and Marketing's segment operating
profit of $.7 million in 1995 decreased $1.7 million from operating profit of
$2.4 million in 1994. Results for 1994 benefited from an $8.5 million refund
received in settlement of a tariff dispute, a gain of $2.4 million from the sale
of assets and favorable feedstock cost adjustments of $1.5 million, partially
offset by $6.6 million for environmental contingencies and other matters.
Excluding these items from 1994, operating profit in 1995 reflected an
improvement of $4.1 million from the 1994 operating results.

The Company's average feedstock costs increased by 8%, to $16.88 per barrel
in 1995 from $15.65 per barrel in 1994, while the average yield value of the
Company's refinery production increased by only 4%, to $20.35 per barrel in 1995
from $19.48 per barrel in 1994. Increased demand for Alaska North Slope ("ANS")
crude oil for use as a feedstock in West Coast refineries and declining
production volumes of ANS, combined with an oversupply of products in Alaska and
on the West Coast, resulted in higher feedstock costs for the Company relative
to increases in refined product sales prices. As a result, the Company's refined
product margins were depressed in 1995.

The start-up in December 1994 of a vacuum unit at the Company's refinery
increased the yield of higher-valued products during 1995 and lessened the
impact of these industry conditions on the Company's refinery spread. The
Company's refinery yield of residual products was reduced to 18% of total
production in 1995 from 32% of total production in 1994. In addition, margins on
sales of inventories and purchased volumes combined to improve the segment's
gross margins on total product sales to $3.02 per barrel in 1995, compared to
$2.92 per barrel in 1994.

The Company's total refinery production increased by 10%, including a 22%
increase in gasoline volumes and a 12% increase in middle distillates volumes.
Accordingly, in 1995, the Company implemented initiatives that increased the
demand for the refinery's production and improved the refinery's capacity
utilization and efficiencies. In these regards, the Company expanded its
marketing efforts by branding and rebranding sales outlets in Alaska and the
Pacific Northwest and by exporting refined products to the Far East, including
Russia. Revenues from export sales totaled $18.5 million in 1995 compared to
$5.2 million in 1994. The Company's total product sales increased to 77,301
average barrels per day in 1995 from 70,675 average barrels per day in 1994.

Revenues from sales of refined products in 1995 were higher than in 1994
due to higher sales prices and the increase in sales volumes. Resales of crude
oil aggregated $75.8 million in 1995 and $72.3 million in 1994. Costs of sales
were higher in 1995 due to higher volumes and prices. Operating expenses
decreased by $3.5 million in 1995 primarily due to lower environmental costs,
partly offset by increased employee costs and fuels and utilities expense.
Depreciation and amortization increased by $1.5 million in 1995 due to capital
additions, primarily the vacuum unit, completed in late 1994. Included in 1994
was a $2.4 million gain from the sale of assets.

26
27

EXPLORATION AND PRODUCTION

1996 1995 1994
------- ------- ------
(DOLLARS IN MILLIONS EXCEPT
PER UNIT AMOUNTS)

U.S. OIL AND GAS
Gross operating revenues.................................. $ 88.4 107.3 87.5
Production costs.......................................... 5.3 12.0 9.0
Administrative support and other operating expenses....... 3.5 2.9 2.3
Depreciation, depletion and amortization.................. 25.3 29.0 24.1
Income from settlement of a natural gas contract(1)....... 60.0 -- --
Gain on sale of assets and other income................... 4.8 33.5 --
------- ------- ------
Operating Profit -- U.S. Oil and Gas.............. 119.1 96.9 52.1
------- ------- ------
U.S. GAS TRANSPORTATION
Gross operating revenues.................................. 5.4 5.7 3.1
Operating expenses........................................ .3 .3 --
Depreciation and amortization............................. .3 .3 .2
------- ------- ------
Operating Profit -- U.S. Gas Transportation....... 4.8 5.1 2.9
------- ------- ------
BOLIVIA OIL AND GAS
Gross operating revenues.................................. 13.7 11.7 13.2
Production costs.......................................... .8 .6 .6
Administrative support and other operating expenses....... 2.8 3.2 3.3
Depreciation, depletion and amortization.................. 1.3 .3 --
------- ------- ------
Operating Profit -- Bolivia....................... 8.8 7.6 9.3
------- ------- ------
TOTAL OPERATING PROFIT -- EXPLORATION AND PRODUCTION........ $ 132.7 109.6 64.3
======= ======= ======
U.S.
Capital expenditures (including U.S. gas
transportation)........................................ $ 59.7 49.6 65.6
======= ======= ======
Net natural gas production (average daily Mcf) --
Spot market and other(2)............................... 76,857 94,668 65,841
Tennessee Gas Contract(1).............................. 10,797 19,822 17,955
------- ------- ------
Total Production.................................. 87,654 114,490 83,796
======= ======= ======
Average natural gas sales price ($/Mcf) --
Spot market............................................ $ 1.95 1.34 1.48
Tennessee Gas Contract(1).............................. $ 8.41 8.41 7.93
Average................................................ $ 2.75 2.57 2.86

Average operating expenses ($/Mcfe) --
Lease operating expenses............................... $ .14 .11 .11
Severance taxes........................................ .03 .18 .18
------- ------- ------
Total production costs............................ .17 .29 .29
Administrative support................................. .10 .06 .08
------- ------- ------
Total operating expenses.......................... $ .27 .35 .37
======= ======= ======
Depletion ($/Mcfe)........................................ $ .79 .69 .79

27
28

1996 1995 1994
--------- --------- ---------
(DOLLARS IN MILLIONS EXCEPT
PER UNIT AMOUNTS)

BOLIVIA
Capital expenditures......................................................... $ 6.9 3.8 --
Net natural gas production (average daily Mcf)............................... 20,251 18,650 22,082
Average natural gas sales price ($/Mcf)...................................... $ 1.33 1.28 1.20
Net condensate production (average daily barrels)............................ 584 567 733
Average condensate sales price ($/barrel).................................... $ 17.98 14.39 13.28
Average operating expenses ($/Mcfe) --
Production costs.......................................................... $ .10 .07 .06
Value-added taxes......................................................... .05 .06 .10
Administrative support.................................................... .27 .35 .25
--------- --------- ---------
Total operating expenses............................................. $ .42 .48 .41
========= ========= =========
Depletion ($/Mcfe)........................................................... $ .15 .03 --

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

(1) See Note D of Notes to Consolidated Financial Statements in Item 8 for
information related to the Tennessee Gas Contract.

(2) Includes 24,500 Mcf per day in 1995 related to certain interests in the Bob
West Field that were sold in the 1995 third quarter (see Note C of Notes to
Consolidated Financial Statements in Item 8).

(3) Mcf is defined as one thousand cubic feet; Mcfe is defined as net equivalent
one thousand cubic feet.

EXPLORATION AND PRODUCTION -- UNITED STATES

1996 Compared to 1995. Operating profit of $119.1 million from the
Company's U.S. oil and gas operations in 1996 increased $22.2 million from
operating profit of $96.9 million in 1995. Comparability between these years was
impacted by several major transactions in 1996, which will also impact future
results of operations. These transactions included the favorable resolution in
August 1996 of litigation with Tennessee Gas Pipeline Company ("Tennessee Gas")
regarding a natural gas purchase and sales contract ("Tennessee Gas Contract")
and the termination of the remainder of such contract in December 1996. As
provided for in the Tennessee Gas Contract, which was to expire in January 1999,
the Company was selling a portion of the gas produced in the Bob West Field
pursuant to a contract price ("Contract Price"), which was above the average
spot market price. In total, during 1996 the Company received approximately $120
million in cash for the resolution of litigation and termination of the
Tennessee Gas Contract, with the Company's Exploration and Production segment
recording operating profit of $60 million for the termination of the contract
effective October 1, 1996. Results of operations in future years will no longer
benefit from the above-market pricing provisions of the Tennessee Gas Contract.
In 1996, 1995 and 1994, the Exploration and Production segment's operating
profit also included $24.6 million, $47.1 million and $38.9 million,
respectively, from the excess of Tennessee Gas Contract prices over spot market
prices. See Note D of Notes to Consolidated Financial Statements in Item 8 and
"Capital Resources and Liquidity" discussed below.

Additionally, during 1996, substantially all of the Company's proved
producing reserves in the Bob West Field were certified by the Texas Railroad
Commission as high-cost gas from a designated tight formation, eligible for
state severance tax exemptions from the date of first production through August
2001. Accordingly, no severance tax is recorded on current production from
exempt wells beginning in 1996 and the Company recognized income of $5 million
for retroactive refunds for production in prior years.

Operating profit for 1995 included a gain of $33 million from the sale of
certain interests in the Bob West Field (see Note C of Notes to Consolidated
Financial Statements in Item 8). Excluding these significant transactions and
the impact of the incremental contract value from both years, operating profit
from the Company's U.S. oil and gas operations for 1996 would have been $29
million compared to $16 million for 1995. This resulting increase was primarily
due to higher spot market prices for sales of natural gas, as industry demand
increased due to unusually cold weather combined with below-normal storage
levels.

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Prices realized by the Company on its spot natural gas production increased
46% to $1.95 per Mcf in 1996 from $1.34 per Mcf in 1995. Excluding 24,500 Mcf
per day related to the sold interests from 1995, the Company's spot production
increased by 6,600 Mcf per day. The Company's exploration and acquisition
programs outside of the Bob West Field contributed 3,800 Mcf per day of the
increase in spot production with the remaining increase attributable to sales to
Tennessee Gas at spot prices effective October 1, 1996. The Company's weighted
average sales price, which included the above-market pricing of the Tennessee
Gas Contract through October 1, 1996, increased 7% to $2.75 per Mcf in 1996 as
compared to $2.57 per Mcf in 1995. For the Bob West Field, production declined
by 6,100 Mcf per day after excluding amounts related to sold interests in 1995.

Gross operating revenues from the Company's U.S. oil and gas operations,
after excluding $11.7 million related to the sold interests from 1995 and
excluding price agreements discussed below, decreased by $3.8 million due
primarily to the decline in volumes sold under the Tennessee Gas Contract,
partially offset by increases in spot market sales prices and production. The
decline in production costs of $6.7 million, or $.12 per Mcf, was mainly
attributable to the severance tax exemptions in the Bob West Field. Total
depreciation, depletion and amortization was lower in 1996 due to lower
production volumes, partially offset by a higher depletion rate.

The Company enters into commodity price agreements to reduce the risk
caused by fluctuation in the prices of natural gas in the spot market. During
1996 and 1995, the Company used such agreements to set the price of 30% and 38%,
respectively, of the natural gas production that it sold in the spot market. The
Company recognized a loss of $3.1 million ($.11 per Mcf) in 1996 and a gain of
$.3 million ($.01 per Mcf) in 1995 related to these price agreements. As of
January 9, 1997, the Company had entered into price agreements for 1997
production totaling .9 Bcf of gas for an average Houston Ship Channel price of
$2.18 per Mcf. In addition, the Company has entered into price agreements with
collars, under which no payment will be made by either party unless the price
falls below a designated floor price or above a designated ceiling price, at
which time the Company receives or pays the difference, respectively. The
Company has entered into price agreements with collars for 1997 production
totaling 1.8 Bcf of gas with an average Houston Ship Channel floor price of
$1.93 per Mcf and a ceiling price of $2.42 per Mcf. See Note N of Notes to
Consolidated Financial Statements in Item 8 for further information on the price
agreements.

In addition to the natural gas and oil producing activities, the Company's
results included revenues of $5.4 million and operating profit of $4.8 million
in 1996 for transportation of natural gas to common carrier pipelines in the
South Texas area, of which approximately 50% relates to transportation of the
Company's production. These amounts were relatively unchanged from the prior
year.

1995 Compared to 1994. Operating profit of $96.9 million in 1995 from the
Company's U.S. oil and gas operations included a gain of approximately $33
million from the sale of certain interests in the Bob West Field. Excluding this
gain, operating profit from these operations would have been approximately $63
million in 1995 compared with $52 million in 1994, reflecting a continued
successful drilling program which resulted in an increase in the Company's U.S.
natural gas production in South Texas. After the sale of certain Bob West Field
interests in September 1995, which included interests in 14 gross producing
wells, the number of wells in which the Company had an interest was reduced to
57 at year-end 1995, compared with 48 producing wells at year-end 1994. The
Company's U.S. natural gas production sold into the spot market increased by 44%
and production sold under the Tennessee Gas Contract increased by 10%. Revenues
increased by $20 million due to these increases in production, but were
partially offset by lower spot market natural gas sales prices. The Company's
weighted average sales price decreased to $2.57 per Mcf during 1995 from $2.86
per Mcf in 1994, reflecting lower spot market sales prices and a lower
percentage of production sold to Tennessee Gas at above-market prices. In 1995,
approximately 17% of the Company's total U.S. production was sold to Tennessee
Gas, compared to 21% in 1994 and 27% in 1993. Total production costs and other
operating expenses were higher in 1995 due to the increased production levels
and severance taxes related to the above-market pricing of sales to Tennessee
Gas, but were relatively unchanged on a per Mcf basis. The impact of the
increased production volumes on depletion expense was substantially offset by a
13% reduction in the depletion rate which resulted from additions to proved
reserves during the year and elimination of proportionately higher future
development costs on the reserves sold in the Bob West Field.

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In 1995, operating results from the Exploration and Production segment
included natural gas production of approximately 24 Mmcf per day, revenues of
$11.7 million and operating profit of $4 million related to the interests that
were sold in the Bob West Field.

Operating results from the Company's natural gas transportation operations
increased by $2.2 million in 1995 due to higher transmission volumes associated
with the increased production levels in South Texas. Transportation of the
Company's production accounted for approximately 51% and 58% of these results in
1995 and 1994, respectively.

EXPLORATION AND PRODUCTION -- BOLIVIA

1996 Compared to 1995. Operating profit from the Company's Bolivian
operations increased to $8.8 million in 1996, from the $7.6 million operating
profit in 1995. This improvement was primarily due to a 9% increase in
production of natural gas together with higher prices received for both natural
gas and condensate. During the second and third quarters of 1996, the Company
benefited from increased demand from the Bolivian state-owned oil and gas
company for higher quality natural gas, in order to meet contract specifications
for exports to Argentina, together with the inability of another producer to
meet supply requirements. Total operating expenses declined by 12% on a per unit
basis reflecting a 6% decrease in costs combined with the increase in volumes.
Partially offsetting these improvements was an increase in depreciation,
depletion and amortization of $1.0 million.

In 1996, a new Hydrocarbons Law was passed by the Bolivian government that
significantly impacts the Company's operations in Bolivia. The new law, among
other matters, granted the Company the option to convert its Contracts of
Operation to new Shared Risk Contracts. During 1996, the Company signed
agreements to convert its Contracts of Operation to Shared Risk Contracts
subject to recision at the option of the Company if the Company is not satisfied
with modifications to the Bolivian fiscal law. The Company expects to complete
this conversion during the first half of 1997. The new contracts extend the
Company's term of operation, provide more favorable acreage relinquishment terms
and provide for a more favorable fiscal regime of royalties and taxes. The new
contracts will extend the term of the Company's operations for Block 18 ten
additional years to the year 2017. For Block 20, the new contract extends the
Company's term 21 additional years to the year 2029 for acreage that is in the
exploration phase of the contract, and ten additional years to the year 2018 for
an area within Block 20 that is designated as being in the development phase of
the new contract. The new contract provisions, along with a substantial
discovery during 1996, significantly increased the Company's reserves (see Note
O of Notes to Consolidated Financial Statements in Item 8).

The Company's Bolivian natural gas production is sold to Yacimientos
Petroliferos Fiscales Bolivianos ("YPFB"), which in turn sells the natural gas
to Yacimientos Petroliferos Fiscales, S.A. ("YPF"), a publicly-held company
based in Argentina. During 1994, the contract between YPFB and YPF was extended
through March 31, 1997, maintaining approximately the same volumes as the
previous contract. YPFB and YPF are currently negotiating a new two-year
contract through March 1999. Currently, the Company is selling its natural gas
production to YPFB based on the volume and pricing terms in the contract between
YPFB and YPF.

1995 Compared to 1994. In 1995, operating profit from the Company's
Bolivian operations decreased by $1.7 million, reflecting a 16% decrease in net
natural gas production. During 1994, the Company had benefited from higher
levels of production due to the inability of another producer to satisfy gas
supply requirements. Partially offsetting the decrease in production in 1995
were increases in the average prices of natural gas and condensate production.

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MARINE SERVICES

1996 1995 1994
------ ------ ------
(DOLLARS IN MILLIONS)

GROSS OPERATING REVENUES
Fuels, lubricants and other............................... $111.6 71.4 75.2
Services.................................................. 10.9 3.1 2.7
------ ------ ------
Gross Operating Revenues.......................... $122.5 74.5 77.9
====== ====== ======
OPERATING PROFIT
Gross profit.............................................. $ 29.5 9.6 10.4
Operating and other expenses.............................. 22.2 13.7 12.4
Depreciation and amortization............................. 1.2 .3 .3
------ ------ ------
Operating Profit (Loss)........................... $ 6.1 (4.4) (2.3)
====== ====== ======
CAPITAL EXPENDITURES (excluding acquisitions)............... $ 6.9 .4 .2
====== ====== ======
FUEL SALES, PRIMARILY DIESEL (millions of gallons).......... 142.7 112.5 119.2
====== ====== ======
NUMBER OF TERMINALS......................................... 20 14 17

1996 Compared to 1995. On February 20, 1996, the Company acquired Coastwide
Energy Services, Inc. ("Coastwide") and combined these operations with the
Company's marine petroleum products distribution business, forming a Marine
Services segment. As a combined operation, the Marine Services segment is a
marketer and distributor of diesel fuel and lubricants and a provider of
logistical services to the offshore exploration and production industry in the
Gulf of Mexico. Operating results from Coastwide have been included in the
Company's Marine Services segment since the date of acquisition. See Note C of
Notes to Consolidated Financial Statements in Item 8.

The Marine Services segment currently consists of 20 terminals, compared to
14 at the prior year-end. The added locations and associated volumes, mainly
related to the Coastwide acquisition, combined with higher fuel prices have
contributed to an increase of $40.2 million in fuels and lubricants revenues. In
addition, revenues from services has grown by $7.8 million. These increases in
revenues together with improved margins during 1996 were partially offset by
higher operating and other expenses associated with the increased activity.
Depreciation and amortization increased during 1996 due to capital additions
during the year. In total, results for the Marine Services segment reflected a
turnaround from the losses incurred in the prior year with operating profit of
$6.1 million for 1996.

The Marine Services segment's business is largely dependent upon the volume
of oil and gas drilling, workover, construction and seismic activity in the Gulf
of Mexico. During 1996, 1995 and 1994, wells drilled in the Gulf of Mexico
totaled 1,068, 1,024 and 958, respectively.

1995 Compared to 1994. In 1995, the Company consolidated certain operations
by exiting the land-based portion of its petroleum product distribution
business, reducing the total number of Company sites to 14, primarily
marine-based, at year-end. In these regards, four Texas locations were sold in
1995. Included in operating and other expenses in 1995 was a charge of $.8
million related to employee terminations and other exit costs. Revenues and
costs of sales were lower in 1995 due to reduced volumes while these operations
were being consolidated.

GENERAL AND ADMINISTRATIVE EXPENSES

General and administrative expenses of $12.7 million in 1996 compare with
$16.4 million in 1995 and $14.7 million in 1994. The decrease in 1996 was
primarily due to lower employee and labor costs resulting from cost reduction
measures implemented by the Company in late 1995. When comparing 1995 to 1994,
the increase was primarily due to higher employee and other benefits costs.

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INTEREST EXPENSE AND INTEREST INCOME

Interest expense of $15.4 million in 1996 compares with $20.9 million in
1995 and $18.7 million in 1994. The Company's redemption of public debt of $74.1
million in November 1996 and $34.6 million in December 1995 contributed to
interest expense savings of $5.9 million in 1996, equating to future interest
savings of approximately $10 million annually. The increase in 1995, compared to
1994, was primarily due to interest on the refinery vacuum unit financing and
cash borrowings under the corporate revolving credit facility during 1995 and
interest capitalized in 1994 related to the construction of the vacuum unit.

In September 1996, the Company received and recorded interest income of
approximately $7 million from Tennessee Gas in conjunction with the collection
of a receivable that resulted from underpayment for natural gas sold in prior
periods (see Note D of Notes to Consolidated Financial Statements in Item 8).

OTHER EXPENSE

Other expense of $10.0 million in 1996 compares with $8.5 million in 1995
and $7.4 million in 1994. The increase in 1996 included costs of $2.3 million
related to a shareholder consent solicitation which was resolved in April 1996
together with a write-off of deferred financing costs and higher environmental
and other costs related to the Company's former operations, partially offset by
lower employee termination and restructuring costs. The increase in 1995,
compared with 1994, was primarily due to severance costs and related benefits of
$3.8 million resulting from a reduction in administrative workforce and other
employee terminations (see Note J of Notes to Consolidated Financial Statements
in Item 8), partially offset by lower environmental and other expenses related
to the Company's former operations.

INCOME TAXES

Income taxes of $38.3 million in 1996 compare with $4.4 million in 1995 and
$5.6 million in 1994. The Company's effective tax rate increased to 33% in 1996,
compared to a 7% effective rate in 1995, due to earnings subject to U.S. taxes
in 1996 exceeding available net operating loss and tax credit carryforwards. The
decrease in income taxes in 1995, compared with 1994, was primarily due to lower
state income taxes.

IMPACT OF CHANGING PRICES

The Company's operating results and cash flows are sensitive to volatile
changes in energy prices. Major shifts in the cost of crude oil used for
refinery feedstocks and the price of refined products can result in a change in
gross margin from the refining and marketing operations, as prices received for
refined products may or may not keep pace with changes in crude oil costs. These
energy prices, together with volume levels, also determine the carrying value of
crude oil and refined product inventory. The Company uses the last-in, first-out
("LIFO") method of accounting for inventories of crude oil and U.S. wholesale
refined products. This method results in inventory carrying amounts that are
less likely to represent current values and in costs of sales which more closely
represent current costs.

Likewise, changes in natural gas prices impact revenues and the present
value of estimated future net revenues and cash flows from the Company's
exploration and production operations. The Company may increase or decrease its
natural gas production in response to market conditions. The carrying value of
oil and gas assets may be subject to noncash writedowns based on changes in
natural gas prices and other determining factors.

Changes in natural gas prices also influence the level of drilling activity
in the Gulf of Mexico. The Company's marine services operation, whose customers
include offshore drilling contractors and related industries, could be impacted
by significant fluctuations in natural gas prices.

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CAPITAL RESOURCES AND LIQUIDITY

OVERVIEW

The Company's primary sources of liquidity are its cash and cash
equivalents, internal cash generation and external financing. During 1996, these
sources were significantly enhanced with the (i) receipt of $67.7 million for
the favorable resolution of the Tennessee Gas litigation in August 1996 and (ii)
the receipt of $51.8 million for the termination of the Tennessee Gas Contract
effective October 1, 1996 (see Note D of Notes to Consolidated Financial
Statements in Item 8). Although the resolution of the litigation and termination
of the remainder of the Tennessee Gas Contract will cause a decrease in the
Company's average natural gas sales prices in future years, it removed a major
financial uncertainty from the Company's capital structure, which improves the
predictability of the Company's cash flows, provides for additional financial
flexibility, and allows the Company to focus on growth initiatives. Furthermore,
during 1996, the Company achieved improvement in profitability from all of its
business segments. Cash flows from operations of $179 million in 1996, which
included approximately $120 million received from Tennessee Gas discussed above,
were used in part to fully redeem the Company's two public debt issues and to
finance the Company's capital expenditure program. The redemption of debt
strengthened the Company's financial condition, reducing the debt-to-capital
ratio to 21% and lowering interest expense (see Note I of Notes to Consolidated
Financial Statements in Item 8). The resolution of the litigation and
termination of the remainder of the Tennessee Gas Contract together with the
lower debt position have improved the Company's ability to access capital
markets.

The Company continues to assess its existing asset base in order to
maximize returns and develop full value through strategic diversification and
acquisitions in all of its operating segments. This ongoing assessment includes,
in the Exploration and Production segment, evaluating ways in which the Company
could diversify the mix of its oil and gas reserves and offset the impact of
declining production through domestic development, exploration and acquisition
activity outside of the Bob West Field. In the Refining and Marketing segment,
the Company has been engaged in studies to improve profitability and has also
evaluated possible joint ventures, strategic alliances or business combinations;
such evaluations have not resulted in any transaction but operating strategies
have been developed to optimize the product and feedstock slates, improve
efficiencies and reliability, and expand marketing to increase placement of
products in Alaska. The Company continues to evaluate its Marine Services
segment, pursuing opportunities for expansion as well as optimizing existing
operations. In these regards, during 1996, the Company made significant progress
with each of its operating segments contributing to improved profitability. In
1996, the Company acquired Coastwide for approximately 1.4 million shares of
Tesoro's Common Stock and $7.7 million in cash and purchased exploration and
production properties, proved and unproved, outside of the Bob West Field for
$25.7 million (see Note C of Notes to Consolidated Financial Statements in Item
8).

The Company operates in an environment where its liquidity and capital
resources are impacted by changes in the supply of and demand for crude oil,
natural gas and refined petroleum products, market uncertainty and a variety of
additional risks that are beyond the control of the Company. These risks
include, among others, the level of consumer product demand, weather conditions,
the proximity of the Company's natural gas reserves to pipelines, the capacities
of such pipelines, fluctuations in seasonal demand, governmental regulations,
the price and availability of alternative fuels and overall market and economic
conditions. The Company's future capital expenditures as well as borrowings
under its credit facility and other sources of capital will be affected by these
conditions.

CREDIT ARRANGEMENTS

In June 1996, the Company amended and restated its corporate revolving
credit agreement ("Credit Facility"), expiring in April 2000, which provides
total commitments of $150 million from a consortium of nine banks. The Credit
Facility provides for cash borrowings up to $100 million and issuance of letters
of credit up to a borrowing base (which was approximately $141 million at
December 31, 1996). The Credit Facility replaced a higher-cost $90 million
facility and provides the Company with more financial flexibility, including
lower interest rates, reduced fees on letters of credit, elimination of certain
restrictive financial tests,

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34

an increased borrowing base, increased cash borrowing availability, and the
right to enter into non-recourse or limited financings for certain subsidiaries.
The Company, at its option, has currently activated total commitments of $100
million.

At December 31, 1996, the Company had outstanding letters of credit of $33
million with no cash borrowings outstanding. Outstanding obligations under the
Credit Facility are secured by liens on substantially all of the Company's trade
accounts receivable and product inventory and by mortgages on the Company's
refinery and South Texas natural gas reserves. Under the terms of the Credit
Facility, the Company is required to maintain specified levels of consolidated
working capital, tangible net worth, cash flow and interest coverage. Among
other matters, the Credit Facility contains covenants which limit the incurrence
of additional indebtedness and restricted payments.

Although the terms of the Credit Facility allow for the payment of cash
dividends subject to a cumulative amount available for dividend payments (which
is defined as the difference of (i) the sum since December 31, 1995, of (a) $5
million and (b) 50% of consolidated net earnings of the Company in any calendar
year and (ii) any amount previously paid for dividends since June 1996), cash
dividends cannot exceed a maximum of $5 million annually. The Credit Facility
also permits the Company to repurchase a limited amount of Common Stock for
oddlot buyback programs, employee benefit plans and open market repurchases. The
Board of Directors has no present plans to pay dividends. However, from time to
time, the Board of Directors reevaluates the feasibility of declaring future
dividends.

In November 1996, a subsidiary of the Company entered into a loan facility
with a bank, which provides a three-year line of credit up to $10 million to the
Marine Services segment for the purchase of real estate and equipment at the
bank's prime rate. The loan facility, which is subject to a borrowing base, is
not guaranteed by the Company and is secured only by such real estate and
equipment that are financed. Beginning in March 1998, credit availability is
reduced quarterly by 6.667%. At December 31, 1996, $.9 million was outstanding
under the loan facility.

DEBT AND OTHER OBLIGATIONS

Under an agreement reached in 1993, which settled a contractual dispute
with the State of Alaska ("State"), the Company is obligated to make variable
monthly payments to the State through December 2001 based on a per barrel charge
on the volume of feedstock processed at the Company's refinery. In 1995 and
1994, based on a per barrel throughput charge of 16 cents, the Company's
variable payments to the State amounted to $2.9 million and $2.8 million,
respectively. The per barrel charge increased to 24 cents in 1996 with the
Company's variable payment to the State totaling $4.0 million in the year. The
per barrel charge of 24 cents in 1997 increases to 30 cents in 1998 with one
cent annual incremental increases thereafter through 2001. In January 2002, the
Company is obligated to pay the State $60 million; provided, however, that such
payment may be deferred indefinitely by continuing the variable monthly payments
to the State beginning at 34 cents per barrel for 2002 and increasing one cent
per barrel annually thereafter. Variable monthly payments made after January
2002 will not reduce the $60 million obligation to the State. The $60 million
obligation is evidenced by a security bond, and the bond and the throughput
barrel obligations are secured by a mortgage on the Company's refinery. The
Company's obligations under the agreement with the State and the mortgage are
subordinated to current and future senior debt of up to $175 million plus any
indebtedness incurred subsequent to the date of the agreement to improve the
Company's refinery.

CAPITAL SPENDING

Capital spending in 1996 amounted to $85 million, which was funded from
available cash reserves, cash flows from operations and borrowings under
revolving credit lines. Capital expenditures for the Company's Exploration and
Production segment were approximately $67 million, including $26 million for
proved and unproved property acquisitions, $22 million for development and $19
million for exploration. During 1996, the Company participated in the drilling
of 16 development wells and 6 exploratory wells in the U.S. and two exploratory
wells in Bolivia. Capital projects for the Company's Refining and Marketing
operations in 1996 totaled $11 million, primarily for installation of facilities
to produce and market asphalt, improvements and

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upgrades at the refinery and expansion of its retail marketing facilities. In
the Marine Services segment, capital spending totaled $7 million during 1996
(excluding amounts for the Coastwide acquisition) primarily for equipment to
improve operating efficiencies.

For 1997, the Company has a total capital budget of approximately $156
million. The Exploration and Production segment accounts for $76 million, or
49%, of the budget with $68 million planned for U.S. activities and $8 million
for Bolivia. Planned U.S. expenditures include $30 million for property
acquisitions; $19 million for development drilling (participation in 19 wells)
and workovers; $9 million for leasehold, geological and geophysical; and $10
million for exploratory drilling (participation in 15 wells). In Bolivia, the
drilling program is budgeted at $2 million for one exploratory well, with the
remainder planned for three-dimensional seismic activity. Capital spending for
the Refining and Marketing segment is planned at $50 million, which includes $17
million for modification and expansion of the refinery hydrocracker to improve
the feedstock and product slate. Additionally, in 1997 the Company will direct
$20 million towards a three-year capital program to build new retail outlets and
remodel existing stations in the Refining and Marketing segment. The Marine
Services segment's capital budget is $29 million, primarily for expansion of its
operations along the Gulf of Mexico and potential acquisitions. Capital
expenditures for 1997 are expected to be financed through a combination of cash
flows from operations, available cash reserves and borrowings under revolving
credit lines.

CASH FLOWS

Components of the Company's cash flows are set forth below (in millions):

1996 1995 1994
------ ----- -----

Cash Flows From (Used In):
Operating Activities..................................... $179.0 35.4 60.3
Investing Activities..................................... (94.2) 2.4 (91.2)
Financing Activities..................................... (75.9) (37.9) 8.3
------ ----- -----
Increase (Decrease) in Cash and Cash Equivalents........... $ 8.9 (.1) (22.6)
====== ===== =====

During 1996, net cash from operating activities totaled $179 million,
compared with $35 million in 1995. This increase in operating cash flows in 1996
was primarily due to the receipt of $120 million from Tennessee Gas for the
favorable resolution of litigation in August 1996 and termination of the natural
gas purchase and sales contract effective October 1, 1996. In addition, improved
profitability plus noncash items, such as depreciation, depletion and
amortization and deferred income taxes, contributed to higher cash flows from
operations. Partially offsetting these increases were higher net working capital
balances, particularly receivables which increased due to higher year-end sales
volumes together with higher prices. Net cash used in investing activities of
$94 million in 1996 included capital expenditures of $85 million and cash
consideration of nearly $8 million for the acquisition of Coastwide. Net cash
used in financing activities of $76 million during 1996 was primarily due to the
redemption of Subordinated Debentures and Exchange Notes aggregating $74 million
together with payments of other long-term debt. During 1996, the Company's gross
borrowings and repayments under its revolving credit lines amounted to $166
million. At December 31, 1996, the Company's net working capital totaled $99
million, which included cash and cash equivalents of $23 million.

During 1995, net cash from operating activities totaled $35 million,
compared with $60 million in 1994. Although natural gas production from the
Company's South Texas operations increased during 1995, lower cash receipts for
sales of natural gas adversely affected the Company's cash flows from
operations. Net cash from investing activities of $2 million in 1995 included
proceeds of $70 million from sales of assets, primarily certain interests in the
Bob West Field, partially offset by $64 million of capital expenditures and $3
million for acquisition of the Kenai Pipe Line Company ("KPL"). Net cash used in
financing activities of $38 million in 1995 was primarily related to the
redemption of $34.6 million of Subordinated Debentures and payments of other
long-term debt. The Company's gross borrowings and repayments under the Facility
totaled $262 million during 1995.

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36

Net cash from operating activities of $60 million in 1994 included net
earnings adjusted for certain noncash charges, together with reduced working
capital requirements. Net cash used in investing activities of $91 million
during 1994 included capital expenditures of $100 million, mainly for
exploration and production activities in the Bob West Field and installation of
the vacuum unit at the Company's refinery. These uses of cash in investing
activities in 1994 were partially offset by a net decrease of $6 million in
short-term investments and cash proceeds of $3 million from sales of assets. Net
cash from financing activities of $8 million during 1994 included $15 million in
borrowings under the Vacuum Unit Loan and $4 million net proceeds from an equity
offering (see Note K of Notes to Consolidated Financial Statements in Item 8).
These financing sources of cash during 1994 were partially offset by the
repayment of net borrowings of $5 million under interim financing arrangements
early in 1994 and dividends of $2 million paid on preferred stock.

ENVIRONMENTAL AND OTHER MATTERS

The Company is subject to extensive federal, state and local environmental
laws and regulations. These laws, which change frequently, regulate the
discharge of materials into the environment and may require the Company to
remove or mitigate the environmental effects of the disposal or release of
petroleum or chemical substances at various sites or install additional controls
or other modifications or changes in use for certain emission sources. The
Company is currently involved in a remedial response and has incurred cleanup
expenditures associated with environmental matters at a number of sites,
including certain of its own properties. At December 31, 1996, the Company's
accruals for environmental expenses amounted to $8.9 million, which included a
noncurrent liability of $3.5 million for remediation of the KPL properties that
has been funded by the former owners through a restricted escrow deposit. Based
on currently available information, including the participation of other parties
or former owners in remediation actions, the Company believes these accruals are
adequate. In addition, to comply with environmental laws and regulations, the
Company anticipates that it will make capital improvements of approximately $6
million in 1997 and $3 million in 1998. The Company also expects to spend
approximately $6 million by the year 2002 for secondary containment systems for
existing storage tanks in Alaska.

Conditions that require additional expenditures may exist for various
Company sites, including, but not limited to, the Company's refinery, retail
gasoline outlets (current and closed locations) and petroleum product terminals,
and for compliance with the Clean Air Act. The amount of such future
expenditures cannot currently be determined by the Company. For further
information on environmental contingencies, see Note L of Notes to Consolidated
Financial Statements in Item 8.

CRUDE OIL PURCHASE CONTRACT

The Company has a three-year contract with the State of Alaska for the
purchase of royalty crude oil covering the period January 1, 1996 through
December 31, 1998. The contract provides for the purchase of approximately
40,000 barrels per day of ANS royalty crude oil, the primary feedstock for the
Company's refinery, and is priced based on royalty values computed by the State.
Under this agreement, the Company is required to utilize in its refinery
operations volumes equal to at least 80% of the ANS crude oil to be purchased
from the State. This contract contains provisions that, under certain
conditions, allow the Company to temporarily or permanently reduce its purchase
obligations.

FORWARD-LOOKING STATEMENTS

Statements in this Annual Report, including those contained in the
foregoing discussion and other items herein, concerning the Company which are
(a) projections of revenues, earnings, earnings per share, capital expenditures
or other financial items, (b) statements of plans and objectives for future
operations, (c) statements of future economic performance, or (d) statements of
assumptions or estimates underlying or supporting the foregoing are
forward-looking statements within the meaning of Section 27A of the Securities
Act of 1933 and Section 21E of the Securities Exchange Act of 1934. The ultimate
accuracy of forward-looking statements is subject to a wide range of business
risks and changes in circumstances, and actual results and outcomes often differ
from expectations. Any number of important factors could cause actual results to

36
37

differ materially from those in the forward-looking statements herein, including
the following: the timing and extent of changes in commodity prices and
underlying demand and availability of crude oil and other refinery feedstocks,
refined products, and natural gas; actions of our customers and competitors;
changes in the cost or availability of third-party vessels, pipelines and other
means of transporting feedstocks and products; state and federal environmental,
economic, safety and other policies and regulations, any changes therein, and
any legal or regulatory delays or other factors beyond the Company's control;
execution of planned capital projects; weather conditions affecting the
Company's operations or the areas in which the Company's products are marketed;
future well performance; the extent of Tesoro's success in acquiring oil and gas
properties and in discovering, developing and producing reserves; political
developments in foreign countries, the conditions of the capital markets and
equity markets during the periods covered by the forward-looking statements;
earthquakes or other natural disasters affecting operations; adverse rulings,
judgments, or settlements in litigation or other legal matters, including
unexpected environmental remediation costs in excess of any reserves; and
adverse changes in the credit ratings assigned to the Company's trade credit.
The Company undertakes no obligation to publicly release the result of any
revisions to any such forward-looking statements that may be made to reflect
events or circumstances after the date hereof or to reflect the occurrence of
unanticipated events.

37
38

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 as of December 31, 1996 and 1995, and the
related statements of consolidated operations, stockholders' equity and cash
flows for each of the three years in the period ended December 31, 1996. 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 generally accepted auditing
standards. 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 at December 31, 1996 and 1995, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1996, in conformity with generally accepted accounting principles.

DELOITTE & TOUCHE LLP

San Antonio, Texas
January 23, 1997

38
39

TESORO PETROLEUM CORPORATION

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

YEARS ENDED DECEMBER 31,
----------------------------------
1996 1995 1994
---------- ---------- --------

REVENUES
Refining and marketing.................................. $ 745,413 771,035 686,994
Exploration and production.............................. 107,415 124,670 103,773
Marine services......................................... 122,533 74,467 77,917
Income from settlement of a natural gas contract (Note
D)................................................... 60,000 -- --
Gain on sales of assets and other income................ 4,417 32,711 3,259
---------- ---------- --------
Total Revenues.................................. 1,039,778 1,002,883 871,943
---------- ---------- --------
OPERATING COSTS AND EXPENSES
Refining and marketing.................................. 726,029 758,329 676,697
Exploration and production.............................. 12,968 19,055 15,302
Marine services......................................... 115,314 77,803 80,507
Depreciation, depletion and amortization................ 40,627 41,776 35,041
---------- ---------- --------
Total Operating Costs and Expenses.............. 894,938 896,963 807,547
---------- ---------- --------
OPERATING PROFIT.......................................... 144,840 105,920 64,396
General and Administrative................................ (12,733) (16,453) (14,750)
Interest Expense, Net of Capitalized Interest in 1994..... (15,382) (20,902) (18,749)
Interest Income........................................... 8,423 1,845 2,522
Other Expense, Net........................................ (10,001) (8,542) (7,363)
---------- ---------- --------
EARNINGS BEFORE INCOME TAXES AND EXTRAORDINARY ITEM....... 115,147 61,868 26,056
Income Tax Provision...................................... 38,347 4,379 5,573
---------- ---------- --------
EARNINGS BEFORE EXTRAORDINARY ITEM........................ 76,800 57,489 20,483
Extraordinary Loss on Extinguishment of Debt (Net of
Income Tax Benefit of $886 in 1996)..................... (2,290) (2,857) (4,752)
---------- ---------- --------
NET EARNINGS.............................................. 74,510 54,632 15,731
Dividend Requirements on Preferred Stock.................. -- -- 2,680
---------- ---------- --------
NET EARNINGS APPLICABLE TO COMMON STOCK................... $ 74,510 54,632 13,051
========== ========== ========
EARNINGS PER SHARE
Earnings Before Extraordinary Item...................... $ 2.90 2.29 .77
Extraordinary Loss on Extinguishment of Debt, Net of
Income Tax Benefit................................... (.09) (.11) (.21)
---------- ---------- --------
Net Earnings.................................... $ 2.81 2.18 .56
========== ========== ========
WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT SHARES...... 26,499 25,107 23,196
========== ========== ========

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

39
40

TESORO PETROLEUM CORPORATION

CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS EXCEPT PER SHARE AMOUNTS)

DECEMBER 31,
-------------------
1996 1995
-------- -------

ASSETS
CURRENT ASSETS
Cash and cash equivalents................................. $ 22,796 13,941
Receivables, less allowance for doubtful accounts......... 128,013 77,534
Inventories............................................... 74,488 80,453
Prepayments and other..................................... 12,046 10,536
-------- -------
Total Current Assets.............................. 237,343 182,464
-------- -------
PROPERTY, PLANT AND EQUIPMENT
Refining and marketing.................................... 328,522 322,023
Exploration and production, full-cost method of
accounting:
Properties being amortized............................. 179,433 119,836
Properties not yet evaluated........................... 12,344 5,118
Gas transportation..................................... 6,703 6,703
Marine services........................................... 33,820 12,757
Corporate................................................. 12,531 12,443
-------- -------
573,353 478,880
Less accumulated depreciation, depletion and
amortization.......................................... 256,842 217,191
-------- -------
Net Property, Plant and Equipment...................... 316,511 261,689
-------- -------
RECEIVABLE FROM TENNESSEE GAS PIPELINE COMPANY (Note D)..... -- 50,680
-------- -------
OTHER ASSETS................................................ 28,733 24,320
-------- -------
Total Assets...................................... $582,587 519,153
======== =======

LIABILITIES AND STOCKHOLDERS' EQUITY

CURRENT LIABILITIES
Accounts payable.......................................... $ 80,747 61,389
Accrued liabilities....................................... 33,256 33,066
Current income taxes payable.............................. 13,822 1,007
Current maturities of long-term debt and other
obligations............................................ 10,043 9,473
-------- -------
Total Current Liabilities......................... 137,868 104,935
-------- -------
DEFERRED INCOME TAXES....................................... 19,151 5,389
-------- -------
OTHER LIABILITIES........................................... 42,243 37,308
-------- -------
LONG-TERM DEBT AND OTHER OBLIGATIONS, LESS CURRENT
MATURITIES................................................ 79,260 155,007
-------- -------
COMMITMENTS AND CONTINGENCIES (Note L)
STOCKHOLDERS' EQUITY
Preferred stock, no par value; authorized 5,000 shares
including redeemable preferred shares; none issued or
outstanding
Common stock, par value $.16 2/3; authorized 50,000
shares; 26,414 shares issued and outstanding (24,780 in
1995).................................................. 4,402 4,130
Additional paid-in capital................................ 189,368 176,599
Retained earnings......................................... 110,295 35,785
-------- -------
Total Stockholders' Equity............................. 304,065 216,514
-------- -------
Total Liabilities and Stockholders' Equity........ $582,587 519,153
======== =======

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

40
41

TESORO PETROLEUM CORPORATION

STATEMENTS OF CONSOLIDATED STOCKHOLDERS' EQUITY
(IN THOUSANDS)

COMMON STOCK RETAINED EARNINGS
--------------- ADDITIONAL (ACCUMULATED
SHARES AMOUNT PAID-IN CAPITAL DEFICIT)
------ ------ --------------- -----------------

DECEMBER 31, 1993............................. 14,089 $2,348 $ 86,748 $(31,898)
Recapitalization and equity offering, net
(Note K)................................. 10,265 1,710 88,481 --
Stock awards and options.................... 36 7 285 --
Net earnings................................ -- -- -- 15,731
Accrued dividends on preferred stocks....... -- -- -- (2,680)
------ ------ -------- --------
DECEMBER 31, 1994............................. 24,390 4,065 175,514 (18,847)
Stock awards and options.................... 390 65 1,085 --
Net earnings................................ -- -- -- 54,632
------ ------ -------- --------
DECEMBER 31, 1995............................. 24,780 4,130 176,599 35,785
Issuance of Common Stock for acquisition.... 1,308 218 11,054 --
Stock awards and options.................... 326 54 1,715 --
Net earnings................................ -- -- -- 74,510
------ ------ -------- --------
DECEMBER 31, 1996............................. 26,414 $4,402 $189,368 $110,295
====== ====== ======== ========

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

41
42

TESORO PETROLEUM CORPORATION

STATEMENTS OF CONSOLIDATED CASH FLOWS
(IN THOUSANDS)

YEARS ENDED DECEMBER 31,
----------------------------
1996 1995 1994
-------- ------- -------

CASH FLOWS FROM (USED IN) OPERATING ACTIVITIES
Net earnings.............................................. $ 74,510 54,632 15,731
Adjustments to reconcile net earnings to net cash from
operating activities:
Extraordinary loss on extinguishment of debt, net of
income tax benefit................................... 2,290 2,857 4,752
Depreciation, depletion and amortization............... 41,459 42,620 36,016
Loss (gain) on sales of assets......................... 835 (32,659) (2,379)
Amortization of deferred charges and other............. 1,601 1,556 2,800
Changes in operating assets and liabilities:
Receivable from Tennessee Gas Pipeline Company....... 50,680 (37,456) (13,224)
Receivables, other trade............................. (42,542) 9,746 (7,279)
Inventories.......................................... 7,210 (11,599) 5,884
Other assets......................................... (3,521) (3,573) (1,808)
Accounts payable and accrued liabilities............. 28,165 4,605 20,567
Deferred income taxes................................ 14,649 807 790
Obligation payments to State of Alaska............... (4,047) (2,892) (2,754)
Other liabilities and obligations.................... 7,673 6,769 1,201
-------- ------- -------
Net cash from operating activities................ 178,962 35,413 60,297
-------- ------- -------
CASH FLOWS FROM (USED IN) INVESTING ACTIVITIES
Capital expenditures...................................... (84,957) (63,930) (99,587)
Acquisitions (Note C)..................................... (7,720) (3,029) --
Proceeds from sales of assets............................. 2,569 69,786 2,544
Sales of short-term investments, net of $1,974 purchases
in 1994................................................ -- -- 5,952
Other..................................................... (4,092) (423) (50)
-------- ------- -------
Net cash from (used in) investing activities...... (94,200) 2,404 (91,141)
-------- ------- -------
CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES
Repurchase of debentures.................................. (74,116) (34,634) --
Payments of long-term debt................................ (3,838) (2,979) (1,383)
Net borrowings (repayments) under revolving credit
facilities............................................. 883 -- (5,000)
Issuance of long-term debt................................ -- -- 15,000
Proceeds from issuance of common stock, net............... -- -- 56,967
Repurchase of common and preferred stock.................. -- -- (52,948)
Dividends on preferred stocks............................. -- -- (1,684)
Other..................................................... 1,164 (281) (2,686)
-------- ------- -------
Net cash from (used in) financing activities...... (75,907) (37,894) 8,266
-------- ------- -------
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS............ 8,855 (77) (22,578)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR.............. 13,941 14,018 36,596
-------- ------- -------
CASH AND CASH EQUIVALENTS AT END OF YEAR.................... $ 22,796 13,941 14,018
======== ======= =======
SUPPLEMENTAL CASH FLOW DISCLOSURES
Interest paid, net of $915 capitalized in 1994............ $ 12,450 18,132 15,898
======== ======= =======
Income taxes paid......................................... $ 6,285 4,046 5,361
======== ======= =======

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

42
43

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE A -- SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation

The Consolidated Financial Statements include the accounts of Tesoro
Petroleum Corporation and its subsidiaries (collectively, the "Company" or
"Tesoro"). Tesoro is a natural resource company primarily engaged in petroleum
refining and marketing, natural gas exploration and production, marketing and
distributing of petroleum products and providing marine logistics services. All
significant intercompany accounts and transactions have been eliminated.

Use of Estimates and Presentation

The preparation of the Company's Consolidated Financial Statements required
the use of management's best estimates and judgment 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.

Certain previously reported amounts have been reclassified to conform with
the 1996 presentation.

Cash and Cash Equivalents

Cash equivalents consist of highly-liquid debt instruments such as
commercial paper and certificates of deposit purchased with an original maturity
date of three months or less. 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 institutions to
limit the amount of credit exposure in any one institution. The Company performs
ongoing evaluations of the credit standing of these financial institutions.

Inventories

Inventories are stated at the lower of cost or market. The last-in,
first-out ("LIFO") method was used to determine the cost of the Company's
inventories of crude oil and U.S. wholesale refined products. The cost of
remaining inventories was determined principally on the first-in, first-out
("FIFO") or weighted average basis. See Note F.

Property, Plant and Equipment

Additions to property, plant and equipment and major renewals and
improvements are capitalized at cost. Maintenance and repairs are charged to
operations when incurred. Depletion of oil and gas producing properties is
determined principally by the unit-of-production method and is based on
estimated recoverable reserves. Depreciation of other property, plant and
equipment is generally computed on the straight-line method based upon the
estimated useful lives of the assets, ranging from 3 years to 33 years for
refining and marketing assets and 3 years to 25 years for other assets. Salvage
values are estimated at 20% for refinery assets and 10% for other assets. Assets
recorded under capital leases and leasehold improvements are amortized on the
straight-line method over the shorter of the term of the lease or the useful
life of the related asset.

Oil and gas properties are accounted for using the full-cost method of
accounting. Under this method, all costs associated with property acquisition
and exploration and development activities are capitalized into cost centers
that are established on a country-by-country basis. For each cost center, the
capitalized costs are subject to a limitation so as not to exceed the present
value of future net revenues from estimated production of proved oil and gas
reserves net of income tax effect plus the lower of cost or estimated fair value
of unproved properties included in the cost center. Capitalized costs within a
cost center, together with estimates of costs for future development,
dismantlement and abandonment, are amortized on a unit-of-production method

43
44

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

using the proved oil and gas reserves for each cost center. The Company's
investment in certain oil and gas properties is excluded from the amortization
base until the properties are evaluated. Gain or loss is recognized only on the
sale of oil and gas properties involving significant reserves. Proceeds from the
sale of insignificant reserves and undeveloped properties are applied to reduce
the costs in the cost centers.

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.

Environmental Expenditures

Environmental expenditures that relate to current operations are expensed
or capitalized as appropriate. Expenditures that extend the life, increase the
capacity, or mitigate or prevent environmental contamination, 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 and the cost can be reasonably estimated. Such amounts are based on
the estimated timing and extent of remedial actions required by applicable
governing agencies, experience gained from similar sites on which environmental
assessments or remediation has been completed, and the amount of the Company's
anticipated liability considering the proportional liability and financial
abilities of other responsible parties. Estimated liabilities are not discounted
to present value. Generally, the timing of these accruals coincides with
completion of a feasibility study or the Company's commitment to a formal plan
of action.

Financial Instruments

The carrying amount of financial instruments including cash and cash
equivalents, accounts receivable, accounts payable and certain accrued
liabilities approximates fair value because of the short maturity of these
instruments. The carrying amount of the Company's long-term debt and other
obligations approximated the Company's estimates of the fair value of such
items.

Earnings Per Share

Earnings per share is based on the weighted average number of common shares
outstanding during the year, including the dilutive effect of common stock
equivalents, principally stock options. For 1994, the assumed conversion of
preferred stocks to common shares was anti-dilutive.

Stock-Based Compensation

The Company accounts for stock-based compensation using the intrinsic value
method prescribed in Accounting Principles Board ("APB") 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 Company has adopted the
disclosure requirements of Statement of Financial Accounting Standards ("SFAS")
No. 123, "Accounting for Stock-Based Compensation," as included in Note K.

44
45

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

NOTE B -- BUSINESS SEGMENTS

The Company's revenues are derived from three business segments: Refining
and Marketing, Exploration and Production, and Marine Services.

Refining and Marketing operates a petroleum refinery at Kenai, Alaska,
which manufactures gasoline, jet fuel, diesel fuel, heavy oils and residual
products. These products, together with products purchased from third parties,
are sold at wholesale through terminal facilities and other locations in Alaska
and the Pacific Northwest. In addition, Refining and Marketing markets gasoline,
other petroleum products and convenience store items at retail through a chain
of 7-Eleven convenience stores in Alaska. Refining and Marketing also markets
petroleum products through other branded and unbranded stations in Alaska and
the Pacific Northwest. Revenues from export sales, primarily to Far East
markets, amounted to $22.0 million, $18.5 million and $5.2 million in 1996, 1995
and 1994, respectively. The Company at times resells previously purchased crude
oil, sales of which amounted to $93.8 million, $75.8 million and $72.3 million
in 1996, 1995 and 1994, respectively.

The Exploration and Production segment is engaged in the exploration,
development and production of natural gas and oil, primarily in the Wilcox Trend
in South Texas and the Chaco Basin in Bolivia. In the U.S., the Company's focus
has recently shifted outside of the maturing Bob West Field in South Texas to
other areas. During 1996 and early 1997, the Exploration and Production segment
purchased interests in the Frio/Vicksburg Trend adjacent to the Wilcox Trend in
South Texas, the Cotton Valley Pinnacle Reef Play in East Texas and the Val
Verde Basin in Southwest Texas (see Note C). This segment also includes the
transportation of natural gas, including the Company's production, to common
carrier pipelines in the South Texas area. In Bolivia, the Company operates
through two contracts with the Bolivian government to explore for and produce
hydrocarbons. The Company's Bolivian gas production is sold under contract to
the Bolivian government for export to Argentina. The majority of the Company's
Bolivian natural gas and oil reserves are shut-in awaiting access to
gas-consuming markets. Major developments in South America indicate that new
markets may open for the Company's production in the near future, particularly
with the construction of a Bolivia-Brazil pipeline scheduled to start in late
1997, with first gas deliveries expected in 1999.

Marine Services markets and distributes petroleum products and provides
logistics services, primarily to the marine and offshore exploration and
production industries operating in the Gulf of Mexico. This segment currently
operates 20 terminals along the Texas and Louisiana Gulf Coast. For information
regarding an acquisition in this segment, see Note C. During 1995, the Company
consolidated certain operations in this segment by exiting the land-based
portion of its petroleum product distribution business, and in 1994 the Company
discontinued an environmental remediation products and services operation
formerly included in this segment.

Segment operating profit is gross operating revenues, gains and losses on
asset sales and other income less applicable segment costs of sales, operating
expenses, depreciation, depletion and other items. Income taxes, interest
expense, interest income and corporate general and administrative expenses are
not included in determining operating profit. In the Exploration and Production
segment, operating profit in 1996 included $60 million of income from
termination of a natural gas contract and $5 million for retroactive severance
tax refunds, and 1995 included a gain of $33 million from the sale of certain
interests in the Bob West Field. In 1996, 1995 and 1994, the Exploration and
Production segment's operating profit included $24.6 million, $47.1 million and
$38.9 million, respectively, from the excess of Tennessee Gas Contract prices
over spot market prices (see Note D). Operating profit from the Refining and
Marketing segment in 1994 included a gain of $2.4 million from the sale of
assets and a refund of $8.5 million for a tariff issue, partially offset by net
charges of approximately $5 million for environmental contingencies and other
matters.

45
46

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Identifiable assets are those assets utilized by the segment. Corporate
assets are principally cash, investments and other assets that cannot be
directly associated with the operations of a business segment. Segment
information for the years ended December 31, 1996, 1995 and 1994 is as follows
(in millions):

1996 1995 1994
-------- -------- --------

REVENUES
Gross operating revenues:
Refining and Marketing --
Refined products............................... $ 620.8 664.5 582.7
Other, primarily crude oil resales and
merchandise................................. 124.6 106.5 104.3
Exploration and Production --
U.S. oil and gas............................... 88.4 107.3 87.5
U.S. gas transportation........................ 5.4 5.7 3.1
Bolivia........................................ 13.7 11.7 13.2
Marine Services.................................. 122.5 74.5 77.9
-------- -------- --------
Total Gross Operating Revenues.............. 975.4 970.2 868.7
Income from settlement of a natural gas contract.... 60.0 -- --
Other, including gain (loss) on asset sales......... 4.4 32.7 3.2
-------- -------- --------
Total Revenues.............................. $1,039.8 1,002.9 871.9
======== ======== ========
OPERATING PROFIT (LOSS)
Refining and Marketing.............................. $ 6.0 .7 2.4
Exploration and Production --
U.S. oil and gas................................. 119.1 96.9 52.1
U.S. gas transportation.......................... 4.8 5.1 2.9
Bolivia.......................................... 8.8 7.6 9.3
Marine Services..................................... 6.1 (4.4) (2.3)
-------- -------- --------
Total Operating Profit........................... 144.8 105.9 64.4
Corporate and Unallocated Costs..................... (29.7) (44.0) (38.3)
-------- -------- --------
Earnings Before Income Taxes and Extraordinary
Item............................................. $ 115.1 61.9 26.1
======== ======== ========
IDENTIFIABLE ASSETS
Refining and Marketing.............................. $ 317.0 313.3 309.1
Exploration and Production --
U.S. oil and gas................................. 136.3 128.9 105.5
U.S. gas transportation.......................... 7.3 7.8 8.4
Bolivia.......................................... 27.0 17.8 11.1
Marine Services..................................... 56.0 18.0 19.8
Corporate........................................... 39.0 33.4 30.5
-------- -------- --------
Total Assets................................ $ 582.6 519.2 484.4
======== ======== ========

46
47

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

1996 1995 1994
-------- -------- --------

DEPRECIATION, DEPLETION AND AMORTIZATION
Refining and Marketing.............................. $ 12.5 11.9 10.4
Exploration and Production --
U.S. oil and gas................................. 25.3 29.0 24.1
U.S. gas transportation.......................... .3 .3 .2
Bolivia.......................................... 1.3 .3 --
Marine Services..................................... 1.2 .3 .3
Corporate........................................... .9 .8 1.0
-------- -------- --------
Total Depreciation, Depletion and
Amortization.............................. $ 41.5 42.6 36.0
======== ======== ========
CAPITAL EXPENDITURES
Refining and Marketing.............................. $ 11.1 9.3 32.0
Exploration and Production --
U.S. oil and gas................................. 59.7 49.4 60.4
U.S. gas transportation.......................... -- .2 5.2
Bolivia.......................................... 6.9 3.8 --
Marine Services..................................... 6.9 .4 .2
Corporate........................................... .4 .8 1.8
-------- -------- --------
Total Capital Expenditures.................. $ 85.0 63.9 99.6
======== ======== ========

NOTE C -- ACQUISITIONS AND DIVESTITURES

During 1996, the Company's Exploration and Production segment recorded
acquisitions of proved and unproved properties totaling $25.7 million. The most
significant of these was the purchase in December 1996 of interests in the Los
Indios and La Reforma Fields, located in Hidalgo and Starr counties of South
Texas, for $15 million. These two fields are in the Frio/Vicksburg Trend, which
lies immediately adjacent to the Wilcox Trend. Other acquisitions in 1996
included the purchase of interests in the Berry R. Cox and the West Goliad
Fields, both located in the Wilcox Trend, for $5.4 million and the purchase of
approximately 35,000 net undeveloped acres in four areas of Texas for $5.3
million.

In September 1995, the Company sold, effective April 1, 1995, certain
interests in its producing and non-producing oil and gas properties located in
the Bob West Field in South Texas. The interests sold included the Company's
approximate 55% net revenue interest and 70% working interest in Units C, D and
E and a convertible override in Unit F of the Bob West Field. Excluded from the
sale were the Company's interests in the State Park and Sanchez-O'Brien leases
and the Ramirez USA E-6 well within the Bob West Field. In total, the sale
included interests in 14 gross producing wells amounting to 77 Bcf, or 40%, of
the Company's total net proved domestic reserves at the time of the sale (see
Note O). For 1995, natural gas production from the interests sold had
contributed approximately $11.7 million to revenues and $4 million to operating
profit in the Company's Exploration and Production segment. Consideration for
the sale was $74 million, which was adjusted for production, capital
expenditures and certain other items after the effective date to approximately
$68 million in cash received at closing, resulting in a gain of approximately
$33 million in the 1995 third quarter. The consideration received by the Company
was used to redeem $34.6 million of the Company's outstanding 12 3/4%
Subordinated Debentures in 1995, reduce borrowings under the Company's revolving
credit facility and improve corporate liquidity (see Note I).

In February 1996, the Company purchased 100% of the capital stock of
Coastwide Energy Services, Inc. ("Coastwide"). The consideration included
approximately 1.4 million shares of Tesoro's Common Stock and $7.7 million in
cash. The market price of Tesoro's Common Stock was $9.00 per share at closing
of this transaction. In addition, Tesoro repaid approximately $4.5 million of
Coastwide's outstanding debt. Coastwide

47
48

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

was primarily a provider of logistical support services and a distributor of
diesel fuel and lubricants to the offshore oil and gas industry in the Gulf of
Mexico. The Company combined the Coastwide operation with its marine petroleum
distribution operations, forming a Marine Services segment. The acquisition was
accounted for as a purchase whereby the purchase price was allocated to the
assets acquired and liabilities assumed based upon their estimated fair values.

In March 1995, the Company acquired all of the outstanding stock of Kenai
Pipe Line Company ("KPL") for approximately $3 million cash. The Company's
Refining and Marketing segment transports crude oil and a substantial portion of
refined products utilizing KPL's pipeline and marine terminal facilities in
Kenai, Alaska. The acquisition was accounted for using the purchase method.

NOTE D -- GAS PURCHASE AND SALES CONTRACT

Resolution of Litigation in 1996 Third Quarter

On August 16, 1996, the Supreme Court of Texas issued a mandate that denied
a motion for rehearing by Tennessee Gas Pipeline Company ("Tennessee Gas") and
upheld all aspects of a Gas Purchase and Sales Agreement ("Tennessee Gas
Contract") which had been the subject of litigation since 1990. As provided for
in the Tennessee Gas Contract, the Company was selling a portion of the gas
produced from the Bob West Field to Tennessee Gas at a maximum price as
calculated in accordance with Section 102(b)(2) ("Contract Price") of the
Natural Gas Policy Act of 1978 ("NGPA"). Subsequent to the mandate, the Company
received cash of $67.7 million from Tennessee Gas, which included collection of
a $59.6 million bonded receivable for underpayment for natural gas sold in prior
periods. The remaining $8.1 million received was for interest and reimbursement
of legal fees and court costs, which had not previously been recorded by the
Company and resulted in income during the 1996 third quarter. Tennessee Gas
resumed paying the Contract Price to the Company for gas taken beginning with
May 1996 volumes up until termination of the Tennessee Gas Contract discussed
below.

Settlement and Termination of Contract in 1996 Fourth Quarter

On December 24, 1996, the Company settled all other claims and disputes
with Tennessee Gas, including litigation in Zapata County, Texas filed by
Tennessee Gas, and agreed to terminate the Tennessee Gas Contract effective
October 1, 1996. The Tennessee Gas Contract would have extended through January
1999. Under the settlement, the Company received $51.8 million and the right to
recover severance taxes paid by Tennessee Gas of approximately $8.2 million,
which resulted in income of $60 million to the Company during the 1996 fourth
quarter.

NOTE E -- RECEIVABLES

Concentrations of credit risk with respect to accounts receivable are
limited, due to the large number of customers comprising the Company's customer
base and their dispersion across the Company's industry segments and geographic
areas of operations. The Company performs ongoing credit evaluations of its
customers' financial condition and in certain circumstances requires letters of
credit or other collateral arrangements. The Company's allowance for doubtful
accounts is reflected as a reduction of receivables in the

48
49

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Consolidated Balance Sheets. The following table reconciles the change in the
Company's allowance for doubtful accounts for the years ended December 31, 1996,
1995 and 1994 (in thousands):

1996 1995 1994
------ ----- -----

Balance at Beginning of Year................................ $1,842 1,816 2,487
Charged to Costs and Expenses............................... 589 300 299
Recoveries of Amounts Previously Written Off and Other...... (44) 122 (4)
Write-off of Doubtful Accounts.............................. (872) (396) (966)
------ ----- -----
Balance at End of Year............................ $1,515 1,842 1,816
====== ===== =====

NOTE F -- INVENTORIES

Components of inventories at December 31, 1996 and 1995 were as follows (in
thousands):

1996 1995
------- ------

Crude Oil and Wholesale Refined Products, at LIFO........... $55,858 70,406
Merchandise and Other Refined Products...................... 13,539 5,153
Materials and Supplies...................................... 5,091 4,894
------- ------
Total Inventories................................. $74,488 80,453
======= ======

At December 31, 1996 and 1995, inventories valued using LIFO were lower
than replacement cost by approximately $17.7 million and $3.8 million,
respectively.

NOTE G -- ACCRUED LIABILITIES

The Company's current accrued liabilities and noncurrent other liabilities
as shown in the Consolidated Balance Sheets at December 31, 1996 and 1995
included the following (in thousands):

1996 1995
------- -------

Accrued Liabilities -- Current:
Accrued environmental costs............................... $ 5,367 5,935
Accrued employee and pension costs........................ 7,759 6,839
Accrued taxes other than income taxes..................... 5,988 3,910
Accrued interest.......................................... 1,155 2,879
Other..................................................... 12,987 13,503
------- -------
Total Accrued Liabilities -- Current.............. $33,256 33,066
======= =======
Other Liabilities -- Other:
Accrued postretirement benefits........................... $30,508 28,706
Accrued environmental costs............................... 3,496 3,968
Other..................................................... 8,239 4,634
------- -------
Total Other Liabilities -- Noncurrent............. $42,243 37,308
======= =======

49
50

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

NOTE H -- INCOME TAXES

The income tax provision for the years ended December 31, 1996, 1995 and
1994 included the following (in thousands):

1996 1995 1994
------- ----- -----

Federal -- Current......................................... $16,206 708 700
Federal -- Deferred........................................ 17,405 -- --
Foreign.................................................... 3,654 3,183 3,588
State...................................................... 1,082 488 1,285
------- ----- -----
Income Tax Provision............................. $38,347 4,379 5,573
======= ===== =====

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
assets and liabilities at December 31, 1996 and 1995 are summarized as follows
(in thousands):

1996 1995
-------- -------

Deferred Federal Tax Assets:
Investment tax and other credits.......................... $ 11,962 9,762
Accrued postretirement benefits........................... 9,941 9,424
Settlement with Department of Energy...................... 3,694 3,981
Settlement with the State of Alaska....................... 728 810
Acquisition............................................... 713 --
Net operating losses...................................... -- 29,695
Other..................................................... 3,417 8,594
-------- -------
Total Deferred Federal Tax Assets................. 30,455 62,266
-------- -------
Deferred Federal Tax Liabilities:
Accelerated depreciation and property-related items....... (47,147) (39,734)
Receivable related to a natural gas contract.............. -- (17,699)
-------- -------
Total Deferred Federal Tax Liabilities............ (47,147) (57,433)
-------- -------
Net Deferred Federal Tax Asset (Liability) Before Valuation
Allowance................................................. (16,692) 4,833
Valuation Allowance......................................... -- (4,833)
-------- -------
Net Deferred Federal Tax Liability.......................... (16,692) --
State Income and Other Taxes................................ (2,459) (5,389)
-------- -------
Net Deferred Tax Liability........................ $(19,151) (5,389)
======== =======

50
51

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The following tables set forth the components of the Company's results of
operations (in thousands) and a reconciliation of the normal statutory federal
income tax rate with the Company's effective tax rate:

1996 1995 1994
-------- ------ ------

Earnings Before Income Taxes and Extraordinary Loss:
United States......................................... $106,675 55,221 18,336
Foreign............................................... 8,472 6,647 7,720
-------- ------ ------
Total Earnings Before Income Taxes and
Extraordinary Loss.......................... $115,147 61,868 26,056
======== ====== ======
Statutory U.S. Corporate Tax Rate (%)................... 35 35 35
Effect of:
Accounting recognition of operating loss tax
benefits........................................... (4) (33) (35)
Foreign income taxes (net of tax benefit)............. 2 5 14
State income taxes (net of tax benefit)............... 1 1 5
Other................................................. (1) (1) 2
-------- ------ ------
Effective Income Tax Rate (%)........................... 33 7 21
======== ====== ======

At December 31, 1996, the Company had approximately $8.2 million of
investment tax credits and employee stock ownership credits available for
carryover to subsequent years, which, if not used, will expire in the years 1997
through 2006. Additionally, at December 31, 1996, the Company had approximately
$3.8 million of alternative minimum tax credit carryforwards, with no expiration
dates, to offset future regular tax liabilities.

NOTE I -- LONG-TERM DEBT AND OTHER OBLIGATIONS

Long-term debt and other obligations at December 31, 1996 and 1995
consisted of the following (in thousands):

1996 1995
------- --------

Liability to State of Alaska................................ $62,079 62,313
Vacuum Unit Loan............................................ 11,250 13,393
Liability to Department of Energy........................... 10,555 11,874
Revolving Credit Lines...................................... 883 --
Industrial Revenue Bonds.................................... 558 1,654
12 3/4% Subordinated Debentures (net of discount of $2,194
in 1995).................................................. -- 27,806
13% Exchange Notes.......................................... -- 44,116
Other....................................................... 3,978 3,324
------- --------
89,303 164,480
Less Current Maturities..................................... 10,043 9,473
------- --------
$79,260 155,007
======= ========

Aggregate maturities of long-term debt and obligations for each of the five
years following December 31, 1996 are as follows: 1997 - $10.0 million;
1998 - $9.7 million; 1999 - $9.6 million; 2000 - $10.7 million; and 2001 - $11.3
million.

Revolving Credit Lines

In June 1996, the Company amended and restated its corporate revolving
credit agreement ("Credit Facility"), expiring in April 2000, which provides
total commitments of $150 million from a consortium of nine banks. The Company,
at its option, has currently activated $100 million of these commitments. The

51
52

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Credit Facility provides for cash borrowings up to $100 million and issuance of
letters of credit up to a borrowing base (which was approximately $141 million
at December 31, 1996). Outstanding obligations under the Credit Facility are
secured by liens on substantially all of the Company's trade accounts receivable
and product inventory and by mortgages on the Company's refinery and South Texas
natural gas reserves. At December 31, 1996, the Company had outstanding letters
of credit of $33 million with no cash borrowings outstanding.

Cash borrowings under the Credit Facility bear interest at the prime rate
plus .50% per annum or the London Interbank Offered Rate ("LIBOR") plus 1.5% per
annum. Fees on outstanding letters of credit under the Credit Facility are 1.5%
per annum. Under the terms of the Credit Facility, the Company is required to
maintain specified levels of consolidated working capital, tangible net worth,
cash flow and interest coverage. Among other matters, the Credit Facility
contains covenants which limit the incurrence of additional indebtedness and
restricted payments. Under the Credit Facility, dividends up to $5 million per
year are allowed, subject to the restricted payment limit.

During 1996 and 1995, the Company's gross borrowings and repayments under
its corporate revolving credit line totaled $166 million and $262 million,
respectively, which were used on a short-term basis to finance working capital
requirements and capital expenditures.

In November 1996, a subsidiary of the Company entered into a loan facility
with a bank which provides a three-year line of credit up to $10 million to the
Marine Services segment for the purchase of real estate and equipment at the
bank's prime rate. The loan facility, which is subject to a borrowing base, is
not guaranteed by the Company and is secured only by such real estate and
equipment that are financed. Beginning in March 1998, credit availability is
reduced quarterly by 6.667%. At December 31, 1996, $.9 million was outstanding
under the loan facility.

Vacuum Unit Loan

In 1994, the National Bank of Alaska and the Alaska Industrial Development
& Export Authority provided a $15 million loan to the Company towards the cost
of the Company's refinery vacuum unit ("Vacuum Unit Loan"). The Vacuum Unit Loan
matures January 1, 2002, requires equal quarterly payments of approximately
$536,000 and bears interest at the unsecured 90-day commercial paper rate,
adjusted quarterly, plus 2.6% per annum (8.23% at December 31, 1996) for
two-thirds of the amount borrowed and at the National Bank of Alaska floating
prime rate plus one-fourth of 1% per annum (8.5% at December 31, 1996) for the
remainder. The Vacuum Unit Loan is secured by a first lien on the Company's
refinery. Under the terms of the Vacuum Unit Loan, the Company is required to
maintain specified levels of working capital, tangible net worth and cash flow,
as defined. For 1996, the Company satisfied all of its covenants except for
working capital and refinery cash flow requirements, which were waived by the
lenders.

12 3/4% Subordinated Debentures and 13% Exchange Notes

In November 1996, the Company fully redeemed its two public debt issues,
totaling approximately $74 million, at a price equal to 100% of the principal
amount, plus accrued interest to the redemption date. The redemption of debt was
comprised of $44.1 million of outstanding 13% Exchange Notes ("Exchange Notes"),
due December 1, 2000, and $30 million of outstanding 12 3/4% Subordinated
Debentures ("Subordinated Debentures"), due March 15, 2001. The redemption was
accounted for as an early extinguishment of debt in the 1996 third quarter,
resulting in a pretax charge of $3.2 million ($2.3 million aftertax) which
represented a write-off of unamortized bond discount and issue costs. The
extraordinary losses on debt extinguishments of $2.9 million and $4.8 million in
1995 and 1994, respectively, related to the redemption of $34.6 million
principal amount of Subordinated Debentures in December 1995 and the exchange of
$44.1 million principal amount of Subordinated Debentures for Exchange Notes in
February 1994 (see Note K).

52
53

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

State of Alaska

In 1993, the Company entered into an agreement ("Agreement") with the State
of Alaska ("State") that settled a contractual dispute with the State. Under the
Agreement, the Company is obligated to make variable monthly payments to the
State through December 2001 based on a per barrel charge on the volume of
feedstock processed at the Company's refinery. In 1995 and 1994, based on a per
barrel throughput charge of 16 cents, the Company's variable payments to the
State totaled $2.9 million and $2.8 million, respectively. The per barrel charge
increased to 24 cents in 1996 with the Company's variable payment to the State
totaling $4.0 million in the year. The per barrel charge of 24 cents in 1997
increases to 30 cents in 1998 with one cent annual incremental increases
thereafter through 2001. In January 2002, the Company is obligated to pay the
State $60 million; provided, however, that such payment may be deferred
indefinitely by continuing the variable monthly payments to the State beginning
at 34 cents per barrel for 2002 and increasing one cent per barrel annually
thereafter. Variable monthly payments made after January 2002 will not reduce
the $60 million obligation to the State. The imputed rate of interest used by
the Company on the $60 million obligation was 13%. The $60 million obligation is
evidenced by a security bond, and the bond and the throughput barrel obligations
are secured by a mortgage on the Company's refinery. The Company's obligations
under the Agreement and the mortgage are subordinated to current and future
senior debt of up to $175 million plus any indebtedness incurred subsequent to
the date of the Agreement to improve the Company's refinery.

Department of Energy

A Consent Order entered into by the Company with the Department of Energy
("DOE") in 1989 settled all issues relating to the Company's compliance with
federal petroleum price and allocation regulations from 1973 through decontrol
in 1981. At December 31, 1996, the Company's remaining obligation is to pay the
DOE $10.6 million, exclusive of interest at 6%, over the next six years.

Industrial Revenue Bonds

The industrial revenue bonds mature in 1997 and require semiannual payments
of approximately $365,000. The bonds bear interest at a variable rate (6.1875%
at December 31, 1996), which is equal to 75% of the National Bank of Alaska's
prime rate. The bonds are collateralized by the Company's refinery sulphur
recovery unit, which had a carrying value of approximately $5.6 million at
December 31, 1996.

NOTE J -- BENEFIT PLANS

Retirement Plan

For all eligible employees, the Company provides a qualified
noncontributory 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 components of net
pension expense for the Company's retirement plan for the years ended December
31, 1996, 1995 and 1994 are presented below (in thousands):

1996 1995 1994
------- ------- -------

Service Costs............................................ $ 1,306 1,147 1,121
Interest Cost............................................ 3,536 3,549 3,351
Actual Return on Plan Assets............................. (6,212) (8,299) (217)
Net Amortization and Deferral............................ 1,687 4,288 (3,408)
------- ------- -------
Net Pension Expense.................................... $ 317 685 847
======= ======= =======

53
54

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The funded status of the Company's retirement plan and amounts included in
the Company's Consolidated Balance Sheets at December 31, 1996 and 1995 are set
forth in the following table (in thousands):

1996 1995
------- ------

Actuarial Present Value of Benefit Obligation:
Vested benefit obligation................................. $40,539 39,012
======= ======
Accumulated benefit obligation............................ $43,404 41,659
======= ======
Plan Assets at Fair Value................................... $46,356 42,406
Projected Benefit Obligation................................ 50,163 47,992
------- ------
Plan Assets Less Than Projected Benefit Obligation.......... (3,807) (5,586)
Unrecognized Net Loss....................................... 5,903 7,319
Unrecognized Prior Service Costs............................ (341) (415)
Unrecognized Net Transition Asset........................... (3,176) (4,412)
------- ------
Accrued Pension Liability................................. $(1,421) (3,094)
======= ======

Retirement plan assets are primarily comprised of common stock and bond
funds. Actuarial assumptions used to measure the projected benefit obligations
at December 31, 1996, 1995 and 1994 included a discount rate of 7 1/2%, 7 1/2%
and 8 1/2%, respectively, and a compensation increase rate of 5%, 5% and 6%,
respectively. The expected long-term rate of return on assets was 8 1/2%, 8 1/2%
and 9% for 1996, 1995 and 1994, respectively.

Executive Security Plan

The Company's executive security plan ("ESP") provides executive officers
and other key personnel with supplemental death or retirement benefits in
addition to those benefits available under the Company's group life insurance
and retirement plans. These supplemental retirement benefits are provided by a
nonqualified, noncontributory plan and are based on years of service and
compensation. Contributions are made based upon the estimated requirements of
the plan. The components of net pension expense for the ESP for the years ended
December 31, 1996, 1995 and 1994 are presented below (in thousands):

1996 1995 1994
----- ---- ----

Service Costs............................................... $ 354 364 474
Interest Cost............................................... 204 205 273
Actual Return on Plan Assets................................ (439) (325) (230)
Net Amortization and Deferral............................... 751 471 228
----- ---- ----
Net Pension Expense....................................... $ 870 715 745
===== ==== ====

During 1996, 1995 and 1994, the Company incurred additional ESP expense of
$.9 million, $1.5 million and $.4 million, respectively, for settlements,
curtailments and other benefits resulting from employee terminations.

54
55

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The funded status of the ESP and amounts included in the Company's
Consolidated Balance Sheets at December 31, 1996 and 1995 are set forth in the
following table (in thousands):

1996 1995
------ ------

Actuarial Present Value of Benefit Obligation:
Vested benefit obligation................................. $3,300 2,470
====== ======
Accumulated benefit obligation............................ $4,434 3,038
====== ======
Plan Assets at Fair Value................................... $7,139 4,447
Projected Benefit Obligation................................ 6,467 4,155
------ ------
Plan Assets in Excess of Projected Benefit Obligation....... 672 292
Unrecognized Net Loss....................................... 4,532 2,343
Unrecognized Prior Service Costs............................ 537 395
Unrecognized Net Transition Obligation...................... 417 643
------ ------
Prepaid Pension Asset..................................... $6,158 3,673
====== ======

Assets of the ESP consist of a group annuity contract. Actuarial
assumptions used to measure the projected benefit obligation at December 31,
1996, 1995 and 1994 included a discount rate of 7 1/2%, 7 1/2% and 8 1/2%,
respectively, and a compensation increase rate of 5%. The expected long-term
rate of return on assets was 8%, 8% and 9% for 1996, 1995 and 1994,
respectively.

Retiree Health Care and Life Insurance Benefits

The Company provides health care and life insurance benefits to retirees
who were participating in the Company's group insurance program at retirement.
Health care is also provided to qualified dependents of participating retirees.
These benefits are provided through unfunded, defined benefit plans. 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. The components of net periodic postretirement benefits expense, other
than pensions, for the years ended December 31, 1996, 1995 and 1994 included the
following (in thousands):

1996 1995 1994
------ ----- ------

Health Care:
Service costs........................................... $ 558 447 471
Interest costs.......................................... 1,294 1,399 1,264
------ ----- ------
Net Periodic Postretirement Expense.................. $1,852 1,846 1,735
====== ===== ======
Life Insurance:
Service costs........................................... $ 158 174 198
Interest costs.......................................... 548 584 518
------ ----- ------
Net Periodic Postretirement Expense.................. $ 706 758 716
====== ===== ======

55
56

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The following tables show the status of the plans reconciled with the
amounts in the Company's Consolidated Balance Sheets at December 31, 1996 and
1995 (in thousands):

1996 1995
------- -------

Health Care:
Accumulated Postretirement Benefit Obligation --
Retirees.................................................. $12,549 13,831
Active participants eligible to retire.................... 1,203 1,382
Other active participants................................. 4,181 4,118
------- -------
17,933 19,331
Unrecognized Net Gain....................................... 2,621 328
------- -------
Accrued Postretirement Benefit Liability............... $20,554 19,659
======= =======
Life Insurance:
Accumulated Postretirement Benefit Obligation --
Retirees.................................................. $ 6,274 5,888
Active participants eligible to retire.................... 484 452
Other active participants................................. 1,205 1,590
------- -------
7,963 7,930
Unrecognized Net Loss....................................... (115) (665)
------- -------
Accrued Postretirement Benefit Liability............... $ 7,848 7,265
======= =======

The weighted average annual rate of increase in the per capita cost of
covered health care benefits is assumed to be 8% for 1997, decreasing gradually
to 6% by the year 2005 and remaining at that level thereafter. This health care
cost trend rate assumption has a significant effect on the amount of the
obligation and periodic cost reported. For example, an increase in the assumed
health care cost trend rates by one percentage point in each year would increase
the accumulated postretirement obligation at December 31, 1996 by $3.3 million
and the aggregate of service cost and interest cost components of net periodic
postretirement benefits for the year then ended by $.5 million. Actuarial
assumptions used to measure the accumulated postretirement benefit obligation at
December 31, 1996, 1995 and 1994 included a discount rate of 7 1/2%, 7 1/2% and
8 1/2%, respectively, and a compensation rate increase of 5%, 5% and 6%,
respectively.

Thrift Plan

The Company sponsors an employee thrift plan which provides for
contributions by eligible employees into designated investment funds with a
matching contribution by the Company. Employees may contribute up to 10% of
their compensation, subject to certain limitations, and may elect tax deferred
treatment in accordance with the provisions of Section 401(k) of the Internal
Revenue Code. Effective October 1, 1996, the thrift plan was amended to change
the Company's matching contribution from 50% (of up to 6% of the employee's
eligible contribution) to 100% (of up to 4% of the employee's eligible
contributions), with 50% of the Company's match invested in Common Stock of the
Company. The Company's contributions amounted to $754,000, $400,000 and $547,000
during 1996, 1995 and 1994, respectively.

Employee Terminations and Other Costs

In 1996 and 1995, the Company incurred charges of $2.9 million and $5.2
million, respectively, primarily for employee termination costs and other
restructuring costs. Other expense in 1996 and 1995 included $2.0 million and
$3.8 million of these charges, representing primarily severance and related
benefits resulting from a reduction in administrative workforce and other
employee terminations together with settlements and curtailments under the
Company's executive security plan. Operating expenses and other included the
remaining amounts of these charges which were related to employee terminations
and exit costs in the Company's operating segments. At December 31, 1995, the
Company's Consolidated Balance Sheet included

56
57

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

an accrual of approximately $.9 million relating to the costs incurred in 1995,
all of which were subsequently paid in 1996. Costs incurred in 1996 were paid
and settled during the year.

Non-Employee Director Retirement Plan

The Company has an unfunded Non-Employee Director Retirement Plan
("Director Retirement Plan") which provides that any eligible non-employee
director who elects to participate in the Director Retirement Plan and who has
served on the Company's Board of Directors for at least three full years will be
entitled to a retirement payment beginning the later of the director's
sixty-fifth birthday or such later date that the individual's service as a
director ends. In 1995, the Company recognized expense of $.8 million related to
the Director Retirement Plan, substantially all attributable to nonrecurring
prior service costs. At December 31, 1996 and 1995, the Director Retirement
Plan's projected benefit obligation and present value of the vested and
accumulated benefit obligation discounted at 7 1/2% were estimated to be $.8
million. The Company's Consolidated Balance Sheet at December 31, 1996 and 1995
included $.7 million in other liabilities related to the Director Retirement
Plan. The Compensation Committee of the Board of Directors is considering the
termination of the Director Retirement Plan and the conversion of the lump-sum
present value of each director's benefit into an unfunded deferred phantom stock
plan.

NOTE K -- STOCKHOLDERS' EQUITY

Stock Plans and Incentive Compensation Strategy

The Company has two employee incentive stock plans, the Executive Long-Term
Incentive Plan ("1993 Plan") and Amended Incentive Stock Plan of 1982 ("1982
Plan"), and the 1995 Non-Employee Director Stock Option Plan ("1995 Plan")
(collectively, the "Plans"). Shares of unissued Common Stock reserved for the
Plans totaled 2,775,191 at December 31, 1996.

The 1993 Plan provides for the grant of up to 2,650,000 shares of the
Company's Common Stock in a variety of forms, including restricted stock,
incentive stock options, nonqualified stock options, stock appreciation rights
and performance share and performance unit awards. Stock options may be granted
at exercise prices equal to the market value on the date the options are
granted. The options granted generally become exercisable after one year in 20%
or 33% increments per year and expire ten years from date of grant. The 1993
Plan will expire, unless earlier terminated, as to the issuance of awards in the
year 2003. At December 31, 1996, the Company had 461,807 shares available for
future grants under the 1993 Plan. The 1982 Plan expired in 1994 as to issuance
of stock appreciation rights, stock options and stock awards; however, grants
made before the expiration date that have not been fully exercised remain
outstanding pursuant to their terms.

The 1995 Plan provides for the grant of up to an aggregate of 150,000
nonqualified stock options to eligible non-employee directors of the Company.
The option price per share is equal to the fair market value per share of the
Company's Common Stock on 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. Under the 1995 Plan, each person serving as a non-employee director on
February 23, 1995 or appointed thereafter, received an option to purchase 5,000
shares of Common Stock. In addition, each non-employee director, while the 1995
Plan is in effect and shares are available to grant, will be granted an option
to purchase 1,000 shares of Common Stock on the next day after each annual
meeting of the Company's stockholders but not later than June 1. At December 31,
1996, the Company had 67,000 options outstanding and 83,000 shares available for
future grants under the 1995 Plan.

In June 1996, the Company's Board of Directors unanimously approved an
incentive compensation strategy in order to encourage a longer-term focus for
all employees to perform at an outstanding level. The strategy provides eligible
employees with incentives to achieve a significant increase in the market price
of the

57
58

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Company's Common Stock. Under the strategy, awards would be earned only if the
market price of the Company's Common Stock reaches an average price per share of
$20 or higher over any 20 consecutive trading days after June 30, 1997 and
before December 31, 1998 (the "Performance Target"). In connection with this
strategy, non-executive employees will be able to earn cash bonuses equal to 25%
of their individual payroll amounts for the previous twelve complete months and
certain executives have been granted, from the 1993 Plan, a total of 340,000
stock options at an exercise price of $11.375 per share, the fair market value
(as defined in the 1993 Plan) of a share of the Company's Common Stock on the
date of grant, and 350,000 shares of restricted Common Stock, all of which vest
only upon achieving the Performance Target.

A summary of stock option activity in the Plans is set forth below:

OPTIONS WEIGHTED-AVERAGE
OUTSTANDING EXERCISE PRICE
----------- ----------------

December 31, 1993........................................ 1,016,870 $ 4.89
Granted................................................ 524,600 9.34
Exercised.............................................. (18,764) 10.15
Forfeited and expired.................................. (26,413) 5.37
---------
December 31, 1994........................................ 1,496,293 6.37
Granted................................................ 450,000 8.34
Exercised.............................................. (507,467) 4.85
Forfeited and expired.................................. (266,745) 9.10
---------
December 31, 1995........................................ 1,172,081 7.16
Granted................................................ 1,095,500 13.45
Exercised.............................................. (315,664) 5.67
Forfeited and expired.................................. (95,171) 8.50
---------
December 31, 1996........................................ 1,856,746 11.05
=========

Options exercisable amounted to 380,230; 360,779; and 478,879 at December
31, 1996, 1995 and 1994, respectively.

The following table summarizes information about stock options outstanding
under the Plans at December 31, 1996:

OPTIONS OUTSTANDING OPTIONS EXERCISABLE
------------------------------------------------- ------------------------------
WEIGHTED-AVERAGE
RANGE OF NUMBER REMAINING WEIGHTED-AVERAGE NUMBER WEIGHTED-AVERAGE
EXERCISE PRICES OUTSTANDING CONTRACTUAL LIFE EXERCISE PRICE EXERCISABLE EXERCISE PRICE
--------------- ----------- ---------------- ---------------- ----------- ----------------

$ 3.92 - $ 6.67............. 199,806 6.3 years $ 4.59 152,470 $ 4.39
$ 6.68 - $ 9.43............. 445,323 8.6 years 8.25 118,843 8.46
$ 9.44 - $12.17............. 531,397 8.9 years 10.89 102,197 10.17
$12.18 - $14.94............. 680,220 9.8 years 14.92 6,720 12.63
--------- -------
$ 3.92 - $14.94............. 1,856,746 8.9 years 11.05 380,230 7.36
========= =======

Performance shares granted to officers and key employees under the 1993
Plan amounted to 137,253 common shares in 1994. Compensation expense,
representing the excess of the market value of the Common Stock on the dates of
the awards over the purchase price to be paid by the employee, is charged to
earnings over the periods that the shares are earned and amounted to $1.3
million in 1994. No performance shares were granted in 1996 and 1995.

58
59

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The Company applies APB No. 25 and related Interpretations in accounting
for its stock plans. Accordingly, no compensation expense has been recognized
for stock option transactions or the incentive compensation strategy discussed
above. Had compensation cost for the Plans been determined based on the fair
value at the grant dates for awards (granted after January 1, 1995) in
accordance with SFAS No. 123, "Accounting for Stock-Based Compensation," the
Company's net earnings in 1996 would have been reduced from $74.5 million ($2.81
per share) to pro forma net earnings of approximately $72.6 million ($2.74 per
share). Net earnings in 1995 of $54.6 million ($2.18 per share) would have been
reduced to pro forma net earnings of approximately $53.8 million ($2.15 per
share). 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 used for grants in 1996 and 1995, respectively: no dividend yield;
expected volatility of 45% and 30%; risk free interest rates of 7% for both
periods; and expected lives of 7 years for both periods. The estimated fair
values of options granted during 1996 and 1995 were $4.26 per share and $3.65
per share, respectively, and the fair value of restricted stock awards in 1996
was $.95 per share.

1994 Recapitalization and Equity Offering

In February 1994, the Company consummated exchange offers and adopted
amendments to its Restated Certificate of Incorporation pursuant to which the
Company's outstanding debt and preferred stocks were restructured (the
"Recapitalization"). Significant components of the Recapitalization were as
follows:

(i) The Company exchanged $44.1 million principal amount of
Subordinated Debentures for a like principal amount of Exchange
Notes, both of which were fully redeemed in 1996 (see Note I).

(ii) The 1.3 million outstanding shares of the Company's $2.16
Cumulative Convertible Preferred Stock ("$2.16 Preferred Stock"),
which had a $25 per share liquidation preference, plus accrued and
unpaid dividends of $9.5 million, were reclassified into 6.6
million shares of Common Stock.

(iii) The Company and the holder ("Holder") of all of the Company's
$2.20 Cumulative Convertible Preferred Stock ("$2.20 Preferred
Stock") entered into an agreement pursuant to which the Holder
agreed, among other matters, to waive all existing mandatory
redemption requirements, to consider all accrued and unpaid
dividends on the $2.20 Preferred Stock (aggregating $21 million)
to be paid and to grant to the Company an option to purchase all
of the Holder's $2.20 Preferred Stock and Common Stock for
approximately $53 million, all in consideration for, among other
things, the issuance by the Company of 1.9 million shares of
Common Stock.

In June 1994, the Company completed a public offering of 5.9 million shares
of its Common Stock, receiving net proceeds of $57 million. These proceeds were
used by the Company in part to pay the Holder $53 million, reacquiring 2.9
million shares of $2.20 Preferred Stock and 4.1 million shares of Common Stock.

In total, the transactions related to the Recapitalization and equity
offering in 1994 resulted in the reclassification of the $2.16 Preferred Stock,
the retirement of the $2.20 Preferred Stock and net increases in Common Stock of
$1.7 million (10.3 million shares) and additional paid-in capital of $88.5
million.

59
60

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

NOTE L -- COMMITMENTS AND CONTINGENCIES

Operating Leases

The Company has various noncancellable operating leases related to
convenience stores, equipment, property and other facilities. Lease terms range
from one year to 35 years and generally contain multiple renewal options. Future
minimum annual payments for operating leases existing at December 31, 1996,
excluding marine charters, were as follows (in thousands):

1997........................................................ $ 5,624
1998........................................................ 4,978
1999........................................................ 2,310
2000........................................................ 1,972
2001........................................................ 1,687
Remainder................................................... 13,472
-------
Total Minimum Lease Payments...................... $30,043
=======

In addition to the long-term lease commitments above, the Company has
leases for two vessels that are used to transport crude oil and refined products
to and from the Company's refinery. At December 31, 1996, future minimum annual
lease payments remaining for these two vessels, which include operating costs,
are approximately $28 million for each of the years 1997 through 1999 and $16
million for the year 2000. Operating costs related to these vessels, which may
vary from year to year, comprised approximately 30% of the total minimum
payments in 1996. The Company also enters into various month-to-month and other
short-term rentals, including a six-month charter of a vessel used to primarily
transport refined products from the Company's refinery to the Far East.

Total rental expense, including short-term leases in addition to rents paid
and accrued under long-term lease commitments, amounted to approximately $42
million, $36 million and $34 million for 1996, 1995 and 1994, respectively.
Rental expense included amounts related to the lease of chartered vessels
totaling approximately $30 million, $26 million and $25 million for 1996, 1995
and 1994, respectively.

Environmental

The Company is subject to extensive federal, state and local environmental
laws and regulations. These laws, which change frequently, regulate the
discharge of materials into the environment and may require the Company to
remove or mitigate the environmental effects of the disposal or release of
petroleum or chemical substances at various sites or install additional controls
or other modifications or changes in use for certain emission sources. The
Company is currently involved with a waste disposal site near Abbeville,
Louisiana, at which it has been named a potentially responsible party under the
Federal Superfund law. Although this law might impose joint and several
liability upon each party at the site, the extent of the Company's allocated
financial contributions to the cleanup of the site is expected to be limited
based upon the number of companies, volumes of waste involved, and an estimated
total cost of approximately $500,000 among all of the parties to close the site.
The Company is currently involved in settlement discussions with the
Environmental Protection Agency ("EPA") and other potentially responsible
parties at the Abbeville, Louisiana site. The Company expects, based on these
discussions, that its liability will not exceed $25,000. The Company is also
involved in remedial responses and has incurred cleanup expenditures associated
with environmental matters at a number of sites, including certain of its own
properties.

At December 31, 1996, the Company's accruals for environmental expenses
amounted to $8.9 million, which included a noncurrent liability of $3.5 million
for remediation of the KPL properties that has been funded by the former owners
through a restricted escrow deposit. Based on currently available information,
including the participation of other parties or former owners in remediation
actions, the Company believes

60
61

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

these accruals are adequate. In addition, to comply with environmental laws and
regulations, the Company anticipates that it will make capital improvements of
approximately $6 million in 1997 and $3 million in 1998. The Company also
expects to spend approximately $6 million by the year 2002 for secondary
containment systems for existing storage tanks in Alaska.

Conditions that require additional expenditures may exist for various
Company sites, including, but not limited to, the Company's refinery, retail
gasoline outlets (current and closed locations) and petroleum product terminals,
and for compliance with the Clean Air Act. The amount of such future
expenditures cannot currently be determined by the Company.

Crude Oil Purchase Contract

The Company has a three-year contract with the State of Alaska for the
purchase of royalty crude oil covering the period January 1, 1996 through
December 31, 1998. The contract provides for the purchase of approximately
40,000 barrels per day of Alaska North Slope ("ANS") royalty crude oil, the
primary feedstock for the Company's refinery, and is priced based on royalty
values computed by the State. Under this agreement, the Company is required to
utilize in its refinery operations volumes equal to at least 80% of the ANS
crude oil to be purchased from the State. This contract contains provisions
that, under certain conditions, allow the Company to temporarily or permanently
reduce its purchase obligations.

61
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TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

NOTE M -- QUARTERLY FINANCIAL DATA (UNAUDITED)

QUARTERS
--------------------------------- TOTAL
FIRST SECOND THIRD FOURTH YEAR
------ ------ ------ ------ --------
(IN MILLIONS EXCEPT PER SHARE AMOUNTS)

1996
Revenues:
Gross operating revenues..................... $238.6 233.8 262.8 240.2 975.4
Income from gas contract settlement.......... -- -- -- 60.0 60.0
Other, including gain (loss) on asset
sales...................................... 5.0 .1 (.7) -- 4.4
------ ------ ------ ------ --------
Total Revenues.......................... $243.6 233.9 262.1 300.2 1,039.8
====== ====== ====== ====== ========
Operating Profit................................ $ 20.7 27.6 25.2 71.3 144.8
====== ====== ====== ====== ========
Earnings Before Extraordinary Item.............. $ 6.0 12.0 16.2 42.6 76.8
Extraordinary Loss on Extinguishment of Debt,
Net.......................................... -- -- (2.3) -- (2.3)
------ ------ ------ ------ --------
Net Earnings............................ $ 6.0 12.0 13.9 42.6 74.5
====== ====== ====== ====== ========
Earnings Per Share:
Earnings Before Extraordinary Item........... $ .23 .45 .61 1.59 2.90
Extraordinary Loss........................... -- -- (.09) -- (.09)
------ ------ ------ ------ --------
Net Earnings............................ $ .23 .45 .52 1.59 2.81
====== ====== ====== ====== ========
1995
Revenues:
Gross operating revenues..................... $234.0 264.2 244.2 227.8 970.2
Other, including gain (loss) on asset
sales...................................... -- -- 33.1 (.4) 32.7
------ ------ ------ ------ --------
Total Revenues.......................... $234.0 264.2 277.3 227.4 1,002.9
====== ====== ====== ====== ========
Operating Profit................................ $ 12.4 19.1 53.8 20.6 105.9
====== ====== ====== ====== ========
Earnings Before Extraordinary Item.............. $ 1.8 7.4 36.8 11.5 57.5
Extraordinary Loss on Extinguishment of Debt,
Net.......................................... -- -- -- (2.9) (2.9)
------ ------ ------ ------ --------
Net Earnings............................ $ 1.8 7.4 36.8 8.6 54.6
====== ====== ====== ====== ========
Earnings Per Share:
Earnings Before Extraordinary Item........... $ .07 .30 1.47 .46 2.29
Extraordinary Loss........................... -- -- -- (.11) (.11)
------ ------ ------ ------ --------
Net Earnings............................ $ .07 .30 1.47 .35 2.18
====== ====== ====== ====== ========

The 1996 first quarter included pretax income of $5 million related to a
retroactive severance tax refund. The 1996 third quarter included pretax income
of $8 million for interest and reimbursement of costs from Tennessee Gas (see
Note D) and an aftertax extraordinary loss of $2.3 million for the early
extinguishment of debt (see Note I). The contract with Tennessee Gas was
terminated during the 1996 fourth quarter resulting in pretax income of $60
million (see Note D).

The 1995 third quarter included a gain of approximately $33 million from
the sale of certain interests in the Bob West Field (see Note C), partially
offset by approximately $5 million for employee terminations and other
restructuring costs (see Note J). An extraordinary loss of $2.9 million was
recognized in the 1995 fourth quarter for the early extinguishment of debt (see
Note I).

62
63

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

NOTE N -- NATURAL GAS PRICE AGREEMENTS

The Company enters into commodity price agreements to reduce the risk
caused by fluctuations in the prices of natural gas in the spot market. During
1996, 1995 and 1994, the Company used such agreements to set the price of 30%,
38% and 11%, respectively, of the natural gas production that it sold in the
spot market. It is the Company's policy to use such agreements to set the price
of not more than 50% of the annual volumes of natural gas production that are
sold in the spot market. The agreements provide for the Company to receive, or
make, payments based upon the differential between a specified fixed price and
the market price for natural gas. The market price is determined by reference to
a published index for natural gas traded at the Houston Ship Channel. The
Houston Ship Channel index is the price upon which the cash prices for
substantially all of the Company's spot market gas sales are based and,
accordingly, the risk of losses from large fluctuations in the basis
differentials (normally approximating the cost of transporting gas between the
Henry Hub and the Houston Ship Channel) is substantially eliminated. The Company
includes the related gains or losses in gas revenues in the period in which the
gas is produced, which amounted to a loss of $3.1 million ($.11 per Mcf) in 1996
and to gains of $.3 million ($.01 per Mcf) in 1995 and 1994.

As of January 9, 1997, the Company had entered into price agreements for
1997 production totaling .9 Bcf of gas for an average Houston Ship Channel price
of $2.18 per Mcf. In addition, the Company has entered into price agreements
with collars, under which no payment will be made by either party unless the
price falls below a designated floor price or above a designated ceiling price,
at which time the Company receives or pays the difference, respectively. The
Company has entered into price agreements with collars for 1997 production
totaling 1.8 Bcf of gas with an average floor Houston Ship Channel price of
$1.93 per Mcf and an average ceiling Houston Ship Channel price of $2.42 per
Mcf. In 1996, the Company's average spot market wellhead price per Mcf for gas
sales was $.23 less than the average Houston Ship Channel index, the difference
representing transportation and marketing costs from the wellhead in South
Texas.

NOTE O -- OIL AND GAS PRODUCING ACTIVITIES

The information presented below represents the oil and gas producing
activities of the Company's Exploration and Production segment. Amounts related
to the U.S. natural gas transportation operations, as disclosed in Note B, have
been excluded. Other information pertinent to the Exploration and Production
segment is contained in Notes B, C, D and N.

In 1996, a new Hydrocarbons Law was passed by the Bolivian government that
significantly impacts the Company's operations in Bolivia. The new law, among
other matters, granted the Company the option to convert its Contracts of
Operation to new Shared Risk Contracts. During 1996, the Company signed
agreements to convert its Contracts of Operation to Shared Risk Contracts
subject to recision at the option of the Company if the Company is not satisfied
with modifications to the Bolivian fiscal law. The Company expects to complete
this conversion during the first half of 1997. The new contracts extend the
Company's term of operation, provide more favorable acreage relinquishment terms
and provide for a more favorable fiscal regime of royalties and taxes. The new
contracts will extend the term of the Company's operations for Block 18 ten
additional years to the year 2017. For Block 20, the new contract extends the
Company's term 21 additional years to the year 2029 for acreage that is in the
exploration phase of the contract, and ten additional years to the year 2018 for
an area within Block 20 that is designated as being in the development phase of
the new contract. The new contract provisions, along with a substantial
discovery during 1996, significantly increased the Company's reserves.

63
64

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Capitalized Costs Relating to Oil and Gas Producing Activities

DECEMBER 31,
--------------------------------
1996 1995 1994
-------- -------- --------
(IN THOUSANDS)

Capitalized Costs:
Proved properties................................. $179,433 119,836 131,930
Unproved properties not being amortized(1)........ 12,344 5,118 3,758
-------- -------- --------
191,777 124,954 135,688
Accumulated depreciation, depletion and
amortization................................... 78,222 51,549 50,261
-------- -------- --------
Net Capitalized Costs..................... $113,555 73,405 85,427
======== ======== ========

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

(1) The Company anticipates that the majority of the costs at December 31,
1996, incurred primarily in 1996, will be included in the amortization
base during 1997.

Costs Incurred in Oil and Gas Property Acquisition, Exploration and
Development Activities

UNITED
STATES BOLIVIA TOTAL
------- ------- -------
(IN THOUSANDS)

1996
Property acquisitions --
Proved............................................. $20,454 -- 20,454
Unproved........................................... 5,216 -- 5,216
Exploration........................................... 11,830 6,704 18,534
Development........................................... 22,228 149 22,377
------- ------ -------
$59,728 6,853 66,581
======= ====== =======
1995
Property acquisition, unproved........................ $ 1,432 -- 1,432
Exploration........................................... 10,011 2,994 13,005
Development........................................... 38,003 792 38,795
------- ------ -------
$49,446 3,786 53,232
======= ====== =======
1994
Property acquisition, unproved........................ $ 438 -- 438
Exploration........................................... 8,808 -- 8,808
Development........................................... 51,133 -- 51,133
------- ------ -------
$60,379 -- 60,379
======= ====== =======

64
65

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Results of Operations from Oil and Gas Producing Activities

The following table sets forth the results of operations for oil and gas
producing activities, in the aggregate by geographic area, with income tax
expense computed using the statutory tax rate for the period adjusted for
permanent differences, tax credits and allowances.

UNITED
STATES BOLIVIA TOTAL
---------- --------- ---------
(IN THOUSANDS EXCEPT AS INDICATED)

1996
Gross revenues -- sales to nonaffiliates............. $ 88,358 13,701 102,059
Production costs..................................... 5,326 837 6,163
Administrative support and other..................... 3,649 2,830 6,479
Depreciation, depletion and amortization............. 25,235 1,279 26,514
Income from settlement of a natural gas
contract(1)....................................... 60,000 -- 60,000
Other income(2)...................................... 5,000 -- 5,000
-------- ------ -------
Pretax results of operations......................... 119,148 8,755 127,903
Income tax expense................................... 41,702 5,439 47,141
-------- ------ -------
Results of operations from producing activities(3)... $ 77,446 3,316 80,762
======== ====== =======
Depletion rates per net equivalent Mcf............... $ .79 .15
======== ======
1995
Gross revenues -- sales to nonaffiliates............. $107,276 11,707 118,983
Production costs..................................... 12,005 600 12,605
Administrative support and other..................... 2,842 3,289 6,131
Gain on sales of assets(4)........................... 33,532 -- 33,532
Depreciation, depletion and amortization............. 29,004 250 29,254
-------- ------ -------
Pretax results of operations......................... 96,957 7,568 104,525
Income tax expense................................... 33,935 4,718 38,653
-------- ------ -------
Results of operations from producing activities(3)... $ 63,022 2,850 65,872
======== ====== =======
Depletion rates per net equivalent Mcf............... $ .69 .03
======== ======
1994
Gross revenues -- sales to nonaffiliates............. $ 87,478 13,211 100,689
Production costs..................................... 8,945 619 9,564
Administrative support and other..................... 2,289 3,242 5,531
Depreciation, depletion and amortization............. 24,143 -- 24,143
-------- ------ -------
Pretax results of operations......................... 52,101 9,350 61,451
Income tax expense................................... 19,104 5,605 24,709
-------- ------ -------
Results of operations from producing activities(3)... $ 32,997 3,745 36,742
======== ====== =======
Depletion rates per net equivalent Mcf............... $ .79 --
======== ======

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

(1) See Note D.

(2) Represents retroactive severance tax refunds resulting from exemptions on
substantially all of the Company's reserves in the Bob West Field.

(3) Excludes corporate general and administrative expenses and financing costs.

(4) Represents gain on sale of certain interests in the Bob West Field (see Note
C).

65
66

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved
Reserves (Unaudited)

The following table sets forth the computation of the standardized measure
of discounted future net cash flows relating to proved reserves and the changes
in such cash flows in accordance with SFAS No. 69. The standardized measure is
the estimated excess future cash inflows from proved reserves less estimated
future production and development costs, estimated future income taxes and a
discount factor. Future cash inflows represent expected revenues from production
of year-end quantities of proved reserves based on year-end prices and any fixed
and determinable future escalation provided by contractual arrangements in
existence at year-end. Escalation based on inflation, federal regulatory changes
and supply and demand are not considered. Estimated future production costs
related to year-end reserves are based on year-end costs. Such costs include,
but are not limited to, production taxes and direct operating costs. Inflation
and other anticipatory costs are not considered until the actual cost change
takes effect. Estimated future income tax expenses are computed using the
appropriate year-end statutory tax rates. Consideration is given for the effects
of permanent differences, tax credits and allowances. A discount rate of 10% is
applied to the annual future net cash flows.

The methodology and assumptions used in calculating the standardized
measure are those required by SFAS No. 69. The standardized measure is not
intended to be representative of the fair market value of the Company's proved
reserves. The calculations of revenues and costs do not necessarily represent
the amounts to be received or expended by the Company.

UNITED
STATES BOLIVIA TOTAL
-------- ------- -------
(IN THOUSANDS)

DECEMBER 31, 1996
Future cash inflows................................... $376,103 368,119 744,222
Future production costs............................... 66,524 72,766 139,290
Future development costs.............................. 13,156 30,632 43,788
-------- ------- -------
Future net cash flows before income tax expense....... 296,423 264,721 561,144
10% annual discount factor............................ 73,687 130,915 204,602
-------- ------- -------
Discounted future net cash flows before income
taxes.............................................. 222,736 133,806 356,542
Discounted future income tax expense(1)............... 70,251 80,102 150,353
-------- ------- -------
Standardized measure of discounted future net cash
flows(2)........................................... $152,485 53,704 206,189
======== ======= =======
DECEMBER 31, 1995
Future cash inflows................................... $265,379 120,510 385,889
Future production costs............................... 53,095 32,005 85,100
Future development costs.............................. 8,625 7,548 16,173
-------- ------- -------
Future net cash flows before income tax expense....... 203,659 80,957 284,616
10% annual discount factor............................ 34,920 32,231 67,151
-------- ------- -------
Discounted future net cash flows before income
taxes.............................................. 168,739 48,726 217,465
Discounted future income tax expense.................. 45,939 25,897 71,836
-------- ------- -------
Standardized measure of discounted future net cash
flows.............................................. $122,800 22,829 145,629
======== ======= =======

66
67

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

UNITED
STATES BOLIVIA TOTAL
-------- ------- -------
(IN THOUSANDS)

DECEMBER 31, 1994
Future cash inflows................................... $292,620 120,886 413,506
Future production costs............................... 52,534 30,873 83,407
Future development costs.............................. 29,933 7,258 37,191
-------- ------- -------
Future net cash flows before income tax expense....... 210,153 82,755 292,908
10% annual discount factor............................ 30,706 34,674 65,380
-------- ------- -------
Discounted future net cash flows before income
taxes.............................................. 179,447 48,081 227,528
Discounted future income tax expense.................. 52,661 26,092 78,753
-------- ------- -------
Standardized measure of discounted future net cash
flows.............................................. $126,786 21,989 148,775
======== ======= =======

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

(1) For Bolivia, the discounted future income tax expense as of December 31,
1996 consisted of $69,363 Bolivian taxes and $10,739 U.S. taxes.

(2) Gross production rates were increased from 45 MMcf per day to 90 MMcf per
day in the year 2000 due to the anticipated completion of the Bolivia-Brazil
pipeline discussed in Note B. This increase accounts for approximately $19
million of the standardized measure of discounted future net cash flows for
Bolivia at December 31, 1996.

Changes in Standardized Measure of Discounted Future Net Cash Flows
(Unaudited)

1996 1995 1994
-------- -------- -------
(IN THOUSANDS)

Sales and transfers of oil and gas produced, net of
production costs..................................... $(93,275) (106,378) (88,751)
Net changes in prices and production costs............. 39,409 (32,931) 12,834
Extensions, discoveries and improved recovery.......... 81,201 83,045 54,503
Development costs incurred............................. 22,228 38,795 51,148
Changes in estimated future development costs.......... (39,932) (19,574) (34,738)
Revisions of previous quantity estimates............... (7,244) 60,800 1,818
Purchases (sales) of minerals in-place................. 55,484 (48,698) --
Extension of Bolivian contract terms................... 26,564 -- --
Other changes in Bolivian Hydrocarbons Law............. 32,894 -- --
Accretion of discount.................................. 14,563 14,878 12,919
Net changes in income taxes............................ (71,332) 6,917 9,850
-------- -------- -------
Net increase (decrease)................................ 60,560 (3,146) 19,583
Beginning of period.................................... 145,629 148,775 129,192
-------- -------- -------
End of period.......................................... $206,189 145,629 148,775
======== ======== =======

Reserve Information (Unaudited)

The following estimates of the Company's net proved oil and gas reserves
are based on evaluations prepared by Netherland, Sewell & Associates, Inc.
Reserves were estimated in accordance with guidelines established by the
Securities and Exchange Commission and Financial Accounting Standards Board,
which require that reserve estimates be prepared under existing economic and
operating conditions with no provision for price and cost escalations except by
contractual arrangements.

67
68

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

UNITED
STATES BOLIVIA TOTAL
-------- ------- -------

NET PROVED GAS RESERVES (millions of cubic feet)(1)
December 31, 1993..................................... 120,198 99,295 219,493
Revisions of previous estimates.................... 9,881 (9,678) 203
Extensions, discoveries and other additions........ 29,606 14,199 43,805
Production......................................... (30,586) (8,060) (38,646)
-------- ------- -------
December 31, 1994..................................... 129,099 95,756 224,855
Revisions of previous estimates.................... 46,239 (553) 45,686
Extensions, discoveries and other additions........ 50,201 -- 50,201
Production......................................... (41,789) (6,807) (48,596)
Sales of minerals in-place......................... (77,373) -- (77,373)
-------- ------- -------
December 31, 1995..................................... 106,377 88,396 194,773
Extension of Bolivian contract terms............... -- 32,998 32,998
Other changes in Bolivian Hydrocarbons Law......... -- 56,704 56,704
Revisions of previous estimates.................... (4,792) (149) (4,941)
Extensions, discoveries and other additions........ 22,977 59,964 82,941
Production......................................... (32,081) (7,412) (39,493)
Purchases of minerals in-place..................... 24,309 -- 24,309
-------- ------- -------
December 31, 1996(2).................................. 116,790 230,501 347,291
======== ======= =======
NET PROVED DEVELOPED GAS RESERVES (millions of cubic
feet)
December 31, 1993..................................... 65,652 99,295 164,947
December 31, 1994..................................... 110,071 81,558 191,629
December 31, 1995..................................... 95,930 72,500 168,430
December 31, 1996(2).................................. 107,509 123,154 230,663
NET PROVED OIL RESERVES (thousands of barrels)(1)
December 31, 1993..................................... -- 2,173 2,173
Revisions of previous estimates.................... -- (280) (280)
Extensions, discoveries and other additions........ -- 168 168
Production......................................... -- (268) (268)
-------- ------- -------
December 31, 1994..................................... -- 1,793 1,793
Revisions of previous estimates.................... 1 10 11
Extensions, discoveries and other additions........ 8 -- 8
Production......................................... (1) (207) (208)
-------- ------- -------
December 31, 1995..................................... 8 1,596 1,604
Extension of Bolivian contract terms............... -- 459 459
Other changes in Bolivian Hydrocarbons Law......... -- 913 913
Revisions of previous estimates.................... (4) 150 146
Extensions, discoveries and other additions........ -- 840 840
Production......................................... (10) (214) (224)
Purchases of minerals in-place..................... 188 -- 188
-------- ------- -------
December 31, 1996(2).................................. 182 3,744 3,926
======== ======= =======
NET PROVED DEVELOPED OIL RESERVES (thousands of barrels)
December 31, 1993..................................... -- 2,173 2,173
December 31, 1994..................................... -- 1,627 1,627
December 31, 1995..................................... 4 1,407 1,411
December 31, 1996(2).................................. 126 2,291 2,417

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

(1) The Company was not required to file reserve estimates with federal
authorities or agencies during the periods presented.

(2) No major discovery or adverse event has occurred since December 31, 1996
that would cause a significant change in net proved reserve volumes.

68
69

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
1997 Proxy Statement, incorporated herein by reference.

See also Executive Officers of the Registrant under Business in Item 1.

ITEM 11. EXECUTIVE COMPENSATION

Information required under this Item will be contained in the Company's
1997 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
1997 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
1997 Proxy Statement, incorporated herein by reference.

PART IV

ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K

(A) 1. FINANCIAL STATEMENTS

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

PAGE
----

Independent Auditors' Report................................ 38
Statements of Consolidated Operations -- Years Ended
December 31, 1996, 1995 and 1994.......................... 39
Consolidated Balance Sheets -- December 31, 1996 and 1995... 40
Statements of Consolidated Stockholders' Equity -- Years
Ended December 31, 1996, 1995 and 1994.................... 41
Statements of Consolidated Cash Flows -- Years Ended
December 31, 1996, 1995 and 1994.......................... 42
Notes to Consolidated Financial Statements.................. 43

2. FINANCIAL STATEMENT SCHEDULES

All schedules are omitted 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.

69
70

3. EXHIBITS

EXHIBIT
NUMBER DESCRIPTION OF EXHIBIT
------- ----------------------

2.1 -- Agreement and Plan of Merger dated as of November 20,
1995, between the Company, Coastwide Energy Services,
Inc. and CNRG Acquisition Corp. (incorporated by
reference herein to Registration Statement No.
333-00229).
2.2 -- First Amendment to Agreement and Plan of Merger dated
effective February 19, 1996 between the Company,
Coastwide Energy Services, Inc. and CNRG Acquisition
Corp. (incorporated by reference herein to Exhibit 2(b)
to the Company's Annual Report on Form 10-K for the
fiscal year ended December 31, 1995, File No. 1-3473).
3.1 -- Restated Certificate of Incorporation of the Company
(incorporated by reference herein to Exhibit 3 to the
Company's Annual Report on Form 10-K for the fiscal year
ended December 31, 1993, File No. 1-3473).
3.2 -- By-Laws of the Company, as amended through June 6, 1996.
3.3 -- Amendment to Restated Certificate of Incorporation of the
Company adding a new Article IX limiting Directors'
Liability (incorporated by reference herein to Exhibit
3(b) to the Company's Annual Report on Form 10-K for the
fiscal year ended December 31, 1993, File No. 1-3473).
3.4 -- Certificate of Designation Establishing a Series of $2.20
Cumulative Convertible Preferred Stock, dated as of
January 26, 1983 (incorporated by reference herein to
Exhibit 3(c) to the Company's Annual Report on Form 10-K
for the fiscal year ended December 31, 1993, File No.
1-3473).
3.5 -- Certificate of Designation Establishing a Series A
Participating Preferred Stock, dated as of December 16,
1985 (incorporated by reference herein to Exhibit 3(d) to
the Company's Annual Report on Form 10-K for the fiscal
year ended December 31, 1993, File No. 1-3473).
3.6 -- Certificate of Amendment, dated as of February 9, 1994,
to Restated Certificate of Incorporation of the Company
amending Article IV, Article V, Article VII and Article
VIII (incorporated by reference herein to Exhibit 3(e) to
the Company's Annual Report on Form 10-K for the fiscal
year ended December 31, 1993, File No. 1-3473).
4.1 -- Amended and Restated Credit Agreement ("Credit Facility")
dated as of June 7, 1996 among the Company and Banque
Paribas, individually, as an Issuing Bank and as
Administrative Agent, and The Bank of Nova Scotia,
individually and as Documentation Agent, and certain
other financial institutions named therein (incorporated
by reference herein to Exhibit 4.1 to the Company's
Quarterly Report on Form 10-Q for the quarter ended June
30, 1996, File No. 1-3473).
4.2 -- Second Amended and Restated Guaranty Agreement dated as
of January 28, 1997 among various subsidiaries of the
Company and Banque Paribas, individually, as
Administrative Agent and as an Issuing Bank, and certain
other financial institutions named therein, entered into
in connection with the Credit Facility.
4.3 -- Amended and Restated Security Agreement (Accounts and
Inventory) dated as of June 7, 1996 between the Company
and Banque Paribas, entered into in connection with the
Credit Facility (incorporated by reference herein to
Exhibit 4.3 to the Company's Quarterly Report on Form
10-Q for the quarter ended June 30, 1996, File No.
1-3473).
4.4 -- Amended and Restated Security Agreement (Accounts and
Inventory) dated as of June 7, 1996 between Tesoro Alaska
Petroleum Company and Banque Paribas, entered into in
connection with the Credit Facility (incorporated by
reference herein to Exhibit 4.4 to the Company's
Quarterly Report on Form 10-Q for the quarter ended June
30, 1996, File No. 1-3473).

70
71

EXHIBIT
NUMBER DESCRIPTION OF EXHIBIT
------- ----------------------

4.5 -- Amended and Restated Security Agreement (Accounts and
Inventory) dated as of June 7, 1996 between Tesoro
Refining, Marketing & Supply Company and Banque Paribas,
entered into in connection with the Credit Facility
(incorporated by reference herein to Exhibit 4.5 to the
Company's Quarterly Report on Form 10-Q for the quarter
ended June 30, 1996, File No. 1-3473).
4.6 -- Security Agreement (Accounts and Inventory) dated as of
June 7, 1996 between Kenai Pipe Line Company and Banque
Paribas, entered into in connection with the Credit
Facility (incorporated by reference herein to Exhibit 4.6
to the Company's Quarterly Report on Form 10-Q for the
quarter ended June 30, 1996, File No. 1-3473).
4.7 -- Security Agreement (Accounts and Inventory) dated as of
June 7, 1996 between Tesoro Coastwide Services Company
and Banque Paribas, entered into in connection with the
Credit Facility (incorporated by reference herein to
Exhibit 4.7 to the Company's Quarterly Report on Form
10-Q for the quarter ended June 30, 1996, File No.
1-3473).
4.8 -- Security Agreement (Accounts and Inventory) dated as of
June 7, 1996 between Coastwide Marine Services, Inc. and
Banque Paribas, entered into in connection with the
Credit Facility (incorporated by reference herein to
Exhibit 4.8 to the Company's Quarterly Report on Form
10-Q for the quarter ended June 30, 1996, File No.
1-3473).
4.9 -- Security Agreement (Accounts) dated as of June 7, 1996
between Tesoro Vostok Company and Banque Paribas, entered
into in connection with the Credit Facility (incorporated
by reference herein to Exhibit 4.9 to the Company's
Quarterly Report on Form 10-Q for the quarter ended June
30, 1996, File No. 1-3473).
4.10 -- Amended and Restated Security Agreement (Pledge) dated as
of June 7, 1996 by the Company in favor of Banque
Paribas, entered into in connection with the Credit
Facility (incorporated by reference herein to Exhibit
4.10 to the Company's Quarterly Report on Form 10-Q for
the quarter ended June 30, 1996, File No. 1-3473).
4.11 -- First Amendment to Amended and Restated Security
Agreement (Pledge) dated as of September 12, 1996 between
the Company and Banque Paribas, entered into in
connection with the Credit Facility.
4.12 -- First Amendment to Deed of Trust, Security Agreement and
Financing Statement dated as of June 7, 1996 among Tesoro
Alaska Petroleum Company, TransAlaska Title Insurance
Agency, Inc., as Trustee, and Banque Paribas, as
Administrative Agent, entered into in connection with the
Credit Facility (incorporated by reference herein to
Exhibit 4.11 to the Company's Quarterly Report on Form
10-Q for the quarter ended June 30, 1996, File No.
1-3473).
4.13 -- First Amendment to Mortgage, Deed of Trust, Assignment of
Production, Security Agreement and Financing Statement
dated as of June 7, 1996 from Tesoro E&P Company, L.P.,
entered into in connection with the Credit Facility
(incorporated by reference herein to Exhibit 4.12 to the
Company's Quarterly Report on Form 10-Q for the quarter
ended June 30, 1996, File No. 1-3473).
4.14 -- Mortgage, Deed of Trust, Assignment of Production,
Security Agreement and Financing Statement dated as of
June 7, 1996 from Tesoro E&P Company, L.P., entered into
in connection with the Credit Facility (incorporated by
reference herein to Exhibit 4.13 to the Company's
Quarterly Report on Form 10-Q for the quarter ended June
30, 1996, File No. 1-3473).
4.15 -- Loan Agreement (the "Loan Agreement") dated as of May 26,
1994 among Tesoro Alaska Petroleum Company, as Borrower,
the Company, as Guarantor, and National Bank of Alaska
("NBA"), as Lender (incorporated by reference herein to
Exhibit 4.30 to Registration Statement No. 33-53587).

71
72

EXHIBIT
NUMBER DESCRIPTION OF EXHIBIT
------- ----------------------

4.16 -- Guaranty Agreement dated as of May 26, 1994 between the
Company and NBA, entered into in connection with the Loan
Agreement (incorporated by reference herein to Exhibit
4.31 to Registration Statement No. 33-53587).
4.17 -- $15,000,000 Promissory Note dated as of May 26, 1994 of
Tesoro Alaska Petroleum Company payable to the order of
NBA, in connection with the Loan Agreement (incorporated
by reference herein to Exhibit 4.32 to Registration
Statement No. 33-53587).
4.18 -- Construction Loan Agreement dated as of May 26, 1994
between Tesoro Alaska Petroleum Company and NBA, entered
into in connection with the Loan Agreement (incorporated
by reference herein to Exhibit 4.33 to Registration
Statement No. 33-53587).
4.19 -- Deed of Trust dated as of May 26, 1994 from Tesoro Alaska
Petroleum Company, entered into in connection with the
Loan Agreement (incorporated by reference herein to
Exhibit 4.34 to Registration Statement No. 33-53587).
4.20 -- Security Agreement dated as of May 26, 1994 between
Tesoro Alaska Petroleum Company and NBA, entered into in
connection with the Loan Agreement (incorporated by
reference herein to Exhibit 4.35 to Registration
Statement No. 33-53587).
4.21 -- Consent and Intercreditor Agreement dated as of May 26,
1994 entered into in connection with the Credit Facility
(incorporated by reference herein to Exhibit 4.36 to
Registration Statement No. 33-53587).
4.22 -- Copy of First Amendment to the Loan Agreement dated as of
January 26, 1995 among Tesoro Alaska Petroleum Company,
Tesoro Petroleum Corporation and NBA (incorporated by
reference herein to Exhibit 4(aa) to the Company's Annual
Report on Form 10-K for the fiscal year ended December
31, 1994, File No. 1-3473).
4.23 -- Form of Coastwide Energy Services Inc. 8% Convertible
Subordinated Debenture (incorporated by reference herein
to Exhibit 4.3 to Post-Effective Amendment No. 1 to
Registration No. 333-00229).
4.24 -- Debenture Assumption and Conversion Agreement dated as of
February 20, 1996, between the Company, Coastwide Energy
Services, Inc. and CNRG Acquisition Corp. (incorporated
by reference herein to Exhibit 4.4 to Post-Effective
Amendment No. 1 to Registration No. 333-00229).
4.25 -- Form of Stock Option Agreement for option grant under the
Coastwide Energy Services, Inc. 1993 Long-Term Incentive
Plan (incorporated by reference herein to Exhibit 4.5 to
Post-Effective Amendment No. 1 to Registration No.
333-00229).
4.26 -- Form of Cancellation/Substitution Agreement by and
between the Company, Coastwide Energy Services, Inc. and
Optionee (incorporated by reference herein to Exhibit 4.6
to Post-Effective Amendment No. 1 to Registration No.
333-00229).
10.1 -- The Company's Amended Executive Security Plan, as amended
through November 13, 1989, and Funded Executive Security
Plan, as amended through February 28, 1990, for executive
officers and key personnel (incorporated by reference
herein to Exhibit 10(f) to the Company's Annual Report on
Form 10-K for the fiscal year ended September 30, 1990,
File No. 1-3473).
10.2 -- Sixth Amendment to the Company's Amended Executive
Security Plan and Seventh Amendment to the Company's
Funded Executive Security Plan, both dated effective
March 6, 1991 (incorporated by reference herein to
Exhibit 10(g) to the Company's Annual Report on Form 10-K
for the fiscal year ended September 30, 1991, File No.
1-3473).

72
73

EXHIBIT
NUMBER DESCRIPTION OF EXHIBIT
------- ----------------------

10.3 -- Seventh Amendment to the Company's Amended Executive
Security Plan and Eighth Amendment to the Company's
Funded Executive Security Plan, both dated effective
December 8, 1994 (incorporated by reference herein to
Exhibit 10(f) to the Company's Annual Report on Form 10-K
for the fiscal year ended December 31, 1994, File No.
1-3473).
10.4 -- Amended and Restated Employment Agreement between the
Company and Bruce A. Smith dated February 15, 1996
(incorporated by reference herein to Exhibit 10(o) to the
Company's Annual Report on Form 10-K for the fiscal year
ended December 31, 1995, File No. 1-3473).
10.5 -- Amended and Restated Employment Agreement between the
Company and James C. Reed, Jr. dated as of December 12,
1996.
10.6 -- Amended and Restated Employment Agreement between the
Company and William T. Van Kleef dated as of December 12,
1996.
10.7 -- Management Stability Agreement between the Company and
Don E. Beere dated December 14, 1994 (incorporated by
reference herein to Exhibit 10(o) to the Company's Annual
Report on Form 10-K for the fiscal year ended December
31, 1994, File No. 1-3473).
10.8 -- Management Stability Agreement between the Company and
Gregory A. Wright dated February 23, 1995 (incorporated
by reference herein to Exhibit 10(p) to the Company's
Annual Report on Form 10-K for the fiscal year ended
December 31, 1994, File No. 1-3473).
10.9 -- Management Stability Agreement between the Company and
Thomas E. Reardon dated December 14, 1994 (incorporated
by reference herein to Exhibit 10(w) to Registration
Statement No. 333-00229).
10.10 -- The Company's Amended Incentive Stock Plan of 1982, as
amended through February 24, 1988 (incorporated by
reference herein to Exhibit 10(t) to the Company's Annual
Report on Form 10-K for the fiscal year ended September
30, 1988, File No. 1-3473).
10.11 -- Resolution approved by the Company's stockholders on
April 30, 1992 extending the term of the Company's
Amended Incentive Stock Plan of 1982 to February 24, 1994
(incorporated by reference herein to Exhibit 10(o) to the
Company's Annual Report on Form 10-K for the fiscal year
ended December 31, 1992, File No. 1-3473).
10.12 -- Amended and Restated Tesoro Petroleum Corporation
Executive Long-Term Incentive Plan, as amended through
June 6, 1996.
10.13 -- Copy of the Company's Non-Employee Director Retirement
Plan dated December 8, 1994 (incorporated by reference
herein to Exhibit 10(t) to the Company's Annual Report on
Form 10-K for the fiscal year ended December 31, 1994,
File No. 1-3473).
10.14 -- Copy of the Company's Board of Directors Deferred
Compensation Plan dated February 23, 1995 (incorporated
by reference herein to Exhibit 10(u) to the Company's
Annual Report on Form 10-K for the fiscal year ended
December 31, 1994, File No. 1-3473).
10.15 -- Copy of the Company's Board of Directors Deferred
Compensation Trust dated February 23, 1995 (incorporated
by reference herein to Exhibit 10(v) to the Company's
Annual Report on Form 10-K for the fiscal year ended
December 31, 1994, File No. 1-3473).
10.16 -- Agreement for the Sale and Purchase of State Royalty Oil
dated as of April 21, 1995 by and between Tesoro Alaska
Petroleum Company and the State of Alaska (incorporated
by reference herein to Exhibit 10 to the Company's
Quarterly Report on Form 10-Q for the quarter ended June
30, 1995, File No. 1-3473).

73
74

10.17 -- Copy of Settlement Agreement dated effective January 19, 1993, between Tesoro Petroleum
Corporation, Tesoro Alaska Petroleum Company and the State of Alaska (incorporated by
reference herein to Exhibit 10(q) to the Company's Annual Report on Form 10-K for the
fiscal year ended December 31, 1992, File No. 1-3473).
10.18 -- Form of Indemnification Agreement between the Company and its officers and directors
(incorporated by reference herein to Exhibit B to the Company's Proxy Statement for the
Annual Meeting of Stockholders held on February 25, 1987, File No. 1-3473).
10.19 -- Settlement and Standstill Agreement, dated as of April 4, 1996, among Kevin S.
Flannery, Alan Kaufman, Robert S. Washburn, James H. Stone, George F. Baker, Douglas
Thompson, Gales E. Galloway, Whelan Management Corp., Ardsley Advisory Partners and
Tesoro Petroleum Corporation (incorporated by reference herein to Exhibit 99 to the
Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 1996, File No.
1-3473).
10.20 -- Settlement Agreement and Release, entered into and effective as of October 1, 1996, by
and between Tesoro E&P Company, L.P., acting through its General Partner, Tesoro
Exploration and Production Company, Coastal Oil & Gas Corporation and Coastal Oil & Gas
USA, L.P., and Tennessee Gas Pipeline Company.
10.21 -- Termination Agreement, entered into and effective as of October 1, 1996, by and between
Tesoro E&P Company, L.P., acting through its General Partner, Tesoro Exploration and
Production Company, Coastal Oil & Gas Corporation and Coastal Oil & Gas USA, L.P., and
Tennessee Gas Pipeline Company.
11 -- Information Supporting Earnings Per Share Computations
21 -- Subsidiaries of the Company
23.1 -- Consent of Deloitte & Touche LLP
23.2 -- Consent of Netherland, Sewell & Associates, Inc.
27 -- Financial Data Schedule

Copies of exhibits filed as part of this Form 10-K may be obtained by
stockholders of record at a charge of $.15 per page, minimum $5.00 each request.
Direct inquiries to the Corporate Secretary, Tesoro Petroleum Corporation, 8700
Tesoro Drive, San Antonio, Texas, 78217-6218.

(B) REPORTS ON FORM 8-K

No reports on Form 8-K were filed by the Company during the quarter ended
December 31, 1996.

74
75

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

March 24, 1997

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

SIGNATURE TITLE DATE
--------- ----- ----

/s/ BRUCE A. SMITH Chairman of the Board of Directors March 24, 1997
- ----------------------------------------------------- and Director, President and
(Bruce A. Smith) Chief Executive Officer
(Principal Executive Officer)

/s/ JAMES C. REED, JR. Executive Vice President, General March 24, 1997
- ----------------------------------------------------- Counsel and Secretary (Principal
(James C. Reed, Jr.) Financial Officer)

/s/ DON E. BEERE Vice President, Controller March 24, 1997
- ----------------------------------------------------- (Principal Accounting Officer)
(Don E. Beere)

/s/ STEVEN H. GRAPSTEIN Vice Chairman of the Board of March 24, 1997
- ----------------------------------------------------- Directors and Director
(Steven H. Grapstein)

/s/ ROBERT J. CAVERLY Director March 24, 1997
- -----------------------------------------------------
(Robert J. Caverly)

/s/ WILLIAM J. JOHNSON Director March 24, 1997
- -----------------------------------------------------
(William J. Johnson)

/s/ ALAN J. KAUFMAN Director March 24, 1997
- -----------------------------------------------------
(Alan J. Kaufman)

/s/ RAYMOND K. MASON, SR. Director March 24, 1997
- -----------------------------------------------------
(Raymond K. Mason, Sr.)

/s/ PATRICK J. WARD Director March 24, 1997
- -----------------------------------------------------
(Patrick J. Ward)

/s/ MURRAY L. WEIDENBAUM Director March 24, 1997
- -----------------------------------------------------
(Murray L. Weidenbaum)

75
76

INDEX TO EXHIBITS

EXHIBIT
NUMBER DESCRIPTION OF EXHIBIT
------- ----------------------

3.2 -- Bylaws of the Company, as amended through June 6, 1996.
4.2 -- Second Amended and Restated Guaranty Agreement dated as
of January 28, 1997 among various subsidiaries of the
Company and Banque Paribas, individually, as
Administrative Agent and as an Issuing Bank, and certain
other financial institutions named therein, entered into
in connection with the Credit Facility.
4.11 -- First Amendment to Amended and Restated Security
Agreement (Pledge) dated as of September 12, 1996 between
the Company and Banque Paribas, entered into in
connection with the Credit Facility.
10.5 -- Amended and Restated Employment Agreement between the
Company and James C. Reed, Jr. dated as of December 12,
1996.
10.6 -- Amended and Restated Employment Agreement between the
Company and William T. Van Kleef dated as of December 12,
1996.
10.12 -- Amended and Restated Tesoro Petroleum Corporation
Executive Long-Term Incentive Plan, as amended through
June 6, 1996.
10.20 -- Settlement Agreement and Release, entered into and
effective as of October 1, 1996, by and between Tesoro
E&P Company, L.P., acting through its General Partner,
Tesoro Exploration and Production Company, Coastal Oil &
Gas Corporation and Coastal Oil & Gas USA, L.P., and
Tennessee Gas Pipeline Company.
10.21 -- Termination Agreement, entered into and effective as of
October 1, 1996, by and between Tesoro E&P Company, L.P.,
acting through its General Partner, Tesoro Exploration
and Production Company, Coastal Oil & Gas Corporation and
Coastal Oil & Gas USA, L.P., and Tennessee Gas Pipeline
Company.
11 -- Information Supporting Earnings Per Share Computations
21 -- Subsidiaries of the Company
23.1 -- Consent of Deloitte & Touche LLP
23.2 -- Consent of Netherland, Sewell & Associates, Inc.
27 -- Financial Data Schedule

78